SPE-203740-MS

Implications of Petroleum Industry Fiscal Bill 2018 on Heavy Oil Field

Economics

Adaobi Stephenie Nwosi-Anele, Department of Petroleum Engineering, Rivers State University; Omowunmi
Illedare, University of Cape Coast, Institute for Oil and Gas Studies, Ghana; Oyebimpe Adeogun, Emerald Energy
Institute, University of Port Harcourt

Copyright 2020, Society of Petroleum Engineers

This paper was prepared for presentation at the Nigeria Annual International Conference and Exhibition originally scheduled to be held in Victoria Island, Lagos, Nigeria,
11 - 13 August 2020. Due to COVID-19 the physical event was not held. The official proceedings were published online on 11 August 2020.

This paper was selected and peer reviewed for presentation by an SPE program committee following review of information contained in an abstract and paper submitted
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this paper without the written consent of the Society of Petroleum Engineers is prohibited. Permission to reproduce in print is restricted to an abstract of not more than
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Abstract
Recent increase in energy demand has made necessary the exploitation of Nigerian heavy oil fields neglected
in the 1990s. These heavy oil fields were neglected due to low oil price and lack of technology to aid their
recovery. Stakeholders in the heavy oil sector have been divided over what fiscal framework applies for the
exploitation of Nigerian's heavy oil. The Nigerian Oil Industry has a well-developed fiscal framework for
light and medium oil exploitation and the Proposed Petroleum Industry Fiscal Bill (PIFB) 2018. This work
studies the economics of an onshore heavy oilfield under the PIFB 2018, to examine the implications of
heavy oil exploitation using the PIFB 2018 as a fiscal policy. Field production profiles showing exponential,
harmonic and hyperbolic field decline patterns were developed to represent 25.38% recovery factor for a
heavy oil field of 196MMSTB OIIP. Deterministic models were built featuring the fiscal instruments of the
PIFB 2018, heavy oil price, capital expenditure, operating expenditure and economic metrics. The stochastic
model featured the impact of heavy oil price, capital expenditure, price escalation rate, discount rate, and
peak production on the contractor's and host government takes for the PIFB 2018. Our stochastic results
show that the output variables are most sensitive to heavy oil price, discount rate and capital expenditure.
The petroleum industry fiscal bill 2018 is found to be an efficient fiscal policy for the host government and
contractor, giving take statistics of 49% and 51% respectively. Varying oil price and discount rate did not
make the investment unprofitable but reduced the investment ranking. Exponential decline behavior proved
most profitable, while hyperbolic decline proves least profitable. Adjustments of two fiscal instruments of
the PIFB was made to enable contractors produce heavy oil using unconventional recovery method and
remain in business during periods of low heavy oil price.

INTRODUCTION
Fiscal terms and instruments of petroleum fiscal policies have been the main enticement for attracting
investors into the domain of any oil and gas producing country. The terms and conditions of the working
fiscal policy of a particular oil and gas producing country define the contract conditions for a willing investor.
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Although these terms and conditions may vary depending on terrain, region and reserve size (Nwosi-Anele
et al, 2018). They are either a concessionary or contractual fiscal policy. The Proposed Petroleum Industry
fiscal policy is a contractual fiscal policy because it is a production sharing contract. It allows contractor
and host government to share profit oil split. The fraction of profit oil split accrued both host government
and contractor is clearly stated in the terms of the contract. Cost recovery limit and Profit oil split are the
major fiscal instruments that differentiate the contractual fiscal policy from a concessionary fiscal policy.
Only about 1% of Nigeria's heavy oil reserve has been harnessed since the inception of the oil industry in
Nigeria (Eremiokhale, 2013). Hence fiscal policies for heavy oil recovery are not clearly defined as stated by
Lawal, (2014). Increased demand for energy and technological advancement has made the heavy oil reserves
long neglected to be economically viable and recoverable (Eremiokhale, 2013). However, the profitability
of heavy oil exploitation to host government and contractor is clearer when there is an economic policy to
govern it. Our paper would expose the implication of the most recent fiscal bill (PIFB 2018) in Nigeria on
the economics of a heavy oil field.

OVERVIEW OF FISCAL POLICIES

Globally Petroleum Fiscal Policies are classified into two; Concessionary Fiscal Policy and Contractual
Fiscal Policy.

