March 2016 ISG Meeting
Who We Are
Our Vision
Our Values
Enriching lives through a safe sustainable energy
future.
Our Mission
Working together to deliver safe, reliable, and
innovative energy solutions that create value for
our customers, communities, employees and
investors.
Total Assets
(2015):
$5.3
billion
What We Do
NorthWestern Energy provides electricity and natural gas
to approximately 701,000 customers in Montana, South
Dakota and Nebraska. We have generated and
distributed electricity in South Dakota and distributed
natural gas in South Dakota and Nebraska since 1923
and have generated and distributed electricity and
distributed natural gas in Montana since 2002.
Approximately 27,750 square miles of electric service and
9,405 miles of natural gas service in Montana, South Dakota
and Nebraska.
701,000 Customers
•
•
422,500 electric
278,500 natural gas
Total owned generation
•
•
MT – 412 MW – regulated
(includes 150 MW (regulation services))
SD – 376 MW (baseload) – regulated
Conceptual Layout
Some
OVERVIEW
Reminders
Table of Contents
Some Basic Overview - Mike and Curt (a few reminders)
• Gas System Overview
Gas System Fundamentals
NorthWestern’s Gas System
Missouri
Missouri
Missouri
River
River
Missouri
Missouri
MissouriRiver
River
River
River
Clark
Clark
ClarkFork
Fork
Fork
River
River
River
Ryan
Ryan
Ryan
Ryan
Ryan
Ryan
Flathead
Flathead
Flathead
Lake
Lake
Flathead
Flathead
FlatheadLake
Lake
Lake
Lake
Fort
Fort
FortPeck
Peck
Peck
PeckLake
Lake
Lake
Lake
Fort
Fort
Fort
Peck
Peck
Lake
Lake
Morony
Morony
Morony
Morony
Morony
Morony
Rainbow
Rainbow
Rainbow
Rainbow
Rainbow
Rainbow
Black Eagle
Cochrane
Cochrane
Cochrane
Cochrane
Cochrane
Cochrane
Kerr
Kerr
Kerr
Kerr
Kerr
Kerr
Great
Great
GreatFalls
Falls
Falls
Falls
Great
Great
Great
Falls
Falls
Holter
• Electric System Overview
Electric System Fundamentals
NorthWestern’s Electric System
Thompson
Thompson
Thompson
Thompson
Thompson
Thompson
Missoula
Missoula
Missoula
Missoula
Missoula
Missoula
Yellowstone
Yellowstone
Yellowstone
Yellowstone
Yellowstone
Yellowstone
River
River
River
Glendive
Glendive
Glendive
Glendive
Glendive
Glendive
Spion Kop
Hauser
Hauser
Hauser
Hauser
Hauser
Hauser
Falls
Falls
Falls
Falls
Falls
Falls
Dave Gates
Colstrip
MONTANA
Helena
Helena
Helena
Helena
Helena
Helena
Missouri
Missouri
MissouriRiver
River
River
River
Missouri
Missouri
Missouri
River
River
Butte
Butte
Butte
Butte
Butte
Butte
Colstrip
Colstrip
Colstrip
Colstrip
Colstrip
Colstrip
Yellowstone
Yellowstone
Yellowstone
River
River
Yellowstone
Yellowstone
YellowstoneRiver
River
River
River
Madison
Madison
MadisonRiver
River
River
River
Madison
Madison
Madison
River
River
Billings
Billings
Billings
Billings
Billings
Billings
Madison
Madison
Madison
Madison
Madison
Madison
• Infrastructure Programs – Current
DSIP – Development and Review
Transmission Investment
Where to go from here…
Mystic
Mystic
Mystic
Mystic
Mystic
Mystic
Hebgen
NWE Hydro Facilities
NWE Gas Facilities
NWE Coal Facilities
NWE Wind Facilities
Transmission Organizational Chart
NEW Vice President-Transmission
Mike Cashell
Director – Substation/Relay Operations
Jim Krusemark
Director – Transmission Line Engineering
and Regional Planning
Emmett Riordan
Director – Support Services
Danny Kaluza
Director – Grid Operations
Casey Johnston
(dual report to VP Distribution)
Director – Project Management - Projects
Tom Pankratz
Director – Gas Transmission and Storage
Marc Mullowney
Manager – Regional Transmission Policy
Ray Brush
6
335 employees
Distribution Organizational Chart
NEW Vice President -- Distribution
Curt Pohl
General Manager – Operations
Jason Merkel
Director – Project Management
Blain Nichols
(DSIP Project Manager)
General Manager – Construction
Mike Schmit
Director – Performance Management
Carolyn Loos
Director – Asset Management
John Carmody
Director – Organizational Development
Mike O’Neil
Director – Business Development and
Strategy Support
Reed Mckee
Director – Safety
Barry O’Leary
Approx.. 700 employees
7
Committed to safety (update slide)
NorthWestern Energy Company
OSHA Recordable Incidence Rates
Lost Time
3.50
Other Recordable
3.00
2.50
1.15
0.98
0.96
1.07
2.00
0.87
0.52
0.60
1.36
1.27
1.50
1.00
1.94
1.83
1.57
1.71
1.41
0.50
0.00
2009
8
2010
2011
2012
2013
2014
2015 YTD
Our safety strategy
•
•
Continued Focus and Refinement on
Safety Plans
– Involvement at all levels,
particularly the field
Continued Utilization of HPI training
and implementing HPI techniques
– Currently 422 employees trained in
the 8 hour session
– Currently 133 employees trained
as practitioners, 32 hour session
9
Utility Capital Spend
As other utilities cut back capital spending during
recession and following, NWE capital continued to grow
significantly.
10
Operating Expense
Even with the largest
expense contingencies
ever included in 2015,
operating
expenses continue to
increase year over year.
CAGR 2004-2015F: O&M
Expense (including DSIP) =
4.2% and A&G Expense =
1.8%
11
O&M expenses in 2004 and 2005 exclude reorganization fees of $41.2M and $7.6M, respectively
O&M expenses in 2006 exclude Ammondson verdict of $19M
O&M expenses in 2012 excludes MSTI write off of $24M
O&M expenses in 2013, 2014 and 2015F excludes Hydro Transaction related expenses of $4.4M, $2.4M and $0.2M respectively
A&G expenses in 2015F exclude insurance recovery of $20.8M
Volumetric Growth
Customer growth rates have
declined significantly since 2008
due largely to economic
conditions. However we have
seen an uptick in all segments
except MT Electric. Overall, we
are forecasting growth rates of
approximately 1%.
While this is certainly a decline
from the growth rates we saw 710 years ago, we are still seeing
growth which is better than the flat
or even declining customer counts
some utilities are experiencing.
12
Conceptual Layout
Natural Gas
System
Overview
Natural Gas Basics
Primarily Methane with a small percentage of other Hydrocarbons (I.e. ethane,
butane, propane etc.) and other impurities.
Odorless in natural state (odorant is added at Transmission System)
– Code requires – readily detectable at 20% of the lower explosive limit.
• About 0.8 – 1.0% Gas in the atmosphere
Lighter than air.
– Specific Gravity of about 0.6 or about 60% the weight of Air
Burning Characteristics
– Gas Burns in the 5% - 15% gas to air ratio.
• 4-5% considered lower explosive limit (LEL)
• 15% considered Upper explosive limit (UEL)
14
Primary Assets
Regulator Stations
– Equipment stations that allow for changes in operating pressures on the system example high
pressure transmission system (300 to 1000 psi) to distribution operation pressures (10 to 100
psi system).
Gas Main – Pipe that delivers gas through the system.
• Types:
– Steel Pipe
» High tensile strength.
» Long life expectancy.
» Operating pressure range (10-200 psi).
» Higher installation costs.
» Higher maintenance costs.
» Been used for a long time.
15
Primary Assets (cont’d)
Gas Main
– Plastic Pipe
» Lower tensil strength.
» Long life expectancy.
» Operating pressure range (10-120 psi).
» Economic installation costs.
» Lower maintenance costs.
» Began installing mid-70’s.
– NWE Pipe Sizes
» Steel (2” – 20”).
» Plastic (2” – 12”).
16
Primary Assets (cont’d)
Services
– Carries gas from mains to the customer entrance.
• Types
– Steel and Plastic
» Same characteristics as mains.
Service sizes:
» Residential (1/2” – 1-1/4”)
» Commercial and Industrial (3/4” – 12”)
Valves – equipment used to isolate gas flows on the system.
» Used at gate stations, regulator stations, on gas mains, and customer
» Meter locations.
» Types: Plug, ball, gate all are manually turn devices.
Distribution Regulators - Reduces distribution pressures a the customer meter from 910 to 100 psi) to
customer delivery pressures of (.25 lbs to 5 lbs.).
Meters – Equipment that measures gas usage.
» Types: Diaphragm or rotary.
System Configuration (i.e. Radial or Network)
Radial Systems
– Designed for only one source of gas usually in rural areas serving
few customers.
– Single line extending from regulator station into outlying areas.
– Serves most residential and small commercial customers.
– Most economical system to build.
Network Systems
– Designed for more than one source of power.
– Used to tie gas mains and multiple regulator stations together.
– Provides increased reliability and capacity.
– Utilized in more densely populated areas.
– Or when two radial systems grow together.
– Requires more valves to isolate gas flows.
18
System Design Parameters
System Design Parameters
– Pressure
• Force that pushes the gas though the system.
• Higher pressure equates to more gas deliverability.
– Pipe Size
• Determines the carrying capacity of the gas main.
• Larger diameter increases system capacity.
• Bigger the pipe the more expensive to install.
