Puget Sound Fuel Blind Integrated Resource Planning Project Final Report
sTA o~
W~ yam?
'L 1889 SEP - g 1994 1
J'
STATE OF WASHINGTON
G
WASHINGTON STATE ENERGY OFFI
925 Plum St. SE, Town Square Bldg #4 0 PO Box 43165 o Olympia, Washington 98504-3165
September 5, 1994
Dear City and County Planners in the Puget Sound Region:
We are pleased to provide you with a copy of the final report on the Puget Sound Fuel Blind Integrated
Resource Planning Project (Project), prepared by the Washington State Energy Office (WSEO).
The Puget Sound Fuel Blind Integrated Resource Planning Project was initiated in the Fall of 1992. The
federal Department of Energy provided funding for WSEO's participation and facilitation of the project.
Participants in the Project include representatives from Puget Sound Power and Light Company,
Washington Natural Gas Company, Seattle City Light, the Washington State Energy Office, and the staff
of the Washington Utilities and Transportation Commission.
The goal of the Project was to identify ways that utilities can work together to reduce costs, increase
efficiency, and enhance the environment. The Project participants have recommended an implementation
plan consisting of five major strategies designed to overcome barriers to cost effective opportunities. Of
particular interest to county and municipal planners in the region is the first recommended strategy,
which involves greater coordination of long-term distribution and infrastructure planning among utilities,
municipalities, and counties.
The three utilities involved in the Project have already been active in commenting on and assisting
counties and municipalities in developing Comprehensive Plans under the Growth Management Act.
The implementation plan proposes that this relationship continue and be strengthened to include active
assistance to counties and municipalities to ensure that the principles established in Comprehensive Plans
can be coordinated with energy planning. Such coordination will likely reduce cost and overall energy
use for cities, utilities, and citizens alike.
The Washington State Energy Office looks forward to discussing this Reportwith you and meeting to
discuss your ideas for greater cooperation among utilities, cities, and counties. For further information,
please contact Dick Byers (206) 956-2022 or Deb Ross (206) 956-2124, at the Washington State Energy
Office.
Si rely,
C
Judith Merchant
Director,
JM/ksa/D-L 1-26W
Enclosure
cc: Dick Byers, WSEO
Deb Ross, WSEO
(206) 956-2000 or SCAN 494-2000 Telefax (206) 956-2217 TDD (206) 956-2218
0'- is A
Puget Sound
Fuell3lind
Integrated Resource
Planning Project
Final Report
Working group participants:
Puget Sound Power Washington State
and Light Company: Energy Off ce:
Jim Heidel Richard Byers,
Corey Knutsen Project Manager
Carl Lian Dan Dodds
Elsie Oleson Jim Harding
Deborah Ross
Seattle City Light:
Vilamar Gamponia Washington Utili-
Dennis Parrish ties and Transporta-
Allen Wilson tion Commission:
Alan Buckley
Washington Natural Ken Elgin
Gas Company: Bruce Folsom
Ron Davis Jaime Ramirez
Jim Norris
Prepared by: Deborah Ross, WSEO
Washington State Energy Office
925 Plum Street SE
P.O. Box 43165
Olympia, WA 98504-3165
Printed on recycled paper
June 1994
WSEO #94-174 W590
This report can be made available in another format
for people with disabilities. Please call (206) 956-2068.
TDD users (206) 956-2218. moingon.7 & Ene/~J/0969
r
ACKNOWLEDGMENTS
The Puget Sound Fuel Blind Integrated Resource Planning Project was partially funded through a grant
from the Department of Energy, administered by Oak Ridge National Laboratories, which is managed by
Martin Marietta Energy Systems, Inc. The working group is grateful for the support of the Department.
In addition, Lotus Consulting Group of Los Altos, California and M.E. Gerber and Associates lent the
use of their software UPLAN-G and MIDAS Gold to the Washington State Energy Office in order to
perform cost/benefit analyses of the opportunities being examined by the group. The working group also
acknowledges the technical assistance and comments provided by the following individuals during the
course of the Project: Kim Acuff (WSEO), Gordon Bloomyuist (WSEO), Bob Carlson (Puget), Jim
Kerstetter (WSEO), Jason Keyes (Puget), Roger Kouchi (WUTC), Lynn Logen (Puget), Roland Martin
(WUTC), Gil McCoy (WSEO), and Chuck Murray (WSEO)
D-R8-O1 W6 ii
Contents
Executive Summary vii
List of Abbreviations and Acronyms ix
1 Description of Project, Working Group Members 1-1
Puget Sound Region Geographic Features, Demographics and
Economics 1-3
Description of Working Group Members 1-5
Puget Sound Power and Light Company 1-6
Seattle City Light 1-8
Washington Natural Gas Company 1-10
Washington State Energy Office 1-11
Washington Utilities and Transportation Commission 1-12
2 The Collaborative Process 2-1
Ground rules 2-1
Case Study 2-1
Limited Membership 2-1
Active Participation by All Members 2-2
Attempt at Consensus 2-2
Role of WSEO 2-2
Work Plan and Process 2-2
Inventory opportunities 2-4
Focus on a few opportunities 2-4
Issue papers 2-4
Cost/benefit analysis 2-4
Barriers analysis 2-4
Implementation plan 2-4
Additional Comments on Collaborative Process 2-5
3 Opportunities Considered 3-1
Main/Distribution Extension Policy 3-1
Statutory and Regulatory Context 3-2
Puget Power 3-2
Washington Natural Gas 3-3
Seattle City Light 3-4
Joint trenching 3-4
Fuel Choice/Fuel Substitution 3-5
Pipeline Capacity Sharing 3-7
Order 636 3-7
The Northwest Hydroelectric System 3-8
Coordinated Pipeline Capacity Contracts 3-9
Examples of Existing Joint Pipeline Capacity Sharing 3-10
D-R8-01 W6 iii
C
Siting Optimization 3-10
Siting priorities for gas-fired generation in the
Puget Sound Region 3-11
Factor 1: Proximity to Steam Host/Industrial Facility 3-11
Factor 2: Proximity to Local Distribution System 3-12
Factor 3: Proximity to Pipeline 3-12
Factor 4: Proximity to Electric Transmission 3-12
Factor 5: Proximity to Electric Load 3-13
Factor 6. Proximity to Oil Backup Supplies 3-13
Opportunities for Synergies in Siting Gas-Fired Generation 3-13
Fuel Cells 3-14
District Heating and Cooling 3-14
Working Group Conclusions 3-15
4 Cost/Benefit Methodology and Results 4-1
Methodology 4-1
Avoided Cost 4-1
Differential Revenue Requirements 4-1
Market 4-1
Case Studies 4-3
Fuel Choice/Fuel Substitution Cases 4-3
Pipeline Capacity Sharing 4-4
Joint Trenching 4-5
Analysis and Results 4-5
Fuel Choice and Substitution 4-5
Fuel Choice--Large Single Family Houses 4-5
Fuel Choice--Small Single Family Houses 4-7
Fuel Substitution--Small Old Houses 4-8
Fuel Substitution--Small Old Houses with Retrofits 4-9
Fuel Choice - Multifamily Housing 4-10
Sensitivity Analysis 4-11
Costs and Benefits of Extending Gas Main 4-12
Pipeline Capacity Sharing 4-13
Joint Trenching 4-14
Conclusions 4-15
5 Barriers 5-1
Choice of Fuels 5-1
Lack of availability of natural gas 5-3
Main extension policy 5-4
Internal revenue code 5-5
First cost considerations 5-5
Split incentives 5-5
Lack of access to information 5-6
Codes and standards for installation 5-6
Electric conservation programs 5-7
Pipeline sharing opportunities 5-7
Joint trenching 5-8
D-R8-O1 W6 iv
6 Implementation Plan 6-1
Recommended Strategies 6-1
Devleop educational programs so that customers,
developers, and the building trades would have
information available concerning fuel options. 6-1
Revise code and permitting provisions and improve
their implementation to minimise their impact on fuel
choice, unless justified by considerations of safety
and health. 6-2
Revise natural gas main extension tariffs. 6-3
Coordinate distribution and infrastructure planning
among utilities, municipalities, and counties. 6-4
Continue to monitor developments in electric energy
distributed generation technologies and cost/benefit
analysis methodologies, and coordinate distributed
generation planning with the gas utility. 6-6
Additional Strategies to be Considered for Future
Implementation 6-6
Consider other ways to reduce the first cost of main and
distribution extensions. 6-6
Be alert to conservation programs that have the
unintended effect of promoting one fuel source over
another, and design them to avoid adverse consequences
on fuel choice. 6-7
Consider promoting specific fuels in certain circumstances. 6-7
Consider regulatory changes to facilitate consideration
of inter-fuel synergies. 6-8
7 Next Steps 7-1
Implementation of Plan 7-1
Impact Analysis 7-2
References R-1
Appendix A Previous Publications Under Puget Sound
Fuel Blind Integrated Resource Planning Project A-1
Appendix B Opportunities for Cooperation Identified
by Working Group B-1
Appendix C Fuel Choice and Fuel Substitution Studies
and Analyses Collected in WSEO Project Library C-1
D-R8-01 W6 v
Executive Summary
For the last several years, regional energy stakeholders have discussed the desirability of establishing
better coordination among energy providers in order to provide benefits to the region's energy customers
and citizens. In Washington State, energy utilities have developed a number of individual cooperative
programs between electric and gas utilities. However, electric and gas utilities have not undertaken
coordinated planning in a systematic or comprehensive way.
In the Fall of 1992, the Puget Sound Fuel Blind Integrated Resource Planning Project (Project) was
launched, with the financial assistance of the Department of Energy under its Integrated Resource
Planning (IRP) program. The Project includes representatives from Puget Sound Power and Light
Company (Puget), Washington Natural Gas (WNG), Seattle City Light (SCL), the Washington State
Energy Office (WSEO), and the technical assistance of the Washington Utilities and Transportation
Commission (WUTC) staff. The three utilities are all located in the Puget Sound area, and are the largest
utilities of their kind in the state.
The group developed a set of ground rules for participation in the Project, designed to encourage open
discussion, to elicit and expect active participation by all members, and to achieve consensus where
possible.
The goal of the Project was to identify ways that utilities can work together to reduce costs, increase
efficiency, and enhance the environment. Over the course of a year and a half, the Project participants
developed a course of action that led to the identification of a number of opportunities for working
together. The group singled out seven of these opportunities for research, and ultimately selected four for
more comprehensive review. These four are examination of line extension policies, fuel choice and fuel
substitution, joint trenching, and natural gas pipeline capacity sharing.
The group developed a cost/benefit methodology, and, at the request of the group, WSEO developed and
analyzed the relative costs and benefits of pursuing the opportunities selected by the group. The
cost/benefit methodology allowed the group to conclude the following:
• First, it appears that under a range of situations in the working group's service territories, from a
societal perspective, natural gas is more cost-effective than electricity for single family residential
space and water heating. However, while these potential cost savings are significant, they may
represent a small fraction of overall societal energy costs.
• Second, there are probably some circumstances in these service territories where heating with
electricity is more cost-effective than with natural gas. These may include the multifamily residential
sector and, under certain assumptions, small single family homes. Relative cost-effectiveness may
vary with assumptions about distance from existing gas main, cost of gas, and other factors.
Therefore, consumer choices should not be unduly constrained or influenced in the direction of one
fuel over another.
D-R&01 % vii
• Third, there would be cost savings associated with increased joint trenching of electricity and natural
gas distribution services.
• Fourth, increased coordination of natural gas pipeline contracts between electric and gas utilities
present opportunities for cost savings.
The group identified a number of barriers that currently exist to implementing a number of apparently
cost-effective opportunities. The group then developed and recommends a five-part implementation plan
designed to address barriers and pursue the cost-effective opportunities identified in the Project. The
implementation plan focuses on three major goals:
• Enhance consumers' ability to choose among fuels.
• Improve education concerning energy resource costs, both at the customer and the builder level.
• Address and remove inefficiencies in energy delivery mechanisms.
The five strategies developed by the group are:
1. Develop educational programs so that customers, developers, and the building trades would have
access to information on fuel choice options.
2. Revise code and permitting provisions and improve their implementation to minimize their impact on
fuel choice.
3. Revise natural gas main extension tariffs.
4. Coordinate distribution and infrastructure planning among utilities, municipalities, and counties.
5. Continue to monitor developments in electric energy distributed generation technologies and
cost/benefit analysis methodologies, and coordinate distributed generation planning with the gas
utility.
Each of the five strategies contains a number of recommended action items. In addition, the group
suggests consideration of another four strategies that could be pursued at a later date or under special
circumstances.
The working group members currently meet regularly in a number of forums and will monitor the
progress of implementing each of the recommended strategies. The group will meet again in
approximately six months for a follow up session on the Project. At the request of the working group
members, WSEO may assist members in developing impact analyses designed to make reasonable
assessments of possible impacts of the various strategies on energy costs and savings.
t)-R8-O1 W6 viii
List of Abbreviations and Acronyms
AGA American Gas Association
aMW Average megawatt, a unit of energy consisting of 8,760 megawatt-hours
AFUE Annual fuel use efficiency
BPA Bonneville Power Administration
BTU British thermal unit, a measure of energy output
CIA Capital investment analysis
CT Combustion turbine
CCCT Combined cycle combustion turbine
DOE U.S. Department of Energy
DSM Demand side management
FERC Federal Energy Regulatory Commission
GMA Growth Management Act
IPP Independent power producer
IRP Integrated resource planning
kW kilowatt (1,000 watts, a unit of capacity)
kWh kilowatt-hour, a unit of energy
LDC Local (natural gas) distribution company
MMBtu million British thermal units
MW megawatt, 1000 kilowatts
NNG Northwest Natural Gas Company
NWPPC Northwest Power Planning Council
PGE Portland General Electric Company
Power Plan Northwest Conservation and Electric Power Plan
Project Puget Sound Fuel Blind Integrated Resource Planning Project
PSAERP Puget Sound Area Electric Reliability Plan
Puget Puget Sound Power and Light Company
PUHCA Public Utility Holding Company Act
PURPA Public Utilities Regulatory Policy Act of 1978
SCL Seattle City Light
SNOPUD Snohomish County Public Utility District
WNG Washington Natural Gas.
WSEO Washington State Energy Office
WUTC Washington Utilities and Transportation Commission
WWP Washington Water Power Company
D-R&O1 W6 ix
Chapter One
Description of Project, Working Group
Members
For the last several years, regional energy stakeholders have discussed'the desirability of establishing
better coordination among energy utilities, with the goals of improving efficiency of energy services,
reducing utility costs, and enhancing the environment. In Washington State, energy utilities have
developed a number of individual cooperative programs. However, electric and gas utilities have not
undertaken coordinated planning in a systematic or comprehensive way.
In the fall of 1991, Washington State's two largest investor-owned utilities, Puget Sound Power and Light
(Puget) and Washington Natural Gas Company (WNG), and the staff of the Washington Utilities and
Transportation Commission (WUTC) met with the Washington State Energy Office (WSEO). The
purpose of the meeting was to consider forming a group to identify opportunities for increased
cooperation between the two utilities, with the assistance and participation of WSEO and WUTC staff.
The two utilities were perhaps uniquely situated to benefit from such collaboration. They are both
growing fast, their service territories overlap in three counties, and they are nationally recognized as
leaders in integrated resource planning and implementation in their respective industries. The Puget
Sound Fuel Blind Integrated Resource Planning Project (Project) officially kicked off in the fall of 1992.
In early 1993, Seattle City Light (SCL) joined the Project as a fifth member. SCL is the largest publicly
owned (municipal) utility in the State of Washington, and its service territory is adjacent to Puget's and
overlaps with WNG's.
WSEO sought and obtained a grant from the Department of Energy (DOE), under DOE's Integrated
Resource Planning (IRP) program. The grant was administered by Oak Ridge National Laboratories and
provided partial funding for WSEO's participation in and facilitation of the project.
The participating utilities and agencies named individuals to serve as members of a working group to
carry out the goals of the Project. Over the course of a year and a half, the working group members met
regularly, reviewed and commented on a large amount of written material, and developed a collegial
relationship that is unusual for entities who historically viewed each other as competitors and
occasionally adversaries. At the end of the Project, the group developed a recommended implementation
plan. Table 1 shows a chronology of the group's meetings and other important events.
D-R8-O1 W6 1-1
Table 1
Chronology of Events
December 3, 1991 WSEO submits proposal to Martin Marietta.
August 17, 1992 Contract signed and project initiated.
September 30, 1992 First meeting of working group.
January 1993 Seattle City Light joins project.
February 1993 Individual meetings with working group participants.
March 23, 1993 Working group meeting. Topics: utility profiles, avoided cost methodology,
targeting opportunities.
April 16, 1993 Issue paper #1: Resource Cost Methodologies.
April 19, 1993 Issue paper #2: Line Extension Policies, Joint Trenching.
April 23, 1993 Report #l. published: Puget Sound Fuel Blind Integrated Resource Planning
Project: Description of Working Group Members, Identification of System
Interaction.
May 3, 1993 Working group meeting. Topics: process and collaborative rules; joint trenching,
line extension policy.
June 4, 1993 Issue paper #3: Fuel Substitution and Fuel Choice.
June 15, 1993 Working group meeting. Topics: cost/benefit methodology; fuel substitution and
fuel choice.
June 28, 1993 Issue paper #4: Pipeline Capacity Sharing and Fuel Cells.
Jul 16, 1993 -Working group meeting. Topics: development of cases for cost/benefit analysis.
August 6, 1993 Issue paper #5: Gas-Fired Generation Siting.
November 2, 1993 Working group meeting. Topics: continuation of cost/benefit analysis.
November 30, 1993 Working group meeting. Topic: continuation of cost/benefit analysis.
February 18, 1994 Working group meeting. Topics: preliminary results of cost/benefit analysis.
February 1994 Report #2 published: Puget Sound Power and Light's Periodic Rate Adjustment
Mechanism.: History and Selected Issues.
March 15, 1994 Working group meeting. Topics: cost/benefit updates; brainstorming on barriers.
March 30, 1994 Issue paper #6: Barriers.
April 12, 1994 Working group meeting. Topics: brainstorming on implementation strategies.
Aril 26, 1994 Issue paper #7: Implementation Strategies.
May 11, 1994 Working group meeting. Topics: narrowing and prioritizing implementation
strategies.
June 1, 1994 Report #3 published: Cost/Benefit Methodology and Results.
June 16, 1994 Final meeting of working group.
Jul 1994 Final report published.
While the end result of the Project is not a true "fuel blind integrated resource plan," since it does not
develop a comprehensive list of activities or an estimate of likely scope and cost of various strategies, the
Project did lay a framework for a number of future actions. This framework includes developing a large
number of possible opportunities for cooperation, a cost/benefit methodology, a description of current
barriers to increased cooperation, and a number of recommended and suggested implementation
strategies.
The Project was recognized by the Washington State Energy Strategy in 1993 as an important element of
the strategy (Washington Energy Strategy Committee 1993). Although the Project involves participation
by only the state's largest three electric and gas utilities, other utilities, regulators and stakeholders in the
state and the nation can use the methodologies and processes developed to initiate similar projects.
The following is a description of the Puget Sound region, and of each of the working group member
institutions.
D-R&01 % 1-2
Puget Sound Region Geographic Features,
Demographics and Economics
The service territories for the three utilities involved in the Project comprise the area of Washington State
surrounding Puget Sound (Figure 1). The three serve a substantial portion of the non transportation
energy needs of the Puget Sound region. Together, the three working group utilities represent about 29
percent of electric sales and about 35 percent of gas sales in Washington State (Ross and Byers 1993).
The geography of the Puget Sound area is unique. Framed by the Olympic Mountains on the West and
the Cascade Range on the east, the area is also virtually bisected by Puget Sound, a body of water
approximately 70 miles wide. It is also by far the most densely populated area of the state. These
geographic features present special difficulties in bringing to the area reliable energy services that are
dependent on centralized distribution. The Cascade Range divides abundant hydroelectric resources on
the east side from load on the west side: energy is transmitted over four major transmission lines that
cross the Cascade Range and are subject to storm and other weather-related outages. Service to the area
west of Puget Sound presents the challenge of crossing the Sound or taking a significant detour to the
south.
