new_zealand_block_offer_2015_report

New Zealand Bid Round Analysis April 2015
mb
New Zealand 2015
Bid Round Analysis
Palantir Economic Analysis
June 2015
www.palantirsolutions.com
info@palantirsolutions.com

Executive Summary
This report was conducted to evaluate New Zealand‘s fiscal regime
attractiveness and resource prospectivity. Four different analyses
were conducted for this evaluation. They are broken down into
three chapters:
 Standard Regime Ranking – This chapter focuses on creating
a baseline regime comparison. The goal of this analysis was
to understand where the New Zealand fiscal regime ranked
both on a global scale, and against a subset of peers.
 Country Level Resource Prospectivity – This analyses builds
on the baseline comparison by replacing the generic data
with average regional analogues from the Palantir
Exploration Analogue Dataset. The data for this analysis
provides a better approximation for prospectivity by using
more representative resource, cost and price estimates for
the regions.
 Threshold Volumes – In this chapter we use a recent find as
an analogue for an “unknown discovery”. This analogue
was tested against the peer subset of regimes to determine
what the threshold field size would need to be to receive a
15% return in the different regions.
Fiscal Regime
The key findings in this report indicate that New Zealand has a very
favourable fiscal regime. At 45%, New Zealand has some of the
lowest rates of government take in the Palantir Regime Library.
Government Take Ranking – Palantir Regime Library
When compared against peer jurisdictions, the New Zealand regime
also placed fairly. We found that in this peer group, government
take had a strong correlation with the amount existing production
within that region. The New Zealand fiscal regime had slightly higher
rates of government take than both the Ireland pre-2015 and 2015
Atlantic margin regimes. This coincides with higher levels of
production in New Zealand. In comparison to Newfoundland and
Nova Scotia, New Zealand had significantly lower rates of
government take.

Government Take – Peer Group
Country Level Prospectivity
When prospectivity is included in the analysis, New Zealand and
Ireland’s fiscal terms remain competitive with the lower average
discovery size. Nova Scotia seems to be the only regime in peer
group with fiscal terms that are significantly less competitive when
considering the relative resource prospectivity of the province.
NPV/boe
Threshold Field Size
Using the Falkland Islands’ Sea Lion project as an analogue for an
“unknown discovery”, we see that it would require a resource size
of around 85 mmbbl to receive a 15% return in New Zealand1
.
Looking at the volumes, we see that New Zealand requires a slightly
lower threshold field size than the Falkland Islands, and a
significantly smaller discovery than would be needed in the
Canadian provinces.
Overall, based on this analogue, it was determined that smaller
fields have a greater chance of being commercially viable in Ireland
and New Zealand than in Newfoundland and Nova Scotia. These
jurisdictions require a larger threshold volume to earn the same
return as one would expect in New Zealand.
1
Analysis was conducted using $60 USD/bbl. l

Threshold Field Size- Sea Lion Analogue

Table of Contents
Introduction ....................................................................................... 3
New Zealand ...................................................................................... 4
Basins Included in Block Offer 2015............................................... 4
Taranaki Basin............................................................................ 4
Northland-Reinga Basin ............................................................. 5
West Coast Basin........................................................................ 5
Great-South Canterbury Basin................................................... 5
Pegasus East Coast Basin ........................................................... 5
Business & Risk Environment......................................................... 6
Regional & Block Activity History................................................... 6
Producing Fields in New Zealand............................................... 6
Recent Bid Rounds ..................................................................... 6
Comparison Jurisdictions ................................................................... 7
Peer Group Selection ..................................................................... 7
Newfoundland ............................................................................... 7
Regional & Block Activity History............................................... 7
Ireland............................................................................................ 8
Nova Scotia .................................................................................... 8
Fiscal Regimes.............................................................................. 10
New Zealand............................................................................. 10
Canada...................................................................................... 10
Ireland ...................................................................................... 11
Fiscal Regime Summary............................................................ 12
Chapter 1: Standard Regime Ranking.............................................. 13
Detailed comparison of New Zealand’s Peer Group.................... 14
Government Take......................................................................... 15
Price Changes............................................................................... 15
Conclusions .................................................................................. 15
Chapter 2: Regime Ranking with Country Level Prospectivity........ 17
Production.................................................................................... 17
Costs............................................................................................. 17
Economic Results ......................................................................... 18
Conclusions .................................................................................. 19
Chapter 3 Quantification of Undiscovered Resource Potential....... 20
Comparison of Known Discoveries............................................... 20
Threshold Field Size –Sea Lion Analogue..................................... 21
Appendix A Bid Round Results......................................................... 23
New Zealand................................................................................. 23
Results from Block Offer 2014 ................................................. 23
Newfoundland.............................................................................. 23
Ireland .......................................................................................... 24
Results from Irelands 2011 Bid Round..................................... 24
Nova Scotia................................................................................... 24

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Appendix B Fiscal Regimes............................................................... 25
New Zealand ................................................................................ 25
Ireland.......................................................................................... 29
Newfoundland ............................................................................. 31
Nova Scotia .................................................................................. 36
Appendix C Sea Lion Analogue Summary Reports Using New Zealand
Fiscal Terms...................................................................................... 40
25 MM BBL................................................................................... 40
50 MM BBL................................................................................... 41
75 MM BBL................................................................................... 42
100 MM BBL................................................................................. 43
125 MM BBL................................................................................. 44
160 MM BBL................................................................................. 45

3
This analysis has been prepared by Palantir Solutions with the
cooperation of New Zealand Petroleum and Minerals (NZP&M). The
report is intended to provide a comparison of New Zealand amongst
its peer group with respect to fiscal regime attractiveness and
resource prospectivity.
The analysis was generated using a combination of information
provided by NZP&M’s 2015 New Zealand Petroleum Exploration
Data Pack and Palantir’s experience, knowledge, and proprietary
data. Palantir makes no warranty on the accuracy of the information
provided. We do not accept any liability for any party’s reliance
upon this information.
Introduction
Palantir is a software and consulting company with a deep
understanding of global fiscal systems. Palantir has a particular
interest in exploration bid rounds such as the upcoming 2015 New
Zealand block offer. A decision was made to undertake a study of
how the New Zealand fiscal regime compares to the entire set of
fiscal regimes in the Palantir Regime Library (PRL). After interviews
with New Zealand Petroleum and Minerals it was decided to create
a focused comparison of the New Zealand fiscal terms with a select
group of countries that formed a “peer group”. This peer group
consists primarily of offshore basins that are either frontier or were
very recently frontier. The peer group consists of, but is not limited
to: Newfoundland, Ireland and Nova Scotia.
We weigh the risk and reward potential of exploration and
development in the New Zealand oil and gas sector as it compares
to this peer group. The study analyses the attractiveness of New
Zealand’s recent 2015 Block Offer on a direct comparison basis
using generic test cases. It also compares the fiscal regimes with
consideration for prospectivity by taking into account the size of the
average resource discovery likely for each region.
Palantir’s proprietary economic software, PalantirCASH, was used to
complete the study. Data sources include Palantir’s Exploration
Analogue Database and the Palantir Regime Library.
The report begins with an overview of each jurisdiction. This section
will look at regional and block history, discuss recent bid rounds,
and outline any recent regime changes. Following the regional
information, there is an outline for each fiscal regime. Here we
discuss specific components such as royalties, taxes and deductions
for each region.
Subsequent to the qualitative review, our analysis is broken down
into chapters:
Chapter 1: Standard Regime Ranking – This chapter focuses on
creating a baseline regime comparison using the Palantir Regime
Library’s standardized dataset. This dataset is frequently used to
evaluate and compare regimes in the Palantir Regime Library. The
goal of this analysis is to create an equivalent comparison of the
regimes in order to better understand the trade-offs to one another
- all else being equal.
Chapter 2: Regime Ranking with Country Level Resource
Prospectivity – This chapter builds on the analysis in Chapter 1 by
replacing the generic data with regional analogues from the Palantir
Analogue Dataset. The data used for this analysis is based on
regional data and provides more representative resource, cost and
price estimates.
Chapter 3: Existing Project Analysis with Threshold Volumes – This
looks at how the economics for an existing project differs between
regimes. We will analyse how the recent Falkland Islands Sea Lion

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discovery would fair in other jurisdictions. For this chapter, we will
be looking to determine what the threshold field size would need to
be to receive a 15% return in each jurisdiction for a project in the
style of the Premier Oil’s proposed Sea Lion development.
New Zealand
On April 14th
, 2015 New Zealand’s Energy and Resources Minister,
Simon Bridges, formally opened the Block Offer 2015 for petroleum
exploration permits. The total tender spans an area of 429,298 km²
and includes coverage in the following basins: West Coast, Taranaki,
Northland, Reinga, New Caledonia, Pegasus, East Coast, Great-
South, and Canterbury.
New Zealand’s licensing process grants large exploration permits on
a work commitment basis for a period of 10-15 years dependant on
location. The government of New Zealand has annual Block Offers
allowing for competitive bidding. Successful bids ensure exclusive
rights for exploration and development within the permit while
fulfilling the work commitments agreed upon in the bidding process:
sampling, geological studies, seismic analysis, and drilling. The
government's goal is to ensure New Zealand has a favourable
system that manages petroleum exploration and production within
underexplored basins while balancing the economic viability, safety
and environmental concerns.
Basins Included in Block Offer 2015 Taranaki Basin
 15TAR-R2: onshore Taranaki (1,039 square kilometres)
 15TAR-R1: offshore Taranaki (53,253 square kilometres)
All producing fields in New Zealand are located in the Taranaki
basin. The offshore regions of Taranaki have proven to contain
hydrocarbons with fields such as Kupe, Maari, Maui, and Pohokura
being some of the prominent producing fields in New Zealand.
Exploration continues in the Taranaki Basin where TAG recently
acquired PEP 57063 to pursue an area with significant elevated gas
and oil shows from the historical Pukearuhe-1 well. TAG was also
awarded PEP 57065 allowing them to extend their Sidewinder
project to a field containing their SuppleJack-1 oil and gas discovery.

