MSAF 616 - LECTURE SLIDES - SESSION FIVE - APRIL 2023.pdf

Production Sharing Contracts / Agreements
• Introduction
• Ownership and Exploitation of Reserves
• Concessionary System
• Production Sharing Contracts
• Production sharing alternatives
• Accounting for Carried Interests
• Accounting for Production Bonuses
• Audit of PSC Costs
• Farm out / in
• Carried Interests
• Unitisations
• Rederminations

Introduction
Ownership and Exploitation of Reserves
• Petroleum reserves are now almost always owned by the State. Some
exceptions to this can be found onshore in the USA, and in parts of
Canada and Trinidad, where the landowner owns the minerals under
the ground.
• In the early days of the industry it was large international oil
companies (IOCs) that explored for and produced the oil. These IOCs
owned the oil they produced and this situation eventually led to
significant political problems in many countries.
• The rules for exploration of the oil and gas resources differ by country
and by region. In particular, the fiscal or tax rules for the exploitation of
hydrocarbons differ from country to country. The essential difference is
the degree of State control and participation.
• The State basically has two choices in establishing a framework for the
exploitation of oil and gas resources and these are:
✓ A Concessionary system
✓ A Contractual system – Production Sharing Contracts

• A Concessionary system is where the international oil companies own the
oil and gas that is produced with the State taking its share of the profits
made from the venture by levying taxes on those profits.
• A contractual system is where the state owns the oil and gas and the
international oil companies are contractors to the State for the
exploitation of the natural resources of the country. The State takes its
share of the profits by retaining share of the production from the field,
although the State may also levy taxes as well.
• Both systems, therefore, are attempting to extract what the State
considers to be its fair share of the profits from the natural resources in its
territory.
• In both systems the State has to recognize that the oil industry is a capital-
intensive industry where the investments needed to bring oil reserves to
the market can be very large. It is also an industry that is characterized by
high risks and many unique uncertainties but an industry that can still
result in high rewards by way of substantial profits.

The risks that all international oil companies accept in exploring for oil and
gas can be detailed as follows:
• The geological risk of finding hydrocarbons in commercial quantities.
• The technical risk of ensuring that production objectives can be
achieved
• The price received for the oil when production eventually starts
• The general economic risk of completing the project on time and on
budget
• The risk of keeping operating costs under control and at the level
anticipated in the Economic evaluation of the project
• Political interference
• Changes to contract terms
• Changes to tax rates
• Possibility of nationalization
• A lengthy period when cash flow is negative as the oil companies
provide all of the funds to explore for and develop oil and gas reserves

• The division of profits is of fundamental importance and
this comes down to what is called contractor take and
government take. These can be expressed as percentages
and can be used as a rough comparison of the terms being
offered by different governments.
• Contractor take is the percentage of profits to which the
contractor is entitled and government take is what is left.
“Take” is calculated as follows:
Total Cash Flow Total gross revenue less total gross
costs over field life.
Government Net All government receipts from, e.g. royalties,
taxes, bonuses, production or profit sharing (excluding
government working interest share of Total Cash Flow (1).

Government
Take
Govt Net Cash Flow (2) x 100
Total Cash Flow (1)
Contractor Take Cont.Net Cash Flow (4) x 100
Total Cash Flow (1)
• Government take will, be a composition of how it has
decided to extract its share of the profits from the field
either by taking a share of the production or by levying
taxes on the various levels of profit.
• The percentage of the contractor take provides an
important comparison between one system and
another and between the differing contract terms
offered by various governments around the world.

Concessionary System
• In a concessionary system, the State owns the reserves in the
ground, but title passes to the license holder (international oil
company), when the reserves are produced.
• The concession holder controls both exploration and
production operations and usually owns all the equipment
used in the petroleum operations. Host governments/rulers
were paid in the form of rentals, royalties on production, and
taxes on profits, but very seldom in oil!
• Concessions were the first type of international contracts and
are still in use in various forms today. The contracting company
provides all the funds and assumes all of the financial and
geological risk of exploration and development.
• The host government does not participate in the operation, but
receives a royalty percentage of any petroleum produced and
sold, and income taxes on the contracting company’s profit.

• The timing of the government’s income from royalty
and income tax differs significantly. Royalty is
payable from the first barrel produced and sold.
• Income taxes can take several years to materialize
since the contracting company must first recover its
initial costs and allowable depreciation of its
investment before it books a taxable profit.
• These taxes were introduced as it was considered
that oil companies were making excess profits from
the unexpectedly high oil prices and these profits
were not arising as a result of the efforts of the oil
companies. They were regarded as windfall profits
and not normal profits arising from regular business
activities.

The taxation structure under a concessionary system may include
some or all of the following;
Royalty
• The State takes a specified percentage of the production from the
field when it has been ‘won and saved’. This percentage may vary
over the life of the field and the State may have the option to take
their share of the oil produced or the cash equivalent. This is
regarded as a tax on production.
Oil Industry Tax
• These taxes are typically levied on the revenues arising from the
field production, after royalty has been deducted, and are specific
to the E&P industry. These special E&P taxes are to maximize the
government take and prevent the oil companies making what might
be seen as excess profits due to high oil prices.

Corporation Tax
• This is a tax levied on all companies who are
conducting business in the Country. Corporation tax is
usually levied on the profits remaining after deduction
of all other taxes.

EXAMPLE – GOVERNMENT TAKE/CONTRACTOR
CONCESSSIONARY
TAKE –
• The government take/contractor take for a
from the
Concessionary system can be calculated
following information:
Royalty 20%
Total operating costs 28%
Capital costs 12%
Income tax 35%

Step 1 Gross revenues 100%
Royalty 20%
Net revenue percentage 80%
Step 2 Costs (opex & capex) 40%
Taxable revenue 40%
Step 3 Income tax (35% of taxable revenues) 14%
Contractor after tax net cash flow 26%
Step 4 Gross revenues 100%
Costs (opex & capex) 40%
Total Profits as percentage of gross revenues 60%
Step 5 Contractor after tax net cash flow 26%
Total Profits as percentage of gross revenues 60%
Contractor take/share of profits 26/60 = 43.3%
Government take/share of profits 34/60 = 56.7%

EXAMPLE- GOVERNMENT TAKE/CONTRACTOR TAKE -
CONCESSIONARY
• The government Take and Contractor Take for a
Concessionary system can be calculated from the
following information as follows:
✓ Royalty 16%,
✓ Costs (opex, DD& A, decommissioning) 42.6%,
✓ Hydrocarbon Resource Tax 28%,
✓ Corporation Tax 30%
✓ Oil price $22

DESCRIPTION SPLIT OF THE
BARREL
GOVERNMENT TAKE
OF PROFITS
CONTRACTOR
TAKE
OF PROFITS
Gross
Revenue
$22.00
Royalty (@16%)
3.52 3.52
Net Revenue 18.48
Costs (@42.6%) 9.37
Taxable Revenue 1 9.11
Hydrocarbon Resource Tax (@28%) 2.55 2.55
Taxable Revenue 2 6.56
Corporation Tax (@30%) 1.97 1.97
Net After Tax Profit 4.59 4.59
Note: Split of Profits
Total Profit($22-$9.37) 12.63
Division of Profits $ 8.04 4.59
Division of Profits % 63.65%
(8.04/12.63*100)
36.35%
(4.59/12.63
*100)
Note : Split of the barrel $ $8.04 $13.96

• In 1960 Indonesia introduced the concept of the
Production Sharing Contract (PSC) or Production
Sharing Agreement (PSA) and signed the first PSC
with Mobil in 1966
• Afterwards Egypt signed a similar PSC with Amoco.
Both of these PSCs were for enhanced recovery from
fields already in production.
• Production Sharing Contracts or Agreements
(PSCs/PSAs) are a common way of regulating the
exploitation of hydrocarbons in many parts of the
world. Regions in the world where companies are
likely to enter into a PSC are shown in this map.