• Pipe size is determined by NWE load projections for area
being served and customer load profile expected in areas.
– Pressure
• Determine by regulator station.
• Higher pressures increase systems capacity.
• Typical NWE distribution pressures
– 10 to 65 psi
Customer
Customer
– Delivery pressure based on
equipment requirements.
– Gas usage based on installed
equipment.
20
Key Operating Difference from Electric Systems
• Federal Mandated Operating Guidelines
• Pipeline Safety Act 1971
• Established Office of Pipeline Safety under
Department of Transportation (DOT)
• Now called Pipeline and Hazardous Materials Safety
Administration (PHMSA)
• Established and continually updated DOT part
191 and 192 requirements
• Montana Pipeline Safety Administered by the Montana
Public Service Commission
• Annual Operating Inspections
21
Gas System Maintenance
Gas System Maintenance
– DOT code.
– Corrosion control Requirements.
» Cathodic protective systems - prevents corrosion on steel
mains and services by transferring corrosion to established
points called cathodic ground beds which are periodically
replaced when depleted.
» Atmospheric surveys – period inspection programs of above
ground steel equipment for deterioration.
» Bell hole reports – forms filled out checking pipe condition for
deterioration any time mains or serves are exposed for
maintenance or inspection.
– Leak surveillance.
» Specialized equipment design to detect gas escaping from the
system.
» Leak detection requires someone to walk all mains and
services.
22
Inspection
Frequency of inspection.
– Overall system – completed once every four years on all gas mains and services.
– Business districts – completed every year.
Valve maintenance.
– Requires turning every zone valve on the system each year to ensure valve works.
Regulator station maintenance.
– Inspection required yearly to ensure equipment functions properly.
Odorant injection and ongoing checks.
– Substance injected into the gas system that gives the gas its distinct smell.
– Odorant allows for detection by average person (early detection system for public safety).
– Odorant checks perform every three months on each distinct gas system.
Public safety communication.
– Education programs to inform public of proper safety measures, who to call and how to respond.
23
Emergency Response
Emergency Response and
Customer Service
–
–
–
–
24
Gas leaks
Hit lines
No-heats
Carbon Monoxide
Natural Gas Mains
Mains
– Identify main capacity requirements
–
Radial source main pressure
profile
–
Main loading pressure curve
–
Overload time factor
–
Reserve capacity for other
systems
–
Establish future growth curve
–
Forecast replacement
25
Natural Gas Distribution Example Map
26
Gas System Performance - Montana
27
*AGA 2015 Information not available till June 2016
Gas System Performance – Montana
28
*AGA 2015 Information not available till June 2016
NorthWestern’s Natural Gas System Overview
 Montana Gas Distribution
–
–
–
–
–
Steel Main 1,228 Miles
Plastic Main 3,458 Miles
168 Communities
188,400 Customers
Total Throughput 90,789,518 MMBTU (propane gal equivalent)
 Montana Gas Transmission
– Transmission Line Miles 2200
– Gas Storage in Montana
– Customers – Bundled Retail, Wholesale
Transport and Storage
29
Montana Natural Gas Service Territory
NorthWestern Energy’s
serves 189,000 Montana
natural gas customers in
105 communities, and
provides gas storage and
transmission to other
parties.
30
Conceptual Layout
Natural Gas
Transmission
Overview
Natural Gas Transmission Overview
“Core Customers” and Third Party Service
• Gas Nominations for the Day
– (Gas Flowing in and Out of the System)
Generally inject gas into storage during
summer months
• (Generally May to early October is injection
season)
Provide gas storage and transportation
capabilities for other entities
$22.1 Million in Revenue in 2015
• Ultimately offsets customer rates
32
Gas Transmission Natural Gas Transmission Map
33
GTS Gas Supply – Design Day
GTS Annual Gas Supply Makeup
GTS Design Day Gas Supply Makeup
15%
14%
22%
61%
63%
Production
34
Interconnects
Storage
Production
25%
Interconnects
Storage
NWE Gas Storage Fields
Field
Bcf
Deliverability, Mcfd
Working Gas,
Cobb
Dry Creek
Box Elder
140,000
40,000
5,000
11.0
5.5
0.5
Total
185,000
17.0
NWE Pipeline Interconnects
The transmission system connects with five
other pipeline companies.
Approximately 48% of the annual gas
supply comes from Canada and the
balance from Montana and Wyoming.
Pipeline
Capacity (Mcfd)
TCPL (Nova)
~120,000
Aden
~50,000
Havre Pipeline
~30,000
CIG
~40,000
WBI
~20,000
2014 Contracted (Mcfd)
98,000
20,000
20,000
20,000
0
NWE Gas Production Acquisitions
Battle Creek acquired 2010
Annual Production = 0.9 Bcf
NFR acquired 2012, Devon acquired
2013
Annual Production = 7 Bcf
Compression Technology
Reciprocating 28,500 HP
38
Gas Turbine – 16,500 HP
Peak Day & Design Day
Peak Day
– Peak day is defined as a weather event during the heating season
that results in the highest gas loads (demands) on the GTS system.
o Largest Recent Peak Day 12-7-2013
Design Day
– Design day is the worst weather event the GTS system can have
over the operating territory and still maintain gas deliveries on a firm
basis.
o Design Day Base 2-2-1989
– Design Day has a direct impact on capital/construction plan.
Top Ten Peaking Events (2004 – 2015)
2015 Model
Accuracy
Total Actual
System
Flow (Mcf)
Design Day
Total For
Weather
State Average
Year
HDD
Rank
Date
Core Actual
Flow (Mcf)
1
12/7/2013
192,042
98.0%
293,543
316,624
80
6
68
13
2
2/5/2014
191,155
99.6%
284,344
322,980
78
7
66
44
3
2/6/2014
189,128
99.5%
280,199
322,980
81
6
68
0
4
12/6/2013
188,589
98.0%
298,007
316,624
76
9
66
44
5
1/5/2004
188,577
96.5%
267,254
302,181
82
7
71
34
6
12/14/2008
183,964
98.1%
275,760
326,623
79
11
64
77
7
12/8/2009
183,113
95.9%
284,503
331,498
79
4
68
9
8
12/15/2008
180,648
99.1%
271,083
326,623
77
7
68
39
9
12/8/2013
179,270
99.2%
279,183
316,624
73
6
75
74
10
2/4/2014
179,240
97.6%
279,046
322,980
72
10
66
73
89
11
56
88
Design Day Weather (2/2/89)
Wind Speed
Relative
Humidity
Cloud Cover
Design Day
NWE is reviewing the Design Day
weather conditions and validating the
use for system requirements and
future capital investments.
– Working with the National Weather
Service for Weather Analysis
– Reviewing design philosophies with
peer companies
– Working with the University of
Montana for Climate Analysis
Gas System Compliance
DOT - Pipeline and Hazardous Materials Safety
Administration (PHMSA)
– DIMP – Distribution
– PIM/HCA – Transmission
o
o
New Regulations coming – Class 3 Locations
Control Room Management
– Drug and Alcohol testing
– Now proposed, Safety Management
System
OSHA
MTPSC / SDPUC / NEPSC
– Line extension policies
42
Conceptual Layout
Electric
System
Overview
Overview – Electric Distribution
Electric Distribution
– Primary Assets
– Design Criteria,
Operations and
Maintenance
– Asset Management and
System Integrity Plan
Development
44
Electric System Primary Assets
Overhead System
– Poles – support structure for ground clearance.
– Conductor – carries electric current.
– Transformer – reduces circuit voltage to household levels.
Other Equipment
– Insulators – provides voltage isolation from pole/equipment.
– Cutouts – individual sectionalizing device.
– Switches – circuit sectionalizing device.
– Arrestors – circuit surge protector (over voltage protection).
– Reclosers – mechanical sectionalizing device.
– Capacitor – line reactance device.
– Regulator – voltage stabilization device.
Design use for longer distances, larger loads, and an earlier design practice.
45
Electric System Primary Assets (continued)
Underground Systems
– Cable – underground current carrying conductor that also provides voltage isolation at
the same time (different types).
Construction Methods
– Conduit – allows UG conductor to be pulled in and out once buried.
– No Conduit – direct buried into ground must be dug up to be replaced.
– Pad Mount Transformers – reduces circuit voltage to household levels.
– Elbows – transition equipment for cable to connect to other pieces of equipment.
– Switchgear – circuit sectionalizing device.
– Arrestors – Circuit surge protector (overvoltage protection).
Design use for shorter distances, serves medium to small loads, design became
economical in mid 80’s to early 90’s.
46
Electric Distribution – System Primary Assets (continued)
Substations
– Breakers – mechanical devices for fault interruption.
– Large Transformers – reduces voltage from transmission levels to distribution levels.
– Regulators – voltage stabilization device.
– Switches – substation sectionalizing device.
– Reclosers – mechanical fault interruption device.
– Other major equipment.
Services and Meters
47
Electric Distribution – Design, Criteria
System Configuration (i.e., Radial, Loop Feeds, Etc.)
– Radial Systems
• Designed for only one source of power.
• Single line extending from substation into outlying areas
• Serves most residential and small commercial customers.
• Most economical system to build.
– Loop Systems
• Designed for more than one source of power.
• Used to tie substations together.
• Provides increased reliability.
• Utilized in more densely populated areas.
• Or when two radial systems grow together.
• Designed for sensitive customer needs.
48
Electric Distribution – Design, Criteria (continued)
System Design Parameters
– Single-Phase
• Overhead lines require two conductors
• Underground lines require one conductor.
– Three-Phase
• Overhead lines requires four conductors.
• Underground lines require three conductors.
• Three-phase lines have three times the load capacity as single-phase lines.
