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PETROLEUM REVENUE
SPECIAL TASK FORCE
FINAL REPORT
SUBMITTED TO:
THE HONOURABLE MINISTER OF
PETROLEUM RESOURCES,
FEDERAL REPUBLIC OF NIGERIA
AUGUST 2012
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The Honourable Minister of Petroleum Resources
Federal Ministry of Petroleum Resources
Abuja
August 2012
Our Reference:
Your Reference:
Report of the Petroleum Revenue Special Task Force
We have pleasure in reporting the conclusion of the assignment given to the
Petroleum Revenue Special Task Force (PRSTF) in accordance with its Terms of
Reference as laid out at the inauguration of the Task Force. We enclose our final
report of work done together with our key findings and recommendations.
Our overall approach has been prescriptive and consultative with various stakeholder
groups within the Petroleum Industry providing in our estimation a unique opportunity
to address some long standing issues that affect the industry.
This is our final report of the assignment. Accordingly, this report supersedes earlier
copies used for presentations and discussions.
We take this opportunity to thank all the Government Agencies and Private
Organisations in the Petroleum Sector who assisted us by providing us with
information and documentation from the Operator's records.
We appreciate the opportunity given to us to be of service to the Ministry and the
Nation on this most important assignment.
Yours faithfully,
Mallam Nuhu Ribadu Olasupo Shasore SAN
Chairman, PRSTF Member/Secretary PRSTF
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EXECUTIVE SUMMARY .................................................................. 4
1. BACKGROUND AND OVERVIEW ............................................. 4
1.1. BACKGROUND ......................................................................... 4
1.2. OVERVIEW .............................................................................. 4
2. TERMS OF REFERENCE OF THE TASK FORCE .................... 4
2.1. INTRODUCTION ........................................................................ 4
2.2. MEMBERS OF THE TASK FORCE ................................................ 4
3. SCOPE AND WORK DONE ....................................................... 4
3.1. WORK APPROACH ................................................................... 4
3.2. LIMITATIONS AND CONSTRAINTS ................................................ 4
3.3. SUBCOMMITTEES' MEMBERSHIP AND TERMS OF REFERENCE ...... 4
4. REVENUE REVIEW AND DEBT VERIFICATION ...................... 4
4.1. INTRODUCTION ........................................................................ 4
4.2. PRODUCTION ........................................................................... 4
4.3. DOMESTIC CRUDE SALES ......................................................... 4
4.4. EQUITY CRUDE OIL SALES ....................................................... 4
4.5. SALE OF THE NATIONAL ENTITLEMENT (GAS) ............................. 4
4.6. SALE OF REFINED PETROLEUM PRODUCTS ................................ 4
4.7. NNPC AND ITS SUBSIDIARIES .................................................... 4
4.8. TAXES ..................................................................................... 4
4.9. SIGNATURE BONUS .................................................................. 4
4.10. CONCESSION RENTALS ......................................................... 4
4.11. ROYALTIES (CRUDE OIL AND GAS) ......................................... 4
4.12. GAS FLARE PENALTIES ......................................................... 4
4.13. MISCELLANEOUS OIL REVENUES ............................................ 4
5. REVENUE LOSSES IN THE NIGERIAN PETROLEUM
INDUSTRY ........................................................................................ 4
5.1. OVERVIEW .............................................................................. 4
5.2. SECURITY ISSUES AND THEFT IN THE NIGERIAN PETROLEUM
REVENUE VALUE CHAIN .................................................................... 4
5.3. PIONEER STATUS GRANTED TO INDIGENOUS COMPANIES ............ 4
5.4. COLLATERAL SOCIAL COSTS OF THEFT ..................................... 4
6. DEBT COLLECTION .................................................................. 4
6.1. DEBT ANALYSIS ....................................................................... 4
6.2. DEBT COLLECTION EFFORTS .................................................... 4
6.3. DEBT RECONCILIATION ............................................................. 4
7. CROSS DEBT MATRIX .............................................................. 4
7.1. DEBT MATRIX SCHEMATIC ........................................................ 4
7.2. DEBTS PROFILE ....................................................................... 4
8. AUTOMATION AND TECHNOLOGY INTEGRATION ............... 4
8.1. INTRODUCTION ........................................................................ 4
8.2. SUMMARY OF WORK DONE ....................................................... 4
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8.3. FINDINGS ................................................................................ 5
9. RECOMMENDATIONS ............................................................... 5
9.1. INTRODUCTION ........................................................................ 5
9.2. STRATEGIC MANAGEMENT RECOMMENDATIONS ......................... 5
9.3. TRANSITION MECHANISMS ........................................................ 5
9.4. REVENUE AND DEBT VERIFICATION ........................................... 5
9.5. REDUCING REVENUE LOSSES IN THE NIGERIAN PETROLEUM
INDUSTRY ......................................................................................... 5
9.6. AUTOMATION OF THE NIGERIAN PETROLEUM INDUSTRY .............. 5
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LIST OF ABBREVIATIONS/ ACRONYMS
AF ALTERNATIVE FINANCING
BPD BARRELS PER DAY
CA CARRY AGREEMENT
CBN CENTRAL BANK OF NIGERIA
COMD CRUDE OIL MARKETING DIVISION
COSM CRUDE OIL STOCK MANAGEMENT
DPR DEPARTMENT OF PETROLEUM RESOURCES
EFCC ECONOMIC AND FINANCIAL CRIMES COMMISSION
EIA ENERGY INFORMATION ADMINISTRATION
ERP ENTERPRISE RESOURCE PLANNING SYSTEM
FAAC FEDERAL ACCOUNTS ALLOCATION COMMITTEE
FGN FEDERAL GOVERNMENT OF NIGERIA
FIRS FEDERAL INLAND REVENUE SERVICE
FMF FEDERAL MINISTRY OF FINANCE
GTL GAS TO LIQUID
HAGF/HMJ HONOURABLE ATTORNEY GENERAL OF THE FEDERATION/
HONOURABLE MINISTER OF JUSTICE
IOC INTERNATIONAL OIL COMPANY
IT INFORMATION TECHNOLOGY
JOA JOINT OPERATING AGREEMENT
JV JOINT VENTURE
LNG LIQUEFIED NATURAL GAS
LOC LOCAL OIL COMPANY
LPG LIQUEFIED PETROLEUM GAS
MCA MODIFIED CARRY AGREEMENT
MPR MINISTRY OF PETROLEUM RESOURCES
NAPIMS NATIONAL PETROLEUM INVESTMENT MANAGEMENT SERVICES
NCS NIGERIA CUSTOMS SERVICE
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NDR NATIONAL DATA REPOSITORY
NEITI NIGERIAN EXTRACTIVE INDUSTRIES TRANSPARENCY INITIATIVE
NGL NATURAL GAS TO LIQUIDS
NLNG NIGERIA LIQUEFIED NATURAL GAS
NNPC NIGERIAN NATIONAL PETROLEUM CORPORATION
NPMS NATIONAL PRODUCTION MONITORING SYSTEM
NXP NATIONAL EXPORT PROCESSING
OAGF OFFICE OF THE ACCOUNTANT GENERAL OF THE FEDERATION
OPTS OIL PRODUCERS TRADE SECTION
OSP OFFICIAL SELLING PRICE
PIB PETROLEUM INDUSTRY BILL
PMO PROJECT MANAGEMENT OFFICE
PPMC PIPELINE PRODUCTS AND MARKETING COMPANY
PPPRA PETROLEUM PRODUCTS PRICING REGULATORY AGENCY
PPT PETROLEUM PROFITS TAX
PRSTF PETROLEUM REVENUE SPECIAL TASK FORCE
PSC PRODUCTION SHARING CONTRACT
TOR TERMS OF REFERENCE
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Executive Summary
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The Petroleum Revenues
Special Task Force carried out a
review of the Nigerian Petroleum
Industry with a view to fulfilling
its Terms of Reference as
inaugurated by the Honourable
Minister of Petroleum
Resources.
Executive Summary
Background
The Honourable Minister of Petroleum Resources, driven by
the need to strengthen the institutions responsible for
Petroleum Revenue Management, commissioned the
Petroleum Revenue Special Task force (PRSTF) on 28
February 2012. The goal of the Task Force was to support
the programme of the Federal Government of Nigeria in
enhancing optimization, probity and accountability in the
operations of the Petroleum Industry.
As part of this agenda and the issues arising from the various
fiscal regimes existing in the sector, there arose an urgent
need to establish the streams of revenue flows from the
Petroleum sector to the Federal Republic of Nigeria and
design systems and processes which would enhance the
accountability of each agency or entity.
The assignment of the Special Task Force is contained in its
Terms of Reference and covers the entire Petroleum Value
Chain. Accordingly, the Task Force set out to confirm if
existing systems, laws, processes and functions across the
value chain provide reasonable assurance that revenues
from the Petroleum Industry are captured, complete,
recorded intact, properly accounted for and that revenue due
is demanded and collected.
Terms of Reference
At the inauguration of the Petroleum Revenue Special Task
Force, the following Terms of Reference (ToR) were
communicated:
1. To work with consultants and experts to determine and
verify all petroleum upstream and downstream revenues
(taxes, royalties, etc) due and payable to Federal
Government of Nigeria;
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2. To take all necessary steps to collect all debts due and
owing; to obtain agreements and enforce payment terms
by all oil industry operators;
3. To design a cross debt matrix between all Agencies and
Parastatals of the Ministry of Petroleum Resources;
4. To develop an automated platform to enable effective
tracking, monitoring and online validation of income and
debt drivers of all Parastatals and Agencies in the
Federal Ministry of Petroleum Resources;
5. To work with world-class consultants to integrate systems
and technology across the production chain to determine
and monitor crude oil production and exports, ensuring at
all times, the integrity of payments to the Federal
Government of Nigeria; and
6. To submit monthly reports for ministerial review and
further action.
Scope and Methodology
Since its inauguration, members of the PRSTF have
approached the assignment with all the seriousness that it
deserves. In carrying out its ToR, one of the initial activities
performed by the PRSTF was to obtain both written and
verbal presentations from the various stakeholder groups
within the Petroleum Industry. This was to enable the Task
Force to understand the challenges faced and the type of
reforms that are required. This was all carried out with a view
to determining and optimising the nation's revenue streams
from all sectors within the industry.
The Task Force members also visited and reviewed selected
agencies and operators, supported by the Consultants, for
the period spanning 1 January 2005 to 31 December 2011 in
line with the Statute of Limitations. Two workshops were also
held to aid information gathering process with respect to key
issues of Metering and Measurement in the Oil & Gas Sector
Value Chain, and Security in the Oil and Gas Sector.
Apart from several plenary meetings to receive briefings,
analyse gathered information and deliberate on findings, the
Task Force also operated through constituted two (2) ad-hoc
subcommittees to conduct a detailed review of NNPC's and
DPR's roles in petroleum revenue management. Five (5)
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standing subcommittees were also formed and conducted
detailed assessments followed with recommendations in
specific areas relevant to the overall ToR. Specifically in
pursuance of ToR 2, the Task Force through the Security and
Enforcement Subcommittee also liaised with relevant
agencies to validate the status of outstanding debts identified
in the course of the forensic review, and to demand
payments where deemed necessary.
Revenue Review and Debt Verification Findings
The Task Force in pursuance of ToR 1 and 2 conducted
activities to determine and verify all Petroleum Upstream and
Downstream Revenues due and payable to Nigeria; and took
all necessary steps to collect all debts due and owing.
It was determined that the main petroleum revenues due to
the national treasury in respect of oil and gas activities in
Nigeria are:
Domestic Crude Oil Sales, Equity Crude Oil Sales, Gas
Sales, Refined Petroleum Products sales, Profits from NNPC
subsidiaries, Petroleum Profits Tax, Company Income Tax,
Signature Bonus, Concession Rentals, Royalties from Oil and
Gas, Gas Flare Penalties, and Miscellaneous Oil Revenues.
The Task Force's key findings are presented below according
to these revenue streams.
1. Proceeds from the sale of Domestic Crude Oil
As at 31 December 2011, N843 million
1
was due to the
Federation in respect of Domestic Crude Oil allocations. The
amounts outstanding as at 31 December 2011 represent
amounts due for the months of September 2011 to December
2011. In view of the 90-day credit period, the outstanding
amount as at 31 December 2011 was not due for payment.
The Task Force received representations from the NNPC and
other relevant agencies on the Corporation's practice of
deducting amounts for subsidy-related expenses prior to
remittance of these revenues. In the course of the Task
Force's work, we did not receive sufficient justification for the
practice which does not accord with the law, with particular
reference to the Constitution.
1
PRSTF is aware that further settlement should now have reflected providing figures as
at April 2012
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Our review of the records received for 2002 to 2011 showed
an inconsistent pattern in the implementation of the policy to
allocate 445,000bpd allocation to NNPC, with variances
found for the ten years reviewed.
The Task Force also compared the average price per barrel
payable by NNPC for Domestic Crude with the average
weekly prices for Nigeria Bonny Light, Forcados, obtained
from the Energy Information Administration (EIA). The review
revealed that over a 10 year period (2002 ÷ 2011), the State
may have been short paid by an estimated sum of US$ 5
billion, although it was understood from discussions with
NNPC officials that the pricing of domestic crude oil was
based on international prices. Enquiries from NNPC revealed
that up until October 2003, NNPC was granted fixed price
regimes which explain the wide disparity in prices in the
earlier years.
The Task Force found that the exchange rates used in
arriving at the Naira equivalent of the amounts payable
differed from the CBN rates for six (6) of the ten (10) years
reviewed. The potential underpayment of amounts payable to
the Federation Account over the 10- year period is estimated
at N86.6 billion. Also, the Task Force's review of the
domestic crude utilisation showed that the percentage not
refined in- country ranged from between 50% to 88% over
the 10 year period.
2. Proceeds from Equity Crude Oil Sales:
Equity Crude represents government's share of crude oil
production (excluding domestic crude) obtained mainly from
three (3) arrangements: Joint Operating Agreements (JOA)
with IOCs, Production Sharing Contracts (PSC) and Service
Contracts. Equity Crude Oil proceeds are remitted into the
Federation account as export proceeds, DPR accounts as
Royalties and FIRS accounts as Petroleum Profit Tax.
The Task Force observed that there is no single point
accountability for the income and expenditure streams of
upstream petroleum operations, compounded by the current
structure of NNPC such as multiple roles executed through
NAPIMS and its COMD.
A decline was also observed in national investments that
would increase the nation's proven reserves. Accordingly,
despite the increase in crude oil production in Nigeria over
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the years, the nation's entitlement has decreased as a result
of various alternative funding arrangements for its upstream
investments.
The Task Force found that legislation governing the industry
and agreements with third parties are outdated, do not reflect
current economic or legal realities; or include ambiguous
clauses. Also, there are some provisions within the legislation
that could significantly improve government's revenue that
the government is yet to take advantage of. Examples
include a provision to ensure that the share of the
Government of the Federation in the additional revenue shall
be adjusted under the Production Sharing Contracts if the
price of crude oil at any time exceeds $20 per barrel; and the
requirement for a periodic review of provisions in specified
time frames.
It was also observed that some traders lifted crude oil
although they were not listed on the approved master list of
customers who had a valid contract and were selected
through an annual bidding process. The Task Force research
also found that quite a number of traders did not demonstrate
renowned expertise in the business of crude oil trading.
Furthermore, the Task Force found that the use of crude oil
traders was contrary to the global trend wherein national oil
companies develop their own trading arms, such as the
various NNPC trading subsidiaries which currently have
limited capacity. The Task Force identified various concerns
in this area with Nigeria being the world's only major oil
producer that sells 100 percent of its crude to private
commodities traders, rather than directly to refineries.
Various submissions to the Task Force demonstrated the
potential for lost margins to middlemen, manipulation of
pricing, suboptimal returns and market fraud as emanating
from this policy and practice.
A review of NAPIMS's audited financial statements as at 31
December 2009 showed that Joint Venture cash calls
payable was N459.568billion. Since 2006, government has
not allocated enough funds to cover these amounts and
NNPC has entered into a range of borrowing arrangements
referred to as Alternative Financing Arrangements with the
costs of financing this debt (estimated at around 8%)
continuously mounting. This cycle will continue to increase in
the coming years unless a systemic solution is found.
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As JV partners there is a need for the effective management
and oversight of oil companies' operating costs which affects
revenues accruable to Nigeria. There is also a clear training,
technology and human capacity gap between NAPIMS staff
and their counterparts in the private oil and gas sector.
3. Proceeds from the Sale of the National Entitlement
(Gas):
The Task Force aided by the Consultants identified a total of
N137.572 billion ($946.878 million) due to the Federation
from SNEPCO representing the proceeds of gas sales from
the Bonga oil field; according to the NNPC (NAPIMS)
Financial Statements for the year ended 31 December 2009.
For Liquefied Natural Gas, the price observed at which the
feedstock gas is sold to NLNG seems too generous,
compared to prices obtainable on the international market.
The estimated cumulative of the deficit between value
obtainable on the international market and what is currently
being obtained from NLNG, over the 10 year period, amounts
to approximately US$29 billion.
4. Proceeds from Sale of Petroleum Products:
From the Task Force's review, NNPC is owed N27billion
including current debt, total overdue, disputed debt and total
debt outstanding, by the major marketers of petroleum
products. We also found that amounts payable to suppliers of
petroleum products, as at 31 December 2011 amounts to
approximately US$3.6 billion, of which US$2.7 billion
represents amounts outstanding for over 365 days. The Task
Force also observed that pipeline product loss has steadily
increased over the years.
5. NNPC and Subsidiaries:
From review of the latest available audited financial
statements (2009) it was noted that NNPC has sixteen (16)
subsidiaries. The financial performance of the Corporation
and its subsidiaries in 2009 shows the Group had a deficit of
approximately N298billion for the period. Various reviews
conducted by the Task Force showed that the NNPC does
not receive the required capital to grow its assets or meet
operating costs. NNPC has therefore increasingly relied on
the FGN for lines of credit, and deduction of oil revenue due
to the Federation Account. In our review, the legal basis for
this practice was unclear.
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6. Signature Bonus:
The Task Force found that discretionary decision-making in
the award of oil blocks can result in revenue losses for
Nigeria. Our review also showed that the management of
past bid rounds has resulted in lower demand and fewer
qualified bidders, uncompleted deals weakened government
returns, and lower development of acreage.
The DPR provided the task force with information indicating
that 67 licenses were awarded between 1 January 2005 and
31 December 2011; with an outstanding balance of $566
million unpaid in signature bonuses. For the 7 discretionary
allocations reviewed, the Task Force found $183million
outstanding and due to the nation's treasury. We were
however informed that of the total $749m outstanding in
signature bonuses, $321m was legally disputed.
7. Concession Rentals:
The Task Force found that $2.9million represents outstanding
amounts to be collected by the DPR from the various
concessionaires. However, we also observed inconsistencies
in records provided by DPR in respect of information and
schedules regarding the list of concessions.
8. Royalties (Crude Oil and Gas):
The Task Force found that $3.027billion was outstanding
from the operators for crude oil royalties as at 31 December
2011 per the DPR's records. Of this amount, the DPR had
stipulated that ADDAX is liable to pay $1.5billion royalties
under the 2003 fiscal regime and there is currently a dispute
between Addax and NNPC on the one hand, and the DPR on
the other. In the course of the review, the Task Force also
encountered differences in records of payments made to the
CBN vis-à-vis DPR records, and lack of independent gas
production and sales data.
9. Gas Flare Penalties:
The Task Force found that the DPR is currently unable to
independently track and measure gas volumes produced and
flared and depends largely on the information provided by the
operators.
We also observed that the periodic reconciliation meetings
with the operators to address the gas flare volumes were
delayed with only 6 completed of 36 at the time of our review.
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The total revenue from gas flaring during the review period
was $175million with the balance outstanding as unpaid was
approximately $58million indicating that $115million had been
received by the DPR. We however reviewed payments
received by the CBN in respect of gas flare penalties.
However a review of CBN records showed that $137million
was received between 1 January 2005 and 31 December
2011. The DPR was not able to reconcile the $115 million to
the $137million.
Lastly, operators have not compiled with the recent
Ministerial directive signed on 15 August 2011 increasing the
gas penalty fee from N10.00 to $3.50. The operators have
continued to flare gas at the rate of N10 and records at the
DPR reveal that none of the companies have paid any gas
penalty fee in 2012.
10. Miscellaneous Oil Revenues:
The Task Force was unable to obtain a comprehensive
miscellaneous oil revenue schedule from the officials of the
DPR, although a review of CBN's records provided some
information albeit with unexplained variances. The amounts
due in respect of the various fees relating to the
miscellaneous oil revenues are also not reflective of the
current economic realities.
Revenue Losses in the Nigerian Petroleum Industry
The Task Force identified sources of revenue losses in the
industry, with a view to identify opportunity areas for major
reform in boosting resources obtainable from the sector for
national development. These include the following.
1. Crude Oil Theft and Associated Revenue Losses:
Hydrocarbon theft was found by the Task Force as being a
major and chronic source of revenue loss to Nigeria. Theft of
crude oil and refined petroleum products may be reaching
emergency levels in Nigeria.
The Task Force observed various estimates by International
Oil Companies and Government officials of the scale and
volume of crude theft which ranged from 6 to 30 percent of
production. While the Task Force does not endorse any of
the numbers it received, we note that it could actually be as
high as 250,000 barrels per day closer to 10% of daily
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productions amounting to as high as N1 trillion annually. This
issue therefore requires immediate attention.
2. Lost Refined Products and Associated Revenue
Losses
The Task Force did not receive comprehensive figures
documenting volumes of refined products stolen or spilled.
NNPC reports that thieves stole 3.2 million metric tons of
products from its pipeline network between 2001 and 2010
and that about 40 percent of products currently channelled
through pipelines are lost to theft and sabotage.
PPMC also recorded 4,468 product pipeline breaks in 2011,
98 percent of them from sabotage; and values the products
stolen from its pipeline network between 2001 and 2010 at
N178 billion.
3. NNPC Withholdings for Costs Associated With Theft
and Sabotage
NNPC withholds oil revenues from the Federation Account to
cover costs associated with theft and pipeline sabotage.
4. Pioneer Status granted to Indigenous Companies
The Task Force was informed that at least five companies:
Allied Energy, Midwestern Oil & Gas, Brittania Oil Nigeria
Limited, Suntrust Oil Company Nigeria Limited; and Niger
Delta Petroleum Resources Limited2 have been granted
pioneer status by the Nigerian Investment Promotion
Commission (with others pending or undetected) for their
exploration and production activities.
The Task Force finds that the granting of pioneer status to oil
operators for an activity that is well established for over 40
years inappropriate. The loss of revenue from the grant of
pioneer status to oil operators is an avoidable loss and it is
recommended that any such further consideration be stopped
forthwith and the current ones set aside and or revoked.
1.Collateral Social Costs of Theft:
The Task Force also found that certain social costs
emanated from crude oil theft and considered them important
and requiring urgent attention. These include environmental
2 The argument that the status is appropriate for "exploration¨ and not "production¨ is
untenable and self-defeating because once it is accepted that "production¨ is "already
being carried on¨ in Nigeria the same goes for "exploration¨
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pollution and its socioeconomic impacts, armed piracy, and
lost investment in the sector leading to revenue losses.
Debt Collection
Based on the detailed review of outstanding debts owed to
the Federation, the Task Force determined outstanding
amounts for royalties, signature bonuses and concession
rentals. Pursuant to an initial understanding of ToR 2 of the
PRSTF, relevant government agencies were invited to assist
in a debt collection drive, and invitation and demand letters
were sent to over 47 oil companies allegedly indebted to the
nation. We have recommended that government pursue
debts further in any manner deemed appropriate.
However during the debt reconciliation exercise, the sum of
USD$5,830,261 was paid into the treasury of Government
with evidence of payment, while several companies made
undertakings to pay at later dates.
Automation of the Nigerian Petroleum Industry
The Task Force identified Information Technology and
business automation gaps, by carrying out Current Position
Assessments of the stakeholders within the Oil and Gas
production value chain, including government regulatory
parastatals. The assessment scope covered three broad
categories namely Core Business Systems, Reporting
Capabilities and Automation Capabilities of these entities.
Our findings showed that there were evident automation gaps
in the oil and gas value chain specifically in key agencies
under the Ministry of Petroleum Resources/ Department of
Petroleum Resources that are vested with the mandate to
produce Oil and Gas, licence, keep and update records,
supervise petroleum industry operations and ensure payment
of rent and royalties.
Additionally, the PRSTF reviewed the state of metering and
measurement in Nigeria's oil and gas value chain vis-à-vis
best practices. The challenges identified with the current
metering and measurement regime can be summarised as a
lack of adequate vision and ownership required to articulate
and drive a cohesive implementation of IT and Automation in
MPR and DPR.
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The Task Force identified the following specific challenges
with the metering and measurement regime:
• Dependence on manual data gathering processes
• Low level infrastructure at remote locations
• Lack of regular and systemic well testing
• Inadequate data and IT infrastructure among industry
players
• Inadequate MIS reporting and dashboard capabilities in
existing systems
• Disparate systems with differing data, nomenclature
among operators
• Diverse data requirements from Government agencies
• Multiple and strong stakeholders with divergent interests
The Task Force also found inconsistent oil and gas data
across the petroleum industry. These inconsistencies in
information were sighted across the major agencies and
parastatals of the MPR as well as with the oil and gas
operators themselves.
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Recommendations
In order to address the findings and issues above, the Task
Force has developed the following recommendations which
Government should implement to address the issues
identified and their root causes.
1. Strategic Management Recommendations
From a strategic viewpoint of the Task Force's review and the
findings discussed above, the Task Force recommends the
following:
• Set up a process, independent of NNPC, to review the
use of oil traders and NNPC's system for selling
crude, on grounds of value for money and probity.
• Undertake a strategic review of all NNPC subsidiaries
before the PIB passes, with a view to privatizing,
repositioning or scrapping non-performing, redundant
or irrelevant business units.
• Require a full public report by NNPC of the amount,
cost and terms of all cash call debts; improve reporting
of this information to the National Assembly as part of
the annual budget and oversight process.
• Pass an oil sector transparency law that requires all oil
companies active in Nigeria to report all payments,
costs and earnings for each license or transaction,
and to publish all contracts and licenses.
• Create a special, properly-trained Oil and Gas Sector
Financial Crimes Unit for law enforcement
3
.
• Appoint a new NEITI Board, now long overdue.
Members should be sector experts with a commitment
to transparency, and civil society should appoint
independent representatives.
• Establish an embedded and independent "office of
transformation¨ for the sector with a fixed term and
3
The EFCC is one government agency with skill sets to develop this specialised area of
law enforcment
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specific mandate to carry through recommendations
and transformational reforms accepted by
government.
• Implement an aggressive debt collection process for
outstanding signature bonus payments; revoke blocks
from non-paying firms; sanction those agencies that
failed to collect.
• Conduct an independent process audit of all upstream
cost control rules and mechanisms, including the use
of cross-country price benchmarking.
• Amend the 1984 Special Tribunal (Miscellaneous
Offenses) Act to strengthen the legal framework for oil
theft and other sector crimes.
• Arrest and prosecute perpetrators and financiers of
illegal bunkering rings.
2. Production
• Production data for fiscal purposes should be obtained
at the flow stations where crude oil is stabilised and
not at the terminals as is currently the practice.
3. Domestic Crude Sales
• No deductions should be made from the amounts
payable to the Federation Account.
• Domestic crude oil should be sold at international
competitive prices.
• FGN should block leakages in the conversion to
finished goods process of NNPC.
• There should be full compliance by NNPC with
prevailing CBN exchange rates for remittance of crude
oil proceeds.
• The Federal Government should revisit the Domestic
Crude Oil Business Model
4. Equity Crude Oil Sales
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• Restructure NNPC for single point accountability for
Petroleum Revenues
• National investment in the oil and gas upstream sector
must be managed from a strategic focal point
• Ensure full compliance of all agencies and companies
with existing legislation
• Regularise Crude Oil Lifting Under Contract
• Ensure open competitive selection process for crude
oil sales
• Review the nominations process for all the Joint
Ventures
• Ensure and institute proper review of all draft
contractual agreements
• Adequate funding of the Federation's investment
obligations
• Create standard terms and conditions and uniform
terms of contract agreements
• Proper and realistic budgets and approvals should be
prepared annually
• Capacity Building should be embarked upon for
NAPIMS in terms of optimal number and appropriate
skills and training level of staff
• Ensure uniformity of the realisable prices used by all
parties
• Carry out adequate review of the purchase or lease
option for production equipment
5. Sale of the National Entitlement (Gas)
• Draw up master agreements for the development of all
potential gas reserves in Nigeria
• FGN should ensure that written consents exist for gas
for all assets
• FGN should intensify efforts to get the other LNG
projects up and running
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• FGN to carry out a comprehensive review of its
NGL/LPG entitlements under the Agip and Shell Joint
Ventures
6. Signature Bonus
• The FGN should expedite action with respect to the
blocks in dispute in order to ensure that the
$321million outstanding is collected.
• DPR should take further actions against the
concessionaires that are yet to pay the amounts due
($167million) within the remit of the law.
• Proper record keeping should be enforced at the DPR
7. Concession Rentals
• DPR should take action and enforce collections of the
amounts due of $2.9million within the remit of the law.
• The DPR should put in place measures to ensure
consistency and accuracy of custodial information
relating to oil and gas concessions
8. Royalties (Crude Oil and Gas)
• DPR should take action and enforce collections of the
amounts due of $3.027billion from relevant operators
within the remit of the law.
• DPR should make a demand for the outstanding
Addax/NNPC Royalties' payments of approximately
$1.5billion on behalf of the Federal Republic of Nigeria
and the consequences of default should immediately
be visited on the contract and the relevant parties.
• DPR should instruct the CBN and operators to ensure
the proper description of all revenue remittances in
