1. 1
Improving
Public
Safety
&
Reducing
Greenhouse
Gas
Emissions
by
Replacing
Vintage
Gas
Distribution
Pipelines
in
Michigan,
New
York,
Pennsylvania,
and
Ohio
Andrew
Ray
The
Johns
Hopkins
University
10/14/14

2. 2
Summary
On
March
12,
2014,
eight
New
York
City
residents
lost
their
lives
and
48
others
were
seriously
injured
when
a
violent
explosion
destroyed
two
five-­‐story
tenements
in
the
densely
populated
borough
of
East
Harlem.
Just
three
years
prior,
the
Commonwealth
of
Pennsylvania
was
shocked
when,
within
a
span
of
three
weeks,
two
separate
explosions
left
six
people
dead.
The
connection
between
these
tragic
and
deadly
explosions:
vintage
natural
gas
pipelines.
Massive
quantities
of
vintage
natural
gas
pipelines
lie
nestled
beneath
the
sidewalks
and
streets
of
New
York,
Boston,
Chicago,
Cleveland,
Philadelphia,
Detroit,
and
Washington
D.C.,
and
dozens
of
other
major
American
cities.
These
aging
gas
mains
are
made
of
cast
iron
and
bare
steel
pipes
that
have
inferior
connection
joints
and
were
installed
without
protective
measures
shielding
them
from
caustic
soil
conditions.
As
such,
vintage
gas
lines
are
far
more
vulnerable
to
corrosion,
leaks,
and
catastrophic
failure
than
modern
day
pipeline
materials.
Safely
transporting
natural
gas
in
a
cost-­‐effective
manner
has
been
an
issue
that
has
confronted
the
gas
industry
since
its
inception.
Preventing
gas
leaks
across
the
millions
of
miles
of
local
distribution
mains
and
customer
service
lines
constantly
challenges
the
utility
companies
and
government
regulators
responsible
for
overseeing
the
country’s
gas
distribution
infrastructure.
In
an
effort
to
improve
the
safety
of
the
United
States
distribution
network,
natural
gas
utilities
are
replacing
thousands
of
miles
of
vintage
natural
gas
pipelines
each
year.
Nevertheless,
more
work
needs
to
be
done.
Since
2006,
the
number
of
people
seriously
injured
because
of
our
aging
distribution
system
has
risen
considerably.

3. 3
And
at
the
current
replacement
levels,
it
will
be
more
than
a
half-­‐century
before
the
last
of
the
highest
risk
gas
mains
are
eliminated.
But
the
ever-­‐present
threat
of
a
natural
gas
explosion
is
not
the
only
hazard
created
by
the
unintended
release
of
natural
gas.
Natural
gas
has
a
composition
that
is
roughly
95
percent
methane
–
a
potent
greenhouse
gas
(GHG)
and
a
primary
driver
of
global
climate
change.
As
atmospheric
GHG
concentrations
climb,
it
is
probable
that
trillions
of
dollars
of
low
lying
costal
infrastructure
will
be
threatened
by
rising
sea
levels,
and
much
of
the
world’s
crop
supply
may
be
jeopardized
by
altered
precipitation
patterns.
(IPCC,
2014)
Accelerating
the
pace
of
vintage
pipeline
modernization
efforts
is
an
issue
positioned
squarely
at
the
nexus
of
pubic
safety
and
climate
policy.
This
paper
seeks
to
provide
a
brief
historical
context
of
vintage
pipeline
infrastructure
and
highlight
the
threat
they
pose
to
public
safety.
It
also
presents
a
prospective
emissions
model
that
attempts
to
quantify
the
volume
of
methane
emissions
avoided
by
the
twenty-­‐eight
natural
gas
utility
companies
participating
in
pipeline
replacement
programs
in
Michigan,
New
York,
Ohio,
and
Pennsylvania
between
2014
and
the
end
of
2040.

4. 4
Introduction
Locked
within
the
geologic
formations
beneath
the
United
States
are
vast
reserves
of
natural
gas.
Abundant
throughout
large
swaths
of
the
country,
these
supplies
have
been
exploited
for
more
than
150
years
and
have
become
a
highly
versatile
and
valuable
fuel
source
used
across
a
diverse
array
of
applications
—
applications
that
affect
nearly
every
facet
of
our
modern
industrial
society.
In
the
early
days
of
natural
gas
production,
the
role
of
this
fossil
fuel
was
limited,
with
most
being
used
to
illuminate
the
streets
of
19th
century
America.
Over
the
following
century,
the
use
of
natural
gas
became
more
widespread
as
production
methods
improved
and
as
the
network
of
transportation
and
distribution
pipelines
expanded.
Today
natural
gas
is
a
prominent
fuel
source
that
has
become
so
vital,
and
so
deeply
woven
into
the
fabric
of
our
modern-­‐day
society,
that
it
is
inexorably
linked
to
the
economic
well
being
of
the
United
States.
Millions
of
residences
rely
on
natural
gas
for
home
heating
and
cooking,
and
hundreds
of
power
plants
to
use
it
to
efficiently
generate
low-­‐carbon
electricity.
The
primary
component
of
natural
gas,
methane,
is
also
an
invaluable
petrochemical
building
block
used
to
produce
a
wide
variety
of
chemicals
and
compounds
that
we
rely
upon
every
day,
including
plastics,
solvents,
and
fertilizers.
But
because
the
vast
majority
of
the
nation’s
natural
gas
distribution
network
is
buried
out
of
sight
beneath
the
soil,
the
aging
network
of
pipelines
that
bring
heat
to
our
homes
and
supply
fuel
to
the
country’s
industrial
base
largely
goes
unnoticed.
As
such,
few
realize
that
massive
volume
of
natural
gas
that
is
lost
from
leaking
vintage
cast
iron,
unprotected
steel,
and
copper
natural
gas
pipeline
infrastructure.

5. 5
Last
year
in
2013,
there
were
91,857
miles
of
leak
prone
natural
gas
distribution
mains
and
approximately
4.61
million
vintage
customer
service
lines
dispersed
throughout
the
United
States.
(PHMSA,
2014)
It
is
estimated
that
more
than
20
million
Mscf
(one
thousand
standard
cubic
feet)
of
natural
gas
was
lost
from
the
network
of
vintage
pipeline
infrastructure
in
2013
alone.
(EPA
GHG
Inventory,
2014)
Michigan,
New
York,
Ohio,
and
Pennsylvania
accounted
for
31
percent
of
the
national
total
as
those
states
have
some
of
the
highest
concentrations
of
leak
prone
pipelines
in
the
country.1
Nationally
gas
lost
from
vintage
pipelines
costs
consumers
hundreds
of
millions
of
dollars
annually.
However,
the
harm
caused
by
leaking
vintage
pipelines
extends
well
beyond
the
financial
burden
that
is
passed
along
to
the
ratepayers
that
must
cover
the
expense
of
natural
gas
which
never
reaches
the
meter.
The
methane
contained
in
natural
gas
also
has
a
notable
impact
on
anthropogenic
climate
disruption.
As
the
second
most
influential
forcer
of
global
climate
change,
and
possessing
a
global
warming
potential
(GWP)
30
times
greater
than
carbon
dioxide
over
a
100-­‐year
timeframe,
fugitive
methane
emissions
from
the
natural
gas
supply
chain,
including
those
from
vintage
pipelines,
have
helped
exacerbate
the
rise
of
global
temperatures
over
the
past
century.
(IPCC,
2014)
Over
shorter
durations,
the
impact
of
incrementally
rising
greenhouse
gas
concentrations
may
seem
distant
or
even
imperceptible.
But
recent
scientific
research
has
made
it
increasingly
clear
that
even
a
nominal
growth
of
atmospheric
GHG
levels
beyond
those
presently
observed
would
almost
assuredly
have
long-­‐term
consequences
that
1
Extrapolated
using
leakage
factors
from
40
CFR
98,
Subpart
W
and
PHMSA
Distribution,
Transmission
&
Gathering,
LNG,
and
Liquid
Annual
Data
(2013)