Puget Sound area energy demand has been growing faster than that of any metropolitan area in the
Northwest, in response to a healthy economy and a population growth rate that exceeds statewide and
national growth rates. Washington State, as a whole, entered into a recession in the early 90s, but Puget
Sound continues to grow economically, albeit at a slower pace than in recent years. According to a
recent report by Bonneville Power Administration (BPA), annual energy consumption in the area grew
by about 3 percent per year in the last seven years. Forecasts prepared by four electric utilities in the
region (Puget, SCL, Snohomish County Public Utilities District and Tacoma City Light) predict annual
peak growth of .6 percent, 3.9 percent, and 2.8 percent for the residential, commercial, and industrial
sectors, respectively, between 1990 and 2010 (Ross and Byers 1993).
Boeing Aircraft, which employs 87,000 workers; Microsoft and other high tech industries, which employ
about 85,000 workers; and the timber and government sectors, including military and state government,
largely drive the economy of the Puget Sound region. The region has historically been very sensitive to
the health of the aircraft industry. Recently, Boeing Aircraft has entered into a downturn, which has
resulted in layoffs of about twenty-five thousand workers. Diversification of the regional economy,
together with Boeing's policy of maintaining substantial backlogs of aircraft orders, has somewhat muted
the impact of this downturn.
The counties in the working group utilities' service territories must comply with Washington's Growth
Management Act (GMA). The GMA requires counties and municipalities to develop Comprehensive
Plans that outline land use, growth policies, capital spending, housing, and other plans to meet twenty
years of forecast growth. The GMA requires the Comprehensive Plans to include a utilities element that
describes how the county or municipality will accommodate need for utility services.
D-R8-O1 W6 1-3
~o• g tilffies
~of
Service rou
Onl }
Thurston Y
King, Pierce, and Countaes
King
XI1; j;.
L
Pierce
Thurston ht
Puget Sound Power big
~
Seattle City Light
lashington Natural Gas
f igur
Description of Working Group Members
Tables 2 through 5 summarize some of the characteristics of the three working group utilities.
Table 2
Customer Numbers
Puget 1993 WNG 1993 SCL 1990
Residential 709,123 396,549 289,888
Commercial 82,875 37,687 32,892
Industrial 3,715 2,957 306
Total 795,993 437,193 323,086
Table 3
Tail Block Rates
Puget (winter WNG (0/therm") SCL (winter
0/kWh)" O/kWh
Residential 6.7809 47.746 6.02
Commercial 6.1009 49.354 4.91
Industrial 4.1425 43.000 4.61
*Pugefs residential rate is before BPA's residential exchange credit (see footnote 1).
**one therm = approximately 29.3 kilowatt hours. (This figure does not reflect differences in end use
efficiencies between electric and gas appliances.)
Table 4
Annual Use Per Customer
Puget kWh WNG therms' SCL kWh
Residential 12,809 996 11,456
Commercial 74,930 7,473 100,018
Industrial 995,889 84,570 4,930,016
*one therm = approximately 29.3 kilowatt hours. (This figure does not reflect differences in end use
efficiencies between electric and gas appliances.)
Table 5
Average Annual Forecast Rate of Sales Growth 1990-2010
Without Programmatic Conservation
Puget WNG SCL
Residential - 1.2% 3.84% -0.13%
Commercial 3.3% 2.69% 2.12%
Industrial 2.8% 1.77% .042%
With Programmatic Conservation
Puget WNG SCL
Residential 0.8% 3.81% -0.23%
Commercial 3.0% 2.69% - 1.55%
Industrial 2.5% 1.77% -0.15%
D-R8-01 W6 1-5
Puget Sound Power and Light Company
Puget serves more than 1.7 million people--over 800,000 customers--within a 4,500 square mile area of
service. Puget serves nine counties in Washington State, three of which overlap WNG's territory (King,
Pierce, and Thurston).
Puget predicts that two major demographic trends will have the most significant impact on electricity
requirements: population growth in the region and aging of the population. Although forecasters expect
population growth to slow down from the 31 percent growth seen in the decade of the '80s, Puget
forecasts that its service territory will accommodate half of the population growth that will occur in the
state in-the next 20 years, with 90,000 new residential customers over the next five years alone. Aging of
the population is the result of the baby boom generation growing older, in-migration due to the relatively
strong regional economy, and an influx of retirees. The impact of this trend on energy will be increases
in the health services sector, shifts to multifamily housing, and decreases in the number of residents per
household.
Puget's residential rates are two-tiered inverted block rates, with a 10 percent seasonal differential (winter
being the more expensive season). The tail block rate approximates long term avoided cost, after BPA's
residential exchange credit is applied. Small commercial and all industrial rates are flat rates, with a
seasonal differential. Large commercial rates are declining block, with a seasonal differential.
Electric use per customer in the Northwest is higher than the rest of the country. The average Puget
residential customer uses about 13,000 kWh per year, compared with about 9,000 nationally (Ross and
Byers 1993). Saturation of electric heat is higher than the rest of country, which partly explains the
difference in energy usage. Puget is a winter peaking utility; that is, customers use more power in the
winter than in the summer. Again, this is partly due to the increased saturation of electric space heat, and
partly due to the moderate climate, which decreases the saturation of residential air conditioning.
Tables 6 through 8 show the average electric usage per Puget customer, and the percentage of Puget
customers in each class for each use (percentage of square feet, in the case of commercial customers), for
those end uses that could either be served by gas or electricity.
U-R&Ol W 6 1-6
Table 6
Selected Usage Characteristics of Puget Power Residential Customers
End Use Annual kWh per Cust. Percentage of Customers
Space Heat 9-10,000 40
Water Heat 4,700 70
Cooking 550 95
Clothes Drying 1,000 88
Table 7
Selected Usage Characteristics of Puget Power Commercial Customers
End Use Annual GWh per End Use Percentage of Sales
Space Heat 1,329 24
Water Heat 239 4
Cooking 38 1
Cooling 221 4
Table 8
Selected Usage Characteristics of Puget Power Industrial Customers
SIC Code Annual GWh per SIC Percentage of Sales
Transportation 789 22
Lumber and Paper 576 16
Petroleum 973 27
Residential sales represent 48 percent of Puget's total sales, commercial 32 percent, and industrial 20
percent.
Puget relies on a variety of resources to meet its needs. On the demand side, Puget has acquired about
140 average megawatts (aMW)1 of demand-side resources (DSM) between 1978 and the end of 1992.
Puget has been a leader in regional conservation activities, and significantly increased its conservation
efforts in 1991. Conservation continues to be an important resource in the company's resource planning
process.
On the supply side, Puget relies heavily on purchased power (with long term contracts), both from other
utilities and the BPA, and, more recently, from independent power producers. Puget also owns a number
of hydroelectric facilities and simple cycle combustion turbines that it uses to back up its hydroelectric
resources in drought years, and has joint ownership in coal-fired power plants.
1 An average megawatt is a unit of energy representing 8,760 megawatt hours.. The Northwest has not
been historically capacity constrained. This is because water is the limiting factor for the Northwest's
large hydroelectric generation capability, rather than generation capability (see chapter three). Therefore,
energy, and not capacity, is the focus of most current regional resource planning and acquisition
decisions.
D-R8-01 W6 1-7
Puget's integrated resource plan (Puget Sound Power and Light Company 1992) calls for acquisition of
significant amounts of "high efficiency cogeneration" and additional combustion turbines. (High
efficiency cogeneration is a term defined by a policy collaborative group consisting of regional energy
policy makers who have assisted Puget in developing its resource acquisition strategy. As defined by the
group, it means cogeneration requiring high efficiency turbines and boilers, with a minimum of 20
percent of total energy output being thermal.) Both of these types of resources are likely to be gas-fired.
Washington State has not yet adopted a statutory or regulatory methodology for treatment of
environmental externalities associated with energy resources, although WUTC regulations require electric
utilities to consider the environmental impacts of new competitively bid resources. In its 1992 least cost
plan, Puget indicated its commitment to "pursuing resources with low environmental effects." Puget
gives a 10 percent price credit in the evaluation process for its resource planning and all-resource bidding
process to conservation and renewable resources. Puget gives preference to high efficiency cogeneration
over other thermal processes.
In 1991, Puget entered into a new regulatory structure, called the Periodic Rate Adjustment Mechanism,
or PRAM, on a three-year experimental basis. Under the PRAM, among other provisions, Puget's
earnings are dependent on the relationship between its costs and the number of customers, rather than the
relationship between costs and the level of sales, as is the case with most regulatory systems in the
United States. The PRAM was continued for another three year period in a recent rate decision by the
WUTC2.
Seattle City Light
SCL is a division of the City of Seattle government. Its service territory generally covers the city,
located in King County, Washington, with 292,080 residential, 35,292 commercial, and 307 industrial
customers in 1990.
SCL's economic forecast is not quite so robust as Puget's or WNG's, but does predict growth throughout
the forecast period. SCL's service territory is largely developed, with very little single family residential
construction occurring. As with Puget, a significant economic driver for SCL's sales forecast is Boeing,
who SCL predicts will continue to grow at a moderate rate over the course of the next 20 years. SCL
expects commercial growth to grow at a moderate rate, fueled by non-manufacturing employment
growth. SCL also expects industrial employment and output to grow moderately, at about .4 percent per
year. However, SCL forecasters expect residential demands to drop--even without considering
programmatic conservation--due to stabilization of the population, increasing shares of multifamily
housing, and market driven fuel switching.
SCL has inverted block rates for its residential customers, with a seasonal differential. It has flat rates for
its commercial customers, also with a seasonal differential. Industrial customers have time-differentiated
peak and off-peak rates, with a seasonal differential.
As is the case with Puget Power, SCL's customers use more electricity on average than the nation, with
11,456 kWh per customer consumed in 1990-1991 (Ross and Byers 1993). Tables 9 through 11 show
additional information for SCL consumption.
2 The impact of this mechanism on this Project is discussed in Ross and Byers 1994. In brief,
however, the significance of the.mechanism for this Project is that it should make Puget (at least in the
short term) less financially sensitive to the impact of customers choosing alternative fuels, such as gas,
for certain end uses. As will be discussed in chapter six below, steps to increase customer choice are key
elements of the Project's implementation plan.
U-R8-01 W6 I-8
Table 9
Selected Usage Characteristics of SCL Residential Customers
End Use Annual kWh/Cust. Percentage of Customers
Single Family
Electric Resist. Space 10,735 22.7
Heat Pump 5,378 1.7
Water Heat 4,839 78.8
Multifamiliy
Electric Resist. Space 4,765 83.2
Water Heat 2,057 78.9
Table 10
Selected Usage Characteristics of SCL Commercial Customers
End Use kWh/Sq. Ft. Percentage of Sales
HVAC 5,098 29.8
Lights 7,254 42.4
Other 4,735 27.7
Table 11
Selected Usage Characteristics of SCL Industrial Customers
Process Total GWh Percentage of Sales
Food 141,282 9.3
Metals 350.803 23.2
Aerospace 431,747 28.6
Stone, Glass 290,725 19.3
Other 294,027 19.5
SCL has significant utility-owned hydroelectric resources that are used to meet over half of its current
load. SCL is also a so-called "preference" customer of BPA. Under a number of federal acts relating to
BPA and its rates, publicly owned utilities, as well as certain customers of privately owned utilities, are
entitled to rates that reflect the cost of power from low cost hydroelectric facilities located in the
Northwest and marketed by BPA. SCL's power costs are somewhat lower than the average cost to an
investor-owned utility in the Northwest. In 1983, the City of Seattle decided not to participate in the
nuclear facilities being built by the Washington Public Power Supply System on behalf of several
publicly owned electric utilities. Hence, SCL has not been saddled with the financial problems
associated with the failure of several of these plants to be completed. SCL has relied significantly on
DSM and on BPA purchases. In its current least cost plan, SCL plans to reduce its reliance on BPA, to
increase its DSM program, to upgrade hydroelectric facilities, to develop simple cycle turbines as part of
a hydrofirming strategy3, and to examine high-efficiency cogeneration opportunities.
3 See chapter three for a description of hydrofirming.
D-R8-01 W6 1-9
SCL has not undertaken to recommend a specific quantification of environmental impacts associated with
its recommended resources. The utility's Resource Plan (Seattle City Light 1992) notes, however, that
SCL's choice of new resources is sensitive to assumptions about the appropriate "adder," if any, for
environmental impacts. Hence, the Resource Plan recommends that further work be done on quantifying
or otherwise explicitly valuing environmental impacts of new resource decisions. The Resource Plan has
provided subjective environmental ranking of the resources considered for inclusion in the plan.
SCL, as a publicly owned utility, does not have investors who expect to earn a return on their investment.
Furthermore, SCL is not subject to regulation by the WUTC and has flexibility to adopt policies designed
to achieve a number of goals other than a fair return to investors. For example, SCL has a special
residential rate for low income elderly and handicapped customers. SCL subscribes to the concept of
"most value" planning, i.e., maximizing social welfare, rather than "least cost" planning.
It has occasionally been asserted that a publicly owned utility need not worry about "lost revenue"
associated with conservation or fuel choice programs. However, fixed costs must be recovered from
utility customers whether or not the utility is privately owned. Therefore, reduction in sales resulting
from DSM or fuel switching may lead to under-recovery of these costs, and upward pressure on rates.
Rate impacts are a concern of both publicly and privately owned utilities.
Washington Natural Gas Company
WNG serves five counties in the state, all in the Puget Sound area4. The counties served by WNG have a
total estimated population of 2.8 million, which represents 57 percent of the state's population. Three of
these counties (King, Pierce, and Thurston) overlap the service territories of Puget and SCL. WNG has
about 437,000 customers. Ninety percent of WNG's customers are residential, and these customers
consume about 40 percent of WNG's annual gas throughput. About 30 percent of WNG's throughput
represents interruptible industrial customers who are either sales customers (i.e., they take both
commodity and distribution services from the company) or transportation customers (i.e., they make their
own arrangements for commodity, using the company's distribution system to transport it). Firm
industrial and commercial customers consume the remaining thirty percent of the throughput.
WNG is currently experiencing extremely robust growth, due primarily to the growing economy in Puget
Sound, the demand for natural gas in new residential construction, and conversions from other fuels.
Fifty-six percent of the new residential customers added to WNG's system in 1990 and 1991 were those
converting from other fuels, primarily electricity. Ninety-nine percent of new single family residences
choose natural gas when it is available.
As with Puget, WNG's economic forecast calls for moderate economic growth, with slightly slower
growth occurring over the second ten years of the 20 year forecast. WNG predicts gas will retain its price
advantage over electricity. It expects residential use per customer will increase somewhat in the near
term, largely due to increased saturation of gas water heat, before declining due to code and efficiency
improvements.
WNG currently has flat rates for the residential, commercial, and small industrial sectors and declining
block rates for large industrial customers. Like many other local distribution companies (LDCs), WNG
also has transportation tariffs available for large industrial customers who wish to avail themselves only
of WNG's distribution facilities and purchase their commodity independently. Table 12 shows results of
WNG's recently completed residential survey.
4 However, gas is not available throughout the entire area. -
D-R8-O1 W6 1-10
Table 12
Selected Usage Characteristics of WNG Residential Customers
End Use Annual therms/Cust. Percentage of Customers
Space heating 779 97
Water heating 290 77
Cooking 27 18
Fireplace 103 13
Drying 50 10
Hot tub 238 3
WNG is currently conducting a commercial end-use study and plans to complete an industrial end use
study in the next two years.
As is the case with all LDCs in Washington State, two interstate pipelines currently serve WNG,
Northwest Pipeline and Pacific Gas Transmission. WNG's pipeline transportation costs are subject to
these pipelines' tariff structures, which are set by the Federal Energy Regulatory Commission (FERC).
In recent years, WNG has been able to rely on increasingly diverse sources of commodity contracts and
gas storage capacity. In addition, WNG's least cost plan calls for development and implementation of a
limited number of DSM programs in the next two years. These developments give WNG somewhat
more control over resource costs than in the past.
FERC Order 636, issued in 1992, dramatically changed the relationship between WNG and Northwest
Pipeline. Northwest Pipeline will no longer provide commodity services to WNG; furthermore,
Northwest Pipeline will make firm transportation services available to all potential customers. However,
subscribers to the pipeline will be able to sell off their excess capacity on a competitively bid basis. The
existence of amarket for firm pipeline capacity provides some additional flexibility to WNG in making
its capacity decisions.
Washington State Energy Office
The Washington State Energy Office is an executive office in Washington State government. WSEO's
director serves in the governor's cabinet. Some of WSEO's funding comes from the state treasury, but the
majority of funds comes from other sources such as other states, BPA, the Department of Energy, the
Northwest Power Planning Council, and private foundations.
WSEO was given primary responsibility to implement the state energy strategy, which was published in
1993. The strategy specifically refers to this Project as an example of the "creative and entrepreneurial"
qualities that WSEO is expected to bring to bear in implementing the strategy. (Washington Energy
Strategy Committee 1993.)
D-R8-O 1 W6 1-11
Washington Utilities and Transportation Commission
The WUTC regulates investor-owned utilities in the State of Washington, including electric, natural gas,
telecommunications, water, solid waste, and transportation. Investor-owned utilities account for about
half of the retail sales of electricity in the state, and virtually all of the natural gas sales.
The WUTC consists of three appointed commissioners, plus a staff of over 200 employees. Advocacy
staff of the WUTC participate as full parties to contested proceedings, as well as offering policy advice
and technical support for uncontested proceedings. The advocacy staff of the WUTC therefore often
represent independent views and do not necessarily speak for the WUTC itself. In addition, Commission
orders restrict the ability of WUTC staff to formally represent staff positions in collaborative utility-
agency groups such as the Project. Therefore, the participation and comments of WUTC staff in the
working group was advisory in nature and did not commit either WUTC staff or the WUTC to a
particular course of action or position.
D-R8-01 W6 1-12
Chapter Two
The Collaborative Process
This chapter describes the ground rules and work plan that the working group.developed during the
course of the Project. The working group found it helpful to establish rules for participation and to
develop a work plan early on in the Project. Having ground rules enabled the participants to understand
what was expected of them and other participants, and were designed to ensure that no single member
would dominate the process. Members also felt free to discuss the ground rules and work plan
periodically to ensure that they were comfortable with the level of participation expected of them and
others.
Ground rules
Case Study
The group agreed at the outset that the Project would be a case study. This meant that the focus of the
Project would be on specific opportunities for cooperation among the three working group utilities and
the two agencies. It also meant that the results of the analysis would be specifically applicable only to
? the working group participating institutions.
However, the group also was conscious that this Project could be used by others as an example for
similar projects around the state and nation. The processes for communication and participation, the
cost/benefit methodology, and some of the implementation strategies developed can be a model for
others.
Limited Membership
The group agreed that participation in the Project would be limited to working group members only.
There are tradeoffs between the need to ensure that the views of all stakeholders are heard, and the need
to have a manageable number of participants. Both the utility participants and the agency participants
felt it was very important that they be free to express and explore ideas and views in a setting that was
free of ideological and other struggles. The group therefore agreed to limit participation to only the
working group members during the course of the Project, but to give all stakeholders an opportunity to
examine the group's conclusions and the implementation plan in appropriate forums once the Project was
complete. Funding for the Project included sufficient funds to enable widespread publication of Project
reports, and presentations of the process and the conclusions in public forums.
,
D-R8-01 W6 2-1
Active Participation by All Members
The group also established a ground rule that all working group members would be expected to
participate actively. This included at a minimum attending all meetings of the group, commenting on
reports and issue papers, and attempting to reach consensus on the implementation plan. The group
expected that no member would feel free to "sit out" the project and remain silent should objectionable
decisions be made.
At the same time, the working group members actively encouraged participants to express their own
views without fearing that their comments would later be held against them or the institution they work
for. Issue papers and comments on them were developed for the sole use of working group members and
did not represent the official position of working group institutional members.
Attempt at Consensus
During the course of the Project, there were disagreements among working group members about a wide
variety of issues. However, the group decided to try to reach consensus on at least two elements of the
Project: the content of the published reports5, and the implementation plan. The group recognized that
WSEO took ultimate responsibility for the content of all published reports. Similarly, the
implementation plan described in chapter six of this report is the result of a consensus-building process
that took several months to develop.
