Well here is issue 5. Not surprisingly as we progress and build on the previous elements of the emissions model, it gets more detailed. That said, I have still tried to be concise and coherent. Enjoy.

1. E|MISSION Statement ™
EMAIL enquiries@our-
future.co.uk
ISSUE
05
The
‘Emission
Statement’
sets
out
to
provide
a
view
of
the
application
and
potential
for
carbon
mitigating
technologies
as
they
strive
to
find
commercial
value
propositions
that
are
considered
supportable
by
policy
makers,
treasuries
and
tax
payers.
The
aspiration
from
publishing
such
a
document
is
not
to
provide
an
oracle
or
prescriptive
roadmap
for
clean
technology
development.
Instead
it
is
offered
as
a
simple
pragmatic
framework
for
all
stakeholders
to
be
able
to
consider
such
developments.
Far
too
frequently
the
complexity
of
situations
is
over
analysed
to
the
extent
it
creates
barriers
to
progress.
As
with
the
‘Engineering
of
Things’
(“EoT”)
though,
simplification
and
the
pursuit
of
solutions
can
be
much
more
productive
and
is
the
foundation
with
which
the
‘Emission
Statement’
is
presented.
Infrastructure
As
the
Emission
Statement
has
advanced
through
an
understanding
of
Application
and
Technology
Design
for
a
cleaner
energy
structure,
we
have
highlighted
the
involvement
of
national
government
in
providing
a
framework
(i.e.
policy
and
legislation)
and
funding
to
stimulate
the
transition
to
a
lower
emissions
future;
whether
such
mechanisms
are
targeted
at
CADS
or
PAPS.
With
consideration
of
the
criterion
of
Infrastructure,
this
is
where
these
two
interventions
of
framework
and
funding
materially
precipitate,
which
is
not
surprising,
because
internationally
such
infrastructure
are
still
or
were
originally
national
assets.
To
demonstrate
the
impact
of
infrastructure,
and
provide
continuity
to
illustrating
our
approach,
we
will
continue
to
use
the
UK
as
a
reference
case.
©
and
™
GB
Management
Services
Ltd
GB
Management
Services
Ltd
offers
consultancy
services
related
emissions
reduction,
process
and
operations
improvement,
and
the
development
clean/renewable
technology
projects.
Contact
Details:
Grant
Budge
Mobile:
+44
(0)
7780
920504 Email:
gbudge@our-­‐future.co.uk
Risk
Management
46%
21%
25%
3% 5%
Domestic0Gas
Supply0Costs
Wholesale(Price
Network(Costs
Supplier(Cost(and(margin
Energy(&(Climate(Change(
Policies
37%
24%
22%
12%
5%
Domestic0Electricity0
Supply0Costs
Wholesale(Price
Network(Costs
Supplier(Cost(and(margin
Energy(&(Climate(Change(
Policies
Before
we
look
at
the
UK
from
an
energy
infrastructure
perspective,
let
us
first
illustrate
why
good
infrastructure
decision
making
is
so
important.
To
the
right
we
provide
two
charts
detailing
energy
supply
costs;
one
for
gas
and
one
for
electricity.
Between
them
Network
Costs
– which
are
the
national
and
regional
transmission/distribution
costs
– account
for
an
average
23%
of
a
households
energy
bill.
In
addition,
the
Wholesale
Costs
that
are
shown,
are
the
costs
for
electricity
and
gas
at
the
point
it
enters
into
the
national
transmission/distribution
network.
The
reason
that
is
important,
is
because
it
already
includes
for
costs
of
production
based
infrastructure.
Combining
these
two
elements,
it
can
be
shown
that
up
to
43%
of
our
total
energy
costs
are
recovering
expenditure
for
the
development
and
maintenance
of
infrastructure.
As
such,
when
infrastructure
decisions
are
made,
they
lock
in
costs
for
generations
to
come;
and
the
full
weight
of
those
decisions
are
borne
by
the
consumer
i.e.