6. 6
are
widespread
and
very
real.
Altered
precipitation
patterns,
rising
sea
levels,
diminished
crop
productivity,
and
the
spread
of
vector-­‐borne
diseases
are
but
a
few
of
the
many
adverse
conditions
that
threaten
the
global
community
if
significant
reductions
are
not
soon
made
to
international
budget
of
carbon
dioxide
and
methane
emissions.
(IPCC,
2014)
But
the
most
obvious
hazard
posed
by
systemic
pipeline
leakage
originates
from
the
explosive
nature
of
natural
gas.
On
the
morning
of
March
12,
2014,
the
citizens
of
New
York
were
painfully
reminded
of
that
fact.
That
morning
a
sudden
and
violent
gas
explosion
ripped
through
a
densely
populated
East
Harlem
neighborhood.
The
force
of
the
blast
and
the
fire
that
ensued
destroyed
two
five-­‐
story
multi-­‐purpose
buildings
and
left
several
other
tenements
severely
damaged.
This
tragic
event
killed
eight
people,
seriously
injured
48
others,
and
caused
$2.8
million
dollars
of
property
damage.
The
explosion,
the
most
deadly
on
the
U.S.
distribution
system
in
over
27
years,
is
thought
to
have
been
caused
by
natural
gas
leaking
from
a
crack
in
an
8-­‐inch
low-­‐pressure
cast
iron
gas
main
installed
in
1887.
(NTSB,
2014)
(PHMSA,
2014)
The
disaster
in
East
Harlem
serves
as
a
powerful
and
vivid
reminder
of
the
potential
dangers
presented
with
the
continued
operation
of
vintage
natural
gas
pipelines.
Unfortunately,
it
is
not
practical,
or
even
possible
for
that
matter,
to
design
a
natural
gas
network
where
the
prospect
of
an
explosion
is
fully
eliminated,
as
there
will
always
be
some
degree
of
inherent
risk
involved
with
transporting
and
distributing
an
explosive
gas.
Nor
is
it
possible
to
completely
eliminate
the
harmful
methane
emissions
that
are
helping
disturb
global
climate
dynamics
and
afflict

7. 7
ratepayers
with
undue
financial
hardship.
But
the
possibility
exists
to
significantly
improve
the
safety
and
efficacy
of
natural
gas
systems,
and
possibly
reduce
long-­‐
term
operational
costs
by
replacing
vintage
natural
gas
pipelines.
Throughout
the
country
efforts
are
underway
to
reduce
the
massive
quantity
of
vintage
natural
gas
mains
and
customer
service
lines.
In
the
decade
between
2004
and
the
end
of
2013,
twenty-­‐three
percent
of
the
nation’s
vintage
gas
mains
were
upgraded
or
retired
from
service.
(PHMSA,
2014)
It
is
very
likely
that
these
efforts
have
prevented
an
unknown
number
of
deaths
and
injuries.
Nonetheless,
it
is
becoming
apparent
that
more
assertive
action
needs
to
taken
as
the
rate
of
pipeline
replacement
has
not
effectively
keep
pace
with
the
decay
of
vintage
infrastructure.
Leak
Prone
Pipeline
Infrastructure
Natural
gas
distribution
infrastructure
is
constantly
subjected
to
a
wide
variety
of
events
and
forces
that
threaten
the
integrity,
reliability,
and
safety
of
natural
gas
delivery.
Corrosion,
ground
movement,
and
improper
installation
can
cause
the
unintended
release
of
gas
from
any
pipeline.
But
vintage
gas
mains,
made
of
cast
iron
and
unprotected
steel,
are
far
more
prone
to
leaks
and
catastrophic
failure
than
modern
pipeline
materials.
Cast
and
Wrought
Iron
Pipe
The
earliest
natural
gas
pipeline
networks
were
laid
beneath
the
major
cities
along
the
eastern
seaboard
of
the
United
States
and
were
composed
of
cast
or

8. 8
wrought
iron
pipes.
These
systems
were
extensively
used
to
feed
the
gas
lamps
that
illuminated
the
streets
of
mid-­‐19th
century
America.
At
that
time
pipeline
technology
made
it
difficult
to
efficiently
transport
gas
over
long
distances
–
so
early
pipelines
usually
carried
syngas,
or
manufactured
gas,
produced
in
gasification
plants
located
near
city
centers
that
collected
the
flammable
gases
released
when
coal
is
heated
in
the
absence
of
oxygen.
Cast
and
wrought
iron
pipe
continued
to
be
used
into
the
mid-­‐20th
century
because
it
was
cheap
and
easy
to
install.
But
the
durability
of
cast
iron
mains,
and
the
composition
of
the
joints,
are
not
comparable
to
present-­‐day
materials,
and
therefore,
are
poorly
suited
for
modern
natural
gas
distribution
systems.
Cast
iron
gas
mains
were
constructed
using
sections
of
pipe
roughly
ten
to
fourteen
feet
long
connected
by
a
bell
and
spigot
union.
(EPA/GRI,
1996)
When
joining
the
sections
end
to
end,
it
was
common
practice
to
tightly
pack
hemp
rope
and
molten
lead
into
the
bell
joint
to
form
a
tight
seal.
Hemp
seals,
also
known
as
jute
or
oakum
seals,
worked
reasonably
well
when
higher
moisture
syngas
was
used.
But
as
natural
gas,
which
possesses
a
lower
moisture
content
became
more
prevalent,
the
hemp
seals
dried
out
permitting
gas
to
escape.
(U.S.
DOT,
2014)
Cast
iron
is
also
a
brittle
material
-­‐
and
although
it
has
a
relatively
high
compressive
strength,
its
tensile
strength
is
intrinsically
low
-­‐
making
cast
iron
vulnerable
to
the
sheering
forces
generated
by
ground
movements.
Moreover,
cast
iron
can
undergo
graphitization,
“a
natural
process
in
which
iron
degrades
to
softer
elements,
making
iron
pipelines
more
susceptible
to
cracking”.
(U.S.
DOT,
2014) As
a
result
of
its
brittleness
and
the
large
number
of
leak-­‐prone
joints
on
cast
iron

9. 9
mains,
it
has
the
highest
overall
leakage
rate
of
all
gas
pipeline
materials
with
each
mile
emitting
an
average
of
239
Mscf
of
natural
gas
annually.
(EPA
GHG
Inventory,
2014)
The
poor
resistance
to
ground
disruptions
and
the
high
number
of
gas
leaks
found
on
cast
iron
mains
also
makes
them
more
prone
to
the
catastrophic
failures
that
often
lead
to
serious
injury
or
death.
In
fact,
the
frequency
of
accidents
occurring
on
cast
iron
segments
of
the
U.S.
gas
distribution
system
is
four
times
greater
than
that
of
modern
pipeline
materials.
(PHMSA,
2014)
In
this
light,
regulators
and
utilities
are
focusing
on
eliminating
cast
iron
pipes
from
the
nation’s
gas
distribution
networks.
Nationwide,
there
were
30,888
miles
of
cast
iron
gas
distribution
mains
that
comprised
approximately
2.4
percent
of
the
U.S.
gas
distribution
system
at
the
end
of
2013.
(PHMSA,
2014)
In
thirty-­‐four
states
and
the
District
of
Columbia
cast
iron
distribution
infrastructure
is
still
in
service.
More
than
40
percent
of
this
infrastructure
is
installed
in
the
states
of
New
Jersey,
New
York,
Massachusetts,
Pennsylvania,
and
Michigan.
(PHMSA,
2014)
The
majority
of
the
nation’s
cast
iron
service
lines
have
been
replaced
over
the
past
decades
and
fewer
than
12,000
of
these
services
lines
remain
in
operation
today,
most
in
upstate
New
York.
(PHMSA,
2014)
Bare
Steel
Pipe
Bare
steel
pipe
has
been
used
for
natural
gas
distribution
for
more
than
one
hundred
years;
and
while
it
is
stronger
than
cast
iron,
and
able
to
withstand
higher