• Most motors greater than 10 hp require three-phase or individual customer
loads greater than 400 amps.
• Lines configuration generally determined by customer load profile and
economics for utility/customer.
49
Electric Distribution – Design, Criteria (continued)
Voltages
– Determine by substation transformer.
– Higher voltages require increase ground clearance and bigger insulators.
– Typical NWE distribution voltages.
– Single-phase voltages.
• 2400, 7200, 14400
– Three-phase voltages.
• 4160, 12470, 24940, 34, 500
Current Capacity
– Determine by the conductor size.
– Larger the conductor the more current capacity.
– Larger conductor requires shorter span lengths and bigger poles.
– Larger conductors have less energy losses due to conductor heating.
50
Electric Distribution – Design, Criteria (continued)
Customer
– Determines voltage.
• Single-phase 120/240 volt.
• Three-phase 120/208 or 277/480.
– Voltage required determined by customer’s equipment.
– Determines power needs.
Power Requirements
– Energy - the customer’s use.
– Power – measure in watts.
– Power – voltage X current.
– Power losses – I2 X conductor losses.
Therefore, higher voltage equates to:
– More load serving capabilities.
– Less energy losses due to conductor heating.
– Larger poles.
– Bigger insulators.
– More expensive equipment.
Systems generally design to find economic balance point.
51
Electric - Operations and Maintenance
National Electric Safety Code
– Provides general direction and sets minimum guidelines (inspection and maintenance
cycles) of our electric facilities.
– Designed to evaluate asset life utilization.
Northwestern Primary O&M Circuit Guidelines
– Overhead line patrol (detailed and visual).
– Underground device inspection (detailed and visual).
– Underground vault inspection (detailed and visual).
– Street light patrol (detailed and visual).
– Tree trimming (circuit and hot spotting).
– Electric meter inspection (visual).
– Pole inspection (detailed test and treat).
52
Electric – Operations and Maintenance (continued)
Substation Guidelines
– Substation inspection and operation plan.
– Power circuit breakers and reclosers – trip timing.
– Power circuit breakers and recloser maintenance.
– Substation nitrogen tanks.
– Battery maintenance procedure.
– Weed spraying.
– Manual closing of breakers and reclosers.
– Capacitors, transformer fans and relaying settings.
– Infrared scanning substations and transformers.
– Relaying testing.
– Equipment oil analysis.
– Equipment SF6 gas analysis.
53
Electric Distribution – Operations and Maintenance (continued)
Emergency Response
– Major storms.
– Day-to-day outages.
– Hit poles or underground.
– Down lines.
– Voltage problems.
54
Conceptual Layout
Electric System Asset
Management and
System Integrity Plan
Development
Asset Management and System Integrity Plan Development
System Integrity Plan Involves Four Major Components
– Capacity
– Reliability
– Asset Life
– Compliance
Performance Criteria Considered (IEEE Indices)
– SAIDI – System Average Interruption Duration Index
– SAIFI – System Average Interruption Frequency Index
– CAIDI – Customer Average Interruption Duration Index Outage Count
56
Asset Management and System Integrity Plan Development (cont’d)
Capacity
– Substation Transformers and Equipment.
• Identify substation capacity requirements.
• Radial source substation.
• Winter loading capacity – 125% of
nameplates.
• Summer loading capacity – 110% of
template.
• Transformer oil temperature - 75°C degree
rise ambient.
• System spare available.
• Overload time factor.
• Reserve capacity for other substations.
• Establish future growth curve.
• Forecast year for replacement.
57
– Circuit
• Identify circuit capacity
requirements.
• Radial source circuit voltage
profile.
• Conductor ampacity loading
damage curve.
• Overload time factor.
• Reserve capacity for other circuits.
• Capacitor placement necessary.
• Regulator replacement necessary.
• Establish future growth curve.
• Forecast replacement.
Asset Management and System Integrity Plan Development (cont’d)
Reliability
– Overall performance of electric system.
– Rolling three-year averages used to soften yearly variations.
– Track trends in major categories.
– Overall effectiveness of O&M guidelines.
– Review of asset life utilization.
– Review of loop sources.
– Effectiveness of automation.
– Overall system SAIDI impact utilized for O&M guideline applications.
• Pole inspection/replacement.
• Tree trimming.
• Underground cable replacement.
• Future applications OH line patrol and UG device inspections.
58
Asset Management and System Integrity Plan Development (cont’d)
Reliability (continued)
– Circuit Reliability Ranking (SAIDI, CAIDI, SAIFI)
• Circuit reliability metric comparison to IEEE quartile ranking.
• Reliability parameters breakdown such as trees, cable failures.
• Possible candidate for increased inspection cycles for O&M guidelines.
• Possible application of new electronic system protection equipment.
– Worst Circuits
• IEEE 4th quartile circuit performance.
• Detailed root cause reliability analysis.
• Review of circuit design for environmental fit .
• Field visit with operations personnel for circuit recommendations.
• Possible application of new electronic system protection equipment.
59
Asset Management and System Integrity Plan Development (cont’d)
60
Asset Life
• Define major asset classes.
• Determine impacts of failures on system performance, safety, customer satisfaction and
potential risk profiles.
• Ability to establish asset life expectancy.
• Ability to determine asset failure curves.
• Evaluate economics of preventative maintenance and inspection guidelines.
• Ability to perform just in time replacement.
• Economics of a proactive replacement program vs reactive failure replacement.
• Proactive maintenance programs.
• Systematic replacement ahead of failure.
• Pole replacement.
• Potential underground cable replacement.
• Street light bulb replacement.
• Substation equipment replacement.
• Electric ERT replacement.
Balancing Risk, Cost and Value
System Risk that has to be Considered and Balanced against Economics
• Potential costs of an individual incident.
• Probably of each incident actually happening.
• Ability to respond to any incident.
• Establishing the value of safety – public and work force.
• Worker compensation values can be established for each lost time incident.
• Evaluating costs of updating system to new standards and guidelines.
• Establishing costs of a reliability minute.
• Impacts of disturbances on customer satisfaction.
• Costs to customers of each option.
61
NorthWestern’s
Electric
System
62
Montana Electric Service Territory
NorthWestern Energy
serves 354,000
Montana electric
customers in 187
communities, and
provides essential
infrastructure for
electric cooperatives
and other
transmission
customers.
63
Reliability Performance (Excluding MEDs)
140.00
2.000
1.800
120.00
1.600
1.400
1.200
80.00
1.000
60.00
0.800
0.600
40.00
0.400
20.00
0.200
0.00
SAIDI
CAIDI
SAIFI
64
2012
2013
2014
2015
127.13
102.55
1.240
132.92
107.48
1.237
112.87
104.90
1.080
129.31
102.17
1.266
Year
Average
(2012-2014)
124.31
104.98
1.186
0.000
SAIFI (frequency)
SAIDI-CAIDI (minutes)
100.00
Reliability Performance (Including MEDs)
300.00
1.800
1.600
250.00
200.00
1.200
1.000
150.00
0.800
100.00
0.600
0.400
50.00
0.200
0.00
SAIDI
CAIDI
SAIFI
65
2012
2013
2014
2015
160.14
119.53
1.340
146.20
112.04
1.305
112.87
104.90
1.080
259.61
165.89
1.565
Year
Average
(2012-2014)
139.74
112.16
1.242
0.000
SAIFI (frequency)
SAIDI-CAIDI (minutes)
1.400
System Overview
Montana Electric Distribution
– Overhead miles of line 13,124
– Underground miles of line 4,536
– 203 communities
– 353,673 customers
–
Montana Electric Transmission
• 97,540 square miles
• 50 kV to 500 kV
• Regulated by MPSC/FERC/NERC/WECC
• Bilateral Markets – Potential Energy
•
Imbalance Market (EIM)
– Customers – Bundled Retail, Wholesale
–
and Interconnection
66
DSIP Progress Update 2011- 2015
67
NWE System Characteristics
Rural
Urban
Comb.
68
Our strategy
must reflect the
challenges of
dispersed rural
assets
Electric System
Transmission
Mike Cashell
Vice President
69
Transmission Overview
• Western two-thirds of
Montana; 97,540 square
miles
• 6,900 miles of transmission
lines & associated terminal
facilities
• Voltage levels from 50 kV to
500 kV
• 286 circuit segments
•  100,000 transmission
poles
70
Electric Transmission Operations
• 97,540 + sq. mi. service territory
• Electric transmission operations (50-500
kilovolt)
– Montana
• 6,700 circuit miles
• 53 substations
• 326,000 customers
• Operate in two reliability councils – WECC
and MRO
• Operates in both vertically integrated SD
and unbundled (changing) markets in MT
• System Dispatch operations for gas and
electric for all three states
• Montana balancing authority area serves
more than
3,600 MW of generation
71
 NorthWestern Service Area
Connected Entities
72
2016 T&D Budgets
• O&M ($131.4M)
– Distribution ($88.6M)
– Transmission ($36.7M)
– Support Functions ($6.1M)
• CAPEX ($232M)
– Distribution ($88.7M)
– DSIP ($51.8M)
– Transmission ($91.5M)
73
Transmission Major Projects
2016 Overall Budget – Transmission; Electric and Gas
•
Montana
- $87 Million
•
South Dakota
- $4.5 Million
•
Total
- $91.5 Million
Transmission Major Projects – 2016 Budget
•
•
•
•
•
•
•
•
•
•
74
ET Columbus-Rapelje to Chrome Junction 100 kV Ln – Capacity/Reliability - $15.4 Million
ET Jack Rabbit -Big Sky 161 kV Line Upgrade – Capacity Reliability
- $7.3 Million
ET NERC Facility Rating Alert 115/100 – Compliance
- $9.7 Million
GTS GTIP Bozeman Eastside – Safety Reliability
- $3.9 Million
GTS GTIP Bozeman Westside – Safety Reliability
- $3.7 Million
ET Crooked Falls Switchyard Expansion – Capacity/Environmental
- $ 2.7 Million
ET Dillon-Salmon 161-69 Auto Bank – Capacity/Reliability
- $ 2.2 Million
GTS MT Station W (Storage) Horsepower – Capacity/Reliability - $ 2.2 Million
GTS MT Meriwether Road/Kalispell – Capacity/Reliability
- $5.8 Million
ETS Stevensville A and B Line
-$4.0 Million
NWE Transmission System - Unique Aspects
•
•
•
•
•
•
75
Colstrip 500-kV transmission system
AMPS line
Retail choice & non-NWE generation
Generation > load within NWMT Balancing
Authority Area; generally an exporting
Balancing Authority
Large volume of transmission service
requests: 1500 to 2000+ per week
Open Access Transmission Tariff (OATT)
differences from other Western utilities
resulting from deregulation, IPPs, choice
loads
Path Diagram
76
Control Center Functions | Butte, MT
EMS
System
Operations
Transmission
Services
Grid
Operations
77
Transmission Services
78
Emerging Transmission Technology
Synchrophasers
• NorthWestern Energy (NWE) has been a participant in the PEAK\WECC synchrophasor project since
2011.