• Concessionary Fiscal Policy

The government of the oil and gas producing nation owns the rights but transfers title of the oil to
the oil and gas company that have successfully acquired the lease or acreage. This is the oldest form
of fiscal policy that has existed; it is sometimes referred to as Royalty and Tax system. It is modified
by country to suit their local terminologies and expectations. In Nigeria, the concessionary fiscal
system exists as the joint operational agreements (JOA). According to Iledare, (2004) the Joint
venture agreement (JOA) Nigeria is a modification of the concessionary system. About 95% of
onshore and shallow water fields in Nigeria are operating on the royalty and tax system. The host
government shares equity of about 55% to 60% with the contractor. Though the royalty and tax
fiscal regime is the oldest fiscal regime, countries like India and Brazil are changing their royalty
and tax system to production sharing contracts (Onwuka et al, 2012). According to Adenikinju
and Oderinde, (2009) the basis for this change is to create favorable investment incentive for the
contractor and increase host government take. The concessionary system in Nigeria has different
versions. They are the Royalty and Tax 1993, 2000, and 2005
• Contractual fiscal policy
The government retains the rights and ownership of the oil and gas resources. The oil and gas
companies are entitled to the production or revenue from the sale of the oil or gas in accordance to
the contracts signed after obtaining license to develop and produce (Mian 2002). The Contractual
fiscal policy is categorized into two:
• Production sharing contract (PSC)
Production sharing contract was first practiced in Indonesia in the year 1966 (Johnston, 2003).
Produced oil is shared between host government and contractor in a stipulated percentage, which
is referred to as profit oil. The components of this fiscal regime are royalty, tax, cost oil, profit oil.
Other payments include bonuses, rents and cryto fees, (these are ways the host government extracts
more many from the investors to meet local needs of its nation, an example is the NDDC levy and
education fund). Nigeria's production sharing contract was first introduced in 1993 to address the
limitations of the joint operating agreements (a modified royalty and tax system) and to create a
fairer fiscal regime for contractors who were given license for exploration in Nigeria's deep water
frontier. The PSC has about 3 versions since its first emergence; they are PSC 1993, 2000, and
2005 and the proposed petroleum industry bill.
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• Service contracts
This fiscal regime engages the contractor to do the service. The contractor is paid for services
done after which the lease is handover to the host government. Service contracts are further sub-
categorized into:
1. Pure service contracts
2. Risk service contracts
They are both the same but the later ties the service charge to the profit generated from the
acreage hence it may be more profitable for the contractor if the recovered hydrocarbon is large.
The existing fiscal policies of the Federal Government of Nigeria have limitations that should be
addressed. The limitations in the existing fiscal policies led to the advent of the Petroleum Industry
Bill in 2008. The proposed petroleum industry bill was first presented to the 6th Assembly in 2008.
Since its advent in 2008, it has continued to receive strict critics and reviews that led to release of
different version of the same bill in 2012, 2016, 2017 and 2018, which is the most recent version.
The 8th Assembly divided the PIB into four parts. They are:

◦ The Petroleum Industry Governance Bill

◦ The Petroleum Industry Host Community and Impact Bill

◦ The Petroleum Industry Fiscal Bill

◦ The Petroleum Industry Administration Bill

Proposed Petroleum Industry Fiscal Bill 2018

The Petroleum Industry Fiscal Bill is a production sharing contract. It has the features of a PSC. The PIFB
has provisions for Oil, Gas and Condensate production as follows:

Royalty
Royalty is the first cash expense made to the government by the contractor when production of oil or gas
begins. It is a fraction of the gross revenue generated by the contractor upon the sale of oil and gas. Royalty
in the PIFB 2018 is deduction for all production volumes including test/appraisal wells. Royalty may be
deducted in cash or in kind depending on the decision of the Minister and the Federal Inland Revenue
Commission. The contractor is informed 90 days in advance, when the host government decides to receive
royalty payment in kind. The 2018 version of the PIFB presents a sliding scale royalty deduction. The royalty
deduction is tied to daily production rates of oil or gas at varying rates for onshore, shallow water and deep
offshore. This is similar to the royalty deduction presented in the 2008 and 2012 version of the jettisoned
PIB. The 2017 version of royalty presented a dual royalty deduction style; royalty deduction by volume of
oil and gas produced and royalty deduction by value (price) of oil and gas which was also jettisoned for
the most recent 2018 version of the PIFB.
The 2018 version presented royalty deduction tied to tranches as shown in Table 1.
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Table 1—Royalty by Tranches of the Proposed Petroleum Industry Fiscal Bill, 2018

Tax
Tax is a stipulated amount of money paid to the government by investors in a host country, salary earners,
and users of utilities. In the oil and gas industry, tax is a fixed deduction a contractor pays to host government
based on the term and conditions of their contract agreement. The petroleum industry fiscal bill 2018 refers
to tax as the petroleum income tax (PIT), separate tax deductions are made for oil and gas investments. PIT
presents two patterns of tax deduction. They are the assessable tax and the chargeable tax.