10. 10
pressures,
under
certain
soil
conditions,
it
is
highly
vulnerable
to
corrosion.
Damage
from
corrosion
is
the
pathway
that
most
commonly
allows
natural
gas
to
leak
from
bare
steel
infrastructure.
While
not
all
bare
steel
pipes
will
experience
corrosion
–
as
even
those
buried
in
soils
that
are
known
to
be
corrosive
will
not
necessarily
degrade
–
corrosion
is
stochastic
in
nature
and
it
is
difficult
to
predict
what
segments
of
pipeline
will
be
affected,
or
when
they
will
become
structurally
compromised.
Many
variables
influence
the
rate
that
which
unprotected
steel
pipe
will
corrode.
These
variables
include:
soil
moisture
content,
aeration,
drainage;
and
most
importantly,
the
chemical
composition
of
the
soil
itself.
Retroactive
protection
measures
are
costly
to
implement
and
their
effectiveness
is
often
marginal
because
it
is
impossible
to
restore
pipelines
already
damaged
by
corrosion.
Consequently,
unprotected
metallic
gas
mains
have
been
slated
for
removal
in
many
states.
Unprotected
steel
pipes
were
installed
extensively
throughout
the
United
States
before
federal
regulations
were
instituted
in
1970
mandating
that
cathodic
protection
(CP)
and
protective
coatings
be
applied
to
all
new
steel
pipes.
In
the
United
States
there
are
55,556
miles
of
unprotected
steel
pipelines
and
over
2.33
million
bare
steel
service
lines
in
operation
as
of
January
2014.
(PHMSA,
2014)
More
than
half
of
the
unprotected
steel
infrastructure
is
located
in
Pennsylvania,
Ohio,
Texas,
New
York,
and
Kansas.
Each
mile
of
bare
steel
pipeline
emits
an
average
of
110
Mscf
of
natural
gas
per
year,
and
each
individual
bare
steel
service
line
leaks
an
average
of
1.66
Mscf
annually.
(EPA
GHG
Inventory,
2014)
The
relative
rate
of
methane
emissions
leaked
from
bare
steel
infrastructure
in
the
United
States
is
less
than
half
of
that
leaked
from
cast
iron.
Despite
this,
the
absolute
volume
GHG

11. 11
emissions
escaping
from
bare
steel
distribution
lines
is
greater
than
its
cast
iron
counterpart
due
to
the
large
volume
of
bare
steel
infrastructure.
Copper
Pipe
Copper
piping
is
now
used
almost
exclusively
for
customer
service
lines
and
is
also
a
candidate
for
replacement
in
some
pipeline
modernization
programs.
Since
copper
is
a
relatively
soft
and
malleable
material,
it
can
be
easily
damaged.
Ground
movements
may
cause
pliable
copper
service
lines
to
kink
and
reduce
or
cut
off
the
flow
of
gas
to
the
customer.
Corrosion
typically
is
not
an
issue
with
copper
lines,
but
can
occur
under
certain
soil
conditions.
Corrosion
may
also
appear
if
at
some
point
of
during
the
gas
line’s
service
life
the
sulfide
content
of
the
natural
gas
exceeded
specifications,
although
this
is
more
of
a
concern
for
collection
lines
that
transport
unprocessed
natural
gas.
Issues
also
can
arise
if
copper
service
lines
are
coupled
with
unprotected
metallic
gas
mains
with
improper
fittings,
whereby
a
galvanic
cell
is
created
and
increasing
the
prospect
of
corrosive
damage
on
the
adjoining
metal
line.
Although
copper
is
superior
to
cast
iron
and
unprotected
steel
in
terms
of
annual
gas
leakage,
copper
gas
lines
are
not
considered
to
be
as
effective
as
modern
plastic
and
protected
steel
gas
lines.
With
more
than
970,000
active
copper
service
lines
in
the
United
States
at
the
end
of
2013,
each
leaking
an
average
of
0.26
Mscf
per
service
annually,
methane
emissions
lost
from
copper
services
are
not
inconsequential.
(EPA
GHG
Inventory,
2014)

12. 12
Modern
Pipeline
Materials
and
Protection
To
improve
safety
of
gas
distribution
systems
the
natural
gas
industry
has
adopted
the
use
of
plastic
and
cathodically
protected
coated
steel
gas
mains.
These
newer
materials
are
not
immune
from
damage
or
catastrophic
failures,
but
they
represent
major
improvements
in
overall
safety
and
reliability
when
compared
to
the
higher-­‐risk
vintage
cast
iron
and
bare
steel
infrastructure
that
they
replace.
Most
of
the
new
low
to
mid
pressure
distribution
mains
(≤
60
psi)
less
than
12”
in
diameter
are
constructed
from
a
medium
density
polyethylene
plastic
that
is
relatively
cheap,
easy
to
install,
will
not
corrode,
and
possesses
both
the
strength
and
flexibility
to
be
largely
impervious
to
damage
from
moving
ground.
Since
plastic
mains
cannot
be
located
using
a
metal
detector,
a
tracer
wire
is
placed
alongside
the
gas
line
during
installation
so
that
the
lines
can
be
properly
marked
in
order
to
prevent
future
damage
from
third
party
excavation.
Cathodically
protected
coated
steel
lines
are
deployed
in
locations
where
high-­‐pressure
mains
(≥
60
psi)
are
necessary
and
sometimes
in
areas
where
the
likelihood
of
excavation
damage
is
high
such
as
in
dense
urban
environments.
Protected
steel
is
also
utilized
for
above
ground
pipeline
segments
because
long-­‐
term
exposure
to
UV
light
degrades
plastic
gas
lines
causing
them
to
become
brittle.
Both
cathodic
protection
and
epoxy-­‐based
protective
coatings
are
applied
to
modern
metallic
gas
mains
and
components
to
shield
from
the
damaging
effects
of
corrosion.
Two
methods
of
cathodic
protection
are
available:
1)
applying
an
impressed
current
using
a
low-­‐voltage
DC
current
between
a
pipeline
and
an
anode
that
permits
electrons
to
flow
towards
the
pipeline
rather
than
be
stripped
of
them;

13. 13
and
2)
wiring
a
pipeline
to
sacrificial
anodes
made
from
magnesium,
zinc,
or
other
metal
that
are
more
reactive
than
the
steel
alloys
used
in
pipeline
construction.
(Fessler
&
Baker
Jr.,
Inc.,
2008)
Grading
Natural
Gas
Leaks
Most
states
have
adopted
the
leak
definitions
and
standards
set
by
the
American
Gas
Association’s
Gas
Piping
Technology
Committee
(GPTC).
Natural
gas
leaks
are
classified
into
three
categories
based
on
the
potential
hazard
that
they
present
to
the
public
and
property.
Grade
one
leaks
are
the
most
serious
and
are
defined
as
“leaks
that
represent
an
existing
or
probable
hazard
to
persons
or
Gas
Piping
Technology
Committee
Natural
Gas
Distribution
Leak
Classifications
Definition
Action
Criteria
Example
Grade
1
A
leak
that
represents
an
existing
or
probable
hazard
to
persons
or
property
Immediate
repair
or
continuous
action
until
conditions
are
no
longer
hazardous.
Notify
police
and
fire
departments
• Any
indication
of
gas
that
is,
or
is
likely
to
migrate
into,
under,
or
near
an
outside
wall
of
a
building
• ≥
80%
LEL
reading
in
confined
space
• Any
leak
that
can
be
seen,
heard,
or
felt
that
may
endanger
the
public
or
property
Grade
2
A
leak
that
is
recognized
as
being
non-­‐hazardous
at
the
time
of
detection,
but
requires
scheduled
repair
based
on
probable
future
hazard
Repair
or
clear
within
one
calendar
year,
but
no
later
than
15
months
from
the
date
the
leak
was
reported.
Should
be
reevaluated
at
least
once
every
six
months.
May
vary
greatly
in
degree
of
potential
hazard
• Any
reading
of
40%
LEL,
or
greater,
under
a
sidewalk
in
a
wall-­‐to-­‐wall
paved
area
that
does
not
qualify
as
a
Grade
1
leak
• Any
reading
between
20%
LEL
and
80%
LEL
in
a
confined
space
• Any
leak
which,
in
the
judgment
of
operating
personnel
at
the
scene,
is
of
sufficient
magnitude
to
justify
scheduled
repair
Grade
3
A
leak
that
is
non-­‐
hazardous
at
the
time
of
detection
and
can
be
reasonably
expected
to
remain
non-­‐hazardous
These leaks should be
reevaluated during the
next scheduled survey, or
within15 months of the
date reported, whichever
occurs first, until the leak
is regraded or no longer
results in a reading
• Any
reading
of
less
than
80%
LEL
in
small
gas
associated
substructures
• Any
reading
under
a
street
in
areas
without
wall-­‐to-­‐wall
paving
where
it
is
unlikely
gas
could
migrate
to
the
outside
wall
of
a
building
• Any
reading
of
less
than
20%
LEL
in
a
confined
space
Source:
GPTC
Guide
For
Gas
Transmission
and
Distribution
Piping
Systems:
2012
Edition
Guide
Material
Appendix
G-­‐192-­‐11
pp.
608-­‐610