Role of WSEO
The group agreed that WSEO would serve a triple role. First, WSEO was an active participant in the
decision making process with a responsibility for substantive comment. Second, WSEO organized,
funded, and facilitated all meetings of the group. Third, WSEO provided both analytical support and was
the primary author of the issue papers and published reports. These multiple roles could have established
WSEO as the most influential or controlling player in the group, potentially disrupting the balance that
the group hoped to achieve. This potential problem was partly solved by having more than one WSEO
staff person present at most of the meetings, so that one person could act primarily as scribe while
another participated more actively in the discussions. This proved to work well. However, other groups
that are considering a similar project may want to consider whether an independent facilitator would
work better in their particular situation.
Work Plan and Process
The work plan developed by the working group was initially driven by the tasks set forth in WSEO's
contract with Oak Ridge National Laboratories. However, as the Project progressed, the group revised
the work plan several times to reflect the group's priorities and needs. In early 1993, the group developed
a plan that is schematically portrayed in Figure 2. Major elements of the plan are as follows:
5 See Appendix A.
D-R8-01 W6 2-2
_--~f - F~gU~e 2 u
o ~
Q, cu
G ~ v
m O
cn O C.- O
U') 'f~ y tt5
p .G[ az C!)
~ O
a.,
w CD
(n O
N°~ o
ca n
cts
C) (n
I- ch x=
o. n
4v
63
. T
CO ca
i.• ca cis
t3~
C ~ to
o
cc$
0 4
Iwo
N
C13
i
a~
G v
a~ o
.4 0 zr °'o
o cc app p c o
~ cn s d T o f
o a
n a' C3 c3-
n
a
¢0
N to Cl*
U n
" O
i v
a-
Inventory opportunities
The first substantive step in the Project was to identify possible opportunities for cooperation that the
group members wanted to consider pursuing. This was essentially a brainstorming exercise, and was
done at meetings between WSEO and individual working group members. WSEO then produced a list of
all of these potential opportunities for the group to consider. A complete list of all the opportunities that
were identified by working group members is found in Ross and Byers 1993 and in Appendix B.
Focus on a few opportunities
The group then met in early 1993 to narrow the focus to a smaller number of opportunities. The group
decided to focus on six opportunities, which it later expanded to seven. Chapter three describes these
opportunities.
Issue papers
The group asked WSEO to write issue papers that would research and provide background for each of the
seven opportunities. At several subsequent meetings the group discussed each opportunity and made a
decision whether and how to proceed any .further. The result of this process was to further narrow the
detailed review to four major opportunities, and to consider the remaining three more subjectively.
Cost/benefit analysis
The group developed a methodology for assessing possible costs and benefits of various opportunities
being examined. Chapter four describes this methodology and results. On the.basis of this analysis, the
group made a decision to proceed with examining all four of the major opportunities.
Barriers analysis
Following the cost/benefit analysis, the group met to identify possible barriers to implementing these
opportunities. The group identified a number of barriers. Chapter five describes these. The group also
agreed that for some cost effective opportunities there appear to be no major barriers. In these cases, the
group noted that the opportunities appeared cost effective but that the working group did not need to take
additional action.
Implementation plan
The final step in the Project was the development of an implementation plan. The group met several
times to brainstorm on possible strategies, and ultimately developed the implementation plan described in
chapter six.
D-R8-01 W6 2-4
Additional Comments on Collaborative Process
Before leaving this chapter, some additional comments on the process developed for this Project are in
order.
Regardless whether the implementation plan is carried out, or its results are successful, the working
group members believe that the simple act of bringing these utilities and agencies together was a valuable
process. Electric utilities and natural gas utilities are traditional competitors. Radio advertisements and
other actions are often focused on drawing market share away from the other utility. To a certain extent,
competition also exists between privately owned and publicly owned utilities in Washington State. This
is partly over market share, and partly over cost allocation of energy resources marketed by BPA.
Furthermore, the WUTC staff is a traditional legal adversary of the investor owned utilities. The staffs
role is to provide a balanced assessment of utilities' filings and make recommendations concerning a fair
return to shareholders and provide customers with reliable service at the lowest possible cost.
Traditionally, this has taken place in adversarial (i.e., contested) proceedings. Therefore relationships
between WUTC staff and utilities are not always free of strain.
Having representatives from these three utilities and WUTC staff in the same room discussing major
policy and planning issues was therefore a unique and valuable experience. Perhaps because of the
personalities involved, and perhaps because of the ground rules established, discussions took place at an
unusually high plane, free for the most part from the acrimony and competitiveness that sometimes has
characterized interutility and utility-WUTC relationships. This is especially noteworthy since, during the
course of the Project, both WNG and Puget had major litigated rate cases pending before the WUTC.
Working group members have pursued the relationships formed during the course of the Project outside
the Project as well. Working group members have contacted each other about new ideas and new ways
to cooperate in arenas other than those defined by the Project. They have developed new ways of sharing
data and information and have defined cooperative projects. These include office sharing, joint meter
reading, joint delivery of conservation programs, and a cooperative fuel substitution program. The open
channels of communication fostered by the project led, at least in part, to these opportunities being
identified and pursued.
The working group members recommend cooperative efforts among electric and gas utilities elsewhere in
the region and country to explore opportunities for synergy and cooperation.
D-R8-O1 W6 2-5
Chapter Three
Opportunities Considered
This chapter describes the seven opportunities that the group decided to focus on during the course of the
Project. As noted above, the working group selected these seven out of a much larger group of
opportunities that the group members identified initially. There were several reasons for selecting this
group. These included: 1) perceived cost effectiveness; 2) ability of opportunity to reveal information
about other opportunities; 3) acceptability to utility or agency management; 4) interest on the part of a
working group member.
There was no attempt to develop a rigorous screening methodology or a comprehensive review of all
possible opportunities. In this sense, the work of the group differs from the approach taken in utility
integrated resource planning (W). IRP usually requires demonstration that the utility has considered
and reviewed all reasonable resource opportunities and can document the reasons for accepting or
rejecting a resource.
The rest of this chapter describes the results of the group's research and conclusions regarding the
possible scope of each opportunity for the working group members.
Main/Distribution Extension Policy
Main extension policy refers to the cost allocation and accounting criteria used by utilities to collect and
account for the cost of extending service to a new customer. The criteria establish the amount of
investment that the utility is willing to make and the amount that the new customer would have to
contribute in order to secure service. The group decided to examine main extension policy because it
seemed possible that the way utilities allocate and account for costs might influence customers' choice of
fuels. This is for two reasons: first, since fuel choice decisions are generally made up front in the form
of investments in service and equipment, the first cost of getting service may influence fuel choice.
Second, there was evidence that some of the current main extension policies and practices in place led to
inefficiencies, as discussed further below.
The group's research revealed the following:
G-R8-01 Wb 3-1
Statutory and Regulatory Context
The Revised Code of Washington (R.C.W.) 80.28.110 sets forth the obligation of gas and electric
companies to serve customers. This obligation apparently extends to both investor-owned and publicly
owned utilities:
Every gas company, electrical company or water company, engaged in the sale and distribution
of gas, electricity or water, shall, upon reasonable notice, furnish to all persons and corporations
who may apply therefor and be reasonably entitled thereto, suitable facilities for famishing and
furnish all available gas, electricity and water as demanded
The Revised Code does not, however, say anything about how to allocate the costs of extending service
to customers. The WUTC's regulations are also silent with respect to cost allocation for regulated
utilities. Regulations for both electric and gas utilities specify that utilities can refuse to extend service if
the extension would be "economically unfeasible," and both industries must file tariffs covering main or
distribution extension cost allocations.
There are no WUTC orders that comprehensively discuss appropriate main extension investment policies.
As we will note below, the main extension policies differ between Puget and WNG; they also differ
among and between other electric and gas utilities in the state. There is one WUTC case that could
support a differential treatment among utilities based on expectation of a return on the investment,
although it is not directly on point. In Mendonza v. Telephone Utilities of Washington, Cause No. U-8 I-
49 (December 16, 1981), the Commission found that it was reasonable for a telephone utility to require a
deposit from a developer or new customers to support the cost of wiring a new neighborhood. The
Commission found that where there is a "speculative return on investment," it is not reasonable for the
body of ratepayers as a whole to bear the cost of the new development. This case could lend support to
the widespread view that, where utility service is "discretionary," and hence recovery of costs is not
guaranteed, the new customers alone should bear the cost of new extensions.
One federal statute influences main policies in that it affects the cost of mains to customers. In 1986,
Congress amended the Internal Revenue Code to specify that where a customer or potential customer
contributes to the capital of a utility, that contribution is taxable as gross income of the utility (26 U.S.C.
§ I I8(b)). Formerly, the I.R.S. did not tax these contributions. The inclusion of such contributions as
gross income means that the utility must collect not only the direct cost of the extension, but the taxes it
will have to pay on those costs. Both Puget and WNG include the taxes in calculating the cost of a line
or main extension to a customer. WNG collects them up front; Puget collects the present value of the
return on the unamortized balance of the taxes, which are deferred and normalized.
Puget Power
Puget's line extension tariff, schedule 85, provides that, "[f]or each residence initially to be served [by
single phase distribution facilities], the Company will provide an allowance of $1,478.00 toward the cost
of construction of facilities." Review of supporting documentation and staff analyses reveals that this
amount corresponds roughly to two years of revenue from each customer, based on average usage. For
customers requiring three phase distribution facilities, the amount is $3,898, which also corresponds to
about two years of revenue from these customers. For nonresidential and recreational facilities, Puget
will invest an amount up to two times the estimated annual new revenue from the customers initially to
be served.
D-R8-01 W6 3-2
If new customers on the line hook up within five years of the initial date of energization, Puget credits
the line with the appropriate credit, and the original customer gets a refund of the new credit amount.
The rule is slightly different for developments. Here, Puget charges a set amount per linear foot to
developers. As houses are energized in the development, Puget will refund the allowance to the
developer.
Puget's main extension rules apply only to lines that are dedicated to the particular customer or
development. "Feeders," or distribution lines that extend from the substation to serve an entire
neighborhood, are paid for by all ratepayers.
Washington Natural Gas
WNG's tariffs and extension policy are somewhat more complex. They are found in one "schedule" and
two "rules." Schedule 7 and Rule 6 apply to charges for gas service where gas main is already located or
approved. For these locations, the company will extend service from the street to the building either for
free, or for a charge, depending on 1) the anticipated usage and 2) the length of the extension.
Rule 7 (as opposed to Schedule 7) applies to service where there is no main already located. In this case
the company and new customer have two options. Under the first option, the company must extend main
and service lines to the customer if the total cost doesn't exceed five times the anticipated annual margin6
from each "bona fide applicant for such service." If the cost of the main and service line does exceed that
amount, the customer must pay the difference. Then, if new customers hook up within five years, WNG
refunds the original customer half of the revenues collected from those new customers for the remainder
of that five year period7. This only applies to customers that are located along the length of main that
was constructed to serve the original customer. If a new customer hooks up one house beyond the
original customer's location, there is no refund, even though the new customer is making use of the main
that the original customer financed.
Under the second option, the company may invest an amount that is greater than the minimum when "in
its opinion, prospective business warrants the investment." In these cases, the company makes an
estimate of the expected revenue from the line and takes the risk that the revenues will materialize.
Under these circumstances, the original customer may not have to pay as much for the main extension,
but does not get the benefit of the refunds that could materialize as new customers hook up. A bone fide
applicant is still required under the second option. The company's analysis to determine when business
warrants the investment is termed a capital investment analysis, or CIA.
The company's CIA policies have changed over the years and have been the subject of scrutiny in rate
proceedings in recent years. Currently WNG's CIA policy is as follows: when an applicant applies for
service and cannot justify the investment based on the five times margin test, the company estimates the
likely revenues that potential future customers on the main will produce. The "futures" assessment only
looks at homes or buildings that are currently located along the proposed main, and assesses the
likelihood that these homes will connect within three to five years. The company then estimates what
twenty years of revenues from these "futures" will produce and compares it with the cost of the project.
6 "Margin" in this context means the difference between revenue and the cost of purchased gas.
7 Compare this with Puget's policy, which grants a refund in the entire amount of the allowance
whenever the new customers hook up in the subsequent five year period. Under WNG's policy, if a new
customer hooks up in year 4.5, the original customer only receives the benefit of half of the revenues
from the remaining half year.
D-R8-O1 W6 3-3
If the anticipated revenues from these futures will pay for the cost within twenty years, the company will
finance the project.
WNG has agreed, as part of a recent rate case settlement, to file new main extension tariffs and rules by
September 24, 1994.
Seattle City Light
SCL's tariff, found in Seattle Ordinance 21.49.110(R) provides that all new customers, or customers
wanting to change from overhead to underground lines, have to pay the entire cost of the line, except for
transformers.
Joint trenching
The cost of digging up streets to install utility services can be a substantial portion of main or distribution
cost extensions. WNG estimates that about 40 percent of the cost of a new gas distribution line relates to
pipe costs; the remaining 60 percent relates to trenching and labor. Also, virtually 100 percent of the cost
of maintenance relates to trenching costs. Where a utility installs service in an existing neighborhood,
there are additional direct and aesthetic costs of replacing pavement.
Installing underground electric or telephone services has positive aesthetic impacts and may reduce the
number of storm-related outages. Joint trenching, by minimizing the first cost of undergrounding electric
and telephone services, would help to encourage more undergrounding. In general, therefore, if utilities
can coordinate trenching opportunities, there would be significant overall quantifiable and non
quantifiable savings.
Working group members note that joint trenching currently takes place among the three utility members
to some extent. Largely, it takes place when a new development or large commercial or industrial
structure is being built. In that situation, the developer or builder will arrange to have all utilities be
present at the time new streets are developed and utility services are being extended in order to minimize
cost and aesthetic impacts (utilities can ask developers to pay substantial deposits toward the cost of new
underground electric, telephone and gas utility service).
Furthermore, utilities coordinate short-term trenching plans with each other. Representatives of the area's
electric, telecommunications, and cable utilities meet monthly for a Joint Utility Coordinating
Conference. The conference exists to coordinate trenching activity that one of the participating utilities
has already scheduled. At that time, other utilities have the opportunity to extend or upgrade service.
However, there historically has been little or no coordination of long term trenching plans. Therefore,
utilities have not been able to adjust their capital expenditure programs in order to maximize the
opportunity to lay new service or upgrade old service when another utility has to dig or open trenches.
(The requirement that WNG have a "bona fide applicant" in order to extend pipe also limits its ability to
take advantage of open trenches to lay new main.) Coordination of long term plans is increasing among
utilities; however, it is far from comprehensive.
Furthermore, there is little coordination between utility and municipal or county infrastructure
improvement schedules. This means that a utility may not be able to take optimal advantage of a road
improvement project to schedule an upgrade or extension of utility service. It also may mean that cities
and counties experience unnecessary disruptions when a utility has to come in for a service upgrade after
a road has already been paved. -
D-R8-01 W6 3-4
Fuel Choice/Fuel Substitution
"Fuel substitution" and "fuel choice" both refer to programs initiated by utilities or others to influence
directly the choice of fuels made by gas or electric customers. These programs are in addition to indirect
ways to influence fuel choices, such as pricing. In this report, the term "fuel substitution" refers to
program to get a customer to change from one existing fuel use to another (this is also known as fuel
switching or fuel conversion). "Fuel choice" refers to programs to influence a new customer (or an
existing customer with a new end use) to choose one fuel over another.
Currently, utilities are operating two fuel choice/fuel substitution programs in Washington State. The
first involves Washington Water Power (WWP), a combination electric and gas utility. WWP's program
involves mailing an offer to potential residential fuel switching customers and offering an incentive to get
them to switch to gas water or space heat, in the form of contributing towards the cost of appliances. The
program has been very successful in increasing the penetration of gas water and space heat in WWP's
service territory; it is one of the major resources in WWP's near-term electric integrated resource plan.
Recently, WWP scaled back the program, partly due to its success and partly due to a revision in WWP's
forecast of resource needs.
The second fuel substitution program is a joint project of WNG and SCL, funded by BPA. This is a pilot
program, where the two utilities are testing the market for fuel substitution by making incentive offers to
residential customers in a Seattle neighborhood to install natural gas equipment. The utilities will collect
data on the program and on its potential impact on energy consumption.
Snohomish Public Utilities District (SNOPUD) and WNG also recently completed a pilot program where
SNOPUD mailed flyers to customers to encourage them to switch to natural gas water heat. WNG then
provided a subsidy for those customers to come on to the system and also agreed only to install the most
cost effective water heaters for those customers taking part in the program. Although the utilities termed
this program a success, they did not continue it as a full-scale project (Snohomish County Public Utilities
District 1991).
Elsewhere in the region, the Oregon Public Utilities Commission (OPUC) ordered Oregon's gas and
electric utilities to work with OPUC staff and Oregon Department of Energy (ODOE) staff to evaluate
the potential and cost effectiveness of fuel substitution as an electric DSM option. OPUC and ODOE
staff submitted a study to OPUC concluding that some fuel substitution probably was cost effective, but
recommending against mandating it at this time (Oregon Department of Energy/Oregon Public Utilities
Commission Staff 1991).
BPA has offered up to $2 million to its customer electric utilities who come up with proposals for pilot
or small scale fuel switching programs designed to reveal information about the cost, potential, and other
factors relating to fuel switching (Meyer 1992). The WNG/SCL project described above is funded under
this offer.
The Northwest Power Planning Council (NWPPC) has decided as a policy matter that direct use of
natural gas for water and space heat should be considered as a resource alternative to generating
electricity with natural gas for the same end uses. The impact of this decision will be examined as part
of the NWPPC's next Conservation and Electric Power Plan (Power Plan). (Northwest Power Planning
Council 1994.)
D-R8-01 W6 3-5
Nationwide, electric utilities generally resist the idea of requiring an electric utility to implement
programs to encourage fuel substitution or fuel choice involving natural gas. Unlike Puget, most electric
utilities experience earnings erosion when it loses sales to natural gas utilities.8 At the same time, gas
utilities have frequently intervened in proceedings where electric utilities subsidize heat pumps or other
activities that the gas utilities view as promotional. A few states have mandated fuel choice or
substitution (California, Vermont, and Wisconsin) (Lawrence Berkeley Laboratories 1991).
Analyzing the cost effectiveness of a fuel choice or fuel substitution program is a challenging task,
because one has to look at the impacts on a large number of players--gas utility shareholders, electric
utility shareholders, and their customers, at the least. A fuel choice or substitution program that reduced
the electric utility's long term revenue requirements would almost certainly increase gas utilities' revenue
requirements. Therefore, analysts must use the total resource cost or societal perspective to determine
whether it is worth trying to influence fuel choice from a societal point of view. If analysts find it
socially cost effective to influence fuel choice, they then can design programs to allocate their cost
equitably.
The analyst must also determine the extent to which the customers would have made the right fuel choice
on their own. In some cases, direct intervention is not worthwhile because the marketplace is already
capturing most cost effective opportunities. Finally, the analyst should determine whether other indirect
influences such as pricing or increased access to competing fuels would be a more cost effective way to
get customers to choose the less expensive fuel source.
To take a concrete example, WWP's cost effectiveness analysis on the pilot fuel switching program it
undertook in Idaho showed that under the utility test for DSM cost effectiveness, the program is a cost
effective electric DSM option both for customers who currently have gas space heat and electric water
heat, and for potential gas customers who currently have electric space and water heat. However, using a
test that considers costs and benefits to both gas and electric operations of the utility, it is only marginally
cost effective to install new gas service for customers who are currently using electric space and water
heat, especially when the current system is electric zoned heat. The WWP study did analyze free
ridership but it appears that they did not analyze other alternatives to a fuel substitution program, such as
pricing and increasing choice in other ways (Washington Water Power 1991).
WSEO developed a Project library during the course of the Project that includes some fifteen fuel
substitution or fuel switching studies. Appendix C lists the studies WSEO has in its library. These
studies only scratch the surface in terms of revealing the potential cost effectiveness of fuel choice or fuel
conversion programs. The studies have, for the most part, focused on a narrow topic: the cost
effectiveness and potential for conversion from residential electric space and water heat to residential gas
space and water heat. One study has looked at conversion from electric drying and cooking to gas;
another study has looked at conversion from electric to gas commercial cooling. No study we are aware
of to date has looked at the potential or cost effectiveness for a gas to electric fuel conversion program.
The studies reviewed by WSEO have all concluded that when a residential customer has gas space heat
and electric water heat, it is cost effective to switch to gas water heat. One study conducted by BPA staff
(Anderson and Draper 1992) concludes that the marketplace can be expected to capture all cost effective
fuel switching opportunities for this type of situation. Other studies either didn't address the question
whether direct intervention was worthwhile, or concluded that some direct intervention was cost
effective.