Assessable Tax
The provisions of the assessable tax are as follows:

• 65% of onshore area crude oil profit

• 50% of shallow area crude oil profit

• 30% of onshore area natural gas profit

• 30% of shallow area natural gas profit.

Chargeable Tax
The provision of the chargeable tax is as follows: if crude oil price exceeds $60/bbl or gas exceeds $6/
MMBtu, the contractor would be made to pay an additional petroleum income tax at the rate of 0.5% for
every $1 oil price increase. A maximum of 60% additional tax rate per increase in oil price above $60/bbl
is applicable for oil and condensate gas exploitation. Gas product is taxed an additional maximum of 5%.
All other service providers of the contractor are charged under the Companies' Income Tax Act.
Tax deduction differs with terrain. Taxation for deep offshore basin is as follows:

• 40% for deep offshore upstream crude oil operations

• 30% for deep offshore upstream gas operations.

Incentives or partial tax holidays in the PIFB 2018 are at the discretion of the minister of petroleum
resources, in such conditions, 30% of taxable income shall be allowed for crude oil and upstream gas
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operations. The corporate income tax is applied for midstream operations to encourage investment in the
midstream sector, operators of upstream sector that venture into midstream are allowed:

• Tax free period of five years

• Capital allowance of 90% and 10% retention for plants and machinery

• Tax free dividends during tax holidays.

This is different from the 2017 version of the PIFB that provides a dual tax deduction (40% national
hydrocarbon tax and 30% corporate income tax) at the same time in the project life.

Capital allowance rates

The PIFB allows the following capital allowances rates:

• Exploration well expenditure - 100% in the first year only.

• Appraisal well expenditure - 100% in the first year only.

• Intangible well capital expenditure - 100% in the first year only.

• Intangible well expenditure is considered to be 75% of the total well cost.

• Tangible well capital expenditure - 20% for years 1-4 and 19th in the 5th year.

• Facilities capital expenditure - 20% for years 1-4 and 19th in the 5th year.

• Infrastructure capital expenditure - 20% for years 1-4 and 19th in the 5th year

Production Allowances
The production allowance for the 2018 PIFB is different compared with the 2017 version of the PIFB. In
this version, production allowance is not tied to production volume. The details are as follows:

• Onshore - $3/bbl or 30% of the oil price

• Shallow water - $3/bbl or 30% of the oil price

• Deep water - $3/bbl or 30% of oil price

• 50% of the value of natural gas production or $1.5/MMbtu is allowed for investment in associate
and condensate gas production.
• Dry gas fields are allowed a 100% of value of dry gas production or $1.5/MMbtu to end gas flaring.

Bonuses, Fees and Rentals

Bonuses, Rents and Fees in the PIFB are determined based on negotiation between Government and
Contractor. All of which depends on the kind of license (Petroleum License or Petroleum Exploration
License).
The PIFB was drafted with light and medium oil in view, no provisions for heavy oil. Lawal, (2014)
tried to study the economics of heavy oil-bitumen recovery and discovered that there was no fiscal policy
to govern the recovery of Nigeria's Heavy oil. The heavy oil sector has been neglected in terms of the
provisions of a suitable fiscal regime to encourage investors and stakeholders. Most stakeholders resort to
application of the fiscal instruments of the Nigerians Minerals and Mining Act 2007 as a fiscal regime for
heavy oil (Ayodele and Odumah, 2017). They opine that heavy oil could be regarded as a mineral resource.
Others apply the Royalty and Tax for heavy oil recovery. The proposed petroleum Industry fiscal bill, 2018
is yet to be passed into a law; it is necessary that provisions for the exploitation of heavy oil be included in
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the bill, since the bill has provisions for light oil, natural gas and condensate. In order to advise government,
contractor and stakeholders appropriately, we carried out an elaborate economic study both deterministic
and stochastic modeling to check the how the fiscal instruments in the PIFB 2018 affects the profitability
of a heavy oil field declining either exponentially, harmonically and hyperbolically.