14. 14
property”.
(GPTC,
2012)
These
leaks
must
undergo
immediate
repair.
Under
standard
atmospheric
conditions
natural
gas
will
ignite
at
concentrations
of
five
percent
by
volume.
This
threshold
is
the
lower
explosive
limit
(LEL).
In
order
to
provide
a
margin
of
safety,
grade
one
leaks
include
any
situation
where
gas
exceeds
80%
of
the
LEL
(4.0%
by
volume
or
40,000
parts
per
million).
On
the
other
end
of
the
leak
spectrum
are
non-­‐hazardous
grade
three
leaks.
It
is
here
where
an
overwhelming
majority
of
natural
gas
leaks
are
categorized.
In
most
states,
grade
three
leaks
must
be
reevaluated
every
fifteen
months,
and
if
they
do
not
present
a
threat
to
public
safety,
they
are
sometimes
allowed
to
remain
for
decades
after
their
detection.
Only
in
five
states
are
limits
established
that
dictate
the
amount
of
time
that
these
“lesser”
leaks
are
allowed
to
continue
without
being
repaired.
(NAPSR,
2013)
Gas
operators
often
refer
to
grade
three
leaks,
as
“non-­‐hazardous”
–
but
this
phrase
can
be
misleading
because
it
is
one
that
can
easily
be
misconstrued
to
denote
that
grade
three
leaks
lack
harmful
consequences.
Although
they
are
sometimes
only
pinhole
sized,
their
impact
should
not
be
dismissed,
for
it
is
these
leaks
that
are
responsible
for
a
majority
of
the
lost
gas
from
distribution
pipelines.
PHMSA
data
indicates
that
U.S.
gas
utilities
were
aware
of
105,513
gas
leaks
at
the
end
of
2013.
(PHMSA,
2014)
However,
this
figure
only
accounts
for
the
number
of
reported
leaks,
and
it
is
exceedingly
likely
that
thousands
more
go
undetected.
Reported
Number
of
Unrepaired
Natural
Gas
Leaks
(As
of
12/31/13)
Michigan
5,077
New
York
422
Ohio
8,197
Pennsylvania
3,895
United
States
105,513
Source:
PHMSA
Annual
Pipeline
Data

15. 15
Methane
Emissions
in
Urban
Environments
Operating
natural
gas
systems
in
America’s
most
densely
populated
urban
environments
involves
a
great
deal
of
intrinsic
risk.
While
many
elements
contribute
to
the
elevated
level
of
risk,
the
most
tangible
originates
from
the
many
individuals
that
may
potentially
be
affected
by
an
unforeseen
outage
or
accident.
Whereas
a
localized
service
disruption
occurring
on
a
rural
network
may
impact
several
dozen
customers,
a
similar
disruption
in
major
metropolitan
area
might
potentially
affect
many
thousands.
And
as
can
be
witnessed
by
the
explosion
in
East
Harlem,
accidents
in
high
population
centers
can
be
catastrophic.
But
in
addition
to
the
high
population
density
of
cities,
there
are
many
other
challenges
presented
with
operating
gas
pipelines
in
urbanized
environments.
A
large
percentage
of
the
nation’s
vintage
pipeline
infrastructure
is
located
in
many
of
America’s
oldest
and
most
populous
cities.
Here,
hundreds,
and
sometimes
thousands,
of
miles
of
the
most
dangerous
leak-­‐prone-­‐pipeline
remains.
Even
though
these
systems
are
remnants
of
a
former
era
their
operation
persists:
For
example,
in
New
York
City,
nearly
3,000
miles
of
cast
iron
pipe
remains;
in
Detroit,
there
are
another
2,000
miles;
and
in
Philadelphia
lies
1,500
more.
(PHMSA,
2014)
In
the
tightly
packed
city
streetscapes,
gas
pipelines
compete
for
space
with
the
myriad
of
water
mains,
sanitary
sewers,
telephone,
fiber
optic
lines,
etc.
situated
below
the
paved
surfaces.
For
natural
gas
pipelines,
this
has
several
implications,
especially
during
the
winter
months,
which
can
be
particularly
troublesome
for
urban
cast
iron
infrastructure.

16. 16
A
significant
portion
of
the
nation’s
cast
iron
gas
lines
reside
in
northern
latitudes
where
the
formation
of
ground
frost
can
disturb
the
surrounding
ground
through
a
process
known
as
“frost
heave”.
The
forces
generated
by
frost
heave
–
a
result
of
soil
moisture
expanding
as
it
transitions
between
a
liquid
and
frozen
state
–
can
shift
the
ground
and
compromise
the
unreinforced
seals
that
connect
the
short
segments
of
cast
iron
pipe.
Most
leaks
allow
only
small
volumes
of
methane
to
escape
and
do
not
generally
present
a
safety
hazard.
But
intermittently
the
disturbances
created
by
the
freeze/thaw
cycle
will
completely
dislocate
an
unreinforced
bell
and
spigot
joint
of
a
cast
iron
gas
main.
It
is
also
possible
for
these
forces
to
cause
the
brittle
cast
iron
pipe
to
crack.
Both
situations
create
an
exceptionally
dangerous
situation
for
any
persons
and
property
in
the
vicinity.
The
removal
of
snow
from
city
streets
can
also
indirectly
contribute
to
subsurface
pipeline
damage.
The
extent
to
which
a
freezing
surface
will
be
disturbed
is
partially
dependent
on
how
deep
frost
penetrates
into
the
ground.
Because
more
ground
moisture
is
affected,
a
deep
frost
is
apt
to
have
a
more
pronounced
impact.
And
because
snow
is
a
surprisingly
effective
insulator,
when
the
blanket
of
insulating
snow
is
plowed,
the
roads
receive
direct
exposure
to
frigid
air
temperatures,
causing
in
a
deeper
and
longer
lasting
frost
layer
that
is
more
likely
to
the
damage
vintage
cast
iron
pipes.
Broken
water
mains,
be
it
caused
by
a
frozen
pipe,
frost
heave,
or
other
cause
is
another
threat
more
frequently
experienced
during
the
winter.
When
a
water
main
breaks
a
large
volume
of
pressurized
water
is
released.
This
can
quickly
wash
out
roads
and
undermine
natural
gas
pipelines.
If
the
soil
supporting
the
short

17. 17
segments
of
cast
iron
pipe
is
washed
away,
it
is
virtually
inevitable
that
the
segments
will
either
shift
or
collapse
allowing
natural
gas
to
escape.
Finally,
frozen
ground
creates
an
extremely
effective
barrier
that
leaking
natural
gas
is
unable
to
penetrate.
When
natural
gas
leaks
from
subsurface
pipes,
the
gas
will
gradually
travel
through
the
soil
before
ultimately
dissipating
into
the
atmosphere.
But
when
an
impermeable
covering
such
as
frost,
a
city
street,
or
sidewalk
prevents
the
gas
from
venting
a
hazardous
condition
can
arise.
When
an
overlying
cap
is
in
place,
natural
gas
is
able
to
collect
and
concentrate
in
nearby
cavities,
migrate
horizontally
below
the
surface,
and
potentially
infiltrate
basements
through
cracked
building
foundations.
If
gas
accumulates
in
sewer
manholes,
the
explosive
gas
may
be
able
to
travel
a
considerable
distance.
Leaking
vintage
pipelines
clearly
are
a
known
risk.
As
part
of
a
risk
management
plan,
gas
distribution
companies
perform
regular
leak
detection
surveys
throughout
their
networks
to
preemptively
pinpoint
and
repair
leaking
segments
of
pipe.
During
the
winter
season,
natural
gas
utilities
in
northern
U.S.
states
are
required
to
conduct
frost
patrols
to
monitor
areas
where
cast
iron
gas
mains
are
present
for
elevated
methane
concentrations.
Yet
despite
the
best
efforts
of
the
natural
gas
utilities
to
minimize
leaks
on
their
distribution
systems,
independent
methane
detection
surveys
in
Washington
D.C.
and
Boston
have
demonstrated
that
a
large
number
of
gas
leaks
go
undetected.
A
2014
study
measuring
gas
leaks
in
the
District
of
Columbia
located
5,893
potential
gas
leaks
over
1,500
miles
of
road.
(Jackson,
et
al.,
2014)
Equivalent
to
one

