OPTS Memorandum on the Petroleum Industry Fiscal Bill · OPTS is supportive of the Bill’s...

May 2018

OPTS Memorandum on the Petroleum

Industry Fiscal Bill

3

MEMORANDUM ON THE REVIEW OF A BILL FOR AN ACT TO PROVIDE FOR

THE FISCAL FRAMEWORK FOR THE PETROLEUM INDUSTRY IN NIGERIA AND

FOR OTHER RELATED MATTERS

(THE PETROLEUM INDUSTRY FISCAL BILL)

The Oil Producers Trade Section (OPTS) is the umbrella body for private upstream oil and gas companies in Nigeria under the Lagos Chamber of Commerce and Industry, a company limited by guarantee. Any use of this material without the permission of OPTS is strictly

prohibited.

4

We thank you for your kind invitation to present our views at this public hearing. We are grateful

for the opportunity to contribute to the consultative process on this very important legislation

under consideration by this Committee.

This memorandum is presented by the Oil Producers Trade Section (OPTS) of the Lagos

Chamber of Commerce and Industry. The OPTS consists of 29 indigenous and international

members that operate about 90% of the total oil and gas production in Nigeria.

With the largest oil and gas reserves in Africa, Nigeria can achieve its economic

development goals through a sustainable and globally competitive Petroleum Industry

fiscal regime and conducive business environment.

Nigeria’s petroleum industry faces severe challenges. Unrest in areas of operation disrupting

production, government oversight overlap, complex and prolonged administrative approvals,

fiscal and contractual disputes all hinder the Industry’s ability to compete for global investment

funds and thus slow the growth of Nigeria’s energy industry and economy. If these challenges

were resolved, this would bolster investor confidence and help unlock Nigeria’s vast oil and gas

resources. The collaboration demonstrated recently between the Nigerian government, NNPC,

and the Industry to resolve the prevailing Joint Venture cash call debts is a clear demonstration

of enabling partnership and restoring investor confidence.

OPTS supports the Committee with respect to the vision of the Petroleum Industry Fiscal

Bill, which is to establish a progressive fiscal framework that encourages substantial and

progressive investment in the petroleum industry by balancing rewards with risk and to

enhance revenues to the Federal Government of Nigeria (FGN). OPTS applauds the Bill’s

efforts to grow Joint Venture (JV) Oil production that would have otherwise continued to be

stranded. From OPTS’s analysis, JV Oil production would grow sizably fulfilling some of

Nigeria’s industry sector ambitions.

A key principle for OPTS, is that legislative reform recognizes the investments already

made and it is therefore critical to preserve the incentives on which past investment projects

were sanctioned. Such incentives should continue to apply to projects launched prior to the

proposed Fiscal Bill being passed into Act. This principal does appear to be in the spirit of

the latest draft of the Bill and is fundamental to maintain investor confidence.

Unfortunately, as currently written, we believe that the current proposal of the Bill does not

achieve all the objectives it was set to accomplish. For example, new production

investments in the Deepwater and for Gas are more unlikely to be sanctioned under the

proposed Bill as compared to the current fiscal regime. Additionally, the proposed Bill is

unsuccessful to monetize smaller resource based fields stranded under current fiscal

terms. OPTS encourages that the same progressive deliberations used to secure existing

production economics and unlock JV Oil production be applied to Deepwater, JV Gas and

currently stranded resources.

Table of contents

1. Executive summary 9

2. What and who is OPTS 12

3. Nigeria’s oil and gas landscape and context for a fiscal regime 14

4.1 Impact to existing assets and investments 12

3.1 Overview of JVs 14

3.2 Overview of PSCs 15

3.3 Gas developments 15

3.4 Global competitiveness 16

4. Recommended adjustments to PIFB terms 19

4.1 PIFB objectives 19

4.2 Critical improvements to ensure competitiveness of the PIFB 20

4.3 Recommendations for PIFB to optimize administrative processes and methodologies 23

5. Conclusion 25

6. Appendix: Clause-by-clause recommendations 27

10

The petroleum industry has been a major contributor to the Nigerian economy and to

government revenue. Nigeria, with the largest oil and gas reserves in Africa, has huge

untapped potential available to advance its economic development goals, including gas-to-

power ambitions.

Nevertheless, the Nigerian petroleum industry continues to face numerous internal and

external challenges that have constrained hydrocarbon production. In the current

environment, where Production Sharing Contract terms are disputed, payments for

domestic gas supply are several years in arrears, and industry infrastructure is routinely

sabotaged, it is essential to have a fiscal regime that does not further erode investor

confidence but rather mitigates the exposure to these risks, preserves the value of existing

investments, and successfully attracts capital investment into the sector for growth and

revenue creation.

OPTS is supportive of the Bill’s objectives to establish a progressive petroleum fiscal

framework that encourages growth in investment, simplifies the administration of petroleum

tax and promotes equity and transparency in the system.

A key principal for OPTS investors is the assurance that investments made prior to

legislative reform will continue to fiscally perform per the terms at the time of sanction.

Legislative reform should therefore recognize the investments already made and preserve

the incentives (ITC, ITA or AGFA) on which past investment projects were sanctioned.

OPTS is appreciative that this principal has been recognized in the latest draft of the Bill.

Furthermore, our analysis of the Bill shows that JV Oil production would grow significantly

accomplishing what the prevailing fiscal regime doesn’t and that is to unlock stranded oil

assets. OPTS applauds and supports the Bill’s efforts in these specific areas.

However, our analysis has also shown that the Bill’s terms and framework, in their current

form, will not deliver on all objectives. Specifically:

• Under the proposed Bill, only 4% of the Deepwater projects that make up the

aggregated IOC Business Plan portfolios would be viable as compared to 49% if

Current Terms prevailed. This is due primarily to the following:

1. Allowances are set at company level, rather than at Project level where they are

required;

2. Allowances are insufficient in value to offset the cost of projects,

3. The Bill excludes companies with existing production from earning allowances

on new projects;

4. Deepwater royalties are significantly increased, with a progressive scale

resulting in new projects within a license being subject to higher royalties than

existing production.

Executive summary 1.

11

• Under the proposed Bill, only 54% of the JV Gas production that makes up the

aggregated IOC Business Plan portfolios would be viable as compared to 66% if

Current Terms prevailed. Unlocking additional JV gas production will prove challenging

because:

1. A significant percentage of gas produced is sold to price-regulated Domestic

Gas markets. These low regulated prices restrict revenue and do not allow for

the recovery of development costs required to deliver the gas;

2. The Bill, for new gas projects, removes the current benefits granted under the

PPT Act to consolidate gas capital allowances at the company level;

3. The Bill introduces fiscal ring-fencing by terrain (onshore, offshore), oil, gas, and

sector (upstream, midstream, downstream). This will make investment

decisions more difficult, as the ability to consolidate new projects with existing

revenue streams will be reduced. This will also significantly increase

administrative complexity by creating multiple tax filing perimeters, and create

a potential source of dispute over the allocation of costs between the various

perimeters;

4. The proposed value of the gas Production Allowances is insufficient incentive to

help compensate for low project profitability at low gas prices;

5. The Bill excludes companies with existing production from earning gas

production allowances, and

6. The Bill requires the segregation of midstream-deemed assets and

infrastructure, some of which is critical to gas flare reduction, into separate

companies from the upstream hindering the ability to optimize project

economics and disconnecting value chain assurance.

• The Commission is given excessive discretionary power to define critical terms, such

as the setting of rents for licenses, the determination of the export gas price for royalty

calculation, the determination of the fiscal price of oil for tax calculations, or the setting

of new metering points with potentially significant cost implications; this is contrary to

a principle of transparency and simplicity; and

• Small and medium size Deepwater fields and gas developments continue to be

undeveloped and stranded under the proposed Bill as they are currently under

prevailing terms.

The issues detailed above are serious shortcomings and OPTS would like to advance our critical

recommendations to the Committee for consideration as follows:

• PIFB must ensure that new incentives are applicable and serve to stimulate investment

and growth, including:

- For Deepwater growth, a Production Allowance of US$30/bbl or an Investment

incentive such as ITA/ITC for new projects is required, including for new projects on

currently producing leases and for asset life / field extension projects. Increased

allowances and / or lower royalty rates would further unlock stranded projects

- For Gas growth, a Production Allowance of minimum US$2/mmbtu is required that

can be cross-consolidated with other revenue streams, also the Bill should facilitate

a market-driven gas pricing based on willing buyer & seller arrangements.

- Continue the current practice that companies can consolidate costs, allowances, and

revenues at the company level across terrains

- A single JV Oil and Condensate tax rate across terrains to simplify and ease

administrative burden as well as facilitate the above consolidation

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- Grant Production Allowances at Project level rather than at Company level to all

companies regardless of production status.

• On existing assets as well as new projects:

- Maintain the existing tax consolidation principles;

- Increase the APIT threshold to tax only windfall gains, i.e. at prices above 80 US$/bbl;

- Refrain from imposing the segregation of midstream-deemed assets and the

multiplication of fiscal perimeters and reporting obligations;

The appendix to this Memorandum specifies clause-by-clause recommendations to the Bill.

