Bright Simons: GNPC’s incompetence forced ENI to resort to arbitration

Meeting
chiefs
of
the
Nzema
area
this
week,
Ghanaian
President,
Akufo-Addo, pledged to
amicably
resolve
the
increasingly
protracted
impasse
between
one
of
the
country’s
local
oil
companies,
Springfield,
and
a
consortium
made
up
of
Italian
oil
major,
ENI
and
its
Swiss
partner,
Vitol.

Attempts
by
the
Government
of
Ghana
to
force
a
“merger”
of
the
separate
petroleum
discoveries
of
Springfield,
on
the
one
hand,
and
Eni
and
Vitol,
on
the
other
hand;
split
the
equity
of
the
merged
“unit”
anew
among
the
companies;
and
have
them
jointly
produce
oil
from
the
combined
field
is
in
stark
contrast
to
the
voluntary
agreement
that
led
to
a
similar
“merger”
(or
technically,
“unitization”)
of
the
country’s
most
successful
oil
field
to
date,
Jubilee.

In
the
case
of
Jubilee,
the
oil
companies
involved
(Tullow,
Kosmos,
Anadarko
and
others)
agreed
that
the
discoveries
they
had
separately
made
on
the
concessions
separately
leased
from
Ghana
were
indeed
connected
in
such
a
manner
that
it
would
make
sense
for
the
discoveries
to
be
unitized
and
produced
as
a
single
oil
field.

In
response
to
the
Government’s
attempt
to
impose
a
formula
for
a
forced
unitisation
of
the
fields,
Eni-Vitol
have
decided
to
trigger
the
dispute
arbitration
clause
in
their
lease
agreement
with
the
Government.
A
showdown
at
the
London
Court
of
International
Arbitration
between
Ghana
and
the
Swiss-Italian
investors
is
now
imminent.

Usual
Justifications
for
Unitisation

The
benefits
from
unitization
are
usually
spread
among
the
producing
oil
companies/investors,
the
Government
and
the
host
country.

Because
petroleum
(oil,
gas
and
other
economically
valuable
derivatives)
is
often
trapped
underground
or
under
the
seabed
(all
of
Ghana’s
commercial
discoveries
so
far
are
“offshore”,
under
the
seabed)
in
fluid
forms,
the
“accumulation”
can
shuffle
around
the
rock
formations
in
which
it
is
trapped.

Concessions
are
often
given
out
without
a
full
picture
of
how
the
petroleum
is
distributed
under
the
seabed,
though
with
every
seismic
mapping
done
by
investors
the
country
knows
better
how
to
carve
out
the
concession
blocks
for
block
lessees
to
minimize
such
“straddling”
of
petroleum
reservoirs.

When
investors
enter
into
contracts
with
Ghana
to
lease
a
block
under
the
sea
(under
international
law,
Ghana
controls
its
coastal
seabed,
or
continental
shelf,
up
to
an
extent
of
200
nautical
miles
or
more
into
the
high
seas),
they
do
so
in
the
hope
that
any
“pool”
of
petroleum
they
discover
in
any
section
of
the
block
that
they
can
drill
profitably
will
be
theirs
to
own
and
exploit.
They
will
usually
also
have
the
right
to
invite
investors
to
share
the
costs
and
profits
(i.e.
“to
participate”)
resulting
from
the
eventual
harvest
of
hydrocarbon
riches
(of
course,
by
law
and
through
negotiation,
the
Government
is
entitled
to
about
10%
more
or
less
of
any
such
discovery,
usually
exercised
through
the
Ghana
National
Petroleum
Corporation
–
GNPC
–
or
one
of
its
even
more
commercial
subsidiaries,
such
as
Explorco
or
Gosco).

If
it
turns
out
that
the
pool
of
oil
extends
to
adjacent
blocks,
then
there
is
the
possibility
that
the
oil
in
one
block
can
be
“suctioned
out”
by
the
oil
companies
who
own
the
adjacent
blocks
faster
or
in
larger
quantities,
draining
the
pool
or
reservoir
to
the
detriment
of
the
slower
or
more
cautious
block
owner.
To
prevent
such
a
fate,
each
block
owner
is
incentivized
to
drill
as
aggressively
as
they
can
(so-called
“competitive
drilling”)
leading
to
suboptimal
decisions
in
many
ways.

Because
effective
drilling
requires
careful
management
of
the
pressure
in
the
reservoir,
one
has
to
position
production
wells
carefully
in
order
to
apply
just
the
right
amount
of
force
on
the
right
points
in
the
overall
“geological
structure”
or
“stratigraphic
trap”
in
which
the
petroleum
has
accumulated.
A
common
reservoir
thus
require
a
central
design.

Often,
additional
measures
are
needed
to
engineer
the
pressure
dynamics,
such
as
injection
of
water
and
gas
at
specific
points
to
build
up
pressure
for
the
petroleum
fluids
to
flow
up
the
production
wells
through
“risers”
into
production
facilities
(such
as
so-called
“FPSOs”
or
“submersible
rigs”)
on
the
sea
surface.
Siting
these
expensive
but
non-producing
“injector
wells”
properly
often
requires
that
the
field
engineer
takes
into
account
where
the
production
wells
are
also
placed.
Without
a
central
field
engineer,
individual
block
owners
would
usually
favour
more
production
wells
on
their
side
than
injector
wells
that
optimizes
pressure
across
the
entire
reservoir.