18. 18
gas
leak
for
every
1,344
feet
of
road
sampled,
the
leak
density
in
Washington,
D.C.
was
only
slightly
less
than
was
observed
the
previous
year
in
Boston,
where
a
related
survey
documented
one
leak
across
every
1,235
feet
of
road
sampled.
(Phillips,
et
al.,
2013)
Since
both
Boston
and
the
District
of
Columbia
possess
a
high
percentage
of
aging
cast
iron
pipelines,
it
is
plausible
that
these
findings
may
mirror
the
leakage
profiles
of
larger
cities
that
too
have
a
significant
quantity
of
cast
iron
gas
mains
including
Detroit,
Philadelphia,
and
New
York
City.
Most
of
leaks
found
in
the
surveys
were
found
to
be
non-­‐hazardous
grade
three
leaks,
but
during
the
Washington
D.C.
survey,
researchers
located
one
dozen
undetected
gas
leaks
that
were
quite
hazardous.
Twelve
manholes
were
found
to
contain
methane
concentrations
that
exceeded
the
explosive
lower
limit
of
40,000
ppm,
and
in
three
of
these
manholes,
methane
concentrations
were
ten
times
greater
than
the
explosive
lower
limit.
(Jackson,
et
al.,
2014)
Shortly
after
they
were
discovered,
the
research
team
notified
the
local
distribution
company.
This
information,
according
to
guidelines
set
by
the
GPTC,
should
have
triggered
the
utility
to
dispatch
an
emergency
response
unit
so
that
each
manhole
would
be
assessed
and
classified
as
a
grade
one
leak
and
be
scheduled
for
immediate
repair.
But
disconcertingly,
when
researchers
returned
four
months
later,
again
they
measured
hazardous
methane
concentrations
in
nine
of
the
twelve
locations.

19. 19
Regulatory
History
Federal
regulations
concerning
pipeline
integrity
and
safety
were
first
introduced
in
1970
as
a
result
of
the
1968
Natural
Gas
Pipeline
Safety
Act.
Thereafter,
all
new
installations
of
natural
gas
pipeline
on
transmission
and
distribution
networks
in
the
United
States
were
required
to
satisfy
the
minimum
safety
requirements
set
forth
by
the
Department
of
Transportation
(DOT).
Among
the
initial
safety
standards
was
the
requirement
that
cathodic
protection
be
installed
on
new
steel
gas
lines
and
the
collection
of
detailed
records
regarding
the
location,
material
type,
and
installation
date
of
pipe.
The
new
guidelines
also
stipulated
that
future
use
of
cast
iron
pipes
for
the
distribution
of
natural
gas
be
prohibited.
Today,
a
division
within
the
DOT,
the
Pipeline
and
Hazardous
Materials
Administration
(PHMSA),
is
tasked
with
developing
and
enforcing
regulations
to
ensure
the
safe,
reliable,
and
environmentally
responsible
operation
of
the
nation’s
natural
gas
pipelines.
The
PHMSA
maintains
minimum
pipeline
safety
standards
as
outlined
under
U.S.
Code
of
Federal
Regulations
§192
which
covers
interstate
and
distribution
pipelines
in
all
fifty
states,
the
District
of
Columbia,
and
Puerto
Rico.
The
PHMSA
analyzes
pipeline
accidents
and
incident
data
to
evaluate
the
strength
of
current
safety
standards
regarding
design,
construction,
operation,
and
maintenance
practices
of
gas
pipeline
systems.
The
states
also
play
a
vital
regulatory
role
in
natural
gas
operations.
State
legislatures
have
the
authority
to
pass
additional
or
more
rigorous
safety
standards
that
exceed
PHMSA
requirements.
In
fact,
nearly
every
state
has
enacted
legislation
to
implement
policies
and
enhanced
safety
initiatives
that
surpass
specifications

20. 20
mandated
by
federal
code.
Only
Montana,
North
Dakota,
South
Dakota,
Utah,
and
the
territory
of
Puerto
Rico
have
failed
to
require
additional
safety
requirements
for
natural
gas
systems.
(NAPSR,
2013)
The
enforcement
and
inspection
of
intrastate
pipelines
and
gas
distribution
systems
is
also
a
task
frequently
performed
by
state
inspectors.
This
is
accomplished
through
a
federal/state
agreement
where
an
agent
of
the
state
acts
on
behalf
of
the
DOT
to
monitor
and
oversee
safety
federal
regulations
while
also
enforcing
additional
state
requirements.
For
their
part
in
safety
enforcement,
the
PHMSA
is
authorized
to
reimburse
state
agencies
up
to
80
percent
of
the
costs
required
to
carry
out
inspection
and
enforcement
activities
of
intrastate
pipelines
and
local
distribution
systems.
(NAPSR,
2013,
p.
11)
Overseeing
the
requests
of
individual
gas
distribution
utilities
are
the
state
public
utility
commissions.
Because
natural
gas
companies
operate
monopoly
franchises,
each
state’s
public
utility
commission
is
granted
the
sole
authority
to
approve
or
deny
proposals,
rates,
and
financial
expenditures
of
distribution
operators
located
within
their
jurisdictional
territory.
The
primary
duty
of
utility
commissions
is
to
determine
and
set
just
and
prudent
rates
that
enable
utilities
to
safely
and
reliably
deliver
natural
gas
while
also
affording
utilities
an
opportunity
to
recover
a
reasonable
return
on
their
investment.
Costs
incurred
by
distribution
companies
are
usually
recovered
through
two
mechanisms:
a)
gas
cost
recovery,
and
b)
base
rates.
Natural
gas
utilities
do
not
generate
profit
on
gas
purchased
from
interstate
pipelines.
Instead,
the
cost
of
gas
is
directly
passed
along
to
ratepayers
via
a

21. 21
volumetric
gas
cost
recovery
charge.
The
volumetric
charge
on
a
customer’s
utility
bill
is
automatically
adjusted
on
a
monthly
basis
based
upon
a
predetermined
formula
because
the
price
of
natural
gas
is
subject
to
a
large
number
of
dynamic
market
forces
and
is
often
highly
volatile.
Base
rates
allowing
utilities
to
recover
the
costs
associated
with
the
operation
of
distribution
systems
are
negotiated
through
formal
rate
case
proceedings.
During
these
proceedings,
state
utility
commissions
rely
on
the
LDC’s
and
intrastate
pipeline
operators
to
deliver
comprehensive
and
transparent
information
pertaining
to
the
cost
of
operation,
the
utility’s
customer
base,
detailed
financial
statements,
and
other
applicable
information
as
requested
by
the
commission
so
that
base
rates
can
be
approved.
Long-­‐term
capital
investments,
operations
and
maintenance
costs,
debt
payments,
other
fixed
costs,
as
well
as
a
reasonable
margin
of
profit
are
determined
during
the
base
rate
ruling.
Many
states
have
elected
to
use
the
base
rate
mechanism
to
recover
costs
associated
with
accelerated
pipeline
programs,
while
others
have
chosen
alternative
rate
designs.
Pipeline
Replacement
Programs
The
first
national
scale
effort
to
remove
cast
iron
pipe
began
in
1991
following
the
investigation
of
a
fatal
gas
explosion
in
Allentown,
PA.
Based
upon
the
recommendations
presented
by
the
National
Safety
Transportation
Board
(NTSB),
the
Research
and
Special
Programs
Administration,
the
predecessor
agency
of
the
PHMSA,
issued
an
alert
notice
to
operators
of
cast
iron
pipe
advising
that
“each
gas
operator
implement
a
program,
based
on
factors
such
as
age,
pipe
diameter,
operating

22. 22
pressure,
soil
corrosiveness,
existing
graphitic
damage,
leak
history,
burial
depth,
and
external
loading,
to
identify
and
replace
in
a
planed,
timely
manner
cast
iron
piping
systems
that
may
threaten
public
safety.”
(RSPA,
1991)
Following
the
advisory,
operators
began
the
removal
of
the
highest
risk
cast
iron
mains
from
their
systems,
eliminating
over
15,000
miles
of
cast
iron
mains
between
1992
and
the
end
of
2003.
(PHMSA,
2014)
These
early
replacement
programs
have
been
cited
as
contributing
to
the
improving
safety
on
the
U.S.
distribution
system.
In
2006,
the
U.S.
Congress
took
further
action
to
enhance
pipeline
safety
by
passing
the
Pipeline
Inspection,
Protection,
Enforcement,
and
Safety
Act.
This
bill
directed
the
PHMSA
to
begin
formulating
guidelines
to
implement
distribution
integrity
management
programs
(DIMP)
for
operators
of
gas
distribution
systems.
In
December
of
2009,
the
PHMSA
promulgated
final
DIMP
rules
aimed
at
reducing
the
frequency
and
severity
of
pipeline
incidents
on
the
U.S.
distribution
system.
The
PHMSA
allowed
distribution
operators
eighteen
months
to
plan,
write,
and
submit
individualized
DIMP
protocols
that
were
to
be
implemented
by
August
of
2011.
While
crafting
DIMP
procedures
the
PHMSA
explicitly
avoided
inflexible
mandates
for
the
1,400
plus
gas
distribution
operators
in
the
United
States
because
the
requirements
of
these
companies
can
be
highly
variable
–
some
have
customer
bases
of
fewer
than
one
hundred
and
the
largest
serve
well
over
one
million.
Natural
gas
distribution
networks
can
vary
wildly
in
age,
size,
pipeline
composition
and
design;
they
operate
in
both
rural
environments
and
in
the
most
densely
populated
cities;
and
operate
in
differing
geographical
locations
that
sometimes
require
unique
maintenance
and
quality
control
procedures.
Given
the
diversity