We hope that our Memorandum, along with the contributions of other stakeholders, will help

the Committee put in place a fiscal regime which enables a strong, growing Nigerian oil and

gas sector.

We remain available to provide further information on the topics raised in this Memorandum

13

OPTS is a private industry group under the umbrella of the Lagos Chamber of Commerce

and Industry, representing the interests of oil and gas producing companies. OPTS members

operate approximately 90% of Nigeria’s oil and gas production, either in partnership with the

Nigerian National Petroleum Corporation (NNPC) or with other local and international lease

holders. OPTS members are the cornerstone of the exploration, development, and production

of Nigeria’s petroleum resources.

The following indigenous and international oil companies are members of OPTS:

• Addax Petroleum Development

Nigeria Limited

• Chevron Nigeria Limited

• Dubri Oil Company Limited

• Elcrest Exploration and Production Nigeria Limited

• ENI - Nigerian Agip Oil Company Limited

• Eroton Exploration and Production

Company Limited

• First Exploration & Production

Development Company Limited

• LEKOIL Nigeria Limited

• Midwestern Oil & Gas Company Limited

• Mobil Producing Nigeria Unlimited

• Moni Pulo Nigeria Limited

• ND Western Limited

• Neconde Energy Limited

• Newcross Exploration and

Production Limited

• Nexen Petroleum Nigeria Limited

• Niger Delta Petroleum Resources Limited

• Oando Exploration and Production Limited

• Oriental Energy Resources Limited

• Pan Ocean Oil Corporation (Nigeria) Limited

• Petroleo Brasileiro (Petrobras) Nigeria Limited

• South Atlantic Petroleum Nigeria

Limited (SAPETRO)

• Seplat Petroleum Development

Company PLC

• Seven Exploration and Production Limited

• Shoreline Natural Resources Limited

• Statoil Nigeria Limited

• The Shell Petroleum Development

Company of Nigeria Limited

• Total E&P Nigeria Limited

• Waltersmith Petroman Oil Limited

• Yinka Folawiyo Group

Our collective objective is to strengthen the long-term health of Nigeria’s petroleum industry.

We achieve this by working closely with companies across the entire industry, as well as

Government and other stakeholders, to address issues of common concern to the industry.

Representatives of our member companies meet monthly to tackle the industry’s pressing

issues.

OPTS has actively supported the Federal Government of Nigeria’s objectives to energize the

gas industry, grow crude oil production capacity, and enhance linkages to the broader

economy.

Some of OPTS’ accomplishments in these areas include increasing gas production by 50%

since 2008, growing Deepwater production from zero in 2004 to around 800 kbopd in 2015 (via

projects such as Abo, Bonga, Erha, Agbami, Akpo, and Usan), and providing significant jobs

for Nigerians and contractors.

What and who is OPTS 2.

14

Our members are committed to ensuring that our operations are conducted in an

environmentally sound manner in line with international best practices through initiatives that

invest in flare-out projects (70% volumetric reduction from 2005 to 2015 by the Industry) and

cleaner power (e.g. Afam power plant designated as a Clean Development Mechanism).

15

Nigeria’s oil and gas landscape primarily consists of Joint Ventures (JVs) in onshore and

shallow water areas as well as Production Sharing Contracts (PSCs) for Deepwater

projects. In 2015, JVs accounted for ~70% of Nigeria’s oil and gas production and PSCs

accounted for ~30%.

EXHIBIT 1: NIGERIA’S OIL AND GAS PRODUCTION

3.1 Overview of JVs

Traditionally, JVs between operators and NNPC have been the backbone of the Nigerian

oil and gas industry. In JVs, joint venture partners enter into an agreement to carry out

exploration, development and production activities of the concession area. The partners

share the risks and costs associated with the exploration and development. The partners,

as concessionaires, hold rights to extract the petroleum resources and to share in the

production, in proportion to their participating interest. Until Deepwater production came

on-stream in 2004, JVs accounted for 100% of petroleum production with the Federal

Government of Nigeria (FGN) receiving ~94% of the income generated from JVs.

|

Concessions account for ~70% of Nigerian oil and gas production,

whereas PSCs account for remaining ~30%

SOURCE: Wood Mackenzie UDT 2018

Nigeria oil and gas production

2.6

3.2

3.0

2.8

1.6

2.4

1.0

1.8

1.2

0.6

2.2

1.4

0.8

2.0

0.4

0.2

0

070201 04 082000 05

~70%

1312 151411100903

~30%

06 16 2017

OnshoreDeep water Shallow waterMillion barrels of oil equivalent per day

Nigeria’s oil and gas landscape and context for a fiscal regime

3.

16

3.2 Overview of PSCs

In the 1990s, PSCs were introduced as a mechanism to develop complex and high-risk

frontier basins in the Deepwater. A fundamental characteristic of the Deepwater PSCs in

Nigeria is that the Contractor carries 100% of exploration risks, project costs, and market

risks and only receives a return on its investment if the project is successful, compared to

a shared investment in a JV which is also a typically less complex and has a higher success

rate. Under this arrangement, the FGN neither invests any money nor shares in any risk

under the PSC arrangement, operators have invested ~ US$ 73Bn in the development and

operations of the existing post-FID and producing PSC projects – largely benefiting

Nigerian stakeholders such as the local Nigerian contractor community.

FGN has significantly benefited from Deepwater production through taxes, royalties, and

NNPC’s allocation of Profit Oil. Based on a 60-70% government take of revenue over

lifecycle of projects, the share of revenue has resulted in cumulative contribution of ~US$

90Bn by year-end 2016. With FGN as a key beneficiary of Deepwater PSC production

growth, OPTS believes that enabling growth in Deepwater should be a fundamental

objective of the PIFB.

In addition, the Deepwater sector has been a catalyst for expanding Nigeria’s technical

skills and creating thousands of jobs through local content development. Deepwater

production has also added essential diversification to Nigeria’s petroleum production

portfolio and a solid source of revenue to FGN – as demonstrated during the 2016 onshore

and shallow water production disruptions.

The 1993 PSCs were effective in balancing the Deepwater risks and the potential rewards,

due to their competitive fiscal regime. Under the 1993 terms, nine PSCs were awarded, all

of which are either producing or currently under development. However, in the current

business environment, even under the 1993 PSC terms, many of the undeveloped

discoveries are not viable today.

With the right fiscal terms and a conducive business environment Nigeria’s Deepwater has

the potential to make continued contributions. Therefore, it is vital that Nigeria provides

these prerequisites to encourage new investments

3.3 Gas development

OPTS supports FGN’s aspiration to attract investment and unlock gas development. With

the largest proven gas reserves in Africa, Nigeria has the potential to be a gas super-power.

In 2015, only ~25% of Nigeria’s gas reserves were being produced or developed, which

leaves significant potential to be captured.

To develop gas reserves, a balanced set of commercial terms and an enabling fiscal regime

are needed. Countries such as Saudi Arabia, Trinidad and Australia have succeeded in

becoming gas super-powers through attractive fiscal provisions for gas development,

government support in developing the required mid- and downstream infrastructure, as well

as close cooperation between the government and industry to fast-track development.

Recently, there has been some improvement in Nigeria domestic gas pricing towards the

equivalent of US$1-2/mmbtu. Still, Nigeria’s gas business requires incentives in order to be

viable as gas prices in Nigeria remain regulated at a low level – in many cases lower than

production costs. Incentivizing gas projects would secure gas supply for power generation

and unlock new industrial and export developments.

17

EXHIBIT 2: NIGERIA’S GAS RESERVES AND CURRENT DEVELOPMENT STATUS

3.4 Global competitiveness

Nigeria’s competitiveness in the global petroleum industry has been eroding due to a broad

set of challenges. This erosion has led to a decline in overall Foreign Direct Investment as

well as petroleum industry related investments. Reversing this negative trend in the

business environment requires a long-term view, which includes ensuring security of life

and property, stable laws and regulations, access to fair and timely arbitration and ensuring

the sanctity of contracts which honors the basis upon which investments were made.