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Northland-Reinga Basin
 15NRN-R1: offshore Northland-Reinga (186,181 square
kilometres)
The Northland-Reinga Basin is almost entirely unexplored. Six wells
have been drilled since 1969: Waimamaku-2, Koromako-1,
Tarapunga-1, and Karewa-1. Todd Petroleum is pursuing Karewa
and reviewing options to begin commercial production. Todd
estimates the formation to contain 145-178 bcf of gas with nearby
areas potentially yielding another 130 bcf. In 2013, Statoil acquired
a 10,000 km² block about 100 km offshore where they will collect
and analyze data. Seismic analysis has been found to be comparable
with that of the Taranaki basin.
West Coast Basin
 15WEC-R1: onshore West Coast (2,007 square kilometres)
 15WEC-R2: onshore West Coast (1,046 square kilometres)
The West Coast basin is under-explored with high potential.
Extensive oil seeps have been identified since the 1900s indicating
that hydrocarbons are present. There has recently been increased
interest in this basin with two exploration permits being granted in
the previous annual block offer.
Great-South Canterbury Basin
 15GSC-R1: offshore Great-South Canterbury (141,757
square kilometres)
The Great-South Canterbury covers an area of approximately
200,000 km2
and has had 13 exploration wells drilled since 1985.
The basin has been explored with encouraging results of
hydrocarbon discoveries most notably with Galleon-1 and Kawau-
1A.
Drilled in 1985 by Shell BP Todd, the Galleon-1 found hydrocarbons
but the recoverable reserves were considered too small for further
development. Kawau-1A was drilled by Hunt International
Petroleum in 1977 and the probable reserves are estimated to be
217 bcf of gas plus condensate. Geological studies forecast
prospective areas to contain 4,675 mmbbl of recoverable reserves
(P50), and that this basin has the potential to contain 10x the gas
held in Taranaki’s Maui field (3.8 tcf).
Shell is planning to drill in the Great South Basin in 2016 under PEP
50119 with the hope that this basin will be “the next Taranaki.”
They are expecting to find natural gas with a 30% success rate which
may result in floating liquefied natural gas development.
Pegasus East Coast Basin
 15PEG-R1: offshore Pegasus/East Coast (44,015 square
kilometres)
Over 300 oil and gas seeps have been identified along the east coast
of the North Island of New Zealand indicating the potential of
commercial reserves. Approximately 40 wells have been drilled
beginning in the 1950’s with approximately 70% showing oil and/or
gas. Most notable is the Titihaoa-1 well drilled offshore of the East
Coast basin in 1994 by Amoco NZ Exploration Company. Gas was
encountered but was considered non-commercial. It is estimated
that the structure may contain up to 400 bcf of gas.
This basin has received significant investments by both OMV and
Statoil and also saw the country entry of Chevron in 2014. The first
exploration permits for Pegasus were granted in 2012 where
Anadarko NZ acquired PEP 54858 and PEP 54861. In 2014 Anadarko
began seismic surveying of the Pegasus region within the blocks
granted from these permits. They are aiming to find about 150
mmbbl of oil.

6
Business & Risk Environment
New Zealand provides favourable conditions for oil and gas
companies to conduct business. Exploration permits are granted
through annual petroleum block offers where companies can bid on
their prospective areas.
The government of New Zealand has a high standing global
reputation with Transparency.org ranking New Zealand as the 2nd
out of 175 countries on perception of corruption.
Euromoney places New Zealand in the top 15 countries with lowest
political risk for investment. O&G investors would be able to enjoy a
stable government platform while conducting business in New
Zealand.
Regional & Block Activity History
Producing Fields in New Zealand
Field
First
Production
Date
P90 EUR/Remaining Oil and
Condensate Reserves
(mmbbl)
P90 EUR/Remaining
Natural Gas and LPG
Reserves (bcf)
Maari 2009 34/12 NA
Pohokura 2006 59/29 1240/805
Maui 1979 162/4 3680/119
Kupe 2009 15/8 266/185
Mangahewa 1997 6/4 223/144
Turangi 2005 4/2 107/63
Tui 2007 38/2 NA
Cheal 2003 4/2 3/1
Ngatoro 1983 10/1 37/7
McKee 1980 48/1 163/32
Kapuni 1969 66/1 1324/53
Puka 2013 1/1 0.3/0
Kowhai 2009 1/0 29/8
Onaero 2011 1/1 4/3
TAWN 1988 27/1 184/3
Copper Moki 2011 1/0.2 1/1
Surrey 2003 0.2/0.1 0.4/0
Rimu 1999 0.6/0 2/0
Sidewinder 2011 NA 5/1
Recent Bid Rounds
On December 9th 2014 the government of New Zealand announced
the petroleum exploration permits from the 2014 Block Offer. The
total committed exploration investment exceeds 84 mm USD. A
complete list of the most recent bid rounds can be found in
Appendix A.

7
Comparison Jurisdictions
Peer Group Selection
In order to evaluate New Zealand’s fiscal regime and prospectivity,
it was important to contrast their recent development activity,
business environment and geo-political climate as it relates to other
jurisdictions with recent block offers. The NZP&M chose three
hydrocarbon producing regimes to compare New Zealand to:
Ireland, Newfoundland, and Nova Scotia.
Although this is not a comprehensive list of peers, it provides a
suitable subset of regions for comparison for a number of reasons:
The jurisdictions chosen for this peer group all have similar
geopolitical climates with recent or ongoing bid rounds. Aside from
Newfoundland, the regions are widely considered frontier areas
with similar industry maturities as New Zealand. Every regime in
the peer group uses a royalty tax, concessionary fiscal regime. Given
these similarities, the bulk of analysis focuses on New Zealand as it
compares to this peer group.
Newfoundland
In August 2014 the Canada-
Newfoundland and Labrador
Offshore Petroleum Board (“C-
NLOPB”) issued a call for bids in
six exploration plots; one in the
Jeanne d’Arc Basin, one in the
Flemish Pass Basin and four in
the Carson Basin. Bidding
closed on December 12th
and
resulted in a 559 mm CAD
spending commitment in the
Flemish Pass Basin. The bid for NL013-01-01 was the largest single
bid in the history of the province.
License Area NL013-01-01 in the Flemish Pass Basin (FPB) is next
door to the 229,000 bbl/d Jeanne d’Arc Basin. The area of the
licence is 266,139 hectares. Currently there is no production in the
FPB basin but exploratory wells have shown excellent results. Leases
to the North East of NL013-01-01 have produced EUR discoveries of
100-200 mmbbl and 300-600 mmbbl in the Mizzen and Bay du Nord
fields respectively. Despite promising discoveries the basin is still in
a very early stage of exploration. Nine new licences are expected to
come up for bid in 2015 that surround NL013 -01-10 and the Jeanne
d’Arc Basin.
The first exploratory leases for the Flemish Pass Basin were issued in
the 1970’s. The results obtained are encouraging as they showed
similarities to the currently producing Hibernia project in the Jeanne
d’Arc Basin. In the mid 80’s three more exploratory wells were
drilled that encountered similar formations to Hibernia.
In 1997, Petro-Canada and Norsk Hydro drilled an exploratory well
after 10 years of inactivity. Results from this well indicated a light oil
play was possible. Since 2008 Statoil has taken over many of the
exploratory leases in the area. The Mizzen O-16 discovery well was
granted Special Discovery Lease status after 3,774 bbl/d was
produced. Further delineation revealed a possible 100 – 200 mmbbl
in recoverable reserves. Statoil drilled two more exploration wells
in 2013 in the northern part of the basin in the Bay du Nord. The
exploration wells paid off and they announced that Bay du Nord was
a giant field with reserves of 300-600 mmbbl of oil.