order to facilitate easy reconciliation.
• DPR should independently track and record gas
production and sales data
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• DPR should ensure that all reconciliation process with
all the outstanding gas producing companies is
concluded before the beginning of the next fiscal year.
9. Gas Flare Penalties
• DPR should independently track and record gas flare
volumes
• The reconciliation process should be expedited for all
operators to ensure timely collection of the gas flare
penalty amounts due.
• DPR should take action and enforce collections of
amounts due as gas flare penalties within the remit of
the law.
• Enforce the new gas flare penalty directive as a
disincentive to gas flaring.
• The FGN should put more effort in enforcing a zero
gas flare policy by the beginning of the next fiscal
year.
10. Miscellaneous Oil Revenues
• The DPR should employ the use of proper IT systems
and databases to keep its records and ensure
consistency and integrity of information across the
organisation.
• The Fee and Licensing regimes for operating in the Oil
and gas sector should be reviewed to reflect the
current economic realities in the Oil and Gas industry
11. Removing the Source and Outlets of Revenue Losses
• Explore Fingerprinting of Nigeria Oil to enable
tracking.
• Establishment of a transparent whistle blowing and
information portal as an independent and transparent
repository of information on petroleum revenue losses,
sabotage, and illegal activity.
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• Implement a deliberate policy on market ban of
participants in crude oil theft
• The Fiscal Responsibility Act 2007 should be
amended to criminalize withholding payment of
petroleum revenue after due date and assessment
and a notice of demand.
12. Automation of the Nigerian Petroleum Industry
1. Department of Petroleum Resources
• The DPR should work with Galaxy Backbone and
competent consultants to review on-going projects,
NDR and NPMS, and also develop a strategic IT
blueprint for the organization.
• DPR and MPR should commence the implementation
of a portal that aggregates and presents in real time all
relevant information about the operations and
performance of the oil and gas industry.
• An ERP Solution should be put in place to capture and
automate the identified backend processes in DPR.
• DPR, based on its mandate should build a Data
Warehouse which would serve as a hub for gathering
vital data about the industry and disseminating reports
in various formats to government stakeholders. A
framework and implementation roadmap to full
automation of measurement and metering should be
developed in a collective effort involving DPR and the
operators with oversight from MPR.
2. Nigerian National Petroleum Corporation
• The implementation of SAP should be expedited to
fully automate key processes especially relating to
revenue generation, processes feeding and pulling
data to external parties.
• The NNPC's culture, end user work ethics and
employee resistance to change all need to be
managed extensively for the SAP implementation to
be a full success.
• The SAP implementation should be independently
monitored from the Ministry to track and ensure that
the strategic objectives are met.
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3. Central Bank of Nigeria
• A quick win solution would be to study and automate
the NXP forms with a view to track shipments and
track repatriation of export proceeds.
• The existing CBN systems should be interfaced with
other systems in the various relevant agencies in
order to provide an overview of all revenue reporting
and enable timely reconciliation between
organizations.
1. Nigeria Customs Services (NCS)
• The existing NCS system should be integrated with
other systems in the various relevant agencies in
order to provide an overview of all revenue reporting
and enable timely reconciliation between
organizations.
1. Full automation of the Petroleum Industry
The PRSTF has recommended a way forward for the full
automation of the Petroleum Industry. Key features of the
proposed metering and measurement regime in particular are
shown below.
Figure A: Features of Proposed Metering and Measurement Regime
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Background
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The Petroleum Revenue Special
Task Force was set up by the
Honourable Minister of
Petroleum with a view to
enhancing probity and
accountability in the Petroleum
Industry.
1. Background and
Overview
1. Background
The Honourable Minister of Petroleum Resources, driven by the
need to strengthen the institutions responsible for Petroleum
Revenue Management, commissioned the Petroleum Revenue
Special Task force (PRSTF) on 28 February 2012. The goal of
the Task Force was to support the programme of the Federal
Government of Nigeria in enhancing optimization, probity and
accountability in the operations of the Petroleum Industry.
As part of this agenda and the issues arising from the various
fiscal regimes existing in the sector, there arose an urgent need
to establish the streams of revenue flows from the Petroleum
sector to the Federal Republic of Nigeria and design systems and
processes which would enhance the accountability of each
agency or entity.
The assignment of the Special Task Force is contained in its
Terms of Reference and covers the entire Petroleum Value Chain
(see Figure 1). Accordingly, the Task Force set out to confirm if
existing systems, laws, processes and functions across the value
chain provide reasonable assurance that revenues from the
Petroleum Industry are captured, complete, recorded intact,
properly accounted for and that revenue due is demanded and
collected.
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Figure 1: Schematic of the Petroleum Value Chain (Source: KPMG)
In recent times, various studies and public commentary are
replete with the alleged low optimisation of the nation's strategic
assets in Oil and Gas reserves and questionable practices within
the Petroleum Industry. This has led to a degree of dispute with
regards to Nigeria's production information, local consumption
figures and remittances to the national treasury and how the
proceeds are utilised.
Technical and commercial conditions in the sector also argue for
maximizing returns from oil and gas. For example, the Task
Force received submissions indicating that in the next three years
government's contractual share of profits in most PSCs is due to
rise around five percent. While it is hoped that passing the
Petroleum Industry Bill (PIB) will unlock investment, the overall
trend (without intervention) in oil revenue receipts is toward
decline, for three main reasons.
First, future demand for Nigerian hydrocarbons looks increasingly
mixed. Supply disruptions due to trouble onshore÷oil theft in
particular÷is increasingly limiting attractiveness and investments.
Observers contend that Nigeria has may have dropped an
opportunity to be a top LNG exporter, given more proactive
investments by Asian producers and the rise of shale gas in
America. Overall, foreign direct investment in Nigeria's oil sector
reduced considerably in the last five years.
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Second, low investment and an uncertain operating environment
could stagnate the sector. Exploration in Nigeria has reduced:
three exploratory wells were drilled in 2011, down from more than
20 in 2005. NNPC reports that output from aging onshore wells is
falling 10 to 12 percent a year. Production offshore has been
bridging the gap but may soon plateau from lack of new projects
and disappointing exploration results.
Industry analysts forecast production could drop 20 percent by
2020 without additional investment. Current average daily
production is barely at 2005 levels. Reserves and production
grew marginally over the past decade, with Nigeria falling well
behind its Sub Saharan African neighbours as shown in Table 1
below:
Table 1: Growth in reserves and production, 2000-2010
Country
Reserves Production
2000 2010 % growth 2000 2010 % growth
Angola 6,000 13,500 125 746 1,851 248
Chad 900 1,500 66 0 122
Congo-B 1,700 1,900 11 254 292 15
EG 800 1,700 112 91 274 301
Sudan 600 6,700 1000+ 180 475 264
Nigeria 29,000 37,200 28 2,155 2,402 10
Third, the Nation's per barrel profits from oil are also shrinking.
As reservoirs age, there is need to drill more wells and use
costlier technology to keep fields producing. NNPC estimates
that by 2014, US$3.7 billion in new drilling costs would be needed
annually to simply retain current production levels. Growing use of
alternative finance mechanisms reduces government's take
onshore. Nigeria also earns less per barrel offshore than it does
on land, such that its increased reliance on offshore fields creates
a revenue gap.
The current period is thus a pivotal one in the life of the nation's
Petroleum Sector. Without reforms in oil revenue management,
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Nigeria will struggle to keep its status as Africa's leading oil
producer and its goal of becoming one of the world's top 20
economies. However, proactive commitment to reforms now
could catalyse sector growth and yield ample funds for national
development.
This Report of the Petroleum Revenue Special Task Force is
therefore structured to present its key findings and
recommendations on the review of the Nigerian Petroleum Sector
in terms of major challenges in revenue generation and
outstanding debt, revenue loss areas, a cross debt matrix, and
automation in the production value chain. Our recommendations
have been made to address lapses and leakages; and remedial
mechanisms that need to be implemented.
Within the limited time given to the Special Task Force it has had
to prioritise its work to ascertain the items with the highest
revenue impact or significance, and bring out the more compelling
recommendations to support decisions that will propel the desired
transformation of the Petroleum Sector.
2. Overview
1. The Nigerian Petroleum Industry
Nigeria is the home to substantial deposits of oil and gas
resources. The country's proven oil reserves totalled 37.2billion
bbls as of January 2010, according to the US Energy Information
Administration. Nigerian Government sources claim that reserves
may actually be as high as 38.2billion bbls. However, due to lack
of transparency in reporting, key statistics on Nigeria's
hydrocarbons industry vary widely and are often coloured by
different interests. Still, Nigeria's deposits are regarded
internationally as the tenth ÷ largest in the world and the second
largest in Africa after Libya.
Nigeria's oil is prized for its purity. Export blends are Bonny Light
and sweet crudes, which require less refining and are thus more
lucrative. The oil typically fetches more on global markets than
Brent Crude, the global benchmark oil that is extracted from the
North Sea.
Despite the fact that the country's reserves are substantial, crude
oil production faces serious challenges such as Nigeria's inability
to meet its funding obligations to the joint ventures (JVs). Nigeria
also faces the challenges which include social unrest in
production areas, wilful damage to the pipeline network and crude
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oil theft to name a few. In 2008, Nigeria's output was enough to
rank it as Africa's largest producer, but since 2009 the country's
production has been occasionally surpassed by Angola.
Nigeria also has the ninth ÷ largest proven gas reserves
worldwide, at about 5.2trn cu meters, according to government
figures. Like its oil, Nigeria's gas is high quality and low in
sulphur. Of the total, 2.7trn cu meters is associated gas mixed in
with oil deposits. Non ÷ associated gas, which is more valuable
because it does not require separation from crude, amounted to
about 2.5trn cu meters.
One of the main issues relating to Nigeria's gas market is gas
flaring. Before 1999, most gas was flared due to lack of demand.
In 2004, both Chevron and Sassol signed gas-to-liquid (GTL)
agreements and Mobil decided to reduce flaring to 10% by 2004.
Since then, alternatives to liquefaction and exporting have
emerged in the form of electricity projects, petrochemicals plants
and other industrial uses. However, supply constraints have
blocked growth in gas use due in part to a lack of distribution
infrastructure.
These constraints have resulted in significant gas flaring in
Nigeria. The US National Oceanic and Atmospheric
Administration show that Nigeria flared 14.9billion cu ft (10.6%) in
2008 making the country the world's second biggest gas flaring
nation after Russia, which burned 40.2 cu ft.
The country's downstream sector is also plagued with various
challenges. Nigeria imports most of its refined petroleum products
due to inadequate refining capacity in-country. Officials of the
Pipelines and Products Marketing Company Limited (PPMC)
submitted to the Task Force that Nigeria owns four (4) refineries
with a combined capacity of 445,000bpd. In addition, for the
purpose of distribution, Nigeria has 5,120km of pipelines, 23
storage depots, 8 LPG depots, 24 pump stations, 2 offshore
jetties (Atlas Cove and Escravos) and 4 Jetties (Apapa, Warri,
Okrika and Calabar). However, the four (4) refineries are in poor
shape and currently operate at about 30% capacity due to poor
maintenance, fire damage, crude oil theft, and other issues.
Domestic consumption of Nigerian crude oil is low ÷ about
200,000bpd, or around 15% of total petroleum products
consumed.
There are well known and frequently documented challenges to
the downstream sector which include frequent wilful damage to
the pipeline network, refined product theft, inadequate storage
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tanks, high demurrage costs, and alleged fraudulent practices
relating to government subsidies.
The government agency overseeing and representing the
interests of Government in the oil and gas sector is the Nigerian
National Petroleum Corporation (NNPC). The NNPC is the
national oil company, but performs several other functions as
well, serving as energy sector regulator, joint venture partner in all
onshore operations and the nation's primary source of income.
The Department of Petroleum Resources, a separate body under
the Ministry of Petroleum Resources, conducts the bidding rounds
for exploration blocks and tends to be regarded as the technical
regulator.
This introduction gives a glimpse of some of the issues and the
case for change in the Petroleum Sector. The next section
describes the terms of reference of the Special Task Force and
the work approach adopted. An international firm of consultants
and auditors Pricewaterhouse Coopers (PwC) was engaged to
support on the forensic reviews and data gathering.
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Terms of Reference
of the Task Force
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The Federal Government of
Nigeria approved the
appointment of Mallam Nuhu
Ribadu, as chair of a 20-member
Petroleum Revenue Special
Taskforce inaugurated by the
Honourable Minister of
Petroleum Resources.
1. Terms of Reference of
the Task Force
1. Introduction
At the inauguration of the Petroleum Revenue Special Task
Force by the Honourable Minister on February 28, 2012, the
following Terms of Reference (ToR) were communicated:
1. To work with consultants and experts to determine and
verify all petroleum upstream and downstream revenues
(taxes, royalties, etc) due and payable to Federal
Government of Nigeria;
2. To take all necessary steps to collect all debts due and
owing; to obtain agreements and enforce payment terms by
all oil industry operators;
3. To design a cross debt matrix between all Agencies and
Parastatals of the Ministry of Petroleum Resources;
4. To develop an automated platform to enable effective
tracking, monitoring and online validation of income and
debt drivers of all Parastatals and Agencies in the Federal
Ministry of Petroleum Resources;
5. To work with world-class consultants to integrate systems
and technology across the production chain to determine
and monitor crude oil production and exports, ensuring at all
times, the integrity of payments to the Federal Government
of Nigeria; and
6. To submit monthly reports for ministerial review and further
action.
The Task Force over the period of its activities constantly
reviewed the TOR to ensure that it properly understood its
Terms of Reference and to ensure that it activities fell within its
TOR. There was some difficulty with interpretation of TOR
number 2 which states that the Task Force was "To take all
necessary steps to collect all debts due and owing; to obtain
agreements and enforce payment terms by all oil industry
operators¨. It was initially interpreted to mean literally that the
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Task Force was to take all necessary steps to collect due debts
and to enforce payment which necessitated invitation to law
enforcement agencies to assist with such recovery. However
the eventual position taken was that appropriate
recommendation would be made to government on necessary
steps to collect due debts and enforcement of payment to
enable government decision on that matter prior to collection
and enforcement action.
2. Members of the Task Force
The membership of the Petroleum Revenue Special Task
Force is as follows:
• Mallam Nuhu Ribadu - Chairman
• Mr. Steve Oronsaye - Deputy Chairman
• Mallam Abba Kyari - Member
• Ms. Bennedikter Molokwu - - Member
• Mr. Olasupo Shasore, SAN - - Member/
Secretary
• Mr. Anthony Idigbe, SAN - - Member
• Mr. Anthony George-Ikoli, SAN - Member
• Dr. (Mrs) Omolara Akanji - Member
• Dr. Olisa Agbakoba, SAN - - Member
• Prof. Olusegun Okunnu - Member
• Pastor Ituah Ighodalo - Member
• Mr. B.O.N. Otti - Member
• Mallam Samaila Zubairu - Member
• Mr. Ignatius Adegunle - Member
• Mr. Gerald Ilukwe - Member
• Rep. of FIRS - Ex-Officio
• Rep. of FMF Incorporated - Ex-Officio
• Rep. of HAGF/HMJ - Ex-Officio
• Rep. of OAGF - Ex-Officio
• Rep of CBN - Ex-Officio
• Rep. of DPR - Ex-Officio
• Rep. of NNPC - Ex-Officio
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Since its inauguration, members of the PRSTF have
approached the assignment with all the seriousness that it
deserves. In carrying out its ToR, one of the initial activities
performed by the PRSTF was to obtain both written and verbal
presentations from the various stakeholder groups within the
Petroleum Industry. This was to enable the Task Force to
understand the challenges faced and the type of reforms that
are required. This was all carried out with a view to determining
and optimising the nation's revenue streams from all sectors
within the industry.
Also, the members of the PRSTF visited various locations as
they deemed necessary.
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Scope and Work
Done
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3. Scope and Work Done
3. Work Approach
The Petroleum Revenue Special Task Force, in order to fulfil its
Terms of Reference, carried out the following activities:
• Set up a Virtual Project Management Office (PMO) managed
by BGL Plc;
• Confirmed the engagement of Bode Ososami as our Adviser
and liaison with other Task Forces set up to consider other
aspects of the oil and gas industry.
• Confirmed the engagement of PricewaterhouseCoopers
Limited (PwC) as consultants to the Petroleum Revenue
Special Task Force;
• Selected Industry Stakeholder Groups that were invited to
address the Special Task Force.
• Prepared and adopted a Work Plan that covered the scope of
the assignment, delineating areas of critical focus, scheduled
meetings, presentations and interaction with the
Stakeholders; and
• Received briefings and presentations from the following
organisations:
- Oil Producers Trade Section (OPTS)
- Shell Nigeria
- Chevron Nigeria
- Trispec Schlumberger
- Sahara Group
- NNPC Finance and Accounts Directorate, Crude Oil
Marketing Division, IT Department and other Divisions
- National Petroleum Investment Management Services
(NAPIMS)
- Pipeline Products and Marketing Company Limited
(PPMC)
- Department of Petroleum Resources (DPR)
- Petroleum Products Pricing Regulatory Agency (PPPRA)
- Central Bank of Nigeria (CBN)
- Economic and Financial Crimes Commission (EFCC)
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- Inspection Agents (Cobalt International Services Nigeria
Limited,
The Petroleum Revenue Special
Task Force (Special Task Force),
in order to fulfil their mandate by
the Honourable Minister of
Petroleum Resources carried out
various activities in order to
acquire relevant information
- Services, Robinson International and Gulf Inspection
Services)
- Monitoring Agents (Swede Control Intertek and Q & Q Pre
÷ Shipment Inspection)
- DFID's Facility for Oil Sector Transparency (FOSTER)
- KPMG Professional Services on the Process and Forensic
Review of Nigerian National Petroleum Corporation.
- HSBC Global Banking and Markets
• Visited and reviewed selected operators and agencies of
government covering the period from 1 January 2005 to 31
December 2011. This exercise covered the Agencies and
Parastatals of the Ministry of Petroleum Resources, the
Central Bank of Nigeria, the Federal Inland Revenue Service,
the Nigerian Customs Service, Nigerian National Petroleum
Corporation and its subsidiaries, International Oil Companies
(IOCs), Local Oil Companies (LOCs) and other relevant
parties.
Our detailed review, supported by the Task Force's
consultants covered an in-depth examination of the various
revenue streams of Government across the various
responsible agencies. The review period covered was from 1
January 2005 to 31 December 2011 in line with the Statute of
Limitations. However, where it was deemed necessary by
members of the PRSTF, the scope was extended. The review
carried out at the NNPC covered a period of ten(10) years
instead of seven (7) to enable the PRSTF determine key
trends in the determination of the FGN's revenue and carry
out better analysis of the status quo.
• Set up Two (2) Ad- Hoc Subcommittees namely NNPC
Review Subcommittee and the DPR Review Subcommittee
to conduct an in-depth review and onsite consultations with
these two key agencies responsible for the management of
revenues from the sector.
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• Set up Five (5) Standing Subcommittees with detailed ToRs
emanating from the Task Force's mandate. This was to
enable the Special Task Force follow up on the assertions
made by the various stakeholders and organisations. See
Scetion 3.3. for the membership and terms of reference of
the Task Force's constituted Subcommittees.
• Two workshops were held in the month of May 2012 to
further assist the Special Task Force in the information
gathering process. These were the: (1) Workshop on
Metering and Measurement in the Oil & Gas Sector Value
Chain, and (2) Workshop on Security in the Oil and Gas
Sector.
• In pursuance of ToR 2, the Task Force through the Security
and Enforcement Subcommittee liaised with relevant
agencies to validate the status of outstanding debts identified
in the course of the forensic review, and to demand
payments where deemed necessary.
4. Limitations and Constraints
The Task Force encountered some limitations in the course of
executing our terms of reference, which in some cases
constrained the depth of the review or access to desired
information. The key limitations are as follows:
• Disputes between agencies on crude oil production data
leading to difficulty in ascertainment
• Timey implementation of the country's production data
repository said to be at pilot stage.
• Some of the companies invited or circularised with
information requests did not respond to the letters sent by
the Task Force requesting information.
• Given the time allocation for the Task Force's work, the
review and findings were constrained owing to the large
number of companies and agencies that required review.
However, the Task Force made all necessary efforts to
ensure a full execution of its mandate and our findings are
presented in the report.
• For crude oil sales, a lot of the supporting documentation
and information was provided towards the end of the
mandated time stipulated for the review. In fact,
information was still trickling in as at the time this report
was being concluded. It is key to note that the information
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was primarily paper based which would have required
further extensions to conclude the reviews of certain
Domestic Crude Oil Revenue Drivers.
• In the course of the work of the Task Force, information
received was not sufficient to carry out a complete
assessment of the cost versus the proceeds of sale for the
entire 445,000bbls domestic allocation by the FGN.
Therefore, we cannot come to a meaningful conclusion in
this regard.
• As at the time of reporting PPMC had not provided the
Task Force with schedules of crude volumes that was
delivered to the refineries and monthly analysis petroleum
products available for sale (import and refined). This would
have facilitated an analysis of utilisation as well as an
estimation of expected generated revenues from sale.
• The nature and scope of work was complex and varied
leading to several related challenges
o Given the volume of contracts under review from
execution of FGN contracts (through the NNPC) with
Contractors (Oil Companies) including JOA, PSC a
further time period would have been of benefit
o Differences of opinion between NNPC and DPR.
o Timely access to the records of NNPC's strategic
subsidiaries ÷ Napoil, Calson, Hyson, NPDC, NGC
etc.
• Information available from NNPC and NAPIMS in respect
of the gas pricing model as well as natural gas
production/sale contracts with the various contractors was
deemed inadequate by the Task Force.
• The Task Force was not provided with the gas supply-
sales agreements between NLNG, NNPC and NGC.
• Reconciliation of the list of concessions and the
concessions per the detailed schedule of concession
rentals.
• The exact status of Royalties due created some
disagreement between agencies
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• The sector wide need to independently track gas volumes
produced, sold and flared by the operators.
5. Subcommittees Membership and Terms of
Reference
Memberships of the Task Force's constituted subcommittees are
as follows:
Ad ÷ Hoc Subcommittees
A. NNPC Review B. DPR Review
• Dr (Mrs) Omolara Akanji (Chair) 1. Mr Olasupo Shasore SAN
(Chair)
• Prof Olusegun Okunnu 2. Ms Bennedikter C. Molokwu
• Rep of OAGF 3. Mallam Samaila Zubairu
• PwC Consultants 4. Mr Ignatius Adegunle
5. PwC Consultants
Standing Committees
A. Revenue Subcommittee B. Legal Subcommittee
1. Mallam Abba Kyari (Chair) 1. Dr Olisa Agbakoba
SAN (Chair)
2. Pastor Ituah Ighodalo 2. Mr Anthony George-
Ikoli SAN
3. Dr (Mrs) Omolara Akanji 3. Mr Anthony Idigbe
SAN
4. Mallam Samaila Zubairu 4. Mr Olasupo Shasore
SAN
5. Mr. B.O.N. Otti 5. Rep of FIRS
6. Rep of OAGF
7. Rep of FIRS
A. IT and Automation D. Security and
Subcommittee Enforcement Subcommittee
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1. Mr Gerald Ilukwe (Chair) 1. Mr Olasupo Shasore
SAN (Chair)
2. Prof Olusegun Okunnu 2. Dr(Mrs)
Omolara Akanji
3. Pastor Ituah Ighodalo 3. Mr Anthony
Idigbe SAN
4. Mr Ignatius Adegunle 4. Rep of CBN
5. Mr Anthony George-Ikoli SAN
A. Report Writing Subcommittee
F. 1. Ms. Bennedikter C. Molokwu (Chair)
2. Prof Olusegun Okunnu
3. Mallam Samaila Zubairu
4. Mr Olasupo Shasore SAN
5. Mr B.O.N. Otti
The Terms of Reference of the Sub-committees were defined as
follows:
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Committee Subcommittee Terms of
Reference
TOR Cross-
Reference
Revenue
Subcommittee
Capture all Revenue loss
areas resulting from:
Unlawful activity
System failure
Inadequate resources
Sundry
Evaluate the fiscal regimes in
the sector and identify
revenue leakage points and
recommend immediate steps
Reconcile revenue payments
due and outstanding to
Government across relevant
agencies ÷ NNPC, DPR, FIRS
and the industry operators ÷
IOCs and LOCs
Propose Revenue
Enhancement initiatives and
programmes for Government's
adoption in the sector
TORs 1, 2 and 3
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Committee Subcommittee Terms of
Reference
TOR Cross-
Reference
Legal
Subcommittee
Identify legal documents
governing the key
Government agencies with all
their partners in Petroleum
revenue generation
processes, for all applicable
fiscal regimes
Review all legal disputes
between Government
agencies and industry
operators regarding revenue,
tax and other financial
obligations
Liaise with the Petroleum
Industry Bill and Governance
and Control Task Forces to
reconcile revenue
expectations with the legal
framework being proposed
Propose legislative reforms to
support transparency in
production and revenue
automation
TORs 1 - 6
Security and
Enforcement
Subcommittee
Establish security and
enforcement challenges as a
critical contributor to
Petroleum revenue losses
Quantify losses arising from
security issues across the
Petroleum industry value
chain
Develop a Security Master
plan to address all revenue
loss issues identified in the
Petroleum sector
TOR 2 regarding
enforcement
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Committee Subcommittee Terms of
Reference
TOR Cross-
Reference
IT & Automation
Subcommittee
Establish the current status of
production automation in the
Nigerian Petroleum sector
Provide the Task Force with a
functional best practice case
study on measurement,
metering and automated
production monitoring, for
Government's adoption
Recommend a short-term
bridging solution to address
identified issues
TORs 4 and 5
Report Writing
Subcommittee
Collate and integrate all the
Subcommittee Reports
Develop the framework of the
Task Force's Final Report
TOR 6
Table 2: Subcommittees TORs
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Revenue Review and
Debt Verification
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4. Revenue Review and
Debt Verification
1. Introduction
This section of the report presents the findings of the Petroleum
Revenue Special Task Force's activities regarding the ToR 1 and
2 which in effect involved determining and verifying all Petroleum
Upstream and Downstream Revenues (Taxes, Royalties etc) due
and payable to Nigeria; and taking all necessary steps to collect
all debts due and owing.
It was determined that the main petroleum revenues due to the
national treasury in respect of oil and gas activities in Nigeria are
as follows:
• Domestic Crude Oil Sales
• Equity Crude Oil Sales
• Gas Sales
• Refined Petroleum Products sales
• Profits from NNPC subsidiaries
• Petroleum Profits Tax
• Company Income Tax
• Signature Bonus
• Concession Rentals
• Royalties (Oil and Gas)
• Gas Flare Penalties
• Miscellaneous Oil Revenues
The table below highlights the scope of this review and provides
an overview of the agencies and revenue streams examined.
Petroleum Industry
Sub ÷ sector
Revenue Streams Responsible
Agency
Upstream Revenues ÷
Oil and Gas
Domestic Crude Sales NNPC
Equity Crude Sales NNPC
Royalties (Oil and Gas) DPR
Concession Rentals DPR
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Petroleum Industry
Sub ÷ sector
Revenue Streams Responsible
Agency
Signature Bonuses DPR
Petroleum Profit Taxes FIRS
Gas Flaring Penalties DPR
Company Income Tax FIRS
Miscellaneous Income ÷
Licensing , Fines etc.
DPR
Midstream/
Downstream
Revenues
Miscellaneous Income ÷
Licensing fees etc.
DPR
Company Income Tax FIRS
Sale of Refined Petroleum
Products
PPMC
Table 3: Overview of the Agencies and Revenue Streams examined
The following sections document the Task Force's detailed
findings arising from the revenue review and verification exercise,
according to each revenue stream.
9. Production
1. Overview
Over the past 10 years, NNPC's record shows that the country
produced an average of 842m bbls per year. An official of Shell in
Nigeria told the task force that with adequate investment and
good security enforcement by the Nigeria's production could be
increased to 1.3b'bbls annually. Production quantities are used in
the determination of Royalties, Taxes, FGN's entitlement etc.
There are various agencies of Government that are charged with
the responsibility of monitoring the nation's upstream activities.
These include: the DPR, NNPC, NAPIMS, Nigeria Customs
Service, Pre-shipment Inspection Agents, Nigerian Ports
Authority, Navy, and the Nigerian Police.
For the purpose of determining Nigeria's entitlement, the Task
Force was told by NNPC's Crude Oil Marketing Division that
standardised contracts ("templates¨) are used for each operator
depending on the agreement type (JOA, AF, CA, MCA, and
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PSC). With the aid of these templates, production entitlements of
the Federal Republic are determined. This is reviewed at COMD
periodically for computation errors and adjustments.
Information provided by the operators on production is accepted
as valid and the operators are relied upon for data on cost and
production. Non- operators are not expected /allowed to visit the
production location.
3. Findings
1. The basis used in determining actual production figures for
fiscal purposes
Crude oil royalties are determined on the basis of saleable crude
at the terminals which is not representative of actual production.
Production figures for the purpose of determining crude oil
royalties due to the nation's treasury are derived from the metric
reading taken at the terminals by the DPR officials. These
measurements are applied in a 'net back' to map throughput back
to well heads and fields.
Monthly reconciliations are performed between the DPR officials
and Operators to determine the final monthly crude oil production
figures which is used in the determination of the final royalties due
per field.
10. Domestic Crude Sales
1. Overview
The Federal Government of Nigeria (FGN) allocates (on behalf of
Nigeria) 445,000 barrels of crude oil to NNPC daily, out of the
total crude oil production of the country for the purpose of
domestic consumption, hence, the term 'Domestic Crude Oil'. The
allocation of 445,000 barrels represents the installed capacity of
the four (4) local refineries situated at Port Harcourt, Warri and
Kaduna. Liftings for domestic crude are made mainly from the
Escravos and Forcados terminals, which produce mainly Bonny
Light and Forcados type of crude oil.
The NNPC is required to pay the Federation for this allocation on
the basis of quantities lifted in any particular month and at
international market prices. A 3-month credit period is granted to
NNPC to make the payment to the FGN.
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In practice, payments for domestic crude oil are made
subsequent to the conclusion of the monthly Federation Accounts
Allocation Committee (FAAC) meetings.
5. Findings
1. Remittance of amounts due to the Federation Account
relating to Domestic Crude Oil allocation
NNPC is responsible for domestic crude oil sales and the
Corporation is meant to remit payments in this regard to the
Federation Account through the Central Bank of Nigeria. As at 31
December 2011, N843 million was due to the Federation in