EXHIBIT 3: NIGERIA’S BUSINESS ENVIRONMENT

| 0

With the largest proven gas reserves in Africa, Nigeria has the potential to

be a gas super-power

39

53

65

159

181

Egypt

Libya

Algeria

Nigeria

Other Africa

1 Includes Tanzania, Senegal, Angola, Mauritania, Equitorial Guinea and all remaining African countries

181

46

135

Total

Proven-not

under

development

Producing today

or under

development

SOURCE: WoodMac UDT Q1 2018, BP Statistical review

Nigeria has the largest proven gas reserves

in Africa; TCF, 2015

With ~25% of the reserves producing or

being developed; TCF, 2015

|

118%

Nigeria’s industry faces a challenging business environment,

also compared to other countries in sub-Saharan Africa

SOURCE: Euler Hermes Country Risk Ratings; World Bank WDI; IMF WFS; Expert interviews; Economist Intelligence Unit Security Risk scores

1 Based on combination of macroeconomic, structural business environment and political risk ratings with intent of estimating risk of non-payment in each

country as a proxy for business risk

2 Figures from International Monetary Fund World Financial Statistics with 2016 data available until 31-OCT; Exchange rate movement from 31-OCT to

31-DEC from 0.00313 USD/NGN to 0.00317 USD/NGN; Inflation rate for November & December 2016 18.5% according to Nigerian Bureau of Statistics

Electric

power

consumption

per capita

kWh per

capita

89

382

436

227

142

Medium term country risk

Low High

Security risk

0=No risk,

100= Most

risky

54

39

39

39

75

N/A

N/A

38

Currency

risk

% change

in currency

vs. USD,

2011-2016

Inflation

Com-

pounded

since

2010; CPI

Community

Issues

Contract

Approval

Cycle

Average,

months

Business

risk

index

Medium-

term risk1

Angola 9 79% 140%

Ghana 6 169% 58%

Mozambique 102% 68%

Tanzania 50% 68%

Nigeria 1022 94%2

18

With respect to exhibit 4, it is not a surprise that Nigeria is one of the few sub-Saharan

African that has seen a decline in both FDI and Oil and Gas related investments. This

reduced inflow of investments is driven by a combination of Nigeria’s uncompetitive fiscal

regime (especially for the Deepwater sector) and the challenging business environment.

EXHIBIT 4: FDI FLOWS AND OIL & GAS INVESTMENT IN AFRICAN OIL AND GAS PRODUCERS

Compared to the regional and global landscape, Nigeria’s Deepwater is the least attractive

for investments in sub-Saharan Africa. This is evidenced by only 2 Deepwater fields coming

online in Nigeria since 2010 versus 9 in Angola – and given the capital deployed they are

mostly incremental projects. This lack of competitiveness is exacerbated by recent

discoveries in East African basins with better fiscal terms such as Tanzania and

Mozambique. Moreover, other African countries are improving their fiscal terms to stimulate

investments – such as the fiscal negotiations in Egypt and cost-recovery ceilings being

raised in Angola. In addition, Nigeria is one of the few African countries which have not

unlocked new gas resources since 2010.

|SOURCE: Wood Mackenzie UDT 2018, World Bank World Development Indicators

82

27

278

347

2,725

1,574

1,830

181

22,408

12,306

14,592

2,157

2,407

7,218

4,055

54,478

Change in investment for the period

Positive Negative

Despite Nigeria’s large reserves, investment in the oil and gas industry

has decreased which is harming the economy

2017 production1

kboed

Reserves of O&G at end

of 20172 mmboe

2006 vs. 2011 2011 vs. 2016

Change in investment

Mozambique

Tanzania

Angola

Egypt

Eq. Guinea

Nigeria

Congo

Ghana

O&G3 FDI4 O&G3Country FDI4

19

EXHIBIT 5 DEEPWATER PROJECTS SANCTIONED IN AFRICAN BASINS

Nigeria currently ranks last compared to other Deepwater producers when applying their fiscal regime to the same Nigeria project and comparing government take. (exhibit 6)

EXHIBIT 6: DEEPWATER FISCAL TERMS FOR AFRICAN OIL AND GAS PRODUCING COUNTRIES

|

Recent investment in African Deepwater projects

The only new projects in Nigeria are incremental projects within producing blocks–

projects without consolidation benefits are not viable

Only a few new projects have been sanctioned in Nigeria due

to challenging business environment

SOURCE: Wood Mackenzie UDT 2018

Number of

fields3 Total capex of these projects2, $bnCountry

2

1

13

2

22

83

26

Deepwater projects currently onstream or under development with production start date 2010 or later and

>$1bn in total capital expenditure

Angola

Nigeria

Egypt1

Ghana

Congo

Eq. Guinea

Mozambique

Tanzania

1 Egypt is able to unlock gas developments by negotiating more favorable ad hoc fiscal terms 2 Including abandonment costs 3 Parent-level & standalone

# FID by date

<2013 13-18

9 36

1 10

2 11

3 30

5 32

3 00

1 01

1 01

|

Other African countries offer more attractive fiscal terms to encourage

investment inflow

SOURCE: Wood Mackenzie 2018

Deepwater oil government take

Ranking based on % government take under each fiscal

regime, testing a representative Nigerian sample of deep

water projects under each fiscal regimes

1 Investment incentives not listed in overview due to incomparability and complexity; 2 Only Oil terms; 3 Excluding Gas revenues; 4 Includes royalties, taxes and NNPC

profit oil based on undiscounted cash flows

1 = most competitive

8 = least competitive

Deep water fiscals1

Government take

Royalty TaxCountry Profit Oil2

12–15% 36%Congo 30-55%

0-12% 50%Nigeria

PSC93

20-60%

0% 32%Mozambique 15-60%

13-19% 35%Eq. Guinea 20-60%

12.5% 35%Ghana 0-30%

7.5% 30%Tanzania 50-70%

0% 50%Angola 40-90%

10% 40% 75-85%Egypt

Nigerian PSC proceeds3 at USD 50/bbl

Ghana

Rank: 1

Nigeria

Rank: 8

Tanzania

Rank: 2

Angola

Rank: 7 Mozambique

Rank: 3

Eq. Guinea

Rank: 4

Egypt

Rank: 6

Congo

Rank: 5

FGN receives USD 19.4/bbl4

which is ~70% of total PSC

proceeds after costs

Tax oil

(incl. VAT

& Duties)

Cost oil

(Capex &

Opex)

Royalty

oil $1.0

Contractor

profit oil NNPC profit oil

$22.1

$7.9

$10.5

$8.4

20

4.1 PIFB objectives

The PIFB should define a globally competitive fiscal regime that enables a robust inventory

of viable project investments and support for ongoing operations. To deliver this robust

inventory the full potential of Nigeria’s abundant resources must be unlocked across all

fiscal and contractual regimes (JVs and PSCs), geographies (onshore, shallow-water and

Deep-water) and at all levels of company size.

The viability of a project means that the expected returns from the project are sufficient to

recover the cost of investments and to earn a margin commensurate to the risks involved

in the exploration and the development of the project’s resources. This viability must also

be resilient to changes in the global demand and pricing of oil and gas.

From the investor’s point of view, a globally competitive fiscal regime means the expected

returns on investment must be comparable with other international investment opportunities

whilst compensating for Nigerian’s specific country risks. Only through globally

competitiveness, for which the fiscal system is a fundamental element, can Nigeria expect

to attract the capital investments required to sustain and grow the petroleum industry.

A sustainable long-term contribution of the sector to Nigeria’s development objectives

requires the unlocking of the country’s vast untapped gas resources. The PIFB should

encourage investment in upstream gas development and infrastructure along the entire

value chain, and also establish the fiscal terms to enable future Deepwater gas

developments.

Unfortunately, the PIFB as currently presented, has numerous serious shortcomings and

OPTS would like to advance our critical recommendations to the Committee for

consideration.

Comments on the Petroleum Industry Fiscal Bill

4.

21

4.2 Critical improvements to ensure the competitivity of the PIFB

The commentary below highlights elements of the fiscal framework which are crucial to

enhance the competitivity of the fiscal system described in the Bill to allow sufficient

economic returns to enable new projects to be sanctioned.

4.2.1 New projects consideration: Stimulus to future growth

Bill terms

Through the repeal of the Petroleum Profits Tax Act (PPTA) and the Deep Offshore and

Inland Basin Production Sharing Contract Act, the Bill eliminates existing investment

incentives for all projects including the Investment Tax Allowance (ITA), Investment Tax

Credit (ITC), and Petroleum Investment Allowance (PIA). Therefore, the Bill establishes a

new fiscal regime that eliminates some of the existing investment enablers that are crucial

to ensure project viability without any new incentives being available:

• Sections 76 & 75.2 provides for the repeal section 11 & 12 of PPTA, also known as the

Associated Gas Fiscal Agreement (AGFA) “The incentives granted under sections 11

and 12 of the Petroleum Profits Tax Act which is repealed by this Act.”

• Production Allowances (PA) introduced will not apply to new projects developed by

companies with existing production: “Subject to the provisions of paragraphs (9) and

(10) of this Schedule, any company that is in, or has been in production on the

commencement of this Act shall not be eligible for the allowances under this Schedule”

(second schedule, section 8). It is worthy of note that companies investing in gas

development in Nigeria as at date are all producing, which implies that all existing

investors are excluded.

• The allowance made available to existing non-producing entities are of little effect in

catalyzing much needed investments in Deepwater and gas development “There shall

be a production allowance for crude oil production by a company determined as follows:

(a) for onshore – the lower of US $3 per barrel or 30% of the official selling price. (b) for

shallow water areas – the lower of US $3 per barrel or 30% of the official selling price.