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Recent Bid Rounds
In August 2014 the C-NLOPD issued a call for bids. Six licenses were
up for grabs and 3 received bids above the minimum 10 mm CAD.
Currently, only the Jeanne d’Arc Basin is producing. The Carson
Basin is the newest and least explored of the three but early
exploration has been promising. A complete list of the most recent
bid rounds can be found in Appendix A.
Ireland
Historically there have been a few producing gas fields in Ireland:
Kinsale Head, Ballycotton, and Seven Heads. Kinsale Head was
discovered off the southern coast of Ireland at a water depth of
100m in the 1970’s by Marathon Oil. It was deemed as the first
natural gas discovery in Ireland. As a result, Bord Gáis was
established in 1976 by the State under the Gas Act and would be
responsible for the supply, transmission, and distribution of this
natural gas to help meet Ireland’s gas needs. Ballycotton and Seven
Heads are smaller fields that were discovered in the surrounding
area and were tied back to the production platforms constructed for
Kinsale Head. Gas from all of these offshore fields is combined,
compressed, and transferred to Bord Gáis to distribute and covers
approximately 15% of Ireland’s natural gas demand.
More recent discoveries include Barryroe and Corrib. Barryroe is an
oil and gas field off the southern coast of Ireland discovered by Esso
in 1973. It is currently owned by Providence with an 80% stake.
Providence estimates the field contains 1000-1600 mmbbl of oil in
place. The field is not currently producing and Providence Resources
is looking for a partner to exploit the discovery.
The Corrib gas field which was discovered by Enterprise Oil in 1996
off the northwest coast of Ireland. Reserves are estimated to be
about 1 tcf of natural gas. The project is now operated by Shell E&P
Ireland and has encountered multiple delays due to local residents
objecting the development plan. However, production is expected
to commence in 2015.
Exploration drilling began in 1970 around the same time exploration
began in the North Sea. Since that time the UK and Norway have
had much more success drilling commercially viable wells. Gas
production began in 1978 at Kinsale after 16 exploration and
appraisal wells were drilled. 73 exploration wells were drilled
between 1975 and 1985 with no further commercial discoveries
made. There is currently little production in Ireland but the
discovery of Corrib has provided evidence for the potential of the
unexplored deepwater of Ireland.
Recent Bid Rounds
In June 2014 Ireland announced the 2015 Atlantic Margin licensing
round that included 995 full blocks and 93 partial blocks in an area
of approximately 256,700 km2
. Applications for licensing are to be
accepted between August and September 2015 when the bidding
closes. The government hopes to build on the success of the 2011
Atlantic Margin licensing round.
The 2011 Atlantic Margin licensing round awarded 13 new offshore
licensing options to 12 different companies. The companies involved
in the bid round included 7 new entrants to Ireland with the other 5
being active companies in offshore Ireland exploration. An area of
over 15,000 km2
was included in the 2011 bid round. A complete list
of the most recent bid rounds can be found in Appendix A.
Nova Scotia
Since 2007, Nova Scotia has offered eight calls for bids for
exploration licenses. No bids were received in 2014, 2013, and 2010
while the remaining five rounds generated 2,418 mm CAD in work
commitments.

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Currently the Nova Scotia government is forecasting additional call
for bids in 2015, 2016 and 2017. These will likely be in the same
format and under the same terms as previous offerings.
The market for Nova Scotia's produced gas is unique as it is
influenced by the regional supply and demand fundamentals of New
Brunswick and parts of the North Eastern United States. Nova
Scotia's gas is priced at Dracut and Algonquin natural gas trading
hubs where prices have traditionally been more volatile and higher
in the winter than the rest of the continent.
207 offshore wells have been drilled since 1967. This activity has
resulted in 24 significant discoveries and eight commercial
discoveries.
Nova Scotia has been producing hydrocarbons since 1992 with
Canada's first offshore project, Cahasset-Panuke. This project
operated for seven years and produced 44.5 mmbbl of oil over its
lifetime.
There are currently two active offshore gas projects: Deep Panuke
Offshore Gas Project and the Sable Offshore Energy Project. These
projects are operated by Encana and ExxonMobil Canada Ltd.
respectively. In 2014, gas production in Nova Scotia averaged 10.6
bcf/month and these volumes are shipped onshore via undersea
pipelines.
Recent Bid Rounds
The last successful bids in Nova Scotia were by BP and Shell in 2012.
BP committed to spending 1050 mm CAD towards exploration while
the bid saw Shell committing to 31.8 mm CAD.
They have both begun exploration with BP conducting a 3D seismic
survey over an area of approximately 7,752 km² and Shell
conducting seabed surveys for bathymetry data. A complete list of
the most recent bid rounds can be found in Appendix A.

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Fiscal Regimes
New Zealand
The New Zealand fiscal regime is based upon a relatively straight
forward royalty/tax system on commercial oil and a levy on natural
gas. The regime consists of royalties from 5% to 20%, a corporate
income tax rate of 28%. Oil and gas capital development
expenditures are eligible for accelerated straight-line depreciation
over seven years and exploration expenses can be written off
immediately. New Zealand also allows for the indefinite carry
forward of losses.
New Zealand does not apply ring fencing when calculating a
company’s corporate tax liability for petroleum expenditures, this
allows companies to offset their unsuccessful exploration costs
against taxable income from other fields.
Under an exploration permit royalties are calculated by an Ad
Valorem Royalty (AVR) of 5% on production. Under a mining permit,
after a company has net revenue in a reporting period of over NZD
1mm, royalties are paid on the maximum of 5% AVR or a 20%
accounting profits royalty on production.
Until the end of the 2014, income from offshore exploratory and
development drilling, and seismic and survey work was exempt
from New Zealand income tax if it was completed by a foreign
corporation. There are currently proposals to extend this incentive
until the end of 2019.
Canada
In Canada, oil and gas producers are subject to federal and
provincial corporate income taxes, while royalty payments must be
made to the mineral rights holder, which in most cases are the
provincial governments.
All corporations in Canada are taxed at rate of 25% but are eligible
for a 10% abatement when income is earned in a Canadian province
or territory resulting in an effective corporate income tax rate of
15%.
For income tax purposes, corporations are eligible to deduct capital
expenditures at different rates depending on the legislated class of
the expense. Capital exploration costs are eligible for a 100%
deduction in the year they were incurred while most capital
development expenditures are written off using the declining
balance method at a rate of 25%.
Unlike many jurisdictions, Canada allows corporations to claim
depletion allowance on production which helps subsidize further
exploration globally.
Projects in Canada are ring fenced disallowing producers to offset
the proceeds of one project by the losses of another.
Until the end of 2015 Atlantic Provinces, such as Newfoundland and
Nova Scotia, are eligible for investment tax credits reducing their
federal income tax payable the cost of buildings and equipment.
Before the approval or a development or any activity takes place
offshore Nova Scotia or Newfoundland, Canadian legislations
requires that an operator submit a Canada-Nova Scotia Benefits
Plan or Canada-Newfoundland Benefits Plan that outlines the
benefits provided to Canadian citizens and companies.
Newfoundland
Newfoundland has a generic offshore royalty regime that is
supplemented by specific agreements negotiated with operators on
a project by project basis. The generic regime consists of a minimum
royalty of between 1% and 9% of gross revenue, and a post pay-out
royalty of 10% to 30% on net revenue.

11
Corporations operating in Newfoundland are subject to a provincial
corporate income tax rate of 14% and use the same taxable income
base that is used for calculating federal corporate income tax.
Nova Scotia
In contrast to Newfoundland, where the legislation acts as a
framework for the fiscal terms, Nova Scotia’s fiscal regime’s terms
are legislated. Nova Scotia’s offshore regime is based on a royalty
structure based on project pay-out. Before payback, projects are
subject to a 2% or 5% royalty on gross revenue and after payback a
20% or 35% royalty on net revenue based on certain pay-out tiers.
The regime also reacts to project size and risk – different rates or
r-factors depending on whether the energy minister considers the
project to be small or high risk.
Corporations operating in Nova Scotia are subject to a provincial
corporate income tax rate of 14% and use the same taxable income
base that is used for calculating federal corporate income tax.
Ireland
Ireland updated their oil and gas fiscal regime for prospective
production in June of 2014. Their simple fiscal regime relies on a
Petroleum Production Tax (PPT) and corporate income tax. Income
from petroleum activities in Ireland is taxed at a rate of 25% in
contrast to the standard rate for corporations of 12.5%.
As an incentive, both exploration and development capital
expenditures are eligible for immediate deduction from taxable
income in the year which they are incurred. These capital
expenditures can be carried forward indefinitely. Additionally,
abandonment costs can be carried back to offset the income of the
previous three years. Ireland enforces ring-fencing and disallows the
offsetting of losses from one project to the profits of another.
The PPT is based on before tax income with the rate being
calculated on a sliding r-factor scale. The PPT is not charged until
the r-factor reaches 1.5 but the updated regime adds a minimum
PPT of 5% which acts as an effective royalty. The royalty rate
increases linearly from 10% to 40% as the r-factor moves between
1.5 and 4.5.
Comprehensive summaries of the above royalty regimes and
calculation of royalties and taxes used in financial models can be
found in Appendix B

12
Fiscal Regime Summary
Comprehensive guides for each regime can be found in Appendix B.
Fiscal Regime New Zealand Newfoundland Nova Scotia Ireland
Type Concessionary Royalty/Tax
Concessionary Royalty/Tax
(with cost recovery)
(with Cost Recovery)
Royalty
Either Ad Valorem Royalty
(AVR) or hybrid of AVR and
Accounting Profits Royalty
(APR)
1 - 9% of gross revenue or
10-30% of net revenue
Offshore: 2 - 5% of Gross
Revenue or 20 - 35% of Net
Revenue
Onshore: 5 - 10% of Gross
Revenue
Only payable on older
developments (phased out
for new developments)
Bonuses None None None None
Local Taxes None None None None
Fees None None None None
Special Taxes None None None None
Corporate Tax –
Provincial
None 14% of taxable income 16% of taxable income
Petroleum Production Tax
(PPT) of up to 40% based on
R-factor
Corporate Tax –
Federal
28% 15% of taxable income 15% of taxable income
Varies between 12.5% and
25%
State Participation None None None None

13
Chapter 1: Standard Regime Ranking
This chapter focuses on establishing a baseline comparison using
the Palantir Regime Library (PRL) and 6 different test projects. The
test projects consist of a range of field sizes and include oil projects
and gas projects.
The Palantir Regime Library is a collection of highly researched and
well maintained fiscal regime models that are built for use with
PalantirCASH™, Palantir’s global economic software. By running the
test projects through the PRL we are able to compare every
petroleum fiscal regime for items such as: Government Take,
Reserves or Entitlement Volumes, and Contractor Return on
Investment. This allows us to compare regimes by maintaining
constant inputs for price, production, capital and operating
expenditures.
This straight forward comparison allows us to rank fiscal regimes on
one or more properties as shown in Visualization 1.1. In this figure,
we can see that New Zealand ranks very favourably against the
majority of fiscal regimes around the world.
This comparison method tests the mechanics of the regimes on a
like for like basis. It is effectively a comparison of the mechanics of
the regimes and how they rank against each other on a variety of
items.
We use the full range of test projects in order to undertake a more
in depth analysis. By varying the resource size and commodity
prices we are also able to determine how progressive or regressive
each regime is. In doing so, we are able to identify regimes that are
designed to favour oil over gas, high prices over lower prices, or
smaller discoveries over larger ones.
Visualization 1.1 New Zealand Compared against Global Fiscal
Regimes
Government take is the calculated revenues received by the
government including bonuses, fees, royalties, and taxes. Here it is
expressed as a percentage of after tax cash flow. As some regimes
calculate royalties on a gross revenue basis, we will see some
regimes in excess of 100%. Based on our initial global ranking, New
Zealand has one of the more favourable fiscal regimes with 45%
government take2
.
2
The initial run was calculated using $90/Bbl and $5 MM Btu prices. They prices were chosen to ensure all
generic fields were economic.