respect of Domestic Crude Oil allocations (Table 4). The amounts
outstanding as at 31 December 2011 represent amounts due for
the months of September 2011 to December 2011.
In view of the 90-day credit period, the outstanding amount as at
31 December 2011 was not due for payment. The Task Force
however sighted evidence of subsequent payments in 2012.
Year Volumes
lifted
Av. price
per bbl
(US $)
Total
Value
$' m
Total Value
N' m
Subsidies
deducted
N' m
Other
Receipts/
Other
Deductions
N' m
Net Payable
N' m
Amount
outstandin
g at
31/12/11
N' m
2002 163,610,046 18 2,945 323,948 - - 323,948 -
2003 157,454,064 23 3,473 409,753 - 25 409,778 -
2004 151,892,709 37 5,688 759,693 - 1,044 760,738 -
2005 159,898,538 54 8,704 1,145,361 - 1,478 1,146,839 -
2006 157,278,731 62 10,599 1,277,965 (232,875) (19,425) 1,025,665 -
2007 165,858,741 73 11,531 1,431,176 (275,177) - 1,155,999 -
2008 164,723,596 98 15,562 1,809,452 (328,118) - 1,481,334 -
2009 161,913,738 62 9,903 1,451,586 260,706) - 1,190,880 -
2010 166,522,807 80 13,229 1,954,125 (414,011) (13) 1,540,100 -
2011 164,454,254 111 18,363 2,776,906 (732,873) 8,473 2,052,506 843,050
Table 4 Amounts payable, paid and outstanding - Domestic Crude Oil
(Source: NNPC)
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Sample selections were made across the 10 year period in order
to verify that the net amounts payable were remitted to the
Federation account in CBN. From the selections made it was
observed that amounts remitted were most times different from
the net payable amount (Table 5 below).
From discussions with the NNPC, the variances were attributed to
other miscellaneous receipts from domestic gas sales and NGL
supplies which were also included in the remittances to the
Federation account by the NNPC.
However, further reviews showed that the negative differences
were as a result of differences in computation of subsidies.
Period
Amount
Payable
(N' m)
Amount Remitted
as traced to CBN
statement!(N' m)
Variance!(NG
N million)
May 2002
27,001 26,541 (460)
June 2002
26,541 26,689 148
August 2002
29,686 29,686 -
October 2002
27,806 24,384 (3,421)
December 2002
28,555 27,563 (992)
August 2003
42,189 42,740 551
September 2003
43,237 44,141 904
October 2003
67,025 66,615 (409)
December 2003
40,889 40,914 25
August 2004
71,972 71,956 (16)
June 2005
87,101 88,413 1,312
August 2005
130,958 130,968 10
September 2005
107,331 106,358 (973)
November 2005
117,670 99,889 (17,781)
December 2005
86,045 80,366 (5,679)
February 2006
57,301 57,905 604
August 2006
109,571 109,911 339
October 2006
71,590 71,752 162
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Period
Amount
Payable
(N' m)
Amount Remitted
as traced to CBN
statement!(N' m)
Variance!(NG
N million)
December 2006
95,791 96,001 211
January 2007
50,607 51,506 899
July 2007
87,276 87,848 572
October 2007
94,085 94,289 204
December 2007
133,256 133,654 398
March 2008
184,233 184,605 372
June 2008
100,728 100,760 31
September 2008
102,673 103,518 845
December 2008
67,732 68,493 761
May 2009
87,933 88,029 96
July 2009
69,264 69,737 473
October 2009
116,303 116,857 554
December 2009
108,577 110,751 2,175
February 2010
96,596 96,596 -
May 2010
105,388 105,764 377
November 2010
118,271 118,323 52
December 2010
192,445 192,467 21
January 2011
116,440 114,697 (1,743)
August 2011
108,563 108,592 29
September 2011
197,145 197,917 772
December 2011
227,005 227,262 257
Table 5: Sample of Domestic Crude Oil remittances made 2002 2011 (Source:
NNPC)
Subsidies deducted by the NNPC per table 4 represent the
difference between the PPPRA approved landing cost and the
NNPC retail price (excluding margins) multiplied by the PPPRA
observed volumes. PPPRA subsidy approvals for the sale of
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refined products by the NNPC were in excess of deductions made
by about N132.7 billion as at 31 December 2011.
At present, subsidy is paid based on the difference between the
proceeds from the sale of refined products and the cost of
importation of refined products.
In the course of the Task Force's work, we did not receive
sufficient justification and basis for the practice of deducting
subsidies from the amounts payable to the Federation Account.
Indeed this practice does not accord with the law, with particular
reference to the Constitution
4
.
2. Annual liftings of Domestic Crude Allocations
Based on the daily allocation by the FGN of 445,000bbls, it is
expected that NNPC would be allocated approximately 162
million barrels annually. Our review of the records received
showed an inconsistent pattern in the implementation of this
policy with variances found for the ten (10) years reviewed
spanning 2002 to 2011 (See Table 6 below).
3. Discrepancy in the pricing of Domestic Crude
The average price per barrel payable by NNPC was compared
with the average weekly prices for Nigeria Bonny Light, Forcados,
obtained from the Energy Information Administration (EIA). It was
understood from discussions with officials of the NNPC that the
pricing of domestic crude oil during the period under review was
based on international prices.
The review revealed that over a 10 year period (2002 ÷ 2011),
showed a difference of an estimated sum of US$ 5 billion, as
shown in the Table 6 below.
Year Volumes lifted
Av. price
per bbl
(US $)
Av. price
per EIA
(US $)
Difference
(US $)
Valuation of
difference (US
$' m)
2002 163,610,046 18 25 7
1,145
2003 157,454,064 23 29 6
979
2004 151,892,709 37 38 1
152
4
See Section 162 which provides "The Federation shall maintain a special account to be
called the Federatiion account into which shall be paid all revenues collected by the
Government of the Federation¨
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Year Volumes lifted
Av. price
per bbl
(US $)
Av. price
per EIA
(US $)
Difference
(US $)
Valuation of
difference (US
$' m)
2005 159,898,538 54 56 2
320
2006 151,193,195 64 67 3
454
2007 165,858,741 73 75 2
332
2008 164,723,596 98 102 4
659
2009 161,913,738 62 63 1
162
2010 166,522,807 80 81 1
167
2011 164,276,790 111 114 3
493
Total 1,613,607,224
5,008
Table 6: An analysis of the prices of Crude Oil per barrel (Source: Energy
Information Administration (EIA))
Enquiries from NNPC revealed that up until October 2003, NNPC
was granted fixed price regimes by the FGN for the domestic
crude as follows:
• 1999 ÷ 2001 $9.50/bbl
• 2002 to July 2003 $18/bbl
• Aug/Sep 2003 $22/bbl
This explains the wide disparity in prices in the earlier years.
Further analysis showed specific examples of transaction with
disparities in price in later years.
4. The Exchange Rates used to remit payments in respect of
Domestic Crude to the Federation Account
Domestic Crude Oil is paid for in Nigerian Naira using CBN
exchange rates. It was noted that the exchange rates used in
arriving at the Naira equivalent of the amounts payable differed
from the CBN rates for six (6) of the ten (10) years reviewed. The
practice appears to have been stopped in 2006; it also appears to
have started again in 2011. The potential underpayment of
amounts payable to the Federation Account over the 10- year
period is estimated at N86.6 billion (Table 7).
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Year Volumes lifted
Av. price
per bbl
(US $) Total value in (US$)
Av. exch
rate (N/$1)
CBN yearly
average
exchange
rate (N/$1)
Diff.
(N/$1)
Valuation of
difference
(N'm)
2002 163,610,046 18 2,944,980,828 110 120 10 29,449
2003 157,454,064 23 3,473,418,919 122 134 12 43,288
2004 151,892,709 37 5,687,518,809 134 133 (1) (5,688)
2005 159,898,538 54 8,704,165,240 132 131 (1) (8,704)
2006 151,193,195 64 9,891,404,099 126 127 1 9,891
2007 165,858,741 73 11,531,242,678 124 124 - -
2008 164,723,596 98 15,561,979,536 117 117 - -
2009 161,913,738 62 9,903,033,496 147 147 - -
2010 166,522,807 80 13,228,939,762 148 148 - -
2011 164,276,790 111 18,342,657,598 151 152 1 18,343
Total 86,579
Table 7: CBN exchange rates used in the conversion of Domestic Crude Oil
payments (Source: CBN Website Rates Archives)
5. Utilization of Domestic Crude
From an analysis of annual domestic crude oil utilisation, it was
revealed that a greater proportion of the Domestic Crude Oil has
been channelled towards crude oil exportation, exchange
transactions and offshore processing than for local refining.
The percentage of Domestic Crude Oil that is not refined in-
country ranges from between 50% to 88% over the 10 year period
(Table 8).
Year
Total
Refinery
Quantity
m' bbls
Unutilized
domestic
crude
exported
m' bbls
Crude Oil-
Crude Oil
Exchange
m' bbls
Crude -Oil
Product
Exchange
m' bbls
Offshore
Processing
m' bbls
Total
Quantity
m' bbls
2002 79 85 - - - 164
2003 43 113 - - - 156
2004 39 115 - - - 154
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Year
Total
Refinery
Quantity
m' bbls
Unutilized
domestic
crude
exported
m' bbls
Crude Oil-
Crude Oil
Exchange
m' bbls
Crude -Oil
Product
Exchange
m' bbls
Offshore
Processing
m' bbls
Total
Quantity
m' bbls
2005 72 84 4 - - 160
2006 42 113 - - - 155
2007 18 139 - - - 157
2008 41 121 2 - - 165
2009 19 143 - - - 162
2010 35 98 1 6 27 167
2011 45 39 - 56 24 164
Table 8: Domestic Crude Oil Utilisation (Source: NNPC)
6. The Domestic Crude Allocation
NNPC's COMD sells to PPMC roughly 445,000bpd of NNPC's
share of crude to supply the nation's four refineries. PPMC is
obligated to pay for this crude within 90 days using revenues from
refined product sales.
In recent years the refineries have operated regularly at below 50
percent capacity. PPMC has stated that all four are running at a
loss due to several challenges- disrepair, infrastructure
vandalism, and theft of crude and refined products. COMD
typically sold the unrefined part of the 445,000bpd on behalf of
PPMC on terms that are identical to other export transactions.
The Task Force's review suggests that the dual agent-buyer
status of any agency on sales to the refineries in several ways
impacts negatively State revenues:
• Subsidized sales:
NNPC sells domestic crude to itself at prices apparently below
market
5
this creates a margin on crude sales to the refineries that
should accrue to FGN and the Federation.
• Exchange Rates:
PPMC declared domestic crude debts are below-market
exchange rates; sometimes perhaps as much as 20 percent
under CBN publicly advertised rates for corresponding periods.
5
Observations of the NNPC sub committee from site visit
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• Deferment of Debts:
In the mid-2000s domestic crude debts were deferred repeatedly:
for example, according to NEITI published reports, between 2004
and 2008 total domestic crude debts outside the 90-day credit
window grew from N1.5b to N588b. Interest on debts outside the
90 day credit window, and infrequent delays sweeping payments
into the Federation Account
6
.
As its debt position worsened after 2009, NNPC also began using
the non-refined portion of the domestic crude allocation in costly
ways:
• Withholding proceeds from sales of exported domestic crude
oil:
This practice began ostensibly to cover fuel subsidy costs. NNPC
itself has denied this publicly, but our findings per Section 1.2.4.1
above shows NNPC withheld N1.983trillion in subsidies between
2006 and 2011.
• Use of product swaps and offshore processing:
Starting late in 2010, a total of 27mbbls of non-refined domestic
crude was sent for offshore processing and 6 mbbls for crude oil
product exchange (2011: 24mbbls and 56mbbls respectively).
The economics of these transactions are not clear and the task
force was unable to deduce whether adequate value is generated
from these transactions.
Ultimately, this combination of deferred receivables, discretionary
withholdings, and cashless contracts may constitute an
unnecessary loss in revenues to the Federation.
11. Equity Crude Oil Sales
6. Overview
The balance of government's share of crude oil production, after
deducting domestic crude is termed "equity crude¨. These crudes
are obtained mainly from 3 types of arrangements which are:
· Joint operating agreements with International Oil
companies. This may be modified by alternative funding
arrangements or modified carry arrangements which arises
6
NNPC has acknowledged N450b worth of debt for unremitted domestic crude proceeds
through end of 2009. It claims this sum represents a series of Presidential "reprieves,¨ but that
it is now agreed a 32 instalment repayment plan.
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as a result of the FGN's inability to fully finance its share of
JV costs
· Production Sharing Contracts (PSC)
· Service Contracts
Equity Crude Oil is required to be sold in the international market
at commercial prices by NNPC (COMD) and the proceeds are
remitted into three (3) principal accounts:
· Federation account, as export proceeds
· DPR accounts - Royalties
· FIRS accounts - PPT
The Task Force has carried out a review of crude oil sales from
the various contract types.
7. Alternative funding agreements (Carry/Modified Carry
Agreements)
These are financing agreements in which International Oil
Companies advance loans to NNPC, for the purpose of investing
in upstream projects. This type of agreement arose because
NNPC was unable to meet its cash call obligations under the joint
operating agreements. As at 31 December 2009, outstanding JV
cash call obligation was N459.568billion.
Under these agreements, the companies take capital allowances,
as allowed by the Petroleum Profit Tax Act to recover up to the
applicable rate of PPT for the calendar year of the principal. This
serves to reduce the taxable profit that is due.
The incremental notional margin is paid to the operators out of the
increased production from which their investment was made.
Where the investment does not yield the expected results, the
payment is stopped. NNPC has no liability for any financial loss
incurred by the carrying party in respect of the project.
The carry oil recovery process covers only capital expenditures.
The operating expenditures are funded by NNPC in accordance
with the joint operating agreement.
For allocation of oil proceeds, this is done in accordance with the
following priority (assume a contract between one operator and
NNPC):
• volume of oil representing the operator's participating interest
share shall be allocated to the operator
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• carry oil shall be allocated to the carrying party to reflect its
carry interest share. If the reimbursable carry expenditure
(principal plus interest) exceeds the amount of carry oil
available in any calendar year, then the excess is carried over
to the next calendar year and
• shared oil is shared between the carrying party and NNPC in
the agreed proportions. In the earlier carry agreements,
shared oil and carry oil are lifted by the operators. In the
modified carry agreements, share oil and carry oil are lifted
and marketed by NNPC on behalf of the carrying party and
proceeds of sale is utilized for repayment of the carrying party
for recovery of the reimbursable carry expenditure.
Recoverable carry expenditure and share oil can be carried
forward to the next calendar year. The balance of NNPC's
equity allocation, which remains after lifting and marketing by
NNPC of the carry oil/gas and share oil/gas, for and on behalf
of the carrying party, shall be for the account of NNPC. The oil
taken as carry oil and shared oil by the carrying party is
treated as equity production of the carrying party and subject
to PPT and royalty. Consequently, the full value of the oil lifted
and owned by the carrying party is subjected to PPT and
royalty as proceeds from sale of oil, rather than consideration
for the disposal of assets to NNPC or tariff income.
When oil recovery from the projects reaches a certain level,
NNPC and the operator are entitled to negotiate the shared oil
ratio.
8. Production Sharing Contracts
The Production Sharing Contracts are contracts where the NNPC,
as holder of all rights in and to the contract area, appoints and
conveys to a contractor, the exclusive right to conduct petroleum
operations in a contract area.
The contractor provides funds and bears interests on the funds, in
addition to bearing the risks of operating costs and risks required
to carry out petroleum operations and therefore have an
economic interest in the development of crude oil and natural gas
discovered.
Under the contract, the available crude oil is allocated to the
parties as follows:
• Royalty oil is allocated to NNPC in such quantum as will
generate an amount of proceeds equal to actual royalty
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payable on the contract area during each month and the
concession rental payable annually;
• Cost oil will be allocated to the contractor in such quantum
as will generate an amount of proceeds sufficient for the
recovery of operating costs, after allocation of royalty oil to
NNPC. All costs will be in US Dollars and recovered
through cost oil allocation;
• The cost oil ceiling shall be 70% of available crude oil. The
realizable price established shall be used in determining
the amount of cost oil allocated to the contractor in respect
of crude oil produced.
• Tax oil shall be allocated to NNPC in such quantum as will
generate an amount of proceeds equal to the PPT liability
payable each month;
• Profit oil, being the balance of available crude oil after
deducting royalty oil, cost oil and tax oil shall be allocated
to each Party in the agreed algorithm.
7. Findings
9. Single point accountability required
The Task Force observed that there is no single point
accountability for the income and expenditure streams of
upstream petroleum operations. This is also compounded by the
current structure of the NNPC and its agencies, as detailed
below:
• The joint operating agreements and contracts with oil
companies in petroleum operations are entered into by
NNPC.
• The responsibility for monitoring costs and the investments
of the FGN in oil and gas upstream operations rests with
the National Petroleum Investment Management Services
(NAPIMS), a strategic business unit of NNPC not a limited
liability company.
• The responsibility for verifying the FGN's share of crude oil
production rests mainly with the Crude Oil Stock
Management Unit (COSM), a unit of the Crude Oil
Marketing Division (COMD) of the NNPC, with cost
considerations based on information provided by NAPIMS.
• The responsibility for marketing and sale of crude oil
(equity and unutilized domestic crude) is with the COMD.
• Remittances of sales proceeds are made directly by
customers into the CBN correspondent bank accounts with
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JP Morgan Chase, which are subsequently swept into the
Federation account. This is monitored and tracked by
Group Finance, NNPC.
• Revenues from equity crude and costs incurred in
upstream operations are recorded in the books of
NAPIMS, which is separate from NNPC's books of
account.
The reconciliation process amongst the various groups listed
above is not clearly defined which makes it difficult and almost
impossible to have a single and holistic view of investments and
the returns thereto at any point in time.
10. Decline in national investment in the upstream sector
The trend observed is that crude oil production has been in a
decline over the 10 year review period. This can be directly linked
to the fact that the nation has not made the necessary
investments that would increase the nation's proven reserves
(Table 9).
The preparation and presentation of Financial Accounts for
NAPIMS are presented as if NAPIMS was a single operating
business entity or profit centre as opposed to a cost centre. This
grossly contradicts the reality and its implications ÷ that there is
no strategic single point perspective of FGN's investment and
returns in the Petroleum sector.
Year JV Production
PSC
Production
SC
Production
NPDC JV
Production Independents
Marginal
Fields
Total
Production
Percentage
change
2002 687,980,920
11,500,555 4,244,744 6,514,425 30,446,536
-
740,687,180
2003 791,227,920
16,718,964 3,483,966 6,819,784 25,900,295
-
844,150,929 14%
2004 844,770,516
24,399,567 3,886,392 13,042,029 24,057,985
-
910,156,489 8%
2005 831,763,445
36,711,219 4,317,081 22,015,929 24,915,639
-
919,723,313 1%
2006 662,491,651
162,532,458 4,013,954 21,693,919 17,680,246
784,278
869,196,506 -5%
2007 581,468,061
192,621,306 3,932,714 15,853,124 8,693,895
431,608
803,000,708 -8%
2008 546,055,056
195,212,480 3,361,078 12,468,295 12,914,554
2,842,065
772,853,528 -4%
2009 468,180,346
268,792,256 3,237,284 21,869,008 19,519,612
3,878,439
785,476,945 2%
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Year JV Production
PSC
Production
SC
Production
NPDC JV
Production Independents
Marginal
Fields
Total
Production
Percentage
change
2010 533,683,737
316,887,117 2,711,402 21,745,142 20,192,353
3,803,447
899,023,198 14%
2011 526,022,734
288,141,531 3,994,220 27,541,493 16,974,827
8,080,760
870,755,565 -3%
Table 9: Country production of crude oil (Source: NNPC).
Also, looking at Figure 2, variations in the FGN's crude oil
revenues have been due principally to variations in crude oil
prices.
Figure 2 - Country production, government entitlement, government revenues
and market prices of crude oil.
Very little impact has been recorded from variations in crude oil
production. Despite the increase in crude oil production in Nigeria
over the years, the nation's entitlement has decreased as a result
of various alternative funding arrangements for its upstream
investments.
11. Legislation in the Petroleum Industry
Legislation governing the industry and agreements with third
parties are outdated and do not reflect current economic or legal
realities. This legislation includes:
• Petroleum Act L.F.N 1990 L.F.N 2004
• Deep Offshore and Inland Basin Production Sharing
Contracts Act L.F.N 2004
• Petroleum profits tax Act L.F.N 1990 L.F.N 2004 etc
In addition, some legislation includes clauses that are ambiguous
in current economic terms. Examples are applicable rates for
calculation of royalties at offshore locations, determination of
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realizable prices to be used in Royalty and PPT calculations,
timing of capital allowances etc. This creates various
controversies between the NNPC, DPR and the oil companies as
to the amount of royalties and invariably cost, tax and profit oil.
We found that there is need for certainty in the law as to
calculation of royalties as a way to avoid existing lingering
disputes.
Furthermore, there are some provisions within the legislation that
could significantly improve government's revenue that the
government is yet to take advantage of. These include Section 16
of the Deep Offshore and Inland Basin Act which provides that:
• The provisions of this Act shall be subject to review, to ensure
that if the price of crude oil at any time exceeds $20 per
barrel, real terms, the share of the Government of the
Federation in the additional revenue shall be adjusted under
the Production Sharing Contracts to such extent that the
Production Sharing Contracts shall be economically beneficial
to the Government of the Federation.
• Notwithstanding the provisions of (1) above, the provisions of
this Act shall be liable to review after a period of 15 years
from the date of commencement and every 5 years thereafter.
Provisions of major enabling legislation governing the petroleum
sector confer powers on the Minister to delegate the power of
regulation and supervision for effective performance of revenues.
The Task Force observed that these provisions have not been
utilised to vary the fiscal terms for production sharing contracts.
The price of crude oil has long since exceeded $20. It seems that
past administrations may have been worried about discouraging
investment in deep offshore as a reason for lack of will to invoke
the provisions of the Act. But the fact today is that the initial
reason for generous PSC terms which was risk of investment in
an unproven basin no longer exists as Nigerian deep offshore has
been proven to contain vast reserves. It is perhaps appropriate
for the present administration to take advantage of the Act to vary
the terms of the PSCs so as to increase government take and
enable the administration achieve its transformation agenda.
Sections of the Petroleum Act and the Associated Gas
Reinjection Act relating to prescription of fines and other revenues
can be delegated as such by the Minister in this regard
7
.
7
See Section 9 of the Petroleum Act and Sections 3b and 5 of the Associated Gas Reinjection
Act, for example
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The impact of these observations is a lack of clarity in
determination of government revenues and the lack of periodic
reviews of legislation to ensure optimization of FGN revenues.
12. Crude sales to traders without formal contracts
NNPC makes use of traders as middlemen for the exportation of
crude oil and importation of petroleum products. This logically will
serve to reduce margins obtainable on sale of crude oil and
increase costs on purchase of petroleum products as compared
with where the sales/purchases are made directly.
The COMD annually requests for bids from oil and gas traders.
This forms the basis for the selection of traders, to whom
contracts are signed, covering a period of 1 year. Table 10 shows
the number of traders engaged by NNPC over a ten year period,
with an over 100% increase from 22 in 2002 to 48 in 2011.
Year
No of
customers/contracts
2002 22
2003 24
2004 24
2005 31
2006 31
2007 47
2008 28
2009 22
2010 40
2011 48
Table 10: Summary of Lifting Contract Agreements (Source: NNPC records)
It was observed that the following traders lifted crude oil however
the companies could not be found as listed on the approved
master list of customers. This suggests that Nigeria sold crude oil
to certain traders without a formal contract
8
.
8
Task Force could only establish formal contracts in writing if any oral contracts exist there
appears no record of same
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Year Names of customers without formal contracts
2002 Tema Oil Refining, Petrobras
2003 Itochu
2004 Crossoil, Energem Petroleum Corporation,
2006 Ovlas Trading, AMG Petro Energy
2007
Safiya Global Investments Ltd, INC Natural Resources, Tristar,
Emo Oil, Republic of Liberia, J&S, OFSI Ltd, Petroleum Corp of
Jamaica,
2008
J&S, Ommart Ltd, Dainom Nig Ltd, AMG Petro Energy, Tacorr,
Roger Princeton, Rheinoel Ltd, Sterling Oil Resources,
Makwande, Alpha Petro Worldwide, Abacus, Ommart, Ovlas
2010 Sunoil Refinery, GNPC, J&S, Mercuria
2011
SPOG Petrochemicals, Sinclair Commercial, Sullom Voe, Liberia
Petroleum, Tocomo Oil, Centro Energy, Republic of Benin, Emo
Oil, Arcadia, Overt Energy, Rheinoel Ltd, Sarb Energy,
Table 11: Customers without formal contracts (Source: NNPC records)
13. NNPC Crude Oil Sales
Crude oil sales are a major source of government revenues. It
makes up roughly 70 percent of the Federation revenue. NNPC's
COMD sells government's share of production÷1,000,000 bpd or
more÷exclusively through one year term contracts. These
contracts grant holders the option to lift a set allocation of crude at
Official Selling Prices (OSPs). COMD quotes OSPs monthly for
each of Nigeria's 26 crude grades.
For the NNPC, an average of 20 to 30 crude oil liftings take place
each month with the standard lifting cargo capacity being at about
950,000 barrels. In some years (2007, 2010, 2011), the number
of contracted customers significantly exceeded available stock,
even though it was noted that there were some instances where
customers were sold less than the standard capacity.
From analysis of the list of customers provided over the 10 year
period, the consistent customers were: Addax, Arcadia, Calson,
Duke Oil, Glencore, Indian Oil Company, Ivory Coast, Napoil,
Petrodel, Sao Tome, Senegal, SINOPEC, Trafigura and Vitol. The
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Task Force research also found that quite a number of traders did
not demonstrate renowned expertise in the business of crude oil
trading. These traders have lifted crude oil only once over the 10
year period. These are Abacus Oil, AlphaPetro Worldwide,
Caligeria Oil Limited, Dainom Nig. Ltd, Gembrook Energy Ltd,
Global Gas and Energy, Kingsbury Trading, Makwande, Ommart
Ltd, Sinclair Commercial Ltd, Tacorr, Tempo Energy, Tocomo Oil,
Worldwide Energy.
The global trend is for national oil companies to develop their own
trading arms. NNPC has created at least five trading subsidiaries
of its own (Hyson, Calson, Napoil, Duke Oil and Nigermed),
however capacity is limited, and most function as financial and
operational black boxes.
NNPC maintains that its sales model is sound and fetches Nigeria
fair value for its crude. However, various submissions received by
the Task Force argued that the process was bureaucratic yet had
potential for discretion, waste and erosion of value in the nation's
petroleum revenues. Specifically, the Task Force identified the
following areas of concern.
First, Nigeria is the world's only major oil producer that sells 100
percent of its crude to private commodities traders, rather than
directly to refineries, as shown in the table below:
Selling most crude direct
to end-users
Relying somewhat
on traders
Relying totally or near-
totally on traders
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US
Chad
Canada
Yemen
Saudi Arabia
Malaysia
UAE
Indonesia
Kuwait
Syria
Iraq
Sudan
Iran
Algeria
Kazakhstan
Venezuela
Norway
Mexico
UK
EU
Russia
Angola
Libya
Singapore
Gabon
Equatorial Guinea
Cameroon
Colombia
Congo-Brazzaville
Southern Sudan
Nigeria
Table 12: Analysis of countries and use of crude traders
No technical or commercial problems prevent NNPC from building
its own full service trading desk, which seems to be the preferred
global best practice. The Corporation's use of oil traders raises
the following issues:
• Lost margins:
Nigeria should ideally be capturing for itself the estimated
average margins of US$100,000-400,000 per cargo made by
traders. COMD also awards a number of contracts each year to
"briefcase traders¨ with little or no commercial and financial
capacity. These small local outfits, then "flip¨ their cargoes to real
traders for a margin, reportedly US$0.20 to US$0.40 per barrel.
Such transactions add no value to the sector or the Nigerian
economy.
• Manipulation of pricing:
Submissions to the Task Force also alleged that there is
manipulation of OSPs. For example, it is alleged that traders are
allowed to choose the most lucrative pricing option for individual
cargoes retroactively. There is also a question of whether
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favoured traders may receive "subsidized¨ prices well below
market.
• Suboptimal returns from current term contract sales system:
NNPC's exclusive use of term sales may not always net Nigeria
best value for its oil, even without manipulation by traders and
officials.
• Market fraud:
The lack of transparency in Nigerian crude sales encourages
fraudulent activities. Allegations have been made of the existence
and circulation of forged documentation on crude allocation in the
local and international markets, increasing Nigeria's perception as
a high-risk market and discouraging bonafide purchasers.
• Government-to-Government (G-to-G) Sales:
Each year NNPC grants other countries, most of them Sub-
Saharan African neighbours, the option to buy approximately
200,000 bpd. Most of these countries cannot refine Nigerian
crude, so they hire private traders to finance, ship and sell the oil
to a third party elsewhere. The traders then either split final
margins with the foreign country, or pay the country a set per-
barrel commission (reportedly between US$0.20 and US$0.50
cents per barrel). NNPC denies that these transactions are
concessionary, and argues that "the nation does not lose¨ from
them. There is no evidence of the additional value to Nigeria in
revenue terms.
14. Cash Calls and Alternative Financing Arrangements
Nigeria faces a cycle of debt related to its equity participation in
six joint ventures. A review of NAPIMS's audited financial
statements as at 31 December 2009 showed that Joint Venture
cash calls payable was N459.568billion. This cycle may continue
to increase in the coming years unless a systemic solution is
found.
NNPC holds 55-60 percent equity shares in six joint ventures. In
2011, these licenses produced 1.5 million barrels per day, or 61
percent of Nigeria's total oil production. Each year, Government
allocates funds to NNPC to cover its share of joint venture
operational and capital expenses. These are the JV cash calls.
As is depicted below, JV costs have risen rapidly since 2005. This
is due to several factors such as increased global demand and
cost for industry services following high oil prices, unrest and
equipment sabotage in the Niger Delta occasioning higher
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security and repairs; and escalating cost despite existence of
NAPIMS and its control measures.
US$ million
total JV budgets
NNPC's share
(estimated at
58%)
Actually paid by
NNPC
Debt to
operator
2005 6,800 4,000 4,000 0
2006 8,100 4,698 4,101 597
2007 9,700 5,626 4,365 1,261
2008 12,400 7,192 4,924 2,268
2009 14,800 8,584 4,223 4,361
2010 17,700 10,266 NA NA
2011 17,200 9,976 NA NA
2012 18,000 10,440 NA NA
Table 13: NNPC JV cash call obligations, payments and debts, 2005-2012
Since 2006, government has not allocated enough funds to cover
these amounts. To cover the gap, NNPC has entered into a range
of borrowing arrangements with its company partners, referred to
as "Alternative Financing Arrangements.¨ These include:
• Carry agreements and modified carry agreements. These are
the most common form. In these cases, the carrying partner
recovers its funds through tax discounts or receipt of a portion
of the government's share of production.
• Third party debt financing. This project finance mechanism is
used to fund certain projects with robust cash flows, such as
four projects under the Mobil JV. For instance, in April 2012,
ExxonMobil and NNPC signed a $1.5 billion exploration
financing agreement, $900 million of which is borrowed from
commercial banks. NNPC holds $900 million of this debt.
• IOC bridge loans. NNPC has taken a bridge Loan from Shell
to cover unpaid performance of years prior to 2008.
The most prevalent model is for operators to recoup their costs
through waived taxes, or by receiving a portion of the
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Federation's share of production. In 2011, 473,000 barrels per
day, or 19% of total production, was designated as "Alternative
Funding¨ joint venture crude.
From all observable indications, cash call debts will continue to
rise while JV contracts remain operational. Additionally, JV costs
would increase if production levels are to be maintained in view of
increasing maintenance costs. Finally the costs of financing all
this debt (estimated at around 8%) are continuously mounting.
JV production may decline in the coming years unless investment
increases ÷ an outcome Nigeria cannot afford. Many fields are
undeveloped. High producing fields are peaking. Most of the
infrastructure is old. NNPC estimates that, by 2014, $3.7 billion in
new drilling costs will be needed annually to simply retain current
production levels (much less to increase production). Given the