• The goal of the project is to provide a toolbox of new situational awareness products for WECC
members to aid in the reliable operation of the transmission system. NWE provides real time
synchrophasor angle data (voltage and current) to PEAK from three Phasor Measurement Units
(PMUs) located at the 500KV substation at Colstrip (1 PMU) and 230KV switchyard at Great Falls (2
PMUs).
• There are over 500 PMUs in the project that have been installed or are in the process of being
installed across the WECC region. Montana Tech is a partner in this project and has provided the
software for the low frequency oscillation monitoring.
Drones
• We have begun investigating the use of Drones for certain transmission applications such as
performing transmission line inspection, LIDAR survey, photogrammetry, vegetation inventory on
rights-of-way and other potential uses. For example, in a transmission line survey, a Drone may be
able to get more accurate and “close up” data, and conduct line survey more safely than conventional
fixed wing aircraft or helicopter.
79
WECC-Rated Paths
NWMT WECC Rated Paths
Path 83
325 MW
MATL
1-230 kV line
300 MW
2,200 MW
1350 MW
200 MW
Path 8
Montana-Northwest
2-500 kV lines
5-230 kV lines
3-115 kV lines
150 MW
256 MW
600 MW
Path 80
383 MW
600 MW
Yellowtail
Path 18
80
Miles City
DC Tie
Montana-Idaho
1-230 kV line
1-161 kV line
Montana-Southeast
1-230 kV line
1-161 kV line
1-200 DC tie
FERC Open Access Transmission Tariff (OATT) Regional Planning
•
81
FERC Order 1000 reforms FERC’s electric
transmission planning and cost allocation
requirements for public utility transmission
providers.
– Required NorthWestern to join a regional
planning group that satisfies certain
identified criteria.
o Northern Tier Transmission Group
(NTTG) in Montana
o Moving to SPP in South Dakota
– It also requires that NorthWestern
coordinate through this regional group with
an even larger group of neighboring utilities
at an inter-regional level.
Electric System Compliance Summary
•
•
•
•
•
82
NERC - Transmission
WECC/MRO - Transmission
– Reliability
– Critical Cyber Infrastructure Protection (CIP)
– Audits (Combo Audit in March/April 2015)
o 99 Standards; 1051 Requirements
o Very Good Outcome
– NERC Alerts
FERC – Transmission – FERC Audit began 3/17/15
– Tariff
– Generation Interconnection
– Transmission Service
MT PSC - Transmission
OSHA, DOT Transmission
FERC Open Access Transmission Tariff (OATT) Open Access Rulemaking
•
•
FERC Order 888 and 889 (late 1990s) provided for Open Access to all eligible
customers of FERC Regulated Transmission Providers
Non-discriminatory Treatment
– Defined Affiliates of Transmission Provider
– Provided New Business for Third Party Transmission Sales
2007- 2015 OASIS Revenue - Cumulative Totals by Year
36,000,000
31,000,000
2007 Actuals
2008 Actuals
26,000,000
2009 Actuals
Revenue
2010 Actuals
21,000,000
2011 Actuals
2012 Actuals
16,000,000
2013 Actuals
2014 Actuals
11,000,000
2015 Actuals
6,000,000
1,000,000
83
Jan
Feb
Mar
Apr
May
Jun
Jul
Aug
Sep
Oct
Nov
Dec
2015 - $32.1 Million
(results in offsets to
customer rates)
FERC Open Access Transmission Tariff (OATT) Generation Interconnection
FERC Order 2003 and Order 2006 - Large
and Small Generator Interconnection
Procedures (LGIP/SGIP)
Boom and Bust…
84
An Example - MSTI Project Failed
MSTI Project Shelved
– In August 2012 NWE called a “Time-Out” with the BLM, MDEQ and ceased all activity on the EIS
process,
– Led to NWE writing off the $24 million in development costs incurred for the Project.
• 50 months of analysis
• 3 ADEIS documents
• No DEIS ever produced
– This decision was the result of:
• The ever changing scope, schedule delays to complete the EIS and the significant cost of these
delays to the Project
• Lack of cooperation and coordination between agencies – BLM, MDEQ, USFS, DOE
• MFSA is outdated and statute not compatible with today’s new transmission development world
making it difficult for NWE to demonstrate purpose and need and commercial viability
• Sage grouse issue created more delays and uncertainty with the decision on possible listing
under the ESA not being made until 2015
• Declining renewable energy market in MT- energy developers unable to secure customers, lack
of national renewable energy standard, PTC uncertainty, restrictions on out of state renewables
allowed by some western states
85
Regional – Energy Imbalance Market (EIM)
Unanimous Resolution of NWPP Participants - May 29, 2015
– Development of Automated Centrally Cleared Energy Dispatch (CCED)
• Market within the BPA footprint
• Transmission to BPA preserved
• Market Operator and Development by September 2015
• Decision point mid-November 2015
• Target “Go-Live” late 2017
– Expanded Ace Diversity Interchange (ADI) Program
– Regulation Sharing Development
– Development of Resource Sufficiency Methodology
– Effort failed in late 2015
– NorthWestern currently evaluating options
86
Shutdown of the Colstrip – What does it mean to the overall Transmission System?
Large mass of stable predictable generation provides important support to the Transmission system.
– Impacts Include
o Import and Export capability reductions
o Voltage Support issues in Eastern Montana
o Loss of resource for Large Industrial Customers
o Impact to transfer capability in the North and South of Great Falls cutplane
o Replacement generation must have similar attributes
o Potential need to operate the Colstrip Transmission System (CTS)in a much less efficient
manner
– Potential contractual need to derate/decommission part or all of CTS
– BPA’s Montana Intertie also key facility paid for by Colstrip Operation
87
88
Transmission & Distribution
Overall Infrastructure
Initiative & DSIP Review
Infrastructure Vision
Integrated T&D investment and maintenance
plans which directly support NWE’s long term
strategic goals for managing our delivery
systems.