All
of
these
suboptimal
decisions
–
competitive
drilling,
poor
siting
of
wells,
underinvesting
in
secondary
recovery
infrastructure
like
injectors,
etc
–
impact
the
long-term
performance
of
the
oil
field.
Investors,
as
a
collective,
may
lose
out
because
of
duplicative
spending
on
competing
wells
and
injectors.
Government
loses
out
on
revenue
because
most
capex
costs
by
investors
are
tax
deductible.
And
the
society
loses
out
since
in
the
medium
term
less
oil
and
less
oil
revenue
are
generated
for
socioeconomic
returns
(jobs,
social
spending,
contracts
for
value
chain
companies
etc).

Unitisation
is
However
Not
Always
the
Only
Option

It
is
important
to
bear
in
mind
however
that
some
of
the
problems
that
unitization
usually
sets
out
to
solve
can
be
addressed
through
other
regulatory
means.
For
example,
every
well
that
is
sunk
in
a
block
usually
needs
prior
regulatory
approval.
In
fact,
some
operators
in
Ghanaian
waters
claim
that
the
total
number
of
approvals
needed
to
get
a
new
oil
field
going
exceed
two
thousand.
The
regulator
has
a
say
in
well
spacing
decisions
through
its
ability
to
coordinate
the
outcomes
of
multiple
“plans
of
development”
for
oil
fields
submitted
by
different
companies
in
adjacent
contract
areas.

Companies
can
also
embark
on
what
is
known
as
“pooling”
whereby
they
co-invest
in
oil
wells
with
regulatory
approval
in
order
to
minimize
the
duplicative
spending
of
drilling
unnecessary
adjacent
wells.
With
horizontal
drilling
and
sidetracking
techniques
getting
more
sophisticated
by
the
day,
such
commercial
solutions
are
even
more
viable
today
than
they
were
in
the
past.
The
broad
term
for
these
other
alternatives
to
unitization
is
“joint
development”.

As
a
last
resort,
regulators
can
even
cap
production
output
to
prevent
excessive
drainage
of
the
reservoir.
In
the
present
case
of
Eni,
the
initial
production
forecast
of
45,000
barrels
of
oil
a
day
has
been
significantly
exceeded
(peak
production
is
now
at
57,300
barrels)
because
this
is
allowed.

The
above
caveats
notwithstanding,
unitization
is
usually
a
preferred
mode
for
maximizing
recovery
when
legal
and
regulatory
certainty
is
required.

Why
the
Eni
–
Springfield
Impasse
then?

Given
the
potential
benefits
to
investors
and
block
owners/lessees
of
unitization
and
the
usually
voluntary
nature
of
the
practice
(some
jurisdictions
like
Texas
don’t
even
have
a
statutory
pooling
or
compulsory
unitization
regime),
why
has
the
Eni-Springfield
matter
become
so
acrimonious?

It
is
clear
from
the
title
of
this
explainer
which
way
my
sentiments
turn.
I
think
GNPC
is
the
problem.
But
to
make
the
case
properly,
it
is
important
to
trace
the
long
genesis
of
the
two
oil
discoveries
that
the
Government
of
Ghana
wants
developed
as
a
single
unit.

The
Eni
–
Vitol
Sankofa
Discovery

In
March
2006,
the
Government
of
Ghana
signed
an
agreement
with
Heliconia
Energy,
for
the
Offshore
Cape
Three
Points
block.
As
is
customary
in
this
space,
Heliconia
flipped
the
block
to
Vitol,
the
parent
of
its
own
Bermuda
holding
company,
Atlantic.

In
2009,
Vitol
struck
gas
in
the
area
of
the
block
which
became
the
Sankofa
oil
field.
As
is
customary
in
this
industry,
Vitol
sold
a
piece
of
the
block
to
Eni,
in
the
process
sharing
the
financial
risk
and
enabling
an
injection
of
further
capital
to
develop
the
block
towards
production.
With
further
exploration,
oil
was
also
discovered
in
the
area
in
2012.

Three
years
later,
the
World
Bank
provided
political
risk
guarantees
totaling
$700
million
(believed
to
be
the
largest
ever
such
commitment
by
the
Bretton
Woods
institutions
to
a
capital
project).
Further
loans
from
the
IFC
and
other
parties
to
Vitol
and
Eni
underwrote
a
program
of
investment
leading
to
oil
production
in
2017
and
gas
production
in
2018.
The
World
Bank
estimated
total
project
costs
at
$7.7
billion
(of
which
it
was
responsible
for
mobilising
about
$1.27
billion).
Eni,
on
its
part,
has
reported
total
expenditure
to
date
of
$6
billion,
and
a
revised
project
life-cycle
capital
expenditure
of
$10
billion.

The
Eni
consortium
companies
see
themselves
as
deserving
credit
for
having
brought
the
biggest
single
overseas
investment
to
Ghana
to
develop
a
risky
and
highly
complex
asset.

The
Springfield
Afina
Discovery

In
the
same
2015
that
the
Eni
consortium
began
drilling
operations
following
the
earlier
approval
of
the
plan
of
development
by
the
Government
in
2014,
the
Springfield
upstream
story
began
in
earnest.