DETERMINISTIC ECONOMIC MODELLING

A deterministic cash flow model is a discounted cash flow model that incorporates time value of money
into a cash flow built on a spreadsheet. Cash flow model subtracts all disbursements (cash flow outwards)
from receipts (Cash flow inwards).
(1)
The cash flow model is expressed for contractor and host government as follows:
(2)
(3)
To determine the profitability of the investment, profitability indicators such as net present value, which
is the present value of the cash flow and the internal rate of return, which is the discount rate at which the
net present value is exactly equal to zero, were imposed on the cash flow model as shown in equations
(4) and (5).

(4)

Where:
 NPV = Net present value
 NCF = Net Cash Flow
 t = the project's economic life
 id = discount rate

(5)

Where:
 IRR = Internal rate of return
 NPV = Net present value
 NCF = Net Cash Flow
 t = the project's economic life
 id=discount rate

Input Parameters of the Deterministic Model

Field Production Profile
The field production profile generated throughout the field life is converted to cash-inflows upon the
sales of heavy oil. This becomes the gross revenue on which the economics of the field is analyzed. Our
Deterministic model incorporates a field production profile of an onshore field of about 196MMSTB OIIP.
Reservoir history showed that 25.38% of the OIIP is recoverable via artificial lift methods. The field
production profile featured the buildup, plateau and decline phases. Arp's equation (Arps, 1945) was used
to calculate the buildup, plateau and decline flow rates. The buildup flow rate is exponential because it is at
the discretion of the oil field operator to influence the field's buildup behavior. The decline phase featured
three different decline behaviors; exponential, harmonic and hyperbolic and the flow rates were calculated
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using the expressions in Table 2. This is because the economics of heavy oil exploitation is not limited
to a particular decline behavior and an oilfield is likely to decline either exponentially, harmonically or
hyperbolically.

Table 2—Arps Equation for Calculating the Decline Phase of a Field

Comparative study of decline behaviors and how they affect the profitability of the heavy oil field under
the influence of the PIFB 2018 was done in this study.

Heavy Oil Price

Globally heavy oil is priced lower than light and medium oil. Between 2008 and 2018, there was an average
of $17 discount on the price of Western Canadian Select (WCS) compared to Western Texas Intermediate
(WTI). There is a North-American Phenomenon that is discounts heavy oil by 30% to 50% of crude oil
price (Lewis and Jacob, 2016). A proposed $10 differential between the prices of the Nigerian Bonny light
and the Nigerian heavy crude is used for our economic model. This is because literature has established
that there is a difference between the prices of light crude oil and heavy crude oil and the least difference
observed is about $10.
Other input parameters of the deterministic cash flow model are presented in Table 3 and Table 4
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Table 3—Field Development and Cost Estimate

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Table 4—Fiscal Incentives for PIFB 2018

STOCHASTIC ECONOMIC MODELLING

Our stochastic model studies the impact of heavy oil price, peak production, capital expenditure, discount
rate and price escalation rate on the host government's take and contractor's net present values. The input
variables were assigned possible frequency distribution to model their likely behavior (see Appendix A7).
Dual simulations of 5000 iterations were carried out to ensure exactness and accuracy of our stochastic
results.
The stochastic model has the following assumptions for the input variables:
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1. Peak Production: The peak production is assigned a normal distribution because mean, median and
mode values are always the same ant the most likely value revolves around the mean.
2. Capital expenditure: The capital expenditure is a cost object and it is assigned a triangular distribution
because from history, it is likely to deviate slightly from the mean value.
3. Heavy Oil Price: Heavy Oil price is always likely to deviate from the mean value hence it is assigned
a triangular distribution.
4. Discount Rate: Scholars may argue that discount rate is not stochastic but the fact that a variation
in discount rate affects the profitability of the investment makes it stochastic. Authors like Iledare
and Fubara, (2017) and Echendu et al, (2012) has assumed discount rate as stochastic in their
economic analysis. Therefore, the probability distribution assigned to the discount rate is a lognormal
distribution because it always revolves around the mode and is always positive.
5. Oil price escalation is assigned a lognormal distribution because it revolves around a mean value and
it is always positive.
The output variables are:
1. Host Government Take ($MM)
2. Contractor's Take ($MM)

MODEL RESULTS AND ANALYSIS

Deterministic Model Results and Analysis
Varying heavy oil price and discount rate between $20 - $55 and 15% - 25% on the deterministic model,
it was discovered that the heavy oil field investment presented positive net present values for contractor
and host government as seen on Table 5. The internal rate of return (IRR) is above the discount rate
for exponential and harmonic decline patterns; except for hyperbolic production decline than presents an
internal rate of return of 18%, when the investment discount rate was varied to 25%. This indicates that if
the field is declining hyperbolically, the investor may not be able to repay the capital, if the investment is
funded by a 100% borrowed capital at 25% interest rate.