14
Detailed comparison of New Zealand’s Peer Group
The New Zealand fiscal regime was run through a complete set of
test cases along with the following regimes:
 Ireland Atlantic RT
 Ireland pre-2015
 Canada (Newfoundland)
 Canada (Nova Scotia)
The test data is summarized in Table 1.1. These projects are
analogues for typical offshore projects in medium to deep water
depths.
Table 1.1: Test Project Summary
The data consists of multiple field sizes and primary products:
Field Size Oil mmbbl Gas bcf
Small 31 168.
Medium 93 506
Large 446 2,365
Price Oil USD/bbl Gas USD/mmbtu
Low 49 2
Base 70 4
High 87 5
The generic dataset uses two primary products across three field
sizes and three prices scenarios. These settings were then applied to
each regime to create a total of 18 different scenarios for Nova
Scotia, New Zealand and Ireland and 9 different scenarios for
Newfoundland3
.
It is important to note that the costs and prices used in these
scenarios are generic, and might not be indicative of actual amounts
within these regions. Prices for example, are based on the North
American price forecast. More representative samples are explored
in Chapter 2 of this analysis.
Visualization 1.2 Average Daily Production BOE
Out of the peer group, Newfoundland is currently the largest
producer4
. Although not shown in Visualization 1.2, nearly all of
Newfoundland’s production is oil. All of the other jurisdiction have
production that is more highly weighted to gas and NGL’s.
3
Currently the PRL Newfoundland regime only supports oil production
4
Sources: Canadian Association of Petroleum Producers , US Energy Information Administration

15
Government Take
Visualization 1.3 shows the average government take across all oil
field sizes at the three different price points for each regime5
.
Visualization 1.3 Average Government Take
The results in this analysis indicate a positive correlation of
government take and production levels. Although Newfoundland
has the highest production amongst the group, it also has some of
the highest levels of government take. Conversely, Ireland has had
very little exploration success and currently has very little
production, but it has the lowest levels of government take in the
group. Looking at the difference between pre-2015 and Atlantic RT
we see that Ireland has moved to a regime with higher levels of
government take with the release of its 2015 Atlantic regime.
Price Changes
Visualization 1.4 shows the difference in contractor take for a 25%
price increase and decrease. For nearly all of the regimes, the
5
Gas fields were omitted as many of the fields were uneconomic using the North America price forecast.
The regimes in the peer group do not make a distinction between oil and gas revenues, so the omission
should have no impact on the results.
percent change is greater for the price increase than the decrease.
These results support our government take analysis and indicate
that with the exception of Newfoundland, each regions current
fiscal regime has some regressive elements.
Visualization 1.4 Difference in Contractor Take for 25% Price Swings
Although the word seems to have a negative connotation,
regressive regimes offer different trade-offs than their progressive
counter parts. Regressive regimes provide contractors a larger share
of the economic upside at higher prices, but expose them to more
risk in lower price environments. For governments, regressive
regimes provide stable income levels in volatile conditions, but this
comes at the expense of capturing a greater portion of project
profits in high price environments.
Conclusions
Judging by % of government take and current production, New
Zealand’s fiscal terms are in line with its peer group. Furthermore,
the New Zealand fiscal regime provides incentive to exploration

16
companies anticipating higher prices for the life of a project. The
pay-out from a large discovery in a higher price environment could
be considerably higher than others in the peer group given the
structure of the regime.

17
Chapter 2: Regime Ranking with Country Level
Prospectivity
This chapter builds on Chapter 1 by replacing the generic data with
country analogues from the Palantir Analogue Dataset. These
country analogues represent the median discovery field for their
respective country6
. The analogue is typical in terms of resource
size, development concept and water depth. The goal from this
chapter is to compare fiscal regimes with more representative
resource, cost, and price estimates for the regions. Most
importantly, the intention was to determine if the fiscal regimes
government take was correlated positively or negatively to the
relative resource prospectivity and commodity prices in each
country. The intention was to identify the regime with the best
balance between exploration potential and fiscal regime fairness.
Pricing was updated to be more indicative of the values realized for
each region. The Canadian provinces were calculated using the
North American gas prices, while New Zealand and Ireland used
European pricing7
.
Table 2.1: Oil and Gas Prices
Price Oil USD/bbl Gas USD/mmbtu
Region All Projects N. America Europe
Low 49 2.8 4.5
Base 70 4.0 6.5
High 88 5.0 8.1
6
Regional analogues were chosen for Newfoundland and Nova Scotia.
7
New Zealand natural gas prices were deemed similar to those
experienced in Ireland
Production
Using the Palantir Analogue Dataset, prospective resource sizes
were chosen for each region. Visualization 2.1 shows the disparity of
mean BOE volumes between the regions being analysed.
Visualization 2.1 - Total BOE Volumes
Newfoundland has the largest resource base – more than doubling
the next region. New Zealand has the second largest resource base,
followed closely by Ireland and Nova Scotia respectively. Overall
New Zealand, Ireland and Nova Scotia have similar outlooks in the
Palantir Analogue Dataset8
.
Costs
The cost estimates for the regions were derived using a combination
of research and the Palantir Exploration Analogue Dataset. The
design concepts were a subjective choice based on the findings of
this process. The mean resource amounts were a significant factor
in the overall project cost.
8
It is anticipated that this ranking changes as more data is collected from
these frontier basins.

18
Table 2.2: Project Concept Development Costs
Region Design Cost Billion USD
Ireland
Tension Leg
Platform
1.1
New Zealand Semi-Submersible 1.7
Newfoundland Platform 1.7
Nova Scotia Platform 1.0
For this analysis, the exploration was deemed to be successful for all
cases. Therefore, the results for this chapter are based on an un-
risked deterministic success case for each region.
Economic Results
NPV/BOE
Looking at Visualization 2.2, we see that the ordering is similar to
government take. The Nova Scotia project is uneconomic in the low
and base price scenarios, and marginal in the high price
environment.
Visualization 2.2 NPV/BOE for Different Price Scenarios
This is a result of having some of the toughest fiscal terms coupled
with the lowest resource estimates. The fact that government take
in Nova Scotia increases as price decreases exacerbates this issue.
In New Zealand, we see the NPV/BOE beginning to converge with
Ireland Atlantic in the high price scenario. The regressive elements
in New Zealand’s regime enable contractors to take a larger portion
of the profits in a high price environment, indicating that these two
would crossover at prices in excess of our high scenario.
The difference between the two Irish projects can be directly
attributed to government take. This difference is significant in the
base price environment as Ireland would have had a higher
NPV/BOE despite having lower volumes with its old regime.
P/I Ratio
Three main factors play into the differences between Nova Scotia,
New Zealand and Ireland: price, cost and fiscal terms. New Zealand
fairs well considering the analogue used has a high cost relative to
the peer group. Ireland maintains a slight edge due to the smaller
government take, and a less costly design concept. Despite having
the lowest concept design, the price differential in Nova Scotia is
too significant, making these projects less competitive with the peer
group.

19
Visualization 2.3 P/I Ratios for Different Price Scenarios
Conclusions
When prospectivity is included in the analysis, it becomes apparent
that the seemingly harsher fiscal terms for Canada’s Newfoundland
regime become much more competitive. New Zealand and Ireland’s
fiscal terms remain competitive with the lower average discovery
size. Nova Scotia seems to be the only regime in peer group that
has fiscal terms that are significantly less competitive when
considering the relative resource prospectivity of the province.