Inefficiencies
in
the
system
created
by
unreliable
or
unpredictable
energy
supply,
force
reliable
back-­‐up
capacity
to
be
available;
and
poor
national
strategy
and
project
locations
embed
unnecessary
connection,
distribution
and
transmission
costs.
Every
less
than
optimal
decision
further
gilds
the
magnitude
of
these
long-­‐term
costs.

2. ©
GB
Management
Services
Ltd
Contact
Details:
Grant
Budge
Mobile:
+44
(0)
7780
920504 Email:
gbudge@our-­‐future.co.uk
E|MISSION Statement ™
For
many
countries,
including
the
United
Kingdom,
Demand
Reduction
and
Source
Substitution
programmes
have
already
yielded
environmental
benefits;
and
the
realisation
that
the
more
challenging
pathways
now
need
to
be
progressed
has
dawned.
So
how
do
we
navigate
this
challenge.
First
it
is
important
for
a
nation
to
have
completed
a
preliminary
plan
like
the
one
proposed
for
the
UK
in
Issue
4.
Following
which
they
should
profile
what
infrastructure
already
exists
to
support
that
plan.
For
our
infrastructure
review
we
will
consider
three
set
of
assets:
electricity
distribution
assets,
gas
distribution
assets,
and
large
scale
emissions
assets
(power
and
industrial).
Through
the
assessment
of
these,
we
propose
to
overlay
the
plan
detailed
in
Issue
4
and
attribute
a
geographical
basis
for
its
deployment.
At
the
heart
of
this
assessment
will
be
the
EoT philosophy
of
Core
Process
Optimisation.
The
process
here
being
how
to
best
enable
the
action
plan.
And
while
we
do
not
desire
to
become
UK
centric
in
using
the
Emissions
Model
framework,
we
will
be
cognisant
in
our
illustration
of
the
recent
Parliamentary
review
which
identified
two
significant
failures
from
state
intervention
in
the
electricity
market
so
far:
insecurity
of
supply
and
energy
prices.
The
basic
design
for
both
the
gas
and
electricity
transmission
systems
is
over
50
years
old,
and
is
geographically
based
on
a
fossil
fuel
architecture
related
to
domestic
coal
and
gas
production
regions.
Major
points
of
landfall
for
natural
gas
supplies
are
at
St
Fergus,
Easington,
Theddlethorpe and
Bacton.
These
have
more
recently
been
augmented
by
LNG
terminals
in
South
Wales
and
Kent.
And
electricity
transmission
emanates
from
the
North
East,
South
Wales,
Staffordshire,
Nottinghamshire
and
Yorkshire;
initiated
by
the
historic
coal
production
in
these
areas.
It
is
the
availability
and
development
of
this
infrastructure
that
today’s
Network
Costs
supports.
Each
time
a
new
production
asset
is
established
away
from
this
infrastructure,
new
long
term
network
costs
are
created.
While
this
has
been
inevitable
for
renewables,
nature
prescribing
their
location;
it
should
not
be
accepted
as
plans
to
continue
Source
Substitution,
and
then
deliver
Demand
Substitution,
Source
Mitigation
and
Source
Containment
are
implemented.
With
these
latter
three
in
particular,
we
should
seek
to
minimise
infrastructure
costs,
beyond
those
required
for
that
particular
Technology
Design.
So
accepting
the
network
architecture
illustrated,
how
should
Transmission) Network
Scottish( Electricity(
Transmission(System
English(Electricity(
Transmission(System
Gas(Transmission(System
Terminal
LNG(Terminal((National( Grid)
LNG(Terminal
Gas(Interconnector
Electricity( Interconnector
we
consider
the
Application
and
Technology
Design
plan,
from
a
geographic
perspective,
to
mitigate
and
minimise
incremental
costs
of
infrastructure.
For
this
we
will
address
each
element
of
the
plan
in
turn.