23. 23
and
individualized
requirements
of
the
nation’s
natural
gas
companies,
enforcing
mandated
safety
procedures
through
prescriptive
policies
would
have
likely
been
unduly
burdensome
and
expensive
for
many
operators.
Instead
the
PHMSA
outlined
seven
key
steps
affording
operators
latitude
in
order
to
address
company/location
specific
safety
needs
and
requirements.
State
regulators
may
choose
to
additionally
implement
further
requirements
for
distribution
operators.
PHMSA
Requirements
for
Distribution
Integrity
Management
Programs
1) Develop
and
implement
a
written
distribution
integrity
management
plan
2) Engage
in
opportunities
to
improve
knowledge
of
system
infrastructure
3) Identify
existing
and
future
threats
4) Analyze,
assess,
and
rank
risks
and
safety
threats
5) Identify
and
implement
risk
mitigation
measures
6) Measure,
monitor,
and
evaluate
program
performance
7) Report
DIMP
results
annually
to
state
pipeline
regulatory
authorities
To
satisfy
risk
assessment
and
ranking
requirements
of
DIMP,
utility
companies
rely
on
risk
analysis
software
packages
tailored
specifically
for
DIMP
analysis.
Theses
specialized
programs
utilize
customized
algorithms
to
analyze
data
inputs
incorporating
pipe
material,
diameter,
age,
pressure,
leak
history,
and
relevant
system
performance
metrics
to
identify
and
rank
at-­‐risk
locations.
By
calculating
localized
risk
profiles
and
the
corresponding
level
of
consequence
of
an
incident
on
each
distribution
segment,
engineers
can
identify
the
highest
risk
infrastructure
and
can
proactively
engage
in
risk
mitigation
activities.

24. 24
One
of
the
integral
components
of
the
integrity
management
rules
was
designed
to
address
an
information
gap
that
could
result
in
operators
overlooking
opportunities
that
address
significant
safety
threats.
Prior
to
the
implementation
of
minimum
federal
safety
standards
set
in
1970,
pipeline
operators
were
not
required
to
retain
detailed
records
identifying
the
location,
material
type,
or
instillation
date
of
gas
mains
and
service
lines.
At
the
beginning
of
2014,
PHMSA
records
show
over
30
percent
of
the
gas
distribution
mains
predate
the
federal
safety
standards
and
that
gas
distribution
companies
were
unable
to
definitively
ascertain
during
which
decade
more
than
96,000
miles
of
natural
gas
mains
were
installed.
(PHMSA,
2014)
This
is
not
because
distribution
operators
were
necessarily
careless
in
their
efforts
to
maintain
accurate
information
prior
to
federal
requirements,
but
rather
that
in
the
absence
of
federal
law,
this
indispensible
information
was
more
apt
to
be
inaccurate,
misplaced,
or
simply
unrecorded
without
penalty
or
consequence.
Although
it
is
uncommon,
companies
are
sometimes
unable
to
verify
the
location
of
underground
gas
mains
due
to
incomplete
or
inaccurate
records.
Inaccurate
records
endanger
construction
crews
engaging
in
underground
excavation,
as
well
as
the
public
as
a
whole.
If
a
utility
is
unable
to
locate
gas
lines
or
does
not
have
proper
knowledge
of
the
pipe’s
material
makeup,
it
is
impossible
to
determine
appropriate
risk
identification
procedures
or
develop
preventative
mitigation
options.
By
narrowing
the
gap
between
what
is
known
and
unknown,
DIMP
should
substantially
decrease
the
number
of
unidentified
risks
on
our
gas
distribution
system
and
thereby
bolster
safety
across
the
network.

25. 25
Call
to
Action
Between
1994
and
2006,
the
number
of
injuries
on
U.S.
distribution
systems
had
been
in
a
variable
but
steady
state
of
decline.
In
2007,
that
trend
suddenly
reversed.
As
a
result,
in
the
years
since
then,
the
number
of
individuals
hurt
by
gas
distribution
accidents
has
significantly
grown
and
continues
to
accelerate.
Then
in
late
2010
and
early
2011,
a
series
of
major
accidents
on
U.S.
natural
gas
distribution
systems
further
reinforced
the
need
to
improve
the
safety
and
integrity
of
the
entire
U.S.
pipeline
network:
0
20
40
60
80
100
120
1994
1995
1996
1997
1998
1999
2000
2001
2002
2003
2004
2005
2006
2007
2008
2009
2010
2011
2012
2013
2014
U.S.
Gas
Distribution
–
Fatalities
&
Injuries:
January
1994
–
August
2014
Source:
PHMSA
Serious
Pipeline
Incident
Data
(Updated
8/31/14)
Fatalities
Injuries
5
Year
Average

26. 26
• On
December
29th,
2010,
a
gas
explosion
at
a
Wayne,
MI
furniture
store
killed
two
employees
and
seriously
injured
two
others.
Although
investigators
were
unable
to
conclusively
determine
the
cause
of
the
explosion,
investigators
believe
that
gas
released
by
a
sudden
joint
separation
on
a
nearby
two-­‐inch
bare
steel
distribution
main
installed
in
1940
migrated
through
a
sewer
line
to
the
store
prior
to
the
explosion.
• On
January
18th,
2011,
one
member
of
a
local
utility
gas
response
crew
was
killed
and
three
others
injured
while
attempting
to
repair
a
major
gas
leak
in
Northeast
Philadelphia.
A
crack
found
on
the
body
of
a
12-­‐inch
cast
iron
distribution
main
installed
in
1942
was
determined
to
be
the
cause
of
the
explosion.
• On
February
9th,
2011,
a
gas
explosion
in
Allentown,
PA
resulted
in
five
fatalities
and
seriously
injured
three
others.
The
initial
explosion
leveled
two
townhomes
and
the
subsequent
fire
destroyed
six
others.
The
cause
of
the
explosion
was
eventually
found
to
be
a
crack
in
12-­‐inch
low-­‐pressure
cast
iron
distribution
main
installed
1928.
Alarmed
by
the
sequence
and
severity
of
these
accidents
on
the
aging
gas
network,
then
Secretary
of
Transportation,
Ray
LaHood,
issued
a
“Call
to
Action”
for
industry
representatives,
researchers,
regulatory
officials,
and
public
safety
advocates
to
assemble
at
a
pipeline
safety
forum
in
April
of
2011
to
identify
potential
gaps
in
industry
practices
and
shortcomings
of
current
regulatory
regimes.
Following
this
forum,
the
Department
of
Transportation
issued
an
updated
advisory
bulletin
again
urging
owners
and
operators
of
distribution
pipelines
of
the
need
to
conduct
a
comprehensive
review
of
cast
iron
and
bare
steel
distribution
mains
and

27. 27
further
accelerate
pipeline
repair
and
replacement
programs
for
high-­‐risk
infrastructure.
(U.S.
GPO,
2012)
Acceleration
of
Pipeline
Replacement
Programs
Proactively
engaging
in
actions
that
limit
fugitive
methane
emissions
from
natural
gas
lines
is
a
fundamental
requisite
in
providing
safe
and
reliable
natural
gas
service.
Removing
or
retiring
cast
iron
and
bare
steel
distribution
lines
from
service
is
the
most
reliable
method
to
eliminate
methane
leakage
from
vintage
pipelines.
Unfortunately,
doing
so
can
be
prohibitively
expensive.
Due
to
the
high
cost
of
replacement,
regulators
have
historically
been
reluctant
to
approve
large-­‐scale
modernization
efforts.
But
an
analysis
of
publicly
available
rate
filings
and
documents
filed
following
the
DOT
advisory
bulletin
indicates
that
state
regulators
are
becoming
more
supportive
of
the
rate
hikes
that
are
necessary
to
more
aggressively
fund
robust
pipeline
replacement
schedules.
In
Michigan,
Pennsylvania,
and
New
York
infrastructure
modernization
investment
has
grown
substantially
since
2011
for
the
gas
utilities
with
the
greatest
amount
of
vintage
infrastructure
–
in
some
instances
replacement
schedules
seeing
a
twofold
increase
from
previous
rate
filings.
In
Ohio,
pipeline
replacement
rates
have
held
steady
during
that
time
because
the
state
public
utility
commission
began
approving
very
ambitious
replacement
schedules
for
the
largest
gas
distribution
companies
in
2001.