20
Chapter 3: Quantification of Undiscovered
Resource Potential
Chapter 2 highlighted the impact on the perceived attractiveness of
the fiscal terms when compared against median discoveries.
However, we can also look at the how the fiscal regimes would react
to “unknown discoveries”. This implies that unexplored blocks have
the potential to find new fields that are larger than the average
“known discovery” by one or more standard deviations. To do this
we will attempt to identify what an “unknown discovery” might look
like in New Zealand as compared to the peer group.
The selection of an “unknown discovery” must be within a
reasonable expected discovery size for New Zealand. Table 3.1
describes our assumptions surrounding discovery sizes for New
Zealand. The estimates below are based off of a combination of
research and the Palantir Exploration Analogue Dataset. Barrels of
oil equivalent were used as the sample size for oil discoveries is
quite small.
Table 3.1 – New Zealand Discoveries:
Average Discovery Size mmboe 114
Standard Deviation mmboe 52
Using these metrics, we can select a representative discovery to
determine the minimum field size needed for a commercial success
in each country. In order to select this discovery, we have widened
our peer group to include technical analogues from the West of
Shetlands and the Falkland Islands. Both of these areas have similar
frontier or near frontier characteristics as the other countries
considered thus far.
Comparison of Known Discoveries
For this part of the study, Palantir has identified the following fields
as representative of potential oil fields “yet to be discovered”:
 Foinaven – West of Shetlands, UK – 700 mmbbl
 Hibernia – Newfoundland, Canada – 1200 mmbbl
 White Rose - Newfoundland, Canada – 400 mmbbl
 Maari – South Taranaki, New Zealand – 100 mmbbl
 Sea Lion – Falklands – 160 mmbbl
The representative projects were run through their respective fiscal
regimes and the following key performance indicators plotted: Net
Present Value at a discount rate of 15%, total capital investment,
and probability of discovery size. The resulting graph is shown in
Visualization 3.1
Visualization 3.1 Comparison of Potential Oil Fields
The size of the bubbles indicates the probability of discovery. The
larger the bubble, the higher the probability. Given our sample

21
mean and standard deviation, there is a low probability of finding
discoveries like Foinaven, Hibernia and White Rose.
Maari is an attractive choice, but was not selected because much of
the acreage available for exploration in New Zealand and the peer
group are at water depths beyond the Maari field. Additionally, it
was decided to analyze a field with a larger than average known
discovery.
The Sea Lion project is a relatively new discovery and was chosen
because it provides a very interesting analysis for an “unknown
discovery” in New Zealand. At 450 m water depth, it is a good fit for
the range of exploration block depths for New Zealand and the peer
group. Finding a discovery similar to Sea Lion is plausible. The
discovery size is under two standard deviations from the mean, and
has an 18% probability of occurrence.
Threshold Field Size –Sea Lion Analogue
The Sea Lion project continues to advance despite the recent
downturn in oil prices and the remoteness of the discovery. Given
these circumstances, this development poses as a worthy aspiration
for the peer group discussed in this report.
The Sea Lion prospect is located on Block 14/10 in Production
Licenses 032 and 033 on the eastern basin margin of the Falkland
Islands. The prospect is expected to produce around 160 million
barrels over a 15 year lifespan. In February 2015, Premier
announced that, due to market conditions, they were shifting their
plans to develop the Sea Lion prospect by leasing an FPSO rather
than using a Tension Leg Platform (TLP). The project costs are
estimated to be $2 Billion USD.
For this analysis, we are assuming that the advancement of the
project implies robust economics for the discovery. Using the base
resource assumptions, and an estimated 200 MM USD exploration
phase, this chapter analyses what the threshold volumes need to be
to receive a 15% return on a project in the style of the Sea Lion
development.
Using the Sea Lion project archetype and the Palantir Exploration
Analogue Dataset, we created 6 variations with volumes ranging
from 25 to 160 MM BBL of resources. These cases were run through
each fiscal regime at $60 USD/bbl using PalantirCASH™. The results
from the various field sizes in New Zealand can be found in
Appendix C.
Visualization 3.2 details the results of the analysis. The x axis
represents the different volumes and the y axis represents the after
tax cash flow NPV at a 15% discount rate.
For a development in the likeness of the Sea Lion project in New
Zealand, we see that it would require a discovery of around 85
mmbbls to receive a 15% return at $60 USD/bbl. Looking at the
volumes, we see that it requires a slightly smaller threshold field
size than the Falkland Islands, and a significantly smaller discovery
than the Canadian provinces.
Visualization 3.2

22
Conclusion
The New Zealand fiscal regime increases the commercially viability
of smaller fields when compared to the Falkland Islands and the
Canadian provinces. Looking at the results, these jurisdictions
require larger threshold volumes to earn the same return expected
in New Zealand. Overall, smaller fields have a greater chance of
being commercially viable in Ireland and New Zealand as they would
in the Falkland Islands, Newfoundland and Nova Scotia.

23
Appendix A Bid Round Results
New Zealand
Results from Block Offer 2014
Permit Granted to Basin Shore Status
57058 Mosman Oil & Gas (NZ) Limited East Coast Onshore
57067 Mosman Oil & Gas (NZ) Limited West Coast Onshore
57068 Mosman Oil & Gas (NZ) Limited West Coast Onshore
57076 Petrochem Limited Taranaki Onshore
57063 TAG Oil (NZ) Limited Taranaki Onshore
57065 TAG Oil (NZ) Limited Taranaki Onshore
57057 Statoil New Zealand B.V. Northland-
Reinga
Offshore
57083 50%: Chevron New Zealand Exploration Limited
(Operator)
50%: Statoil New Zealand B.V.
Pegasus Offshore
(Operator)
Pegasus Offshore
(Operator)
Pegasus Offshore
57073 OMV New Zealand Limited Pegasus Offshore
57070 New Endeavour Resources (NZ) Limited Taranaki Offshore
57075 OMV New Zealand Limited Taranaki Offshore
57080 50%: Todd Exploration Limited (Operator)
50%: Beach Petroleum (NZ) Pty. Limited
Taranaki Offshore
57090 ONGC Videsh Limited Taranaki Offshore
Newfoundland
NL13-01
(Parcel 1)
ExxonMobil Canada Ltd. (40%)
Suncor Energy Inc. (30%)
ConocoPhilips Canada
Resources Corp. (30%)
Flemish Pass Basin Offshore
NL13-02 (Parcel 1) No bids received Carson Basin Offshore
NL13-02 (Parcel 2) ExxonMobil Canada Ltd (50%)
Suncor Energy Inc. (50%)
Carson Basin Offshore
NL14-02 (Parcel 1) ExxonMobil Canada Ltd (100%) Jeanne d’Arc Basin Offshore

24
Ireland
Results from Irelands 2011 Bid Round
Permit Granted to Basin
Shore
Status
11/5, 11/10, 11/15,
12/1, 12/6, 12/11(p)
Serica Energy UK Limited Rockall Basin Offshore
35/13, 35/14, 35/15,
35/18, 35/19, 35/20
Providence Resources Plc (32%)
Chrysaor E&P Ireland Ltd (58%)
Sosina Exploration Limited (10%)
Porcupine Basin Offshore
35/25(ep), 35/30,
36/21, 36/26, 44/5(p),
45/1
Bluestack Energy Limited (100%) Porcupine Basin Offshore
35/23, 35/24,
35/25(wp)
Petrel Resources plc (100%) Porcupine Basin Offshore
44/4, 44/5(p), 44/9,
44/10, 44/14, 44/15
Antrim Energy Inc. (100%) Porcupine Basin Offshore
45/6, 45/11, 45/16 Petrel Resources plc (100%) Porcupine Basin Offshore
43/9, 43/10, 43/14 and
43/15
Europa Oil & Gas Plc (100%) Porcupine Basin Offshore
54/1, 54/2, 54/6 and
54/7
Europa Oil & Gas Plc (100%) Porcupine Basin Offshore
52/5, 52/10, 52/15,
53/1, 53/6, 53/11
Providence Resources (80%)
Plc Sosina Exploration Ltd (20%)
Porcupine Basin Offshore
34/19, 34/20, 34/24,
34/25, 35/16, 35/21
Two Seas Oil & Gas (100%) Porcupine Basin Offshore
61/13(p), 61/14,
61/15, 61/18(p),
61/19(p), 61/20,
62/11(p), 62/16(p)
Providence Resources Plc (40%)
Repsol Exploration Irlanda S A (40%)
Sosina Exploration Ltd (20%)
Goban Spur Offshore
18/25(p), 18/30 Providence Resources plc (66.66%)
First Oil Expro Ltd (33.33%)
Slyne Basin Offshore
n 27/13, 27/14, 27/19,
27/24
San Leon Energy (100%) Slyne Basin Offshore
Nova Scotia
NS-12-1 BP plc (100%) Scotian Basin Offshore
NS-13-1 Royal Dutch Shell (100%) Scotian Basin Offshore

25
Appendix B Fiscal Regimes
New Zealand
The New Zealand fiscal regime is based upon a relatively simple
royalty/tax system on commercial oil and a levy on natural gas.
Oil and gas are currently produced from 21 petroleum mining fields,
all in the Taranaki Basin which has been the main focus for
hydrocarbon exploration and production in New Zealand. The first
well was drilled in 1865 and petroleum has been continuously
produced from the basin since about 1900.
Type Concessionary (Royalty/Tax)
Royalty
Either Ad Valorem Royalty (AVR) or hybrid of AVR and
Accounting Profits Royalty (APR)
Bonuses No signature bonuses or production bonuses
Revenue Taxes None
Local Taxes None
Fees None
Special Taxes None
Corporate Tax Currently set at 28%. Previous rates detailed below.
State Participation None
Royalty
Historically royalties were calculated as a fixed percentage (usually
between 5.0% and 12.5%) of the 'wellhead value' of petroleum (i.e.
revenues net of transportation costs). However, a newer profits-
based royalty was introduced which levied at 20% of 'accounting
profits' (i.e. gross revenues net of all exploration, development,
operating and transportation costs incurred prior to the point of
sale).
As a result, we now have the following types of royalty systems in
place:
 AVR : Applicable to all permits awarded pre-1995
 Hybrid AVR+APR: Applicable to all permits awarded post-
1995 and calculated at a Permit (Gross) level.
Royalty paid under an exploration permit is AVR of 5% while under a
mining permit the higher of AVR and APR is payable.
Royalty Rates
All rates quoted are for the life of the project based on discovery
date:
Period of Discovery AVR APR
Prior to 1985
5% to 10% based on
year and type (oil/gas)
of discovery
N/A
1 January 1985 to
31 December 1994
12.5% for both oil &
gas discoveries
N/A
1 January 1995 to
29 June 2004
5% of net revenue 20% of net revenue
30 June 2004 to 31
December 2009
1% for gas and 5% for
oil
Offshore Discovery – 15% on the first
NZ$750 million (cumulative) gross sales
and 20% on additional production.
Onshore Discovery – 15% on the first
NZ$250 million (cumulative) gross sales
and 20% on additional production.
After 1 January
2010
5% of net revenue 20% of net revenue