Source:
National
Grid
UK
Map
of
National
Gas
and
Electricity
Infrastructure

3. ©
GB
Management
Services
Ltd
Contact
Details:
Grant
Budge
Mobile:
+44
(0)
7780
920504 Email:
gbudge@our-­‐future.co.uk
E|MISSION Statement ™
Source:
Atlas
of
UK
Marine
Energy
Resources
(2004)
1. Solar
and
wind
should
be
capped
or
required
to
privately
reinvest
Due
to
the
nature
of
wind
and
solar,
there
is
little
that
can
be
done
on
a
project
basis
to
mitigate
the
influence
of
infrastructure
on
the
cost
of
supply;
optimising the
potential
for
natural
energy
being
the
primary
location
determinant.
However,
what
can
be
done,
is
to
drive
the
performance
of
such
supply.
Overloading
any
supply
chain
with
unpredictability
will
lead
to
erosion
of
system
security
and
integrity.
Where
such
issues
are
effectively
sponsored
(as
with
subsidies)
the
inevitable
response
is
to
act
to
compensate
for
these
effects,
embedding
further
cost
to
manage
the
impact,
rather
than
deal
with
the
root
cause.
This
is
EoT 101
-­‐ treat
the
root
cause
not
the
symptom.
Source
Containment
is
the
final
Technical
Design
solution
for
the
same
reason.
Renewables
must
be
a
significant
part
of
the
worlds
climate
change
strategy,
but
it
needs
to
be
value
for
money.
And
as
a
market
segment,
when
it
has
reached
25%
to
30%
of
a
national
source
of
electricity
supply;
we
would
propose
that
it
has
reached
a
point
of
maturity,
that
finding
and
funding
its
own
solution
to
market
penetration,
must
be
part
of
the
business
model.
The
UK
is
now
at
this
inflection
point.
The
solution
can
be
simple.
Set
a
performance
standard
that
all
new
projects
must
adhere
to;
and
that
all
existing
operators
must
meet
within
10
years.
We
would
propose
that
such
a
generator
standard
could
be
for
assets
to
deliver
a
minimum
power
dispatch
of
75%
of
generate-­‐able
power
to
the
grid.
Such
a
standard
would
require
asset
owners
to
invest
in
energy
storage
capability
and
would
require
independent
verification
based
on
an
agreed
industry
availability
standard,
and
local
weather
data.
But
if
implemented,
could
independently
drive
the
market
merits
of
these
renewables
beyond
a
subsidised platform.
2.
Tidal
range
should
be
prioritised
over
Nuclear
for
flexible
baseload
capacity
The
UK
is
acknowledged
to
be
home
to
50%
of
Europe’s
tidal
energy
potential.
The
two
figures
to
the
right
illustrate
the
coastal
areas
of
greatest
tidal
height
differential
(i.e.
tidal
range)
and
sub-­‐surface
water
flow
(i.e.
tidal
stream)
potential.
However,
for
now,
we
advocate
that
tidal
range
should
be
prioritised,
because
it
has
been
commercially
demonstrated
and
offers
comparable
scale
to
nuclear.
However,
before
addressing
our
proposal
to
prioritise tidal
range
over
nuclear
power,
a
statement
regarding
off-­‐shore
wind
is
considered
appropriate.
It
may
be
cited
that
the
environmental
impact
from
large
scale
impounding
of
the
sea
is
too
significant.
However,
current
best
in
class
off-­‐shore
wind
yields
around
4MW
per
square
kilometer, while
tidal
range
is
16MW.
As
such,
it
could
be
proposed
under
a
‘best
available
technology’
analysis
that
wind
has
the
potential
to
create
a
higher
environmental
impact
per
MW
produced
or
tonne of
CO2 mitigated.
So
to
nuclear,
why
should
the
UK
pursue
nuclear
without
appropriate
consideration
of
tidal
range.
As
foundation
to
this
remark,
we
summarise below
key
metrics
for
comparison
of
the
two
technologies.
With
capital
costs
of
generation
infrastructure
being
the
main
driver
of
wholesale
costs
of
supply;
then
surely
minimising these
must
be
central
to
low
cost
electricity
supply
in
the
future.