28. 28
Cost
of
Programs
The
economics
surrounding
the
replacement
of
underground
pipelines
is
a
barrier
limiting
the
rate
of
pipeline
modernization.
The
amount
of
capital
investment
required
to
modernize
aging
gas
main
infrastructure
is
closely
correlated
to
the
population
density
of
the
replacement
area.
For
example,
upgrading
a
single
mile
of
gas
main
and
adjacent
customer
service
lines
usually
ranges
between
$300,000
and
$1,000,000,
but
in
dense
urban
environments
like
Manhattan,
replacement
projects
may
be
as
high
as
$10.56
million/
mile,
or
$
2000
per
foot
of
gas
main.
(New
York
State
PSC,
2014)
Tearing
out,
and
then
replacing
the
sidewalks,
streets,
and
other
infrastructure
after
the
vintage
pipelines
are
removed
drives
up
the
cost
of
pipeline
replacement
a
great
degree.
Sometimes
the
cost
of
restoring
the
surrounding
infrastructure
on
a
project
can
equal,
or
may
even
be
greater
than
the
actual
cost
of
installing
new
pipelines.
(NY
State
Assembly,
2014)
With
larger
distribution
companies
replacing
upwards
of
50
miles
or
more
annually,
it
is
not
difficult
to
see
that
replacement
programs
can
present
a
strong
financial
burden.
Additional
Benefits
of
Pipeline
Replacement
Programs
Accelerated
pipeline
replacement
programs
will
produce
benefits
that
extend
beyond
the
primary
purpose
of
enhancing
public
safety.
With
the
installation
of
newer
and
less
leak-­‐prone
gas
lines
the
costs
of
frequent
leak
repair
will
be
avoided,
service
quality
of
a
given
system
will
be
improved
as
the
amount
of
unplanned
service
interruptions
from
leak
repairs
is
reduced,
and
the
number
of
personnel
and

29. 29
equipment
needed
to
perform
leak
repair
and
maintenance
duties
will
decrease.
Further
workforce
reductions
can
be
realized
once
all
cast
iron
mains
are
removed
from
a
gas
network,
as
winter
frost
patrols
are
no
longer
necessary.
With
a
leaner
workforce,
a
company’s
operational
and
maintenance
costs
can
be
curtailed,
benefiting
both
the
ratepayer
and
the
utility.
Replacing
cast
iron
infrastructure
with
newer
plastic
and
CP
steel
mains
can
also
increase
the
gas
throughput
of
local
gas
networks
because
modern
materials
are
able
to
operate
at
far
higher
maximum
allowable
operating
pressures
(MAOP).
2
Segments
of
distribution
networks
with
cast
iron
mains
are
ordinarily
limited
to
operating
pressures
below
25
psig
by
federal
code
to
prevent
the
sudden
separation
of
unreinforced
bell
and
spigot
joints.
As
low-­‐pressure
segments
are
upgraded
with
new
gas
mains
having
a
greater
MAOP,
the
capacity
of
the
upgraded
system
can
be
increased,
thereby
opening
up
previously
unavailable
expansion
opportunities
and
providing
new
revenue
streams
for
utility
companies.
With
this
expanded
network,
more
customers
will
be
provided
an
additional
choice
in
how
they
chose
to
heat
their
homes.
Consumers
that
switch
from
fuel
oil
or
propane
to
the
newly
available
natural
gas
will
also
likely
benefit
from
lower
monthly
energy
bills.
Another
advantage
of
updating
vintage
cast
iron
mains
with
higher-­‐pressure
lines
is
that
it
can
lead
to
a
more
uniform
and
streamlined
gas
network
because
the
number
of
pressure
regulators
and
step
down
valves
within
the
system
can
be
substantially
reduced.
This
carries
the
benefit
of
further
improving
reliability,
2
Plastic
gas
mains
are
generally
limited
to
60
psig
while
CP
steel
distribution
pipes
can
be
engineered
to
withstand
pressures
up
to
400
psig

30. 30
increasing
overall
safety,
and
lowering
system
wide
GHG
emissions.
(PA
PUC,
2013,
p.
41)
Further
benefits
of
modernizing
gas
distribution
systems
include:
• Decreased
probability
of
catastrophic
incidents
• Reduction
in
emergency
response
costs
and
evacuations
• Fewer
fines/penalties
associated
with
natural
gas
accidents
• Fewer
legal
settlements
with
injured
parties
and
families
of
victims
• Reduced
insurance
premiums
for
the
utility
companies
• Direct
and
indirect
creation
of
employment
opportunities
• Significant
reduction
of
GHG
emissions

31. 31
Prospective
Emissions
Model
This
prospective
emissions
model
attempts
to
quantify
the
future
direct
methane
emissions
from
cast
iron,
bare
steel,
and
copper
natural
gas
infrastructure
from
the
28
natural
gas
utility
companies
with
mandatory
pipeline
replacement
programs
operating
in
Michigan,
New
York,
Ohio,
and
Pennsylvania
between
2014
and
the
end
2040.
Although
the
primary
impetus
behind
the
implementation
of
pipeline
modernization
efforts
stems
from
the
need
to
enhance
pubic
safety
and
welfare,
the
removal
of
leak
prone
vintage
gas
main
will
nonetheless
produce
substantial
reductions
of
GHG
emissions
in
the
natural
gas
distribution
sector.
The
model
also
presents
an
analysis
of
the
marginalized
cost
of
fugitive
CH4
abatement
in
terms
of
dollars
per
metric
tonne
of
CO2e
reduced
for
each
utility
and
for
each
state
and
in
aggregate.
Prospective
Model
Methodology
Pipeline
mileage
and
methane
emissions
estimates
from
2013
are
used
as
the
baseline
for
the
prospective
emissions
model.
Pipeline
mileage
was
gathered
from
the
2013
PHMSA
distribution
annual
data
reports.
Company
specific
pipeline
replacement
rates
and
capital
investment
data
used
in
the
prospective
emissions
model
was
primarily
compiled
from
publicly
available
rate
case
filings
gathered
from
the
regulatory
commission
websites
for
each
state.
Where
replacement
schedules
or
capital
information
was
either
incomplete
or
unavailable,
multiple
inquiries
were
sent
to
each
respective
company
in
order
to
fill
information
gaps.

32. 32
Public
utility
commissions
typically
designate
the
minimum
amount
of
at-­‐
risk
gas
main
to
be
replaced/removed
in
each
year
of
a
pipeline
replacement
program.
However,
the
specific
length
of
each
material
type
to
be
removed
is
not
always
indicated.
Where
specific
material
replacement
schedules
were
not
publicly
available,
the
model
assumes
that
the
replacement
rate
for
each
material
is
equivalent
to
the
utility’s
ratio
of
cast
iron
and
bare
steel
mains.
For
companies
with
multiple
service
line
material
types
targeted
for
replacement,
the
model
assumes
that
the
annual
removal
rate
for
each
material
is
also
equivalent
to
the
ratio
of
each
material
within
the
utility’s
system.
When
the
removal
schedules
for
higher
risk
customer
service
lines
was
unavailable,
unless
indicated
otherwise,
the
model
applies
the
greater
removal
rate
of
the
following
scenarios:
A)
the
final
removal
of
targeted
service
lines
coincides
with
the
final
removal
of
targeted
gas
main;
or
B)
the
average
service
removal
rate
between
the
years
2010
and
2013
as
indicated
by
PHMSA
data.
Methane
Emissions
Based
on
data
from
the
5th
IPCC
Assessment
Report,
the
model
incorporates
a
GWP
of
30
to
convert
fossil
methane
emissions
into
CO2
equivalents.
The
model
does
not
subtract
the
impact
GWP
of
CO2
emissions
that
would
have
been
produced
by
the
combustion
of
methane
had
the
leaks
not
been
present.
This
determination
was
made
because
only
during
extraordinary
circumstances
do
natural
gas
networks
operate
at
maximum
capacity.
So
at
any
given
moment,
any
party
in
possession
of
a
firm
delivery
contract
(this
includes
residential
customers)
will
have
access
to
an
adequate
gas
supply.
Therefore,
the
marginal
loss
of
natural
gas
supply