• PSC appear to be very different from Concessionary
Agreements and while there are a number of significant
differences, many of the apparent differences are political
and symbolic rather than real.
• The most significant difference is that in a PSC the State
retains ownership and control of the oil and gas in the
reservoir and after it has been produced, with the oil
companies as contractors providing services to the State.
• The contracting companies’ costs incurred in exploring for
and exploiting oil and gas resources are reimbursed by way
of “Cost Recovery Oil”, usually referred to as “Cost Oil”.
• The production remaining after Cost Oil is defined as
“Profit Oil” and is split in the proportions specified in the
contract. The contractor’s profit from their share of the oil
is often also taxable.

• A PSC is a contract between the State (or the State
Oil Company as a rep. of the State) and an oil
company (or a JV of oil companies). PSCs are
preferred as the means of controlling the
exploitation of petroleum in those regions due to:
• Lack of financial resources within the country to
explore for and exploit any hydrocarbon that are
found.
• Lack of technical expertise and know how within the
country
• Reluctance to accept the risk of exploring for oil and
gas, even when the State has adequate financial
resources

The main features of a PSC are:
• Exploration and Appraisal (E&A) Costs are funded by the Joint
Venture (JV) Group. The State Oil Company normally has no
financial participation or risk during this phase.
• If no oil is found, the JV Group bears all the cost (with no claim
on the State for any money spent) and must normally relinquish
all or part of the acreage in the license.
• If oil or gas is found in commercial quantities, the development
costs are usually borne by the JV Group although the State Oil
Company, if they are a participant in the JV, will often have the
option to take a participating interest in the venture at this time
and pay its share of costs, the other members of the JV Group
will pay these on its behalf, with re-imbursement taking place at
a later stage.
This kind of arrangement is designed to finance the State Oil
Company and is effectively a loan, referred to as a Carried Interest.

• The State repays E&A/Development Costs only when
production starts and does so from Production (Cost
Oil).
• Where there is participation in the venture by the
State Oil Company, It forfeits an agreed percentage of
its entitlement (in its capacity as a participant in the
JV) to oil produced until such time as the value of the
Cost Oil has repaid the other members of the JV
Group for the costs that have been incurred on
behalf of the State Oil Company during the
exploration and development phases of the venture.
• This may also include interest on the carried costs if
this is provided for in the contract.

The liability of the oil company to local taxes may also vary from country to
country. Additional payments made by the oil company to the State are also
diverse, e.g. :
• Signature Bonus – a lump sum cost paid by the joint venture group at the
time of signing an exploration and or exploitation agreement.
✓ Rosneft agreed to pay $1.1 billion to the Venezuelan government in May
2013 to secure a 40% interest in the Petrovictoria project, with their
share of reserves estimated to be around 40 billion barrels.
✓ In 2006 Sinopec paid $2.2 billion to the Angolan government to secure an
interest in Blocks 17 and 18.
• Production Bonus – an agreed scale of fees paid by the joint venture to
the State depending on production factors such as production volumes in
a given period, total production from the field, daily production rate, etc.
• Social Obligation – an agreed sum to be paid every year by the joint
venture group for social projects, such as building and equipping a school
or medical facility. This may also be defined as a Training Bonus, whereby
the joint venture commits to spend a specified amount for the training
and development of host country national employees of the State Oil
Company.

Further typical provisions of a PSC include:
• That the contractor or JV group must spend minimum annual amounts of money during
particular phases of E&A, Devt. and production. This is usually most onerous during the
exploration phase of the venture and there can be penalties if these are not complied.
• That all equipment and facilities purchased by the contractor and imported into the
Country for the exploration, development and production of oil becomes the property of
the State when it is installed in place. The contractor will nearly always have the right to
use the equipment and facilities for the duration of the contract. This does not apply to
equipment provided by a third party service company, which is only hired for a period
when specific services are being provided.
• The State will retain management control of the PSC. Usually there will a management
Committee established that would have representatives of both the State and the
contrator. However, final decisions- making will be by the State.
• The contractor will be responsible for preparing and submitting annual work plans and
the annual Budget for review and approval by the State. Once this has been approved,
the contractor is responsible for carrying out the agreed work programme.
• Most Contracts will provide the National Oil Company (NOC) of the State the right to
become the Operator of the project at certain key times.

• That a certain percentage of staff must by recruited locally. This
percentage may increase over the life of the project.
• That favour in contract award is to be shown to local companies as long
as their price is within e.g. 10% of the next highest bidder. There may
also be a requirement that a certain percentage of contracts be awarded
to local companies irrespective of price as long as the local company can
demonstrate that they are competent to provide the service.
• That a certain percentage of expatriates’ pay is in local currency as an
encouragement to spend that money within the local economy.
• That profits are subject to local tax.
• That the percentage share of production entitlement of the oil company
may fall as output rises.
• Responsibility for decommission of the facilities and how these should
be funded.
• Responsibility for insurance of the facilities

The method for recovering costs and sharing production can vary from contract to contract
but typically the following principles will apply.
Royalty
• Royalties are often applied in PSCs and, where they imposed, they are the first cut of the
barrel.
• That is to say that when the oil has been produced, the royalty percentage immediately
belongs to the State, before any calculations of cost oil/profit oil.
• The contractor may be allowed to offset certain costs associated with transporting oil
from the location where it is produced to the point of sale. This is because the State’s oil
is being transported as well as general oil from the field that will be subject to cost
oil/profit oil allocation.
• The allowable costs incurred in transporting the oil usually include normal operating
costs of the offtake system together with DD&A of the associated equipment as well as
agreed
• Interest charges on the capital investments in the transportation facilities. This is known
as Royalty Netback.
As we stated earlier, royalty can also be applied in a concessionary system in just the same
way as in a PSC, although in a PSC, there is a greater likelihood that the royalty oil will be
taken in product rather than cash.

Cost Oil
• Contractors recoup the costs of operating the PSC, i.e.
exploration, development and production costs, out of gross
revenues (after deduction of royalty, if applicable) received
from the venture.
• The costs to be recovered are referred to as Cost oil. There is
normally an upper limit set of between 35 – 60% of the sales
revenue available for cost recovery. The cost oil percentage is
subject to negotiation on each individual contract.
• This cost oil percentage is of great importance to the contractor
as it impacts on the payback period over which it will recoup its
investment.
• The higher the cost recovery percentage, the quicker payback
will be achieved. This will also have a significant bearing on the
profitability and economics of the project for the contractor.

• In a PSC, the produced barrel is split between the
portion of the barrel
host government and the contractor
. The first
is any royalty obligation
imposed by the contract. Payback of development
costs, and sometimes exploration expenditures, is
included in the recovery of cost oil.
• The agreement may stipulate that such exploration
costs must be amortised or written off over, say, ten
years and the generally much larger development
expenditures over perhaps five years.
• Again, this is an area where each contract may differ
in the manner in which its treats such expenditures.

The following costs are normally recoverable out of
cost oil:
• Unrecovered costs from previous years
• Operating costs
• Capital expenditures
• Interest on funding
• Decommissioning cost recovery provision
A number of these costs can present problems for
the contractors.

Profit Oil
• Revenues remaining after cost recovery are known as Profit Oil and there will
be an agreed profit sharing percentage between the contractor and
government.
• The split ratio can vary depending on a number of different factors and also
over the period of the contract.
• An agreement may initially split the profit oil 60/40 in favour of the State oil
company at commencement of production. As the average production levels
increase the ratio may move to 70/30 or beyond.
• In PSC negotiations this is obviously one of the key issues as this determines the
profits that the oil companies will make on the venture.
Income Taxes
• The contracting company may also pay local taxes on the profit share in
accordance with the prevailing legislation of the country.
• The international oil companies would prefer if the tax rates to which they will
be subject were specified in the contract. This almost never happens, as the
State will want to retain the flexibility to modify its tax regime to reflect
changing economic circumstances. This is similar to concessionary system.