Two
years
earlier,
in
December
2013,
Kosmos
Energy
had
to
give
up
a
part
of
the
West
Cape
Three
Points
block
because
under
Ghanaian
law
a
company
is
time-bound
to
explore
for
oil
and
develop
any
quantity
found,
or
it
must
relinquish
parts
of
the
block
on
which
it
has
not
hit
commercially
exploitable
oil.

The
1.37
square
kilometers
of
seabed
given
up
by
Kosmos
in
this
fashion
was
split
into
two
new
blocks
and
companies
invited
to
bid
for
both.
About
12
companies
expressed
interest,
Springfield
being
one.
In
April
of
2014,
Springfield
was
thus
allowed
access
to
the
GNPC
data
room
to
evaluate
the
cumulated
data
on
the
two
blocks
gathered
by
previous
lessees.

Springfield
came
to
GNPC
with
the
Taleveras
Group,
a
company
part-owned
by
Nigerian
tycoon,
Igho
Sanomi.
In
June
2014,
Taleveras
was
introduced
as
the
technical
partner
that
will
operate
any
blocks
awarded
the
consortium.
Unfortunately,
soon
thereafter,
Taleveras
began
to
experience
serious
financial
challenges,
culminating
in
a
string
of
legal actions around the
world.
Not
surprisingly,
the
Evaluation
Committee
disqualified
it
as
the
Technical
Operator
for
lack
of
relevant
experience
and
financial
capacity,
and
decided
to
limit
Springfield’s
bid
to
block
2
alone.

Hence,
in
October
2014,
Springfield
introduced
a
new
Technical
Operator,
Vaalco
Energy,
a
small,
Houston-based,
Gabon
focused
oil
junior.
Vaalco
had
some
requisite
experience
(it
was
Hunt’s
partner
during
a
small
seismic
campaign
in
Ghana
as
far
back
as
1999)
and
was
thus
acceptable
to
the
Committee.
But
just
before
the
Committee
could
complete
its
evaluation,
Vaalco
also
decided
to
pull
out
as
the
Technical
Operator.

Here
is
where
Springfield’s
exceptional
tenacity
comes
into
the
picture.
They
convinced
the
Committee
and
the
Ministry
of
Energy
to
award
them
the
block
nonetheless
pending
the
onboarding
of
a
Technical
Operator.
The
Committee
agreed
and
in
turn
convinced
Parliament
to
ratify
Springfield’s
Petroleum
Agreement
with
the
Government,
but
with
a
caveat.
Springfield
was
asked
to
find
a
Technical
Operator
within
a
year.
The
Ghanaian
model
contract
gives
an
oil
company
7
years
to
find
oil
anyway,
with
room
for
extension
under
certain
conditions.

Springfield
succeeded
in
convincing
the
Ministry
of
Energy
and
the
GNPC
to
allow
it
to
continue
to
explore
and
operate
the
block
without
a
formal
Technical
Operator
on
the
basis
that
oilfield
services
contractors,
like
Schlumberger,
will
more
or
less
play
that
role
despite
the
lack
of
official
designation.
Furthermore,
it
had
set
up
a
technical
services
company
itself
called
Fairfax
and
also
intended
to
form
a
joint
venture
with
Aker
Solutions,
the
Norwegian
equipment
player,
to
explore
capacity
development
for
exploration
and
production.

After
a
3D
seismic
mapping
exercise
involving
the
giant
Ramfom
Titan
in
2017,
it
secured
the
necessary
regulatory
approvals
for
drilling.
Now
primed,
Springfield
secured
a
rig
to
drill
two
wells
in
August
2019.
The
initial
plan
was
to
mirror
a
discovery
in
the
adjacent
ENI
block
(discussed
above)
called
Beech
by
targeting
a
well
named
Oak-1x
before
targeting
the
Afina-1x
well.
Somehow,
the
campaign
was
reduced
to
just
one
well,
Afina,
and
after
64
days
of
drilling,
the
targeted
depth
was
reached
in
November
2019.

False
starts
notwithstanding,
just
before
Christmas
2019,
Springfield
announced
with
massive
fanfare
the
discovery
of
1.5
billion
barrels
of
oil
in
its
budding
Afina
field.

No
doubt
that
Springfield
sees
itself
as
a
highly
tenacious,
groundbreaking,
visionary
African
oil
pioneer
that
will
stop
at
nothing
to
realise
its
dream
to
become
the
first
African
operator
of
a
massive
ultra
deepwater
block.

Legal
&
Engineering
Best
Practices

After
a
new
oil
find,
Ghanaian
law
requires
oil
companies
to
“appraise”
it.
This
is
such
a
critical
point
in
this
story
that
it
merits
quoting
the
relevant
portion
of
the
law.
Appraisal
is
defined
as:

           “operations
or
activities
carried
out
…following
a
Discovery
of
Petroleum
for
the
purpose
of
delineating
the
accumulations
of
Petroleum
to
which
that
Discovery
relates
in
terms
of
thickness
and
lateral
extent
and
estimating
the
quantity
of
recoverable
Petroleum
therein,
and
all
operations
or
activities
to resolve
uncertainties
required
for
determination of
a
Commercial
Discovery”.

It
is
worth
noting
the
boldened
portion
of
the
definition
above.
A
major
part
of
the
dispute
arbitration
commenced
by
Eni-Vitol
may
well
turn
on
the
meaning
of
this
sentence.