33. 33
due
to
leaking
pipelines
should
have
negligible
impact
on
levels
of
natural
gas
consumption
and
the
resulting
CO2
emissions
from
the
combustion
of
this
gas.
It
is
noted
that
natural
gas
leaks
create
operational
inefficiencies
that
require
greater
volumes
of
natural
gas
be
produced
and
processed,
and
that
additional
energy
is
used
to
transport
the
gas,
which
does
result
in
increased
levels
of
GHG
emissions.
However,
quantifying
these
emissions
is
beyond
the
scope
of
this
model
and
are
consequently
not
included.
The
emissions
factors
used
to
calculate
the
estimated
reduction
of
direct
methane
emissions
from
pipeline
replacement
programs
are
those
used
by
the
EPA
to
generate
the
U.S.
GHG
inventory.
Emissions
factors
are
a
commonly
used
in
bottom-­‐up
studies
to
quantify
sectoral
GHG
emissions
by
applying
a
representative
emissions
rate
for
an
individual
component
type
and
scaling
it
by
the
activity
data
of
each
component
type
across
an
industry.
In
1996
the
EPA
and
the
Gas
Research
Institute
(GRI)
released
a
study
that
quantified
annual
GHG
emissions
throughout
the
natural
gas
supply
chain.
The
purpose
of
the
study
was
to
develop
a
nationwide
methane
budget
and
compare
the
relative
global
warming
impact
of
natural
gas
vis-­‐à-­‐vis
coal
and
oil.
Individual
industry
segments
were
analyzed
to
develop
a
comprehensive
model
of
upper,
Emissions
Factors
for
Natural
Gas
Distribution
Lines
(a)
Gas
Mains
Cast
Iron
Bare
Steel
Plastic
CP
Steel
Mscf/mile/year
238.71
110.20
9.90
3.07
Service
Lines
Cast
Iron†
Bare
Steel
Plastic
Copper
Mscf/service/year
3.61
1.66
0.01
0.26
(a)
Derived
from
figures
in
40
CFR
§98
Subpart-­‐W
Table
W-­‐7;
†
See
methodology
below

34. 34
middle,
and
downstream
GHG
emissions.
Information
derived
from
the
EPA/GRI
study
has
been
the
basis
of
numerous
peer-­‐reviewed
studies
examining
national
scale
methane
emissions
and
was
used
in
developing
methodologies
used
to
create
the
EPA
Greenhouse
Gas
Inventory
from
natural
gas
systems.
This
paper
uses
default
methane
emission
factors
for
natural
gas
distribution
that
were
principally
derived
from
the
EPA/GRI
study.
(40
C.F.R.
§98
Subpart-­‐W,
Table
W-­‐7,
2011)
Fugitive
emissions
can
calculated
by
the
following
equation:
𝐸 = 𝐴𝐹 × 𝐸𝐹
Where
E
is
the
emissions
for
a
specific
material
(e.g.,
cast
iron
distribution
main),
AF
is
the
activity
factor
(e.g.,
miles
of
cast
iron
distribution
main),
and
EF
is
the
volume
of
fugitive
emissions
per
unit
of
time.
(EPA/GRI,
1996)
The
EPA/GRI
study
determined
emissions
factor
measurements
for
distribution
mains
by
first
locating
leaking
infrastructure
using
a
portable
hydrocarbon
analyzer
that
detects
methane
levels
above
natural
background
concentrations.
After
the
leaking
segment
was
isolated
and
disconnected
on
either
side
of
the
leak,
one
end
of
the
affected
section
was
sealed
while
the
other
was
connected
to
an
auxiliary
gas
supply.
The
targeted
pipe
segment
was
then
repressurized
to
the
system’s
standard
operating
pressure,
and
the
rate
of
gas
leakage
was
measured
using
a
calibrated
measurement
device.
Measurement
procedures
for
cast
iron
mains
were
conducted
along
entire
segments
rather
than
isolating
individual
leaks
because
of
the
propensity
of
cast
iron
mains
to
leak
gas
from
the
multitude
of
bell
and
spigot
joints.
Cast
iron
test

35. 35
segments
were
isolated
and
pressurized
to
maintain
standard
operating
pressure
and
leakage
rates
across
the
entire
segment
were
determined.
Customer
service
lines
sometimes
have
multiple
gas
leaks
that
are
often
imperceptible
requiring
that
services
also
be
tested
along
the
entire
segment.
Emissions
factors
are
those
used
by
the
EPA
for
mandatory
GHG
reporting
requirements
for
distribution
companies
emitting
over
25,000
metric
tonnes
of
CO2e
annually
and
are
derived
from
U.S.
Code
of
Federal
Regulations
§98
Subpart
W,
Table
W-­‐7
with
the
following
caveat
regarding
emissions
from
cast
iron
services.
Emissions
factor
values
for
cast
iron
service
lines
are
not
present
in
the
1996
GRI/EPA
Study
-­‐
Volume
9:
Underground
Pipelines,
U.S.
CFR
§92
Subpart-­‐W,
nor
the
2009
API
Greenhouse
Gas
Compendium.
This
is
likely
because,
on
a
national
scale,
the
impact
of
methane
lost
from
cast
iron
services
is
of
marginal
consequence,
since
fewer
than
12,000
active
cast
iron
services
remain
in
the
United
States.
(PHMSA
2014)
Despite
the
low
number
of
cast
iron
service
lines
nationally,
more
than
half
of
the
service
lines
that
do
continue
to
operate
are
found
in
the
territories
of
two
minor
gas
distribution
companies
in
upstate
New
York
and
are,
therefore,
required
for
the
prospective
emissions
model
in
this
paper.
To
generate
an
appropriate
emissions
factor
for
cast
iron
service
lines
this
model
takes
the
equivalent
emissions
factor
ratio
between
bare
steel
and
cast
iron
gas
mains
and
then
applies
the
ratio
to
bare
steel
and
cast
iron
services.
While
it
is
likely
that
the
application
of
this
methodology
to
some
extent
underrepresents
actual
methane
emissions
from
cast
iron
services
because
smaller
diameter
service
lines
lack
the
structural
integrity
of

36. 36
their
larger
diameter
counterpart,
but
for
the
purposes
of
this
model,
the
application
this
ratio
was
more
suitable
than
ignoring
the
emissions
category
altogether.
Forecasted
Natural
Gas
Prices
The
forecasted
price
of
natural
gas
for
each
state
was
derived
from
data
provided
by
the
U.S.
Energy
Information
Administration
(EIA)
2014
National
Energy
Modeling
System
(NEMS).
The
NEMS
uses
modules
for
each
energy
resource
to
produce
short
and
long-­‐term
regional
energy
projections
by
analyzing
trends
surrounding
the
interaction
of
supply
and
demand
fundamentals.
Key
inputs
used
in
the
natural
gas
module
include
domestic
natural
gas
production
rates,
current
and
forecasted
macroeconomic
conditions,
international
and
domestic
market
trends,
emerging
technologies,
regional
demographics,
pipeline
tariffs,
etc.
These
inputs
are
used
to
generate
Henry
Hub
natural
gas
price
forecasts
and
regional
residential,
commercial,
and
industrial
price
estimates.
3
The
public
NEMS
natural
gas
module,
however,
does
not
provide
the
city
gate
price
forecasts
that
are
needed
to
determine
the
cost
of
leaked
methane
emissions.
In
order
to
construct
city
gate
price
forecasts
for
each
utility
company,
the
model
uses
historical
natural
gas
data
from
the
EIA
to
calculate
average
monthly
premium
of
city
gate
prices
over
the
Henry
Hub
price
between
Jan
2010
to
Jan
2014.
While
a
longer
time
frame
could
have
been
used
to
determine
the
city
gate
/
Henry
Hub
price
differential,
using
a
more
recent
time
frame
is
likely
to
more
accurately
reflect
the
current
and
future
pricing
trends
within
the
natural
gas
industry.
After
3
Henry
Hub
is
a
major
natural
gas
distribution
hub
through
which
gas
futures
contracts
are
traded
on
the
New
York
Mercantile
Exchange