EXAMPLE – GOVERNMENT TAKE/CONTRACTOR TAKE PSC
• The government Take and Contractor Take can be
calculated from the following information for a Production
Sharing Contract:
✓ Royalty 15%,
✓ Costs Oil 40%,
✓ Profit Oil split 80% to Government and
✓ 20% to the Contractor
✓ Oil Price $ 22

D E S C R I P T I O N S P L I T O F
T H E
BARREL
G O V E R N M E N T
T A K E O F P R O F I T S
C O N T R A C T O R
T A K E O F P R O F I T S
G r o s s R e v e n u e $ 2 2 . 0 0
R o y a l t y ( @ 1 5 % )
3.30 3 . 3 0
N e t R e v e n u e
1 8 . 7 0
C o s t Oil(@40%)
7 . 4 8
Profit Oil
1 1 . 2 2
Government Share of
Profit Oil (@80%)
8 . 9 8 8 . 9 8
C o n t r a c t o r S h a r e o f Profit
oil (@20%)
2 . 2 4 2 . 2 4
N o t e : Split of Profits
T o t al Profit ( $ 2 2 - $ 7 . 4 8 )
14.52
D iv is ion o f Profits
1 2 . 2 8 2 . 2 4
D iv is ion o f Profits % 8 4 . 5 7 % 1 5 . 4 3 %
N o t e : Split o f t h e barre l $
$ 1 2 . 2 8 $ 9 . 7 2
Split o f t h e barre l %
5 5 . 8 2 % 4 4 . 1 8 %

Management of PSC
A|W
• Whilst it is the contractor who is finance all of the pre-production
expenditures and taking all the risks, the NOC or government
representatives still retain overall control of the venture.
• Every PSC will have a management board or committee who must
approve annual budgets and work programmes. The management board
will include the contractors and members of the NOC or government,
with the host country representatives having the deciding vote.
• The contractors develop and propose the work programmes and budget
for the forthcoming year and once approved, they are expected to
ensure that the work programme is completed.
• Any failure to complete the approved work programme must be fully
explained to the management committee. The contractor is also obliged
to seek management committee ( i.e. government) approval for various
aspects of the work programme such as the award of major contracts.
• The PSC will define in considerable detail the authorization limits of the
contractor and also clearly specify when it will be necessary for the
contractor to seek the sanction of the PSC management committee.

R Factors
• Rate of return (ROR) based profit sharing regimes are becoming
increasingly the norm. Is a means of capturing a greater share of the
profits from the production of oil and building flexible terms into the
contract.
• The intent with most ROR systems is to reimburse the contractor fairly
quickly for the costs they have incurred by way of a relatively high cost
oil/profit oil split.
• Once it has recouped its costs, an ‘R’ factor will be used to change the
split to more heavily favor the host government with a greater share of
the profits from the venture being passed to the State. The ‘R ‘in R factor
often refers to ‘ratio’.
• It is also used to encourage the development of smaller less profitable
fields while still capturing the high upside possibilities for the host
government.
• Host governments have recognized the need to provide some improved
incentive for the foreign oil company contractors to develop such smaller
less attractive fields.

• Rate of Return-based profit sharing contracts often follow the traditional
concession approach with relatively modest royalty and income tax rates.
• A substantial additional level of tax is then applied as predetermined
discounted cash flow rates of return are achieved by the contracting oil
company.
• Negative cumulative cash flows during the exploration and early years of
production are compounded forward at specified interest rates, where
applicable, along with the positive cash flows once production
commences.
• When the cumulative cash flow becomes positive the surtax is applied as
an additional payment to the host government.
• In this type of agreement the royalty, basic income tax rate, surtax rate
and the compounding interest rate are all subject to negotiation in
arriving at the basic PSC agreement.
• The most convenient way to describe the change in economic parameter
is through a formula that includes an R factor that changes in a
predetermined manner as some measurable contract area value changes.

Cumulative Production
(Millions barrels) Government Share Contractor Share
Tranche 1 0 - 20 60% 40%
Tranche 2 20 - 35 65% 35%
Tranche 3 >35 70% 30%
Daily Production
(Thousands barrels) Government Share Contractor Share
0 - 20 50% 50%
20 - 35 60% 40%
>35 70% 30%

Crude Oil Production ( BOPD) Royalty Rate
Up to 50,000 8% of Crude Oil Production
50,001 to 75,000 10% of Crude Oil Production
Over 150,000 25% of Crude Oil Production
EXAMPLE OF AN R FACTOR FOR ROYALTY AND PRODUCTIONRATE
The R factor can be used to adjust more than one variable as in this example from
Vietnam. Royalty is calculated on the following basis:

Production Royalty Rate Royalty Oil
First 50,000 Barrels 8% 4,000 Barrels
Next 25,000 Barrels 10% 2,500 Barrels
Next 20,000 Barrels 15% 3,000 Barrels
Total 9,500 Barrels
In this example, the rates are applied to each tier of production,
so for a production rate of 95,000 barrels per day the royalty
would be as follows:
Cost oil is up to 35% of crude oil production.

Crude Oil
Production(BOPD)
Contractor State Oil Company
Up to 75,000
50% 50%
75,000 to 100,000
45% 55%
100,000 to 150,000
40% 60%
Over 150,000
30% 70%
Profit oil is shared as follows:

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R FACTOR PROFITS OIL TAKE BY STATE PROFIT OIL TAKE BY
CONTRACTOR
<1.5 50% 50%
1.5 - 2.0 55% 45%
2.0 - 2.5 60% 40%
2.5 - 3.0 65% 35%
3.0 - 3.5 70% 30%
3.5 + 75% 25%
Based on this simple calculation, the tax rate applicable to
profits made the venture will be as follows:

Domestic Market Obligation
• A domestic market obligation (DMO) is a provision whereby a certain
percentage of the contractor’s profit oil is sold to the State or the State
owned Oil Company. This is to address the domestic crude oil or natural
gas requirement of the host country.
• This can also be referred to as the domestic supply requirement. The
selling price for this DMO is usually less than the normal market price for
oil & gas sales and the basis for this price for oil & gas sales and the basis
for this price will be specified in the contract.
• Sometimes the proportion of the profit oil or the price paid will vary
through the life of the production sharing agreement and again this will
be specified in the contract.
• For example during the first 4 years of the contract, DMO may be
refunded at the market price. Thereafter, it may be reduced to 10% or
15% of market price. In some cases the price may be set at, say $2 a
barrel.

• Whilst a domestic market obligation may appear, at first sight, to be
somewhat onerous and unfair to the contractor, it will be a condition of
the contract and the way it will apply will be precisely specified in the
PSC. The contractors will therefore be aware of this obligation and can
recognize the DMO in their economic evaluation of the proposed
contract, and as with any contractual provision, these are usually difficult
for the State to change, unlike tax rates!
• The Government may also pay for the domestic crude in local currency
and at a predetermined exchange rate. This can be beneficial to the
foreign oil company contractor as these funds can be used to pay costs
incurred in the host country.
• This can also however cause difficulties in countries that have strict
currency exchange control regulations. If there are surplus funds after all
local bills have been paid it can be very onerous and lengthy process to
obtain central bank approval to convert the surplus funds to an
alternative currency for repatriation to the home country of the
contractor.

Risk Service Contacts
• Risk Service Contracts are a variation on the PSC theme and only differ in
a small way from more standards PSCs. The difference is in the nature of
the payment to the contractor where he is paid a fee for providing
service rather than in crude oil. The fee may be based on a percentage of
remaining reserves or some other basis. The fee is often subject to tax
by the host government.
• In a risk service contract all production belongs to the state. The
contractor does not get a share of production even though he will be
reimbursed for the expenditures incurred in exploration and
development through the sale of hydrocarbons from the field.
• Risk Service Contracts are more likely to be used by countries that are
net importers of the oil and therefore wish to retain as much as possible
of the production for their own use. They are commonly used in South
America, particularly in Venezuela, the Philippines and more recently
Iraq.
• A feature of these contracts is that the contractor take is usually a very
low percentage of overall profitability.

All Service contracts are slightly different but share some
important common features.
• The contractor has no ownership of the reserves or of the
production
• The contract is to develop the reserves for the host
governments.
• The contractor usually recovers his cost from a sharing of
production, and often ahead of the service fee.
• Development facilities become the property of the host
government.
• From the mid-1960s a number of governments moved to a
Risk Service Contract where the contractor takes on all the
risk and cost of the exploration and production. The
contractor is paid by an agreed fee based on an agreed
factor. This can be a fee per barrel of oil produced or a fee
based on the remaining reserves.