TIDAL
RANGE
Resources
TIDAL
STREAM
Resources
KPI
Comparison
Table Tidal
Range Nuclear
Total
Installed
Capital
Cost
(£/kW) 2,800
4,500
Operating
Costs
(£/kWh) 0.01 0.04
Minimum
Design
Life
(Years) >100 60
Decommissioning
Liability No Yes
Legacy
Environmental
Liabilities Limited Yes
Energy
Independence Yes No
Design
Complexity
Low High
Source
Substitution

4. Contact
Details:
Grant
Budge
Mobile:
+44
(0)
7780
920504 Email:
gbudge@our-­‐future.co.uk
E|MISSION Statement ™©
GB
Management
Services
Ltd
3.
Domestic
decarbonisation
through
hydrogen
grids
should
be
embraced
Here
the
infrastructure
costs
impact
production,
distribution
and
supply.
Demand
Substitution
by
hydrogen
also
requires
regulated
and
safe
domestic
CADS
products
to
be
available;
but
when
we
acknowledge
that
the
UK
use
to
be
heated
predominantly
by
town
gas
only
50
years
ago,
then
it
is
conceivable
that
a
pathway
for
such
products
could
be
enabled
by
a
policy
to
focus
on
heat
decarbonisation
through
hydrogen.
Infrastructure
costs
here
though
are
likely
to
be
significant
and
must
be
led
by
a
‘fit
for
purpose’
assessment
of
current
installations.
Following
a
‘fit
for
purpose’
assessment,
the
question
of
where
to
begin
arises.
Evolution
of
any
new
system
requires
careful
project
management
based
on
a
stage
gate
strategy
for
expansion.
So
to
assess
this
and
location,
we
propose
to
consider
three
factors.
First
the
profile
of
UK
carbon
emissions
sources
(see
University
College
London
map
below);
second
the
known
potential
areas
for
CO2 storage
(superimposed
below);
and
third
the
UK’s
population
density
(see
map
to
the
right).
Overlaying
these
three
criteria,
it
becomes
relatively
clear
that
a
pragmatic
and
least
cost
approach
should
be
to
focus
across
central
UK.
Demand
Substitution
Source:
Office
for
National
Statistics.
2011
Such
an
approach
would
also
allow
funding
to
be
targeted
towards
areas
which
have
sufficient
market
scale
for
products
as
well
as
for
common
national
infrastructure;
and
with
43%
of
gas
supplies
entering
through
terminals
in
the
Humberside
region,
central
UK
could
provide
a
cost
effective
centralised
location
to
enable
gas
grid
decarbonisation
and
CO2 storage.
4.
EV
and
Fuel
Cell
transport
should
be
embraced
When
we
consider
how
to
create
markets
for
both
EV
and
fuel
cell
technology,
we
again
would
review
population
density,
but
more
importantly,
look
to
ensure
that
each
element
of
the
national
plan
is
ultimately
reinforcing
and
building
on
previous
actions.
With
this
latter
objective
central
to
our
view,
we
would
propose
that
incentives
are
offered
for
hydrogen
and
fuel
cell
technology
developers
to
establish
themselves
within
the
central
UK
region.
Beyond
this,
we
would
propose
balancing
this
geographic
bias
by
providing
comparable
incentives
and
support
to
EV
infrastructure
developers
within
major
cities
where,
population
density,
shorter
average
journeys
and
restricted
car
charging
options
(i.e.
for
flats)
would
warrant
such
support.
Establishing
the
infrastructure
for
these
technologies
in
defined
areas
will
provide
investor
confidence
to
develop
and
market
their
products.Source:
University
College
London
UK
Map
of
Population
Density
CO2 Store
UK
Map
of
CO2 Emissions
Intensity
and
Storage
Locations

5. Contact
Details:
Grant
Budge
Mobile:
+44
(0)
7780
920504 Email:
gbudge@our-­‐future.co.uk
E|MISSION Statement ™©
GB
Management
Services
Ltd
Source
Mitigation
6.