(c) for Deepwater areas – the lower of US $3 per barrel or 30% of the official selling

price” (Second schedule Section 1); for gas: US$1.5/mmbtu: “2. (a) There shall be a

production allowance for natural gas fields of 50% of the value of the natural gas

production or US $ 1.5 per million Btu, whichever is lower” (Second Schedu le Section

2.a)

Industry concerns

• With the elimination of AGFA, which is currently a crucial enabler for the unlocking of

Nigeria’s gas reserves, a key to FGN’s domestic power aspirations, the terms proposed

in PIFB will hinder new gas developments as at the current regulated prices for gas are

set low when compared to market prices, the low prices set by regulation do not allow

for recovery of the significant development costs incurred to deliver gas to market.

• With the elimination of existing investment enablers for Deepwater projects, such as the

Investment Tax Allowance (ITA) and Investment Tax Credit (ITC), and the increase in

Deepwater royalty rates, the proposed PIFB will render most new Deepwater

development economically unviable.

• The proposed Bill does not recognize that growth projects are typically developed within

existing leases / companies and such projects require project level allowances and the

ability to consolidate costs, allowances and revenues at the contract and company levels

and across produced products. In addition, production allowances introduced

(particularity for Deepwater and gas developments) are insufficient to ensure viable

project economics

22

Recommendations

Deepwater specific

The PIFB terms must aim to stimulate new investments:

• Companies in Deepwater with existing production should be entitled to incentives on

new projects, including on the blocks which host existing production;

• Robust incentives are required to make up for the loss of ITA/ITC such as a Production

Allowance at a minimum of US$30/bbl (inflation adjusted over time) or an Investment

incentive such as ITA/ITC, for new approved projects. To unlock small to medium

resource developments would require even higher allowances.

• The Bill should continue the existing practice that companies can consolidate costs,

allowances and revenues at the company level and across Deepwater blocks, including

for cost recovery purposes.

• Specific terms are needed to unlock Deepwater non-associated gas developments.

Onshore and shallow water gas specific

Gas revenues at the prevailing prices of (<US$2/mmbtu) are typically insufficient so that

most gas projects are not viable on a stand-alone basis under the PIFB terms. Significant

adjustments to improve gas project economics are required:

• Companies with existing production should be entitled to incentives on new projects

such as new Production Allowances, including on blocks that host existing production;

• A gas Production Allowances (inflation adjusted over time) at US$2/mmbtu;

• The Bill should continue the exiting practice of consolidating at the company level and

across produced products all costs, allowances and revenues.

• Allow for increased gas revenue through a higher deregulated gas price (upwards from

US$3.5/mmbtu) through Willing Buyer & Seller arrangements or other free-market

mechanisms to attract investment

4.2.2. Considerations for all assets both existing & yet to be developed

Bill terms

• Introduction of Additional Petroleum Income Tax (APIT) to capture windfall profits

(above US$60/bbl): “The company shall pay additional petroleum income tax in

accordance with the provisions of this section where: (a) the average official selling price

for crude oil in a particular accounting period exceeds US$60 per barrel” (section 16.1)

• The Bill prescribes a separation of upstream, midstream and downstream assets and

defines the fiscal regime applicable to each. (Specific midstream and downstream terms

defined in PIFB Parts 4 & 5)

Industry concerns

• The PIFB introduces Additional Petroleum Income Tax (APIT), a mechanism to allow

FGN to capture a greater share of ‘windfall’ profits at higher oil prices. As currently

drafted, the Bill considers that APIT will start to be applied at an oil price of US$60/bbl ,

which is too low to be considered a windfall scenario and is simply an additional tax

burden.

• The Bill implies an imposed carve out of midstream infrastructure from their current

upstream fiscal regime that, notwithstanding the increased administrative complexity

this would create, may also be economically detrimental to operations and future project

viability. It is unclear how previously integrated assets would mitigate against transfer

pricing risks. Moreover, the domestic midstream gas market is not yet sufficiently

matured in terms of capacity or revenue generation (due to the low gas price) to be fully

23

independent: much of its value generation is derived by enabling upstream production.

By fully segregating midstream assets from upstream support there is a risk that critical

future gas infrastructure will be economically unviable and remain undeveloped.

• The ring-fencing by terrain, product1 and sector, namely the fiscal separation of onshore

and shallow-water, oil and gas, and upstream and midstream activities significantly

increases administrative complexity, multiplies tax filing requirements, and is a potential

source of dispute over the allocation of shared costs between these perimeters. This

structure is particularly punitive for larger integrated companies.

Recommendations

• The APIT windfall threshold should start from ~US$80/bbl;

• The fiscal and administrative segregation of integrated midstream-deemed assets

should not be imposed. For new developments, a company should have the flexibility

to choose how to treat their investment. Support for stand-alone midstream assets

should be done directly with targeted incentives, rather than ‘levelling the playing field’

by penalizing existing integrated businesses that have, so far, developed most of

Nigeria’s infrastructure;

• Reduce sector and fiscal fragmentation by retaining simple company-level consolidation

for costs and tax.

• Interpretation (section 77): “Deep Offshore”: An amendment of the definition of “Deep

Offshore” in line with the provisions of the Deep-Water Block Allocation to Companies

(Back-in Rights) Regulations, 2003 is hereby requested. Per the back-in rights “deep

water blocks mean those concessions for the exploration and /or exploitation of

petroleum in which all or part are in waters deeper than 200 meters”

• Production Allowance (Second schedule, section 1(b)): We recommend introducing

special Production Allowances for assets between 100-200m water depth as they are

more complex than more shallow waters (<100m) and Production Allowances need to

be in line with the risk and complexity of the assets.

• Royalties (Schedule four, section 18 (2)): We recommend introducing special Royalty

for assets between 100-200m water depth as they are more complex than more shallow

waters (<100m) and royalties need to be in line with the risk and complexity of the assets.

Proposed schedule:

Tranches (Kbpd) Royalty Rate

First 20 5.0%

Next 20 10.0%

Above 40 15.0%

1 PIFB Section 13.1.

24

4.3 Recommendations for PIFB to optimize administrative processes and methodologies

The following recommendations on processes and methods focus on elements of the fiscal

administration which do not engender the principles of simplicity and transparency, or would

introduce a significant additional administrative burden on companies.

Bill terms

The Bill introduces specific processes and methodologies related to administration of the

fiscal regime, including:

• 20% of foreign costs not tax deductible - unless not available in Nigeria: “…twenty

percent of any expense, incurred outside Nigeria, except where such expenditure

relates to the procurement of goods or services which are not available domestically in

the required quantity and quality” (Section 7.1 l)

• Discretionary role given to the Commission, such as:

- Setting rents for licenses and leases: “…Every Petroleum Exploration License

("PEL") and Petroleum License ("PL") shall be subject to a rent as determined by a

regulation by the Commission” (Third Schedule, Part II, Section 2)

- Determining the gas net-back pricing system for exported LNG for royalties (Third

Schedule, Part III, Section 12): “…The international LNG market price and the LNG

shipping and marketing allowance shall be determined by the Commission”

- Determining the official selling price (OSP): “The official selling price applicable to

any calendar month for, crude oil and condensates produced from any OPL, OML

or PL shall be determined by the Commission” (Third Schedule, part III, Section

11)Set measurement point : “The measurement point(s) referred to in paragraph 10

of this schedule shall be determined by a regulation to be issued by the

Commission…” (Third Schedule, Part III Section 8); and metering set up: “The

production shall be measured at standard temperatures and pressures as defined

from time to time by regulation” (Third Schedule, Part III, Section 9)

Industry concerns

• PIFB stipulates that 20% of any cost incurred outside of Nigeria (unless not available in

country in required quantities and quality) shall not be tax deductible. Aside from the

troubling further administrative burden this clause implies, this is an unnecessary tax

penalty on companies who are already obliged to be compliant with the purchasing

provisions under the Nigerian Content & Development Act

• The Commission is given an excessive discretionary role to define (and change) critical

fiscal conditions, terms or rates that would create additional uncertainty, including:

- Setting of rent for licenses and leases is left at the discretion of the Commission

- Gas net-back pricing system for exported LNG with discretionary role for

Commission (determining the market price and shipping allowance), introduces

uncertainty which could pose significant additional downside risk

- Selling price for crude oil and condensate with discretionary role for Commission

introduces uncertainty which could pose significant additional downside risk

- Measurement point for fiscal purposes to be set in future regulation could have

significant technology and cost implication

• The Bill makes no provisions to address the causes of the ongoing disputes and litigation

present in the Deepwater sector. These disputes are highly damaging to investor

confidence and have arisen from a fundamental confusion around the rights and

responsibilities of joint-tax filing obligations.

25

Recommendations

OPTS recommends the following adjustments to PIFB processes and methodologies:

• Eliminate the unnecessary deduction limitation on costs incurred outside of Nigeria for

all assets and projects that are compliant with their obligations under the Nigerian

Content Development Act. The NC Act has copious provisions to ensure local sourcing,

and the Commission retains cost oversight and project approval authority.