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TheStateagreestopaythecontractorafeecomprisedofthefollowing:
• AlloperatingCostinthecurrentyear
• 1/10thofallunrecoveredcapitalexpenditure
• $0.50perbarrelonproductionupto4,000perday
• $0.75perbarrelonproductionfrom4,001to10,000perday
• $1.00perbarrelonproductionover10,001perday
Maximumfeepayablethatwillbepaidinanyyearis$1.35perbarreltimesthenumberof
barrelsproduced.
Anyunrecoveredoperatingcostorcapitalexpenditurecanbecarriedforwardtofutureyears.
T
odatespendis$10,000,000capex,$2,000,000onopex,productionwas4,000,000inyear.

Therefore production is 4,000,001/365=10,959 barrels per day. The fee is therefore:
Operating Cost $ 2,000,000
Capital Expenditure $ 1,000,000
4,000*365 days @$0.50 $730,000
6,000*365 days @$0.75 $1,642,500
959*365@$1.00 $350,035
Total Fee $5,722,535
Total fee per barrel is computed as $5,722,535/4,000,000 = $ 1.4306 per barrel
This is greater than $ 1.35
The fee is therefore calculated as 4,000,000* $1.35= $ 5,400,000
The difference of $322,535 between the fee and the amount computed using the formula in
the contract is considered to be unrecovered capex and therefore carried forward.
This type of contract can be a very effective way of ensuring that the contractor operates in a
cost effective manner.

Accounting for Carried Interests
• It is a condition in many PSCs that the national Oil Company (NOC) will be a
participant in the venture in just the same way as the other Partners.
However, they will not contribute any funds during the exploration phase
and, in many cases, they will not pay any development cost either.
• The contractor(s), i.e the other Partners, will therefore be obligated to pay
the NOC’s proportional share of costs until the commencement of
production.
• In strict accounting terms this is a carried interest and the question therefore
arises as to how this should be accounted for in the books of the
contractor(s).
• The equity percentage of the JV allocated to (NOC) will be specified in the
PSC. This can range from 15% to as high as 51%. This allows the state to be
closely involved in all aspects of the venture and exercise a greater degree of
control.
• Staff of the NOC to work closely with the staff of the IOCs and gain training
and awareness of modern technology and latest techniques and skills. The
transfer of technology is one of the areas that the NOC are keen to see in
most PSCs, as this will enhance their capability to operate their own
ventures in the future.

• It is important to recognize that the IOCs in this situation
will have twofold relationship with the NOC.
✓ Firstly, with the NOC for the overall management and
conduct of the venture and
✓ secondly, with the NOC as a partner in the JV.
• In a number of PSCs, the government will only exercise its
right to become a full JV partner after the exploration
phase has been successful. In this situation, the contractors
therefore have to bear all of the costs of exploration
themselves.
• The question of interest on the carried amounts can be
somewhat contentious. Whether interest is allowable will
be defined in the contract terms.

• In the accounting books of the venture in the host
country, the carried interest should be clearly shown
as owing by the NOC and these should be recorded
on a monthly basis. In many instances a copy of the
JV billing statement is issued to the NOC.
• This ensures that the NOC is fully advised of the costs
being incurred, provides a basis on which interest
will be calculated if allowed under the contract and
will also be of use to the NOC auditors.
• If exploration efforts are unsuccessful then the
amount show as owing by the NOC is written off and
the venture wound up

Description AFE Number US Dollars Local Currency Total USD
Equivalent
Seismic 2376 5,468,217 2,798,421 7,333,831
Exploration Well 2465 18,326,945 9,385,761 24,584,119
Appraisal Well 2585 22,498,834 10,996,474 29,829,817
General & Admin 2219 3,587,466 5,698,234 7,386,289
Sub Total Exploration 49,881,462 28,878,890 69,134,055
Design & Engineering 3290 37,882,146 2,938,175 38,840,929
Jacket Construction 3478 98,323,641 4,598,347 101,389,206
Topside Facilities 3592 56,227,793 7,968,124 61,539,876
Sub Total Development 192,433,580 15,504,646 202,770,011
Total Expenditure 242,315,042 44,383,536 271,904,066
EXAMPLE PSC BILLING STATEMENT

PARTNER EQUITY % US DOLLAR
EXPENDITURE
CASH CALLS PAID BALANCE OWED
TO/(FROM)
Company 1 30 72,694,513 151,126,531 78,432,018
Company 2 12 29,077,805 60,450,612 31,372,807
Company 3 7 16,962,053 35,262,857 18,580,671
Manistan
NOC
51 123,580,671 0 (123,580,671)
TOTAL 100 242,315,042 246,840,000 4,534,958
US Dollar Expenditures allocated as follows:

Accounting for Production Bonuses
• In some PSCs it is a contractual requirement that
bonuses are payable by the joint venture to the state,
based on production factors that are detailed in the
contract.
• Bonus payments are one of the mechanisms
whereby the State takes an increasing share of the
profits from the field.
• These bonuses are usually based on one of the
following factors:
✓Cumulative production volumes
✓Daily rates of production
These production bonuses differ in nature and their
accounting treatment can also differ.

Bonuses Based on Cumulative Production Bonuses
• These bonuses are based on scale of fees that are
related to the cumulative gross production from the
field. In some instances, the first bonus payment is
payable at the start of production!
• An example of these bonuses is as follows:
✓When cumulative field production reaches 50 million
barrels, a payment of $10 million shall be made
✓When cumulative field production reaches 100
million barrels, a payment of $15 million shall be
made
✓When cumulative field production reaches 150
million barrels, a payment of $20 million shall be
made. Etc….

Bonuses Based On Daily Rates of Production
• These bonuses are paid when production from the
field reaches a specified daily volume and these
usually increase as the quantity of production
increases, in just the same way as bonuses based
cumulative production volumes.
• The contract usually states that the payment are
made when the required level of production has
been sustained for a specific period, such as thirty
days.
• This is to avoid the payment being activated by a
short lived spike in daily production volumes that
may be the result of a new production well being
brought on stream, or some other exceptional
factor.

Accounting for Bonus Payments
• Bonus payment must be accounted for in the country of
operations according to the fiscal rules that are in force
form time to time.
• However, the accounting for bonus payments in the
corporate books of the company will be in accordance with
the accounting rules established by the company and will
be applied in all cases, irrespective of where the bonus
payments are made.
• Charge the bonus payments to the profit and loss account,
that is to say charge it to expense. The reasoning here is
that the payment is as a result of production that has
already been received in previous periods and by charging
it to expense, the correct cumulative profit will be
reported, when all of the accounting periods are
considered together.

• At the start of production from the field, make a provision for
those payments that are considered to be certain by the technical
staff of the company. These payments will therefore be included in
the tangible fixed assets for the field and consequently included in
the DD&A calculation.
• The important consideration here is the degree of certainty that
the required amount of production will be achieved that will
activate the bonus payments. A provision is a liability of uncertain
timing or amount and here, the amount is specified in the
contract.
• Therefore the only uncertainty is the timing of the payment,
inasmuch as it will only be paid if the volume of production
reaches the required level. When the payment is made, the
provision is released.
• This method gives the best matching of costs to revenues, as all of
the expenditures required under the contract to enable the JV to
gain access to the oil from the field over the life of the contract
will be included in the DD&A calculation.

Audit of PSC Costs
• The State has the right in all PSCs to fully audit the costs
reported by the contractors as being incurred for the cost
recovery account.
• This audit is often carried out by employees of the State
owned oil company and the approach adopted by the
auditors can be very aggressive, even hostile at times.
• One of the most frequent areas of concern for the auditor
is the charge and costs that originate from the home office
of the contractor.
• In the case of mandatory charges it is almost impossible to
provide full supporting documentation and consequently
these can be very contentious.
• The auditors are to ensure that the contractor is not unduly
inflating his costs and that there is no profit element in
these charges.