higher government take of the JVs, maintaining production levels
is essential for Nigeria to sustain oil earnings. The higher
investment needed, however, will mean larger cash calls. We
however note that production peaked recently at 2.7m barrels a
day. Many factors have been alleged to have contributed to this
achievement principal of which has been the success of the
administration's amnesty programme which has reduced
insecurity within the producing regions. Whilst the current
success is commendable it may not be sustainable in the long run
unless a comprehensive strategy is adopted and implemented to
address the noted areas of decline observed in the Report.
15. Upstream cost oversight and tax assessment
As JV partners there is need for the effective management and
oversight of oil companies' operating costs. This is because
higher operating costs of the oil companies reduce tax payments,
tend to increase NNPC's JV cash call obligations and increase
cost oil under PSCs.
The impact of these issues on Nigeria's revenues accruable from
the industry is highlighted by the following:
• Various companies have argued that Nigeria is uniquely
expensive due to the security problems, equipment sabotage,
local content requirements, and industry delays which
arguably add to costs. This makes it more difficult for the
authorities to evenly compare costs in Nigeria with those in
other countries to assess reasonableness. It also means
companies can more easily inflate costs.
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• There is an inherent conflict in NNPC's role as both a
participant in the industry and a cost regulator (via NAPIMS).
• Capacity constraints impair both the NAPIMS cost regulator
and FIRS tax assessor functions.
• The current bureaucratic cost regulation processes at
NAPIMS and the overlapping responsibilities of the agencies
delay investment decisions in the industry above industry
averages.
• Control of training programme for NNPC, NAPIM and DPR
staff by the contractor/IOC generates conflict of interest as
there is potential for perception of compromise in regulation in
exchange for expensive overseas training programmes.
Several short-term steps can be taken to reduce these risks and
capture Nigeria's fair share of the revenues, while long term
reform and capacity development will improve this situation in the
long term.
16. National entitlement in a JV
Based on production and lifting data by operator, obtained from
NNPC, we performed an analysis to establish whether the
government is receiving crude oil entitlement in accordance with
the provisions of the various joint operating agreements as
modified by the alternative funding and modified carry
agreements. See Table 14 for detailed analysis.
We observed the following lifting percentages:
Contractual
entitlement 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011
Shell
55%
55% 54% 55% 53% 56% 54% 58% 53% 56% 56%
Chevron
60%
60% 59% 61% 60% 60% 60% 60% 49% 62% 74%
AGIP/PHILLIPS
60%
60% 60% 65% 61% 56% 58% 56% 60% 61% 60%
MOBIL
60%
60% 60% 60% 60% 76% 58% 57% 54% 72% 124%
ELF
60%
61% 61% 60% 61% 58% 59% 56% 65% 62% 59%
TEXACO
60%
68% 59% 56% 52% 80% 42% 46% 66% 72% 52%
PAN OCEAN
60%
52% 73% 53% 62% 41% 0% 72% 0% 18% 72%
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Table 14: Percentage of government lifting to total JV production (Source:
NNPC)
Shell Chevron
AGIP/
PHILLIPS MOBIL ELF TEXACO
PAN
OCEAN
2002 (545,748)
(393,966) 263,734
(436,622) 348,124
739,959
(346,002)
2003 (2,481,889)
(940,268) (273,792)
(414,646) 369,134
(51,090)
569,132
2004 1,256,776 1,270,874 3,441,711
648,775 19,615
(244,080)
(520,643)
2005 (5,121,577)
(168,638) 655,429
(372,463) 895,452
(438,713)
214,415
2006 887,700
18,935 (2,335,577)
35,646,569 (1,742,704)
931,212
(219,656)
2007 (1,818,828)
(296,806) (986,707)
(4,719,880) (1,107,992)
(390,745)
-
2008 3,600,933
(584,040) (1,647,883)
(4,736,312) (3,326,856)
(586,375)
1,124,884
2009 (2,117,118) (10,208,937) 68,460
(8,919,080) 3,242,685
248,011
(1,537)
2010 1,071,071 2,076,726 368,510
19,930,192 1,051,046
506,757
(1,353,259)
2011 2,154,960 13,718,474 58,102
104,130,905 (576,046)
(318,444)
302,191
Total (3,113,721) 4,492,354 (388,011)
140,757,438 (827,541)
396,491
(230,476)
Table 15: Difference between government lifting and contractual entitlement under the
JOA (expressed in barrels of oil)
On enquiry from NNPC, the reasons for the differences are
mainly due to the fact that the lifting data provided for some of the
operators (particularly Chevron and Mobil), have not been
segregated by agreement type.
In the absence of accurate information on entitlements and lifting
per contract type, the Task Force could not arrive at an accurate
conclusion as to whether the government is receiving their
contractual entitlements or not, in the joint venture agreements.
17. Carrying parties in the carrying agreements recover in
excess of 10% of the capital cost through investment tax
allowances
RCE is the quantity of carry oil/gas determined in US dollar
equivalent and corresponding to the unrecovered residual carry
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capital expenditure. In other words, it represents the outstanding
principal and interest due from NNPC in the carry agreements.
We observed two (2) distinct methods of calculating RCE from the
contracts reviewed. The earlier contracts calculated RCE as
Carry tax expenditure less carry tax relief less carry oil recovered,
divided by the guaranteed notional margin. The later contracts
calculated RCE as cumulative capital cost amortized and
expensed to date less cumulative tax relief less carry oil/gas,
divided by the incremental notional margin.
CTE = the cumulative amount of capital allowances, including any
investment tax allowances.
This implies that in determining the reimbursable capital in the
earlier contracts (EA/EJA Field Development (Shell) and
Amenam/Kpono Field (OMLs 99 and 70-Elf)), the carrying parties
are recovering 10% in excess of the capital cost, representing the
investment tax allowance. In the case of the Elf agreement, the
amount of the investment allowance on the total capital cost of
US$697 million, will be in the range of US$69.7 million, recovered
in excess of capital cost carried. Total capital costs include
intangible and tangible capital expenditure.
18. Shared oil allocation
Shared oil means the quantity of oil production available after
allocating the participating interest share of oil production to the
operator and allocating carry oil to the operator. Royalty and tax is
deducted from the shared oil allocated to the operator, leaving it
with the actual fiscal margin for each shared oil barrel allocated to
it, as compensation for the cost of the carry. We observed that
the percentage of share oil allocated to the carrying party ranges
from 6.5% to 50%. In addition, based on the defined financial
models and the stage of the project, incremental notional margin
ranges from $6 to $14 per barrel.
The basis of the determination of shared oil varies from one
agreement to the other. See Table 16 below for details.
Carry agreement Basis of allocation of shared oil
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Between NNPC and Total E&P
for Ofon Phase 2 Project
Agreement date ÷ 24 November
2008
Share Oil= (SOE-SOR)/INM
Where
SOE=Share Oil Entitlement
SOR = Share Oil lifted and marketed by NNPC for and on behalf of
TEPNG in previous months. Value in US$
INM= Incremental Notional Margin of TEPNG
Between NNPC and ELF
Petroleum Nig Ltd for the
development of the
Amenam/Kpono Field (OMLs 99
& 70)
Agreement date ÷ 7 June 2000
Shared Oil is shared between NNPC and the Carrying party in the
ratio of 55% to NNPC and 45% to the Carrying party.
It is hereby expressly agreed by the parties that with effect from the
effective date of the new MOU superseding the ELF MOU, which
new MOU contains a revised notional margin of US$2.70 per
barrel, shared Oil will be shared between the Parties in the ratio of
59.1% to NNPC and 40.9% to the Carrying party
Between NNPC and Chevron
Nigeria Limited for the Meji Re-
development Project
Agreement date ÷ 20 May 2005
Share Oil is shared between NNPC and the Carry Party in the ratio
of 25.5% CNL and 74.5% NNPC. The carry party pays PPT and
Royalty for the crude in its hands.
Between NNPC and Chevron
Nigeria Ltd for the Meren-X-
Platform Project Agreement date
÷ 20 May 2005
Share Oil is shared between NNPC and the Carry Party in the ratio
of 6.5% CNL and 93.5% NNPC. The carry party pays PPT and
Royalty for the crude in its hands.
Between NNPC and Chevron Nig
Ltd for the Delta South Central
Development Project
Agreement date ÷ 20 May 2005
Share Oil is shared between NNPC and the Carry Party in the ratio
of 16.5% CNL and 83.5% NNPC. The carry party pays PPT and
Royalty for the crude in its hands.
Between NNPC and Shell and
Total E&P and Nig AGIP Oil
Company Ltd for the Cawthorne
Channel Integrated Project
Agreement date ÷ 27 November
2008
Share Oil= (SOEV-SOR)/INM
Where
SOEV=Share Oil Entitlement Value (the after-tax and royalty value
in US$ of Share Oil entitlement due up to the current month) as per
the schedule defined in the financial model.
SOR = Share Oil value received (the after-tax and royalty value in
US$ of Share Oil lifted and marketed by NNPC for and on behalf of
the Carrying Parties in previous months.
INM= Incremental Notional Margin of the Carrying parties
The value of Share Oil to be received by the carrying parties in the
current month shall be the share oil entitlement value less the value
of the Share Oil received by the carrying parties in the previous
months.
Between NNPC and Shell
Petroleum Development
Company and ELF Petroleum
Nig Ltd and Nigerian Agip Oil
Company
Agreement date ÷ 17 November
1999
Share Oil is shared between NNPC and the Carry Party in the ratio
of 50% CNL and 50% NNPC. The carry party pays PPT and
Royalty for the crude in its hands.
Between NNPC and Chevron Nig
Ltd for the Escravos Gas to
Liquids (EGTL) project
Agreement date ÷ 14 August
2001
Share EGTL products are shared between NNPC and the Carry
Party in the ratio of 50% to NNPC and 50% to the Carrying Party.
The carrying party's share of shared EGTL products shall be
subject to the same tax treatment as its participating interest share
of EGTL Products
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Modified Carry Agreement
Between NNPC and Mobil
Producing Nigeria Unlimited
Share Oil= (SOE-SOR)/INM
The value of Share Oil to be lifted and marketed by NNPC for and
on behalf of MPN is the Share oil entitlement less the value of the
Share oil lifted and marketed by NNPC for and on behalf of MPN in
the previous months.
Modified Carry Agreement
Between NNPC and Shell
Petroleum Development and
Total E&P Nig Ltd and Nig Agip
Oil Company Ltd for the
GBARAN Ubie Phase 1 Project
Agreement date ÷ 24 February
2009
Share Oil= (SOEV-SOR)/INM
Where
SOEV=Share Oil Entitlement Value (the after-tax and royalty value
in US$ of Share Oil entitlement due up to the current month) as per
the schedule defined in the financial model in appendix 2.
SOR = Share Oil value received (the after-tax and royalty value in
US$ of Share Oil lifted and marketed by NNPC for and on behalf of
the Carrying Parties in previous months.
INM= Incremental Notional Margin of the Carrying parties
The value of Share Oil to be received by the carrying parties in the
current month shall be the share oil entitlement value less the value
of the Share Oil received by the carrying parties in the previous
months.
Modified Carry Agreement
Between NNPC and Total E&P
Nig Ltd for OML 58 Upgrade Gas
Export
Agreement date ÷ 14 October
2008
Share Oil= (SOE-SOR)/INM
Between NNPC and Shell
Petroleum Development
Company and Total E&P and
Nigerian Agip Oil Company Ltd
for the
Nembe Creek Trunkline Project
Nembe Creek Field Logistic
Base
Nembe Creek Phase 1 Project
Santa Barbara Phase 1 Project
Agreement date ÷ 12 December
2008
Share Oil= (SOEV-SOR)/INM
The value of Share Oil to be received by the carrying parties in the
current month shall be the share oil entitlement value less the value
of the Share Oil received by the carrying parties in the previous
months.
Table 16: Summary review of the basis of shared oil allocations for the various
carry agreements
19. Implicit cost of alternative funding arrangements
NNPC provided the Task Force with production and lifting
volumes under the various alternative funding arrangements. The
differences in percentages from the baseline contractual
agreements of 55% with Shell and 60% with the other joint
ventures can be interpreted as the cost of the carry agreements,
being incurred by NNPC.
We found that the fluctuation in government take between various
projects was wide. This leaves room for arbitrariness. If NNPC
gets 74% in one instance, why does it take 55% in another
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instance? There is need to eliminate or adequately explain such
arbitrariness so the basis on which NNPC acts is clear and
transparent.
NNPC informed the Task Force that in the case of Chevron and
Mobil, lifting data provided for some of the operators have not
been segregated by agreement type. This implies that some of
the liftings made by NNPC are more than actual NNPC liftings, as
they include liftings made and sold on behalf of the operators.
Year
Shell Production
(bbls)
Chevron
Production (bbls)
Mobil
Production (bbls)
Elf Production
(bbls)
2003
26,768,881 - 38,869,336 6,436,445
2004
43,071,975 3,138,185 43,106,427 32,656,414
2005
42,439,487 9,083,259 73,694,178 40,909,893
2006
3,418,766 9,121,439 91,516,761 40,250,115
2007
- 6,927,280 71,116,205 40,535,587
2008
- 4,941,662 28,873,600 36,420,384
2009
6,096,195 21,703,939 76,845,529 26,851,534
2010
29,746,886 24,758,070 89,673,390 21,808,427
2011
23,080,837 24,472,853 102,488,316 22,965,461
Total
174,623,027 104,146,687 616,183,742 268,834,260
Shell Lifting/
Entitlement
(bbls)
Chevron
Lifting/ Entitlement
(bbls)
Mobil Lifting/
Entitlement
(bbls)
Elf
Lifting/ Entitlement
(bbls)
2003
- - 12,344,101 -
2004
8,208,489 1,882,911 14,241,265 349,610
2005
11,366,628 4,667,007 30,901,102 13,136,805
2006
1,865,460 3,184,337 15,455,790 12,829,913
2007
- 3,876,368 35,519,350 8,037,498
2008
- 2,392,769 18,230,459 10,014,611
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Year
Shell Production
(bbls)
Chevron
Production (bbls)
Mobil
Production (bbls)
Elf Production
(bbls)
2009
960,061 10,508,501 45,342,125 11,154,952
2010
8,408,407 9,645,512 43,697,662 9,409,471
2011
5,646,750 3,411,834 24,751,615 8,604,953
Total
36,455,795 39,569,239 240,483,469 73,537,813
% of
lifting/entitlement
over production
Shell Chevron MOBIL ELF
2003
0% 0% 32% 0%
2004
19% 60% 33% 1%
2005
27% 51% 42% 32%
2006
55% 35% 17% 32%
2007
- 56% 50% 20%
2008
- 48% 63% 27%
2009
16% 48% 59% 42%
2010
28% 39% 49% 43%
2011
24% 14% 24% 37%
Average total
21% 38% 39% 27%
Table 17: Production and Lifting Data for IOCs
20. Generous provisions in the Production Sharing
Contracts
Some of the provisions of the PSCs and deep offshore and inland
basin Act are generous compared with other existing agreements
and do not reflect current economic realities. These include:
Royalty rate ÷ The payment of royalty in respect of deep offshore
PSCs is graduated as follows:
o In areas from 201 to 500 metres water depth 12%
o From 500 to 800 metres water depth 8%
o From 801 to 1000 metres water depth 4%
o In areas in excess of 1000 metres water depth 0%
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o Inland basin PSC 10%
The applicable petroleum profit tax rate for deep offshore and
inland basins of 50% as compared to 65.7 ÷ 85% for
onshore/shallow offshore.
Investment tax credit of 50%/Investment tax allowance of 10%
21. Interpretation of the Production Sharing Contracts
Some of the clauses of the contracts are ambiguous and subject
to multiple interpretations. Parties translate the contracts to
template models which are used for the determination of
entitlements.
Examples of contentious interpretations, as obtained from the
review of the contracts and discussions with stakeholders include:
• Applicable rate of royalty for crude coming from wells in
varying water depths
• Whether signature bonuses are tax deductible
• Entitlement's carried forward in volumes or proceeds
• Ring fencing/Consolidation of costs
• Segregation of liftings
• Determination of realizable price etc.
This creates reconciling differences between NNPC, DPR and the
oil companies as to the amount of royalties, cost, tax and profit
oil. The impact of these observations is a lack of clarity in
determination of government revenues. A clear finding is that due
to various interpretations the law in this area is uncertain and
need to be clarified. Also the dispute resolution mechanism for
resolving issues of interpretation between FGN, NNPC and the
IOCs does not seem to be working effectively.
22. Budget, work plans versus cost verification
The operators prepare their budgets and work plans for the year
and these are approved by the management committee. The
management committee consists of 10 persons, appointed by the
parties (NNPC: 5, Contractor: 5). Should NNPC wish to propose a
revision, as to specific features of the said work programme and
budget, it shall within eight (8) weeks after receipt of the work
program and budget, notify the contractor in writing, specifying in
reasonable detail the changes requested and the reasons thereof.
The Management committee shall resolve the requests for
revisions proposed by NNPC. Considering the composition of the
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management committee, where revisions are proposed by NNPC
and NNPC does not present a unified front of its entire
representative, the revision might not pull through.
At the end of the year, the work program and budgets are
compared to actual performance on a code by code basis.
NAPIMS reviews performance against approved work programs,
as well as cash call paid during the year. Periodically (bi-
annually), NAPIMS reviews the invoices for the reported
performance. Upon verification of costs, work programme is
signed off, as agreed.
In determination of entitlements, cost is a critical input for the PSC
as this determines the cost oil to be lifted by the contractors. The
initial cost used for calculation of entitlements represents the
reported performance of the company. This is actualized upon
NAPIMS's verification and certification of the cost.
The implication of this is that in the event that the costs are not
approved for years (as is obtainable in some instances); the
entitlement determination cannot be final.
23. Human capacity needs at NAPIMS
There is a clear training, technology and human capacity gap
between NAPIMS staff and their counterparts in the private oil
and gas sector. Certain NAPIMS activities are performed without
the required depth and speed of a cost regulator that would aid
quick investment decisions. NAPIMS' capacity challenges should
be bridged to enable detailed analysis using independent
benchmarks to verify cost submissions by operators.
24. Determination of realizable price
The basis for determination of realizable price is explicitly defined
in the PSCs. The intent, as defined in the PSCs, is to ensure that
prices reflect the true market value based on arm's length
transactions.
Realizable price is very important under the PSCs as royalty oil,
cost oil, tax oil and profit oil are all converted from proceeds (in
US$) to barrels of oil, using the realizable price. The operators
and NNPC are hardly able to come to a consensus on what the
realizable price, to be used in entitlement determination is. This
results in reconciliation differences.
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Nevertheless, the contracts provide that the records of the
Ministry of Petroleum Resources (represented by NNPC) will
prevail. We compared the realizable price used in determining
entitlement for NNPC/NAE PSC for the Abo Light crude with the
Brent Blend prices (source: EIA)
9
, for the period under review.
The Abo Light crude is priced in similar terms with the Brent
Blend.
The price as determined by the Ministry of Petroleum Resources
should prevail ending the need for any disputes.
25. Opportunity cost ÷ Purchase or lease of equipment
The contract provides that equipment purchased and financed by
the contractor, to be used in petroleum operations, in the contract
area, shall become the property of NNPC, on arrival in Nigeria.
The contract also provides that the above provision does not
apply to leased equipment belonging to local or foreign third
parties. This implies that the choice of leasing by oil companies
may lead to decline in the potential revenues accruable to the
Federation in its joint venture operations.
26. Differences in the sales information provided by the
NNPC and NAPIMS
We compared the amounts provided as revenues with the
amounts recorded in the latest available financial statements of
NAPIMS for the years 2009 and 2008. FGN's crude oil sales are
recorded in the books of NAPIMS and this is not consolidated by
the NNPC.
2009
NAPIMS Financial
statements !US$'000
NNPC revenue
schedules!US$'000 Difference US$'000
Equity crude 9,575,506 5,334,666 4,240,840
Domestic crude 9,903,033 9,903,033
(0)
Total 19,478,539 15,237,700 4,240,839
2008
Equity crude 16,518,320 17,772,860 (1,254,540)
9
source: EIA
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2009
NAPIMS Financial
statements !US$'000
NNPC revenue
schedules!US$'000 Difference US$'000
Domestic crude 15,599,104 15,561,980 37,124
Total 32,117,424 33,334,839 (1,217,415)
2007
Equity crude 17,021,863 15,229,031 1,792,832
Domestic crude 11,624,328 11,531,243 93,085
Total 28,646,191 26,760,274 1,885,917
2006
Equity crude 15,391,648 14,982,798 408,850
Domestic crude 9,943,796 10,598,620 (654,824)
Total 25,335,444 25,581,418 (245,974)
2005
Equity crude 16,302,777 16,290,789 11,988
Domestic crude 8,704,165 8,704,165
(0)
Total 25,006,942 24,994,955 11,987
2004
Equity crude 11,894,316 11,544,161 350,155
Domestic crude 5,718,429 5,687,519 30,910
Total 17,612,745 17,231,680 381,065
2003
Equity crude 7,758,499 7,740,499 18,000
Domestic crude 3,359,337 3,473,419 (114,082)
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2009
NAPIMS Financial
statements !US$'000
NNPC revenue
schedules!US$'000 Difference US$'000
Total
11,117,836 11,213,917 (96,081)
2002
Equity crude 5,891,001 5,891,001
(0)
Domestic crude 2,944,981 2,944,981
0
Total 8,835,982 8,835,982
0
Table 18: Differences in crude oil revenue as recorded by NAPIMS and
compared to NNPC s data.
12. Sale of the National Entitlement (Gas)
8. Overview
Nigeria is endowed with abundant natural gas resources, which in
energy terms, is in excess of the nation's proven crude oil
reserve. More so, the gas was discovered whilst searching for
crude oil, as no deliberate effort had been made to search for
natural gas. The current reserved estimate of the Nigerian gas is
over 120 (EIA: 187 as of December 2010) trillion cubic feet, with
about 50/50 distribution ratio between Associated Gas (AG) and
Non Associated Gas (NAG).
In order to diversify its revenue base and reduce the huge
wastage of valuable resource as well as the degradation of the
environment as a result of flaring, the Nigerian Government,
through the NNPC, is vigorously pursuing a number of natural gas
utilization projects with its joint venture partners whereby
associated gas would be harnessed to achieve these objectives.
Current Fiscal Incentives in the Nigerian Oil and Gas Industry are
as follows:
• All capital costs of upstream gas investments up to the
custody transfer points are treated as oil investments and
the resulting capital allowances are deducted from PPT (at
a marginal rate of 85%). These incentives also apply to
some downstream investments.
• The upstream producer is exempted from payment of
royalty and PPT on any gas that is transferred to a
downstream project.
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• The LNG projects receive a 10-year tax holiday/break.
• The LNG project is also exempted from withholding tax on
interest and dividends paid to non-residents and from
income tax on work or services provided by non-residents.
• There is an additional investment allowance of 20% for
upstream projects, 35% for NGL extraction and gas-to-
liquid facilities and 15% for downstream projects.
• Downstream investments receive accelerated capital
allowances of 90% of cost of plant and machinery
expenditure in the first year with 10% retention.
• Downstream gas projects which received a 3-year tax
holiday/break that begins on the first day of production, is
renewed for a further 2 years,
• Accumulated capital allowances can be carried forward
until the end of the holiday. Qualifying dividend distribution
during the tax holiday is tax-free.
• Downstream projects are allowed to fully deduct interest
on project-financing for corporate income tax purposes.
• The table below depicts gas produced in Nigeria from the
joint ventures, PSCs and service contracts, over the 10
year period. (figures in thousands MMSCF)
2002 2003 2004 2005 2006 2007 2008 2009 2010 2011
SPDC 532 686 739 696 720 832 831 459 776 865
MPNU 388 361 434 456 505 527 478 469 490 440
CNL 197 206 210 244 241 212 236 174 215 274
NAOC 376 388 434 429 439 428 386 360 419 458
TEPNG 122 139 210 227 280 335 372 294 286 264
POOC 22 20 27 27 4 - 20 0 10 16
TOPCON (TEXACO) 22 16 14 - - - - - - -
NNPC JV TOTAL 1,660 1,816 2,068 2,079 2,189 2,334 2,323 1,755 2,195 2,315
ADDAX ( ADANGA,
OKWORI & INDA
PPs) 33 39 38 48 55 76 84 78 83 82
AENR ( AGBARA PP) 9 8 14 15 28 30 21 19 18 9
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NAE (ABO FPSO) - - - - - - - - - 10
SNEPCO (BONGA
FPSO) - - - - - 59 53 52 57 47
ESSO (ERHA FPSO) - - - - - 107 126 123 139 134
TUPNI(AKPO FPSO) - - - - - - - - - 151
STAR DEEP WATER
( AGBAMI FPSO) - - - - - - - - - 124
PSC-SC TOTAL 42 46 52 62 83 272 284 273 298 558
NNPC JV AND PSC
TOTAL 1,702 1,862 2,120 2,141 2,272 2,606 2,607 2,028 2,493 2,873
Table 19: Gas Production (Source: NAPIMS)
The natural gas produced in Nigeria, (associated and non-
associated gas) is currently utilised as follows:
• NLNG Feedstock, being raw materials for the Nigeria LNG
plant
• Domestic Gas managed by Nigeria Gas Company (a
subsidiary of NNPC)
• Natural Gas to Liquids Projects. There are currently 2
operating joint venture projects between NNPC on the one
hand and Chevron (Escravos) and Mobil (Oso), on the
other hand.
• Fuel Gas ÷ used in production
• Gas reinjection/Gas lift make -up
• The balance unutilized is flared. Products from gas
comprise ethane, methane, propane, butane and
penthane+.
See Table 20 and Figure 3 below for breakdown of how the gas
produced is utilized.
UTILISATION/FLARED 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011
Fuel Gas 61 69 81 88 86 98 100 97 119 138
LNG 285 460 523 503 689 958 1,032 609 913 1,125
NGL / LPG 43 36 57 69 48 46 48 48 85 62
Dom Sales 93 176 202 240 207 221 220 210 244 308
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Gas Re-injection / Gas Lift
Make Up 330 301 447 471 474 546 583 576 653 805
Gas flared 891 820 810 770 769 737 623 488 479 435
1,702 1,862 2,120 2,141 2,272 2,606 2,607 2,028 2,493 2,873
Table 20: Gas Flared - figures in thousands MMSCF (Source: NAPIMS)
Figure 3: Natural gas to liquids (NGLs)/Liquefied Petroleum Gas (LPG)
NNPC, alongside other major joint venture operators have
embarked on several gas- to- liquid utilization projects. The
existing projects are:
Escravos Gas Project (EGP) - EGP 1, the first major gas project
to gather and process associated natural gas in Nigeria, came on
stream in 1997. NGLs are stripped for export and the remaining
gas is used domestically. The Escravos gas-to-liquids plant
came online in 2005. The 33,000-barrel per-day plant utilizes
Johannesburg-based Sasol Ltd.'s proven synfuels conversion
technology. The plant produces premium-quality, ultralow- sulfur
diesel fuel and naphtha sold in Europe and the United States.
Oso NGL Project - Mobil JV NGL plant, located at its Oso field in
the south-eastern part of Nigeria started production for export
during the third quarter of 1998. The Project provides additional
gas make-up for the Oso NGL as well as maintains condensate
production at the expected plateau.
Although we have not been provided with the separate gas
agreements covering these projects, we have been informed that
the agreements are in a joint venture structure, where NNPC is
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entitled to 60% participating interest under the Chevron project
and 49% participating interest under the Mobil project.
9. Findings
27. Gas sales proceeds ($946.878million) due to the Federation
from SNEPCO
According to the NNPC (NAPIMS) Financial Statements for the
year ended 31 December 2009, a total of N137, 572 billion
($946.878 million) is due to the Federation from SNEPCO. This
amount represents the proceeds of gas sales from the Bonga oil
field (OPL 212) held by SNEPCO, the production sharing
contractor operating the field. Included in the amount is the sum
of N17.325billion which is the gas tax payable on the amount.
The PSC clause 20.1 states that If the Contractor discovers a
commercially viable quantity of natural gas the Corporation shall
require the contractor to investigate and submit proposals for the
commercial development of the natural gas for the corporations
consideration provided that any cost in respect of such proposals
or investigation shall be included in Operating Cost.
For the commercial development of natural gas field, the funding
arrangements and participation by the Contractor in the project
shall be the subject of another agreement and the contractor shall
have the right to participate in such development project.
However, the Bonga oil field has been producing and selling gas
since 2007. There is no available record that a separate contract
agreement with respect to gas exists for the field as required by
the PSC to determine the funding arrangements and participation
by the contractor (in this case, SNEPCO). The absence of a
separate agreement presupposes that the gas is owned by
Nigeria and therefore, the proceeds thereof.
28. Fuel Gas & Gas Re-injection/Gas Lift Make-Up Utilisation
Gas reinjection is the reinjection of natural gas into an
underground reservoir, typically one already containing both
natural gas and crude oil, in order to increase the pressure within
the reservoir and thus induce the flow of crude oil or else
sequester gas that cannot be exported. On the other hand, Gas
lift is the situation where gas is injected into the annulus of the
well rather than the reservoir. After the crude has been pumped
out, the natural gas is once again recovered. Since many of the
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wells contain heavy crude, this process increases their
production.
The earlier joint operating agreements contain no specific
provisions for gas discoveries. They (Article 13) however provide
that "each party shall have the right to nominate, lift and
separately dispose of its participating interest share of available
production of petroleum¨.
The later joint operating agreements (NPDC Agreements) Article
18 provide that "it may be necessary for the parties to enter into
special arrangements, for the disposal of natural gas in
accordance with the 'Natural Gas clause' of the standard PSC
and any other requirements therein.
If a discovery of crude oil which is a commercial discovery, but
the associated natural gas cannot all be used in production, flared
or economically reinjected, then the parties shall attempt to
negotiate agreements with the NNPC. These should provide for
an appropriate economic interest for the contractor in the
development of such natural gas and allow for its economic
disposal simultaneously with the crude oil, taking into account, as
far as practicable, the international value of alternate fuels. If non-
associated gas is discovered and the parties desire to pursue the
development of the same, then the parties shall attempt pursuant
to the 'Natural Gas clause' of the PSC, to negotiate agreements,
with the Corporation and other involved parties, which shall
provide for an appropriate economic interest for the contractor in
its development¨.
The PSCs Clause 20/22/23 (depending on specific PSCs) provide
that¨ if the contractor discovers sufficient volumes of natural gas
whether or not associated with crude oil that could justify
commercial development, the contractor shall report the volume
of potentially recoverable natural gas to NNPC and shall upon
NNPC's request, investigate and submit proposals to the NNPC
for the commercial development of said natural gas taking into
consideration, local strategic needs as may be identified by
NNPC. Any cost in respect of such proposals or investigation
after the final investment decisions has been achieved presented
by the contractor to the NNPC shall be included in the operating
costs for the commercialization of the natural gas.
For the commercial development of natural gas, the NNPC and
contractor shall enter into a gas development agreement. Such
agreement shall recognize that the contractor has the right to
participate in such development project, with the right to recover
the costs and share of profits.
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Notwithstanding the provisions above, the contractor may utilize
at no cost, any proportion of the produced natural gas, required
as fuel for production operations, gas recycling, gas injection, gas
lift or other crude oil enhancing recovery schemes, stimulation of
wells necessary for maximum crude oil recovery in the field
discovered and developed by the contractor and such usage shall
be with prior written consent of the NNPC, which consent shall
not be unreasonably withheld.
The implication of the above clauses is that gas designated as
fuel gas and gas reinjection/gas lift make-up, with a potential
value over the 10 year period under review of US$46 billion,
technically bears no value to the Federation, as provided by the
agreements.
29. Liquefied Natural Gas (LNG)
A significant portion of Nigeria's marketed natural gas is
processed into LNG. Nigeria's main natural gas project is the
Nigeria Liquefied Natural Gas (NLNG) facility on Bonny Island.
Partners include: NNPC, Shell, Total, and Agip. NLNG currently
has six trains and a production capacity of 22 million metric tons
per year (1.1 Tcf). A seventh train is under construction but this
addition has been delayed until sometime after 2012.
Three additional LNG plants with a total of seven trains were
expected to come online after 2012, but their expected start-ups
have been postponed beyond 2016. Plans included OK LNG (4
trains), Brass LNG (2 trains), and Progress LNG (1 train). These
are in varying stages of development and investment decisions
will depend heavily on security, world LNG markets, and the final
outcome of the provisions of the Petroleum Industry Bill.
Availability of natural gas will also depend on Nigeria's efforts to
expand the use of natural gas for domestic electricity generation.
See table below for details of LNG produced, implied share
received by NNPC, LNG feedstock sold by NNPC to Nigeria LNG
Year
LNG
Produced
000's
(mmscf) - a
LNG Feedstock
supplied by NNPC
000's
(mmbtu) ÷ b