26
Note that from 1 January 1995 onward, royalty payable in any one
year would be AVR or APR, whichever is higher.
AVR – Ad Valorem Royalty
Ad Valorem Royalty (AVR) is a royalty payable on either a sales price
received or the deemed sales price (where there has been no sale or
no arm's length sale).
The AVR payable is a percentage of the 'landed value' (net sales
revenue) which is calculated as follows:
Net Sales Revenue = Gross Sales of Petroleum + Value of Unsold
Petroleum – Netbacks
Netbacks (net forwards) are the portion of sales price that
represents the cost of transporting/storing/processing of
petroleum. This is a naming convention used by the authorities in
New Zealand. Effectively it means that the transportation costs to
point of sale are deductible.
APR – Accounting Profits Royalty
Accounting Profits Royalty (APR) is a mechanism whereby the state
receives a share of profits once all significant costs have been
recovered. It takes into account the prices received for products and
the costs of extracting, processing and selling those products up to
the point of sale.
The APR payable is a percentage of the accounting profits which is
the excess of the net sales revenue less the allowable APR
deductions. Allowable APR deductions are:
 Production costs
 Capital costs (prospecting and exploration costs,
development costs, permit maintenance and consent costs
and feasibility study costs)
 Indirect costs
 Decommissioning costs
 Operating and capital overhead allowance
 Operating losses and capital costs carried forward
 Decommissioning costs carried back
Note that depreciation can be used as a deduction rather than
expenditure. Furthermore, not all capital necessarily qualifies for
APR deduction. Qualifying capital has to be associated with the
upstream project.
For any accounting period, the provisional accounting profits are the
excess of the net sales revenues less the allowable APR deductions
excluding the decommissioning costs carried back. Once the
decommissioning costs carried back figures are taken into account,
the resulting figures give the final accounting profits.
Decommissioning costs may have been incurred during the life of
the field and not eligible for deduction against net sales revenues
until the final royalty return. These decommissioning costs are
called decommissioning costs carried back and are determined at
time of contract negotiation.
The overhead allowance is an allowance at a rate of 2.5% (onshore)
or 1.5% (offshore) of the total production, capital and indirect costs
that can be claimed as a royalty deduction. This allowance cannot
be claimed against decommissioning costs.

27
Corporate Tax
Prior to 31 March 1989
Corporate tax was charged at two rates: 28% for New Zealand
resident companies and 33% for foreign companies.
Between 01 April 1989 and 31 March 2008
Corporate tax was charged at a uniform rate of 33% regardless of
the domicile of the contracting company.
Between 01 April 2008 and 31 March 2012
Corporate tax was reduced to a standard 30% for all contracting
companies.
01 April 2012 Onwards
Corporate tax was reduced to 28% for all contracting companies.
Exploration Expenditure
Pre-1990
All exploration costs were fully deductible in the year in which they
occurred.
1990 – 1991
An immediate write-off was only allowed when a prospecting
licence or exploration permit was relinquished or if a well was
plugged and abandoned.
If a well was suspended then the exploration costs relating to that
well were capitalised to a 'cost of licence account'. The contractor
was unable to write off any of the expenditure from the cost of
licence account until the licence was either relinquished or until
commercial production commenced. Capitalised costs were then
deductible on a ten year straight line basis, or over the life of the
field, whichever was shorter.
Post-1991
Exploration expenditure is expensed immediately, irrespective of
whether a well is plugged and abandoned or not.
Development Expenditure
Pre-1990
Split into two categories: 'normal' and 'remote'. Where the field was
not in a remote location, a deduction spread over a minimum five
year period was allowed beginning in the year in which commercial
production commenced. In each year a total of 20% of gross capital
expenditure could be offset. Alternatively, a variable amount could
be offset, over five years, which amounted to a total of 20% per
annum. In 'remote' areas, the variable offset could not be used, but
costs could be written off over five years, commencing in the year in
which the expenditure was incurred.
October 1990 – December 1991
Capital expenditure was capitalised to a cost of licence account and
carried on the accounts until the start of commercial production.
Costs were deductible on a 10-year straight-line basis or over the
life of the field, whichever was shorter.

28
Post-1991
Development expenditure is amortised over 7 years straight line or
the remaining field life, whichever is the quickest.
For offshore projects expenditure may be expensed from the year in
which it is incurred, while for onshore developments costs can only
be written off once production commences.
Carried Costs
Prospecting and exploration costs incurred between 30 June 2004
and 31 December 2009 can be carried forward with an annual
interest rate equal to the 10-year government bond rate plus 1
percentage point.

29
Ireland
The oil industry in Ireland started with exploration in 1970, with
Kinsale Gas being the first discovery in 1971.
Ireland has a relatively simple hydrocarbon tax regime with identical
terms applying to all assets up to 2007. Some fields pay royalty and
most are subject to a reduced corporate tax rate. Changes have
been introduced which will be applicable to fields allotted under the
Atlantic Licensing round 2015. The changes will ensure a relatively
high return for the Government when compared to the previous
regime which provided a very high Contractor take.
Type Concessionary (Royalty/Tax)
Royalty
Only payable on older developments (phased out for new
developments)
Bonuses None
Revenue Taxes None
Local Taxes None
Fees None
Special Taxes Petroleum Production Tax (PPT) of up to 40% based on R-factor
Corporate Tax Varies between 12.5% and 25%
Interest & Participation
There is currently no participation by the Irish government.
Royalty
Royalty is not payable on new developments but is payable at a rate
of 12.5% on older licences. Royalty is payable on the sales value
rather than the wellhead value of the hydrocarbon and as such a
number of deductions associated with transportation are
permissible, e.g. transportation opex.
There is no gas royalty.
Corporate Tax
The rate of corporate income tax is 12.5% but the higher rate of
25% often applies to oil and gas assets. For assets that qualify for
the lower rate, that reduced rate will apply for the entire life of the
asset.
The lower rate applies to specific licence rounds and may well apply
to new assets going forward, particularly in frontier areas.
Deductions
Corporate tax is payable on a company’s entire oil and gas activities
in Ireland.
The permissible deductions are:
 Operating costs
 Royalty
 Exploration costs
 Development capital
 Interest (except that used to fund exploration)

30
 Abandonment
 R&D costs (with 25% uplift)
 PPT paid
Abandonment may be carried back for up to 3 years against historic
profits. Failing this it may be possible to carry it forward into non-
oil-and-gas activities.
All capital is expensed, i.e. written off in the first year of production.
Deductions can be carried forward indefinitely, although if there is a
change in ownership then the right to carry losses forward may be
denied.
Corporate tax is ringfenced around the upstream petroleum
industry and it is not possible to offset losses from other sectors
against profits from oil and gas activities.
Payment
Tax payments are paid in two instalments: 90% of the current year’s
liability 7 months after the end of the tax year and the remainder 2
months later.
PPT
The Petroleum Production Tax (PPT) will be applicable to fields
under the Atlantic 2015 licensing round. The mechanism is based
approximately on a pre-CT R-factor.
PPT is ringfenced and calculated on each field’s net income (Gross
Sales less Field Development and Operating Costs).
The incurred Exploration Capital is allowed as deduction in the
exploration licenses containing the field for PPT calculation.
The R-factor has a slightly unusual definition:
𝑅𝐹 =
( 𝑅𝑒𝑣𝑒𝑛𝑢𝑒 − 𝑃𝑃𝑇 𝑃𝑎𝑖𝑑)
𝐶𝑢𝑚𝑢𝑙𝑎𝑡𝑖𝑣𝑒 𝐼𝑛𝑣𝑒𝑠𝑡𝑚𝑒𝑛𝑡
The numerator is based on the field’s total revenue less PPT
payments and the denominator includes both capital and
operational expenditures.
The R-factor for the band 1.5 to 4.5 is interpolated as follows:
𝑃𝑃𝑇 𝑅𝑎𝑡𝑒 % = (
𝑅𝐹 − 1.5
4.5 − 1.5
× (40% − 10%)) + 10%
Minimum PPT: There will be a minimum PPT payment of 5% of
revenue to Government in each year of production. The higher of
the Normal PPT Rate and Min PPT Rate will be applicable for the
calculation of PPT.
R-Factor Tax Rate (%)
< 1.5 0
= 1.5 10
1.5 < RF < 4.5 Pro Rata
> 4.5 40