Audit of PSC Costs
• The contractor can only endeavor to negotiate on areas of
conflicts and attempt to resolve these issues in a
reasonable manner.
• Issues arise where the two parties fail to reach agreement,
the contractor normally accept the opinions of the State
owned oil company auditors.
• PSCs have an arbitration clause but these are seldom
invoked.
• In some countries, the State owned Oil Company would
have the audit carried out by an internationally recognized
accounting firm.
• The Operator may also be subject to a separate tax audit
and there is no guarantee that costs accepted by the NOC
will be accepted as allowable for tax calculation purposes.

Impact on Contractor Reserves
• One factor that must be recognized is the impact on
the reserves to which the contractor will be entitled.
• Under most modern PSCs the sharing of oil is a
function of production and oil price. When the price
of oil increases the contractor will receive less barrels
in total.
• This is because it will take fewer barrels to repay the
contractor for his costs with a greater number of
barrels being split as profit oil where the state takes a
far higher proportion and the contractor less. The
converse is true when the price of oil falls i.e. the
contractor will receive a greater number of total
barrels.

• This can appear to have an adverse impact on
international oil companies who usually publish
their reserve estimate in their annual accounts.
• This is particularly relevant in the USA where SEC
regulations are very specific as to the basis on
which reserve estimate must be calculated.
• A reduction in the total number of barrels to
which the contractor is entitled does not
necessarily mean a reduction in profitability. It
can often result in an increase in profitability as
the contractor will receive fewer barrels but be
able to sell those barrels at a higher price.

EXAMPLE-CONTRACTOR RESERVES
Cost oil up to a maximum of 40%, Profit oil split: State 75%, Contractor 25%
Expenditures: exploration and development
Operating costs
$400 million
$100 million
Reserves
At $15 per barrel
200 million barrels
If we assume an oil price of $ 15 per barrel, then:
Total revenues
Cost oil
Therefore Profit oil
200 million X $15 = $3,000
$500
$2,500
$625
$1,125
75 million
Contractor 25% share of Profit oil
Contractor total cash flow
Converted to barrels at $15 per barrel

A
t
$
2
0p
e
rbarr
el
H
o
w
e
v
e
r
,w
h
e
n
thepricechangesto$
2
0perbarrel,
Totalrevenues 2
0
0millionX$
2
0 = $4,000
Cos
toil $500
ThereforeProfitoil $3,500
Contractor2
5
%shareofProfitoil
Contractortotalcashflow
Co
n
v
e
r
t
e
dtobarrelsat$
2
0perbarrel
$
8
7
5
$1,3
75
68.8million

Summary
Barrels
Contractor barrels at $15 per barrel
Contractor barrels at $20 per barrel
Net reduction in barrels to contractor of
Or a reduction of
Share of Profit Oil
Contractor 25% share at $15 per barrel
Contractor 25% share at $20 per barrel
Net increase in share at Profit oil
Or an increase of
75 million
68.8 million
6.3 million
8.33%
$625
$875
$250
40%
Although there has been a reduction in the overall number of barrels that are attributable to
the contractor as a result of the change in the oil price, these fewer barrels give a significant
increase in the profitability of the venture.

Summary of International Petroleum Contracts
• Despite all the variants that have emerged in
recent years, the dominant types of agreements
between the contractors and host government
remain the Concession, the PSC, and the Service
Contract.
• The following table summarizes the most
important provision typical to these contracts.

Issues Concession PSC Service
Parties Grantor:
Sovereign or Govt.
Agency
Grantor:
Govt. Agency or NOC
Grantor:
NOC
Grantee:
One or more investors
Contractor:
Contractor:
Rights Granted Exclusive to explore, develop&
dispose of all production
Exclusive to explore, develop&
dispose of share ofproduction
Pure Service:
Conduct operations for a fee
Risk Service
Exclusive to operate, paid byfee,
but only fromproduction
Production Ownership Grantee owns productionat
wellhead, may have duty tosupply
to local market
Contractor takes entitlementto
share at point of transfer,may
have duty to supply tolocal
market
Usually not applicable. Maybe
paid in oil. May have right tobuy
production.
Performance Obligations Grantee has duty to explore&
develop
Contractor has work programme
to explore, & mustspend
specified amounts
Pure Service:
Work programme agreed with
NOC

Issues Concession PSC Service
Control of operations Grantee has control subject to
regulations
Govt./NOC has nominal
control. In reality Contractor
has discretion to conduct work
programme subject to approval
& regulations
Pure Service:
Govt./NOC control operations
Asset Ownership Grantee owns assets till passed
to Govt. at termination
Govt./NOC own assets Pure Service:
Govt./NOC own assets:
Government Take Large signature & production
bonuses, income & Property
taxes, daily rentals & royalties
Signature & production
bonuses, production share,
income taxes
Signature bonuses, all
production, income tax
Area Size Very large areas Smaller areas to be explored in
first term of agreement
Like PSC
Relinquishment According to license rules According to PSC rules Like PSC
Decommissioning Duty of grantee as per
regulations
Duty of Govt./NOC unless
contract says otherwise
Like PSC

Farm In/Out Arrangements
• The term farm in/out refer to variety of transactions
• According to ASC 932-360-55 the terms farm-in and farm-
out typically refer to an arrangement in which the owner
of a working interest (the farmor) assigns all or part of
the working interest to another party (the farmee) in
return for the exploration and development of the
property
• Farm-in /farm-out agreements are exchange transactions
for which there is no gain or loss recognition.

• A farm in/farm out arrangement results in the holder of an
interest in a license e.g. Company X, transferring all or part of its
licence obligations to another party, e.g. Company Y, in return for
a share of the anticipated benefits arising from the licence. In
this arrangement, the original licensee ( Company X ) who is said
to farm out its interest to the other company (Company Y ) who
is said to farm in from Company X.
• Farm outs most frequently occur during the exploration phase of
venture.

FA R M IN, FA R M O U T
Fa r m Ou t
Co. X Co. Y
Fa r m In

Reasons for Farming Out
A company may wish to enter into a farm out arrangement for a variety
of reasons:
• A farm out may enable it to carry out evaluations of properties which
it would not otherwise be able to do. It may have more prospects
than it has money available to evaluate.
• Time pressure because some of its prospects are nearing the end of
the licence period. Another company may have the resources to carry
out the evaluations more quickly.
• Lack expertise or knowledge. Another company may be able to
provide the necessary skills or may have access to more data.
• Insufficient confidence in a drilling prospect or greater than usual
concerns that financial risks will outweigh the potential rewards.
Another company may have a different view of the risks or may be
more willing to undertake the risks.

●It may be prepared to farm out an interest in a good property in return
for some other rights which it particularly wants, such as interest in
equally good property elsewhere, quantities of different crude which
better meet its requirements, or access to gas reserves as part of
strategic portfolio adjustment. Another company may welcome the
opportunity to farm in to adjust its own portfolio to achieve similar or
different strategic objectives.
Reasons for Farming In
The reasons for farming in include access to resources, skills or data
which are lacked by the party farming-out, a different view of risk, or
different strategic objectives. More specifically:
• A company which has just had a significant discovery may seek to
farm in to adjacent properties while it has an advantage of superior
information.
• farm-in may be cost –effective way of acquiring new skills or
information.

• The party farming in may have greater experience in the area of
activity which may cause it to view the prospect as a viable
proposition.
• A desire to obtain the Operatorship of venture.
• A company may have a significant stake in an existing
infrastructure of platforms and pipelines that result in a
different view on the commerciality of small or medium-sized
accumulations.
• To obtain a presence in a highly prospective hydrocarbon basin
that will allow a company to gain knowledge and expertise in
the area.
• To become established in an area with a view to obtaining new
licenses in further exploration licensing rounds that may be
offered by the government.

• Farm outs usually occur as result of differing views on the risk/reward
relationship of drilling an exploration well.
• It enables a company farming out to participate in a high risk exploration activity
with no cash outlay.
• It enables a farming in with no cash funds to participate in a licenses where it
believes there is sufficiently high chance of gaining an adequate return on the
outlay.
• The farming in company might also pay for any cost incurred to date by the
farming out company. In return, the farming-in company would receive an
agreed percentage of the farming –out company’s equity interest in the licence.
• Each farm in/farm-out will be subject to individual negotiation and the terms
agreed between the parties will reflect the relative strengths and weakness of
their respective negotiating positions. A typical arrangement would be for the
company farming-in to pay a premium, referred to as a “promote”, whereby it
will pay for a higher share of the well costs than the equity interest it will
eventually receive in the venture.