LNG Feedstock
(converted to
mmscf)
000's
c=b*0.0009704
mmscf
% of LNG
produced
d=c/a
International
Market Price
(EIA) ÷f
US$
Expected
revenue
h = c*f
US$'m
Actual
revenue
per NNPC
000'scf
= i
US$'m
Deficit
h-i
US$'m
2002 285 210,880 205 72% 4 835 96 738
2003 460 303,374 294 64% 4 1,321 158 1,164
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2004 523 337,545 328 63% 5 1,618 197 1,421
2005 503 330,895
321 64% 6 1,853 228 1,625
2006 689 477,530 463 67% 6 2,802 392 2,410
2007 958 618,846
601 63% 6 3,758 540 3,218
2008 1,032 633,115
614 60% 8 4,718 753 3,965
2009 609 430,360
418 69% 8 3,464 415 3,049
2010 913 646,031 627 69% 11 6,584 1,208 5,375
2011 1,125 724,466 703 62% 11 7,862 1,641 6,220
29,186
Table 21: NLNG Feedstock
From the percentages depicted above, NLNG seems to be
receiving their participating interest in gas operations and even
more.
However, the price at which the feedstock gas is sold to NLNG
seems too generous, compared to prices obtainable on the
international market. The Task Force is yet to obtain the gas
supply and sales agreements from NNPC, to establish and
understand the basis of the pricing.
The estimated cumulative of the deficit between value obtainable
on the international market and what is currently being obtained
from NLNG, over the 10 year period, amounts to approximately
US$29 billion.
30. LPG produced by Agip and Shell
We are aware of the NGL gas projects with Chevron and Mobil.
From our review of data provided by NAPIMS, Agip and Shell
Joint Ventures also produce NGL/LPG, for which we have not
been able to trace the revenue streams to the Federation
Account. It should be noted that Shell produced LPG in 2010
only. The estimated revenue from the gas produced for NGL/LPG
under these ventures is depicted in the table below:
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Year
Total
country
production
of Natural
gas for
NGL/LPG
(mmscf) - a
Mobil &
Chevron
production
of Natural
gas for
NGL/LPG
(mmscf) - b
Difference
accounted
for by Agip
and Shell
(2010)
production
(mmscf)!c=a-
b
Expected
NNPC's
share of
difference!d
International
market price of
natural
gas!US$!e
Valuation
of
difference!
US$'m!f
=d*e
2002 43 43 - - 4 -
2003 36 29 (6) (4) 4 (17)
2004 57 39 (18) (11) 5 (52)
2005 69 50 (18) (11) 6 (64)
2006 48 42 (6) (3) 6 (21)
2007 46 26 (20) (12) 6 (74)
2008 48 27 (21) (13) 8 (97)
2009 48 33 (15) (9) 8 (72)
2010 85 30 (55) (32) 11 (332)
2011 62 32 (30) (18) 11 (202)
(189) (931)
Table 22: Estimated Revenue from the Gas Produced for NGL/LPG
31. LPG produced by Chevron/Mobil
Minimum expected revenue from natural gas produced for LPG
was computed as gas produced multiplied by International market
price of gas (Source of gas prices: EIA). This was compared to
the sales proceeds made by NNPC from sale of LPG (export and
domestic). It was observed that gains of about 286% were made
in the LPG projects with Chevron and Mobil, over the 10 year
period.
13. Sale of Refined Petroleum Products
10. Findings
32. Major marketers debt as at 31 December 2011 (N27 billion)
NNPC is owed N27billion by the major marketers of petroleum
products. This includes current debt, total overdue, disputed debt
and total debt outstanding (Table 23).
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Marketers Current debt
N' m
Total Overdue
N' m
Disputed debt
N' m
Total Debt
Outstanding N' m
CONOIL 865.06 3,208.47 177.65 4,251.18
MOBIL 620.51 753.76 3.61 1,277.88
TOTAL 1,097.02 1,650.07 373.71 3,020.80
MRS 348.95 4,960.27 169.20 6,478.43
OANDO 822.89 3,452.62 332.74 4,608.25
FORTE 528.40 3,303.86 200.64 4,032.89
OTHERS - - - 3,746.13
Grand Total 4,282.83 17,329.04 1,257.55 27,415.56
Table 23: Consolidated Major Marketers Debt as at 31/12/2011
33. Outstanding amounts due to importers of refined petroleum
products ($3.6billion)
The total amounts payable to suppliers of petroleum products, as
at 31 December 2011 amounts to approximately US$3.6 billion, of
which US$2.7 billion represents amounts outstanding for over 365
days.
S/N Supplier
Amount in
US$ 'm Amount in NGN 'm
1 Addax Energy S.A 206.65 30,947.93
2 Allemaine Intl 0.21 32.04
3 Amaz Oil 107.19 16,072.90
4 AOT Trading AG 57.19 8,588.30
5 Arcadia Petroleum 269.30 40,212.18
6 Astana Energy 136.05 20,279.87
7 Azenith Energy Res 30.25 4,513.72
8 BP Oil Intl 169.48 25,219.21
9 Calson Bermuda ltd 115.11 17,165.61
10 Curtis Petroleum 0.04 5.36
11 Delaney Petroleum 153.64 22,894.76
12 Elan Oil 31.58 4,689.59
13 Glencore Energy 138.06 20,562.36
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S/N Supplier
Amount in
US$ 'm Amount in NGN 'm
14 J&S Services Limited 350.17 52,209.78
15 J.P.M Supply and Transport 0.07 10.56
16 Kingsbury Trading 7.03 1,054.84
17 Le-Gor Energy 89.90 13,405.99
18 Linetrale Oil and Service 55.60 8,275.23
19 Matrix Energy 28.79 4,271.28
20 Mid Atlantic 33.24 4,944.92
21 MRS Oil and Gas 106.87 15,910.07
22 Napoil Limited 75.60 11,251.98
23 North Petroleum 0.26 39.59
24 Oil and Gas Trading 393.22 58,977.63
25 Orpington Trad Ltd 0.26 38.55
26 Performing Energy 198.50 29,725.78
27 Practoil Limited 75.49 11,400.00
28 Radric General Trading 0.08 12.73
29 Sahara Energy 286.53 42,861.74
30 Sunray Petroleum 0.28 42.60
31 Shell Western 80.19 120,539.95
32 SPOG Pet 26.51 3,954.70
33 Total international 75.65 11,247.67
34 Trafigura 53.33 7,956.13
35 Vitol S.A 197.96 29,448.94
Grand Total 3,550.29 530,305.46
Table 24: Petroleum Products imports outstanding creditor balances as at 31st
dec 2011 (Source: NNPC)
34. Pipeline product losses
Pipeline product loss has steadily increased over the years.
There are concerns as to why the Federal Government is not
making gains from sales of petroleum products refined in -
country. This is attributed mainly to losses incurred in the transfer
of crude oil from the terminals to the refineries and transfer of
products from the refineries to the depots. A further factor is the
diminished capacity of the existing refineries due to lack of
maintenance, obsolescence etc.
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Year Pipeline Product Loss in %
2002 8.68
2003 48.51
2004 12.59
2005 24.65
2006 38.31
2007 56.07
2008 45.67
2009 45.67
2010 45.65
2011 No information yet
Table 25 - Pipeline Product Loss (Source: NNPC)
Figure 4: Pipeline Product Loss in percentages 2002-2010
14. NNPC and its subsidiaries
1. Overview
From review of the latest available audited financial statements
(2009) it was noted that NNPC has sixteen (16) subsidiaries.
Names and principal activities of these subsidiaries are per the
table below:
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S/N Subsidiary % Holding Principal Business Activity
1 Pipelines and Products Marketing
Company Limited (PPMC)
100 Petroleum products marketing
and distribution
2 Port Harcourt Refining Company Limited
(PHRC)
100 Refining of crude oil
3 Kaduna Refining and Petrochemical
Company Limited (KRPC)
100 Refining of crude oil and
manufacturing of petrochemicals
4 Warri Refining and Petrochemical
Company Limited (WRPC)
100 Refining of crude oil and
manufacturing of petrochemicals
5 Nigerian Gas Company Limited (NGC) 100 Gathering, treatment, marketing
and distribution of gas
6 Integrated Data Services Limited (IDSL) 100 Geophysical and petroleum
engineering services
7 Nigerian Petroleum Development
Company (NPDC)
100 Exploration and production
8 National Engineering and Technical
Company Limited (NETCO)
100 Engineering, procurement,
construction and technical
services
9 Duke Oil Company Inc 100 Marketing of crude oil and
petroleum products
10 The Wheel Insurance Company 100 Providing reinsurance cover in
respect of excess capacity of
NNPC oil assets insurance
transferred abroad.
11 Duke Oil Services UK Limited 100 Providing logistics services to
Duke Oil Incorporated
12 Hyson (Nigeria) Limited 60 Provision of logistic and
operational services, marketing of
excess crude oil
13 Calson (Bermuda) Limited 51 Marketing of crude oil and
petroleum products
14 NAPOIL Company Limited ÷ Bermuda 51 Marketing of crude oil and
petroleum products
15 Nidas International Enterprises Limited 51 Shipping and marine
transportation
16 NIKORMA 51 Shipping and marine
transportation
Table 26- NNPC s Subsidiaries (Source: NNPC Financial Statements as at 31
December 2009)
The accounts of National Petroleum Investment Management
Services (NAPIMS) are not part of the consolidated accounts of
the Corporation. Proceeds from equity crude oil sales from the JV
and PSCs are recorded by NAPIMS.
A cursory look at the financial performance of the Corporation and
its subsidiaries in 2009 shows the Group had a deficit of
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approximately N298billion for the period. This is analysed as
follows:
NGN '000
The Corporation (270,230,663)
Subsidiaries (28,196,375)
(298,427,038)
Table 27 - Analysis of the Group s Deficit for the year ended 31 December 2009
12. Findings
1. NNPCS Role in petroleum revenues
NNPC manages various oil revenue streams on behalf of the
FGN, with proceeds from crude oil and gas sales being the
largest. As the national oil company owned by the FGN, NNPC
represents the interests of the Federation in the Oil and Gas
Sector via the various fiscal regimes and thereby mobilises and
collects revenues due to the Federation from sale of crude oil and
gas resources
10
.
Various reviews conducted by the Task Force showed that the
NNPC does not receive the required capital to grow its assets or
meet operating costs. Its status as a statutory corporation makes
accessing third-party financing extremely difficult. Lacking a more
efficient or sustainable option, NNPC has increasingly relied on
the FGN for lines of credit which include formal and informal
loans, and deduction of oil revenue due to the Federation
Account.
At the same time, fiscal and debtor-creditor relationships between
NNPC and Government are blurred. The NNPC Act of 1977 offers
little help, and Section 162(2) of the Constitution would seem to
require the Corporation to forward all oil revenues to the
Federation Account. NNPC participates to a limited degree in the
annual appropriations process, but budgeted sums have fallen
short of costs for decades.
10
However, NNPC's fiscal health has weakened dramatically in recent years. Between 2007
and 2009 the Corporation's closing net balance sheet liabilities grew from N952bn to N1.36tn.
Gross margins turned to deficit, capital reserves shrunk by half and nearly all SBUs appeared
to be running at growing losses. NNPC's asset base appears stagnant from age and absence
of strategic investment.
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2. Revenues from NNPC subsidiaries
The Task Force found that NNPC retains revenues generated by
its subsidiaries listed earlier in the report, to finance operations. In
our review, the legal basis for this practice was unclear. Business
justification may also be weak, given the poor performance
records and unprofitability of many of these subsidiaries.
From submitted information, the Task Force has not received
adequate information to determine specific amounts in NNPC
subsidiary revenue which is withheld from the Federation
Account. It is also unclear what portion of retained earnings
Government could properly recover as debt. However, the
practice raises red flags around subsidiary governance and
requires immediate reform. We found that there are no clear
guidelines on this practice.
Most of the trading companies, for instance, are incorporated with
offices and accounts outside Nigeria. All but Duke Oil are joint
ventures with major traders, but rules for how the partners share
profits were not provided to the Task Force. Accountability of
subsidiaries to NNPC Group also appears weak with opaque
management structures and Boards reportedly do not meet
regularly.
15. Taxes
1. Overview
The PPTA governs the taxation of companies engaged in
petroleum operations. It is the principal legislation on the
assessment of the oil companies' taxable profits and the
distribution of these profits between the government and the
companies.
The Act defines petroleum operations as,
"the winning or obtaining and transportation of petroleum or
chargeable oil in Nigeria by or on behalf of a company for its own
account by any drilling, mining, extracting or other like operations
or process, not including refining at a refinery, in the course of a
business carried by the company engaged in such operations,
and all operations incidental thereto and sale of or any disposal of
chargeable oil by or on behalf of the company¨.
Any other activity not covered by the above definition is liable to
tax under the CITA. The PPTA states that the income of a
company shall be taken to be the sum of:
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(a) the proceeds of all chargeable oil sold by the company in that
period;
(b) the value of all chargeable oil disposed by the company in that
period; and
(c) all income of the company for that period incidental to and
arising from any one or more of its petroleum operations.
Incidental income includes interest income, rent/hire of equipment
and services provided to other petroleum companies.
Key Provisions
Key provisions of the PPTA include:
• Rates: 85% for Joint Ventures (reduced to 65.75% for
companies in the first 5 years of production) and 50% for
PSCs.
• Estimated tax for a year to be prepared and filed not later
than the last working day in February.
• Revision to be made if there is any significant change in
the parameters used in the estimate i.e. production, cost
and price.
• Final returns to be filed not later than May 31 after year
end.
16. Signature Bonus
14. Overview
Signature bonuses are paid to the State in order to secure the
rights to explore a certain oil and gas field or block. The amounts
to be paid are determined by the Ministry of Petroleum Resources
and collected by the DPR.
Successful concessionaires receive Award Letters which
indicates the name of the awardee(s), concession awarded, the
signature bonus and the minimum work program commitment.
15. Findings
3. Upstream licensing rounds
Whilst the law allows discretionary grants of oil licenses, best
practice suggests that best value is realised from a transparent
bid process for oil and gas licenses. The government between
2000 and 2007 has endeavoured to set up a transparent bid
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process but the use of discretionary grants even during those
same periods of time remains. Design of the five major licensing
rounds Nigeria held between 2000 and 2007 was satisfactory.
There are however allegations of practices that undermined
competition and due process; setting aside bid guidelines,
arranging "forced marriages¨ between companies, and awards
outside of the auction process or to low-ranked bidders.
Denying investors access to geophysical data from blocks up for
sale has also kept Nigeria from getting full value for its acreage.
In past rounds, faulty data management practices by the NDR
have affected the results of the bid rounds.
The Task Force from its review identified various issues that have
resulted from the management of the past bid rounds. These are
discussed below.
• Lower demand and fewer qualified bidders:
Each of Nigeria's 2000-2007 rounds drew less interest and fewer
qualified bidders. The only contestants left by 2007 were small
independents and indigenous players with low capacity. Only 57
percent of blocks offered in 2005 drew even a single bid; by 2007,
the number was 40 percent. This came at a time of strong global
competition. In comparison, Libya's 2005 auction attracted 100
bids for 15 blocks.
• Uncompleted deals:
Nearly half of the awards in 2005 ended in default. Overall it
appears that less than 50 contracts were signed on the roughly
175 blocks offered in 2000-2007.
• Weakened government returns:
Acreage which in 2005 attracted signature bonuses of over
$100mn, but saw bidders default, fetched less than $20mn when
re-offered in 2006 and 2007. One OPL netting government
$76mn went for $6.5mn two years later. Compare this with
Angola, which in the same period captured record-breaking
bonuses through open, well-managed bid rounds.
• Poor growth of the indigenous petroleum sector:
Conduct of past bid rounds also undermined the stated goals of
boosting "local content¨ and nurturing serious Nigerian operators.
Of the 24 marginal fields awarded in the early 2000s, less than 10
have produced oil. Marginal field production is around
10,000bpd, according to NNPC.
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• Low development of acreage:
This is the ultimate consequence of past licensing practices.
Only around half of the over 80 blocks won between 2005 and
2007 are being explored or mined at present. NNPC reports that
of the roughly 60 PSCs signed, six are currently producing.
• Public controversy:
All of Nigeria's past licensing rounds led to official probes, reports
of scandals in the media, and several court cases. Litigation has
delayed development of some blocks for a number of years.
During the period from 2005 to 2011 potential revenue of $321m
in signature bonuses is tied up in litigation.
4. Outstanding Signature Bonuses due to the Federation
The DPR provided the task force with information indicating that
67 licenses were awarded between 1 January 2005 and 31
December 2011. A total of Sixty (60) concessions were awarded
during the 3 bid rounds in the period (2005, 2006 and 2007).
Expected revenue from the bid rounds was approximately
$2.26billion. Cash received of the revenue expected in relation to
the bid rounds was $1.7billion leaving $566 million unpaid.
Year No. of
Concessions
Signature Bonus
($)
Amount paid ($) Amount due ($)
2005 26 1,118,778,167 788,196,321 330,581,846
2006 17 656,530,010 421,404,975 235,125,035
2007 17 486,452,000 486,125,378 326,622
Total 60 2,251,660,177 1,699,876,774 566,033,503
Table 28 Signature bonuses, payments and amounts due from the 2005, 2006
and 2007 bid rounds
An additional seven (7) concessions were allocated at the
discretion of the office of the Honourable Minister of Petroleum
Resources in 2008, 2009 and 2011. The expected revenue from
the discretionary allocations was $414.45million. Of the expected
amount of $414.45million, only $231.79million has been paid to
date and $183million remains outstanding and is due to the
nation's treasury.
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The signature bonuses per concession over the periods reviewed
range from $150,000 to $310million. Of the $414.45 million
expected for the seven discretionary allocations, three (3) were
awarded at $150,000 each to Afren Energy Services/Oriental, All
Grace Energy and Green Energy Nigeria Limited.
Year No. of
concessions
Signature bonus
($)
Amount paid ($) Amount due ($)
2008 3 40,150,000 18,150,015 21,999,985
2009 1 164,000,000 5,000,000 159,000,000
2011 3 210,300,000 208,260,000 2,040,000
Total 7 414,450,000 240,543,052 183,039,985
Table 29 Signature bonuses, payments and amounts due from the
discretionary allocations
The total unpaid amount with respect to Signature Bonus is
approximately $749million. This comprises mainly of:
• $321million relating to legal disputes currently in Nigerian
Courts
• $80 million relating to oil & gas blocks that were returned
to the FGN or re-awarded.
• $181million not yet due from the operators until they hit
first oil, and
• $167 million actual long overdue amounts outstanding
from the concessionaires.
The delay in resolving the abovementioned disputes has resulted
in the FGN's inability to collect $321million. With respect to
recovery of the aggregate undisputed unpaid amounts due ($167
million), the DPR informed us that letters had been written to the
various concessionaires to request payment.
5. No evidence of award for the discretionary allocations
The Task Force was not provided with the evidence of award for
any of the discretionary allocations.
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17. Concession Rentals
16. Overview
In line with Section 60 (1) and (2) of the Petroleum Act Cap P10,
concession rentals on acreages for development are charged at:
• $10 per square kilometre on Oil Prospecting Licences (OPLs),
• $20 per square kilometre on Oil Mining Licences (OMLs) for
the first ten years, and
• thereafter for each square kilometre or part thereof until
expiration of the lease and on renewal, US$15 shall be
charged.
The sizes of the acreages are defined at the time the concessions
are awarded. The Task Force, with its consultants reviewed a
schedule of concessions and the rentals paid between 1 January
2005 and 31 December 2011. Findings from the review are
presented below.
17. Findings
1. Outstanding concession rentals due to the Federation
($2.9million)
Based on the information provided by officials of the DPR, there
were fifty ÷ seven (57) concession holders for the period under
review.
Total revenue accruing to the nation for the period amounted to
$12.7million. Of the $12.7million owed to the FGN, the payments
received from the concession holders during the period amounted
to $9.8million indicating that $2.9million represents outstanding
amounts to be collected by the DPR from the various
concessionaires.
2. Record keeping by the DPR (Concession rentals)
We obtained a list of concessions (active and inactive) from
officials of the DPR as at September 2011 and noted that when
compared to the schedule of concession rentals obtained also
from the DPR, there were a number of inconsistencies which
resulted in our inability to rely on the list. We are unable to
confirm the completeness of the schedule provided to us;
therefore, revenues due may be misstated.
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18. Royalties (Crude Oil and Gas)
18. Overview
The Petroleum Act CAP P10 vests ownership of all acreages with
the Federal Republic of Nigeria ("the State¨). Royalties are
income due to the nation resulting from the production of oil and
gas. This is other than the amounts accruable from taxation and
equity participation. Royalties should be paid by the Oil and Gas
Operators quarterly.
Royalties are earned from both the production of Crude Oil and
the sale of Gas. In line with the Petroleum Act, royalties are
determined per stipulated rates.
Water depth % Production (Royalty)
Onshore areas 20
Inland basins 10
Up to 100 metres water depth 18.5
Up to 200 metres water depth 16.5
From 201 to 500 metres water depth 12.5
From 501 to 800 metres water depth 8
From 801 to 1000 metres water depth 4
Areas beyond 1000 metres water depth 0
Table 30 - Crude oil royalty rate table (Source: Petroleum Act CAP P10)
Parameters used in determining crude oil royalties are:
Official Selling Price (OSP) this is the price of crude as advised by
the Crude Oil Marketing Division (COMD) of the Nigerian National
Petroleum Corporation (NNPC).
Reference API gravity (APIr). This is the index assigned to a type
of crude to indicate its level of quality. The higher the quality of
crude, the higher the API and the more white products will be
obtained from it when it is refined.
Field API gravity (APIf). This is the API gravity for the field the
crude oil is produced from.
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Realisable price (RP). This is the actual price of the crude oil from
a particular field when compared to the price of the benchmark
crude for that particular field. The realisable price is obtained
using the following equation;
The Realisable Price is therefore determined based on the
relationship between the OSP and the APIr and APIf as shown
below:
RP = OSP + (APIr ÷ (APIf * 0.03))
19. Findings
3. Outstanding Crude Oil Royalties due to Nigeria
($3.027billion)
The total crude oil royalties due for the period 1 January 2005 to
31 December 2011 was $32.011billion
11
. Of this amount,
$3.027billion was outstanding from the operators as at 31
December 2011 per the DPR's records.
4. On-going DPR dispute with Addax Petroleum on outstanding
royalties
During the course of the work carried out by the Task Force, it
was understood that of the $3.027billion dollars outstanding per
4.11.2.1, the DPR had stipulated that ADDAX is liable to pay
$1.5billion royalties under the 2003 fiscal regime. There is
currently a dispute between Addax and NNPC on the one hand,
and the DPR on the other.
The DPR should operate independently of the NNPC and report
directly to the Minister only on matters relating to the
interpretation of the various operations in the Petroleum Industry.
An operator should not be allowed to flout a determination of the
properly constituted regulatory authority without consequences.
5. Reconciliation of payments made to the CBN and the
amounts due from operators
11
This figure is not without dispute for instance whether or not there is a sum and how much
is "due from¨ ADDAX does not have a consensus between the parties
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The Task Force noted that there was a difference of $2.55 billion
between the royalties payment inflow per the CBN statements
(total - $31.5billion) and the payments recorded by the DPR's
Revenue Unit (total -$28.98 billion), the CBN statements being
higher. The Task Force was unable to match some of the
payments made by the oil companies to the appropriate revenue
heads during the period as a result of inadequate information.
This made it difficult to determine the actual amounts outstanding.
It was understood that the DPR is only able to match payments to
the revenues due during reconciliation meetings or through
correspondence with the oil companies.
6. Lack of independent gas production and sales data
Gas royalties due to the nation are determined using volumes of
gas sold during the period which is in line with the Petroleum Act.
The Task Force was unable to determine if a shortfall existed per
the DPR records as the officials of the DPR explained that there
is currently no process in place to independently track gas
volumes produced and sold by the operators. This has resulted in
the DPR relying heavily on the oil and gas companies for
information. There were no records or information for the year
ended 31 December 2011.
7. Outstanding reconciliation of gas royalties due to the
Federation from Shell, Mobil and Agip
Gas royalties information provided by the DPR was considered
incomplete as details were available for Chevron and Total only.
No gas production or sale information was available for any other
company, in particular Shell, Mobil and Agip. It was explained that
reconciliation discussions have been concluded with Chevron and
Total but is pending for all the others.
19. Gas Flare Penalties
1. Overview
Gas flare penalty is one of the revenue streams collected by the
DPR through the CBN. It should be computed in line with the
Associated Gas Reinjection Act of 1979, which compels every
company producing oil and gas in Nigeria to submit preliminary
programs for gas re-injection and detailed plans for its
implementation.
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The legislation banned the flaring of gas after 1 January 1984
without the permission of the Minister of Petroleum Resources.
Although where the Minister is satisfied after 1 January 1984 that
utilization or re-injection of the gas produced is not appropriate or
feasible in a particular field or fields, the Minister may issue a
certificate in that respect to a company engaged in the production
of oil or gas and permit the company to continue to flare gas if the
company pays a sum as the Minister may from time to time
prescribe for every 28.317 standard cubic feet (scf) of gas flared.
In January 1998, the penalty fee for flaring of gas was increased
from 0.50 kobo to N10.00 per square cubic feet (scf). This was
later increased to $3.50 on 15 August 2011 (April 2008). The
operators have failed to comply with the new directive and have
continued to pay based on the N10 per scf. The discrepancy
between the amounts due to the Government based on the new
Ministerial directive and the amounts paid by the operators based
on the old rates, have resulted in a revenue loss for Government
amounting to at least N515 per scf assuming that $1=N150 for
the period after the new Ministerial directive.
21. Findings
1. Incomplete records of volumes of Gas Flared
The volumes of gas flared were obtained from both the Revenue
and Production Units of the DPR. The situation in respect of gas
flare penalties is similar to that of gas production mentioned
previously. The DPR is currently unable to independently track
and measure gas volumes produced and flared. It depends
largely on the information provided by the operators.
There were no available records or information in respect of gas
flare volumes for the years 2005 and 2011. This implies that the
current records as they exist are incomplete.
2. Inconsistencies noted in gas flared information
Differences were noted between the gas flared data provided by
DPR's two units. These differences are yet to be resolved as at
the time of reporting.
3. Delayed gas flare volume reconciliations
The DPR carries out periodic reconciliation meetings with the
operators. It was noted that of the 36 operators in their listing,
reconciliations have been completed for only 6 of them. This
implies that the Nation may have made losses due to the delay in
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confirming the amounts due and enforcing payments in line with
the laid down statutes.
4. Outstanding Gas Flare penalties due to the government
CBN statements and reports of inflows were also obtained in
order to corroborate the payment information received. Per the
information obtained from DPR, total revenue from gas flaring
during the review period was $175million.
The balance outstanding as unpaid was approximately
$58million. This indicates that $115million had been received in
respect of gas flare penalty by the DPR. The Task Force however
reviewed CBN statements and noted that $137million was
received between 1 January 2005 and 31 December 2011. The
DPR was not able to reconcile the $115 million to the $137million.
5. Non compliance with the new gas flare penalty regime
The Minister issued a directive which was signed on 15 August
2011 increasing the gas penalty fee from N10.00 to $3.50.
However, the oil companies have failed to comply with the
directive and have continued to flare gas without compliance with
the new rate as communicated in the Minister's directive. Using
the DPR gas flare information (irrespective of the inherent errors
arising per the factors earlier stated) to compute the potential
revenues for the relevant years at the rate of $3.50 per scf is
$4.1billion versus the $177million computed by the DPR using the
N10 per scf.
The records at the DPR reveal that none of the companies have
paid any gas penalty fee in 2012.
6. The detrimental effect of gas flaring
See table below for the trend of percentage of gas production
flared:
GAS FLARED 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011
Gas flared 891 820 810 770 769 737 623 488 479 435
Gas produced 1,702 1,862 2,120 2,141 2,272 2,606 2,607 2,028 2,493 2,873
% of production flared 52% 44% 38% 36% 34% 28% 24% 24% 19% 15%
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Table 31 - Gas flared
Although there has been a steady decline in the amounts of gas
flared, the numerous deadlines to implement the Zero gas flaring
policies and fine for oil companies have been repeatedly
postponed, with the most recent deadline, being December 2012.
In 2009, the government developed a Gas Master Plan that
should promote new gas-fired power plants to help reduce gas
flaring and provide a source for the much-needed electricity
generation. However, progress is slow largely due to the lack of
infrastructure to produce and market gas.
Gas flaring has both environmental and economic impacts. The
value of gas flared over the 10 year period is estimated at about
US$44 billion. Environmental impacts resulting from gas flaring
include:
• Environmental pollution
• Adverse climate changes
• Food insecurity
• Diseases
• Unemployment
• Deforestation
20. Miscellaneous Oil Revenues
22. Overview
Miscellaneous Oil Revenues are all other revenues due to Nigeria
through the DPR which do not fall into any of the other major
types of revenue classes documented above. Examples include
drilling permits/licenses, fuel station permits, renewal of licenses
etc.
23. Findings
7. No comprehensive miscellaneous oil revenue schedule
The Task Force was unable to obtain a comprehensive
miscellaneous oil revenue schedule from the officials of DPR.
Our reference point for the purpose of determining the amounts
earned in respect of miscellaneous oil revenues was the schedule
of revenues presented by the DPR to the members of the Special
Task Force on 13 April 2012. The presentation indicated total
miscellaneous oil revenues for the period 1 January 2005 to 31
December 2011 to be approximately N102.5billion.
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Receipts issued for the various licences and permits were initially
provided by the DPR as a basis for determining the total revenues
received and only N640million worth of receipts were made
available.
Subsequently, CBN statements (Miscellaneous Oil Revenue
Account statements) for the period were provided N102.3billion
was traceable. Upon conclusion of the review there was an
unexplained reconciliation difference of N151million.
Lack of transparency of license-level earnings and costs inhibits
oversight and enables manipulation. The record keeping of the
DPR calls to question the completeness and accuracy of reports
generated as there was no way to determine if there were
miscellaneous oil revenues due to the Federation which were yet
to be collected.
Also, the DPR has not provided an analysis of the miscellaneous
revenues by type and amounts due.
8. Outdated oil licensing fee regimes
The amounts due in respect of the various fees relating to the
miscellaneous oil revenues are not reflective of the current
economic realities. For example, the fee to apply for the operation
of a petrol station ranges from N5,000 to N250,000 and the
license to operate a drilling rig costs between N20,000 to
N100,000.
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Revenue Losses in
the Nigerian
Petroleum Industry
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5.
6. Revenue Losses in the
Nigerian Petroleum
Industry
21. Overview
This section of the report presents the Task Force's findings on
the revenue losses in the industry, with a view to identify
opportunity areas for major reform in boosting resources
obtainable from the sector for national development. Of these
findings, losses arising from inadequate security and enforcement
are significant. As a result, new enforcement initiatives have been
developed and recommended as part of this report to combat
revenue loss in the petroleum industry.
22. Security Issues and Theft in the Nigerian Petroleum
Revenue Value Chain
The illegal activity of hydrocarbon theft in the petroleum industry
is both an organized and on-going enterprise. The phrase
"vandalization" should be expunged from the reporting of this
activity because it tends to trivialize the purpose and severity of
hydrocarbon theft. Hydrocarbon theft is a major source of loss of
revenue to the Federal Republic of Nigeria. Accordingly, the
examination of the incidence, recommendations for the protection