More
so
because
the
famous
Article
8
of
the
model
Petroleum
Agreement
sets
conditions
for
unitization
hinged
on
this
basic
prerequisite
(various
relevant
extracts):

           “As
soon
as
possible
after
the
analysis
of
the
test
results
of
such
Discovery
is
complete,
and
in
any
event
not
later
than
one
hundred
(100)
days
from
the
date
of
such
Discovery,
Contractor
shall
by
a
further
notice
in
writing
to
the
Minister,
the
Petroleum
Commission,
and
GNPC,
indicate
whether
in
the
opinion
of
Contractor
the
Discovery
merits
Appraisal.

…
Where
the
Contractor
does
not
make
the
indication
required
by
Article
8.2
within
the
period
indicated
or
indicates
that
the
Discovery
does
not
merit
Appraisal,
Contractor
shall,
subject
to
Article
8.19,
relinquish
the
Discovery
Area
associated
with
the
Discovery.

…In
the
event
a
field
extends
beyond
the
boundaries
of
the
Contract
Area,
the
Minister
may
require
the
Contractor
to
exploit
said
field
in
association
with
the
third
party
holding
the
rights
and
obligations
under
a
petroleum
agreement
covering
the
said
field
(or
GNPC
as
the
case
may
be).
The
exploitation
in
association
with
said
third
party
or
GNPC
shall
be
pursuant
to good
unitization
and
engineering
principles
and
in
accordance
with
International
Best
Oil
Field
Practice.

…Where
Contractor
indicates
that
the
Discovery
merits
Appraisal,
Contractor
shall
within
one
hundred
and
eighty
(180)
days
from
the
date
of
such
Discovery
(or,
in
the
case
of
the
Existing
Discoveries,
within
nine
(9)
months
from
the
Effective
Date)
notify
the
Minister
and
submit
to
the
Petroleum
Commission
for
approval
and
to
the
Minister
for
information
purposes
a
Proposed
Appraisal
Programme
to
be
carried
out
by
Contractor
in
respect
of
such
Discovery.”

Model
clauses
from
Ghana’s
petroleum
contracting
regime

Here
too,
the
boldened
text
–
“good
unitization
principles
&
international
Best
Oil
Field
Practice”
–
is
the
fulcrum
around
which
the
arbitration
about
to
commence
in
London
will
turn.

Is
Afina
a
commercial
discovery?
Are
the
directives
by
the
Minister
for
the
ENI
consortium
and
Springfield
to
compulsorily
unitise
their
separate
finds
on
grounds
of
“straddling”
following
International
Best
Oil
Field
Practice?
Can
a
find
that
has
not
yet
been
established
as
commercial
through
appraisal
be
made
part
of
any
other
arrangement,
including
field
unitisation,
considering
the
language
of
the
provision?

Obviously,
it
would
be
imprudent
to
make
categorical
pronouncements
now
that
the
matter
is
in
arbitration.
But
we
can
explore
certain
critical
aspects
to
gauge
whether
things
should
even
have
been
allowed
to
go
this
far.

The
Fracas
Begins

The
complications
arose
a
few
months
after
Springfield’s
announcement
in
December
2019
that
it
had
made
a
massive
find
containing
1.5
billion
barrels
of
oil.
A
field
containing
that
amount
of
oil
is,
with
virtual
certainty,
a
commercial
discovery.

Whilst
the
determination
of
whether
an
oil
find
is
commercial
is
driven
by
multiple
factors
such
as
the
prevailing
oil
price,
the
complexity
of
the
reservoir
(which
will
impact
costs)
and
the
distance
to
production
facilities
or
need
for
totally
new
infrastructure,
volumes
and
the
certainty
of
recovering
those
volumes
are
by
far
the
most
commercially
sensitive
parameter.

Springfield’s
initial
estimate
of
1.5
billion
barrels
was
followed
by
a
claim
that
the
find
it
had
made
is
in
fact
connected
to
the
Sankofa
East
field
in
the
ENI
consortium’s
block
(Springfield
would
later
reveal
that
it
had
suspected
this
from
geophysical
analysis
since
2018).

Following
a
formal
application
by
Springfield
for
unitization,
the
Minister
of
Energy,
on
9^th April
2020, issued a
directive
pursuant
to
Section
50
of
the
2018
petroleum
regulations
requiring
Eni
and
Springfield
to
unify
their
finds.

The
interesting
thing
about
Section
50
is
that
it
does
not
elaborate
on
the
preconditions
of
commerciality
mentioned
in
the
Model
Petroleum
Agreement
nor
does
it
touch
on
the
role
of
appraisal
in
establishing
the
equity
split
(or
“unit
interests”).
It
primarily
focuses
on
the
Minister’s
powers
to
issue
model
contracts
specifically
for
unitisation.

Eni
insisted
that
both
appraisal
and
commerciality
were
critical
factors
in
any
unitization
process
and
refused
to
budge.
So,
on
29^th July
2020,
the
Chief
Director
of
the
Ministry
of
Energy
wrote
a
second
letter
to
the
two
companies
lamenting
their
refusal
to
share
data
and
the
general
lack
of
cooperation.
Springfield
says
that
it
persistently
pursued
ENI
for
a
meeting
with
scant
results.
Vitol,
the
other
main
half
of
the
ENI
Consortium,
responded
to
the
Ministry
that
Springfield
had
already
proceeded
to
the
High
Court
in
an
attempt
to
enforce
the
order
to
unitise.