31
Newfoundland
The terms generally follow a generic royalty regime structure
promoted by the Newfoundland government, though it also
documents current and historic variations in the regime.
Royalty History
Prior to 1997, royalty terms were negotiated on a project by project
basis, and typically involved a minimum royalty of 1–5% from gross
revenue, and a post-payout royalty on net revenue in the range of
25–50%.
Royalty
The fiscal regime generally reacts to cost recovery, production
levels, and market price. There are three stages of “cost recovery
points”, each of which will trigger a higher and additional royalty
rate and a modification of the calculation. Prior to costs being
recovered (simple, tier I, and tier II, payouts), between 1–9% of
gross revenue will be paid as royalty to the crown.
Allowed Costs
The following costs are deemed allowable if they meet the following
criteria:
Pre-development Costs
 Costs incurred before the commencement date
 Costs incurred after the commencement date for the
purpose of exploration on project lands
 Costs the minister determines to be pre-development costs
Operating Costs
 Must not be a pre-development cost, a cost incurred in
compliance with a decommissioning plan, or an allowed
capital cost
 Must be incurred after production start-up
 Would be classified as an operating cost in accordance with
Canadian generally accepted accounting principles
 Plus a 10% uplift on operating costs referred to above that
are not overhead, marketing costs or costs for a funded
reserve
Type Concessionary Royalty/Tax (with cost recovery)
Royalty 1–9% of gross revenue, or 10–30% of net revenue
Bonuses None
Revenue Taxes None
Local Taxes None
Special Taxes None
Corporate Tax –
Provincial
14% of taxable income
Corporate Tax –
Federal

32
Capital Expenditures
 Must not be a pre-development cost, a cost incurred in
compliance with a decommissioning plan, or an allowed
operating cost, and
 Must be incurred after the commencement date, or
 Qualifies as an eligible operating cost that was incurred
before production start-up, or
 Is a cost incurred to abandon a well not incurred with
respect to a decommissioning plan provided the cost meets
all other capital cost criteria
 Plus a 1% uplift cost on expenditures that are not overhead,
marketing costs or costs for a funded reserve
Decommissioning costs
 Costs that satisfy all other requirements of these
regulations and were made, incurred or required under the
decommissioning plan
 Decommissioning revenue is revenue received or deemed
to be received by the interest holder or the project operator
on behalf of the interest holders in the lease in accordance
with the decommissioning plan
Revenue
Incidental Calculations
Incidental revenue is consideration received or deemed to be
received or declared by the interest holder or the project operator
on behalf of the interest holder from the following:
 Sale, lease, licence or other disposal or use of lease assets or
technology under the lease where the costs were royalty
costs under the lease
 Other revenue received on account of the lease that the
minister may reasonably declare to be incidental revenue.
Revenue Calculations
𝑃𝑟𝑜𝑗𝑒𝑐𝑡 𝑅𝑒𝑣𝑒𝑛𝑢𝑒 = ( 𝑃𝑟𝑜𝑑𝑢𝑐𝑡 𝑉𝑜𝑙𝑢𝑚𝑒) ∗ (𝑈𝑛𝑖𝑡 𝑃𝑟𝑖𝑐𝑒)
𝐺𝑟𝑜𝑠𝑠 𝑅𝑒𝑣𝑒𝑛𝑢𝑒
= ( 𝑃𝑟𝑜𝑗𝑒𝑐𝑡 𝑅𝑒𝑣𝑒𝑛𝑢𝑒)
− (𝑇𝑟𝑎𝑛𝑠𝑝𝑜𝑟𝑡𝑎𝑡𝑖𝑜𝑛 𝐶𝑜𝑠𝑡𝑠)
𝑁𝑒𝑡 𝑅𝑒𝑣𝑒𝑛𝑢𝑒
= ( 𝐺𝑟𝑜𝑠𝑠 𝑅𝑒𝑣𝑒𝑛𝑢𝑒 + 𝐼𝑛𝑐𝑖𝑑𝑒𝑛𝑡𝑎𝑙 𝑅𝑒𝑣𝑒𝑛𝑢𝑒
+ 𝑂𝑖𝑙 𝑇𝑎𝑘𝑒𝑛 𝐼𝑛 𝐾𝑖𝑛𝑑) − ( 𝐴𝐶)
Where:
AC = Allowable Costs
Return Allowance
Tier I Return Allowance
𝑅𝐴 = [( 𝐶𝐴𝐶 + 𝐵𝑅 + 𝐶𝑢𝑚𝑢𝑙𝑎𝑡𝑖𝑣𝑒 𝑇𝑖𝑒𝑟 𝐼 𝑅𝐴) − 𝐶𝑅] × 𝑅𝐴 𝑅𝑎𝑡𝑒
Where the respective (RA Rates) are:
Post 30 November 2001
( 𝑅𝐴 𝑅𝑎𝑡𝑒) = (1.05 + 𝐿𝑇𝐵𝑅)
1
12 − 1
30 April 1990 to 30 November 2001
( 𝑅𝐴 𝑅𝑎𝑡𝑒) = (1 + 𝑋)
1
12 − 1

33
Tier II Return Allowance
𝑅𝐴 = [( 𝐶𝐴𝐶 + 𝐵𝑅 + 𝐶𝑢𝑚𝑢𝑙𝑎𝑡𝑖𝑣𝑒 𝑇𝑖𝑒𝑟 𝐼𝐼 𝑅𝐴) − 𝐶𝑅] × 𝑅𝐴 𝑅𝑎𝑡𝑒
Where the respective (RA Rates) are:
Post 30 November 2001
( 𝑅𝐴 𝑅𝑎𝑡𝑒) = (1.15 + 𝐿𝑇𝐵𝑅)
1
12 − 1
30 April 1990 to 30 November 2001
( 𝑅𝐴 𝑅𝑎𝑡𝑒) = (1 + 𝑋)
1
12 − 1
Where:
RA = Return Allowance
CAC = Cumulative Allowed Costs
BR = Basic Royalty (not including payments in kind)
LTBR = Long Term Bond Rate
X = Percentage Increase in CPI over prior 14 months
CR = Cumulative Revenue
Determining Payout
Simple payout occurs when:
𝐶𝑅 > 𝐶𝐴𝐶 + 𝐵𝑅
Tier I payout occurs when:
𝐶𝑅 > 𝐶𝐴𝐶 + 𝐵𝑅 + 𝑇𝑖𝑒𝑟 𝐼 𝑅𝐴
Tier II payout occurs when:
𝐶𝑅 > 𝐶𝐴𝐶 + 𝐵𝑅 + 𝐼𝑅 + 𝑇𝑖𝑒𝑟 𝐼𝐼 𝑅𝐴
Where:
IR = Incremental Royalties (not including payments in kind)
Royalty Calculation
Basic Royalty
( 𝐺𝑟𝑜𝑠𝑠 𝑅𝑒𝑣𝑒𝑛𝑢𝑒 + 𝑉𝑎𝑙𝑢𝑒 𝑜𝑓 𝑂𝑖𝑙 𝑇𝑎𝑘𝑒𝑛 𝑖𝑛 𝐾𝑖𝑛𝑑) × 𝑟
Tier I Royalty
An interest holder shall calculate and pay Tier I incremental royalty
to the Crown every month, starting with the month in which Tier I
payout for that interest holder occurs.
( 𝑁𝑒𝑡 𝑅𝑒𝑣𝑒𝑛𝑢𝑒 × 𝑟) − 𝐶𝑢𝑚 𝐵𝑅 − 𝐶𝑢𝑚 𝑇𝑖𝑒𝑟 𝐼 𝐼𝑅
Tier II Royalty
An interest holder in a lease shall calculate and pay a Tier II
incremental royalty to the Crown every month, starting with the
month in which Tier II payout for that interest holder occurs.
( 𝑁𝑒𝑡 𝑅𝑒𝑣𝑒𝑛𝑢𝑒 × 𝑟) − 𝐶𝑢𝑚 𝑇𝑖𝑒𝑟 𝐼𝐼 𝐼𝑅
Where:
r = is the applicable royalty rate from below.
Super Royalty Rate
Adds an additional royalty of a contract per cent of net revenue,
over and above the existing net royalty, when West Texas
Intermediate crude oil trades above USD50 per barrel any time after
Tier I payout.

34
30 April 1990 to 30 November 2001:
Basic Royalty
Before Simple Payout
Cumulative Production (MM Bbl) Royalty Rate (%)
≤ 50 1.0
> 50 2.5
After Simple Payout
Cumulative Production (MM Bbl) Royalty Rate (%)
≤ 100 5.0
> 100 7.5
Incremental Royalties:
Tier I (after Tier I payout occurs): 30%
Tier II (after Tier II payout occurs): 12.5%
Post 30 November 2001:
Basic Royalty
Before Simple Payout
WTI Price (CAD/bbl) Net Royalty Rate (%)
≤ 50 or 20% of initial established total
reserves
1.0
50 < CP ≤ 100 2.5
100 < CP ≤ 200 5.0
100 < CP ≤ 200 7.5
After Simple Payout
Cumulative Production
(MM Bbl)
Royalty Rate (%)
< 100l) 5.0
> Next 100 7.5
Incremental Royalties
Tier I (after Tier I payout occurs): 20%
Tier II (after Tier II payout occurs): 10%
Corporate Tax
The Canadian federal tax rate is 15% of taxable income; the
provincial rate is 14%.
The majority of capital and operational expenditures are deductible.
These deductions include:
 Operational Expenditures — Written off in full, at the end of
the period they were incurred
 Royalties — Written off in full, at the end of the period they
were incurred
Capital Expenditure:
 Capital Development Expenditure (CDE) — Includes the
costs of developing at the well level. Depreciated at 30%
declining balance
 Capital Exploration Expenditure (CEE) — Can be written off
instantly

35
 Capital Cost Allowance (CCA) — Includes most machinery
and equipment. Depreciated at 25% declining balance
 Property Costs — Deductible at 10% per year
 Abandonment — Straight line depreciation