against and the enforcement measure in respect of the organised
robbery of this resource are within the terms of reference of the
Special Task Force.
Hydrocarbon theft was found by the Task Force as being a major
and chronic source of revenue loss to Nigeria. From the Task
Force's review and briefings received, it was evident that small
scale pilfering of crude and refined products, illegal refining, and
large-scale theft involving barges and boats have been endemic
since at least the late 1990s. Significant "over-lifting¨ at crude
export terminals is also alleged, as is theft from tank farms,
refinery storage tanks, jetties and ports. In these latter cases,
submissions to the Task Force alleged that officials and private
actors disguise theft through manipulation of meters and shipping
documents.
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Bunkering operations can be complex. Consider this sketch of a
typical larger-scale Niger Delta oil theft ring:
Figure 5: Illustrative sketch of a typical larger-scale Niger Delta oil theft ring
Past attempts to address theft have made only limited progress.
Criminal prosecutions to date have reached no higher than the
level of transport or operations. The recent arrest of 22
Ghanaians and five Nigerians caught stealing 25,000 MT of crude
in two boats is laudable, for instance, but law enforcement efforts
need to reach much higher.
Protecting Nigeria's petroleum infrastructure from theft and
sabotage presents a tremendous challenge. No one actor can
secure everything÷PPMC alone maintains 5120km of above-
ground pipeline. Difficult terrain, poor community relations, and
high operating costs all complicate matters further. Yet there is
also evidence that members of the security forces condone and,
in some cases, profit from theft. The void in effective security
likewise appears to increasingly hand over control of coastal and
inland waterways to undesirable elements.
In view of the rising costs described below, a review of available
policy options together with serious commitment to act is needed
urgently.
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24. Volumes of crude oil theft and associated revenue losses
Theft of crude oil and refined petroleum products may be
reaching emergency levels in Nigeria. The Task Force has
received reports suggesting that volumes stolen have risen
dramatically in the past 12-18 months. The Royal Dutch Shell
Company, Shell in its presentation to the Task Force stated that
an estimated 150,000 barrels of crude oil are stolen per day
(about 6% of Nigeria's total annual production) causing a revenue
loss of $13.5 million per day (at $100 per barrel) which amounts
to $5billion per year of lost revenue.
On the other hand, high ranking Officials and Executives in the
Federal Government tasked with the management of the nation's
strategic Oil and Gas assets have several times stated the
existence of large-scale on-going theft of Nigeria's crude oil. This
represents government acknowledgment of the magnitude of the
loss. Mr. Leke Oyewole, a Senior Special Adviser to President
Goodluck Jonathan on Maritime Affairs, disclosed to the media in
March, 2012 that Nigeria loses about 40 million metric tonnes of
petroleum products amounting to about $20 billion (N3 trillion) to
crude oil theft and illegal bunkering; while NNPC has publicly
stated that it spent $1.2billion in the last ten years on pipeline
repairs.
Further to the above, the Honourable Minister of Petroleum
Resources had also stated at a media briefing in May, 2012 that
the country was losing about $7billion annually to crude oil theft in
Nigeria, at the rate of 180,000 barrels per day. Indeed, President
Goodluck Jonathan has acknowledged the scale and seriousness
of crude oil theft in Nigeria as being incomparable to anywhere
else in the world, describing the occurrence as being cancerous
to the nation's economy. The Ministry of Finance has taken a
middle ground, stating theft claimed 17 percent of daily production
nationwide in April. Overall, estimates of crude oil stolen or
spilled reviewed by the Task Force ranged from 6 to 30 percent of
production, with 35 percent claimed for one especially troubled
area. Based on these estimates, the Task Force believes Nigeria
could be losing over N1tn per year to crude oil theft.
The Task Force does not endorse any of the numbers it received
as solely authoritative. The bases for many were unclear, and the
decentralized, secretive nature of oil theft makes it difficult for any
one party to know the full extent of losses. There is a lack of
consensus on the actual loss, naturally public records are not
satisfactory in this regard but it could actually be as high as
250,000 barrels per day closer to 10% of daily productions.
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However, submissions to the Task Force on oil theft suggest that
the problem needs immediate attention.
NNPC and oil company data shows dramatic recent rises in theft
and sabotage. For example, Shell claims it found at least 50 tap
points on its 90km Nembe trunk line in January 2011 alone. Shell
submissions to the Task Force showed average total losses in its
operational areas climbing from 10,000bpd in late 2009 to over
50,000bpd in March 2012. Chevron reports 29 tap points for the
year so far, and claims volumes lost from its operations in Q1
2012 exceeded losses for all of 2011. The NNPC put its total
losses from 2009 to Q1 2012 at over 20mn barrels.
It appears small-scale theft and illegal refining are also becoming
more decentralized and wide spread, though losses from such
practices remain relatively small compared with the more
sophisticated large-scale theft rings. In one striking example of
rising costs, NNPC data shows the value of stolen crude along
the 60km Forcados-Warri refinery supply pipeline was 600
percent higher in 2011 than in 2010. Total losses were N60
billion from this pipeline alone÷or N1bn of oil stolen per km of
pipeline.
These incidences of crude theft also delay realization of revenues
by deferring production. Shell has declared force majeure on
onshore liftings five times since early 2011, all reportedly linked to
illegal bunkering. One December 2011 stoppage, allegedly
caused by two failed pipeline taps, took a month to fix and
deferred over 4 million barrels. Damage to infrastructure also
causes long-term production deferments. Government data
shows dozens of fields sabotaged before the amnesty still sit idle.
Shell's onshore output÷currently around 600,000bpd÷is barely
half of 2005 levels. In Delta State, Chevron still produces one
third less oil than it did in 2008.
25. Volumes of Lost Refined Products and Associated Revenue
Losses
The Task Force did not receive comprehensive figures
documenting volumes of refined products stolen or spilled, but
NNPC reports that thieves stole 3.2 million metric tons of products
from its pipeline network between 2001 and 2010. Stolen
amounts appear to be growing; in NNPC's submissions the Task
Force was informed that about 40 percent of products currently
channelled through pipelines are lost to theft and sabotage.
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Wilful damage of downstream infrastructure has also spiked as of
late. PPMC recorded 4,468 product pipeline breaks in 2011, 98
percent of them from sabotage. This is a sharp increase over
1,746, the average number of sabotage cases logged between
2001 and 2010.
Theft of products at import points also appears endemic. For
example, submissions to the Task Force claimed that as much as
5,000 MT of a typical cargo of petrol can be stolen at ports and
jetties, offloaded into light vehicles.
In a worrying trend, organized theft of products has also spread
far beyond the Niger Delta. PPMC recorded sizable losses on its
Mosinmi-Ibadan-Lokoja line in 2011. The Jos-Gombe-Maiduguri
line also saw theft, and pipeline sabotage around Atlas Cove in
Lagos is chronic.
Organized theft of refined products also denies Nigeria significant
revenues, though the Task Force did not receive comprehensive
figures. PPMC values the products stolen from its pipeline
network between 2001 and 2010 at N178 billion. It is alleged that
when products are stolen at ports and jetties, inspectors sign
discharge sheets for the full landing amount, which allows
importers to collect fuel subsidy on stolen products.
26. NNPC Withholdings for Costs Associated With Theft and
Sabotage
NNPC withholds oil revenues from the Federation Account to
cover costs associated with theft and pipeline sabotage. Data
from the Corporation shows huge increases in recent periods:
Product losses (Jan-Dec
2009)
Product losses (Jan-Dec
2010)
Product losses (Jan-Dec
2011)
Product losses (Jan- May
2012)
9,750,000,000
123,072,000
18,000,000,000
335,000,000,000
Audited/not validated
Not validated or audited
Not validated or audited
Not validated or audited
Pipeline Security and
repairs (2006-2009 Feb)
Pipeline Security and
repairs (2010-2012 May)
83,657,522,776
344,852,000,000
Not validated/not audited
Not validated/not audited
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Table 32 - NNPC claims against FGN for failure to provide security, 2006-date
Beyond the obvious damaging impact of these revenue losses to
the Nigerian economy, crude oil theft also impacts the nation in
other major ways, some of which include the following.
23. Pioneer Status granted to Indigenous Companies
The Task Force has been informed that at least five companies:
Allied Energy, Midwestern Oil & Gas, Brittania Oil Nigeria Limited,
Suntrust Oil Company Nigeria Limited; and Niger Delta Petroleum
Resources Limited
12
have been granted pioneer status by the
Nigerian Investment Promotion Commission (with others pending
or undetected) for their exploration and production activities.
Pioneer status is a form of five-year tax holiday to qualifying
industries anywhere in Nigeria. The grant of pioneer status, gives
a company a preferred position in getting established, usually
through exemption from income tax. Pioneer companies are
companies engaged in manufacturing, processing, mining,
servicing and Agricultural industries whose products have been
declared pioneer products on satisfying certain conditions.
In granting a company pioneer status the industry or product is
regarded as one that is not already carried on in the country or
the existing industry is not producing enough to meet the current
or expected requirements. The concept is further broadened to
include any industry or product for which there is a favourable
prospect of development. The policy relating to pioneer industry is
based on the desire of the Government to encourage the
development of new or relevant industries that will reduce the
country's dependence on imports. The pioneer industries and
products are identified by a list published in the official gazette.
The law governing the operations of the pioneer companies was
first laid out under the Aid to pioneer Industries ordinance No.10
of 1952. This was repealed by the Industrial Development
(Income Tax Relief) ordinance No.8 of 1958. This ordinance was
subsequently repealed by the Industrial Development (Income
Tax Relief) Act 1971, otherwise known as CAP 179 LFN, 1990
which is the current legislation governing the operations of the
pioneer industries. The Act empowers the Federal Executive
12
The argument that the status is appropriate for "exploration¨ and not "production¨ is
untenable and self-defeating because once it is accepted that "production¨ is "already being
carried on¨ in Nigeria the same goes for "exploration¨
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Council to publish from time to time a list of Industries or products
as pioneer Industries or products.
The revenue implications though well-known bear some
repetition:
• No tax shall be payable during the pioneer period on the profit
and consequently no capital allowance could be claimed on
all the qualifying capital expenditure incurred starting from the
production date.
• Dividend can be declared out of the pioneer account profit but
not more than the balance standing in that account.
• Dividend paid out of the pioneer profit shall not be subject to
tax in the hand of the first recipient
• The net qualifying expenditure for capital items during the
pioneer period are accumulated and are qualified for both
initial and annual allowances in the new business.
• Losses incurred by the pioneer company during the pioneer
period and certified, may be relieved after the pioneer
period since such loss is deemed to have been incurred on
the first day of the new business
It cannot be a correct exercise of incentive for oil operators to be
given pioneer status for an activity that is well established for over
40 years and which to any commercial consideration is a
profitable venture. The loss of revenue from the grant of pioneer
status to oil operators is an avoidable loss. The Task Forces
recommends that any further consideration of the industry for
pioneer status be stopped forthwith. Indeed to the extent that the
application of the Act has been extended to oil exploration it is
ultra vires and ought to be set aside and or revoked. To the effect
that all tax and exemption be reinstated; from the date of the
initial grant and payments be made to FIRS accordingly.
24. Collateral Social Costs of Theft
The following social costs, while outside the Task Force's
immediate remit, deserve mention. They also arguably result in
decreased Government revenue by increasing the perceived risks
of investing in Nigeria's oil sector.
27. Environmental Pollution and Associated Socio-Economic
Impacts
Crude oil theft is surely a major cause of Niger Delta oil pollution,
though again there are no reliable nationwide figures. SPDC
claims that illegal bunkering caused 118 spills around its facilities
in 2011, at a loss of 11,806 barrels. Figures are scarce for the
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resulting water and soil pollution, or secondary impacts on human
health, livelihoods or food and fuel stocks.
Mixing highly unstable stolen condensate with kerosene, diesel
and petrol damages automobiles and generators, and causes
frequent explosions. These may have killed several hundred
Nigerians over the past decade. PPMC recorded 376 fires
around its product pipelines between 2000 and 2010, and press
reports record several thousand deaths from pipeline fires since
1998. Illegal refineries explode frequently, incinerating works and
bystanders.
28. Armed Maritime Piracy
37 piracy incidents logged in 2011 involved hijackings of
petroleum products tankers. In over a dozen cases, pirates stole
all or part of the ship's cargo. Although the locus of attacks has
shifted to the Bight of Benin, pirates steered several of the
hijacked tankers to rendezvous points near Escravos and Bonny,
where waiting vessels came alongside to siphon products. The
value of products lost in these attacks, or secondary costs like
cargo insurance and demurrage, is unknown.
The International Maritime Organization now refers to the Bight of
Benin as the world's second most dangerous piracy enclave, after
Somalia.
29. Lost Investment Leading to Revenue Loss
Illegal bunkering, together with the insecurity surrounding it, also
discourages investors owing to increased operational risks and
costs. The oil sector Foreign Direct Investment fell significantly
between 2005 and 2011.
Nigeria's petroleum sector infrastructure vulnerability and frequent
damage to crude transport capacity has resulted in long-term
production deferments across the country. Presently average
daily production countrywide is barely at the levels in 2005, even
though NNPC estimates an achievable national capacity of 3.7m
bpd given the observable state of affairs.
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Debt Collection
7. Debt Collection
25. Debt Analysis
Based on the detailed review of outstanding debts owed to the
Federation for the various revenue streams discussed above, the
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Task Force supported by its consultants developed Table 33
showing outstanding amounts for royalties, signature bonuses
and concession rentals.
On the basis of its initial interpretation of TOR2 and the
information thus compiled the Task Force through the Security
and Enforcement subcommittee invited the relevant government
agencies to assist in a debt collection drive pursuant to the ToR 2
of the PRSTF. As stated under the Terms of Reference above the
Task Force on further reflection decided to make
recommendations to Government on collection so that it may be
able to conclude its work within the rather engaging time frame.
26. Debt Collection Efforts
Invitation and demand letters were sent out to over forty seven
(47) Oil companies who were alleged to be indebted to the
Federal Republic of Nigeria as royalties, signature bonus, gas
flaring etc.
It is appropriate to mention that these efforts were carried out
based on an initial understanding of ToR 2 of the PRSTF.
However on further reflection the task force considers that its
recommendation to government on measures that could and
should be taken to recover debt is more in accord with a proper
interpretation of ToR 2.
27. Debt Reconciliation
However during the debt reconciliation exercise, the sum of
USD$5,830,261 was paid into the treasury of Government with
evidence of payment. Several companies made undertakings to
pay at later dates; this lends credence to the need to make
concerted and focused efforts to recover revenue.
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Table 33: Petroleum Revenue Special Task Force Oil royalties by operator Period under review: 2005 -2011
*The analysis above was arrived at based on data provided by the DPR. This information has not been corroborated by the operators of
the various concessions. ** Also, the analysis does not consider payments relating to royalties due from prior periods nor does it consider
subsequent payments (2012) in respect of royalties
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Cross Debt Matrix
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8. Cross Debt Matrix
1. Debt Matrix
This section presents a review of the cross debt matrix showing
the key stakeholders involved in the generation and management
of Nigeria's petroleum revenues and their financial transactions.
29. Debts Profile
The table below presents a summary of outstanding debts found
by the Task Force in the course of its review:
DEBT ISSUES AGENCIES TO
BE DEBITED +
AMOUNT
AGENCIES TO
BE CREDITED+
AMOUNT
BALANCING
+ AMOUNT
DOMESTIC CRUDE
SALES
NNPC $4.6b
from 2002-2011
arising from
discrepancies in
pricing.
FGN $4.6b to be
collected from
NNPC
EXCHANGE RATE
DISPARITY
NNPC N77.5b
from 2002- 2011
arising from
exchange rate
discrepancies
FGN N77.5b to
be collected
from
NNPC
SIGNATURE BONUS DPR $560m
unpaid from the
bid rounds of
2005,2006 and
2007
FGN $560m to
be collected
from DPR
CONCESSION
RENTALS
DPR $183m for
concessional
allocation of
2008, 2009 and
2010.
$2.9m
outstanding
amount to be
collected from
various
concessionaires
FGN $183m to
be collected
from DPR
FGN $2.9m to
be collected by
the FGN for the
outstanding
amount on the
various
concessionaires
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DEBT ISSUES AGENCIES TO
BE DEBITED +
AMOUNT
AGENCIES TO
BE CREDITED+
AMOUNT
BALANCING
+ AMOUNT
ROYALTIES DPR
$3.027billion
being
outstanding from
the operators as
at Dec. 2011
FGN
$3.027billion
being the
outstanding as
at Dec. 2011
GAS FLARING DPR $58m
balance
outstanding in
respect of gas
flare penalty
FGN $58m to be
collected from
DPR being the
outstanding in
respect of gas
flare penalty
SUBSIDY
Miscellaneous Debt
NNPC $0.9b as
at 31
st
December
arising from the
debt owed the
supplier of
petroleum
products
DPR N102.5b
being
miscellaneous
amount due to
be paid
NNPC to pay
the suppliers of
Petroleum
Products arising
from amount
outstanding for
over 365days
FGN to collect
the
miscellaneous
amount from
DPR
Of the
N102.5b,
N640m was
reconciled
LOANS TO BPE FGN N798.6m
being loan
granted to BPE
by NNPC as
directed by the
FGN
NNPC N798.6m
to be collected
from the FGN
LOAN TO SAO TOME&
PRINCIPE
FGN N700.5m
being loan
directed to be
given by NNPC
NNPC N 700.5m
to be collected
from FGN
PRESIDENTIAL
CHOPPER
FGN N2.230b
paid by NNPC
NNPC N2.230b
to be collected
from FGN
ROYAL SWAZILAND
SUGAR COY
FGN N2.421b
paid by NNPC
NNPC N2.421b
to be collected
from FGN
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DEBT ISSUES AGENCIES TO
BE DEBITED +
AMOUNT
AGENCIES TO
BE CREDITED+
AMOUNT
BALANCING
+ AMOUNT
FED. MIN OF
SCIENCE+TECH
(RTCOM- GALAXY
BACKBONE)
FGN N11.466b
paid by NNPC
NNPC N11.466b
to be collected
from FGN
FED. MIN. OF
SCIENCE+ TECH
SKILLS G- SCIENCE +
TECH
FGN N4.185b
paid by NNPC
NNPC N4.185b
to be collected
from FGN
FED. MIN. OF
SCIENCE + TECH
WIND ENERGY
(LAHMEYE, INT); FMS&
T)
FGN N128.9m
paid by NNPC
NNPC N128.9m
to be collected
from FGN
PHCN INDEBTEDNESS A total of N17b
debt was
incurred out of
which N10.6b
had been paid a
at end 2011
NNPC to collect
the outstanding
debt of N6.4b
from FGN
SPONSORSHIP OF
WORLD CUP +
OTHERS
FGN N866.2m
directed that
NNPC pay for
the sponsorship
of world cup
NNPC N866.2m
to be collected
from FGN
NIG. CONTENT
DEVELOPMENT
MONITORING BOARD
(NCDMB) LOCAL
CONTENT BOARD
START UP OPERATION
FGN N673.0m
paid by NNPC
for local content
board
NNPC N673.0m
to be collected
from FGN
STORAGE COST ON
ILLEGAL BUNKERING
FGN N563.9m
paid by NNPC
NNPC N563.9m
to be collected
from FGN
LEGAL EXPENSES
(SOUTH ATLANTIC V)
MIN. OF PET.
RESOURCES
FGN N250.0m
paid by NNPC
NNPC N250.0m
to be collected
from FGN
PAYMENT TO DPR NNPC N651.0m DPR N651.0m
to be collected
from NNPC
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DEBT ISSUES AGENCIES TO
BE DEBITED +
AMOUNT
AGENCIES TO
BE CREDITED+
AMOUNT
BALANCING
+ AMOUNT
EXPENSES OF THE
FED. MIN. OF
PETROLEUM
RESOURCES
NNPC N521.0m
incurred on
behalf of the Fed
Min of Petroleum
Resources
FGN N521.0m
to be paid to
NNPC
PICOMSS PHASE1 NNPC N19.878b
incurred on
behalf of the
Presidential
Implementation
Committee on
Maritime Safety
and Security
FGN N19.878b
to be paid to
NNPC
Table 34: Summary of Outstanding Debts found by the Task Force in the
course of its review, as at April 2012
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Automation and
Technology
Integration
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9. Automation and
Technology Integration
1. Introduction
30. Overview
Part of the main objectives of the Petroleum Revenue Special
Task Force when it was inaugurated was to:
• Develop automated platforms that would enable tracking,
monitoring and online validation of income and debt drivers
for all parastatals and agencies in the Federal Ministry of
Petroleum Resources, and
• Ensure the integrity of payments to the FGN through the
integration of systems and technology across the production
chain in order to determine and monitor crude oil production
and exports.
1. Summary of Work Done
In order to achieve the objectives highlighted above, the members
of the PRSTF carried out the following:
• IT automation gap assessment: The Task Force identified
Information Technology and business automation gaps, by
carrying out Current Position Assessments of the
stakeholders within the Oil and Gas production value chain,
including government regulatory parastatals. To achieve this,
it was necessary to identify key operational processes within
the focal organizations or scoped-in entities.
• Workshop on Oil and Gas Metering and Measurement: A
workshop was organized for Metering & Measurement in the
Oil & Gas Production Value Chain. This was to provide a
better understanding of the challenges in the industry, identify
industry best practices and create a road map to facilitate the
achievement of industry-wide consensus and implementation
options.
• Review of all Automation presentations made to the Task
Force: The IT and Automation sub-committee also reviewed
all the related presentations made to the Task Force to
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ascertain current industry practices and benchmark practices
in the Nigerian Oil and Gas industry against these practices.
• Development of Recommendations: Following the detailed
review and assessment carried out by the Task Force,
specific processes and systems were identified that the
Ministry of Petroleum Resources and the relevant government
agencies should implement to cover the identified gaps.
1. IT Automation Gap Assessment
The assessment scope covered three broad categories namely:
Core Business Systems, Reporting Capabilities and Automation
Capabilities of the entities within the Oil and Gas Production value
chain. The entities in scope for this review were the DPR, NNPC
(Finance Department, PPMC, COMD, and NAPIMS), CBN (Trade
and Exchange Department), Customs and Inspection Agents.
• Core Business Systems
This review focused on determining the required
business/operational application functionality required for
each in-scope entity to discharge its duties within the
production value chain by evaluating the suitability of
implemented applications (if any) and the modules in use.
• Reporting Capabilities
This review focused on determining reporting requirements
for each entity by evaluating:
o Existing reporting relationships especially with third
parties
o Third party information inputs (information inflow) into
the entity's operations and processes
o Third party information outputs (information outflow) in
form of reports generated for other entity's in the
production value chain or for regulatory requirements
o The ability of each report or information provided to
serve as a "single view of the truth¨ and is thus
consistent across entities.
• Human Capital
The review also evaluated the adequacy and capability of
human capital in the public sector organisations within the
Oil and Gas industry. This is a prerequisite for any
deployment of IT and Automation in the sector. Particular
attention was paid to the DPR.
• Automation Capabilities
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This review focused on determining the level of automation
maturity (i.e. automation support for each entity's business
and reporting processes).
32. Findings
32. Department of Petroleum Resources
The Department of Petroleum Resources (DPR) is the regulator
of the oil and gas industry in Nigeria. Its functions are wide and
varied. DPR's responsibilities/ powers include:
• Overseeing the lifting of oil, gas and condensates exported
from the country's terminals.
• Overseeing the lifting of finished petroleum products from
depots to service stations throughout the country and
monitoring the quality of products and compliance with
regulations.
• The issuance and renewal of permits and licences,
inspection of operational sites and conducting of licensing
rounds leading to the allocation of oil blocks. DPR, on
behalf of the Nigerian government collects licensing fees
and signature bonuses.
• Imposing fines and closing down non-compliant
operations.
• Advising the Federal Government and relevant agencies
on technical matters and public policies which may have
impact on the administration and control of petroleum.
• Custodian of data, information, and reports necessary for
investment and operational planning, revenue monitoring
and management, and industry regulation.
The Task Force's review showed that:
• Rudimentary Automation in DPR: MS Excel is utilised to
process about 80% of the DPR's information. This is very
rudimentary and falls far short of requirements. The Payroll
software was developed by the NNPC and is used to
process payroll and other compensation related
computations.
• The DPR significantly lags the rest of the petroleum
industry in technology appreciation and adoption.
• DPR has infrastructural (power) and operational
challenges that necessitated them to shut down the
servers at night.
• Current storage measurement is mostly done manually
with staff deployed at tank farms and choke points.
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• The DPR stated in their presentation at the workshop that
a National Production Monitoring system (NPMS) and a
National Data Repository exist. These two systems appear
not to meet industry standards and are yet to be
successfully implemented.
• DPR has challenges with capacity to manage complex IT
systems & Infrastructure
• IT does not appear to be recognized and positioned as a
strategic imperative for the effective and enhanced
functioning of the DPR.
• The DPR appears not to fully appreciate its role as the
custodian of all production information and other key
performance indicators that will enable planning,
monitoring, and other imperatives of this strategic national
asset.
33. Nigerian National Petroleum Corporation
The NNPC is involved in oil and gas exploration activities,
refining, petrochemicals and products transportation as well as
marketing.
In 1988, the NNPC was commercialised into 12 strategic
business units, covering the entire spectrum of oil industry
operations: exploration and production, gas development,
refining, distribution, petrochemicals, engineering, and
commercial investments. Currently, the subsidiary companies
include:
• National Petroleum Investment Management Services
(NAPIMS)
• Nigerian Petroleum Development Company (NPDC)
• The Nigerian Gas Company (NGC)
• The Products and Pipelines Marketing Company (PPMC)
• Integrated Data Services Limited (IDSL)
• Nigerian LNG limited (NLNG)
• National Engineering and Technical Company Limited
(NETCO)
• Hydrocarbon Services Nigeria Limited(HYSON)
• Warri Refinery and Petrochemical Co. Limited (WRPC)
• Kaduna Refinery and Petrochemical Co. Limited(KRPC)
• Port Harcourt Refining Co. Limited (PHRC)
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The Task Force's review showed that:
• The NNPC is in the process of implementing SAP as the
Corporation's ERP. The Current SAP deployment is at
later stages of the deployment will include regional/zonal
office. The SAP Modules being implemented are, financial
accounting, controlling, sales and distribution, materials
management, plant maintenance and project systems.
SAP Implementation at NAPIMS is still yet to commence,
the main business application used by NAPIMS is SUN
systems (version 5). The current stage of implementation
supports only partial automation of key processes relevant
to exchanging data between internal & external parties.
• Challenges with change management are a big hindrance
to the NNPC wide adoption of SAP.
• An independent evaluation of the SAP project should be
undertaken by MPR given the importance of this project
and the enormous resources expended to date.
1. Central Bank of Nigeria
These are the functions of the CBN as it is relevant to the
petroleum industry:
• the banker and financial adviser to the FGN.
• provides information required for revenue reconciliation
with the various collecting agencies (FIRS, DPR, NNPC
etc.)
• in charge of the Nigerian Export Supervision Scheme
(NESS)
The Task Force's review showed that:
• The matching/reconciliation of the amounts received by the
CBN to revenues due per the collection agencies are
predominantly manual.
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• The processing of exports proceeds (using NXP forms) is
manual which is cumbersome and introduces bottlenecks
in getting accurate and timely reports.
35. Nigeria Customs Service
These are the functions of the NCS as it is relevant to the
petroleum industry:
• Intercept contraband
• Assess and collect customs duties and other taxes on
goods and services
• Enforce import and export restriction and prohibitions
• Collect accurate import and export data for economic
statistical usage and planning
• Physical checks on containers, vessels or travellers.
• Prosecute offenders.
The Task Force's review showed that:
• The NCS has a Government Executive Vision¯ (GEV), for
the monitoring of revenue, cargo dwell time, customs
performance and business intelligence analytics. The GEV
should have capabilities (could be customized) to integrate
with external systems such as the proposed central
repository residing at DPR.
• The manual process of collating the proceed repatriation of
oil & Gas Products is cumbersome and introduces
bottlenecks in getting accurate and timely reports.
1. Pre ÷ shipment Inspection Agents
As the name implies, the PIAs were commissioned to oversee
and monitor the export terminals. Their main function is to carry
out a pre - shipment inspection of oil and gas liftings and certify
the exported quantities.
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The certification process is manual as all the forms are processed
manually which introduces bottlenecks in getting accurate and
timely reports on exports.
37. The current metering and measurement regime
On 24 May 2012, the Task Force hosted a stakeholder workshop
on metering and measurement in the oil and gas value chain. The
workshop participants identified certain challenges with the
current metering and measurement regime.
The challenges identified with the current metering and
measurement regime can be summarised as a lack of adequate
vision and ownership required to articulate and drive a cohesive
implementation of IT and Automation in MPR and DPR. The
diagram below presents the detailed components of these
challenges:
:
Figure 6: Key Challenges with the current metering and measurement regime
38. Inconsistent oil and gas data across the petroleum
industry
A number of the findings in Section 2 ÷ Revenue review and debt
verification of this report evidenced inconsistencies in the
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information sighted across the major agencies and parastatals of
the MPR as well as with the oil and gas operators themselves.
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Recommendations
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10. Recommendations
33. Introduction
On conclusion of the Task Force's review and the findings
presented above, recommendations have been developed which
Government should implement to address the issues identified
and their root causes.
The recommendations are a mixture of quick wins and those with
short, medium and long term impact.
34. Strategic Management
Recommendations
From a strategic viewpoint of the Task Force's review and the
findings discussed above, the Task Force recommends the
following immediate and practical quick wins to be implemented in
ending the revenue losses in the Nigerian Petroleum Sector.
Timeline for implementation should be 3 months.
39. Reduce NNPC-related debts and losses
• Set up a process, independent of NNPC, to review the use of
oil traders and NNPC's system for selling crude, on grounds of
value for money and probity.
• Undertake a strategic review of all NNPC subsidiaries before
the PIB passes, with a view to privatizing, repositioning or
scrapping non-performing, redundant or irrelevant business
units.
• Require a full public report by NNPC of the amount, cost and
terms of all cash call debts; improve reporting of this
information to the National Assembly as part of the annual
budget process.
1. Attract investment, build trust and deter
corruption
• Pass an oil sector transparency law that requires all oil
companies active in Nigeria to report all payments, costs and