On
19^th August
2020,
the
Minister
again
wrote
to
the
ENI
consortium
that
it
is
engaging
an
independent
third
party
to
review
the
claims
of
the
two
parties
and
will
impose
the
findings
once
they
were
ready.

Meanwhile,
the
parties
had
so
far
failed
to
sign
a
confidentiality
agreement
for
data
exchange
to
commence.
Consequently,
on
14^th October
2020,
the
Minister
imposed
conditions
for
the
unitization.
Eni
and
Vitol
continued
to
insist
that
as
far
as
they
were
concerned
the
basis
for
unitization
had
not
been
established
by
sound
engineering
principles
and
data.

It
is
critical
at
this
juncture
to
establish
that
whilst
the
Minister’s
14^th October
order
imposing
terms
for
the
unitization
was
based
on
a
6^th October
technical
report
by
the
GNPC,
his
9^th April
order
appears
to
have
been
triggered
primarily
by
the
Springfield
application
without
any
comprehensive
technical
evaluation
of
the
latter’s
claims.

Readers
would
notice
that
the
14^th October
order
was
merely
laying
out
terms,
including
crucial
determinations
about
unit
interest
(how
much
equity
two
parties
–
ENI+Vitol
and
Springfield
–
stood
to
gain
in
the
unitized
field),
for
a
directive
that
had
already
been
made.

It
will
weigh
heavily
on
the
minds
of
the
arbitrators
that
the
substantive
9^th April
directive
itself
was
made
before
an
independent
technical
evaluation
of
the
claims
of
Springfield
in
its
application
for
unitization
to
the
Ministry
claiming
that
its
Afina
find
was
connected
to
ENI’s
Sankofa
East
field.
The
Arbitrators
are
also
likely
to
ponder
if
GNPC,
an
entity
with
commercial
interest
in
the
fields
in
contention
(and
therefore
potential
bias
for
one
partner
over
the
other)
could
be
considered
an
“independent
third
party”
to
provide
a
technical
assessment
that
could
rewrite
the
commercial
rights
and
entitlements
of
its
partners.

With
those
important
observations
in
the
background,
we
can
now
turn
to
the
6^th October
technical
report
from
the
GNPC
based
on
which
Ghana
decided
to
divvy
up
a
future
combined
Sankofa-Afina
field
between
Eni-Vitol
and
Springfield,
with
Springfield
getting
a majority stake
of
54.5%.

Illustrative
Chart
of
the
Equity
Split
Imposed
by
Government
on
the
Future
Combined
Field

Block Owner/Lessee	OCTP Participation (%)	WCTP-2 (New Discoveries)* Participation (%)	Total Unit Interest (Sankofa-Afina Merged Unit)
ENI	44.44		~17.5%
Vitol	35.56		~14%
GNPC	14	11	10%
Explorco	5	5	4%
Springfield		84	54.5%

The
GNPC
report
asserts
in
its
executive
summary
that
the
two
finds
–
Eni-Vitol’s
Sankofa
East
and
Springfield’s
Afina
–
are
indeed
connected
(both
emanate
from
a
common
reservoir
straddling
their
separate
blocks).
It
also
states
that
based
on
analysis,
the
P90
case
(the
lower
bound
of
estimates
or
the
quantity
that
has
at
least
a
90%
probability
of
being
produced
or
exceeded)
for
how
much
oil
is
in
the
Springfield
side
of
the
common
reservoir
is 290
million barrels,
whilst
the
mean
case
puts
the
oil
in
place
at 642
million
barrels (revised
upwards
from
the
506
million
barrels
estimated
from
earlier
3D
seismic
analysis).

Extract
from
the
fateful
GNPC
6th
October
Report

The
important
matter
here
is
the
applicability
of
the
International
Good
Oilfield
Practice
(IGOP)
requirement
in
Ghana’s
petroleum
regime
as
indicated
in
earlier
sections.
The
classification
of
reserves
by
probabilistic
scenarios
like
P10,
P50
and
P90
is
not
an
arbitrary
process.
It
follows
well
laid
down
IGOP
guidelines
in
the
Society
of
Petroleum
Engineers framework for
classification.
Such
guidelines
are
of
course
the
very
types
of
doctrines
and
principles
constituting
the
bedrock
of Lex
Petrolea,
or
international
petroleum
law,
the
domain
of
norms
governing
the
ongoing
Eni-Vitol
–
Government
of
Ghana
dispute
arbitration
currently
underway
in
London.

The
key
issue
in
reserves
classification,
as
a
matter
of
global
practice,
is the
narrowing
of
uncertainties
and
unrisking.
In
this
discussion,
we
have
witnessed
a
progressive
narrowing
of
Springfield’s
initial
communication
of
P50
reserves
of
1.5
billion
barrels
of
oil
in
place
to
GNPC’s
estimate
of
642
million
barrels
in
place.
Eni’s
corresponding
P50
number
of
535
million
barrels
in
place,
on
the
other
hand,
has
gone
up
from
an earlier estimate
of
450
million
barrels
of
oil
equivalent
(BOE)
in
2013
to
535
million
BOE after
20
wells
drilled
and
consistent
production
of
more
than
3
years.