8 See discussion of Pugefs PRAM mechanism in Chapter 1 above.
D-R8-01 W6 3-6
i Likewise, most studies conclude that when gas main is either directly in front of, or within a reasonable
distance from, a single family residence; it is worthwhile from a societal perspective to have the customer
switch to natural gas for space and water heat. Again, studies differ on the need for direct intervention,
although even Anderson and Draper concede that the marketplace does not appear to be picking up all
cost effective opportunities. One study performed outside the region concluded that switching to natural
gas cooking and clothes drying is probably cost effective for customers who already have gas. Another
study from Wisconsin concludes that switching to natural gas commercial cooling is cost effective.
Pipeline Capacity Sharing
This section discusses opportunities available for gas and electric utilities to coordinate interstate pipeline
transactions gas and electric utilities under the current regime of FERC Order 636.
Order 636
As a background for identifying some of the opportunities that exist for coordinated pipeline capacity
contracts, we will review briefly the conditions created by FERC's Order 636.
"Firm capacity" means the right of a purchaser to use interstate pipeline capacity at any time of the year
in contracted-for amounts. Firm capacity is expensive, since the pipeline must be sized so that it can
supply the contract firm demand of all purchasers simultaneously.
Before FERC issued Order 636, only local distribution companies (LDCs) could contract for firm
capacity from interstate pipelines. LDCs, in theory, could not resell firm pipeline capacity to other LDCs
or to end users, although some LDCs found various ways of getting around this prohibition. Pipelines
could both transport gas and sell gas commodity. However, many pipelines began scaling down their gas
commodity sales functions after FERC orders made it more feasible for LDCs and gas end users to obtain
their gas commodity from marketers and other non-pipeline sellers, who often beat pipeline commodity
prices.
Pipeline charges were in three parts: a charge for commodity sales (if any), and two demand charges, one
based on the peak capacity contracted for (D-1), and the other based on annual usage (D-2). LDCs
passed on a greater portion of demand charges to customers who had greater proportional demand on the
system on peak days--that is, firm residential or commercial customers (also known as core customers).
Order 636 made dramatic changes in the way interstate pipelines operate and price their service. First,
pipelines may no longer sell commodity (with negligible exceptions). Second, pipelines must pass on all
their fixed costs (which represents the bulk of their costs) in their peak demand (D-1) charges. This is
termed straight fixed variable rate design (as opposed to modified fixed variable rate design, which
existed when pipelines passed some of their fixed costs via the throughput-based D-2 charges). Third,
anyone can contract for firm pipeline capacity and resell their entitlement to firm capacity. Sellers must
' post any offers to sell pipeline capacity on an electronic bulletin board and offered to the highest bidder,
although private deals are also authorized within certain constraints.
i
D-R8-O1 W6 3-7
Order 636 has two important impacts on the relationship between electric utilities and the LDCs who
serve them with gas. The first is the straight fixed variable rate design. LDCs must by statute serve the
needs of their firm customers. They must have enough fine capacity resources to meet peak day
requirements that might only occur every twenty years or more. Previously, at least a part of pipeline
charges was based on annual consumption, so that costs to LDCs varied with consumption. Now, all
pipeline charges will be based on the peak usage anticipated by the LDC. LDCs therefore have a much
stronger incentive now to take steps improve pipelines' load factors, since they will have to pay for their
full share of unused pipeline capacity. If they can spread the pipeline demand charges over therms that
are riot consumed on peak, the cost of peak day therms will be reduced. They will also have a stronger
incentive to explore alternative capacity resources such as liquefied natural gas facilities or load
management.
The other major change affecting LDC and electric utility relationships is the ability of the LDC to sell
capacity to anyone who wants it (e.g., an electric utility or cogenerator)--or, conversely, the ability of the
LDC to purchase capacity from anyone who has it. Discussions between electric utilities and gas utilities
may be able to identify ways to minimize the adverse impacts of Order 636 and take advantage of some
of its benefits. We will discuss these further below.
The Northwest Hydroelectric System
The Northwest hydroelectric system is uniquely capable of taking advantage of capacity opportunities
offered by other regions, or by other energy systems such as gas. Because of the enormous amount of
installed turbine capacity loaded at the Northwest's hydroelectric dams, electric capacity is relatively
inexpensive here. There are two problems with the Northwest system, however, for utilities located west
of the Cascade Range. First, although capacity is plentiful, hydroelectric energy is limited by annual
snow or rainfall, and is hence not reliable, or "firm." Regional planners have proposed two ways to take
advantage of excess capacity and increase firm energy resources. The first is to increase regional firm
energy resources via a so-called hydroftrming strategy. Under hydrofirming, a utility builds a generating
plant--say, a simple cycle combustion turbine (CT)--that would operate when hydro conditions are poor.
Operation of the plant would reduce the need to generate with hydropower, allowing more water to build
up behind the dams during spring runoff. The availability of the CT would permit the nonfirm water to
be firmed up. The second strategy is to make capacity-energy trades with electric utilities outside the
region who need capacity but have energy available for sale.
The second problem for Puget Sound area electric utilities is that capacity and energy are transmitted
over the Cascade Range via four major transmission lines. A consortium of four retail utilities and BPA
has found that when there is high load and a simultaneous outage of one or more of the transmission
lines, the Puget Sound Region could experience unacceptable brownouts or blackouts in a few years.
The Puget Sound Area Electric Reliability Plan has proposed a number of possible solutions to this
problem, including siting new generation west of the Cascades, beefing up the existing transmission
system, and taking initial steps to build a new transmission line in several years.
D-R&01 % 3-8
Coordinated Pipeline Capacity Contracts
The changes wrought by Order 636, together with the opportunities presented by the Northwest
hydroelectric system, mean that coordinated pipeline capacity contracts could benefit both electric and
gas utilities. Here are three examples of how such joint planning could work:
In the first example, the electric utility would plan to site a simple cycle CT west of the Cascade Range,
which would operate very infrequently--only when capacity west of the Cascade Range is limited. The
' CT would be gas-fired, but the utility would also maintain a few days of alternative fuel backup supplies.
Alternatively, the electric utility could initiate a load management program whereby certain of its large
industrial customers agreed to interrupt during those times when the CT was unavailable.
The LDC would contract for firm pipeline capacity with the intent of using most of the capacity to move
gas commodity to its customers at a high load factor. However, when the electric utility is short on
capacity (e.g., when a transmission line crossing the Cascades Range is unavailable), it would have an
agreement with the LDC to call on the pipeline capacity to fuel the CT. In the event that the LDC's peak
day coincided with a time of an electric capacity peak, the electric utility could use its alternative fuel or
load management contract as backup.
The second example also involves the siting of a simple cycle CT. Here, however, the utility would
operate the CT as part of a hydrofirming strategy. In this case, the operation of the CT can be timed so
that it does not coincide with the LDC's peak day--for example, it could operate during spring runoff.
Under hydrofirming, it doesn't matter when the CT operates so long as it keeps the hydroelectric plants
from having to generate so much hydropower. Another cost advantage of using the CT for hydrofirming
versus for peaking capacity is that an alternative fuel backup might not be necessary. It is also possible
that a simple cycle CT could perform both functions.
' In the third example, the electric utility or independent power producer (IPP) would plan to site a
combined cycle combustion turbine (CCCT) or a cogeneration plant. This generation plant would
operate at a relatively high capacity factor--perhaps 70 percent or more. During the LDC's annual times
of greatest need--say, the 30 coldest days of the year--the LDC would use the gas while the CCCT was
either off line or using backup fuel. The remainder of the time, the electric utility or IPP would use the
natural gas for its generator.
The first two examples are mirror images of the third example. In the first two cases, the electric utility
or IPP uses the pipeline capacity only rarely and the LDC uses it most of the time. In the third case, the
LDC uses the capacity only for peak periods and the electric utility uses it the rest of the time.
Utilities would have to determine the relative benefits of these types of joint pipeline capacity planning
via an appropriate cost-benefit analysis. Suffice it to say here that under both examples,-access to
pipeline capacity for design day or for peak seasons is very valuable to the LDC: as noted in above, the
' LDC would have to pay a high premium for this capacity if it could not sell some of it to others in off-
peak seasons. Furthermore, access to pipeline capacity is valuable to electric utilities under both
examples, because it either firms up hydroelectric power or provides capacity benefits, or makes new
generation resources adequately reliable.
D-R8-01 W6 3-9
Examples of Existing Joint Pipeline Capacity Sharing
Coordinated pipeline transactions have already been considered or are being developed by other electric
and gas utilities in the region.
In Oregon, Northwest Natural Gas Company (NNG) negotiated an agreement with Portland General
Electric Company (PGE) whereby NNG will contract for pipeline capacity and deliver natural gas to the
site of a generation plant operated by PGE. NNG retains the right, however, to recall the capacity for up
to 30 days per year, and 60 days in any five year period. PGE pays the pipeline demand charges even if
NNG uses the capacity. If NNG uses the capacity, it pays only the cost of the backup oil that PGE uses
to run the generator. NNG's linear programming model shows that it would use the capacity about 20
days in a design (very cold) winter, and less than one day during a normal winter.
In Washington, Cascade Natural Gas and Tenaska, a cogenerator, have worked out a deal whereby
Cascade is building a pipeline to connect Tenaska with Westcoast Energy, the Canadian pipeline.
Tenaska is agreeing to maintain several days' of backup fuel so that Cascade could call on Tenaska s
transportation capability on peak days.
A unique idea by Washington Water Power (WWP) could also be used in a modified way by the working
group utilities in this project. WWP is building a CT at Rathdrum. The CT will take gas via the Pacific
Gas Transmission pipeline. In order to avoid having to sign up for firm pipeline capacity, WWP plans to
"divert" gas going to customers in Southern California. WWP will maintain storage at fields in Southern
California and release its storage gas to Pacific Gas Transmission's customers in the south to make up for
the diversion to the Rathdrum plant. Puget or Seattle City Light could make a similar arrangement in
western Washington where they would make storage capacity available to WNG in exchange for being
able to divert Northwest Pipeline-transported gas to a cogenerator or CT.
Siting Optimization
This section describes opportunities to minimize electric and natural gas costs by finding optimal sites for
natural gas-fired electric plants.
Both in the region and in the Puget Sound area, electric utilities expect to rely heavily on natural gas to
meet their generation needs. The 1991 Power Plan identifies 1,720 aMW of gas-fired cogeneration
available and 2,500 megawatts of CTS available as a hydrofirming strategy by 2010 regionally. The
cogeneration estimate assumes thermal match--i.e., that plants are sized to meet the energy needs of their
industrial host sites. Of that potential, the Portfolio 19 resource plan selected 830 aMW of cogeneration
and 1,020 aMW of CTS for hydrofirming, making gas-fired generation as a group the second largest
resource after conservation.
The working group utilities also expect to rely heavily on natural gas for generation. Puget's least cost
plan selects 1,000 aMW of high efficiency cogeneration to meet its medium case, far exceeding any other
resource in its plan (note that Puget's plan calls for more cogeneration for Puget alone than the Power
Plan anticipates for the entire region). The 1,000 aMW was an artificial cap established for planning
purposes. Puget may acquire more than 1,000 aMW of gas-fired resources, and they may not necessarily
be high efficiency. SCL's projected generation acquisitions are exclusively natural gas, consisting of
89.5 megawatts of cogeneration and 30 megawatts of CTs (simple cycle) for hydrofirming.
9 -The Power Plan developed a number of "portfolios" to respond to varying scenarios.
D-R8-01w6 3-10
The Puget Sound Area Electric Reliability Plan (PSAERP) inventoried least cost plans of the utilities in
the Puget Sound region as well as relying on economic analyses performed by BPA, in order to
determine how much locally built capacity the Puget Sound region could rely on in the event of a
capacity emergency. It found that the region could in the short term (within the next 10 years) install
about 420 MW of CT capacity and 1,100 MW of cogeneration (950 aMW). As with the Power Plan, the
PSAERP study assumes thermal match of cogeneration facilities. Taken together, these resources are the
largest generation resources.
Because of the expected heavy reliance on natural gas for future generation, some have concerns that
there may not be adequate gas supplies to fire all the anticipated generation. The Power Plan limits its
estimate of available gas fired generation in part because of concerns over gas availability. A number of
studies have looked at the feasibility of getting gas into the region to serve the generators. Many have
concluded that there are adequate pipeline capacity and commodity supplies to serve forecasted needs.
Others have serious reservations.
' What none of these plans have looked at, however, is strategic siting of these facilities to minimize
societal costs and fuel use. This section will describe some of the considerations that could guide energy
planners in siting gas-fired generating facilities in the Puget Sound region.
Siting priorities for gas-fired generation in the Puget Sound Region
In siting a new generation facility, the planner has to make tradeoffs among a number of factors--
proximity to a steam host, to gas distribution or pipeline, to electric transmission and distribution, to
load, etc. While developers and utilities do consider these factors, it does not appear that they have been
discussed comprehensively in published documents in the Northwest. The following discussion is
compiled from observations of knowledgeable planners and industry representatives.
Factor 1: Proximity to Steam Host/Industrial Facility
There are two main reasons why cogeneration, as opposed to stand-alone gas-fired generation, is being
built in the Northwest: the first is that cogeneration is an efficient use of energy. The second is that the
federal Public Utilities Regulatory Policy Act of 1978 (PURPA) and other federal and state legislation
gave cogenerators tax and regulatory incentives. In the last few years, the second consideration was
predominant. A number of recent developments have now considerably narrowed, if not eliminated, the
financial and regulatory "boost" for cogeneration. However, the debate over the extent to which
cogeneration is preferable to stand-alone generation has not disappeared.
The economic value of locating a generation unit close to an industrial facility in order to qualify as a
cogeneration unit, versus building stand-alone generation, is probably measured largely by comparing the
value of the usable process-related energy. Regional planners differ regarding the value of cogeneration
compared to stand-alone generation. Clearly cogeneration is a more efficient use of energy, particularly
when thermal match exists. The Power Plan endorses the concept of cogeneration as an efficient use of
energy that a stand-alone facility would otherwise waste; in fact the Power Plan limits the amount of
cogeneration in the plan to the-amount that would be thermally matched at industrial facilities in the
` Northwest. Similarly, Puget's 1992 least cost plan includes only "high efficiency cogeneration" as a new
gas-fired generating resource.
However, others believe that large scale cogeneration is simply not as cost effective as stand-alone
generation. Developers are mostly interested in cogeneration because of its potential revenue from
electric utilities. For a typical mid-size plant, as little as 3 percent of revenues might come from steam
sales, versus 97 percent from electric sales. The British Thermal Unit (BTU) usefulness and value of
steam are far lower than the BTU usefulness and value of electricity.
? D-R&01 % 3-11
Formerly, a cogeneration facility was exempt from federal regulation as an electric utility under the
Public Utility Holding Company Act (PUHCA) while a stand-alone independent power producer, was
not. This is no longer the case under the National Energy Policy Act of 1992, which now permits
Exempt Wholesale Generators to be exempt from PUHCA regulation.
The economics of cogeneration may begin to change as: 1) costs of transmission and distribution
continue to escalate, making siting of generation near load centers more advantageous; and 2) capacity
becomes more of an issue in the Puget Sound region, again making local generation more attractive (see
discussion under factor 5 below).
Factor 2: Proximity to Local Distribution System
A gas-fired generating plant must have gas. This either requires building a line directly to the pipeline or
connecting with the local distribution company (LDC). So far, most of the large IPPs in Washington
have opted for bypassing the LDC or, in one case, making an arrangement to build a direct line to Canada
that the IPP would pay for through its gas rates but the LDC would own (see discussion of the Tenaska-
Cascade Natural Gas arrangement in the previous section). From a societal perspective, the only criterion
should be which altemative has lower costs and can offer the greatest benefits of reliability and other
desirable criteria. From the LDC's point of view, there are benefits to avoiding bypass. This is
especially true with cogeneration because not only the generator but also the steam host might bypass the
LDC. Loss of a major industrial customer adversely affects load factor and risks allocating "stranded
investment" to remaining customers. However, this is largely a cost allocation issue.
Formerly, an advantage to a generator from being a customer of an LDC was the LDC's greater ability to
contract for pipeline capacity. After Order 636 (see discussion above under pipeline capacity sharing),
this consideration is virtually nonexistent. This is not to say that there are no advantages to having any
relationship between an LDC and a generator. However, pipeline sharing transactions such as those
described above, and other synergistic relationships can exist even if a generating unit is not physically
connected to an LDC.
Factor 3: Proximity to Pipeline
There are two types of cost considerations in siting a generating unit near the pipeline: first, the amount
of pipe and the permitting process associated with hooking up to the pipeline; second, the types of
transactions available that depend on where on the pipeline route the generator hooks up. A generator
can achieve significant cost savings from strategic siting on the pipeline, depending on whether gas is
flowing from Canada or the Southwest, on where there are pipeline constraints, and on where storage is
located. The Rathdrum CT described above is an example of fortuitous siting on the Pacific Gas
Transmission Company line. Other examples would be locating at the "advantageous" side of a pipeline
constraint, or locating at points in the pipeline where capacity sharing transactions with the LDC could be
advantageous to both parties.
Factor 4: Proximity to Electric Transmission
One independent power producer has recently remarked that siting is easy: you take a map of the
pipeline, another of the electric transmission grid, and you site your facility where they overlap.
Regional plans largely ignored the impact of new generation on the transmission grid until now. The
PSAERP saw addition of new generation west of the Cascades as an advantage because of its potential to
relieve strains on cross-Cascades transmission; however, it performed no detailed cost analysis of the
transmission costs associated with siting over one thousand new megawatts in the region. There is some
emerging evidence that these costs are not inconsiderable, however. A recent study of the costs of a new
D-R8-01 W6 3-12
small cogeneration plant indicated that for a $50 million capital investment, an additional $5 million in
transmission upgrades would be required. Some commenters believe that this is a conservative estimate
of the costs of transmission relative to generation. The Electric Power Research Institute (EPRI) has
recently completed a study that shows that up to two-thirds of electric utilities' rate based resource costs
may now be transmission costs. BPA imposes heavy penalties on utilities who exceed their entitlement
on BPA's transmission lines. Power flow calculations are very complex, and the transmission charges
may not reflect the true marginal transmission cost associated with a new generation plant.
1
One advantage to locating near transmission is that the developer can site the facility in rural areas with
fewer GMA, public opposition, and Clean Air Act problems. There are also locational advantages
similar to those described for pipelines above: depending on the location, a new facility can have
positive or negative effects on power flows.
Factor 5: Proximity to Electric Load
Common sense suggests that cost savings could be achieved by locating a new facility at the place where
load is growing. This may avoid the cost of new transmission and distribution upgrades and line losses
and it may improve power flows. Surprisingly, however, utilities do not appear eager to site new
generation at load sites--at least not baseload generation. This could be due to a number of factors,
including local resistance to building a plant near populations, the relatively low current cost of electric
transmission provided by BPA, and the importance of other factors such as fuel availability.
An exception to this apparent aversion may be for dispatchable facilities. The Puget Sound area is
beginning to plan for the capacity shortages predicted in the PSAERP. Under that plan there is value to
capacity located west of the Cascades. A dispatchable CT could be relatively easy to site, have minimal
environmental impacts and provide reliability benefits in the event of transmission problems.
Locating generation near load may become increasingly attractive in the coming years. As noted above,
siting generation near the load avoids new transmission and distribution upgrades, which are becoming
much more expensive than before. The Growth Management Act may or may not favor local generation
development. If counties' GMA plans include adequate infrastructure development to support local
generation, it could be easier to site new generation if the GMA plan includes it. However, counties may
be tempted to import their energy resources--and export their environmental, infrastructure, and other
energy-related problems.
Factor 6. Proximity to Oil Backup Supplies
Another important factor is the availability of oil for a backup fuel. Generators must typically have
several days' entitlement to oil available in the event natural gas supplies are interrupted. Generators
located on the coastline may have access to coastal oil supplies. Others may be able to store sufficient
backup supplies on site in storage facilities. Others yet may want to site their facilities near oil pipelines.