CCS
should
be
prioritised
on
all
industrial
applications
where
biomass
is
used
as
a
feedstock
If
industry
has
taken
the
steps
towards
carbon
emissions
neutrality
through
the
carbon
cycle
of
biomass;
then
it
would
seem
an
appropriate
strategy
to
augment
these
facilities
and
create
carbon
negative
products,
through
the
combined
full
or
partial
application
of
CCS.
Dependent
on
the
industrial
process,
there
may
not
be
a
benefit
from
an
immediate
step
to
100%
implementation
of
carbon
capture.
In
fact
we
advocate
that
where
biomass
has
been
deployed,
post
carbon
neutral
CCS
capacity
should
be
built
up
over
time
in
line
with
market
driven
inclusion
of
the
cost
of
carbon
into
the
product
value
chain;
thus
constraining
any
premature
consumer
burden
through
taxation.
An
illustration
of
such
a
progression
is
provided
below,
where
an
Integrated
Basic
Oxygen
Steel
Mill
(production
capacity
1.6
million
tonne
per
annum),
phases
the
utilisation
of
biomass
as
a
raw
energy
feedstock;
and
the
application
of
carbon
capture
and
storage.
It
should
further
be
noted
that
it
may
also
be
possible
to
include
CO2
utilisation
up
to
Case
3,
thus
deferring
some
infrastructure
costs
and
creating
an
additional
source
of
revenue.
5.
Biomass
should
be
prioritised
for
use
in
industrial
applications
Currently
23.7
million
tonnes
oil
equivalent
of
energy
is
used
across
the
UK’s
industrial
sector.
This
demand
covers
a
variety
of
needs
as
illustrated
in
the
pie
chart
(top
right).
More
than
half
of
these
needs
could
be
supplied
through
electrification,
emissions
being
addressed
more
efficiently
upstream
in
the
energy
supply
chain;
but
process
heating
(high
and
low)
must
find
an
alternative
pathway
to
emissions
reduction.
We
mentioned
in
Issue
3,
that
direct
and
indirect
process
heating
can
impact
alternatives
available.
For
indirect
heating
where
the
energy
source
and
process
flow
do
not
make
direct
contact,
substitution
can
be
relatively
straight
forward.
But
for
direct
process
heating,
consideration
must
be
given
to
potential
contaminants,
new
or
affected
by-­‐products,
changes
to
process
productivity
due
to
rate
of
heating,
and
variations
to
charge
characteristics
or
mass
flow
rates. Source:
Digest
of
UK
Energy
Statistics
It
is
forecast
that
by
2050,
the
UK
will
be
able
to
supply
approximately
28
million
tonnes
per
annum
of
biomass;
which
at
an
average
15GJ/tonne
could
provide
420million
Giga
Joules
of
energy.
The
industrial
sector
as
a
whole
consumes
990million
Giga
Joules
of
energy
per
annum,
48%
of
which
(476
million
Giga
Joules)
is
process
heat
related
(chart
top
right).
The
fuel
used
for
process
energy
is
unclear,
but
will
predominantly
come
from
solid,
liquid
or
gaseous
fuels
(see
chart
middle
right
for
profile
of
raw
energy
use
in
the
industrial
sector).
Other
than
closure
of
assets
or
an
unparalleled
advance
in
production
technology,
few
solutions
other
than
biomass
can
support
industrial
emissions
reductions.
Considering
biomass
supply
constraints,
it
would
make
sense
to
direct
product
to
these
applications;
commencing
with
solid
fuel
switching,
ahead
of
liquid
or
gas
switching.
It
should
also
be
remembered
that
gas
switching
may
also
be
supported
by
action
3.