• The current proposal empowers concessionaires as the filing entity for other entities

participating in the PSC, this is not ideal, all entities should report and pay taxes directly

to FGN through FIRS

• Eliminate or reduce the discretionary role given the Commission to modify fiscal

conditions, terms or rates, namely:

- Offset the amounts paid as concession rentals against royalty obligations as per

current practice;

- Retain the current PPT Act mechanism for determination of fiscal prices, including

that for gas sold to Nigerian companies engaged in the export of LNG.

- The selling price for crude oil and condensate should be determined in accordance

with a methodology agreed between Industry and FGN and should be based on

international benchmark prices thus limiting arbitrariness/discretion;

- Retain fiscal metering at the point of sales as per current practice. The proposed

measurement point at flow-station would bring additional cost burden, administrative

complexity and scope for dispute. The treatment of losses is not addressed.

• Eliminate the obligation for joint-tax filing for PSCs and allow each party to determine

and file its own tax return with FIRS who shall act as the sole administrator and ensure

that tax is paid in accordance with the requirements of the law. While simplifying the tax

reporting process and eliminating a significant source of dispute, this recommendation

will also promote transparency of the tax flows to Government.

26

Unlocking Nigeria’s abundant natural resources requires a competitive, transparent fiscal

regime implemented with best-in-class process and oversight. Putting these prerequisites

in place will ensure that Nigeria can attract the required investments to enable a strong,

long-term growth in the petroleum industry that will increase and stabilize FGN revenues

and contribute to the overall Nigerian economy.

OPTS is fully supportive of the objectives of the Bill however, due to the serious

shortcomings identified herein, OPTS believes these objectives will not be realized. Most

critically, we strongly recommend due consideration be given to the recommendations

required to unlock new Deepwater and Gas resources. These essential improvements in

competitivity require the introduction of new incentives to stimulate investments; for

Deepwater a Production Allowance of 30US$/bbl or an Investment incentive such as

ITA/ITC and for gas, a fully consolidated Production Allowance of 2US$/mmbtu, allow a

transition to a market defined gas price based on free-market willing buyer & seller

arrangements, and the removal of all forms of segregation or fiscal ring-fencing. In addition,

a higher APIT threshold, 100% tax deductibility of foreign costs and the removal of

discretionary powers given to the Commission are required improvements to optimize

administrative processes and methodologies.

We hope that our Memorandum will help the Committee to put in place an Act that provides

an enabling fiscal regime that fully realizes Nigeria’s potential in the petroleum industry.

The success of the upstream is critical in achieving fully developed and sustainable

midstream and downstream sectors.

We remain available to provide further information on the topics raised in this Memorandum.

We thank you for your attention and for the opportunity given to OPTS to present this

document to this esteemed Committee.

Conclusion

5.

28

17

6. Appendix: Clause-by-clause recommendation

29

Categories Section PIFB provision Concern/justification Recommendation/suggested language

Critical improvements to ensure competitiveness of the PIFB

4 (2) Where a company has operations spanning different terrains, the tax shall be charged and assessed separately on the operations in each terrain.

Tax ringfencing by terrain in the Joint Venture promotes complexity, ambiguity, and inefficiencies. This is further compounded by ringfencing operations of midstream and Upstream. No laws are written for integrated companies The proposed ringfencing will result in complexity and promotion of disputes in cost allocation between the FIRS and the taxpayer. Multiple tax returns per terrain per operation. The existing onshore / shallow water allowances have been removed (PIA) - therefore the stated tax rate should be reduced

4. Charge of tax 1) There shall be levied upon the profits of any company engaged in upstream petroleum operations a tax to be known as Petroleum Income Tax which shall be charged, and assessed upon its profits and payable during each Accounting Period in accordance with the provisions of this Act. (2) The tax shall be determined in accordance with the provisions of this Act and shall be on a company basis Provided that in the deep offshore and inland basins the tax shall be based on the contract area. (3) Subject to the provision of sub-section (2) each party in a production sharing contract or arrangement in the Deepwater shall be accountable for computing, filing and payment of chargeable tax on its share of crude oil and gas entitlement lifted from the development, operations and production activities in the contract area (4) Notwithstanding anything to the contrary in this Act, the Commission may, for the purpose of incentivizing Frontier Basin exploration and development, subject to the approval of the Minister responsible for petroleum operations, direct or allow consolidation of costs and income from Frontier Basin operations with costs and income from operations in the Deepwater. (5) The consolidation granted pursuant to subsection 4 of this section shall be for a period of time stipulated by the Commission. (6) Companies engaged in upstream gas operations shall be entitled to a tax-free period of five years commencing from the first year tax is due and payable to the Government through FIRS on production from such operations provided that the provision of this subsection 6 shall not apply to a development or project to which subsections 2 and 3 of section 75 apply.


5.c Condensate spiked into crude oil shall be treated as an upstream petroleum operation and condensate not spiked into crude oil will

Condensate not spiked into crude is produced via midstream/downstream assets and currently taxed under the CITA regime. This clause forces condensate to be taxed under the PIT regime, albeit at the CITA tax

Substitute current text with the following:

Condensate spiked into crude oil shall be treated as an upstream petroleum operation and

30


be taxed at the downstream tax rate. rate, with associated processing facilities stranded in the CITA regime. The current matching of revenue from unspiked condensate with associated processing facilities under the CITA regime should be retained.

condensate not spiked into crude oil shall be treated as a downstream petroleum operation and taxed under the Companies Income Tax Act.


12 (3) The amount to be allowed as a deduction under subsection (1) in respect of

the said allowances shall be–

(a) the aggregate amount computed under subsection (2) of this section;

or

(b) a sum not more than 80 % of the assessable profits of the accounting

period whichever is less.

Production Allowances should not be subject to the 80% cap

Amend section 12:

(3) The amount to be allowed as a deduction under subsection (1) in respect of the said allowances shall be–

(a) the aggregate amount computed under subsection (2) of this section excluding Production Allowances;

or

(b) a sum not more than 80 % of the assessable profits of the accounting period whichever is less, excluding Production Allowances.


13 Where a company has operations spanning different terrains, the tax shall be charged and assessed separately on the operations in each terrain.

Tax ringfencing by terrain in the Joint Venture promotes complexity, ambiguity, and inefficiencies. This is further compounded by ringfencing operations of midstream and Upstream. No laws are written for integrated companies The proposed ringfencing will result in complexity and promotion of disputes in cost allocation between the FIRS and the taxpayer. Multiple tax returns per terrain per operation. The existing onshore / shallow water allowances have been removed (PIA) - therefore the

stated tax rate should be reduced

Amend Section 13 (1) The assessable tax for any accounting period of a company shall be a percentage of the chargeable profit for that period as follows: (a) 50% for crude oil and condensate profit (b) 20% for gas profit (2) The assessable tax for Deepwater activities shall apply to the contract area as follows: (a) 40% for crude oil and condensate profit (b) 20% for gas profit (3) Each party in a production sharing contract or arrangement in the deep offshore and inland basins shall be accountable for computing, filing and payment of chargeable tax on its share of crude oil and gas entitlement lifted from the development, operations and production activities in the contract area


16(1) The company shall pay Additional Petroleum Income Tax in accordance with the provisions of this Section where: (a) the average official selling price for crude oil in a particular accounting period exceeds US$60 per barrel

APIT threshold introduced is close to the current oil price environment; which is not a windfall situation. The existing allowances (PIA) have been removed - therefore tax rate should be reduced

Amend 16(1)(a) to shift APIT threshold from US$60 per barrel to US$80 per barrel Add a Section 16(1)(c) to allow adjustment of Price Threshold with annual inflation


59 Parties engaged in Upstream petroleum operations in the deep offshore and inland basins shall be entitled to production allowance as applicable in the second

Paragraph 8 of the 2nd Schedule appears to contradict this earlier Section of the proposed law as it “excludes all companies already in production before PIFB from the (Production) Allowances introduced by the Act”.

Add to Second Schedule a Section 9(c) to allow new projects approved by the Commission to be eligible for production allowances regardless of company production position and/or product

31


schedule of this Act The proposed Bill does not recognize that, due to the size of leases in Nigeria, there are many fields in leases which are undeveloped. Therefore, growth projects are typically developed more within existing leases by companies and thus incentives should be granted at project level including ability to consolidate at the contract and company levels and across produced products to assure growth and value creation.

produced


61 & 63 61: Chargeable tax on Upstream petroleum operations The chargeable tax on Upstream petroleum operations in the terrain shall be split between the parties engaged in Upstream petroleum operations in the deep offshore and inland basins in the same ratio as the split of profit oil or gas as defined in any agreement or arrangement between them and in the absence of any such agreement, as may be advised by the Commission. 63: Service to issue receipts to each parties Where Upstream petroleum operation is being undertaken by two or more parties, the Service shall make available to the parties separate receipts bearing the names of each party as defined in the agreement or such arrangement between the parties in accordance with each party’s payment of petroleum income tax under their agreements and in the absence of an agreement, as advised by the Commission.