Opportunities for Synergies in Siting G'as-Fired Generation
i One purpose of this Project was to identify resources or other opportunities where, because costs are
divided among gas and electric utilities and society, a cost/benefit analysis performed by only one party
does not reflect the true societal benefit. To a large extent the siting tradeoffs between electric costs and
natural gas costs that the previous section described will be internalized in the cost to the developer or
electric utility. However, utilities, developers and regional stakeholders should examine the following
issues: first, to what extent does embedded cost pricing of electric transmission service hide the marginal
D-R8-01 W6 3-13
ti
cost of new transmission needed to bring remote generation to the load? Second, what opportunities
exist for natural gas cost savings via strategically siting a gas-fired facility at particular points along the
pipeline? Third, what relative environmental costs will be incurred at each proposed location? Fourth,
how can strategic siting decisions minimize reliability impacts to the LDC? The expertise of the LDC
would certainly be useful to potential generation developers in order to minimize their pipeline costs and
minimize adverse impacts on the LDC's reliability.
Fuel Cells
Fuel cells are devices that continuously convert the chemical energy of a fuel, typically hydrogen from a
hydrogen-rich gas mixture; and an oxidant, typically oxygen from air, into electric energy. Fuel cells
offer benefits that may be especially valuable to the working group utilities. These include the ability to
be built in small sizes and sited in dispersed areas. For a utility, such as Seattle City Light, which serves
a densely populated area, fuel cell technology offers the possibility of siting in distribution or
transmission-constrained areas, thereby eliminating the need for transmission upgrades and offering the
ability to site the plant at the exact location where it needs the power (see previous section). For
example, the utility could site the plant on top of a large commercial building, to serve the needs of that
building alone, and perhaps its close neighbors. The heat generated could be used for space heating or
cooling.
Fuel cell technology has to date been limited to space technology, and demonstration projects. Costs per
kW are currently extremely high.
Since fuel cells are typically natural gas-fueled, a gas supply must be available in order to take advantage
of the technology. Careful planning on the part of gas and electric utilities could provide opportunities to
reduce costs. For example, in areas where siting of a new electric transmission line or substation is
problematical, or where there are other cost advantages to locating a generator near load; and where
similar constraints do not exist for the gas utilities, the gas utility could provide adequate supply to the
electric utility to fuel a fuel cell at or near the load. Depending on the type of load being served, this
could also have the benefit to the gas utility of improving load factor, thereby minimizing unit costs to
remaining customers.
District Heating and Cooling
Bloomquist, Nimmons, and Rafferty 1988 define district heating as:
The heating of two or more structures from a central heat source. Heat may be provided in the
form of either steam or hot water and may be utilized to meet process, space, or hot water
requirements.
Fuel sources for heating include not only fossil fuels but also biomass and other fuel sources such as
solid waste. The technology of district heating has existed since Roman times and is well developed.
D-R8-O1 W6 3-14
There are also applications for district cooling, which involves using a centralized cooling system. One
such system is currently under construction in Puget's service territory. It involves Boeing and Metro,
Seattle's sewage treatment operator. The Boeing project involves piping sewage effluent to assist with
the cooling system for a new Boeing Customer Services Training Center, an office facility. The effluent
' will operate as a heat sink for the facility's heat exchangers that provide cooling for the Center. This
project will eliminate the need to build and run an evaporative cooling plant, thereby saving
approximately 2.2 million kWh per year of electricity and reducing the utility's cost of providing that
electricity. Puget provided a grant to Boeing to finance the project as a DSM measure (Ross 1994).
The relevance of district heating and cooling for this Project is the possibility that natural gas could be
the fuel used for the heating or cooling system. If so, close coordination between the electric and natural
gas utility would be beneficial to optimize siting and operation decisions in order to minimize the cost to
both utilities. The tradeoffs and considerations would be similar to those described in previous sections
on pipeline capacity sharing and fuel cells.
Working Croup Conclusions
/ After researching these seven opportunities, the group decided to focus on four, namely: fuel choice/fuel
substitution, joint trenching, line extension policy, and pipeline capacity sharing. There were several
reasons for this decision.
First, the group believes that all seven of the opportunities have potential. However, in the case of fuel
cells, the group believes that the technology is not sufficiently well developed to be able to undertake a
comprehensive and useful cost/benefit analysis. The group believes that both fuel cells and district
heating opportunities are highly site-specific and need to be analyzed as they come up. The group agreed
' that close coordination between the electric and gas utilities involved is likely to improve the cost
effectiveness and other benefits of these technologies.
In the case of siting opportunities, the group again believes that this opportunity ultimately needs to be
pursued. However, after considering the siting issues described in this chapter, the working group
decided that, while siting should be an important topic for discussions among utilities, it would not
pursue specific opportunities in this Project. This is for three primary reasons. First, Northwest Pipeline
runs directly through Puget Power's service territory. Therefore, the tradeoffs between siting near electric
transmission and siting near gas transmission are not so important as other considerations. Second, as
noted above, most of the siting tradeoffs will be internalized to the generation developer and do not need
to be the subject of inter-utility coordination. Third, the tradeoffs will be highly site-specific and highly
complex. The complexity of the calculations did not justify the limited usefulness of the information that
the working group would gain by performing an analysis of this opportunity.
,
Finally, the group believes that utilities can effectively use the cost effectiveness methodology developed
and described in the next chapter to analyze these other opportunities, as occasions to do so arise.
r
y
D-R8-01 W6 3-15
Chapter 4
Cost/Benefit Methodology and Results
This chapter discusses the methodology developed to quantify the likely benefits and costs of the various
' opportunities that the working group decided to pursue, and the results of its analysis.
Methodology
Under traditional IRP, the goal is to minimize long-term revenue requirements to a utility, given
appropriate levels of service and reliability and other desirable criteria. Therefore, IRP analysis starts
from the utility's perspective. Occasionally, however, IRP takes broader interests into account. For
example, analysis of DSM programs often considers the program's "total resource costs" (e.g., including
participant contributions), not only costs to the utility. In addition, there is increasing interest in taking
the extemal--e.g., environmental--costs of utility's resource acquisitions into account.
In fuel blind IRP, the analysis must include broader perspectives than a single utility's alone. In some
cases, the opportunity analyzed will lower the long-term revenue requirements of all utilities involved.
In others, one utility's revenue requirements will increase and another's decrease. This will almost
certainly be true, for example, for a fuel choice or substitution program, and may be true for some types
of line extension reform and other opportunities. The working group therefore agreed that at the outset it
needed to analyze the opportunities from society's long-run perspective, rather than from the perspective
of individual utilities or their customers.
The opportunities selected for further research all have a multitude of impacts. These include: resource
? costs (including energy and capacity); transmission and distribution costs; end use appliance costs,
including operation and maintenance costs; and environmental, infrastructure, and aesthetic impacts.
There are a number of possible ways to analyze the costs and benefits of particular opportunities. The
group reviewed three major methodological approaches.
Avoided Cost
One approach is to use utilities' filed generic "avoided cost" and to compare the cost of the opportunity
with that avoided cost. The opportunity may be cost-effective if it costs less than avoided cost. In the
existing fuel switching and fuel choice studies that WSEO reviewed (see chapter three), this appeared to
be the most common methodology (analysts compared the avoided costs of reducing reliance on one
energy resource with the incremental costs of increasing reliance on the other).
,
However, this method had a number of drawbacks. The first and most important for the Project was that
neither the electric nor the gas utilities' avoided cost techniques were well suited to the type of cost
comparison involved in this situation. WNG currently uses its avoided cost solely for analyzing the costs
and benefits of demand-side measures. Puget uses its avoided cost methodology in conjunction with
other resource selection methodologies such as the market and differential revenue requirements
described below.
D-R8-01 W6 4-1
Finally, the comparison of the opportunity is made only with some previously determined generic
avoided cost. It does not rely on a specific or rigorous comparison of that opportunity with a
contemporaneous alternative or cost of an equivalent opportunity.
Differential Revenue Requirements
Another methodology commonly used is to have the utility run its production cost models with and
without the opportunity being analyzed. This methodology has the advantage of being able to identify
with some precision the impacts of each opportunity. Currently, the working group utilities use their
production cost models to test the impacts of "scenarios," i.e., combinations of resource acquisitions to
achieve certain strategic results. They also use these models to test the impact of individual resource
decisions in certain cases (e.g., pipeline capacity expansion opportunities).
Possible disadvantages are that this method is time consuming and may not be transparent (i.e., it may be
difficult to determine the reasons why it produces certain results). Also, each utility's model is designed
to ascertain the impact on the utility of pursuing opportunities. Because the group was interested in
society's perspective, the group would have to change certain inputs, and even then the model outputs
would not accurately reflect all of society's interests.
Market
A third, increasingly common, methodology for revealing the value of a resource is to go to the
marketplace with requests for competitive bids or other types of solicitation. This method is arguably the
most accurate way to ascertain the value of a resource, given the effective operation of a market (i.e.,
existence of competition, equal access to capital, and full information). However, the working group did
not seriously consider it at this time as a cost/benefit analysis tool because the opportunities being r
considered are not sufficiently mature or defined to go to the marketplace with them. However, as
described below in chapter six, the recommended implementation plan involves marketplace tools.
After considering all three methodologies, the group decided to use the differential revenue requirement
method as an initial screening for cost-effectiveness. For a variety of reasons, the group decided to focus i
its analysis on opportunities for synergy between Puget and WNG. WSEO agreed to use WNG's and
Puget's production cost models to analyze the costs and benefits of each opportunity selected for further
research10. The group believes that the results of the analysis of WNG and Puget costs are probably
generally applicable to SCL as well.
Because running the computer models is time consuming and somewhat cumbersome, the group decided
to identify a limited number of "cases" to analyze. We describe these below. The cases are not intended
to describe either the existing marketplace or the impact of pursuing any of the various opportunities
identified by the working group. The working group selected them primarily to reveal information about
r
the costs associated with various fuel choices and with selected opportunities.
s
10 The utilities assisted WSEO in making arrangements with the owners of the software licenses for
WNG's and Puget's production costing models, UPLAN-G and MIDAS Gold (Lotus Consulting Group
and M.E. Gerber and Associates, respectively) to allow WSEO to perform some of the model runs. The
working group is grateful to LCG and M.E. Gerber for making the models available to WSEO.
D-R8-01 W6 4-2
In this respect, we should point out that the case studies we selected cannot necessarily be used to draw
conclusions about the likely results of other scenarios. For example, many of our case studies looked at
' relative costs of heating 1,000 homes in a subdivision with gas or electricity.. It may not be possible to
use the results of these analyses to draw conclusions about the likely costs for 100,000 homes, or homes
not located in a subdivision. Costs of serving end uses vary depending on the types of end use, the size
of the load' distance from existing system, and a host of other factors.
1 As noted in chapter one, Puget is adding new customers at the rate of over 15,000 customers per year;
? WNG is adding over 20,000 new customers. Therefore, the cases that analyze the impacts of adding
1,000 new customers over the course of 20 years are not intended to represent the impact of a particular
implementation strategy on any of the working group utilities' entire systems. Such an analysis will have
to be undertaken as a separate exercise, as we remark below in chapter seven.
1 Even for the cases considered, the dollar values must be taken with a grain of salt. The present value of
cost differences in the cases generally is a few million dollars or less out of a total revenue requirement of
billions of dollars for each utility. This is not much larger than the potential round-off error in the
production cost programs. While the working group is generally confident in the direction of cost
differences shown by the analysis, we are much less confident about the size of those differences. In
particular, we believe that these results are not precise enough as yet to be used to justify levels of
expenditures to pursue any particular opportunities.
Case Studies
I The ultimate goals of the Project are to identify areas where increased cooperation between utilities
would be beneficial, to identify the reasons why such beneficial cooperation is not occurring, and to find
ways to remove barriers to increased cooperation. The purpose of the case studies was to provide general
yes or no answers as to whether these are opportunities for beneficial cooperation, not to estimate the
total magnitude of net benefits of specific potential actions.
Some of the opportunities the group selected for review have the potential to influence customers' choice
between gas and electricity for end uses such as space and water heating. Therefore, most of the cases
focused on the relative societal costs and benefits of different fuel choices. The group also developed
cases to identify the costs and benefits of gas and electric utilities sharing natural gas pipeline capacity
and joint trenching of distribution systems.
Fuel Choice/Fuel Substitution Cases
As used in this Project, the term "fuel choice" refers to the choices made by consumers when erecting a
new building or implementing a new end use. The term "fuel substitution" refers to the decision of a
consumer to change the type of fuel he or she is consuming for an existing end use. The cost/benefit
analysis did not make any assumptions about how consumers are making these decisions (e.g., as the
result of a program, the "marketplace," costs of alternatives, etc.) It simply compared the cost of serving
the new structure or end use with each type of fuel (in the case of fuel choice) or the cost of changing
from one fuel to another (in the case of fuel substitution). The next chapter on barriers discusses the
factors influencing the decision.
I A utility might very well alter its resource mix if it were serving a load of 1,000 new homes as
opposed to 100,000 homes. -
D-R8-O1 W6 4-3
The group agreed to focus on the residential sector for the time being. We know more about the
residential sector than the commercial and industrial sectors. WSEO relied on two primary sources of
information for developing its prototypical residences. These were information contained in a recent
customer survey performed by Puget, and in a commercially available database entitled MetroScan®,
which contains information about housing characteristics of several of Washington's counties. WSEO
developed four cases analyzing single family residences, and one case analyzing multifamily residences.
Examination of data from Puget's customer survey and the MetroScan® database indicated that most
larger new single family houses are being heated by gas, and that about half of smaller new single family
houses are being built with gas heat. The group wanted to identify if there was a break point, where for
larger houses, the social costs of heating with gas were lower, and for smaller houses, the social costs of
heating with gas were higher. The group also wanted to examine whether other factors influenced the
socially optimal fuel choice.
The group agreed to use a subdivision of 1,000 houses as the unit of analysis for its single family home
cases. The load from such a subdivision is large enough to have an impact on the two utilities' system
cost models, but is well under the number of new houses being built each year in their shared service
territory. The group originally wanted to do several cases using generic transmission and distribution
costs and one with costs for a specific hypothetical subdivision. The working group decided to drop this
last case when it became clear that the effort required to estimate distribution costs at that level of detail
would be prohibitive and the results of little general application.
The group settled on two single family and one multifamily fuel choice--i.e., new home--cases. The
single family cases looked at a subdivision of 1,000 large single family houses and a subdivision of 1,000
smaller single family houses. The multifamily case looked at the cost to heat 1,500 medium sized
apartment units with electricity and with natural gas. WSEO developed a prototypical 12-plex apartment
building, and compared the relative electric and natural gas costs to provide water and space heat to 125
of these buildings. In all cases WSEO compared the total costs of gas space and water heat in all the
houses with electric space and water heat in all the houses.
The group also decided to examine two single family fuel substitution cases. These looked at 1,000
small, older gas heated houses, in an area where the gas distribution system needs replacing. The first
case compared total costs for converting these houses to electric space and water heat with keeping them
on gas and replacing the distribution system. The second made the same comparison, except that the
houses being converted to electric heat also were brought up to current energy code standards, as required
by City of Seattle building codes.
The group also asked WSEO to perform sensitivity analyses, changing various assumptions to determine
the sensitivity of the results to the assumptions used. The next section also shows the results of these
sensitivity analyses.
Pipeline Capacity Sharing
The group originally wanted to address two issues relating to the construction of new gas-fired
generation. The first was whether the social costs were lower for building the power plant close to the ,
pipeline to minimize new gas line construction, or for building close to electric loads to minimize new
electric transmission construction. The second issue was whether there were potential cost savings from
the two utilities sharing pipeline capacity.
D-R8-O1 W6 4-4
The first issue turned out to be moot. As we noted above in chapter three, the Northwest Pipeline runs
north to south through the Puget Sound area. A developer could build a gas-fired power plant that was
both next to the pipeline and located in the center of Puget Power's service area. However, such a
location would be impractical or impossible because of air and noise pollution limitations and other
siting considerations. Distance from the pipeline simply is not a constraint.
WSEO addressed the issue of pipeline capacity sharing by comparing a case where the developer of a
new gas-fired power plant buys new firm pipeline capacity to meet its needs year round with a case
where the developer uses existing capacity owned by the gas utility for 335 days per year and bums fuel
oil for the 30 days per year with highest gas loads.
Joint Trenching
Joint trenching refers to the practice of having more than one utility share a single trench for underground
services. Since well over half of the cost of installing underground services can be the cost of trenching,
not to mention the unquantified aesthetic and convenience impacts of trenching activities, joint trenching
' can have benefits for society and for the utilities.
Our research revealed that there are currently two types of joint trenching occurring in the Puget Sound
' region. The first is "reactive," that is, a utility that is planning to open up a trench in the near future
notifies other utilities so that they can have the opportunity to share the trench. The second is "planned,"
where utilities actually engage in medium to long-term distribution upgrade, maintenance and extension
planning, and coordinate long-term construction budgets to minimize the numbers of times trenches are
opened. Currently, there is a good deal of reactive joint trenching. Furthermore, planned joint trenching
does occur to serve new developments. However, planned joint trenching for system-wide repairs,
extensions, and upgrades of service is in its infancy. To assess the value of joint trenching versus
uncoordinated trenching, WSEO used the results of its sensitivity analysis to draw rough conclusions
about the value of increased joint trenching.
Analysis and Results
Fuel Choice and Substitution
Fuel Choice--Large Single Family Houses
WSEO based the new house prototypes used in the fuel choice cases on designs it developed to analyze
building code cost-effectiveness. The new large house is a 2,356 square foot split level with four
bedrooms, three-and-a-half bathrooms, a kitchen, dining room, living room, family room, and laundry. It
has a central forced air furnace. WSEO modeled the gas furnace as a standard model with 78 percent
? annual fuel utilization efficiency (AFUE) rather than a more efficient condensing furnace. Some new
electrically heated houses of this size will have heat pumps. However, heat pumps provide air
conditioning as well as heating, while few gas heated houses in the Puget Sound area appear to have air
conditioning. The group therefore decided to compare fuels for conventional forced air heat to keep the
houses as comparable as possible. The group originally intended this case to be representative of large
new houses, but Puget's survey and the MetroScanO data indicate that it is closer to the median for new
construction in King County.
D-R8-Ol W6 4-5
WSEO calculated gas and electric heating loads for this house using the SUNDAY thermal modeling
program from Ecotope, Inc. 12 WSEO based the loads on average Seattle weather. WSEO based water
heating loads and other appliance loads on the average loads observed in the Residential Standards
Demonstration Program13. This data did not allow WSEO to estimate a firm relationship between house
size and non-heating loads. Therefore, the analysis used the same water heating and appliance loads in
all houses. Table 13 shows the monthly space heat loads for gas and electric heat, and the monthly gas
and electric loads for water heat, and the monthly electric loads for heating and appliances for the large
house. Note that Washington's residential building code requires homes heated with electricity to contain
more insulation and more efficient windows than those heated with gas. Therefore, the gas heated large
house is not identical to the electrically heated large house.
Table 13
Monthly Gas and Electric Loads for Large Houses (2,356 sq. ft.)
Electric Gas Electric Gas Other Total Total Total
Space Space Water Water Electric Electric Gas Electric
Heat Heat Heat Heat Load, Load, Load, Load,
Load, Load, Load, Load, kWh Electric Gas Gas
kWh therms kWh therms House House House
Jan. 1,869 120.2 440 27.2 675 2,984 147.4 675
Feb. 1,219 81.2 430 27.2 640 2,289 108.5 640
Mar 1,101 74.5 420 26.6 600 2,121 101.1 600
Apr. 588 44.2 375 24.1 575 1,538 68.2 575
May 278 21.8 360 22.8 560 1,198 44.6 560
June 18 2.3 310 20.3 525 853 22.6 525
Jul 3 1.3 290 19.0 525 818 20.3 525
Aug. 0 0 290 19.0 545 835 19.0 545
Se v. 46 5.3 320 20.3 580 946 25.5 580
Oct. 485 36.3 330 21.5 585 1,400 57.8 585
Nov. 1,020 69.4 380 24.1 645 2,045 93.4 645
Dec. 1,809 115.6 410 26.0 660 2,879 141.6 660
Total 8,435 572.0 4,355 278.0 7,115 19,905 850.0 7,115
For the gas heat case, WSEO added the gas load for 1,000 of the large houses to WNG's current load
forecast and ran UPLAN-G with this forecast to give gas system costs. In addition, WSEO added the
electric load for 1,000 large gas-heated houses to Puget's current load forecast and calculated the resulting
i
electric system cost using Puget's resource costing spreadsheet and MIDAS Gold. WSEO used average
figures from WNG's and Puget's recent experience for gas distribution costs and electric transmission and s'
distribution costs. WSEO assumed that the two distribution expansions would share a trench, and
included the trenching cost in the electric transmission and distribution cost. WSEO also calculated the
cost of the gas heating systems and water heaters.