• For example , if the company farming –out has a 50% share of
the venture, the farming in company may agree to pay the full
50% share of the costs of the next exploration well in order to
acquire a 20% equity interest in the venture. This may appear
somewhat harsh on the company farming-in but it must be
recognized that they have not incurred any of the previous
expenditures on the licence such as seismic costs, geological
studies and general and administrative costs.
• Another arrangement sometimes used is that of cost
equalization. Under this arrangement the company farming-in
would be required to pay all of the farming-out company’s costs
until it had paid its cumulative equity share of the percentage
interest it is acquiring in the licence.

Company X has a 45% interest in the license block 12. The
gross expenditure to date has been $14,500,000 (which
include the drilling of an unsuccessful exploration well) and
therefore Company X’s inception to date share is $6,525,000.
Company Y has agreed to farm-in and will acquire a 15%
interest in the license. In order to acquire this 15% interest,
Company Y has agreed to pay all of Company X’s costs in the
forthcoming exploration well until such time as it has paid a
cumulative 15% of all of the expenditures on the venture
since the start of the license. The forecast cost of the next well
is $14,000,000.
All costs are shown in 000s.

Description GrossCosts CompanyX
Equity
CompanyX
Costs
CompanyY
Equity
CompanyY
Costs
Priorto2nd
well $14,500 45% $6,525 0% $0
2ndWell
cost1 $7,250 0% 0% 45% $3,262.5
2ndWell
cost2 $6,750 30% $2,025 15% $1,012.5
Summary
TotalCosts
$28,500 30% $8,550 15% $4,275

• The accounting treatment for Company X in this situation would be to
account for those costs it actually pays. That is to say that it only
accounts for expenditure on the well after the first $7,250,000 has
been paid by the other participants to the venture with Company Y
being one of these.
• Company Y will account for its expenditure in accordance with its
normal accounting policies. Company X would disclose in its accounts
for the year that this farm-out had taken place and that its equity
interest in the license had been reduced from 45% to 30%.
• When farm-out deal has been negotiated between the two
companies concerned, the farming out company is usually obligated
to offer the deal to their existing partners in the JV. This is because
most JOAs provide the right of pre-emption whereby the other
partners can opt to take the deal on the same terms accepted by the
company who wishes to farm in.

• The company farming in to the license does not earn its interest in the JV until it
has completed its obligations negotiated. These are fully defined in the Farm In
Agreement, they will not to be entitled to any equity interest in the venture,
irrespective of how much they may have spent.
• During the time when the work of the farm out is underway, the farming in
company has no legal right to participate in the decision making process of the
venture. However, it is normal for the two companies to consult on future plans
for the venture and farming for the farming out company to use its vote to
reflect the wishes of both companies, wherever possible. This is to give the
farming in company some protection from being committed to plans and
expenditures in which it has not had an opportunity to express their opinions.
• Farm ins/outs usually happen during the exploration phase of a venture.
However, it is possible that there could be a farm in/out during the appraisal or
development stage. Development farm ins/outs are very rare but appraisal farm
ins/outs do occur. The risk/reward relationship in this instance is greatly different
from that in an exploration farm in/out as the presence of hydrocarbons has
already been established.

• The reasons for an appraisal farm in/out might be associated
with portfolio management whereby companies want the right
mix of assets as regards nature, size and timing.
• Companies also want the right mix of gas and oil assets. But
again, one of the most significant factors will almost certainly be
cash flow. If a company has committed to a major development,
it may not have the funds to embark on a second major
development. It must be recognized that the drilling of a
discovery well still leaves a number of uncertainties that can
only be resolved by further drilling.
• Furthermore, with an appraisal farm out, the company would be
unlikely to realize the full value of the field that had been
discovered.

Recommended Accounting Practice
The UK SORP states:
• A farm in typically involves the transfer of part of an oil and gas
interest in consideration for an agreement by the transferee
(‘farmee’) to meet, absolutely, certain expenditure which would
otherwise have to be undertaken by the owner (‘farmor’).
• Recommended accounting practice in these circumstances is
that:
✓ The farmor should not record in its financial statements any
expenditure made ‘on its behalf’ by the farmee.
✓ Any capitalized costs previously incurred by the farmor in
relation to the whole interest should be re-designated as
relating to the partial interest retained.

✓ The farmor would therefore treat any reimbursement of costs
already incurred as credit to the accounts that were originally
debited with the costs.
✓ Any cash received in excess of related unamortized past costs
should be accounted for by a successful efforts company as a gain
on disposal of an interest in a field.
✓ A full cost company might credit reimbursements in excess of cost
incurred to one pool of capitalized costs, where the costs relate to
a number of different license blocks.
✓ The farmee accounts for the costs that it incurs as a result of the
farm in, including any payment to the farmor. The initial
expenditure would be capitalized and, in the case of a successful
efforts company, would be written off to expense if the drilling
activity shows the well to be dry.

Disclosures by farmor of consideration received
• The UK SORP recommends disclosure by the farmor of
information to give users of financial statements an
indication of the full consideration received in cases where
the farm- in requires the farmee to bear subsequent costs
that would otherwise fall to the retained interest of the
farmor.
• The farmor should disclose the amount of such
expenditures in aggregate during the accounting period.
• No similar additional disclosure is required by farmees,
since expenditure incurred on license interests will already
be disclosed in their accounts.

Carried Interests
• A carried interest is an agreement under which one party
(the carrying) agrees to pay for a portion or all of the pre-
production costs of another party (the carried party) on a
license in which both own a portion of the working interest.
• The UK Statement of Recommended Practice (SORP)
explains that this arises when the carried party is either
unwilling to bear the risk of exploration or is unable to fund
directly the cost of exploration or development.
• The carrying party is often an existing participant in the
joint venture but may be an incoming participant. The carry
arrangement may be during the exploration phase, or the
development phase, or both.

CARRIED INTERESTS
Co. X CARRIED PARTY
Repayment
Finance 0R
Production
Co. Y CARRYING PARTY

Carried Interests
• The nature of the arrangement is that, for an agreed period of time or until an
agreed event happens, a carrying party (Company Y) agrees to pay for the costs
of the carried party (Company X). During this period, Company X can elect to
end the arrangement by repaying Company Y for its costs incurred, plus interest,
and sometimes, an amount in recognition of the risks taken on by Company Y.
The repayment to Company Y could either be a lump sum settlement or
alternatively, could be out of Company X‘s share of future production.
• Company X would not record any transactions in its accounts during the carrying
period but would disclose the nature of the agreement in its published accounts.
If Company X exercises its option on Company Y, which it would be more likely to
do if exploration efforts have been successful and commercial, any payment to
Company Y would be recorded in the way it normally accounts for exploration
expenditure.
• Company Y would account for its share of expenditures incurred during the
carrying period as if it were its own account and make a disclosure to this effect
in the published accounts. If Company X exercises its option, Company Y will
credit the accounts to which the original expenditures were charged. The
reimbursement should be treated as “other income” in the year the option is
exercised where costs have been written off in previous years.

Carried Interests
• It must be recognized that ownership of the equity interest remains with
Company X during the period of the carry. Company X will assign a beneficial
interest of all, or an agreed part, of its equity interest in the venture until the
carried amounts are repaid in full, together with any financing interest that may
have been negotiated.
• For example Company X may have a 5% equity share in the license where it is
being carried by Company Y. It will assign to Company Y say, 75% of its share, i.e.
75% of 5%, which equals 3.75%, retaining 1.25% for itself. Company X will still
legally have title to the full 5%.
• There must also be an agreement as to which company will pay for the operating
costs associated with the assigned 3.75%. Typically this will be Company Y. In the
Carry Agreement there will also be a formula whereby the production from the
assigned 3.75% will be valued in order to determine the amount being repaid of
the carried amount.
• When the carried amount, and any financing charge, has been repaid in full, the
3.75% reverts back to Company X who will then have a full 5% equity share in
the venture.