Source
Containment
Coal
Petroleum
Natural,Gas
Electricity
Bio4Energy
Source:
Digest
of
UK
Energy
Statistics
Scenario
Profile
Table Base
Case Case
1 Case
2 Case
3 Case
4
CO2 Produced
(tpa) 4,145,600
4,992,400
4,992,400
5,251,300
5,251,300
%
Biomass
Substitution -­‐ 23% 23% 50% 50%
%
CCS
Installed -­‐ 0% 23% 23% 50%
CO2
Avoided
(tpa) -­‐ 654,700
1,553,200
2,147,550
4,094,343
%
CO2 Avoided -­‐ 16% 37% 52% 99%
Lighting Refrigeration
Compressed2
Air
Motors
Space2
Heating
Drying2/2
Separation
Other
High2
Temperature2
Prcoess
Low2
Temperature2
Process
Industrial
Energy
Use
Industrial
Energy
Source

6. Contact
Details:
Grant
Budge
Mobile:
+44
(0)
7780
920504 Email:
gbudge@our-­‐future.co.uk
E|MISSION Statement ™©
GB
Management
Services
Ltd
Timetable
Source
Containment
(Continued)
No
matter
what
the
architecture
of
electricity
supply,
there
will
continue
to
be
a
need
for
flexible
and
rapid
response
generation.
From
a
total
installed
capital
cost,
fixed
operating
cost
and
unabated
emissions
performance
perspective,
Combined
Cycle
Gas
Turbine
(“CCGT”)
is
still
the
industry
benchmark
for
such
generation.
It
would
be
expected
that
with
a
forecast
2050
peak
electricity
demand
(including
10%
installed
capacity
margin)
of
between
110GW
and
140GW,
that
at
least
15%
of
this
should
be
flexible
rapid
response
CCGT
generation
(i.e.
up
to
16.5GW
to
21GW).
However,
despite
its
emissions
performance,
this
capacity
should
not
be
unabated
and
must
be
enabled
at
the
right
time
with
CCS.
As
such,
and
in
acceptance
of
the
preceding
actions,
it
is
proposed
that
this
infrastructure
is
developed
within
the
central
eastern
corridor
of
the
UK
– namely
Humberside/Yorkshire.
One
critical
factor
that
hasn’t
been
presented
and
that
materially
influences
this
proposed
plan,
is
time. It
takes
time
to
develop
new
infrastructure.
Concept
clearance
to
execution
of
hydrogen
gas
mains
enablement
takes
time.
Without
policy
and
strategy
to
support
its
creation,
investors
in
PAPS
and
CADS
can
not
justify
the
development
costs.
It
takes
time
to
develop
source
projects,
industrial
or
generation
(PAPS).
On
average
it
would
be
reasonable
to
say
this
period
from
idea
to
commercial
operation
would
be
a
minimum
5
years
up
to
a
maximum
of
8
years.
Such
decision
require
long
term
market
certainty,
supported
by
guarantees
that
the
biomass
supply
chain
and/or
hydrogen
grid
and/or
CO2 transport
and
storage
capacity
will
be
available.
The
objective
from
the
plan
proposed
here,
is
that
by
establishing
a
geographic
framework
alongside
a
decarbonisation
strategy,
a
national
plan
can
be
accelerated.
But
it
will
require
all
stakeholders
to
be
altruistic
and
see
that
a
race
to
be
first
is
futile,
unless
you
know
where
the
finish
line
is.
Generating
Infrastructure
Capacity
(GW)
Infrastructure
Status
Drax 3.9 Potential
CCGT
Eggborough 2 Potential
CCGT
Ferrybridge 2 Potential
CCGT
Keadby 0.7 Existing
CCGT
Saltend 1.2 Existing
CCGT
Immingham 1.18 Existing
CCGT
Thorpe
Marsh 1.5 Consented
CCGT
Hatfield 0.9 Consented
CCGT
Knottingley 1.5 Consented
CCGT
TOTAL 14.88
7.
Balance
of
installed
power
capacity
should
be
CCGT
with
CCS:
The
table
above
illustrates
the
existing
CCGT
capacity,
the
consented
CCGT
capacity
and
the
extended
generation
capacity
(i.e.
coal)
that
can
be
repurposed
within
a
1,000
square
kilometer
area
of
Humberside.