Table 5—Performance of Profitability Indicators on Varying Heavy Oil Price, Discount Rates and Decline Patterns
SPE-203740-MS 11

Results indicate that the heavy oil field investment is sensitive to the methods of production decline.
Our stochastic results present P10, P50 and P90 values of both host government and contractor takes. It is
observed that the investment remained profitable under all scenarios as the net present value is positive for
all production decline methods as seen on Table 6.

Table 6—Output Distribution for Stochastic Analysis

Results from our stochastic model indicate that the heavy oil field is sensitive to volatility of heavy oil
price, discount rate, price escalation rate and capital expenditure as shown in Appendix. The deterministic
model has shown NPVs for contractor and host government at periods of varying oil price. Therefore if the
investment is sensitive to heavy oil price volatility the deterministic model show that at prices as low as
$23/bbl for heavy oil, the heavy oil field investment remains profitable for all decline scenarios. However
because the investment presents an internal rate of return of 18%, which is lower than the discount rate
of 25% at $23/bbl heavy oil price when the field is declining hyperbolically, a production allowance of
$3/bbl is incorporated in the fiscal instrument of PIFB 2018 for the contactor as an incentive to allow the
contractor remain in business at periods of heavy oil price lower than $25/bbl. The investment is seen to be
sensitive to the capital expenditure; the paper suggests that capital allowance be allowed for the contractor
at development phase to leverage the huge capital cost of heavy oil exploitation especially when complex
tertiary recovery methods are needed for heavy oil recovery.

CONCLUSION
In our paper, the implication of the fiscal instruments of the petroleum industry fiscal bill 2018 was
studied to check the implication on a heavy oil field economics. We discovered that the heavy oil field
economics remained profitable when imposed with the fiscal terms and condition of the PIFB at heavy oil
price (between $53 and $23) and high cost of capital (discount rate between 15% and 25%). However we
discovered that the profitability of the field is sensitive to the type of production decline method that the field
exhibits. It is on this premise that we suggest that the government may adopt the PIFB 2018 for recovery
of heavy oil in Nigeria, if these two fiscal instruments are modified; (1) capital allowance for the investor
when complex recovery methods are needed for heavy oil recovery. (2) A $3/bbl production allowance is
allowed for the investor during the production decline period when heavy oil price is $25/bbl.
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It is important to note that the least heavy oil price ($23/bbl) studied in this paper is greater than $21/bbl
which is the unit technical cost of producing a barrel of heavy oil. Stakeholders in the heavy oil industry
should push that the PIFB 2018 be passed into law and be used as a fiscal policy for heavy oil recovery in
Nigeria with the modification here suggested.

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Contracts: A Meta Modelling Analysis. In 14th Annual Conference of African Econometric Society.
Arps J.J. (1945): Analysis of Decline Curves. Trans., AIME 160, 228 – 247
Ayodele, O. R., and Odumah, G. (2017): Economics of a 1,000-B/D In-Situ Bitumen Project in Southwestern Nigeria.
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Echendu, J. C., and Iledare, O. O. (2016): Progressive Royalty Framework for Oil-and Gas-Development Strategy:
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Nwosi-Anele, A. S., Adeogun, O., and Iledare, O. (2018): Analysis of Government and Contractor Take Statistics in the
Proposed Petroleum Industry Fiscal Bill. Society of Petroleum Engineers. doi:10.2118/193470-MS
Onwuka, E. I., Iledare, O. O., & Echendu, J. C. (2012, January). Evaluating the Impact of Depreciation Methods and
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APPENDIX A1

Figure 1—Sensitivity Analysis of Host Government Take on Exponential Decline.

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APPENDIX A2

Figure 2—Sensitivity Analysis of Contractor's Take on Exponential Decline Pattern

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APPENDIX A3

Figure 3—Sensitivity Analysis of Host Government Take on Harmonic Decline Pattern

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APPENDIX A4

Figure 4—Sensitivity Analysis of Contractor's Take on Harmonic Decline Pattern

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APPENDIX A5

Figure 5—Sensitivity Analysis of Host Government Take on Hyperbolic Decline Pattern

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APPENDIX A6

Figure 6—Sensitivity Analysis of Contractor's Take on Hyperbolic Decline Pattern

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APPENDIX 7

Frequency Distribution for Input Data on Stochastic Model