Carried Interests
• Most carried agreements provide that Company X will be
under no obligation to reimburse Company Y if the
assigned interest does not repay the carried amount by the
end of the life of the field. Company Y is entering into this
arrangement on a voluntary basis and therefore will have to
accept the risks associated with any E & P activity.
• The other partners in the venture are usually advised of the
carry arrangement but not the terms of the carry, as these
are commercially confidential. There is usually no right of
pre-emption by the other partners as there is no change in
the equities in the venture, i.e. it is not a sale or transfer of
ownership of any part of the license interest.

Carried Interests
Different types of Carry arrangements
• Carry arrangements can differ considerably. The terms are a matter for
negotiation, each party seeking an agreement in its own best interests, and
therefore also taking into the relative bargaining positions of the parties to it.
Each party must assess the risks and rewards of the arrangement.
• When companies enter into a carry arrangement during the exploration phase,
there will normally be a significant transfer of risk from the carried party to the
carrying party. The carrying party will expect a higher reward in the event the JV
is successful. This may take the form of cash or production and may be either a
predetermined amount or based upon a share of the carried parties
entitlement, and so dependent upon reserves discovered and economically
produced.
• There is therefore the prospect of a large upside potential if successful. If
unsuccessful, the carrying party may forfeit not only his own original share of
costs incurred but also the share of costs borne on behalf of the carried party.
• Carried interests entered into during the development phase are also highly
variable, to the extent that in some cases they are in effect financing
arrangements, while in others they are in effect an acquisition of an interest in
reserves.

Carried Interests
Accounting for carried interests
• Since the accounting treatments of carried interests differ according to the terms
of the carry agreement, we will deal here with the three main types of
arrangement:
✓ exploration carried interests;
✓ development carried interests of a financing nature; and
✓ development carried interests in the nature of an acquisition of reserves.
Exploration carried interests
• Where the terms of a carry arrangement are such that significant benefits and
risks are considered to have been transferred from the carried party to the
carrying party, as is typical of an exploration carry, the underlying assumption in
accounting for the activity is that revised equities have been agreed for an
indefinite period.
• The carrying party should therefore capitalize or expense the costs borne on
behalf of the carried party in accordance with the carrying party’s normal
accounting policies. The carried party should not make any accounting entries in
relation to these carried costs.

Carried Interests
Development carried interests of a financing nature
• Where the terms of a development carry arrangement indicate
that it is essentially a financing arrangement, it should be
accounted for accordingly.
• The UK SORP suggests circumstances in which this would be the
case are those where there is a high probability of success, the
terms of the carry arrangement require reimbursement of costs
borne on behalf of the carried party with interest, and there is no
material premium to be paid at the end of the carrying period.
• The recommended accounting treatment by the carrying party is to
record a debtor for costs that may subsequently become
reimbursable by the carried party.
• If the project is successful and the amounts received from the
carried party exceed the debtor balance, the excess should be
credited to the profit and loss account.

Carried Interests
• During the period of the carry, the carrying party will have incurred
additional interest charges, or will have forgone interest or profit
on sums paid on behalf of he carried party. The credit to Profit and
Loss Account of any excess over the debtor balance is therefore, in
part, compensation for the interest sacrificed.
• The UK SORP does not give specific guidance on the accounting
treatment by the carried party in this situation. During the period
of the carry, the carried party is not incurring expenditure in
connection with the interest carried.
• The UK SORP envisages that this type of arrangement will only be
entered into if there is a high probability of success, it would seem
reasonable that the carried party records a creditor.

Carried Interests
Development carried interests in the nature of an acquisition of
reserves
• In some carry arrangements during the development phase, the
carrying party has the potential to receive significantly more than a
lender’s rate of return in consideration for a higher level of risk
than would normally be borne by a lender.
• In these circumstances the transfer of risks and potential benefits
to the carrying party is such that the arrangement would not be
regarded as essentially a financing arrangement.
• The substance of the transaction is that the carrying party has in
effect acquired oil and gas reserves.
• Accounting practice recommended in the UK SORP is therefore that
the carrying party should account for the costs borne on behalf of
the carried party as its own costs. The carried party should account
for the arrangement as a disposal in accordance with its normal
accounting policy.

Carried Interests
Sole Risk as a form of carried interest
• The terms of some ‘sole risk’ activities may be such that they are
effectively carry arrangement. This arises where one (or more, but
not all) of the parties in a JV funds seismic or drilling work and the
‘non sole risk parties’ have the right to participate if results show
positive benefits.
• In these circumstances, the non sole risk parties (the carried
parties) will typically reimburse the sole risk party (the carrying
party) for their share of costs incurred plus a substantial premium.
• Accounting treatment in this case would be as for a carry
arrangement, following one of the three types discussed above as
appropriate to the circumstances.

Carried Interests
Production sharing as a form of carried interest
• Under the terms of Production Sharing Contracts (PSCs), the
host government is entitled to a substantial share of any
hydrocarbons produced, often through its National Oil Company
(NOC) having an equity share in the venture.
• Under terms commonly included in such contracts, neither the
host government nor its NOC will contribute its equity share of
expenditure during the exploration, appraisal and development
phases of the venture.
• These costs must therefore be borne by the other parties to the
venture – the international oil companies, generally referred to
as the ‘contractors’. However, under the terms of virtually all
PSCs, the contractors will be allowed to recover the
government’s share of these costs by taking an increased share
of subsequent production, referred to as ‘cost oil’ (or gas).

Carried Interests
• In these PSC arrangements, the host government or its NOC is
effectively a carried interest and the contractors account for the
activities on that basis in the country of operations.
• The UK SORP recommends that the costs carried on behalf of
the host government or its NOC should be capitalized in its
corporate books as though it were its own expenditure.
• These costs should be treated in accordance with the company’s
stated accounting policies. The rationale is that these costs are
being carried because of a contractual obligation specified in the
terms of license.
• The expenditure on the carried interest is as fundamental a part
of the expenditures necessary to gain access to the
hydrocarbons as expenditures on the company’s own equity
share of the venture.

Carried Interests
Disclosure of carried interest in financial statements
• Neither the UK SORP nor COPAS Bulletin No. 9 give
specific guidance on disclosures in financial
statements relating to carried interests.
• Companies usually include explanatory notes on the
circumstances of carried interests, recognizing the
general requirement to disclose material facts. This
will apply to both the party being carried and the
party carrying the expenditures.

Poolings and Unitisation
• In a pooling or unitisation, the working interests as well as
the nonworking interests in two or more properties are
typically combined.
• Each interest owner owns the same type of interest (but a
smaller percentage) in the total combined property as they
held previously in the separate property.
• The terms pooling and unitisation are often used
interchangeably, however, the most common usage of the
term pooling is the combining of unproved properties. The
term unitisation commonly refers to a larger combination
involving an entire producing field or reservoir for purposes
of enhanced oil and gas recovery.

Poolings
• In a pooling, two or more properties are combined to form
a single operating unit. After the pooling, if the working
interests are held by two or more parties, a joint operating
agreement is entered into and one of the parties is
designated as Operator.
• Pooling may be voluntary or nonvoluntary and usually
brings together small tracts to obtain sufficient acreage so
that a well may be drilled under a state’s specific well
spacing rules.
• As a rule, both working and nonworking interests are
combined, and each party receives an interest stated as a
percentage of ownership in the combined acreage of the
same type as contributed.

Unitisations
• A Unitisation is similar to a pooling, although unitization
usually refers to the combination of leases that have been
at least partially developed.
• In a unitization, the parties enter into a Unitization
Agreement that defines the areas to be unitized and
specifies the rights and obligations of each party.
• Unitisations arise where an oil or gas reservoir is found to
extend into more than one license block and consequently,
is owned by more than one set of license holders.
• Where this arises, the licensees need to agree an
estimate of total recoverable reserves in the reservoir
and the part that lies within their license block.