The
question
that
will
weigh
on
the
minds
of
the
arbitrators
is
whether
GNPC’s
approach
to
P90
and
P50
classifications
is
solidly
grounded
in
international
standards
seeing
the
wide
uncertainty
ranges
on
display.

All
this
while,
due
to
the
disagreements
over
confidentiality,
Eni
had
not
actually
received
the
information
based
on
which
these
determinations
by
GNPC
and
the
Ministry
were
being
made.
Finally,
on
23^rd March
2021,
the
Minister
decided
to
instruct
the
Petroleum
Commission
to
hand
over
the
data
on
Springfield’s
Afina
to
Eni
under
a
confidentiality
agreement
signed
with
the
Commission
(as
opposed
to
Springfield).

On
26^th April
2021,
Eni
and
Vitol
(for
simplicity
sake,
we
shall
sometimes
refer
to
the
Consortium
simply
as
“Eni”
going
forward)
concluded
its
analysis
of
the
data
and
submitted
a
report
containing
a
startling
claim
to
the
Ministry:
in
its
view,
Springfield’s
Afina
find
is
so
small
it
may
not
even
be
commercial
after
all
(i.e.
it
may
not
be
economically
profitable
to
be
produced).

Because
Ghanaian
law
does
not
require
finds
made
in
two
adjacent
blocks
to
be
directly
connected
before
a
finding
can
be
made
that
they
are
best
produced
as
one
field,
the
technical
debate
till
then
had
focused
on
whether
there
was
even
any
merit
in
the
investigation
into
whether
Afina
and
Sankofa
were
really
linked
geologically.
The
dimension
of
non-commerciality
now
took
center-stage
and
shook
up
the
premises
of
the
debate.

Eni’s
analytical
posture
in
the
26^th April
report
starts
with
a
sketch
of
the
geology
of
the
border
between
the
two
adjacent
blocks.
Per
this
analysis,
the
closer
one
moves
westward
from
the
Sankofa
East
area
to
the
Afina
find
area,
the
poorer
the
petrophysical
properties
become
reducing
to
an
extent
the
likelihood
of
the
presence
of
a
continuous
geological
structure.
Accordingly,
Afina,
compared
to
Sankofa
East,
has
much
greater
mud
contamination
in
its
hydrocarbon
columns.
Thus,
whilst
the
rocks
in
both
fields
may
be
of
similar
origin
and
could
have
matured
through
time
by
means
of
similar
geological
processes,
the
evidence,
says
Eni,
does
not
yet
confirm
that
the
two
reservoirs
are
actually
connected.

In
line
with
these
arguments,
Eni
then
brought
up
the
issue
of
why
the
Afina
well
has
so
far
not
been
tested.
After
all,
the
flow
rate
would
have
helped
further
reduce
the
uncertainties
involved.
Bearing
in
mind
that
on
average
5
wells
are
drilled
to
establish
commerciality
in
many
similar
contexts,
to
use
one
untested
well
as
the
basis
for
firm
estimates
is
pushing
the
envelope.

A
more
technical
argument
related
to
why
certain
production
activities
on
the
Eni
side
were
not
impacting
on
pressure
observations
on
the
Afina
side.
But
by
far
the
most
aggressive
claim
in
Eni’s
26th
April
report
was
the
assertion
that
rather
than
the
GNPC
estimate
of
642
million
barrels
of
oil
in
place
in
the
P50
case,
a
more
reliable
estimate
would
be 94
million
barrels,
which
under
present
conditions
may
not
even
be
worth
developing
for
production.

If
Eni
really
believes
this,
it
is
completely
ridiculous
for
anyone
to
have
assumed
on
the
Government
of
Ghana
side
that
any
amicable
solution
could
be
found
whilst
compulsory
unitization
was
still
on
the
table.
Below
is
a
very
crude
calculation
that
nevertheless
illustrates
the
commercial
impracticality
of
expecting
either
Springfield
or
Eni
to
play
ball
along
conventional
unitization
lines.
For
reasons
of
simplicity,
the
calculation
looks
at
the
nominal
value
(without
accounting
for
inflation
or
the
time
value
of
money)
of
the
oil
in
the
two
adjacent
fields.
It
also
ignores
production
costs
in
both
the
status
quo
scenario
and
the
scenario
in
which
the
unitization
proceeds.
Whilst
it
far
from
an
NPV+
calculation,
it
still
serves
the
purposes
of
illustration
fairly
well
because
it
is
strictly
from
Eni’s
view,
and
thus
assumes
no
savings
from
unitization.

Eni’s
Oil-in-Place
Nominal
Valuation
Scenario

Block Owner/Lessee	Total Unit Interest (Sankofa-Afina Merged Unit)	Nominal Economic Value of Interest Post-Unitisation	Economic Value of Interest Pre-Unitisation	Economic Impact of Unitisation
Eni	~17.5%	$5.162 Billion	$11.11 Billion	-$5.948 Billion
Vitol	~14%	$4.13 Billion	$8.89 Billion	-$4.76 Billion
GNPC	10%	$2.95 Billion	$2.95 Billion	0
Explorco	4%	$1.18 Billion	$2.43 Billion	-1.25 Billion
Springfield	54.4%	$16.07 Billion	$3.78 Billion	+12.29 Billion

From
Eni’s
standpoint
the
unitization
is
heavily
tilted
towards
Springfield
and
offers
it
nothing
besides
nearly
$6
billion
in
asset
losses.
Together
with
Vitol,
it
stands
to
lose
more
than
$10
billion
should
the
unitization
proceeds.
While
Ghana
would
like
to
couch
the
forced
unitisation
as
a
technical
regulatory
matter,
the
prospect
of
large
financial
losses
invokes
some
comparisons
with expropriation,
a
well
travelled
area
in
the
growing
body
of Lex
Petrolea. In
short,
in
Eni’s
eyes,
the
unitisation
is
tantamount
to
Ghana
taking
half
of
its
find
and
giving
it
to
another
company.