• Delivery systems serve our customers in
urban, suburban and rural areas and are
comprised of:
• Electric & Gas Transmission
• Substations/Gate/Compressor
Stations
• Electric & Gas Distribution
89
Least Cost Replacement Rate
Desired Economic
Operating Range
Prohibitively
Expensive
90
Very frequent
replacement
Unacceptable
Operations
Frequency of asset replacement
Replace only at failure
T&D Major System Categories
Major categories are used in monitoring our system delivery capabilities
 Asset Life (Managed by components)
 Reliability (By segment and asset performance)
 Capacity (By segment and asset performance)
 Compliance (By segment and asset performance)
 Automation and Technology (utilized throughout the major
categories)
91
Future Infrastructure CAPEX Plan Blueprint
Distribution Base – includes Reactive and Normal Maintenance
Transmission Base – includes Reactive and Normal Maintenance
Overall Infrastructure
Electric
Gas
Capacity
•
Distribution
•
Transmission
Capacity
•
Distribution, Substations, Transmission
Reliability
•
Distribution, Substations, Transmission
92
Automation &
Technology
Reliability
•
Distribution
•
Transmission
Asset Life
•
Distribution, Substations, Transmission
Asset Life
•
Distribution,
•
Transmission
Compliance
•
Distribution, Substations, Transmission
Safety/Compliance
•
Distribution
•
Transmission
Infrastructure Stakeholder Group
Build on model and success of DSIP and DSIP
stakeholder process
Diverse stakeholder group, including technical
skills, customers, and others
Meeting monthly over an extended period
93
Our Specification for the Future (Devleloped by first ISG)
Our vision, which we developed with the input of the ISG, is a distribution system that is:
– Safe for our employees and the public
– Reliable – consistent with the needs of a society that is increasingly dependent on electricity
– Able to grow – to accommodate the needs of new customers and potential quantum growth from
new electric applications
– Optimized – an optimum mix of investment in new plant and maintenance of existing facilities
– Responsive to all customers – minimizes the service gap between urban and rural customers
– Energy efficient – a system that provides the platform to achieve the efficient use of energy
resources
– Cost effective – a system designed, built and operated for least, long-term cost while achieving
the above objectives
– State-of-the-art – a system that employs effective technologies to further the above objectives
94
94
Future Scenarios
“Brave New Grid”
A range of potential outcomes was
initially defined
“Ready for the Future”
“More Aggressive Asset
Management”
“Stay the Course”
“Slow Decline”
Less Investment
Further ageing
Cost of catch-up
becomes too high
Spiral with recovery
nearly impossible
95
95
Same Investment
Investment now above
depreciation
Some continued
ageing
Higher maintenance
costs
Declining reliability
Cost of catch-up grows
Modest New
Investment
Arrest the ageing
New Generation of
Asset ManagementHigher Quality of
Information
More Proactive Less
Reactive Investment
and Maintenance
costs
Maintain reliability
Smart Grid
Near-term widespread
Smart Grid deployment
Significant New
Investment
Reverse the trend in
ageing
Optimize maintenance
costs
Improve reliability
Position for Smart Grid
“No barriers to future
deployment”
“No regrets about deployment”
Basis for the NWE Strategy
Facing similar challenges to those at the national level, we have set the following goals
– Arrest or reverse the trend in aging infrastructure
– Build margin (capacity) back into the system
– Maintain reliability over the long-term, and improve it for our rural customers
– Position NWE to adopt Smart Grid
– Enthusiastically embrace the industry’s new performance driven model (DIMP)
– Employ state-of-the-art analytical capabilities to proactively manage safety
– Improve leak rate performance
96
96
DSIP Progress Update 2011- 2015 Q1 (update)
DSIP
Base
Project To Date (PTD)
Gas Repairs (G1’s)
$13,596,260.00
$5,597,931.00
$2,623,084.00
$1,122,260.00
$789,508.00
$530,866.00
$17,539.00
$756,204.00
$10,566,438.00
$2,219,236.00
N/A
N/A
N/A
N/A
N/A
N/A
8,643 OH miles
8,541 OH miles
5,772 repairs
8 Circuits
*51 Substations
*28 Base Stations, 8 Subs
*15 Farm Taps
7,254 repairs
Capital Projects- $144M
Pole Replacement
Underground Cable Replacement
Substation Upgrades
Capacity Upgrades
Gas Historic Block Refurbishment
Rural Reliability Improvement
Automation
Farm Taps
$56,396,772.00
$28,260,229.00
$12,151,861.00
$10,310,909.00
$23,120,000.00
$2,076,454.00
$4,644,622.00
$329,361.00
$11,495,784.95
$7,986,501.34
N/A
N/A
N/A
N/A
N/A
N/A
21,299 poles
787,000 trench ft.
*51 Substations
19 projects
160 blocks
8 Circuits
*28 Base Stations, 8 Subs
*15 Farm Taps
Expense Projects- $42M
Tree Trimming
Pole Inspection
OH Electric Repairs (P2’s)
Rural Reliability Improvement
Substation Upgrades
Automation
Farm Taps
*Combination of Capital and Expense
97
Conceptual Layout
Questions?
98
DSIP Progress Update 2011- 2015 Q1 (update)
Operations Prioritization Model
– Emergency response – out of powers, gas odors, hit gas lines.
– Service continuity in jeopardy (outage inevitable) overloaded equipment, low gas pressure, no
heats, low voltage, busted cross-arm.
– Compliance requirements – federal mandates, contractual obligations.
– Customer service – new construction, pilot lights – off season, turn on/turn offs.
– Routine maintenance – O&M guidelines not covered by compliance requirements, routine
system equipment replacement not covered above.
99
Asset Management and System Integrity Plan Development
Asset Management and System Integrity Plan Development
– Three major components.
• Capacity
– Transmission system, gate station and equipment.
» Identify gate station capacity requirements.
»
Radial source station.
»
Winter loading capacity – design capacity.
»
Actual system monitoring to determine diversity.
»
Factor and loading timeframe.
»
Proximity to other sources.
»
Determine minimum pressure requirements.
»
Establish future growth curve.
»
Forecast year for upgrades.
100
System Reliability
System reliability.
Evaluate leak history.
Evaluate cathodic reads and shorts.
Evaluate bell hole reports watching for external and internal corrosion
Issues.
101
Asset Life
Asset Life
Define major asset classes.
Determine impacts of failures on system performance, safety, customer
satisfaction and potential risk profiles.
Ability to establish asset life expectancy.
Ability to determine asset failure curves.
Evaluate economics of preventative maintenance and inspection
guidelines.
Ability to perform just in time replacement.
Economics of a proactive replacement program vs reactive failure
replacement.
102
Asset Life (cont’d)
– Proactive maintenance programs.
– Systematic replacement ahead of failure.
–
Main replacement.
–
Service replacement.
–
Gate station heaters and equipment replacement.
–
Gas ERT replacement – metering.
• System risk that has to be considered and balanced against economic risk.
– Potential costs of an individual incident.
– Probably of each incident actually happening.
– Ability to respond to any incident.
•
•
•
•
•
•
103
Establishing the value of safety – public and workforce.
Worker compensation values can be established for each lost time incident.
Evaluating costs of updating system to new standards and guidelines.
Establishing cost of a reliability minute.
Impacts of disturbances on customer satisfaction.
Costs to customers for each option.
Physical and Cyber Security
Security Coordinating Council
•
The Security Coordinating Council (“SCC”) serves as the cross-functional clearinghouse for consulting, advising and guiding
NorthWestern Energy policies, procedures, direction, prioritization, and coordination for cyber and physical security.
–
•
Initiatives include NERC physical and cyber security requirements, cyber security beyond NERC as it relates to our overall corporate cyber
infrastructure and general security of our facilities.
The Members/Participants are:
– Permanent Members.
o
o
o
o
o
o
o
o
–
Participants. The following will participate in the SCC in order to provide continuity with related internal controls, internal and
external audit and compliance considerations, and technical and business process expertise:
o
o
o
o
104
Vice President – Transmission (Executive Sponsor and Chair);
Chief Business Technology Officer;
Director of Support Services;
Director of Grid Operations;
Director of Substation Operations;
Director of Human Resources;
Director of Safety, Health, and Environmental Services;
General Manager of Generation.
President & CEO, and other Executives, as necessary;
Other subject matter experts, as necessary and at the request of the SCC Chair.
Chief Audit and Compliance Officer;
FERC Compliance Officer.
Operations Prioritization Model – Gas and Electric
Guidelines for O&M and CAPEX Investment Decisions
1. Emergency Response – out of power, gas odors, hit gas lines.
2. Service Continuity in Jeopardy (outage inevitable) - overloaded equipment, low gas pressure, no heat, low voltage,
busted cross-arm.
3. Compliance Requirements – federal mandates, contractual obligations.
4. Customer Service – new construction, pilot lights-off season, turn-on, turn-off.
5. Proactive and Routine System Maintenance and Investment – O&M guidelines not covered by compliance
requirements, proactive and routine system equipment replacement not covered above.
a. Sub-prioritized based on overall value and risk.
105
Reliability Data Base Demo
106
Current Situation
Reliability
– First quartile performance
– Stable and holding in the short-term.
– Current Investment will not sustain this level of service long term
Capacity
– Adequate to serve existing needs.
– Stable in the short term
Asset Life
– Aging assets.
• Some major assets have high percentage reaching predicted useful life.
– Pole assets 40% in ten years (115,000 poles).
– Cable assets 20% in ten years (3,822,386 feet of cable).
107
Pole Age Profile
Pole Age Profile
100000
# of Poles
80000
60000
40000
20000
0
0 to 10
10 to 20
20 to 30
30 to 40
40 to 50
50 to 60
60 to 70
Urban
5131
11114
8160
6932
4362
3386
1412
Rural
27245
59010
43325
36806
23162
17976
7499
4140
8966
6583
5593
3519
2731
1139
91
196
144
122
77
60
25
36607
79286
58212
49453
31121
24153
10075
Combination
Undefined
Total
Age Category
108
Underground Cable Age Profile
Underground Cable Age Profile
Percent of Total
50.00%
40.00%
30.00%
20.00%
10.00%
0.00%
Years
0 to 10
10 to 20
20 to 30
30 to 40
40 to 50
41.21%
38.74%
15.78%
4.15%
0.12%
Years Category
109
Underground Cable Age Profile II
Underground Cable Age Profile
9,000,000
8,000,000
Feet of Cable
7,000,000
6,000,000
5,000,000
4,000,000
3,000,000
2,000,000
1,000,000
Cable Feet
0 to 10
10 to 20
20 to 30
30 to 40
40 to 50
7,857,453
7,387,183
3,008,746
790,639
22,833
Years Category
110
What is the
Future?
111
Glossary of Terms
CAIDI
– Customer Average Interruption Duration Index (Hrs/Cust): Average outage duration (hours) for those
customers who have been interrupted during the year.
SAIFI
– System Average Interruption Frequency Index (Int/SysCust): Number of outages, on average, that any
average system customer would experience during the year.
SAIDI
– System Average Interruption Duration Index (Hrs/SysCust): Average outage duration (hours) that any
average system customer would experience during the year.
Note: Outage Indices Definitions based on IEEE/EPRI publications.
IEEE
– Institute of Electrical and Electronic Engineers Professional Engineers Society.
112
Organization Overview
•
113
Distribution (770 Total Employees)
– Mt Operations
o 344 Craft (union represented)
o 34 Engineering & Supervision
– Mt Construction
o 51 Supervision & Engineering
– SD Operations
o 150 Craft (union represented)
o 31 Engineering & Supervision
– Asset Management (Supports both T&D)
o 61 Supervision and Support
– Support Functions (99 Employees)
2014 Operations Highlights
1. Best year ever from a Safety Perspective
2. Strong year in Electric Reliability and Gas Leak performance
3. Great execution of work plans
1. Both Operating (expense plans) and Construction (CAPEX) plans
2. More work completed in our History
1.