For the all electric case, WSEO used WNG's base case (i.e., the case without the 1,000 new homes) for
gas system costs and added the electric load for 1,000 large all electric houses to Puget's base case in
calculating electric system costs. WSEO estimated costs for the electric heating system and electric
water heater, and for the additional insulation measures the Washington building code requires for
electrically heated houses.
12 Versions 3 and 4.
13 This was a program funded by BPA in the mid 80s to verify changes in electric savings due to
changes in construction practices.
D-R&01% 4-6
Table 14 shows the present value of the costs over 19 years at a 3 percent real discount rate to serve
1,000 large all electric houses and 1,000 large gas heated houses, and the differences. Positive values in
the difference column indicate savings associated with the gas houses, while negative differences indicate
net cost increases.
i
Table 14
Costs for 1000 Large Houses
All Electric Gas Heat Difference
Gas System Cost $0 $2,533,000 -$2,533,000
} Electric System Cost $9,980,000 $3,590,000 $6,390,000
Appliance and Insulation Cost $3,327,000 $2,700,000 $627,000
Gas Distribution Cost $0 $900,000 -$900,000
Electric T&D Cost $3,243,240 $2,619,130 $624,110
Total $16,550,240 $12,342,130 $4,208,110
i
Using natural gas to heat space and water in these 1,000 houses would reduce social costs by
approximately $4 million net present value compared to use of electricity to serve the same end uses.
Fuel Choice--Small Single Family Houses
The new small house is a 1,344 square foot rambler with three bedrooms, two baths, a kitchen, and a
living room. The gas house has a central furnace and forced air heating. The all electric house has a
combination of baseboards and wall heaters. Consequently, the electric heating system incurs no duct
losses.
Table 15
Monthly Gas and Electric Loads for Small Houses (1,344 sq. ft.)
Electric Gas Electric Gas Other Total Total Total
Space Space Water Water Electric Electric Gas Electric
Heat Heat Heat Heat Load, Load, Load, Load,
Load, Load, Load, Load, kWh Electric Gas Gas
kWh therms kWh therms House House House
Jan. 836 68.9 2 27.2 675 1,951 96.1 675
Feb. 485 44.4 430 27.2 640 1,555 71.7 640
Mar 408 39.6 420 26.6 600 1,428 66.2 600
Apr. 146 20.3 375 24.1 575 1,096 44.3 575
May 42 8.1 360 22.8 560 962 30.9 560
June 0 0.1 310 20.3 525 835 20.3 525
Jul 0 0 290 19.0 525 815 19.0 525
Aug. 0 0 290 19.0 545 835 19.0 545
Sep. 0 A4 320 20.3 580 900 20.7 580
Oct. 125 15.5 330 2105 585 1,040 37.0 585
Nov. 353 35.2 380 24.1 645 1,378 59.3 645
Dec. 794 65.6 410 26.0 660 1,864 91.5 660
Total 3,189 298.0 4,355 278.0 7,115 14,659 576.0 7;115
WSEO calculated costs for the gas and electrically heated small houses in the same way as for the large
houses. Table 16 shows the results.
D-R8-O1 W6 4-7
Table 16
Costs for 1000 Small Houses
All Electric Gas Heat Difference
Gas System Cost $0 $1754,000 -$1,754,000
Electric System Cost $7,350,000 $3,590,000 $3,760,000
Appliance and Insulation Cost $1,778,000 $2,500,000 -$722,000
Gas Distribution Cost $0 $900,000 -$900,000
Electric T&D Cost $3,243,240 $2,619,130 $624,110
Total $12,371,240 $11,363,130 $1008,110
Using natural gas to heat these 1,000 small new houses saves approximately $1 million compared to use
of electricity to serve the same end use.
Fuel Substitution--Small Old Houses
The small old house is a 1,000 square foot bungalow with a basement and an attic that is used as a room. '
It has a central furnace operating at 50 percent AFUE and forced air heating. The conversion to electric
heat requires installing baseboards and wall heaters and a new electric service and breaker box.
Table 17
Monthly Gas and Electric Loads for Old Houses
Electric Gas Electric Gas Other Total Total Total
Space Space Water Water Electric Electric Gas Electric
Heat Heat Heat Heat Load, Load, Load, Load,
Load, Load, Load, Load, kWh Electric Gas Gas
kWh therms kWh therms House House House
Jan. 2,371 159.2 440 27.2 675 3,486 186.5 675
Feb. 1,708 115.5 430 27.2 640 2,778 142.7 640
Mar 1,658 112.8 420 26.6 600 2,678 139.4 600
Apr. 1,107 76.3 375 24.1 575 2,057 100.4 575
May 573 39.6 360 22.8 560 1,493 62.4 560
June 110 8.0 310 20.3 525 945 28.2 525
Jul 57 4.2 290 19.0 525 872 23.2 525
Au 2 0.2 290 19.0 545 837 19.2 545
Se 161 11.3 320 20.3 580 1,061 31.6 580
Oct. 822 56.1 330 21.5 585 1,737 77.6 585 f,
Nov. 1,410 95.2 380 24.1 645 2,435 119.2 645
Dec. 2,237 150.1 410 26.0 660 3,307 173.0 660
Total 12,217 828.4 4,355 278.0 7,115 23,687 1,106.4 7,115
Table 18 shows the costs for keeping these 1,000 houses on the gas system and for switching them to
electricity.
D-R8-01 W 6 4-8
i
1
Table 18
Costs for 1000 Old Houses
All Electric Gas Difference
Gas System Cost -$3,284,000 $0 -$3,284,000
Electric System Cost $8,330,000 $0 $8,330,000
Incremental House Cost $2,300,000 $0 $2,300,000
Gas Distribution Cost $0 $900,000 -$900,000
Electric T&D Cost $624,110 $0 $624,110
Total $7,970,110 $900,000 $7,070,110
1
Keeping these old houses on the gas system and replacing the distribution system costs $7 million less
than switching them to electric heat.
a Fuel Substitution--Small Old Houses with Retrofits
If the small houses converting to electricity were located in Seattle, the city would require that they be
brought up to the requirements of the current state building code. Table 19 shows the electric loads for
1 the house with additional insulation.
1
Table 19
Monthly Electric Loads for Upgraded Old Houses
Electric Electric Other Total Electric
Space Heat Water Heat Electric Load, Electric
Load, kWh Load, kWh Load, kWh House
Jan. 1,036 440 675 2,151
Feb. 419 430 640 1,489
Mar 331 420 600 1,351
Apr. 19 375 575 969
May 7 360 560 927
i June 0 310 525 835
Jul 0 290 525 815
Aug. 0 290 545 835
Sep. 0 320 580 900
Oct. 24 330 585 939
Nov. 198 380 645 1,223
Dec. 929 410 660 1,999
Total 2,963 4,355 7,115 14,433
} WSEO estimated the minimum cost for converting this house to electric heat and bringing it up to code is
at least $10,149. Table 20 shows the costs for this case.
}
1
D-R8-01 W6 4-9
Table 20
Costs for 1000 Upgraded Old Houses
All Electric Gas Heat Difference
Gas System Cost -$3,284,000 $0 -$3,284,000
Electric System Cost $5,730,000 $0 $5,730,000 t
Appliance and Insulation Cost $10,149,000 $0 . $10,149,000
Gas Distribution Cost $0 $900,000 -$900,000
Electric T&D Cost $624,110 $0 $624,110
Total $13,219,110 $900,000 $12,319,110
r
Converting these houses to electric heat and bringing them up to current code standards is even less cost
effective than just converting them. This is because it is much more expensive to retrofit an old house
than to include efficiency measures in a new house as it is being built. t
t
Fuel Choice - Multifamily Housing
The multilevel apartment building is a traditional twelve unit building, each with a floor area of 1,000
square feet. The electrically heated apartments have wall heaters and a conventional water heater. The
gas heated apartments have a combined water heat/hydronic space heat unit in each apartment. With the
small window area in a typical apartment, the gas heated apartments can meet the energy code with 2x4
walls while the electrically heated apartment has 2x6 walls. The gas heated apartment also has less
expensive windows, but the cost of the heating system makes the gas apartments cost $1,200 more to
build.
Table 21 shows the gas and electric loads for this apartment building.
Table 21
Monthly Gas and Electric Loads for 12-Plex
{
Electric Gas Electric Gas Other Total Total Total
Space Space Water Water Electric Electric Gas Electric
heat Heat Heat Heat Load, Load, Load, Load,
Load, Load, Load, Load, kWh Electric Gas Gas
kWh therms kWh therms Apts. Apts. Apts.
Jan. 5,797 413.0 3,779 161.4 8,100 17,676 574.4 8,100
Feb. 3,286 262.6 3,693 161.4 7,680 14,659 424.1 7,680
Mar. 2,772 232.5 3,607 157.7 7,200 13,579 390.1 7,200
Apr. 900 114.1 3,221 142.7 6,900 11,021 256.7 6,900
May 237 41.7 3,092 135.1 6,720 10,049 176.8 6,720
June 0 0.0 2,663 120.1 6,300 8,963 120.1 6,300
Jul 0 0.0 2,491 112.6 6,300 8,791 112.6 6,300
Aug. 0 0.0 2,491 112.6 6,540 9,031 112.6 6,540
Sep. 0 0.6 2,748 120.1 6,960 -917-0-8 120.8 6,960
Oct. 752 85.1 2,834 127.6 7,020 10,607 212.7 7,020
Nov. 2;272 202.3 3,264 142.7 7,740 13,275 345.0 7,740 i
Dec. 5,463 391.1 3,521 153.9 7,920 16,905 545.0 7,920
Total 21,479 1,742.9 37,404 1,648.0 85,380 144,263 3,390.9 85,380 r
D-R8-01 W6 4-10
Table 22 shows WSEO's estimate of the costs of serving 125 of these buildings with 1,500 apartments.
Table 22
Costs for 125 Apartment Buildings
All Electric Gas Heat Difference
Gas System Cost $0 $1,284,000 -$1,284,000
Electric System Cost $8,420,000 $6,120,000 $2,300,000
Appliance and Insulation Cost $853,000 $2,672,000 -$1,818,000
Gas Distribution Cost $0 $232,500 -$232,500
Electric T&D Cost $405,405 $327,391 $78,014
Total $8,825,405 $9,781,891 -$956,486
Although there are fuel cost savings associated with heating these apartments with natural gas, they are
more than offset by the incremental cost of having individual gas heating systems in each apartment.
Using natural gas to heat this type of apartment is therefore not cost effective with individual heating
systems. The results of this analysis, however, are not necessarily applicable to other types of
multifamily buildings, such as zero lot line units, townhouses, condominiums, etc.
i
Sensitivity Analysis
Since all of the single family cases examined showed lower social costs for heating with gas, WSEO
made several changes in assumptions to test the sensitivity of the results. 14 First, WSEO doubled the gas
distribution cost. Table 23 shows the results.
Table 23
Higher Gas Distribution Cost
Total Cost, All Total Cost, Gas Difference
1 Electric Heat
1,000 Large Houses $16,550,240 $13,242,130 $3,308,110
1,000 Small Houses $12;371,240 $12,263,130 $108,110
1,000 Old Houses $7,970,110 $1,800,000 $6,170,110
Next, WSEO eliminated the difference in electric transmission and distribution costs between the
electrically heated home and the gas heated home. Table 24 shows the results.
Table 24
No Electric Distribution Cost Difference
Total Cost, All Total Cost, Gas Difference
Electric Heat
1,000 Large Houses $16,493,240 $12,966,240 $3,527,000
1,000 Small Houses $12,371,240 $11,987,240 $384,000
1,000 Old Houses $7,970,110 $900,000 $7,070,110
14 WSEO did not perform similar sensitivity analyses for its multifamily case, since that case shows
lower societal cost to heat with electricity than to heat with natural gas.
D-R8-O1 W6 4-11
Table 25 shows the results from combining these two cases.
Table 25
Both
Total Cost, All Total Cost, Gas Difference
Electric Heat
1,000 Large Houses t $16,550,240 $13,866,240 $2,684,000
1,000 Small Houses $12,371,240 $12,887,240 -$516,000
1,000 Old Houses $7,970,110 $1,800,000 $6,170,110
To check the sensitivity of the results to gas prices, the large house case was run with higher gas
escalation rates. Real annual escalation rates were set to 9.2 percent for the period 1994 - 2000 and 5.5
percent for 2001 - 2012. These are the averages of the annual escalation rates for these periods in the
NWPPC's high gas price scenario. (Northwest Power Planning Council 1993.) Table 26 shows the
incremental costs of serving 1000 large houses with these higher gas costs.
Table 26
1,000 Large Houses with High Gas Price Escalation
All Electric Gas Heat Difference
Gas System Cost $0 $2,750,000 $2,750,000
Electric System Cost $12400,194 $4,830,610 $7,569,584
Appliance and Insulation Cost $3327,000 $2,700,000 $627,000
Gas Distribution Cost $0 $900,000 4900,000
Electric T&D Cost $3,243,240 $2,619,130 $624,110
Total $18,970,434 $13,799,740 $5,170,694
The cost advantage for natural gas increases with this increase in assumed gas prices. This is because
Puget plans to meet electric load growth primarily with gas fired generation. Higher gas prices increase
the cost of meeting this load with electricity more than they increase the cost of meeting the load directly <
with gas because gas-fired electricity generation has lower thermal efficiency. At some level of higher f
gas prices, gas-fired generation would not be cost effective and the electric loads would be met with some
other resource. Increases in gas prices beyond that point would reduce gas's cost advantage.
Costs and Benefits of Extending Gas Main
The fuel choice cases all assumed a subdivision or dwelling unit immediately adjacent to areas where gas
is available. WSEO calculated how many miles WNG could extend gas service to single family homes
and still retain a societal cost advantage over electricity, for each of the various cases and sensitivities ,l
described above. 15
i
15 Since WSEO's analysis shows that the multifamily homes used for the analysis are more cost
effectively heated with electricity than natural gas, this calculation was not performed for the multifamily
home case. -
D-R8-O1 W6 4-12
Table 27 shows the present value of social cost savings from having 1,000 new houses heated with gas
for each of the cases and the miles of gas main extension that these savings could pay for at two different
levels of cost. Gas main extensions either use low pressure plastic distribution main for short distances,
or high pressure steel pipe for long distances. Extension of low pressure plastic distribution mains using
an existing road right-of-way costs about $14 a foot. At this cost, all of the large house cases and the
small house base case justify extending service a considerable distance--farther than a utility is likely to
make extensions and still use low pressure pipe. High pressure steel pipe, which a utility would use for
long distances, costs about $25/foot installed. At this cost, cost savings for 1,000 large houses justify
} extension of up to thirty-two miles, while 1,000 small houses would justify extension of less than eight
miles.
Table 27
Costs and Benefits of Main Extension
PV of Net Maximum Miles of Maximum Miles of
Savings from Gas Main Extension at Main Extension at
Heat $14/ft $25/ft
1,000 large houses, base case $4,208,110 56.9 31.9
1,000 small houses base case $1,008,110 13.6 7.6
1,000 large houses higher as T&D $3,308,110 44.8 25.0
1,000 small houses, higher as T&D $108,110 1.5 0.8
1,000 large houses, no elec. T&D diff. $3,527,000 47.7 26.7
1,000 small houses, no elec. T&D diff. $384,000 5.2 2.9
1,000 large houses, both $2,684,000 36.3 20.3
` 1,000 small houses, both -$516,000 0.0 0.0
1,000 large houses, high as esc. $5,170,694 69.9 39.17
Actual extension costs could differ greatly depending on terrain and the nature of the existing system to
which the connection is made.
As we have emphasized above, these costs represent societal costs and savings, not the costs and savings
that individual utilities or their customers would face. In the next chapter, we examine whether the actual
allocation of main extension costs under current tariffs leads customers and utilities to make decisions
that are consistent with societal benefits.
Pipeline Capacity Sharing
As discussed above in chapter three, both electric and gas utilities might benefit from cooperative
pipeline capacity contracts. We provided three examples of how such an arrangement might work.
WSEO analyzed the possible benefits of the third case, that is, where the electric utility or an independent
power producer builds a baseload plant. Under this example, the gas utility and power producer agree
that the LDC may use the pipeline capacity for up to 30 days per year to meet its peak load.
i
Although the power producer may have other options besides running the plant during those 30 days (for
example, load management or scheduled maintenance, WSEO made the conservative assumption that the
power producer would be required to find and run alternative fuel for the thirty days that pipeline
capacity was not available. 16
16 This analysis assumes that the producer can meet environmental and other limitations to using oil as
a backup fuel.
D-R8-O1 W6 4-13
For the power plant operator to return pipeline capacity to the gas utility for thirty days a year, the power
plant would need up to thirty days of oil storage capacity. Oil storage costs about $3,00 per barrel-year,
or $0.50 per MMBtu-year. Thirty days of oil storage capacity would therefore cost $15.00 per MMBtu-
day. New pipeline capacity costs roughly $1,000 per MMBtu/day. This is equivalent to an annual
payment of $67.22 for 20 years. 17 The difference between the annual cost of pipeline capacity and the
annual cost of oil storage capacity is therefore $657.22 - $15.00 = $52.22 per MMBtu-day. The lower
cost of oil storage capacity would allow the power plant operator to pay more for fuel oil than for gas and
still come out ahead as long as the price difference between fuel oil and natural gas was less than
$52.22/30 = $1.74/MMBtu. From 1970 to 1990, the price of natural gas and oil were virtually the same.
Currently, oil is slightly less expensive than natural gas. Such an arrangement therefore appears cost
effective based on historic and current cost differentials.
Joint Trenching
The base cases for the three new single family house cases assumed that electric and gas services would
be installed using joint trenching. According to WNG, trenching costs represent about 60 percent of the
costs of laying gas main. The sensitivity analysis that doubles the cost of gas main extension (see Table
23) would therefore represent a conservative estimate of the additional cost incurred if joint trenching did t
not occur (that is, if WNG had separately dug and laid pipe to the development). The present value
difference between the base cases and the case that doubled extension costs is in all cases $900,000, the
assumed cost of extending or upgrading natural gas to 1,000 residences.
Table 28
Savings Associated with Minimizing Distribution Costs
Base Cost Higher Difference
Differential Distrib cost f
Differential
1,000 Large houses $4,208,110 $3,308,110 $900,000
1,000 Small houses $1,008,110 $108,110 $900.000
1,000 Old houses $7,070,110 $6,170,110 $900,000
This simplistic, but arguably conservative, analysis, demonstrates that there may be significant savings
associated with joint trenching of electric and gas services. Table 27 above contains a calculation of the
number of miles of gas main that can be cost-effectively extended using different assumptions about the t
cost per foot of main. Joint trenching, by reducing the cost per foot of main, would make longer
extensions of main cost effective from a societal perspective.
i
c
17 1
In constant dollars using a 3 percent real discount rate.
D-R8-O1 W6 4-14
Conclusions
On the basis of its analysis, the group drew the following conclusions:
• First, it appears that under a range of situations in the working group's service territories, from a
societal perspective, natural gas is more cost-effective than electricity for single family residential
space and water heating. However, while these potential cost savings are significant, they may
represent a small fraction of overall societal energy costs.
• Second, there are probably some circumstances in these service territories where heating with
electricity is more cost-effective than with natural gas. These may include the multifamily residential
sector and, under certain assumptions, small single family homes. Relative cost-effectiveness may
> vary with assumptions about distance from existing gas main, cost of gas, and other factors.
Therefore, consumer choices should not be unduly constrained or influenced in the'direction of one
fuel over another.
• Third, there would be cost savings associated with increased joint trenching of electricity and natural
gas distribution services.
• Fourth, increased coordination of natural gas pipeline contracts between electric and gas utilities
present opportunities for cost savings.
On the basis of these conclusions, the group decided to examine to what extent the marketplace is
currently reflecting societal costs and benefits of fuel alternatives. To the extent it is not, the group
wanted to identify whether there are barriers to choice that are causing inefficient behavior. An
implementation plan could then be developed to address these barriers appropriately. The group agreed
to approach the development of an implementation plan with caution, in order to avoid tilting the playing
field in favor of a fuel choice that is not clearly preferable in all circumstances. The group also decided
to examine whether there are barriers to increased joint trenching and expanded coordination of pipeline
capacity contracting.