earnings for each license or transaction, and to publish all
contracts and licenses.
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• Create a special, properly-trained Oil and Gas Sector Financial
Crimes Unit.
• Appoint a new NEITI Board, now long overdue. Members
should be sector experts with a commitment to transparency,
and civil society should appoint their own representatives.
• In order to keep fidelity with the acknowledged need to reform
the sector FGN should establish an embedded and
independent "office of transformation
13
¨ for the sector with a
fixed term and specific mandate to carry through
recommendations and transformational reforms accepted by
government. This will reduce the possibility of missing the
opportunity that addressing the ToR's of the task force
presents.
41. Increase Government revenues via Debt
Collection and Cost Control
• Implement an aggressive debt collection process for
outstanding signature bonus payments; revoke blocks from
non-paying firms; sanction those agencies that failed to collect.
• Conduct an independent process audit of all upstream cost
control rules and mechanisms, including the use of cross-
country price benchmarking.
1. Combat theft of crude oil and petroleum
products and insecurity in the Niger
Delta
• Amend the 1984 Special Tribunal (Miscellaneous Offenses)
Act to strengthen the legal framework for oil theft and other
sector crimes.
• Arrest and prosecute the barons and financiers of illegal
bunkering rings.
• Continue with and sustain the Federal Government Amnesty
Programme.
13
While the Task Force is aware of the existence of a management-led transformation
initiative within NNPC, this recommendation is targeted at ensuring an independent sector-
wide transformation office focused on reform implementation.
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35. Transition Mechanisms
Many of the problems the Task Force's work uncovered are
complex, long standing, and lacking in instant fixes. Beyond the
quick wins already listed, Government should endorse the
following coordinated series of longer term steps and processes
to ensure Nigeria captures full value for its oil and gas
endowments within this decade.
First, to improve the rules and processes governing revenue
collection and management across the sector:
• The Petroleum Ministry should set up an independent advisory
process to design a government-wide oil revenue management
framework in line with international best practices.
More specifically, in the critical area of NNPC crude oil sales:
• The Petroleum Ministry should set up an independent process
to redesign the domestic crude allocation.
• NNPC should develop and publish guidelines for setting crude
oil prices, allocating crude cargoes among buyers, and
renewing buyer contracts. Appointment of selling agents
should be based on an open competitive procurement policy
which is the industry best practice.
• NNPC, in consultation with the Petroleum Ministry, should step
up the process of developing a full-strength trading arm that
can sell Government's crude directly to end users at full and
fair prices.
As further steps towards decreasing NNPC-related debts and
improving oil revenue performance more generally:
• The Presidency, in consultation with BPE and/or the NCP,
should hire consultants to perform a financial due diligence
review of NNPC before the PIB passes.
• Also prior to passing the PIB, the Presidency, with guidance
from the Petroleum and Finance Ministries, should develop a
road map for fully commercializing NNPC so that it has
incentives to minimize costs and maximize earnings. The final
PIB should contained detailed transition provisions that
enshrine the roadmap in law.
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At the same time, to aid the development of rules, systems, and
processes that ultimately will reduce debts and others losses
associated with oil company operations:
• DPR, together with the Petroleum Ministry and the Ministry of
Justice where needed, should resolve outstanding legal and
policy disputes over assessment of royalties and gas flaring
penalties. In particular, royalties should be paid on the basis
of production rather than lifting and sales volumes. The
relevant point of measurement should be the flow station, not
the terminal as is the case now.
• NNPC should develop a policy framework to streamline and
open up the NAPIMS contract approval processes to reduce
costly delays and opportunities for abuse. A performance
management methodology such as the Balance Scorecard
should be implemented in NAPIMS.
• The Petroleum Ministry should articulate a medium-term
strategy for discharging cash call debts and joint venture
expenses, including in the post-PIB era.
• DPR should award all acreage through open, competitive bid
processes, and curb license awards to local companies with
no oil sector experience.
• DPR should work with Galaxy Backbone to hire outside
consultants to review and improve the content of the National
Data Repository, and standardize access to data.
• The Presidency should introduce an amendment to the 2007
Fiscal Responsibility Act 2007 that would criminalize
withholding payment of petroleum revenue after due date and
assessment and a notice of demand.
Meanwhile to guarantee lasting progress on the fight against
illegal oil bunkering:
• The Presidency should convene a multi-stakeholder task force
to develop a Security Master Plan to combat theft and
sabotage.
• The Petroleum Ministry should set up a multi-stakeholder
committee, to develop an implementation framework and
roadmap for the transition to full automation of measurement
and metering of oil and gas production.
In the same vein and to ensure public systems for managing oil
revenue become fully automated and accessible:
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• The Petroleum Ministry should work with Galaxy Backbone
14
the Government IT Company to appoint suitable consultants,
to design, develop and implement a centralized portal for
collating and disseminating hydrocarbon production
information among the relevant government and industry
stakeholders in a standardized format.
• DPR should implement a solution, including a portal to
automate the tracking of royalties, licenses, permits, and other
revenues it monitors and collects.
• At the back-end of both portals recommended above, DPR
should build a functioning Data Warehouse to serve as a main
hub for gathering vital sector information. Management of the
Warehouse should be outsourced.
• NNPC should complete its on-going implementation of SAP to
fully automate key processes relating to revenue management.
The final system should have flexibility to push and pull
information in specified formats to the new DPR Data
Warehouse, all NNPC zonal offices, and other relevant
revenue collection bodies. The SAP implementation in NNPC
should be subject to independent oversight from the Ministry to
ensure that the strategic objectives of this important project are
being met. This can be achieved through consultants
appointed by the Ministry.
36. Revenue and Debt Verification
43. Production
9. Production data for fiscal purposes should be obtained
at the flow stations
The Task Force deems it more appropriate that production
measurement for the purpose of royalty computation should be
taken at the flow stations where crude oil is stabilised and not at
the terminals as is currently the practice. This is in line with the
Petroleum Act Chapter P10, which says Crude Oil Royalties
should be determined based on production figures.
The DPR and operators broadly use the figures measured at the
terminals to determine production data for Royalty purposes. The
Task Force deems it more appropriate to determine production for
Royalty purposes at the flow stations. This would require that the
14
Galaxy Backbone is a wholly owned government establishment with critical ICT resources
reporting to the Hon Min for Communications
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output at flow stations be metered henceforth. It would also mean
that Royalty is due on all the oil in the pipeline network between
the flow stations and the terminals.
If this is implemented, and assuming that the oil in the pipelines
between the flow stations and terminals is the equivalent of 20
million barrels, at an estimated oil price of $50/bbl and average
royalty rate of 10%, monies potentially accruable to the
Federation is in the order of $100million.
44. Domestic Crude Sales
1. No deductions should be made from the amounts
payable to the Federation Account
No deductions should be made from the amounts payable to the
Federation Account, and amounts due to the Federation Account
should be settled gross.
Furthermore, in the determination of subsidy amounts, a proper
review of the Domestic Crude Oil allocations scheme should be
made. The current basis of calculation does not seem to take into
consideration, all of the elements involved in the domestic crude
allocation and utilisation. These include proceeds from sale of
refined products, proceeds from sale/exchange of unutilised
domestic crude, proceeds from sale of other by-products of
refining crude oil, cost of domestic crude, cost of refining, cost of
importation of refined products, other incidental selling costs.
2. Domestic crude oil should be sold at international
competitive prices
The findings clearly show a pattern of under-pricing. This practice
should be stopped forthwith and domestic crude should be paid
for at competitive international market prices. Preferential prices
should not be given to NNPC subsidiaries.
The FGN should also block the leakages within the conversion
process to refined goods in order to make the business of
conversion profitable and worthwhile.
3. Compliance of NNPC with prevailing CBN exchange
rates for remittance of crude oil proceeds
The practice of remitting domestic crude oil payments to the
Federation Account using exchange rates different from the
CBN's should be stopped forthwith. The duty to comply with the
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prevailing CBN exchange rates should be enshrined in a suitable
legal enactment such as the proposed amendment to the Fiscal
Responsibility Act. NNPC should ensure full compliance
accordingly on the exchange rates to be used for the conversion
of Crude Oil proceeds. This should be monitored by the MPR on
behalf of the FGN and where discrepancies are noted,
reimbursements should be enforced.
4. Revisit the Domestic Crude Oil Business Model
The rationale behind the allocation and utilisation of the Domestic
Crude Oil allocations should be revisited. It is hardly acceptable
that in an industry as viable as the petroleum industry, the
company is unable to break even from the purchase and
conversion of crude oil and sale of petroleum products.
45. Equity Crude Oil Sales
1. Restructure NNPC for single point accountability for
Petroleum Revenues
NNPC, as a corporate entity needs to be repositioned and
restructured to be a national oil company capable of making well
calculated business decisions that will optimise revenue and cost
for the Federation from its upstream operations. This will only be
achievable if it has an appropriate overview of the government's
investments and it is able to make timely decisions based on a
complete and accurate flow of information.
2. National investment in the oil and gas upstream sector must
be managed from a strategic focal point
The Federation's investment must be managed from a strategic
focal point to ensure accountability for financial soundness and
investments. This must be underpinned by a robust and
centralised overview of production, sales, investments, taxation
etc.
This should be separate from NNPC operations.
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3. Ensure full compliance of all agencies and companies with
existing legislation
Pending the passage into law of the proposed Petroleum Industry
Bill which would update the current legislation and ensure more
clarity, the Federal Government needs to take advantage of the
provisions in current legislation that would immediately improve
Government revenues.
4. Regularise Crude Oil Lifting Under Contract
Due process must be followed and only traders with valid and
formal contracts that have gone through an open competitive
trader selection process under a documented procurement
process should be allowed to lift crude oil on behalf of the nation.
Where there are breaches to this policy, the approving officer
should be held accountable.
5. Open Competitive selection process for crude oil sales
The list of crude oil traders should be optimised to ensure that
where the country cannot utilise uniquely its trading companies
(Calson, Dukoil, Napoil, and Nigermed), only traders with
renowned expertise and technical know-how are used.
6. Review of the nominations process for all the Joint Ventures
A proper review should be performed, examining the processes
around NNPC's nominations in the joint ventures, actual
production, the split of production losses or gains and liftings, to
determine whether the Federation is receiving their entitlements
in line with the joint venture agreements.
7. Proper review of draft contractual agreements
Immediate steps should be taken to closing the skills gap
between the private sector and government officers in the drafting
and negotiating of all contracts involving upstream operations.
Inappropriate wording could cost the Federation huge losses in oil
revenues.
It is important that the implied costs of these arrangements (cost
of carry), depicted by the proportionate share of the shared oil
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needs to be carefully examined for all agreements, to ensure that
cost is reduced to the minimal necessary level.
An immediate and comprehensive legal audit should be carried
out with external counsel reviewing and standardising legal
processes, protocols, contracts and contract administration
methods. Legal audits should be carried out periodically
thereafter.
8. Adequate funding of the Federations investment obligations
It would be cheaper for the country to avoid these alternative
funding arrangements as the costs seem really high. The FGN
should set aside adequate funds from the proceeds of crude oil
sales to finance cash call obligations under the joint operating
agreements, rather than entering into carry agreements.
Carry arrangements generate an additional cost over and above
the interest on finance, which serves to reduce the federation's
revenue. Therefore, where NNPC must have alternative funding,
these should be entered into directly and not through carry
arrangements. A market structured financing platform would
support the strategic and financial objective of NNPC.
9. Create standard terms and conditions and uniform terms of
contract agreements
FGN should procure for NNPC the drafting, issuance and
implementation of standard terms and conditions and uniform
terms of contract agreements. These should be reviewed on a
periodic basis to ensure uniformity in the interpretation of
contracts and remove ambiguity.
10. Proper and realistic budgets and approvals should be
prepared annually
More emphasis should be placed by NNPC on the budget and
work plan preparation and approval, under all contract types (JV,
PSC and SC) to ensure that the budgets represent realistic
estimates of costs of production. NNPC should maintain a
database of benchmark costs that can serve as reference for the
verification of budgets, work plans and costs.
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In terms of cost verification, emphasis should be laid on
expenditures that are unreasonably higher than the established
benchmarks or extra budgetary expenditures.
In addition, the process of budget/work plan approvals might
need to be revisited, to ensure that NNPC is in a position to
properly review the budgets and work plans and propose
revisions, where the budgets are unrealistic.
11. Capacity Building for NAPIMS
The calibre of staff deployed to NAPIMS need to be accredited to
ensure that they possess the required technical competence and
skills to review the operations of the contractors. Furthermore,
they should be provided with the optimal number of staff, capable
of getting the reviews done in a timely manner. Review and
certification of costs should normally not exceed a year following
the reporting year.
12. Ensure uniformity of the realisable prices used by all
parties
The method used in the determination of realisable prices should
be more specific. Once prices have been determined using this
method, the resulting prices should be published to all partners
and enforced, to avoid disparities in the prices used by the
various parties in these transactions.
13. Carry out adequate review of the purchase or lease
option for production equipment
For the lease or purchase provisions to yield optimum benefits to
the Federation, there has to be a careful analysis of the costs and
benefits of the purchase or lease options for equipment to be
utilized in petroleum operations.
46. Sale of the National Entitlement (Gas)
1. Draw up master agreements for the development of all
potential gas reserves in Nigeria
It has been established that Natural Gas reserves exist in
commercially viable quantities in OPL 212. This has been
developed and produced since 2007, to that effect; the FGN
should facilitate the execution of a master contract that is
agreeable to all parties in this respect.
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Also, the amount of $946.878million said to be due from
SNEPCO should be paid immediately.
The gas situation with SNEPCO may not be one ÷ off, the FGN
should develop standard agreements with respect to gas
production when found in commercial quantities.
2. FGN should ensure that written consents exist for gas
for all assets
The Federal Government should ascertain that there are validly
approved prior written consents for all gas used as fuel gas, gas
injection, gas lift make- up.
3. FGN should intensify efforts to get the other LNG
projects up and running
Government should intensify efforts to bring the other LNG
projects on board, as this will reduce the quantity of gas flared,
amongst many other economic advantages. The generous pricing
mechanism advanced to NLNG needs to be reviewed as the
current prices being paid are way below economic realities.
4. FGN to carry out a comprehensive review of its
NGL/LPG entitlements under the Agip and Shell Joint
Ventures
The Federal Government should carry out a comprehensive
review to understand how the revenue streams from the
Federation's entitlements of gas produced for NGL/LPG under the
Agip and Shell joint ventures are accounted for and remitted.
47. Signature Bonuses
1. Expedite and enforce collections of amounts due with
respect to Signature Bonuses
The oil blocks in litigation are currently inactive and of no benefit
to the FGN in their current state. The FGN should expedite action
with respect to the blocks in dispute in order to ensure that the
$321million outstanding is collected.
Also, the DPR should take further actions against the
concessionaires that are yet to pay the amounts due ($167million)
within the remit of the law. Proposed actions would be to charge
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interest on the amounts outstanding, revoke the company's
license etc.
2. Proper record keeping should be enforced at the DPR
The documentation and records for all awards of concessions
should be domiciled with the DPR to ensure that all amounts due
to the FGN are collected accurately and promptly.
48. Concession Rentals
1. Expedite and enforce collections of amounts due with
respect to Concession Rentals
The DPR should take action against the concessionaires that are
yet to pay the amounts due ($2.9million) within the remit of the
law. Proposed actions would be to charge interest on the
amounts outstanding, revoking the companies licenses etc.
2. DPR should ensure consistency and accuracy of
custodial information
The DPR is the custodian of the information relating to oil and gas
concessions for the nation it is imperative whatever information
obtained can be relied upon. The DPR should put in place
measures to ensure consistency and accuracy of oil and gas
information throughout the organisation. The use of a co-located
offsite data centre should also be considered for risk
management and back up.
49. Royalties (Crude Oil and Gas)
1. Expedite and enforce collections of amounts due with
respect to Crude Oil Royalties
The DPR should take action against the operators that are yet to
pay the amounts due of $3.027billion within the remit of the law.
Proposed actions would include charging interest on the amounts
outstanding.
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2. Demand of outstanding Addax/NNPC Royalties'
payments
The situation where Addax and NNPC continue to use legal
interpretation as basis for non-payment of statutory revenues due
to the Federation is not acceptable. The joint or several liabilities
of NNPC and/or Addax in the outstanding amount of
approximately $1.5billion is undeniable. A demand should be
made on behalf of the Federal Republic of Nigeria and the
consequences of default should (if found liable) immediately be
visited on the contract and the relevant parties.
3. Prompt and proper reconciliations for all revenue
remittances
The DPR should instruct the CBN and operators to ensure the
proper description of all revenue remittances in order to facilitate
the ease of reconciliation. Also, operators and other oil and gas
companies should be instructed to provide timely information for
all revenue remittances to the CBN.
4. DPR should independently track and record gas
production and sales data
The DPR should develop a proper process to independently track
and record gas sales and production figures. This would ensure
that there are no losses of revenues due to the Federation. It
would also provide the important data necessary for reservoir
management.
5. Reconciliation and collection of gas royalties from all
gas producing companies
DPR should ensure that the reconciliation process with all the
outstanding gas producing companies is concluded before the
beginning of the next fiscal year. The companies should be asked
to provide a self-assessment to the DPR within a stipulated
timeframe. Where defaults of this directive is experienced,
adequate penalties should be levied.
50. Gas Flare Penalties
1. DPR should independently track and record gas flare
volumes
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The DPR should develop a proper process to independently track
and record gas flare figures. This would ensure that there are no
losses of revenues due to the FGN. It would also provide the
important data necessary for reservoir management.
2. Automation of the record keeping system at the DPR
The DPR should employ the use of proper IT systems and
databases to keep its records and ensure consistency and
integrity of information across the organisation.
3. Reconciliation and collection of gas flare penalties from
oil and gas operators
The reconciliation process should be expedited for all operators to
ensure timely collection of the gas flare penalty amounts due.
Self-assessment should also be encouraged where possible.
4. Expedite and enforce collections of amounts due with
respect to gas flare penalties
The DPR should take action against the operators that are yet to
pay the amounts due within the remit of the law. Proposed actions
would be to charge interest on the amounts outstanding.
5. Enforce the new gas flare penalty directive as a
disincentive to gas flaring
Annually it is estimated that Nigeria flares 14.9billion cu ft of gas.
At a rate of $11.8/thousand cu ft (average price in 2011) this
implies an estimated $166.582 million in lost revenues (FGN
entitlements, royalties, taxes etc).
The Minister has powers to prescribe to any company permitted
to flare gas any such sum from time to time for every 28.317 scm
of gas flared under section 3b of the Associated Gas Reinjection
Act of 1979. Accordingly, the regulators and the Ministry should
enforce full compliance by all operators with the new gas flaring
tariff regime.
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6. The FGN should enforce a zero gas flare policy
More efforts should be put in to ensure that the zero gas flare
15
policies are implemented, by the beginning of the next fiscal year.
This will improve government revenues and also reduce the
adverse environmental effects of gas flaring.
51. Miscellaneous Oil Revenues
1. Automation of the record keeping system at the DPR
The DPR should employ the use of proper IT systems and
databases to keep its records and ensure consistency and
integrity of information across the organisation. Also, the DPR
should develop adequate processes and procedures to enable
the units charged with the responsibility to collect the various
miscellaneous oil revenues track and collect all revenues due.
2. Update the fees and licensing regimes to reflect current
economic situation
The Fee and Licensing regimes for operating in the Oil and gas
sector should be revisited and reviewed periodically to ensure
that it reflects the current economic realities in the Oil and Gas
industry.
37. Reducing Revenue Losses in the
Nigerian Petroleum Industry
1. Fingerprinting of Nigeria Oil to enable tracking
Fingerprinting can be used to ascribe the status of "Legal Oil' to
oil that has been obtained and sold by the Nigerian authorities
and its licensed operators. A national database of known
components can be quickly created in order to "check the
register¨ for Legal Oil status once it is placed on the market.
National policy should adopt the use of this technology and
require operators to submit known samples to build and sustain
the database. If properly standardized this technology will be a
veritable tool for identifying stolen oil from Legal Oil.
15
The technical considerations are recognised however the achievement of zero gas flare
should be the rule and exceptions to be made only on technical grounds
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53. Establishment of a transparent whistle blowing and
information portal
The Task Force recommends the establishment of a website for
Petroleum Revenue ("PetRev¨) Vigilance such as www.PetRev-
ombudsman.ng.org as a standing independent accessible and
transparent repository of information on revenue losses,
sabotage, and illegal activity affecting the petroleum industry.
54. Policy on market ban of participants in crude oil theft
A deliberate policy that results in the ban from the Nigerian
market of corporations and individuals that have either been
found culpable of:
• Receiving stolen oil from revenue theft in the Nigerian
petroleum industry or;
• Insufficiency in providing information of its participation
(legal or otherwise) in petroleum sector transactions or;
• Unresponsive in its attention to request for transparent
surrender of information regarding Nigerian petroleum
sector transactions.
1. Amendment of Fiscal Responsibility Act regarding
Petroleum revenues
The Fiscal Responsibility Act 2007 should be amended to
criminalize withholding payment of petroleum revenue after due
date and assessment and a notice of demand. This amendment
is strongly recommended.
38. Automation of the Nigerian Petroleum
Industry
1. Department of Petroleum Resources
• The DPR should work with Galaxy Backbone and
competent consultants to review on-going projects, NDR
and NPMS, and also develop a strategic IT blueprint for
the organization. This should include:
o Web-based license application portal with work flow
and approval features
o Hydrocarbon accounting solution with interfaces with
IOCs, LOCs, etc
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o Robust production data repository with online-real
time data collation and dissemination features
o Operational data warehouse with dashboard
reporting features for monitoring and revenue
recognition
o A strategic organizational and human capital
development plan to ensure that DPR builds
capacity to manage and leverage its IT and
technology investments and also has capacity at par
with the industry it regulates.
• DPR and MPR should commence the implementation of a
portal that aggregates and presents in real time all relevant
information about the operations and performance of the
oil and gas industry.
• An ERP Solution should be put in place to capture and
automate the identified backend processes in DPR.
• DPR, based on its mandate should build a Data
Warehouse which would serve as a hub for gathering vital
data about the industry and disseminating reports in
various formats to government stakeholders. The
implemented system should be "owned¨ at DPR and
managed by an outsourced party and hosted at a
Government Data Centre. It is necessary to develop a
framework and implementation roadmap for the transition
to full automation of measurement and metering of oil and
gas production and focalization. This will be a collective
effort involving DPR and the operators with oversight from
MPR.
• A phased approach should be adopted with emphasis on
good record keeping, timely collation and dissemination of
data and accessible to internal & external parties.
57. Nigerian National Petroleum Corporation
• The implementation of SAP should be expedited to fully
automate key processes especially relating to revenue
generation, processes feeding and pulling data to external
parties:
o It should facilitate oversight of group activities and
enable operational efficiency for revenue recognition
and other internal processes
o There should be an appropriate interface with
selected oil and gas industry stakeholders for
supervisory purposes
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o The SAP system should have flexibility to Pull &
Push information in specified formats to the
recommended central Data repository to be
administered by DPR
• The NNPC's culture, end user work ethics and employee
resistance to change all need to be managed extensively
for the SAP implementation to be a full success.
• The SAP implementation should be independently
monitored from the Ministry to track and ensure that the
strategic objectives are met.
58. Central Bank of Nigeria
• A quick win solution would be to study & automate the
NXP forms with a view to track shipments, track
repatriation of export proceeds, and serve as an early
warning system where a company has defaulted.
• The existing CBN systems should be interfaced with other
systems in the various relevant agencies in order to
provide an overview of all revenue reporting and enable
timely reconciliation between organizations:
o Access to customs, banking and agency activities
with respect to shipment documents generation and
FX demand
o Access to industry operational data warehouse for
oil & gas production and related information to
facilitate supervision and intervention efforts
59. Nigeria Customs Services
• The existing NCS system should be integrated with other
systems in the various relevant agencies in order to
provide an overview of all revenue reporting and enable
timely reconciliation between organizations:
o Automated platform to monitor international trade
transactions
o Document management system for trade documents
(i.e. manifests, etc.)
o Reporting dashboards to monitor revenue and
customs performance
1. Pre ÷ shipment Inspection Agents
• A quick win solution would be to study & automate the
NXP forms with a view to track shipments, track
repatriation of export proceeds, and serve as an early
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warning system where a company has defaulted. Online
forms should be developed for export agents, NCS, DPR
as wells as Oil & Gas Exporters to facilitate efficient
processing, tracking and review of transactions and
information. Specifically :
o Access to up-to-date information on shipping
schedule, planned loading activities, etc.
o Automated portal for NXP reporting process among
relevant agencies (i.e. DPR, exporters, customs,
etc.)
1. Full automation of the Petroleum Industry
The PRSTF has recommended a way forward; this
recommendation is based on identified critical building blocks and
guiding principles to achieve the desired outcome of increased
revenue and efficiency for industry players.
Figure7: Building Blocks for achieving full automation to the Petroleum
Industry
As part of the automation initiative, one of the main components
of the new system is the metering and measurement regimes.
The key features of the proposed metering and measurement
regime have been identified along with key automation
considerations in Figure 8 below.
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Figure 8: Features of proposed metering and measurement regime
As a number of activities have to take place in order to fully
digitise oil production measurement and achieve industry-wide
integration, the Task Force recommends a four-phase approach
(Figure 9). The Task Force has also identified proposed key
activities to be performed during the first phase. The key activities
for phases 2 ÷ 4 will be determined upon the conclusion of Phase
1 based on defined requirements and target architecture.
Figure 9: Proposed Four (4) Phase Approach
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Finally for Industry wide integration of data and information, the
Task Force has proposed a Management Information Architecture
as depicted in Figure 10 below.
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Figure 10: Schematic of the Proposed Architecture
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Key terms used in depicting the Management Information
Architecture have been explained below:
Data Acquisition (Systems and Source)
• Data sources from various stakeholders will be fed into a
staging database for the extraction, loading and
transformation (ETL) of captured data
Staging Database - Raw Production Data
• Central source data hub feeds the data warehouse and can
be availed for operational needs
• Collection of metadata starting from source system extracts to
the presentation
Data warehousing
• Data warehouse is the source system for all DSS reports with
the exception of operational reports
• Exploratory data warehouse supports long running jobs that
require persistent data view
• Use of open standards such as SQL, MDX, PMML to access
data warehouse
Analytics Management
• Consolidation of access mechanisms into a single sign-on
platform
Strategic Decision Making (Output to Ministry of Petroleum
Resources and other Stakeholders)
• Dashboards are created for the use of pre-specified recipients
including the Minster of Petroleum Resources and other
stakeholders.
Connectivity Infrastructure
All of the above will be underpinned by industry-wide connectivity
infrastructure that will ensure the secure and reliable transmission
of data from wellheads through field offices to corporate and MPR
headquarters. This will be independently implemented with
central coordination and project management from professional
project managers engaged by the Ministry.
This document is © 2012 by ross-glover - all rights reserved.
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Report and committee things