In
the
same
vein,
Springfield
stands
to
gain
more
than
$12
billion
in
this
scenario.
Since
none
of
the
current
unitisation
models
on
the
table
contain
a
scenario
in
which
Springfield
is
worse
off,
it
stands
to
reason
that
Springfield
will
stand
its
ground. Its
position
is
perfectly
logical and,
in
fact,
is
to
be
expected.

GNPC,
the
House
of
Supreme
Incompetence

The
conduct
of
the
private
companies
is
completely
understandable
from
a
cursory
review
of
the
scenarios
above.

If
GNPC’s
view
is
correct
and
Springfield’s
Afina
has
642
million
barrels,
Springfield
gets
its
just
share
from
the
initial
tract
participation
(i.e.
the
equity
split
of
54.5%
–
44.5%
in
its
favour)
but
if
Eni’s
more
pessimistic
view
turns
out
to
be
right,
Springfield
gets
a
$12
billion
windfall.

Whilst
the
Minister’s
terms
include
the
standard
“redetermination”
provision,
whereby
these
equity
splits/unit
interests
could
be
revised
in
light
of
new
data,
within
an
18-month
timeline,
the
order
falls
far
short
of
international
best
practice
in
how
redetermination
of
international
tract
participation
is
to
be
managed.

First,
a
Preliminary
Unitisation
Agreement
would
normally
be
constructed
very
differently
from
the
outright
Unit
and
Unit
Operating
Agreement
the
Minister
sought
to
impose
through
his
order.
Such
an
agreement
will
seek
to
establish
the
full
extent
of
the
common
reservoir
in
order
to
determine
the
Initial
Tract
Participation
(ITP).
The
ITP
would
not
be
imposed
as
a
fait
accompli
prior
to
any
Preliminary
Agreements
on
the
approach
to
embarking
on
the
road
to
unitisation.

Second,
a
cost
sharing
provision
would
be
necessary
at
the
preliminary
level
to
cover
the
additional
costs
of
reservoir
modeling.
Under
no
circumstances,
judging
from
the
picture
that
emerges
from
a
scan
of
dozens
of
relevant
case
studies
in
IHS’
commercial
PEPS
databases,
can
a
pre-unitisation
agreement
(PUA)
even
be
entered
into
without
preliminary
agreements
on
joint
data
collection,
which
in
this
case
would
include
some
appraisal
work.
It
is
the
PUA
that
sketches
both
the
“unit
interval”
and
the
initial
unit
interests
for
subsequent
confirmation.
Not
arbitrary
reports
by
National
Oil
Companies
aiming
to
short-circuit
the
path
to
a
Unit
&
Unit
Operating
Agreement
(UUOA).

It
is
also
the
PUA
that
establishes
the
working
groups
within
an
atmosphere
of
mutual
trust
and
confidence
to
enter
serious
discussions
for
final
unitization.
One
of
the
key
tasks
facing
such
a
working
group
(for
example,
a
Pre-Unitisation
Operating
Committee)
is
the
thorny
issue
of
historic
capex
that
would
have
contributed
to
the
overall
commerciality
of
the
combined
field.
In
this
case,
we
have
one
field
that
has
already
incurred
costs
in
excess
of
$6
billion.
The
Minister’s
directive
by
focusing
purely
on
historic
production
numbers
without
addressing
historic
capital
expenditure
showed
considerable
misunderstanding
of
the
issues
at
stake.

Another
source
of
confusion
is
the
lack
of
clarity
on
the
role
of
truly
independent
experts
in
the
redetermination
process.
We
can
dismiss
out
of
hand
the
notion
of
a
National
Oil
Company
serving
as
both
participating
interest
holder
and
an
independent
expert
offering
mediation
services
in
a
fraught
matter
such
as
this.

In
a
situation,
such
as
this
one,
where
the
Joint
Database
of
production
and
appraisal
data
reflects
activities
to
prove
reserves
by
one
party
and
almost
none
by
the
other
party,
one
wonders
why
a
uniform
redetermination
provision
makes
sense.
And
what
if
a
redetermination
in
18
months
results
in
a
drastic
reallocation
of
historic
production
numbers
from
the
deemed
majority
holder
to
the
minority
holder?
Are
both
parties
equally
placed
to
take
the
financial
hits?
The
degree
of
complexity
introduced
by
trying
to
unitise
an
already
producing
field
with
one
that
has
not
even
been
appraised
requires
a
level
of
sophistication
in
designing
preliminary
frameworks
that
was
wholly
absent
in
the
Minister’s
proposed
terms.

Ghana’s
refusal
to
stick
to
these
common
global
practices,
egged
on
by
the
GNPC,
was
bound
to
lead
all
parties
to
the
current
impasse.

But
why
heap
most
of
the
blame
on
GNPC?