Section 58 clearly stated the intention for each company to file its own taxes, however, Section 61 & 63 do not respect that principle and require amendment to ensure that each company (even within one PSC / PSA) files its own tax returns. Each equity stakeholder within each PSC / PSA should file separate individual taxes. Currently, administration of taxation per contract area is cumbersome for the FIRS and has resulted in litigation and arbitration amongst the Partners.

Sections 61 and 63 should be amended to reflect individual tax filing by each Partner in a PSC or PSA. This is in line with the recognition of each Partner as a Taxpayer. Substitute the current text with the following: Section 61: The chargeable tax on Upstream petroleum operations in the deep offshore and inland basins shall be determined on the basis of the contract area, provided that each company shall be accountable for computing, filing and payment of chargeable tax on its share of crude oil, condensate and gas entitlement lifted from the development, operations and production activities in the contract area Section 63. Service to issue receipts to each party Section 63 The Service shall issue a receipt to the company for tax paid in accordance with Section 61 of this Act in relation to the contract


64 & 69 Midstream/Downstream petroleum operations

The gas market is in process of maturing and is not yet able to independently succeed on its own and provide for the needs of midstream investments because the value they generate is through enabling the Upstream. By segregating Midstream from Upstream, the industry will be presented with the risk that gas and its infrastructure will not be developed

For committed investments there should not be a change towards the condition at which the investments were committed - therefore existing Upstream assets should not be requalified For future investments each company should have the option to qualify assets as Upstream or midstream as long as there is no self-standing midstream sector capable of developing the required economic infrastructure projects necessary for Upstream flow assurance and flare reduction

Critical improvements to 75 (2) The incentives granted under Sections 11 1. The wording needs to be clearer if the intent is for Detailed transition and savings provisions

32


ensure competitiveness of the PIFB

and 12 of the Petroleum Profits Tax Act which is repealed by this Act shall continue to apply to projects which have been approved by the NNPC or DPR prior to the commencement of this Act and in respect of which significant investment has been made prior to the commencement of this Act. For the purposes of this Section, significant investment means such level of investment as determined by the Commission.

(3) Notwithstanding any provision under this Act, a company shall be entitled to claim under this Act any capital allowances, investment tax credits / allowances and Act, but unutilised by the company before the commencement of this Act

existing business e.g. 1993 PSCs or existing JVs to enjoy ITC or ITA as the case may be for the life of those assets. Current draft cited below suggests it is only the unutilized portion that is grandfathered - leaving future spend on existing assets unincentivised. a. “Notwithstanding any provision under this Act, a company shall be entitled to claim under this Act any capital allowances, investment tax allowances and investment tax credits earned under any of the legislations repealed by this Act, but unutilized by the company before the commencement of this Act” 2. Similarly to what is provided for AGFA, investment tax credits / allowances shall continue to apply to projects which have been approved by the NNPC or DPR prior to the commencement of this Act.

2. Furthermore, Paragraph 8 of the Second Schedule excludes all companies already in production before PIFB from the (Production) Allowances introduced by the Act: “Subject to the provisions of paragraphs (9) and (10) of this Schedule, any company that is in, or has been in production on the commencement of this Act shall not be eligible for the allowances under this Schedule” With the removal of AGFA, the gas development incentives proposed are insufficient to grow the gas sector when gas pricing is too low to offset development cost for (dry) gas projects 3. In addition to the comment above, the Act should specify which tax rate will be applicable to the unutilised capital allowances. It goes without saying that any tax rate lower than the 85% at which the cost was incurred originally leaves the impacted tax payers worse off. 4. Investment has been taken in good faith and under existing law - the conditions should therefore not changed after the investment has been committed and is running

protecting the claims on unutilised capital allowances ,gas capital expenditure, unutilised Investment Tax Credits (ITC) with tax rate to be used, how to be allocated, etc. For avoidance of doubt, include Sections 11&12 from the PPT act in their entirety to preserve AGFA for sanctioned projects (historic and future cost). Amend 12(2) to reflect allowances retained and/or gained from Section 75


75(2) (2) The incentives granted under Sections 11 and 12 of the Petroleum Profits Tax Act which is repealed by this Act shall continue to apply to projects which have been approved by the NNPC or DPR prior to the commencement of this Act and in respect of which significant investment has been made prior to the commencement of this Act. For the purposes of this Section, significant investment means such level of investment

The provision is giving discretional power to the Commission to determine the meaning of "significant investment". The continuation of incentives should not be made conditional due to the current state of approval process in the industry. In addition, there are many non-technical risk challenges today that impact projects' take-off and progression. It would be unfair to companies

S. 75 (2) (a)- The fiscal terms provided in sections 11 and 12 of the Petroleum Profits Tax Act which is repealed by this Act shall continue to apply to projects which were committed and in existence prior to the commencement of this Act. The applicable fiscal terms are as stated in sub-section (2)(b) of this section- S. 75(2)(b)- The following incentives shall continue to apply to projects stated in (2)(a) of this

33


as determined by the Commission section for companies engaged in the production and utilisation of gas, that is; (a) investment required to separate crude oil and gas from the reservoir into usable products shall be considered as part of the oil field development; (b) capital investment on facilities equipment to deliver gas in usable form at utilisation or designated custody transfer points shall be treated, for tax purposes, as part of the capital investment for oil development; (c) capital allowances, production allowances and operating expenses on gas development and operation activities shall be allowed and chargeable as part of oil, condensate or gas development; (d) expenses incurred in the utilization of associated gas shall be allowable against crude oil operations where impracticable to separate such expenses from crude oil operations (e) companies which invest in natural gas liquid extraction facilities to supply gas in usable form to downstream projects, including aluminum smelter and methanol, Methyl Tertiary Butyl Ether and other associated gas utilisation projects shall benefit from the incentives; (f) all capital investments relating to gas-to- liquids facilities shall be treated as chargeable capital allowance and recovered against crude oil income; (g) gas transferred from natural gas facilities to gas-to-liquid facilities shall be at zero per cent tax and zero per cent royalty.


Second Schedule, Section 1 & 2(a)

the value for PA of oil is: US$3 per barrel: “There shall be a production allowance for crude oil production by a company determined as follows: (a) for onshore – the lower of US $3 per barrel or 30% of the official selling price. (b) for shallow water areas – the lower of US $3 per barrel or 30% of the official selling price. (c) for Deepwater areas – the lower of US $3 per barrel or 30% of the official selling price” (Second schedule Section 1) For gas: US$1.5 per mmbtu: “ 2. (a) There shall be a production allowance for natural

The Production Allowances introduced are insufficient as they do not reflect cost of production in each terrain. Without a significant increase the current construct will not unlock new Deepwater developments

Acknowledge that cost of production in the various environments are different and raise allowances as necessary. Second schedule Section 1 should be amended to reflect the following Production Allowance values (a) for onshore – the lower of US$5 per barrel or 30% of the Official Selling Price (b) for shallow water areas – the lower of US$7 per barrel or 30% of the Official Selling Price (c) for Deepwater areas – the lower of US$30 per barrel or 30% of the Official Selling Price

34


gas fields of 50% of the value of the natural gas production or US $ 1.5 per million Btu, whichever is lower” (Second Schedule Section 2.a)


Second Schedule, Section 6

The total amount of the allowances computed under this Schedule shall be deducted from the amount determined pursuant to Subsection (1) of Section 16 of this Act and where these allowances cannot be deducted under Subsection (1) of Section 16 of this Act owing to there being an insufficiency of or no assessable profits of the accounting period the deductions shall be added to the aggregate amount to be computed for the following accounting period of the company, and thereafter shall be deemed to be an allowance due to the company, under relevant provisions of the Third Schedule to this Act for that following accounting period

The current construct will not allow gas developments to be unlocked. (Dry) gas developments typically have higher cost than the low regulated gas price. To enable these projects additional consolidation of Production Allowances is required.

To assist in improving the economics of gas projects, we can propose that Production Allowances attributable to gas can be relieved against oil and condensates to the extent not fully absorbed by gas profits. Recommend amending the clause below: 2nd Schedule Paragraph 6- 6. "The total amount of the allowances computed under this Schedule shall be deducted from the amount determined pursuant to subsection (1) of section 16 of this Act and where these allowances cannot be deducted under subsection (1) of section 16 of this Act owing to there being an insufficiency of or no assessable profits of the accounting period the deductions shall be added to the aggregate amount to be computed for the following accounting period of the company, and thereafter shall be deemed to be an allowance due to the company, under relevant provisions of the Third Schedule to this Act for that following accounting period; provided that the gas production allowances granted under paragraph (2) that cannot be deducted under subsection (1) of section 16 of this Act owing to there being an insufficiency of or no assessable gas profits of the accounting period shall be deducted from the company’s assessable profits from oil, condensate or gas activities within the same or other terrain in which the company operates"


Second Schedule, Section 8

“Subject to the provisions of paragraphs (9) and (10) of this Schedule, any company that is in, or has been in production on the commencement of this Act shall not be eligible for the allowances under this Schedule”

The proposed Bill does not recognize that, due to the sizes of leases in Nigeria, there are many fields in leases which are undeveloped. Therefore, growth projects are typically developed more within existing leases by companies and thus incentives should be granted at project level including ability to consolidate at the contract and company levels and across produced products to assure growth and value creation.