have become normal in Naija I'm not bothered jare it is just d same old story http://earn4refer.com/ref.php?page=act/ref&invcod=185905 check that link, register and start refering people

This is an incomplete report.

This is a very important and complex issue. In my opinion, Johnathan should give this committee till the year's end to complete this review-investigation-recommendation task. This right here is very very important to Nigeria's health. There are too many Limitations and constraints listed in this report which should be plugged. But knowing how Nigerian govt people work; probably One of Johnathan's paddy-paddy/sponsors/friends already knows that they will get in big trouble if a truly comprehensive report is finished and so therefore it has to be submitted incomplete. JOHNATHAN GIVE THESE GUYS 2 MONTHS MORE AND THE AUTHORITY TO SUMMON (punishable if denied) ANY ENTITY OR BODY FOR THE PURPOSE OF GETTING A TRULY COMPREHENSIVE (not partial) REPORT.

Re:Nuhu Ribadu report

The 2005 Audit of the Oil and Gas Industry revealed the following: a total of 917 million barrels of crude oil were produced during the period under review. CBN received from the oil and gas sector, a net revenue of US$ 28 billion and a value of N790 billion. Amount owed by NNPC 2 d federation acc: domestic crude and other income was N654.8 billion and dividend payments from NLNG were $.2billion. Underpayments for Recovery in 2005 amounted to $.8billion and a value of N1.5 billion. More revenue would have accrued to the federation but for the losses occasioned by the significant process weaknesses identified in the system. Since 2005 NEITI has conducted more Audits with details 'frauds' established what happened??? What is the NOISE on President asking for Ribadu committee findings, what a funny people - Nigerian elites?

ABATI THE BIG LIAR OF GEJ

ABATI HAS REPLIED USING FIGURES NO ONE KNOWS. IT MEANS THAT THE REPORT MR. PRESIDENT REQUESTED BY FRIDAY HAS BEEN ALTERED. THE POSTING ABOVE IS AN ANSWER FORTHCOMING. WHY COVER UP AND FRAUD IN PROGRESS. WE HOPE RIBADU COMMITTE SAVED THEIR COPY TO CONTRADICT ABATI DEFENSE. AMERICA REUTERS IS NOT LIKE PAID NEWSPAPERS WRITTEN UPS IN NIGERIA MISTAKENLY THOUGHT TO BE NEWS, THEY REPORT THE NEWS AND DON'T MAKE THE NEWS. THE ONLY NEWS THAT EXIT IN NIGERIA IS INDEPENDENT SAHARAREPORTERS. FAKE AUDITS IN PROGESS.......OOOOOOOO

ALLISON IS CONDOM

Married couple wanting to be pregant using condom. That is what Jonathan has done allowing petroleum Minister Allison Madueke (the condom) to stage manage the Ministries atrocities. It was safe to appoint Allison for strategic reasons, but she has expired. So upon the disuse of condom by the couple the wife got pregnant. Allison is the condom used in this case, so if Jonathan continues to use condom in his relationship with Allison there would be no pregnancy(image improvement). Under Allison NNPC reduced to decay, highest oil thefts in nigeria history under her, fake marketers, frauds, massive corruption, incompetence and arrogant manner,which she has used to run the Ministry means Jonathan’s downfall is inevitable. How possible can all the oil marketers commit all the alleged crimes and other NNPC atrocities unearthed and the person (Allison) at the helm of affair is not involved?

ANOTHER ALAMS OF BAYELSA state REPORT BY RIBADU

What is the difference between thief Farouk Lawal and Boniface who connived with their masters in SNG and Occupy 9ja, via the home of Buhari, to leak the report of d 25 yrs old fuel scam which IBB introduced in 9ja to the media and the present unpatriotic act of Ribadu and his alawada team? Rather than have Farouk present the final report on the oil scam to d president or d minister, he first handed the document to Buhari and Bakare. The story about the fuel scam is that over 99 percent of those who stole from the poor masses of the country, hail from the 3 old regions of 9ja! The Ijaw man BH, wants to chase out of aso rock, did not benefit from the fuel scam-In sound economic environments-u would expect that most of the portfolio carrying contractors that abound in the oil sector, come from the SS-tribalism abi? Fine biko let us split quietly-for we shall be here for another 52 yrs, playing games with our zonal thoughts while our hospitals and the masses remain in ruins! Animals

What!???

You must be stupid and ignorant!mumu like u. pls address the issues raised, and not biggotery! idiot!

useless comment

I can't believe this kind of comment can come from a right thinking person. He didn't even make a point. Everything was just filled with hatred, sectionalism, bigotry and all sorts. This is definitely not the kind of citizen Nigeria needs at this time. Shame on you.

That is the kind arrogance

That is the kind arrogance these emergency big boys benefitting from militancy have. They never have the patience to listen or read in between lines. Who are you threatening with splitting? Do people who live on water have a place to call their own? Okay...go and drill the oil , you can not, go and fish you can not, go and read you can not...so who gains/loses when Nigeria splits. Be responsible and patriotic to Nigeria not ND or SS.

That is the kind arrogance

That is the kind arrogance these emergency big boys benefitting from militancy have. They never have the patience to listen or read in between lines. Who are you threatening with splitting? Do people who live on water have a place to call their own? Okay...go and drill the oil , you can not, go and fish you can not, go and read you can not...so who gains/loses when Nigeria splits. Be responsible and patriotic to Nigeria not ND or SS.

NNPC STINKS

THERE IS NO OIL NATION THAT IS MISMANAGED LIKE NIGERIA IN THE WORLD. LATE GHADAFI INVESTED AND SAVE OVER $200BILLION IN SOVERIGN FUNDS AND INVESTMENTS FOR LIBYAN PEOPLE. NGOZI IWUELA IS IN HASTE TO BORROW MORE FOREIGN MONEY FOR NIGERIA USING HER FAMILY AS FRONTS AND COLLECTING MILLIONS OF DOLLARS IN COMMISSION IN ADDITION TO HUNDREDS OF CONTAINERS SHE COLLECTS FROM NIGERIA CUSTOMS.UNDER ALLISON MADUEKE, NNPC IS BANKRUPT AND YET JONATHAN CANNOT SEE THAT. WHEN OIL IS HIGHEST IS WHEN NIGERIA IS BORROWING. HOLD NGOZI IWUELA AND ALLISON MADUEKE RESPONSIBLE FOR NIGERIANS DWINDLING OIL REVENUES. WHO WAS INCHARGE OF OIL LICENSING AND OIL MARKETERS LICENSES? WHO SUPERVISED WHO AND WHO KNOWS WHAT AND WHEN? IT HAS BEEN REPORTED THAT JONATHAN SLEEPS WITH ALLISON MADUEKE A MARRIED WOMAN, IS THAT THE REASON ALL HER EXCESSES ARE PUT UNDER THE TABLE? ALLISON SHOULD BE ARRESTED AND TRIED.

NAIJA 4 U

My brother, That is Naija 4 u.The venom of His leaders's corruption has eaten deep into his brain.And anybody that has never been to a nation having power stability will believe that having power generating plant in Naija is the peak of blessing. May my own sufferness and that of the true patriotic Nigerians not be significant.

RIBADU Report and OIL Theft Scam

Today, if President Goodluck Jonathan is ignorant of the theft of money from the Oil sector, may our good God grant him abundant wisdom and blessings. If he is a partaker of the theft, and pretends not to know, may he and his family's gains in money from this oil sector be their losses in Good health, happiness, wisdom and God's blessings. So shall it be to his ministers who are partakers of it. Amen. Nigeria requires the Ghana revolution of Jerry Rawlings. A responsible military personal, not the IBB or Abacha type.