2.
Base plans (higher growth)
DSIP Execution
4. In-Service Implementation
114
Major Initiatives
•
•
115
T&D – Development of a Comprehensive Infrastructure Plan
Distribution
– Continued Process Improvement (refined work planning and execution, Construction and
Operations
– Continued In-Service refinement
o Mobile Workforce Management
o Outage Management
– Distribution System Infrastructure Project (DSIP) execution
– Workforce Planning
– Other Technology Evaluation and Testing
o Smart Grid Pilot – Distribution Automation
o Volt / Var Optimization
o AMI
o LED Lighting
o Solar and other Distributed Generation Applications
Technology Evaluation
1.
2.
3.
4.
5.
116
System Automation
1. Distribution Segmentation (Fault Location Isolation and Service Restoration)
2. Communications Platform
Distributed Generation
1. Rural Solar Reliability Project (Beck’s Hill)
2. Solar – Community / Residential
1. Bozeman Project
3. Potential Microgrids
Volt / Var Control
LED Lighting
Other
1. Gas Expansion
2. Electric Vehicles
Montana Electric Delivery System Reliability Overview
Montana SAIDI w/o MEDs
S
A
I
D
I
m
i
n
180
160
140
120
100
80
60
40
20
0
TOTAL
TRANS.
DIST.
Linear (TOTAL)
Linear (TRANS.)
Linear (DIST.)
2007200820092010201120122013201420152016201720182019
YEAR
180
S
A
I
D
I
160
m
i
n
80
Considerations
Improve outage collection process
A lot of unknowns being recorded
Improve integration between distribution and
transmission outage recording systems
Montana SAIDI with MEDs
140
120
TOTAL
100
TRANS.
DIST.
Linear (TOTAL)
60
Linear (TRANS.)
40
Linear (DIST.)
20
0
117
Current Status
Reliability trend upward
Outage information from distribution outage tracker
Sustained outages include line and substation
outages
2007200820092010201120122013201420152016201720182019
YEAR
Delivery System Reliability Overview
YEAR
118
150
2000
100
1000
50
0
YEAR
2019
0
2018
Linear (TRANS.)
3000
2017
2019
2018
2017
2016
2015
2014
2013
2012
2011
2010
2009
0
2008
0
Linear (DIST.)
200
2016
50
4000
2015
1000
Linear (TOTAL)
250
2014
100
5000
2013
2000
TRANS.
300
2012
150
3000
DIST.
6000
2011
200
4000
350
2010
5000
TOTAL
7000
2009
250
400
2008
6000
8000
2007
300
Distribution Outages
7000
Transmission Outages
350
2007
Distribution Outages
8000
Transmission Outages
MT Outages with MEDs
MT Outages w/o MEDs
TOTAL
DIST.
TRANS.
Linear (TOTAL)
Linear (DIST.)
Linear (TRANS.)
Substation System Reliability Overview
Substation Equipment Failures
9
O
u
t
a
g
e
C
o
u
n
t
s
8
7
AirBreak
6
Arrestor
Breaker
5
Disconnect
4
Insulator
3
Recloser
2
Transformer
1
0
AirBreak
Arrestor
Breaker
Disconnect
Insulator
Recloser
Transformer
119
2007
8
0
0
0
2
4
2
2008
0
0
5
0
0
5
0
2009
0
3
4
6
0
3
2
2010
0
0
1
0
0
0
0
2011
0
1
2
1
2
0
1
2012
0
3
0
1
4
0
2
2013
0
1
8
0
2
1
9
Transmission Substation System Reliability Overview
Transmission Substation Reliability
Current Status
Both Outages & SAIDI dropped for 2-3
years, but rose in 2013. Sustained
outages including only those occurring
within the substation
SAIDI
35
5
4.5
30
4
25
3.5
3
20
2.5
15
2
1.5
10
1
5
0.5
0
0
2007
120
2008
2009
2010
2011
2012
2013
SAIDI
Outage Count
Considerations
Improve outage collection process, a lot
of unknowns being recorded Substation
is the highest level of outage
recordable, so a line outage that
causes a sub
outage is very difficult to record
Outage Count
Transmission Capacity Summary
System Loading
•The Electric Transmission System is generation rich with slowly
increasing load:
•1,800 MW Peak Load In Demand/Core Customers (control
area peak Dec ‘08).
•2875 MW Pre-2000 Generation now in service.
•988 MW Post-2000 Generation now in service.
•251 MW planned (signed LGIA, not yet in service).
•Additional 1835 MW (43 Projects) now in study queue.
Regional Interconnections
There are five major paths to other systems with interconnections to six other utilities and for export/import.
NWE’s planning efforts are coordinated with WECC (interconnection wide - western US, Canada, Mexico) and
NTTG (regional - Pacific Northwest and neighbors) and TRANSAC (local utilities and neighbors)
Note: 4 of 5 import/export paths are heavily or fully loaded.
121
Transmission System Capacity Overview
Transmission Delivery Capabilities
4500
4000
3500
3000
Total Capacity MVA
2500
MVA
Contingency Capacity MVA
Peak Usage MVA
2000
Average Usage MVA
Minimum Usage MVA
1500
1000
500
0
2007
122
2008
2009
2010
2011
2012
2013
2014
2015
Transmission System Capacity Overview
System Line Capacity Loading
2015 System Normal
% Utilization
Available Capacity (MW)
Line KV
Min
Max
Average
Min
Max
Average
230
7.9
56.5
33.0
210.2
452.9
311.4
161
5.0
56.3
26.8
72.7
158.9
126.6
100/115
3.5
55.4
26.9
12.8
147.8
66.3
69
2.9
65.6
20.5
8.1
58.1
26.5
50
1.4
50.8
19.8
6.7
57.2
23.3
Current Status
System Capacity is stable with some areas of segment
congestions
4,000 MVA of Total system deliverability
3,500 MVA of NERC Contingency deliverability
3,200 MVA peak system usage (load, generation, transfer)
80%
2015 Single Outage
%Transformer Utilization by Voltage
- Summer 2015
60%
40%
% Utilization
123
Available Capacity (MW)
Line KV
Min
Max
Average
Min
Max
Average
230
19.2
103.5
58.5
-16.7
386.2
190.0
161
7.8
73.7
42.6
43.4
154.7
99.1
100/115
7.9
108.2
49.1
-6.6
112.8
47.1
69
2.9
78.3
23.2
4.5
57.3
25.8
50
1.4
90.0
26.9
2.5
56.8
21.1
20%
0%
500
230
161
115
100
69
50
Conceptual Layout
T&D
Asset
Life
124
Asset Life – Mt Distribution Pole Plant
125
Asset Life – Transmission Pole Plant
Electric Transmission Pole Plant Age
kV
Pole
Coun
t
kV %
Sum of
of
Current
Total Rejected
Poles
Poles
Sum of
Replace
d
Rejecte
d Poles
Sum of
Total
Rejecte
d Poles
% of
% of
Rejected
Total
Poles
Rejected
Rejec Replace
Poles
t Rate
d
Replaced
11788
12.7
%
269
127
396
3.4%
32.1%
14.9%
21937
23.6
%
781
307
1088
5.0%
28.2%
36.0%
100
26106
28.0
%
1048
157
1205
4.6%
13.0%
18.4%
115
4698
5.0%
22
147
169
3.6%
87.0%
17.3%
16419
17.6
%
355
42
397
2.4%
10.6%
4.9%
12129
13.0
%
14
72
86
0.7%
83.7%
8.5%
50
69
161
230
126
40,000
20,000
0
0-9
10 - 19 20 - 29
30 - 39
40 - 50
> 50
Current Status
•Pole Inspect.(test/treat) on 10 yr cycle
•Completed first inspection cycle in 2013
•Funding does not address all 4 rated poles
•Average reject rate of 3.28%
•Backlog of 2,489 - 4-rated poles (93,077)
•Assumed asset Life cycle of 80 years
Asset Life - Distribution Transformer Age Profile
Transformer Age Profile
Transformer Counts by Age Group
104
120
87
100
66
80
69
61
60
40
16
20
0
127
24
19
•Transformer counts by age
group
•Transformers replacements
account for the majority of the
plan costs
•Average transmission
transformer age is 42 years
•Current criteria recommends
replacing transformers at 45
years
128
Asset Life - Transmission Transformer Age Profile
Transformer Age Profile
Transformer Counts by Age Group
66
70
51
60
50
40
30
20
10
0
20
13
13
4
20
11
•Transformer counts by age
group
•Transformers replacements
account for the majority of the
plan costs
•Average transmission
transformer age is 43 years
•Current criteria recommends
replacing transformers at 40
years
Electric System Compliance Summary
•
•
•
•
•
•
129
NERC - Transmission
WECC - Transmission
– Reliability
– CIP
– Audits (Combo Audit in April 2015 – very good results)
– NERC Alerts
FERC – Transmission
– Tariff
– GIAs
– TSRs
NESC – Distribution
– Line Clearance
MT PSC / SD PUC - Distribution
– Line extension tariffs
OSHA – Transmission & Distribution
Major Initiatives
•
•
T&D – Development of a Comprehensive Infrastructure Plan
Transmission
– Large Project Completion
o Big Sky Jackrabbit 161 kV conversion (MT) – $51.9 Million
o Columbus Chrome – Stillwater 100 kV (MT) – $46.7 Million
o NERC Alert Facilities Rating Project (MT) - $24.2 + 230/161
o Various Large Substation Projects (MT/SD)
o Gas Transmission Growth – Compression/Pipeline Looping
130
– Continued Improvement of Project Management Processes
– Further Implementation of Substation Maintenance Plans and
Data Bases
– Grid Operations – Enhanced Same Day/Real Time System
Diagnostics
– Gas Transmission System Operations (Gas/Electric System
ops split)
– Third Party Revenue that Offsets Customer Costs – Electric
and Gas
– Regulatory Compliance Activities
TX SYSTEM “NERC ALERT – FACILITIES RATINGS”
•
•
The North American Electric Reliability Corporation (NERC) issued a Recommendation and
Guidance to Industry on the "Consideration of Actual Field Conditions in Determination of
Facility Ratings."