D-R8-01 W6 4-15
Chapter Five
Barriers
To recap the conclusions from the preceding chapter, the working group concluded the following:
• Consumers should have the opportunity to have a choice of fuels available, in order to facilitate cost
effective energy resource decisions.
• Cost effective opportunities for greater cooperative use of natural gas pipeline capacity may exist.
• Opportunities for increased joint trenching would result in efficiencies and indirectly increase
availability of natural gas.
The group then proceeded to examine whether there currently are barriers to these opportunities, and, if
so, whether utility action is desirable. The barriers analysis was not scientific or rigorous, but was for the
most part based on knowledge and information held by individual working group members or their
colleagues.
Choice of Fuels
Natural gas saturation for residences in WNG's service territory is about 50 percent. However, in the
single family residential sector, where gas is available, penetration in new construction is well over 90
percent. This overwhelming bias in favor of natural gas for new single family homes appears generally
to be justified both from a societal perspective and from an individual customer perspective, as we will
show.
From a societal perspective, the previous chapter shows that for single family residences, where gas is a
reasonable distance, natural gas is a less expensive fuel option than electricity under a range of scenarios.
Of the limited sensitivity analyses that we performed, only the small home with high distribution costs
and no savings in electrical distribution costs for a gas home gave electricity a cost advantage.
WSEO performed an analysis of one of the single family home cases that looked at the individual
customer's perspective: that is, would the customer's investment in natural gas service be justified by
savings in energy bills, and if so, how much? WSEO calculated the difference in total energy bills for
1,000 large houses using Puget's and WNG's residential tariffs and calculated the service extension
charges for gas and electric service.
Table 29 shows the total energy bills for a single large house. WSEO calculated electric bills at Puget's
residential rate of $5.00 per month plus $0.047882 per kWh for the first 600 kWh per month and
$0.05596 per kWh over 600 in April through September and $0.061509 per kWh over 600 in October
through March18. WSEO calculated gas bills at WNG's residential rate of $4.00 per month plus
$0.47746 per therm.
18 These rates reflect the BPA residential exchange credit of.63 cents per kWh, applied equally to all
kWh sold.
D-R8-01 W6 5-1
TABLE 29
ENERGY BILLS FOR LARGE HOUSE PROTOTYPE
All Electric House Gas Heated House
Electric Electric Bill Electric Electric Bill Gas Load, Gas Bill
Load, kWh Load, kWh Therms
Jan. 2,984 $180.37 675 $38.34 147.4 $74.38
Feb. 2,289 $137.61 640 $36.19 108.5 $55.80
Mar 2,121 $127.29 600 $33.73 101.1 $52.27
Apr. 1,538 $86.21 575 $32.53 68.2 $36.56
May 1,198 $67.21 560 $31.81 44.6 $25.29
June 853 $47.86 525 $30.14 22.6 $14.79
Jul 818 $45.92 525 $30.14 20.3 $13.69
Aug. 835 $46.88 545 $31.10 19.0 $13.07
Sep. 946 $53.08 580 $32.77 25.5 $16.18
Oct. 1,400 $82.91 585 $33.01 57.8 $31.60
Nov. 2,045 $122.61 645 $36.50 93.4 $48.59
Dec. 2,879 $173.91 660 $37.42 141.6 $71.61
Total 1990 $1171.86 7,115 $403.68 850.0 $453.84
r
The present value of nineteen years of bill savings from gas heat is $4,502 with a 3 percent social
discount rate. However, consumers are likely to value future bill savings using a higher discount rate. At
an 8 percent discount rate, the present value is $3,019. The customer therefore sees a present value of
$3,019 in energy bill savings by having natural gas versus electric space and water heat. Presumably,
therefore, the customer would be willing to invest up to that amount towards getting natural gas installed
in their homes.
The service extension tariffs for both Puget and WNG include charges based on feet of line or pipe (see
chapter three). WSEO drew up a simple subdivision plan of 1000 lots averaging slightly less than 1/4
r
acre, including road easements, located in one-and-a-half quarter-sections (240 acres). Puget's applicable
tariffs, Schedules 85 and 86, charge $12.71 per foot for distribution plus $123 per house for service
connections. The hypothetical development contains 55,440 feet of road centerlines. With 1,000 service
drops, the total charge would be $827,642.40. However, Puget provides an allowance of $1,478 against t
this for each new house connected in the development during the first five years. If all 1,000 houses are
built, this credit more than covers the charge, and Puget would not charge for new distribution for this
development.
i
WNG also has two charges. Schedule 7 provides a cost for individual service lines of over 60 feet in
length where gas is available. Rule 7 specifies that main extensions are free to a single or group applicant
as long as the cost is less than five times the difference between estimated annual bills and estimated
average cost of gas. The customer or customers must pay any costs in excess of this limit, with part or
all of these costs being rebated if other customers later connect to the same line within five years.
WNG's 1993 Least Cost Plan indicates an average cost of gas of $0.279 per therm. For the 850 therms
consumed by the prototypical large house, the average cost of gas is $237.15, which is $216.69 less than
the annual bill of $453.84. The allowance for mains is five times this, or $1,083.45.
D-R8-01W6 5-2
The development requires 50,160 feet of new distribution line. Using the cost of $6.11 per foot which
WNG reported for a recent development using joint trenching, the cost for distribution within the
development would be $306,478. With 1,000 houses in the development, the tariff would require WNG
to pay for the entire cost within the development, plus an additional $700,000 to extend main to the
development. Therefore, these customers would have access to natural gas at no additional cost to them.
If home buyers were willing to pay up to the value they place on future bill savings to have gas heat, they
would spend up to an additional $3.0 million (that is, $3,019 per customer) to extend service to the
development, for a total of $3.7 million. 19 This is somewhat less than the $4.2 million in social cost
saving that could be cost effectively spent on main extensions from a social perspective.
While the bill savings a customer will see from gas heat are less than the social cost savings, the
incentive provided by bill savings and line extension policies do not appear to diverge too far from social
cost when an entire new development is involved.
What accounts for the difference between the 90 percent penetration of natural gas for single family
i residences where natural gas is available, and the 50 percent penetration of natural gas overall to the
residential sector? There are a number of factors. We will discuss several: lack of availability, first cost
considerations, split incentives, lack of access to information, codes and standards, and electric
conservation programs.
Lack of availability of natural gas
A number of factors govern availability of natural gas. Natural gas service is only extended when
someone is willing to pay to extend it. This decision is made by the utility itself, by a builder or
developer, or by individual customers. Ultimately, the decision is based on cost. As our analysis shows
in chapter four, there are situations where it is not in society's interest to install natural gas in residences.
In these cases, the cost barriers to natural gas are appropriate, and any changes that altered the cost
signals without altering the societal cost/benefit results would induce uneconomic behavior. For
example, WSEO performed an analysis comparing energy bills that customers pay in the multifamily
sector, with societal values for heating with electricity versus natural gas in that sector.
WSEO calculated annual gas and electricity bills for each apartment in its hypothetical 12-plex at Puget's
and WNG's residential rates. For the all electric apartment, annual bills for consumption of
approximately 12,000 kWh would be $694.77. For the gas heated apartment, the electric bill for
consumption of about 7100 kWh would be $403.68, and the gas bill for consumption of 68.1 therms
would be $250.20. The gas heated apartment would have total annual energy bills $40.89 lower than the
apartment with electric heat. However, the gas heated building is more expensive and would have higher
rents. An apartment owner requiring an 8 percent real rate of return and recovering the investment over,
40 years would charge at least $100 per year more in rents for the gas heated apartment.. Even ignoring
any charges for gas mains and service lines, the ultimate consumers would pay more to live in the gas
heated apartment than the electrically heated apartment. This is consistent with the conclusion in
WSEO's analysis of societal costs that providing these apartments with natural gas space and water
heating is costlier than with electricity.
19 At $14 a foot, this would pay for about 50 miles of main.
D-R8-Ol W6 5-3
On the other hand, there may be situations where current policies and laws increase or skew costs in ways
that deviate from the societal perspective examined in chapter four. In some cases these policies and
laws are fully justified for other reasons. In others, they may create barriers that should at least be
reexamined and possibly removed. Two of these may be current natural gas main extension policies for
WNG, and Internal Revenue Code provisions regarding taxation of main extension contributions.
Main extension policy
There are a number of features of current main extension policy that have significant impacts on both the '
utility's and individual customers' decisions to invest in main extensions.
As discussed in chapter three, WNG must invest in main extensions when the cost is less than five times
annual margin from bona fide applicants. WNG also has the option to invest more if it is willing to take
on the risk; WNG's current policy is that it will only invest when it believes the costs will be offset by
revenues from existing buildings on the proposed route who are likely to hook up within the next three to !
five years. It will not build to serve future load growth other than from existing buildings. WSEO,
however, based its cost effectiveness analysis on a twenty year planning horizon, and assumed that load
growth will materialize. In addition, WNG's line extension tariff requires that there be at least one bona
fide applicant for service. Even in a situation where WNG might have the opportunity to extend main,
and its capital investment analysis shows that such extension would be prudent, WNG cannot make the
investment if there are no bona fide applicants for service.
Furthermore, Rule 7 contains disincentives for a customer to take on the risk of extending main to serve
the needs of potential future customers. If the customer's decision to invest in the main is partly justified
by hopes that additional new customers will hook up, the customer must assume that risk entirely;
moreover, the hookup must occur within five years for there to be any refund at all--and the refund
diminishes the longer the customer has to wait. Furthermore, if the customer who finally takes the risk is
not located at the end of a street, he or she will never recoup revenues from subsequent customers who
are located further down along the street. It is therefore not likely that the customer will make a decision
based on the twenty-year planning horizon that WSEO employed in its analysis.
The Rule 7 mechanism can also increase overall costs and create inefficiencies. WNG reports that in
several neighborhoods developers have installed electric space heat, only to have some subsequent
customers demand to be switched to gas. It is the rare customer, however, who can organize an entire
neighborhood to make the switch.20 Therefore, the gas utility may have to return several times to the
same neighborhood to dig up the street and extend the main to only one or two additional customers.
The cost difference per home of having the utility hook up an entire neighborhood all at once, versus
having to come out several times, can be as much as 300 percent, according to WNG. The first cost
problem discussed below is exacerbated in a situation where the cost to extend a main is triple what they
would have been had the utility planned and developed its distribution system to account for long-term
growth needs.
r
20 Even if the customer were able to organize such a group, it might cost more than simply waiting for
another customer to hook up. Once a main is in front of the house, extensions are free. Furthermore,
potential customers may resist the idea of sharing equally in extension costs, when one customer is closer r
to an existing main than another.
D-R8-01 W6 5-4
Internal Revenue Code
The Internal Revenue Code provision described in chapter three, that counts consumer contributions
towards main as income, increases the cost of mains by requiring the utility to collect from the new
customer, or from others, not only the cost of the main but also the taxes that the utility will have to pay
on that contribution. Costs might be reduced by having customers pay for mains themselves; however,
most utilities do not want to take on the risk of having individual customers owning and maintaining
significant portions of the gas company's distribution system.
First cost considerations
In addition to the situations described above, there is the additional impact of first cost. The investment
decisions prompted by Rule 7 require WNG to ignore most of the value of any main extension that
occurs after the first five years or so, even though the main has a lifetime of well over 20 years. Thus,
WNG's ratepayers do not have the costs of investments spread over a large number of years, as they do
other capital investments such as storage facilities or pipeline. Rather, they pay for these costs up front.
The problem this creates is familiar to anyone who reads the literature on utility-sponsored DSM
programs. There is evidence that energy consumers are very first-cost conscious. When faced with a
choice between two energy options with the same net present value, they may be more likely to pick the
option with the lower first cost. The reasons for this are generally laid to lack of access to capital, lack of
information, and market imperfections.
In a growing system and in the long run, the net present value to utility customers of paying individually
for new main extensions versus having the cost spread to all customers should be about the same.
However, because of the first-cost consciousness of utility customers, many customers would pick an
energy option with lower first cost over an option with higher first cost, even if the net present value of
ultimate energy costs were somewhat lower for the second option.
All new customers require electricity. Puget's line extension tariff does not require customers to pay
more for line extensions when they are going to use more power. Therefore, if customers choose gas
space and water heat, they must pay more for access to utility service than if they choose electric space
and water heat, because they have to pay both for electric service and gas service. This may cause
prospective customers who are not directly in front of an existing main to prefer electricity over natural
gas for space and water heat, in order to reduce first costs. The cost of installing a gas, furnace with all
the necessary ductwork and exhaust system is also first-cost intensive, if the comparison is to an existing
home or a new home with electric zoned heat. The fact that natural gas appliances usually cost more than
electric appliances only exacerbates the first cost problem.
Split incentives
A related issue is the fact that the person making the investment decision may not be the person paying
the bills. This is the case when professional developers undertake new development for later resale or
lease to the residential or commercial customer. Here, the developers' only cost signal is to minimize
first cost, since they will generally not be responsible for utility bills. The only motive the developers
have to install the utility service with natural gas's higher first cost is to respond to consumer demand for
gas utility services. That is, they will only install natural gas when they can be sure that the home buyers
1 or renters are willing to pay the extra costs. In the Northwest this demand does exist to some extent in
the single family residential market, overwhelmingly so where gas is available; but the multifamily and
mobile homes seem more inclined to take advantage of the landlord's or developer's ability to pass along
the lower first cost of electricity.
D-R8-01 W6 5-5
Lack of access to information
Consumers may not have access to adequate information about the cost, environmental, safety,-and other
differences between natural gas and electricity. Developers and builders may not have access to
information about technologies, particularly new gas appliance technologies and applications.
Codes and standards for installation
As a rule, code provisions for natural gas installation are more stringent than for electric service. In most
cases safety concerns fully justify these requirements and the associated cost. However, there are
circumstances when the application of codes can add to the cost of a job without providing added benefit.
To the extent that these circumstances can be identified and corrected, the cost of installing natural gas
can be kept at a minimum. The following paragraphs will provide several examples illustrating how
codes may add to the cost of installations.
It is important to understand that codes do not necessarily provide exact specifications for installation.
Codes are a set of guidelines. How a specific installation is accomplished is the outcome of
interpretations made by the installing contractor with the approval of the local building inspector. Under
most circumstances, particular types of installations are performed repeatedly. The building inspector
consistently interprets the code in a particular fashion, and a standard practice for installation is
established. Contractors, knowing exactly what is expected, will then bid competitively on these
projects. For example, the standard practice for installing a natural gas forced air furnace and a natural
gas water heater in new homes is well established. This is a very competitive market.
New applications, new technologies, and new code language can make the business of installing natural
gas equipment more expensive. If there is not a clear set of well established standards for a particular
application, contractors will submit bids which cover the additional cost of uncertainty. This does not
necessarily mean that the market is not competitive, but it raises the overall price. For example, in
Washington State there has been little activity installing natural gas in apartments. Because of this, the
installation standards are not well established. Contractors' bids for this type of project will initially be
high to cover the cost of uncertainty. This makes market introduction in new applications more costly
and perhaps less likely. ;
1
In addition, contractors are also faced with uncertainty when working in numerous jurisdictions. What is {
acceptable in one jurisdiction may not be in another. In well established markets, like new single family r
construction, this is less likely to occur. But in new or more difficult applications, the cost associated
with uncertainty are likely to have at least some additional impact.
New types of equipment sometimes have difficulty entering new markets because of code interpretations.
When combination space and water heating systems were originally introduced in Seattle, the building
department, lacking specific code language for this product, chose to apply the standards required for hot
water boilers. These standards were excessive, and added cost to the product. The equipment could l
more accurately be regulated by the standards for domestic water heaters. i
Poorly planned inspections can also add to the cost of installation. For example, some local jurisdictions
require that the contractor be present when the natural gas piping is pressure tested. Contractors have
noted that inspectors are not able to give accurate schedules for inspections. Contractors have
complained that they may have to spend additional time on a jobsite simply waiting for inspection.
rD-R8-O1 W6 5-6
Of course, permits specific to natural gas add to the cost of the installation. If these cost exceed the
administrative cost of a particular installation, they are not fully justifiable and compound the first cost
problem.
To facilitate the introduction of new or difficult natural gas installations, institutional support for new
installation standards is frequently provided by the American Gas Association (AGA) and/or local gas
utilities. The support they provide can help limit the uncertainty associated with new applications and
subsequently limit cost. AGA and local gas utilities frequently have staff which provide educational
support, limited engineering services, and expertise in code interpretation. Some utilities even finance
demonstration projects. The limitation of this approach is that code officials sometimes see these
institutions as "pro-gas," and are suspect of their implementation strategies.
Electric conservation programs
Electric utility conservation programs often provide incentives to install measures that the customer
would not otherwise have installed. These programs are justified from an electric utility and customer
perspective because they reduce overall energy costs to serve the customer. However, from a total energy
perspective these measures may not be cheaper nor save as much energy as installing natural gas space
and water heat.21 A customer may choose an electrically heated home if the program narrows the first
cost gap between a natural gas-heated home and an efficient electrically heated home, or if it narrows or
reverses the lifetime cost gap between electrically heated homes and natural gas-heated homes.
Pipeline sharing opportunities
The working group believes that there are no significant barriers to pursuing additional opportunities for
pipeline capacity sharing. While few such relationships currently exist, many are now being developed
and pursued. The cost of electric generation largely internalizes the benefits of these transactions.
The group did identify two possible existing barriers to further development.
Electric utilities are only now coming to understand the nature and extent of natural gas markets, costs,
and opportunities. In the last several years, knowledge and market power have been held largely by
independent power producers and marketed to electric utilities. Utilities may have paid a premium to
IPPs to assume the risk of natural gas uncertainty. As electric utilities become more knowledgeable, they
may be able to assume some of that risk themselves and be willing to enter into the natural gas pipeline
and commodity market.
On some occasions, regulatory structures may make it difficult for regulators to consider the overall
benefits and cost of joint gas-utility pipeline capacity sharing arrangements. Generally, the regulator
looks at each utility transaction in a separate proceeding. For example, the WUTC considered the
Cascade Natural Gas-Tenaska-Puget arrangement, described in chapter three, twice: once in the context
of the rate Tenaska would pay Cascade for natural gas distribution service, and once in the context of the
J rate Puget would pay Tenaska for electricity. A joint proceeding might have been able to highlight some
of the unique regional benefits of the coordinated transaction, as well as saved in attorney and staff costs.
21 Northwest Power Planning Council 1994 compared the cost of weatherizing homes to the cost of
converting and found that the cost of converting was lower than the average cost of weatherization.
However, for conversions from electric zoned heat to natural gas, the costs were about the same. The
NWPPC has decided as a policy matter to treat fuel conversions as a potential resource to be compared
with other electric resources such as demand side measures.
D-R8-01 W6 5-7
Joint trenching
The group found that joint trenching does occur between electric and gas utilities in two types of
situations. First, when there is a new development, the developer generally provides for joint trenching
of all utility services. The developer works out the timing and logistics of the trenching with all of the
utilities. Second, utilities meet regularly to discuss upcoming projects. If one utility needs to upgrade,
expand or replace service, other utilities have the opportunity to take advantage of the open trench to
expand or upgrade their service.
However, joint trenching between the working group electric utilities and Washington Natural Gas is not
yet being pursued at an optimal level. This is for at least three reasons.
First, WNG's line extension policy requires a bona fide applicant before WNG can extend mains.
Therefore, even if Puget or SCL has a trench open, and the Capital Investment Analysis (CIA) justifies
extending service, WNG cannot extend service without having a customer present.
Second, coordination of long term trenching plans among utilities is in its infancy. Therefore, utilities do
not comprehensively consider mutual needs in developing capital budget programs. The utilities do not
comprehensively share information on distribution systems and long term needs for enhancements, i
extensions and upgrades. Barriers to better coordination might include a reluctance of utilities to share
information about their customer bases, since, these electric and gas utilities are traditional competitors r
for the same load.
Third, counties and municipalities do not coordinate long term infrastructure improvements with utilities.