Much
of
the
justification
for
blaming
GNPC
is
best
illustrated
by
its
24^th May
2021
response
to
Eni’s
assessment
of
Springfield’s
Afina
data.
The
tone
of
this
rather
shoddy
piece
of
work
was
not
merely
cavalier
and
perfunctory,
but
also
unanalytical.

Confronting
the
issue
of
why
a
well
test
has
not
been
conducted
at
Afina,
GNPC
airily
dismisses
the
point
by
citing
“value
for
money”.
In
what
world
does
testing
a
well
in
a
field
declared
as
suitable
to
be
combined
with
another
field
for
joint
production
not
“value
for
money”
when
any
data
so
collected
would
go
to
improve
the
eventual
common
reservoir
model?

On
the
extremely
critical
issue
of
how
much
oil
is
in
the
Afina
find,
GNPC
beat
about
the
bush
with
speculations
about
possible
differences
in
areas
used
in
computation.
No
effort
is
made
to
actually
address
any
discrepancies
that
could
have
resulted
from
such
speculated
geometric
causes.
They
then
quickly
retreat
to
the
ridiculous
mantra
that
producing
best
estimates
of
oil
in
place
is
a
“post-unitisation”
matter.
That
is
to
say,
the
parties
should
just
give
up
their
rights
on
the
say-so
of
the
GNPC
and
the
Minister
and
the
calculations
can
come
later.

Having
been
blatantly
caught
out
for
discrepancies
in
their
use
of
inferences
about
the
oil
and
water
contact
dynamics
and
compositions
in
the
hydrocarbon
column,
GNPC
barefacedly
mumbles
something
about
using
data
from
other
nearby
structures
to
approximate
the
drivers
of
the
volumetric
figures.
It
is
absolutely
elementary
in
reservoir
estimation
to
be
confident
about
“fluid
contacts”
data.
The
dismissive
approach
GNPC
took
to
this
issue
alone
would
absolutely
have
strongly
reinforced
perceptions
of
unprofessionalism
and
bias.

As
a
further
sign
of
incompetence,
GNPC
does
not
include
in
any
of
its
technical
evaluations
to
the
Minister
the
actual
implication
of
unitization
for
Ghana’s
own
fiscal
situation.
As
the
crude
nominal
valuation
analysis
above
shows,
it
is
entirely
possible
for
Ghana
to
lose
money
(due
to
the
relative
differences
in
participating
interest
in
the
pre-unitisation
tracts)
–
maybe
up
to
25%
–
if
Eni’s
numbers
turn
out
to
be
correct.
In
these
circumstances,
why
would
a
National
Oil
Company
breezily
argue
that
sound
estimation
of
commerciality
is
irrelevant
in
an
assessment
of
unitization?

The
only
sound
and
professional
thing
for
GNPC
to
have
done
when
the
Minister
referred
the
matter
for
advice
was
to
lay
out
the
requisite
preparatory
work
needed
ahead
of
a pre-unitisation
agreement.
As
the
organization
relied
upon
by
the
government
for
technical
insight
into
the
petroleum
business,
it
was
GNPC’s
duty
to
know
and
to
advise
that
a
rush
towards
a
Unit
and
Unit
Operating
Agreement
was
completely
immature
when
the
global
best
practice
is
to
establish
a
preliminary
framework
within
which
issues
of
commerciality
and
optimal
recovery
can
be
thrashed
out
in
an
atmosphere
of
mutual
trust
and
confidence.

By
persistently
pushing
the
thesis
that
all
commercial
determinations
must
happen
“post-unitisation”,
GNPC
proves
itself
to
be
a
wholly
provincial,
unsophisticated,
and
even
oafish
National
Oil
Company
that
cannot
be
relied
upon
to
guide
our
political
leaders
to
make
the
right
decisions
for
harnessing
our
national
energy
resource
endowment.

The
conduct
of
GNPC
invokes
comparison
with
that
of
Pemex,
Mexico’s
National
Oil
Company,
which
has
led
to
a
similar
international dispute about
the
operatorship
of
the
Zama
field.
A
general
approach
of
disregarding
international
best
practices
has
led
to
a
Pemex
that
has
been
ranked
as
the
world’s
most
indebted
oil
company,
perpetually
struggling
to
fund
its
capital
expenditures.

It
is
clear
that
Ghana
must
follow
the
footsteps
of
Brazil
and
India
and
establish
a
technical
agency
for
hydrocarbons
(like
Brazil’s
ANP)
that
is
focused
on
providing technical policy
leadership in
the
petroleum
sector
(not
merely
exercising
regulatory
oversight
like
the
Petroleum
Commission)
instead
of
one
suffering
from
the
schizophrenia
of
combining
commercial
hubris
with
technical
policy
savvy.

Of
course,
the
culture
and
mandate
of
the
Petroleum
Commission
can
also
be
transformed
for
it
to
take
over
from
the
GNPC
the
role
of
providing
technically
sound,
professional
unbiased,
purely
national
interest
driven,
policy
advice
to
the
Government.

If
this
does
not
happen
soon,
GNPC’s
reckless
conduct
will
not
only
end
up
embarrassing
the
country,
it
will
one
day
cost
all
of
us
billions
of
dollars
we
can
ill
afford.

Source
Bright
Simons,
a
Vice
President
of
IMANI
Africa