Eliminate 9(b) Amend Section 8 8. The allowances provided in paragraphs (1), (2) and (3) of this schedule shall apply to oil, gas and condensate production from new fields and oil, gas and condensate production from new formations in existing producing fields PROVIDED such new production is pursuant to a development plan approved by the Commission

Critical improvements to Fourth Schedule, “with respect to gas exported as LNG, as the Bill introduces uncertainty trying to determine Replace Schedule 3 Section 12(b)(i) with the

35


ensure competitiveness of the PIFB

Section 12(b)(i) international LNG market price, less the LNG shipping and marketing allowance and the gas liquefaction allowance and any applicable transportation tariffs between the inlet of the liquefaction plant and the marketable gas delivery point(s) and this procedure shall be subject to the provisions of paragraph (b) of Subsection (8) of this Section. The international LNG market price and the LNG shipping and marketing allowance and shall be determined by the Commission, while ensuring a reasonable approximation of the average international fair market value of natural gas for such month”

revenue/price basis for royalty payment by introducing gas net-back pricing system for exported LNG with discretionary role for Commission (determining the market price and shipping allowance). This is expanding the core constraint of Nigeria Gas market development – regulated pricing rather than market determined. A gas royalty rate is applied to a value of gas sold, used or transferred by a company. The current drafting does not allow for the estimation of the value of gas sold by the Upstream producer to a Midstream company involved in the liquefaction and export of LNG. This is due to the opaque pricing and allowances defined at the discretion of the Commission. Furthermore, any derived price may be significantly different from the value of gas, in either a positive or negative sense, commercially sold from the Upstream to the midstream entity. This represents a risk for Upstream gas project viability. Sales to Midstream gas processing companies, including Nigerian LNG producers are domestic sales on which VAT is levied. They are not volumes exported by the Upstream and it is unreasonable to subject projects that supply volumes to this class of domestic gas buyers to additional uncertainty. The valuation for royalty purposes should be in line with the valuation provisions for other sales gas streams in the Bill.

following: “With respect to gas sold to Midstream entities to be exported as LNG, as the gas sales price pursuant to the respective gas sales agreement, less any applicable transportation tariffs between the delivery point at the inlet of the liquefaction plant and the marketable gas delivery point”. Delete the following Sections: Schedule 4, Section 13(e) Schedule 4, Section 13(f) Schedule 4, Section 13(g)


Fourth Schedule, Part III, 12(b)(ii)

with respect to gas exported by pipeline, as the gas export price pursuant to the respective international agreement, less any applicable transportation tariffs between the valuation point of the gas export price and the marketable gas delivery point in so far as the Commission shall determine that the applicable international price as well as the transportation tariffs reflect a reasonable approximation of the average international fair market value of natural gas

Like LNG above, Bill introduces uncertainty trying to determine revenue/price basis for royalty payment by introducing gas net-back pricing system for WAGP with discretionary role for Commission (determining the market price and shipping allowance). This is expanding the core constraint of Nigeria Gas market development – regulated pricing rather than market determined. West Africa Gas pipeline export contracts are long term and tariffs are governed by an independent regulator (WAGPA). Commission should have no discretionary role in determining either final sales price or tariff for royalty determination.

Delete "In so far as the Commission shall determine that the applicable international price as well as the transportation tariffs reflect a reasonable approximation of the average international fair market value of natural gas"

36

Categories Section PIFB provision (Original) Concern/justification (Original) Recommendation/suggested language

Recommendations to optimize administrative processes and methodologies

5(2)(b) & (c) (b) any cost of extraction of that oil or chargeable natural gas deducted in determining its value as referred to in paragraph (a) of this Subsection; and (c) any cost incurred by the company in transportation and storage of that oil and natural gas between the field of production and the custody transfer point.

Current wording of Sections 5(2)(b) & (c) implies that chargeable condensate has no cost of extraction or transportation

Chargeable condensate should be explicitly mentioned in these provisions


5(4) The assessable profit of an accounting period shall be the adjusted profit of that period after any deduction allowed by Section 12 of this Act.

Seems an omission in linking to Section 12 instead of Section 10

Correct linkage to refer to Section 10


6(1)(c) all royalties, the liability for which was incurred by the company during that period in respect of natural gas sold or delivered to any buyer or customer or disposed of in any other commercial manner;

Condensate royalties not included in current set-up The royalties on condensate should be recognized as tax deductible


7(1)(l) Twenty percent of any expense, incurred outside Nigeria, except where such expenditure relates to the procurement of goods or services which are not available domestically in the required quantity and quality

This Section creates oversight duplicity between the NCDMB and the Commission. Cost are already regulated by the WEN principle

Delete Section 7(1)(l)


7(k) (k) any expenditure incurred as a penalty. Penalties should be limited to government imposed penalties

Amend Section to limit non-deductibility to government imposed penalties only


15(2) & (3) 2) The amount referred to in the foregoing Subsection is, for any accounting period of a company, the amount which the chargeable tax for that period, calculated in accordance with the provisions of this Act, would come to if, in the case of crude oil exported from Nigeria by the company, the reference in Section 5 (1) (a) of this Act to the proceeds of sale thereof were a reference to the amount obtained by multiplying the number of barrel of that crude oil by the realizable price per barrel. (3) For the purposes of Subsection (2) of this Section the relevant sum per barrel of crude oil exported by a company is the official selling price applicable to that crude oil as may from time to time be advised by the Commission after

This (re-)introduces the concepts of RP vs. OSP The determination of price should not be a responsibility of the Commission. What is important, is that the price mechanism must be agreed between the Commission and tax payers. The tax payer, being the revenue earner, must be the party determining the price based on the agreed model and commission can then approve. Commentary: if this is an attempt to resolve the OSP vs. RP disputes, it needs to be reviewed and may not be relevant again given the DPR/OPTS Resolution of Dec 2018. This is important as these terms play important roles in the determination of Additional PIT and Royalty determination in the proposed Bill

Retain construct from PPTA - "fiscal price" in relation to any crude oil products exported from Nigeria means the price FOB at the Nigerian port of export of the gravity and quality in question which is from time to time established by the company after agreement with the Federal Government of Nigeria / Commission

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determination under Subsection 5 of this Section.


16 Assessment of additional petroleum income tax

It is not clear which crude oil price and gas price the provision is referring to. There are multiple crude types with different prices, and multiple gas prices. Therefore one should be picked to carry out the evaluation

Language to be more specific to make clear that it should refer to the realized price (basis for tax revenue reported for PIT)


16(4) For oil and condensate production, the maximum additional tax rate shall be 60%

Section 58 provides that Petroleum Income tax for deep offshore crude oil operations is 40%. Our understanding is the intent of Section 16(4) is to make the maximum tax rate 60%. If the max. “additional” tax rate is 60%, especially when compared to Section 16(5) below, the max. tax rate becomes a 100% for deep offshore upstream crude oil operations.

Amend language: “For oil and condensate production, the maximum total tax rate shall be 60%”


62(2) The assessable tax rate for Frontier Basin operations shall be 30% for crude oil and Upstream gas operations

Frontier is being separated from Deep Offshore Frontier basin should be properly defined, royalty suspension must be more specific and not at the discretion of the regulations issued Commission


66(4) (4) For the purposes of this Section “gas fertilizer” means the marketing and distribution of natural gas for commercial purposes and includes power plant, fertilize natural gas, gas to liquid plant, fertilizer plant, gas transmission and distribution pipelines; “tax‐free period” means the tax‐free period referred to in Subsection (1) (a) of this Section.

Unclear as to purpose of this Section. There is a second Section 66(4) with two (b) headings.

Delete first Section 66(4) as does not appear applicable and correct the second Subsection b (the first "b" should be "a")


73 (general) Periodic review We do not see the need of Section 73(1) because is virtually included in 73(2)

Reformulate to take out redundancies (1a / 2c and 1b / 2b are similar)


73(b) & 73(2)(b) (b) In the case of a new project sanctioned prior to the commencement of the new legislation, the affected company or companies have not made significant investment in respect of the project within 12 months of the commencement of the new legislation introducing the new fiscal terms. For the purposes of this Section, significant

The provision is giving discretional power to the Commission to determine what “significant investment” means

Add exception to this clause "provided that no force majeure items have prevented investments to be spend" Remove the word "significant" before investments as it introduces unclarity and replace with "any" Delete the section "For the purposes of this Section, significant investment means such level

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investment means such level of investment as determined by the Commission.

of investment as determined by the Commission."


77 “Commission” means the Petroleum Regulatory Commission established under the Petroleum Industry (Governance and Institutional Reforms) Bill. (a) any rights to participation in the operation and or development of the PML by the Fund; or (b) financing obligations of petroleum operations in the PML by the Fund; or (c) pre-emption rights at a swap, re-assignment and/or divestment of the PML by any of the equity holders.