This recommendation is to verify actual field conditions and compare them to the documented
design of the facility. This recommendation applies to all bulk electric transmission system
facilities (100 kV and above). These are safety reliability related improvements.
Line Voltage
230 kV - Medium Priority
161 kV - Medium Priority
115 kV - Low Priority
100 kV - Low Priority
131
Gas System Capacity
132
•
Distribution monitored thru flow models and planned out 5 years
– Reviewed each year with lowest actual system pressures experienced
•
Transmission Monitored thru historical models updated each year with peak year
and estimated design day results.
o Could change based on the 2014/15 winter experience or potential gas
expansion opportunities
Gas Distribution Reliability / Safety
Excavation Damages per 1,000 Locate Tickets - NWE
NWE
AGA 1st Quartile Average
5.0
3rd Quartile
4.0
3.6
2nd Quartile
3.0
2.6
1st Quartile
2.0
1.7
1.5
1.0
2011
133
2012
2013
2014
Gas Distribution Reliability / Safety
Leaks per 100 Miles of Pipe - NWE
NWE
18.0
16.0
14.0
12.0
10.0
8.0
7.0
1st Quartile
6.0
6.2
5.6
4.6
4.0
2.0
2011
134
2012
2013
2014
Asset Life -T&D Gas
•
•
•
Distribution System components currently under evaluation
– Historic Business Districts
– Inside Meter Sets
– Pre 1950 construction
– Aldyl A pipe (pre 1970)
Monitored thru the DIMP program
– Risk ranked model of distribution components
– Currently addressing accelerated actions through base budgets and DSIP
Transmission System components currently under evaluation
– Farm Taps
– Pre 1950 construction
– Electric Resistance Weld Seams
– High Consequence Areas
o Monitored thru the PIM program
o
135
Risk ranked model of transmission components
Gas System Compliance
•
DOT - Pipeline and Hazardous Materials Safety Administration
(PHMSA)
– DIMP – Distribution
– PIM/HCA – Transmission
o
o
•
•
136
New Regulations coming – Class 3 Locations
Control Room Management
– Drug and Alcohol testing
– Now proposed, Safety Management System
OSHA
MTPSC / SDPUC / NEPSC
– Line extension policies
MT Natural Gas - Production
Existing Production
• Battle Creek (2010)
o 170 Wells - Production Estimate – .37 BCF (2015)
o Net PDP Gas Reserve – 8.4 BCF
o Purchase Price - $12.4 Million
o 20 Year Levelized Cost - $5.96/dth – Approved Nov. 2012
o Production vs. Model – 98.2% (4.5 years)
•
•
Bear Paw (NFR- 2012)
o 600 Wells - Production Estimate - 0.98 BCF (2015)
o Net PDP Gas Reserve – 13.7 BCF
o Purchase Price $16.8 Million
o 20 Year Levelized Cost - $3.80/dth
o Production vs. Model – 102.1% (3 years)
Bear Paw South (Devon- 2013)
o 916 Wells - Production Estimate - 4.41 BCF (2015)
o Net PDP Gas Reserve – 63 BCF
o Purchase Price $62.6 Million
o 20 Year Levelized Cost - $4.10/dth
o Production vs. Model – 101.1% (2 year)
Percent of Retail Load
2% 5%
22%
71%
•
•
•
Market Purchases
Battle Creek
Bear Paw
Bear Paw South
Core supply need 20 BCF
Owned production = 29% of supply
Remaining need filled through purchases
Distribution Infrastructure Investment Strategies
Execution and Continued Improvement of Existing Business
Execute Existing Plans - Find ways to improve processes that
balances service quality and cost.
• Organic Growth Capital $122M over next five years.
• Base Maintenance Capital $241M over the next five years.
• DSIP Capital $233M over the next five years.
• Total $596M over the next five years.
139
Distribution System Infrastructure Plan (DSIP) Update
Well Established Processes
• Construction team organized processes.
• Solid project management structure.
• Baseline scope, schedule, budget, monitoring and control.
Excellent Monthly and Annual Reporting
• Tracking reports and SAP reports- feeds into the project management reports which provides
early warning signs.
Maintain Scope
• Aware of any scope creep.
• Documentation physical work (earned value) complete.
Current Challenges
• Pole inspection and pole change out.
• Substations – will be addressed with SSIP.
• Underground cable replacement.
• Overall gas plan re-prioritization.
140
Current DSIP CAPEX Plan
DSIP CAPEX (updated June 2014)
Significant Rough Order of Magnitude (ROM) Estimate
Projects That Have Been Rescheduled or Postponed Due To Annual Budget Constraints
Planned Cost (PC) of Work Performed - By Year
ACTUAL
Orig Budget
Forecast by 2017
Delta by 2017
2011
PLANNED
E/G
Task Name
2012
2013
2014
2015
2016
2017
E
DSIP Poles
$93,860,000
$110,470,779
$16,610,779
$6,748,015
$7,934,239
$15,788,525
$20,000,000
$20,000,000
$20,000,000
$20,000,000
E
DSIP Cable
$49,140,000
$71,451,934
$22,311,934
$1,062,059
$1,811,178
$10,898,957
$10,429,740
$15,750,000
$15,750,000
$15,750,000
E
DSIP Circuits (Rural Reliability)
$4,290,000
$4,520,732
$230,732
$457,674
$482,218
$1,080,840
$200,000
$300,000
$1,000,000
$1,000,000
E
DSIP Capacity
$21,940,000
$19,194,823
-$2,745,177
$0
$0
$5,299,074
$4,995,749
$3,600,000
$2,725,000
$2,575,000
E
DSIP Substations
$16,930,000
$21,735,185
$4,805,185
$777,374
$2,243,768
$3,867,043
$2,397,000
$4,450,000
$4,000,000
$4,000,000
E
DSIP UG Equip Repair
$1,380,000
$346,917
-$1,033,083
$0
$0
$46,917
$0
$100,000
$100,000
$100,000
G
DSIP Gas One Plan
$0
$14,500,000
$14,500,000
$4,500,000
$5,000,000
$5,000,000
G
DSIP Gas Business Districts
$36,500,000
$20,678,147
-$15,821,853
$5,540,852
$5,205,466
$4,631,197
$5,300,632
$0
$0
$0
G
DSIP Zone Valves
$5,180,000
$3,203,062
-$1,976,938
$376,315
$721,775
$5,354
$399,618
$200,000
$750,000
$750,000
G
DSIP Farm Taps
$530,000
$686,885
$156,885
$0
$0
$214,117
$122,768
$175,000
$175,000
$0
G
DSIP Gas Service Stubs
$4,980,000
$694,316
-$4,285,684
$0
$0
$494,316
$200,000
$0
$0
$0
G
DSIP Gas Line Under Structure
$4,130,000
$1,645,200
-$2,484,800
$0
$0
$815,398
$829,802
$0
$0
$0
G
DSIP Inside Mtr Serv Repl
$850,000
$341,214
-$508,786
$0
$0
$171,232
$169,982
$0
$0
$0
E
DSIP Automation
$42,900,000
$14,682,103
-$28,217,897
$0
$41,868
$1,232,498
$6,200,000
$1,481,076
$1,956,833
$3,769,828
E
DSIP Line Code Corrections
$3,920,000
$3,224,580
-$695,420
$0
$0
$624,580
$650,000
$650,000
$650,000
$650,000
DSIP DIMP
$350,000
$317,806
-$32,194
$139,486
$168,774
$9,546
$0
$0
$0
$0
DSIP Other
$0
$2,387,000
$2,387,000
$56,991
$128,280
$2,201,729
$0
$0
$0
$0
$286,880,000
$290,080,683
$3,200,683
$15,158,766
$18,737,566
$47,381,323
$51,895,291
$51,206,076
$52,106,833
$53,594,828
Financial Targets
Based on 5-Year Plan
$51,206,076
$52,106,833
$53,594,828
Delta
$0
$0
$0
$184,379,022
$236,485,855
$290,080,683
Cumulative Budgeted
Cost (Actual,
Forecasted &
Planned)
$15,158,766
$33,896,332
$81,277,655
$133,172,946
Current DSIP O&M Plan
DSIP O&M (June 2014)
Significant Rough Order of Magnitude (ROM) Estimate
Projects That Have Been Rescheduled or Postponed Due To Annual Budget Constraints
Planned Value (PV) of Work Performed - By Year
E/G
Task Name
E
DSIP-Pole Inspections
E
DSIP-Line Clearance
E
ACTUAL
Orig Budget