36
Nova Scotia
The terms generally follow a generic royalty regime structure
promoted by the Newfoundland government, though it also
documents current and historic variations in the regime.
Roy
alty
Hist
ory
As
rece
ntly
as
2006
offsh
ore royalty terms were negotiated with producers on a project by
project basis. These included a minimum initial tier duration, a
minimum royalty of 1-5% on gross revenue, and 20-35% royalty on
net revenue.
Royalty
The offshore fiscal regime royalty is based upon revenues and
profits from oil and gas production, and reacts to cost recovery,
project size, and project risk. The government also provides two
modified regimes for small oil and high risk projects.
The base regime has four royalty tiers which are triggered by three
distinct ‘field payout points’. In each tier the royalty rate and cost
recovery calculation is modified. Prior to costs being recovered in
tiers one and two between 2-5% of gross revenue will be paid as
royalty to the crown while in tiers three and four net revenue is
used to calculate the royalty.
The Small Oil Regime guarantees producers a minimum of two years
in tier one and another three years in tier two; the High Risk Regime
prescribes a net revenue royalty ceiling in tier three with only two
field payout points. These modified regimes may also allow the use
of unsuccessful exploration costs for royalty purposes.
In all cases, after primary and secondary cost recovery, a 5% gross
revenue royalty floor persists in tiers three and four.
The following components of the calculation will be outlined,
starting with the definitions of important inputs:
 Allowed Costs
 Revenue
 Return Allowance
 Determining Payout
 Net and gross royalty rates
Allowed Costs
The following costs are deemed allowable if they meet the following
criteria:
Type Concessionary Royalty/Tax (with Cost Recovery)
Royalty (Offshore) 2–5% of Gross Revenue or 20–35% of Net Revenue
Royalty (Onshore) 5–10% of Gross Revenue
Bonuses None
Revenue Taxes None
Local Taxes None
Special Taxes None
Corporate Tax –
Provincial
Corporate Tax –
Federal

37
Pre-Development Costs
 Costs incurred before the commencement date
 Costs that would be considered an allowed capital cost after
the commencement date
 Costs the minister determines to be allowed pre-
development costs
 Unsuccessful exploration costs in a high risk exploration
area or small reserve oil projects only
Operating Costs
 Must not be a pre-development cost, or an allowed capital
cost
 Must be incurred on or after production start-up
 Would be classified as an operating cost in accordance with
Canadian generally accepted accounting principles
 Transportation costs within the field area
 Costs, expenses or other amounts in respect to Canada-
Nova Scotia Benefits, that are not reasonably attributable to
the field
Additional 10% uplift on operating costs referred to above
Capital Expenditures
 Must not be a pre-development cost, or an allowed
operating cost, and
 Must be incurred on or after the field commencement date,
or
 Costs that qualify as a eligible operating costs that were
incurred before production start-up, or
 Costs incurred to abandon a well
Additional 1% uplift cost on expenditures referred to above that are
not allowed operating costs incurred before the production date
Abandonment Costs
 Costs incurred in closing down, decommissioning,
abandoning, or removing, in whole or in part, a field asset as
required
 Costs incurred prior to the month of cessation or within
three years after cessation
Cumulative Allowed Costs
 Aggregate of allowed predevelopment, capital, and
operating costs incurred on or before end of month
 Royalty payable for all previous months
 Royalty payable for the current month using the royalty
calculation from the previous month
Definitions:
Commencement Date - The first day of the month in which a
development plan for the field is approved by the government
Revenue
Gross Revenue
𝐺𝑟𝑜𝑠𝑠 𝑅𝑒𝑣𝑒𝑛𝑢𝑒
= ∑ 𝑃𝑟𝑜𝑑𝑢𝑐𝑡 𝑃𝑟𝑜𝑑𝑢𝑐𝑡𝑖𝑜𝑛 𝑉𝑜𝑙𝑢𝑚𝑒 × 𝑃𝑟𝑜𝑑𝑢𝑐𝑡 𝑆𝑎𝑙𝑒𝑠 𝑃𝑟𝑖𝑐𝑒
𝑝𝑟𝑜𝑑𝑢𝑐𝑡𝑠
𝑃𝑟𝑜𝑑𝑢𝑐𝑡 𝑆𝑎𝑙𝑒𝑠 𝑃𝑟𝑖𝑐𝑒 =
𝑃𝑟𝑜𝑑𝑢𝑐𝑡 𝑆𝑎𝑙𝑒𝑠 𝑃𝑟𝑜𝑐𝑒𝑒𝑑𝑠
𝑃𝑟𝑜𝑑𝑢𝑐𝑡 𝑆𝑎𝑙𝑒𝑠 𝑉𝑜𝑙𝑢𝑚𝑒

38
Monthly sales proceeds must be at arms-length and are adjusted for
allowable netback costs
If no monthly sale proceeds for a produced product the price is
equal to the fair market value at the royalty valuation point
Cumulative Gross Revenue
𝐶𝑢𝑚𝑢𝑙𝑎𝑡𝑖𝑣𝑒 𝐺𝑟𝑜𝑠𝑠 𝑅𝑒𝑣𝑒𝑛𝑢𝑒
= 𝐶𝑢𝑚. 𝐺𝑟𝑜𝑠𝑠 𝑅𝑒𝑣𝑒𝑛𝑢𝑒 + 𝐶𝑢𝑚. 𝑀𝑖𝑠𝑐. 𝐴𝑚𝑜𝑢𝑛𝑡𝑠
Net Revenue
𝑁𝑒𝑡 𝑅𝑒𝑣𝑒𝑛𝑢𝑒 = 𝐺𝑟𝑜𝑠𝑠 𝑅𝑒𝑣𝑒𝑛𝑢𝑒 + 𝑀𝑖𝑠𝑐. 𝐴𝑚𝑜𝑢𝑛𝑡𝑠 − 𝐴𝐶
Where:
AC = Allowed Capital Costs and Allowed Operating Costs incurred
during the month
Misc. Amounts = Total of all amounts that becomes receivable, of
any commodity (other than petroleum or field asset) derived in the
lease interest from petroleum produced by virtue of holding the
lease interest
Return Allowance
Calculation of return allowances begin in the month which field
commencement occurs
Primary Return Allowance:
𝑅𝐴1 =
(0.05+𝐿𝑇𝐵𝑅)
12
× ( 𝐶𝐴𝐶 − 𝐶𝑅)
Secondary Return Allowance:
𝑅𝐴2 =
(0.20+𝐿𝑇𝐵𝑅)
12
× ( 𝐶𝐴𝐶 − 𝐶𝑅)
Final Return Allowance:
𝑅𝐴3 =
(0.45 + 𝐿𝑇𝐵𝑅)
12
× (𝐶𝐴𝐶 − 𝐶𝑅)
Where:
RAx = X Return Allowance
LTBR = Canadian Long Term Bond Rate
CAC = Cumulative Allowed Costs
CR = Cumulative Gross Revenue
Determining Payout Points
The month in which the payout point triggers the next royalty tier is
determined by the month in which the following successive
inequalities become true:
Primary Payout Point:
𝐶𝑅 ≥ (𝐶𝑅𝐴1 + 𝐶𝐴𝐶)
Secondary Payout Point:
Final Payout Point:
Where:
CRAx = Cumulative X Return Allowance = ∑RAx
Royalty Calculation
As successive incremental royalty tiers are recognized the monthly
royalty calculation is adjusted to the tier and the interest holder is
liable to pay the incremental royalty every month.

39
In the month which a payout point is triggered a transition royalty is
calculated. This transitional royalty is calculated as the sum of: 50%
of the royalty calculation used in the previous month; and 50% of
the royalty calculation for the next tier.
Base Regime
Tier 1 Royalty:
𝑅𝑜𝑦𝑎𝑙𝑡𝑦1 = 𝐺𝑟𝑜𝑠𝑠 𝑅𝑒𝑣𝑒𝑛𝑢𝑒 × 0.02
Tier 2 Transitional Royalty
𝑅𝑜𝑦𝑎𝑙𝑡𝑦 𝑇2 = [ 𝑅𝑜𝑦𝑎𝑙𝑡𝑦1 × 0.50] + [ 𝑅𝑜𝑦𝑎𝑙𝑡𝑦2 × 0.50]
Tier 2 Royalty:
𝑅𝑜𝑦𝑎𝑙𝑡𝑦2 = 𝐺𝑟𝑜𝑠𝑠 𝑅𝑒𝑣𝑒𝑛𝑢𝑒 × 0.05
Tier 3 Transitional Royalty
Tier 3 Royalty:
𝑅𝑜𝑦𝑎𝑙𝑡𝑦3 = max(𝑁𝑒𝑡 𝑅𝑒𝑣𝑒𝑛𝑢𝑒 × 0.20, 𝐺𝑟𝑜𝑠𝑠 𝑅𝑒𝑣𝑒𝑛𝑢𝑒 × 0.05)
Tier 4 Transitional Royalty:
Tier 4 Royalty:
𝑅𝑜𝑦𝑎𝑙𝑡𝑦4 = max(𝑁𝑒𝑡 𝑅𝑒𝑣𝑒𝑛𝑢𝑒 × 0.35, 𝐺𝑟𝑜𝑠𝑠 𝑅𝑒𝑣𝑒𝑛𝑢𝑒 × 0.05)

40
Appendix C Sea Lion Analogue Summary
Reports Using New Zealand Fiscal Terms
25 MM BBL

41
50 MM BBL

42
75 MM BBL

43
100 MM BBL

44
125 MM BBL

45
160 MM BBL

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