Subsections (a), (b) and (c) do not have any relationship with the definition

Delete Subsections (a), (b), (c)


77 Interpretation ―Midstream Petroleum Operations‖ means activities Downstream of the Measurement Point(s) of Petroleum Licenses, or unrelated to Petroleum Licenses, OPLs or OMLs with respect to the construction and operation of facilities for heavy oil; construction and operation of crude oil transport pipelines, including the related pumping stations; acquisition, operation, leasing, rental or chartering of barges, coastal or ocean going tankers, rail cars and trucks for the transport of crude oil; construction, leasing and operation of crude oil tank farms and other storage facilities; construction and operation of refineries; other construction and activities incidental thereto and related administration and overhead.

There is no mention of gas infrastructure and assets in the definition of Midstream petroleum operations. In the draft Petroleum Industry Administration Bill there is a separate Midstream gas operations definition

Update definition to clarify qualification of gas infrastructure and assets and ensure consistency with Petroleum Industry Administration Bill


First Schedule, Section 19

Table: “ii) Intangible well cost shall be deemed as 75% of the total well cost”

Not appropriate to give a standard rate for every well. Intangible cost may vary depending on the type of drilling, therefore sometimes not meeting the 75% and other times being more

Delete sentence: the tangible / intangible split should be based on actual cost –


Second schedule, Section 2(j)

Omission in numbering Correct Section numbering Correct Section numbering


Second schedule, Section 4

The reserve replacement ratio, for calculating additional production allowance, shall be determined and certified by an independent expert recognized by the Commission, and subject to verification by

RRR will vary depending if SPE and SEC calculation is adopted.

It may be prudent to specify the approach to be used by the independent expert so that companies use the same framework.

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the Commission.


Fourth Schedule, Part II, Section 2

Every Petroleum Exploration License ("PEL") and Petroleum License ("PL") shall be subject to a rent as determined by a regulation by the Commission

Setting of rent for licenses and leases is left at the discretion of the Commission

In determining the rates the commission should follow a transparent process including stakeholder consultation


Fourth Schedule Part III, Section 6(1)

All production of petroleum, including production tests shall be subject

to royalties on a non-discriminatory basis with respect to all Licensees.

Royalty shall be determined based on a Licence.

Royalties are calculated at License level, compared to Production Allowances which are calculated at a field level, creating significant administrative complexity for the operators

Royalties should be calculated at field level


Fourth Schedule, Part III, Section 8

The measurement point(s) referred to in paragraph 10 of this schedule shall be determined by a regulation to be issued by the Commission

Measurement point for fiscal purposes to be set in future regulation could have significant technology and cost implication – should be at point of sales. Also, measurement point should account for losses due to security issues. Commission should not have the discretionary power to set the measurement point

Fiscal measurement point should be at point of sales (i.e. after treatment and / or processing when the product is merchantable and marketable)


Fourth Schedule, Part III, 12(c)(i,ii,iii)

for domestic markets, the value of the marketable gas at the marketable gas delivery points shall be determined: (i) for gas supplied under wholesale gas contracts pursuant the provisions of the Petroleum Industry Administration Act for the contracted prices, provided such prices reflect fair market value as determined by the Commission, less any applicable transport costs between the point of sale and the marketable gas delivery point, where the point of sale is not the marketable gas delivery point. Where a Licensee provides gas under more than one wholesale gas contract, the price shall be the weighted average price of such contracts; (ii) for gas supplied under the Domestic Gas Supply Obligation, the aggregate gas price as adjusted from time to time by the applicable regulations, and (iii) where the Commission determines that competitive markets exist in Nigeria, the price determinations pursuant to paragraphs (i) and (ii) of this paragraph shall be replaced

Gas price is already regulated in the Petroleum Industry Administration Bill. Methodologies introduced in these Sections are administratively complex

Royalties should be based on revenues reported for PIT

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by a reference price at the appropriate gas market location, determined by the Commission; and


Fourth Schedule, Part III, Section 14

Commission to establish procedure for determining production, official selling price and the value of natural gas The detailed procedures for determining the production, official selling price and the value of natural gas pursuant to this Section shall be established by regulation issued by the Commission.

Section is redundant Should be deleted as it is redundant


Fourth Schedule, Part III, 15

Measurement point and measurement of product; crude oil, condensates and natural gas production shall be measured at the point(s) where the Commission determines that petroleum leaves the petroleum licence area prior to transportation. Where no measurement takes place at these point(s) the Commission on its own initiative or at the request of the Service shall require the Licensee to install the necessary measurement equipment at such point(s). In exceptional cases the Commission, with the consent of the Service, may permit the measurement at another location, provided that production volumes and values pursuant to this Section shall be calculated back to the point(s) that the Commission determines to be the point(s) where the petroleum leaves the petroleum licence area;

Measurement point should coincide with the point that product is marketable

15(a) should state measurement point should be point of sales (i.e. after treatment and / or processing when the product is merchantable and marketable) Delete Section 15(b)


Fourth Schedule, Part III, Section 17(1)

The total royalty rate shall be the royalty rate based on average monthly daily production pursuant to paragraph 3 of this schedule plus the royalty rate based on the average monthly value pursuant to paragraph 4 of this Schedule.

Does not refer to anything in the Bill Delete reference to average monthly value royalty rate and change Paragraph 3 to Paragraph 18

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Additional recommendations to for PSC Assets in the Shallow water with a water depth beyond 100m


Enable SW PSC assets 77 “Deep Offshore” means areas offshore Nigeria with a water depth in excess of 200

meters;

Update the definition of “Deep Offshore” in line with the provisions of the Deep-Water Block Allocation to Companies (Back-in Rights) Regulations, 2003

Deep offshore blocks mean those concessions for the exploration and /or exploitation of petroleum in which all or part are in waters deeper than 200 meters

Enable SW PSC assets Second schedule, section 1(b)

1(b) for shallow water areas – the lower of US $3 per barrel or 30% of the official selling price.

Assets between 100-200 m water depth are more complex than more shallow waters (<100 m) and Production Allowances need to be in line with the risk

and complexity of the assets.

Introduce special Production Allowances for assets between 100-200 m water depth

Enable SW PSC assets Schedule four, 18(2)

for shallow water areas: Tranches (kbpd) Royalty Rate First 10 5.0% Next 10 10.0% Next 10 15.0% Above 30 20.0%

Assets between 100-200 m water depth are more complex than more shallow waters (<100 m) and royalties need to be in line with the risk and complexity of the assets

Introducing special Royalty for assets between 100-200 m water:

Tranches (kbpd) Royalty Rate First 20 5.0% Next 20 10.0%

Above 40 15.0%

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Additional recommendations to enable Deepwater Non-Associated Gas (DW NAG) developments


Enable DW NAG Developments

Second Schedule 2(a), 2(j)

2(a) There shall be a production allowance for natural gas fields of 50% of the value of the natural gas production or US $ 1.5 per million Btu, whichever is lower

2(j) There shall be a production allowance for the development of dry gas fields of 100% of the value of the natural gas production or US $ 1.5 per million Btu, whichever is lower

Proposed production allowance insufficient to unlock Deepwater non-associated gas developments

Combine section 2(a) and 2(j) to read:

2. There shall be a production allowance for natural gas fields of 100% of the value of the natural gas production or US $ 2.5 per million Btu, whichever is lower


62, 62(1) 62(1) The Minister of Petroleum Resources upon the recommendation of the Commission

may by an Order published in a gazette grant suspension of royalties for operations in

Frontier Basin for a period of time

Deepwater non-associated gas operations require same type of incentives as frontier operations

62 (1) The Minister of Petroleum Resources upon the recommendation of the Commission

may by an Order published in a gazette grant suspension of royalties for Frontier Basin and Deep Offshore Non-associated gas operations for a period of time

In all other instances in section 62 replace “Frontier Basin” by “Frontier Basin and Deep Offshore Non-associated gas”


4(6) 6(4) Companies engaged in upstream gas operations shall be entitled to a tax-free period of five years commencing from the date of production provided that the provision of this subsection 6 shall not apply to a company to which subsections 2 and 3 of section 75 apply

Strategic Deepwater non-associated gas operations require additional incentives

6 (4) B Companies engaged in strategic upstream deep offshore gas operations, shall in addition to the incentives under 6a) be entitled to an additional tax-free period of ten years commencing from the date of production provided that the provision of this subsection 6 shall not apply to a company to which subsections 2 and 3 of section 75 apply

© Copyright 2019 Oil Producers Trade Section (OPTS)

The Oil Producers Trade Section (OPTS) is the umbrella body for private upstream oil and gas

companies in Nigeria under the Lagos Chamber of Commerce and Industry, a company limited

by guarantee.

This document contains proprietary information of OPTS and is intended for internal use by you

and your company. Do not reproduce, disclose, or distribute the information contained herein

without OPTS’s express prior written consent. Nothing herein is intended to serve as investment

advice or a recommendation of any particular transaction or investment, the merits of purchasing

or selling securities, or an invitation or inducement to engage in investment activity. While this

document is based on sources believed to be reliable, OPTS does not warrant its completeness

or accuracy.

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