With
the
actions
detailed
under
items
3,
4
and
6
being
targeted
within
the
central
UK
region,
this
CCS
capacity
should
have
relatively
low
transport
and
storage
costs,
ensuring
such
flexible
capacity
is
best
value
for
the
consumer.
We
illustrate
below
how
this
would
work
in
practice
as
emissions
reductions
progress
through
the
sequential
actions
proposed.
0%
10%
20%
30%
40%
50%
60%
70%
80%
90%
100%
25% 50% 75% 100%
Relative(Costs(per(Tonne(Stored
Shared((Transport(and(Storage)(Infrastructure(Capacity(Utilisation,(%
Relative(Cost(per(tonne(Vs(Shared(Infrastructure(Capacity(Utilisation
30(£/t
24(£/t
18(£/t
13.5(£/t
Effective(shared(cost(of(transport(and(storage(in(£/t
Action
3
&
4
Decarbonise Heat
(Hydrogen
Grid)
Action
6
Industrial
CCS
Action
7
Power
CCS

7. Contact
Details:
Grant
Budge
Mobile:
+44
(0)
7780
920504 Email:
gbudge@our-­‐future.co.uk
E|MISSION Statement ™©
GB
Management
Services
Ltd
A
Consolidated
Infrastructure
Strategy
Through-­‐out
Issue
5
there
have
been
three
interlinked
Engineering
of
Things
basic
philosophies
that
have
filtered
through
every
element
of
the
infrastructure
design
and
progression
considered.
They
are:
Centralisation:
Centralised
solutions
are:
easier
to
implement
through
clear
strategy,
standardised
policy
and
practice:
ensures
continuity
of
approach
across
the
system:
are
easier
to
coordinate,
especially
around
budgets:
and
allow
for
quicker
decision
making.
During
the
early
stages
of
multiple
interlinked
industry
evolution,
this
is
the
most
appropriate
design
management
structure.
Economies
of
Scale:
Scale
brings
unit
cost
reductions.
Through
setting
out
a
geographic
strategy,
economies
of
scale
can
be
accelerated
across
several
actions.
These
economies
become
reinforcing,
reducing
the
state
sponsored
risk
capital
required
to
reach
a
competitive
market
place.
Shared
Infrastructure:
This
is
a
consolidation
of
the
above
two,
but
warrants
separate
identification.
With
these
three
underlying
principals
we
can
set
a
foundation
for
a
geographically
targeted
enabling
action
plan,
supported
by
an
overlapping
deployment
strategy
that
can
deliver
lowest
cost
emissions
reduction
for
the
UK’s
obligations,
from
the
end
of
the
3rd carbon
budget
up
to
2050.
Electricity
Heat
Transport
Industrial
Action
6
and
7
Focused
Enabling
CCS
Infrastructure
for
Industry
and
Power
Action
2
Targeted
Tidal
Range
Capacity
Action
3
&
4
Targeted
Electrification
&
Enabling
EV
Infrastructure
Action
3
&
4
Focused
Enabling
Hydrogen
and
Fuel
Cell
Infrastructure
Action
5
Targeted
Industrial
Biomass
Deployment
New
Wind
&
Solar
With
Energy
Storage
Drives
Need
For
Predictable
Tidal
Range
Power
New
Capacity
Enables
Heat
Electrification
Enable
Regional
Hydrogen
Grid
Baseload
Volume
Demand
for
CCS
New
Capacity
Enables
EV
Deployment
Hydrogen
Grid
Enables
Fuel
Cell
Deployment
Biomass
Deployment
on
Industrial
Processes
Reduces
Emissions
Allows
2nd Stage
Expansion
of
CCS
and
Integrated
CCU
Provides
Low
Cost
Platform
for
Flexible
Power
and
3rd Stage
CCS
Expansion
3
4
5
6
7
1
2
3
4
GEOGRAPHIC
INFRASTRUCTURE
ENABLING
REINFORCING
INFRASTRUCTURE
DEVELOPMENT
PLAN