Forecast by 2017
Delta by 2017
2011
PLANNED
2012
2013
2014
2015
2016
2017
$8,000,000
$11,264,535
$3,264,535
$611,279
$1,533,067
$1,920,189
$1,800,000
$1,800,000
$1,800,000
$1,800,000
$24,670,000
$24,899,699
$229,699
$2,431,672
$2,646,630
$4,021,397
$3,400,000
$4,200,000
$4,000,000
$4,200,000
DSIP-OH Repair from Patrol P2
$5,910,000
$5,466,284
-$443,716
$0
$576,576
$889,708
$1,000,000
$1,000,000
$1,000,000
$1,000,000
E
DSIP-Rural Reliability Improvements
$8,640,000
$2,341,738
-$6,298,262
$170,142
$556,024
$396,094
$0
$21,000
$198,478
$1,000,000
E
DSIP-System Automation
$1,460,000
$552,233
-$907,767
$0
$369,970
$79,263
$43,000
$60,000
$0
$0
E
DSIP-Substation Upgrade & Improvements
$4,130,000
$1,864,487
-$2,265,513
$0
$0
$264,487
$400,000
$400,000
$400,000
$400,000
E
DSIP-Underground Equipment Repair
$3,390,000
$3,816,927
$426,927
$0
$0
$60,000
$0
$1,000,000
$1,250,000
$1,506,927
G
Gas One Plan
$250,000
$500,000
$500,000
G
DSIP-Dist Integrity Mgmt Prog
$2,090,000
$792,215
-$1,297,785
$522,952
$269,235
$28
$0
$0
$0
$0
G
DSIP-Zone Valve Installation
$4,710,000
$2,363,461
-$2,346,539
$167,755
$289,444
$36,262
$20,000
$0
$850,000
$1,000,000
G
DSIP-Non-Business Inside Mtr
G
DSIP-Gas Line Damage Prevention
G
G
G
DSIP-Gas Lines Under Structures
G
DSIP-Repairs G1
O
$210,000
$26,740
-$183,260
$0
$0
$26,740
$0
$0
$0
$0
$8,060,000
$3,993,953
-$4,066,047
$0
$0
$243,953
$750,000
$1,000,000
$1,000,000
$1,000,000
DSIP-Farm Tap Rebuild
$110,000
$167,539
$57,539
$0
$0
$17,539
$0
$75,000
$75,000
$0
DSIP- Gas Stub Removal
$530,000
$345
-$529,655
$0
$0
$345
$0
$0
$0
$0
$1,060,000
$0
-$1,060,000
$0
$0
$0
$0
$0
$0
$0
$0
$886,500
$886,500
$0
$75,058
$471,442
$340,000
$0
$0
$0
DSIP-Supervision & Engineering
$7,220,000
$7,432,438
$212,438
$686,540
$896,402
$861,823
$1,200,000
$1,201,318
$1,273,080
$1,313,275
E
DSIP-GIS Expansion
$8,210,000
$3,444,363
-$4,765,637
$292,328
$3,152,035
$0
$0
$0
$0
$0
E
DSIP-EL Lighting Inventory
$500,000
$431,681
-$68,319
$0
$431,681
$0
$0
$0
$0
$0
$88,900,000
$69,745,138
-$19,154,862
$4,882,668
$10,796,122
$9,289,270
$8,953,000
$11,007,318
$12,346,558
$13,720,202
Cumulative
Budgeted Cost
(Actual, Forecasted
& Planned)
$4,882,668
Budgeted Cost (Actual, Forecasted & Planned)
$15,678,790
$24,968,060
$33,921,060
$44,928,378
$57,274,936
$70,995,138
Electric Amortization
$2,532,412
$2,532,413
$2,532,413
$2,532,413
$2,532,413
Gas Amortization
$603,346
$603,346
$603,346
$603,346
$603,346
Total Annual Budget
$12,425,028
$12,088,759
$14,143,077
$15,482,317
$16,855,961
Financial Targets
Based on 5 year
Plan
$14,143,077
$15,482,317
$16,855,961
Delta
$0
$0
$0
142
Beyond DSIP Anticipated Infrastructure Investment
Planned Cost - By Year
E/G
Task Name
E
E
E
E
E
E
G
G
G
G
G
G
G
E
E
DSIP Poles
DSIP Cable
DSIP Circuits (Rural Reliability Improvements)
DSIP Capacity
DSIP Substations
DSIP UG Equip Repair
DSIP Gas One Plan
DSIP Gas Business Districts
DSIP Zone Valves
DSIP Farm Taps
DSIP Gas Service Stubs
DSIP Gas Line Under Structure
DSIP Inside Mtr Serv Repl
DSIP Automation
DSIP Line Code Corrections
DSIP DIMP
DSIP Other
TOTALS
TOTAL
$25,000,000
$78,750,000
$5,000,000
$0
$0
$0
$25,000,000
$0
$0
$0
$0
$0
$0
$10,000,000
$0
$0
$0
$143,750,000
Current 5 yr Plan
2018
$5,000,000
$15,750,000
$1,000,000
$0
$0
$0
$5,000,000
$0
$0
$0
$0
$0
$0
$2,000,000
$0
$0
$0
$28,750,000
$24,000,000
2019
PLANNED
2020
$5,000,000
$15,750,000
$1,000,000
$0
$0
$0
$5,000,000
$0
$0
$0
$0
$0
$0
$2,000,000
$0
$0
$0
$28,750,000
Electric
• Second 10 year Cycle of Pole Replacement (20 – 30,000 poles) $5M per yr
• Complete 2nd phase of the10 year plan of Cable replacement $15.7M per yr
• Continue rural worst circuit program $1M per yr
• Complete Substation Automation / Communication
Gas
• Continue to mitigate High risk Blocks $5M per year
143
$5,000,000
$15,750,000
$1,000,000
$0
$0
$0
$5,000,000
$0
$0
$0
$0
$0
$0
$2,000,000
$0
$0
$0
$28,750,000
2021
$5,000,000
$15,750,000
$1,000,000
$0
$0
$0
$5,000,000
$0
$0
$0
$0
$0
$0
$2,000,000
$0
$0
$0
$28,750,000
2022
$5,000,000
$15,750,000
$1,000,000
$0
$0
$0
$5,000,000
$0
$0
$0
$0
$0
$0
$2,000,000
$0
$0
$0
$28,750,000
Beyond DSIP Anticipated O&M Cost
Planned Cost - By Year
PLANNED
E/G
Task Name
TOTAL
2018
2019
2020
2021
2022
E
DSIP-Pole Inspections
$4,750,000
$950,000
$950,000
$950,000
$950,000
$950,000
E
DSIP-Line Clearance
$6,000,000
$1,200,000
$1,200,000
$1,200,000
$1,200,000
$1,200,000
E
DSIP-OH Repair from Patrol P2
$1,500,000
$500,000
$250,000
$250,000
$250,000
$250,000
E
DSIP-Rural Reliability Improvements
$500,000
$100,000
$100,000
$100,000
$100,000
$100,000
E
DSIP-System Automation
$0
$0
$0
$0
$0
$0
E
DSIP-Substation Upgrade & Improvements
$0
$0
$0
$0
$0
$0
E
DSIP-Underground Equipment Repair
$2,350,000
$500,000
$600,000
$700,000
$250,000
$300,000
G
Gas One Plan
$2,500,000
$500,000
$500,000
$500,000
$500,000
$500,000
G
DSIP-Dist Integrity Mgmt Prog
$0
$0
$0
$0
$0
$0
G
DSIP-Zone Valve Installation
$0
$0
$0
$0
$0
$0
G
DSIP-Non-Business Inside Mtr
G
DSIP-Gas Line Damage Prevention
G
G
$0
$0
$0
$0
$0
$0
$5,000,000
$1,000,000
$1,000,000
$1,000,000
$1,000,000
$1,000,000
DSIP-Farm Tap Rebuild
$0
$0
$0
$0
$0
$0
DSIP- Gas Stub Removal
$0
$0
$0
$0
$0
$0
G
DSIP-Gas Lines Under Structures
$0
$0
$0
$0
$0
$0
G
DSIP-Repairs G1
$0
$0
$0
$0
$0
$0
O
DSIP-Supervision & Engineering
$3,000,000
$600,000
$600,000
$600,000
$600,000
$600,000
E
DSIP-GIS Expansion
$0
$0
$0
$0
$0
$0
E
DSIP-EL Lighting Inventory
TOTAL
Current 5 year plan
Electric O&M Estimated $3M per year
Gas O&M Estimated $1.5M per year
$0
$0
$0
$0
$0
$0
$25,600,000
$5,350,000
$5,200,000
$5,300,000
$4,850,000
$4,900,000
$3,905,309
Distribution Segmentation
•Under Evaluation – Estimated $4.0M
• Impact estimated at eight min SAIDI.
10
20
5
0
0
YEAR
145
2019
40
2018
15
2017
60
2016
20
2015
80
2014
25
2013
100
2012
30
2011
120
2010
35
2009
140
2008
40
2007
Distribution (mins)
160
Transmission (mins)
D. SEGMENTATION
SAIDI
Impact: 8 mins
TOTAL
DIST.
TRANS.
Linear (TOTAL)
Linear (DIST.)
Linear (TRANS.)
Gas Distribution – GAS ONE Plan
•Combines all of the components of DSIP into one plan
•
•
•
•
•
•
•
Main components:
Inside meterfits
Stubs
Lines under structures
Pre-1950 services
Components combined into blocks
Each component is risk ranked giving a block a total risk ranking
• Currently approx 7000 blocks in the database with elements
of these components
•Planned implementation in 2015 within DSIP
• Better Planning and efficient construction
• Better risk mitigation
146
Longer Term- Distribution Infrastructure Investment
Electric
• Substation Equipment Investment – Plan under
development
• South Dakota Version of DSIP (Poles and UG)
• $15M - $25M incremental over the next 10 years
• Other infrastructure to be evaluated
• Conductor
• Lack of Neutrals
Gas
• Adyl A (pre 1970) – pipe replacement ($15M - $25M)
• Other DIMP ($20M - $30M)
• Continue with Gas One plan - Higher risk blocks
147