Unitisations
• The estimate of recoverable reserves from any one of
the license blocks is expressed as a percentage of
overall Stock Tank Oil Initially In Place (STOIIP).
• The purpose of unitization is more economical and
efficient development and operations. In particular, a
unitization may be necessary to conduct secondary or
tertiary operations.
• Unitisations and poolings may be voluntary or
mandatory according to state Law. In some states,
unitisations may be forced if some percentage of the
involved parties, such as 65%, agrees to the unit.

Unitisations
• Two significant issues must be resolved in a unitisation. These
are:
✓ The determination of oil and gas reserves underlying each
property contributed by each party. The relative amount of the
reserves contributed by each party is typically used to
determine the parties ‘participation factors’ i.e. percentage of
working interests in the unitised property. These participation
factors are very important since the amount of costs paid by
each party and revenues received by each party are based on
the participation factors.
✓ The determination of the fair market value to be assigned to
each lease’s wells, equipment, and facilities that are contributed
to the unit. These contributions must be equalised, because the
participation factors do not account for the fact that the
properties may be in varying stages of development.

Unitisations
• To equalise investment, i.e. to equalise contributions, the
participation factors are multiplied by the total agreed upon
fair market value of the Intangible Drilling Cost (IDC) and
equipment contributed by all parties. This calculation is to
arrive at the assigned value of each participant’s interest in the
unit-wide IDC and equipment.
• The participant’s assigned value is matched against the fair
market value of the property transferred by the participant to
determine the amount each participant will pay or receive in
cash. Cash is treated as a recovery of cost, and cash paid is
treated as additional investment. No gain or loss is recognised.

Unitisations
• According to ASC 932-360-55-7:
In a unitisation all the operating and nonoperating participants pool their
assets in a producing area (normally a field) to form a single unit and in
return receive an undivided interest (of the same type as previously held) in
that unit. Unitisations generally are undertaken to obtain operating
efficiencies and to enhance recovery of reserves, often through improved
recovery operations. Participation in the unit is generally proportionate to
the oil and gas reserves contributed by each. Because the properties may be
in different stages of development at the time of unitisation, some
participants may pay cash and others may receive cash to equalise
contributions of wells and related equipment and facilities with the
ownership interests in reserves. In those circumstances, cash paid by a
participant shall be recorded as an additional investment in wells and related
equipment and facilities, and cash received by a participant shall be recorded
as a recovery of cost. The cost of the assets contributed plus or minus cash
paid or received is the cost of the participant’s undivided interest in the
assets of the unit. Each participant shall include its interest in reporting
reserve estimates and production data.

Unitisations
UNITISATION
BLOCK 1
40%
ORIGINAL
BLOCK 2
60%
Co. X 36%
Co. Y 24%
Co. A 20%
Co. B 12%
Co. C 8%

Unitisations
• A redetermination arises where the original estimate of recoverable
reserves contained within the various license blocks is revised or
redetermined. The original percentage split will be very much an
estimate based on information from seismic data and exploration and
appraisal wells drilled based on information from seismic data and
exploration and appraisal wells drilled prior to the start of production
from the field. As more wells are drilled, more information is gathered
about the properties of the reservoir, the relative amounts of oil or gas in
place and their distribution between the two license blocks. This
additional data invariable results in a revision of the ownership
percentages of the reserves.
• This revision to the ownership of the reserves will form the basis of
product entitlement and hence capital and revenue expenditures. The
Unitisation Agreement will detail the procedure whereby a participant
who now considers its entitlement to be invalid can invoke for deciding
when a field is subject to redetermination. This might be after a
stipulated number of development wells have been drilled.

Unitisations
REDETERMINATION
AFTER
BLOCK 1
30%
BLOCK 2
70%
Co. A15% Co. X 42%
Co. Y 28%
Co. B 9%
Co. C 6%

Redetermination
• Normally a redetermination cannot be carried out within the
first year of operations or within one year of a previous
redetermination.
• Once a participant has raised a request for a re-evaluation of
reserves and the other participants agree to it, an external
consultant may be appointed to review all the data available and
determine the overall reserves and the volume attributable to
each license group. The Agreements often stipulate the
methods under which these calculations are done.
• The results will be presented to the Operating Committee for
endorsement. Companies will carry out their own checks on the
results. The costs of the external consultants are charged to the
joint venture, but companies own costs are not. If the revised
volumes and hence equities are approved, a date is established
for the formal commencement of the new percentages.

Redetermination
• This revision has many implications:
✓ Revised equity shareholdings and voting rights.
✓ Revision to capital cost allocations since inception
✓ Revision to lifting entitlements
✓ Possible separate capital cost sharing formula and operating
expenditure
• The adjustments required following a redertermination fall into
two broad categories:
✓ Adjustments to unit substances
✓ Adjustments to unit costs

Redetermination
Adjustments to Unit Substances
• This adjustment recognizes that the companies in one of the
licence blocks has lifted more or less oil than it is entitled to, based
on the redetermined equities. For example, assume after
redetermination that, Licence Group A is entitled to 84 million
barrels since inception at the end of year 4 but has only received
72 million barrels. Group A is therefore in a unit substance shortfall
by 12million barrels and Group B is in a unit substance surplus by
12 million barrels.
• The adjustment required is that Group B must pay back, or make
up to, Group A the 12million barrels surplus it has received since
inception. The Unitisation Agreement will stipulate the precise
rules and mechanism for achieving this.

Redetermination
The choices might be:
• A financial adjustment - at what product price?
• A physical payback or make up adjustment
✓How quickly?
✓Without limitations?
• The principle normally adopted for this adjustment is
for the group in surplus to physically pay back the
amount by which it is in surplus from future production
volumes. This recognizes that JOAs normally only refer
to a basis for cost sharing and make no provision for
joint venture revenue, i.e. there is no joint venture
earnings account.

Redetermination
In this example, the 12 million barrels is to be repaid by Group B
to Group A out of Group B’s entitlement to future production.
The payback rules are normally subject to a number of different
conditions that must be satisfied, e.g. :
• Payback must be achieved within 12 months from the date of
redetermination
• No more than 20% of unit substances are to be made
available for payback
• If payback cannot be achieved after satisfying the above two
conditions, then payback may take place over a 24 month
period
• If payback cannot be achieved satisfying the above
conditions, then payback is achieved over whatever period
required, subject to 20% ceiling of unit substances being
made available for payback.

Redetermination
• These rules are designed to protect the companies in the
group that is in surplus at the date of redetermination
from having its earnings and cash flow unduly eroded as
a result of having to pay back the surplus.
• Whilst this is a normal method for achieving production
volume adjustment, is the method completely fair and
equitable or are other methods feasible? Is the method
fair during periods of highly volatile oil prices?
• The revised percentages will be used for allocating future
revenue costs, as there is a fairly close relationship
between production costs and production volumes.

Redetermination
• During the payback period, the Operator will closely
monitor and report on cumulative payback and will
advise unit participants of the date on which payback
is achieved. At the end of the payback period, equity
entitlement to unit substances will be according to
the redetermined percentages.

Redetermination
EXAMPLE – PAYBACK
BLOCK 1
30% - 40%=(10%)
BLOCK 2
70% - 60% = 10%
PRIMARY SURPLUS
(12) MBBLS
PRIMARYSHORTFALL
12 MBBLS

Redetermination
Adjustments to Unit Costs
• Unitisation Agreements normally make distinctions between
adjustments required for capital expenditure and operating
expenditure as these are treated very differently.
Capital Expenditure
• Any revision to equity shares requires adjustments to the
investment the participants have sunk into the venture. This
must be done for both the capital invested and the fixed assets
created.
• Therefore, on the agreed implementation date of the re-
determination, an adjustment to the cash advanced to date will
be done. This will be relevant to the amount incurred creating
fixed assets and pre-operating expenditure. It is therefore
necessary to create a separate analysis account of pre-
production expenditures.

Redetermination
• Therefore, on the agreed implantation date of the re-
determination, an adjustment to the cash advanced to date will
be done. This will be relevant to the amount incurred creating
fixed assets and pre-operating expenditure. It is therefore
necessary to create a separate analysis account of pre-
production expenditures.
• The Operator will calculate the redistribution required, based on
the venture’s historic records. This is illustrated by the example
below:

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