Better coordination with governmental bodies could reduce costs to taxpayers and utility customers and
minimize disruption and aesthetic impacts of trenching and infrastructure improvements. Barriers to
such coordination might include strained capital of municipalities, so that municipalities have to time
infrastructure improvements to meet their own needs, and not the needs of the utility. {
t.
r
t
r
r
r
i
D-R8-01 W6 5-8
t
Chapter Six
Implementation Plan
On the basis of its cost/benefit analysis, as well as its review of the barriers that currently exist to
implementing cost effective opportunities, the group developed an implementation plan consisting of five
broad recommended strategies. Each strategy contains one or more recommended action items. The
implementation plan focuses on three goals:
• broadening choice,
• making information available, and
• removing inefficiencies in energy service delivery.
The group believes that these goals and strategies will go a long way towards taking advantage of cost
1 effective opportunities, without requiring additional, potentially cumbersome and controversial
interventions in the marketplace.
In addition to the five recommended implementation strategies and recommended action items, the group
i developed a list of four additional strategies that could be considered in the future but are not
recommended at this time.
f Recommended Strategies
1. Develop educational programs so that customers, developers, and
the building trades would have information available concerning
fuel options.
Working group members believe that impediments to optimal fuel choice alternatives may be overcome
through education, both for end use consumers and for the building trade. The group recommends:
• Have utilities develop jointly sponsored information on relative fuel costs and other issues. Utilities
could also jointly provide additional information on equipment and fuel efficiency. The utilities
could provide this information in a number of ways: as part of a DSM program, in response to
consumer inquiries, in an educational program, etc. In addition to potentially enhancing efficiency
and consumer choice, such a program could have the effect of increasing customers' satisfaction with
the energy services available to them. (The program should be coordinated with the state-sponsored
program described in the next bullet to ensure consistence of information.)
f Include information on fuel alternatives as part of a state-sponsored energy information program.
This information would be fuel neutral and include all end use fuels such as propane, wood, and oil.
The program would provide information on first costs, lifetime costs, cost risks, safety issues,
technologies, etc. The program could also be segmented to target different sectors. For example, one
outreach effort would be targeted to end use consumers, and another to the-building trades.
D-R&O1 W6 6-1
2. Revise code and permitting provisions and improve their
implementation to minimize their impact on fuel choice, unless
justified by considerations of safety and health.
A number of actions could be taken to limit the financial impact codes and permit requirements,have on
the installations of natural gas equipment, without adversely affecting health, safety or energy
conservation standards. These have the potential most strongly to affect the multifamily sector. As
noted in chapter four, WSEO's analysis showed that fuel costs of serving the units developed in its case
with natural gas are lower than serving them with electricity. However, the equipment costs more than
offset these savings. Efforts to reduce equipment costs might have the beneficial effect of reducing
overall costs to the extent that the fuel saving opportunities for this sector could be realized.
The following comments were not gathered specifically for the purpose of this report. They are a
summary of suggestions WSEO staff and other working group members have had the opportunity to
gather while working in the field. A more rigorous examination of codes and code implementation
strategies would probably yield a more complete list of implementation actions.
• Provide institutional support in the development of new applications or when new equipment is
introduced. As noted in chapter five, codes do not provide specific solutions for all installations. If
clear installation instructions can be developed and delivered, new installation practices can be more
easily and uniformly implemented. Institutional support may be provided by gas utilities, and/or
government agencies. Funding sources will need to be identified.
An excellent example of institutional support can be taken from the Wisconsin Blue Flame Council.
Member utilities wanted to introduce the use of copper tubing for interior gas piping. Utilities
realized that obtaining code approval was only the beginning. In addition, the utility financed the
development of in depth instructions for installation, education programs for contractors and code
officials, and a demonstration project.
i
In Washington State institutional support may be useful in limiting the barriers facing the use of
natural gas in new multi-family housing. Developing detailed implementation strategies for venting,
combustion air, and gas piping could reduce the cost of installing natural gas equipment in this
application. There may also be opportunities in other areas.
r
• Review permit fees for the installation of equipment. Suggest limiting the cost of permits to the
actual cost of administration of the code, not on the size of equipment or unrelated factors.
• Centralize the permitting process (one-stop permitting) so that all permits (electrical, mechanical,
plumbing and gas piping may be obtained at once.
• Allow licensed contractors, designers, and installers to obtain permits electronically.
• Review possible revisions to the inspection process. Contractors have described the inspection
process to be troublesome in some jurisdictions. One example is the requirement that contractors be
present for fuel piping pressure test.
D-R8-O1 W6 6-2
i
The Uniform Mechanical Code requires that new installations of natural gas piping be pressure tested
"in the presence of the building official." The installing contractor is responsible for setting up this
test, and in many jurisdictions, must be present during the test. Some contractors have argued that
the requirement that they be present during the test may add an unnecessary and unpredictable cost to
the installation.
Contractors would like to see the gas piping inspection process streamlined. Recommendations have
included: self certified inspection by licensed contractors, utility staff certified as third party
inspectors, home owners as third party inspectors, or building official administered test.
Other opportunities to streamline the inspection process may also exist.
• Facilitate uniform implementation of codes from one jurisdiction to another. This is particularly
important when instituting new practices. If standards for installation and inspection can be
uniformly applied from one jurisdiction to another, contractors will be able to reduce the cost
associated with uncertainty. This approach has been tried with limited success in Pierce County.
Evaluation of the successes and failures of their process may provide some guidance.
• Facilitate reasonable changes in code requirements. Two examples follow:
Amend the Uniform Mechanical Code to allow the use of copper tubing for interior natural gas
piping. Copper tubing is thought to be the lowest cost alternative for complex piping systems,
typical in apartments and commercial structures. WSEO staff have reviewed the technical
specification developed in other parts of the country. There do not seem to be any technical barriers.
Amending the Uniform Mechanical Code to allow for the use of copper tubing will take some time
because the schedule governing amendments is limiting.
Eliminate the Washington State Energy Code (WSEC) requirement limiting the capacity output for
natural gas equipment. WSEC requires that installed heating systems capacity be limited to not more
than 150 percent of the design heat load of the structure. Contractors are sometimes required to
perform design heat loss calculations of the structure before they install new equipment. The
equipment is then checked during inspection to see that it meets this requirement. Besides adding to
the cost of the home, it may be difficult in some cases to find a furnace that meets the requirement,
especially for a small residence. Further, this requirement provides little in the way of benefits for
the natural gas system. It is primarily targeted to limit peak loads of electric utilities. However, due
to the flexibility of pipeline operation, the peak load benefit to the gas system of the sizing limitation
is less important.
3. Revise natural gas main extension tariffs.
As noted above in chapters three and six, Washington Natural Gas's main extension tariffs, and their
application by WNG, contain features that may impede both the efficiency and the fuel choice goals of
this project. The working group recommends that both the main extension tariff (Schedule 7) and Rule 7
be amended to eliminate these features, and that the company implement practices regarding main
extension investments that would further the goals of choice and efficiency. The working group
recommends that these alternatives be explored in the upcoming tariff filing referred to in chapter three,
and offers to assist WNG and parties in discussing and developing alternatives. The group recommends
the following changes:
D-R8-01 W6 6-3
• Eliminate the requirement that a "bona fide applicant" exist before WNG can extend mains. This
provision of the tariff makes it currently impossible for the utility to lay gas main even when the
electric utility has opened a trench to lay new underground electric cable or replace existing cable. It
also creates inefficiencies because the utility must return several times to extend service piecemeal to
individual converting customers in an existing neighborhood.
• Alter the Capital Investment Analysis policy so that the reasonableness of WNG's investment in
mains is based on long-term benefits that are consistent with WNG's obligations under the least cost
planning rule. The working group suggests two alternative mechanisms to achieve this result. The
first would involve prescribing explicit CIA rules in the tariff. Alternatively, the language regarding
"additional investments" could be eliminated altogether and the utility and regulator could apply
traditional prudence tests to determine the reasonableness of WNG's choice to extend mains. This is
the current practice for electric utilities, as noted above in chapter three.
• Amend Rule 7 so that new customers have more time to hook up and reimburse the customer who
originally financed the cost of the main. There is evidence that the current five year threshold is too
short to give financing customers enough incentive to undertake the risk that new customers will
reimburse them for their costs.
• In order to reduce the possibility that the WUTC find a particular main or electric distribution
extension investment imprudent in a future rate proceeding, WNG and Puget should consult with
WUTC staff and be prepared to document the reasonableness of their investment decisions. A
number of factors could support the reasonableness of an investment decision. For example, where a
city or county's Comprehensive Plan identifies an area as an urban growth area, the utilities could
rely on the Comprehensive Plan, together with documentation of their discussions with cities and
counties, as evidence of the reasonableness of their investment to extend or upgrade mains or
distribution lines to meet the anticipated growth. In some cases, such as the City of Seattle's
proposed Commons project, a city might actively encourage extension of utility service to meet
anticipated growth needs. Utilities should document any such encouragement. Discussions with
WUTC staff in advance of the investment decision would be helpful both to the WUTC staff and the
utilities in order to head off possible misunderstandings.
4. Coordinate distribution and infrastructure planning among utilities,
municipalities, and counties.
Currently, communication and planning among utilities and city and county planners are reactive rather
than proactive. Opportunities for cost savings may be lost when a city expands or repairs streets and
other infrastructure, and does not coordinate with utilities. Likewise, if utilities can share long term
expansion and repair plans with each other, they can alter and develop construction budgets to minimize
trenching and other construction disruptions. Greater coordination would help to achieve the goals of
making choice more broadly available (by minimizing the cost of service) and eliminating inefficiencies.
(Note that, for natural gas to be more widely available, this strategy might have to.be combined with
strategy number 3 regarding line extension reform.)
i
D-R8-01 W6 6-4
The group recommends the following action items to pursue this strategy:
• Utilities, cities, and counties should share long-term construction plans and budgets.
• Utilities should review and comment on Comprehensive Plans, as well as zoning, regulatory, and
code changes developed to implement the Plans. The Working Group utilities are currently active in
development of and commenting on Comprehensive Plans. GMA requires each Comprehensive Plan
to contain a utilities element that shows where utilities are going to locate future services. However,
many planners do not regard need for efficient delivery of energy services as a major criterion for
developing all elements of the plan, and hence do not seek input from utilities on how they can
coordinate the various elements of the comprehensive plan with utility needs in order to minimize
overall energy costs.
One possible solution is to identify the need for energy services as "essential public facilities," under
R.C.W. 36.70A.200. A report prepared by the Puget Sound area electric utilities recommended that
city and county planners so designate electric facilities (Puget Sound Electric Utilities Task Force
1992). The working group echoes this recommendation but would expand the recommendation to
include all energy services. The working group members recommend that utility participation be
encouraged in developing not only the utility element of the Plan and its associated regulations and
codes, but other elements as well, so that optimal energy decisions can be made.
• Utility representatives, city and county planners should begin developing planning groups or forums
that would meet regularly to develop coordinated long-term utility and infrastructure improvement
plans. (Currently, utilities meet regularly to discuss upcoming trenching and other repair and
enhancement projects. However, they do not coordinate long term planning, nor are cities and
counties regularly involved. The type of action recommended here could be undertaken by the same
group that currently meets, or by a new group.)
• Utilities should work with city and county planners to develop policies that enhance fuel choice
options. For example, the city or county could create incentives for developers to make gas main
available to new developments, whether or not the initial heating source is natural gas. This policy
would eliminate the need to return on a case-by-case basis to install natural gas to individual homes
seeking to convert.
• Work with the city to develop long-term capital budgeting plans that accommodate improvement
needs of the utilities that serve its residents.
In addition to the recommended action items discussed above, the group believes the following actions
should be considered for possible future implementation:
• Develop a joint Geographic Information System that overlays utility and municipal systems. The
system could be capable of identifying priorities, time frames for'improvements, growth areas, and
constraints on utility services. There is proposed Federal legislation (H.R. 4394, the "Comprehensive
One-Call Notification Act of 1994") that would require states to establish a comprehensive "one-call"
system to identify utility services could expedite the development of such a system. This system
would gather information about the location of underground facilities, in order to disseminate the
information to potential excavators. Utilities could take advantage of such a system to develop
shared information about existing utility underground systems, so that long term plans for extension,
upgrades, and replacements could be coordinated and prioritized.
D-R&01 % 6-5
• Establish electronic bulletin boards that share planning information through a single phone call.
Again, the one-call system that would be established under the proposed federal legislation might
facilitate or hasten the establishment of a bulletin board system.
5. Continue to monitor developments in electric energy distributed
generation technologies and cost/benefit analysis methodologies,
and coordinate distributed generation planning with the gas, utility.
As transmission and distribution facilities become more difficult and expensive to site, electric utilities
are increasingly interested in exploring so-called distributed generation options. These include such
technologies as fuel cells, photovoltaics, and district heating and cooling potentially coupled with
cogeneration. Some distributed generation alternatives involve the use of natural gas as a fuel source.
However, little attention has been given to the need to coordinate distributed generation evaluation with .
the LDCs or pipelines.
The working group agreed that both Puget and Seattle City Light are still in the early stages of evaluating
distributed generation options for their respective utilities. The group recommends that as these options
are considered, the utilities closely coordinate with Washington Natural Gas and other LDCs, as well as
other fuel sources such as propane, biomass, steam, and oil, to make best use of energy and capacity
availability and needs. The group also recommends that no actions be taken by the state or its regulators
that preclude utilities from taking advantage of the benefits of distributed generation resource options. f
f
Additional strategies to be considered for future
implementation
In addition to the recommended five strategies discussed above, the group considered a number of other
possible strategies and action items. The group is not recommending these at this time. However, the
following should be considered for future implementation.
6. Consider other ways to reduce the first cost of main and distribution
extensions.
One barrier to cost effective fuel choice is the problem of first cost. The working group has identified a t.
number of ways that first costs might be reduced, particularly those described in strategies 2, 3 and 4.
Additional steps might include the following:
• Work with others to change tax laws so that the IRS does not tax contributions in aid of construction
as income to the utility. As discussed in chapters three and six, the Internal Revenue Code currently -
provides that when a customer pays for part of the cost of a new main, the IRS treats the contribution
as income to the utility. The utility's revenue requirement therefore must be "grossed up" to include
the taxes it must pay on this contribution. This provision of the tax code results in higher costs to the
U-R8-O1 W6 6-6
utility and hence its customers. To the extent that the utility collects the taxes from contributing
customers, they exacerbate the first cost problem for new service22. The working group utilities do
not believe that they alone can effect this change to the Internal Revenue Code. However, if access
to fuel choice is considered a national priority, the working group believes it is possible to draw
attention to the disincentives created by this provision of the Code.
• Develop mechanisms for the utility to finance the customer's cost of service installation. In order to
avoid rate payer subsidies that are not justified, the utility could design a financing program to charge
the customer interest at the utility's cost of capital. In many cases, customers can finance the cost of
service through conventional routes and would not benefit from such a program. However, in others,
access to utility financing might make service more affordable.
7. Be alert to conservation programs that have the unintended effect of
promoting one fuel source over another, and design them to avoid
adverse consequences on fuel choice.
The working group members are also concerned that certain "conservation" programs in fact may provide
an incentive to choose one fuel over another. For example, an electric conservation program, by making
electricity less costly, may narrow the gap between electric and natural gas costs. The working group
believes that this is not currently a major problem for the working group utilities. However, it has been a
problem in the past and continues to be identified as a problem elsewhere in the region and the country.
The group therefore recommends being alert to the possibility that a conservation program may have
unintended adverse impacts on fuel choice, and that conservation programs be designed so that they
avoid the potential problem.
8. Consider promoting specific fuels in certain circumstances.
As noted in the chapter on cost/benefit analysis, an action to influence a customer to choose an
alternative fuel has the same impact on the utility as a conservation program. However, the societal cost
should reflect the increased cost of the alternative fuel. To the extent that societal energy costs can be
reduced by choosing an alternative fuel, mechanisms should be considered to facilitate that choice. The
primary means chosen by the working group is to use a combination of reforms that make choice more
easily available, together with the implementation of education programs. However, the group also
suggests considering the following action items:
•
Current programs that provide for public financing of DSM measures could be clarified or redefined
so that it finances fuel choice and fuel substitution for low income customers, for end uses and
sectors where the cost effectiveness of one fuel over another appears reasonably clear.
• Utilities consider jointly encouraging specific alternative fuel choices where intervention with market
choices appears particularly advantageous to both utilities and to society. Utilities would target such
programs to deal with unique resource constraints and to meet specific energy delivery problems.
22 This problem could be addressed by spreading the cost over several years, as Puget does (see chapter
three); or by recovering the cost from all ratepayers.
D-R8-Ol W6 6-7
9. Consider regulatory changes to facilitate consideration of inter-fuel
synergies.
Currently, WUTC regulates each utility and each industry separately. There is no mechanism that allows
for consideration of opportunities that reduce societal costs through cooperation. The group does not
recommend any dramatic change to the existing system at this time. However, it recommends one
relatively minor change for consideration:
• Consider a single review of supply side resources that have implications for both gas and electric
utilities. For example, some of the pipeline capacity sharing scenarios described above in chapter
three would require regulatory approval both for the gas transaction (since it involves a retail sale of
natural gas)-and review of the electric transaction (since it involves purchased power). A "one-stop"
evidentiary proceeding that considered the costs and benefits of the entire transaction would have at
least two benefits: first, it would eliminate multiple proceedings, freeing up Commission, WUTC
staff, utility, and independent participants' time. Second, it would give the Commission the
opportunity to look at the total costs and benefits of the transaction, not costs and benefits that were
artificially isolated into their electric and gas categories.
t
r
t
rr"
D-R8-O1 W6 6-8
Chapter Seven
Next Steps
The working group has developed an ambitious but achievable set of strategies that it believes will help
to achieve the goals of choice, education, and efficiency. This chapter will provide some suggestions on
where to go from here.
Implementation of Plan
The action steps described in chapter six contemplate actions taken by various working group members
and others. In some cases, it is fairly clear who should bear the responsibilities for taking action. For
example, the recommendations concerning amendments to WNG's tariffs should probably be primarily
implemented by WNG, with input and assistance as needed from other working group members. In
others, the responsibility is shared or has not been fully worked out. For example, working group
participants might jointly work on actions to improve code implementation.
Working group members are already working together far more than they did when the Project began.
The Project can take some credit for introducing the working group utilities to each other and for
suggesting ways that the utilities might cooperate and achieve savings. Examples of the ways that the
utility members are already cooperating are the following:
• Shared office building by Puget and WNG in Renton.
• Arrangement between WNG and Puget to accept bill payments for the other utility at any office.
• Joint meter reading pilot program by WNG and SCL.
• Joint delivery of water conservation measures with WNG, Puget, SCL, and Seattle Water Utility.
• Pilot fuel substitution project with WNG and SCL, funded by BPA.
• Exploration of expanded joint trenching opportunities for WNG and Puget.
• Participation in each other's least cost planning technical advisory committees.
The working group utilities believe that these steps and others have demonstrated that utilities are
increasingly willing to look for opportunities to cooperate. For the most part, the action steps described
in the previous section will be the result of individual commitments and efforts. The group agreed,
however, to reconvene the working group in about six months to discuss progress on the implementation
plan.
The results of this Project will be presented to major energy policy stakeholders in the region, including
WUTC and the Northwest Power Planning Council. This report will also be disseminated widely
throughout the state. The Project participants believe that this case study can be used as an example for
others in the state, region, and country to consider.
D-R8-O1 W6 7-1
Impact Analysis
At this early stage it is difficult, if not impossible, to undertake a credible analysis of the possible impact
of the implementation plan. The goals of the plan are to increase choice, to educate the public and
builders about fuel alternatives, and to pursue efficient use of utility resources. Hopefully, the plan will
result in savings for the region, both in dollars and in energy consumption. However, too little is known
about the current status of consumer choice and education to determine what impact these strategies will
have.
We do have sufficient information to develop some reasonable bounds around the impact of the
implementation plan. For example, as discussed more fully in chapters two and six, we know the
following regarding fuel choice:
• Fifty percent of residential homes in WNG's service territory choose natural gas either for space and
water heating, or for both.
• Only about four percent of multifamily homes and percent of manufactured homes in WNG's service
territory choose natural gas.
• About six thousand customers converted from electricity to natural gas for space heat in 1991; about
2,600 customers converted from oil or wood to natural gas in the same year.
• WNG added about 27,000 customers a year to its service territory in 1993.
• Puget added about 15,000 customers in 1993.
• Blackmon and Aos 1992 used BPA data to estimate that, in the Northwest as a whole, 26 percent of
homes had gas installed, 32 percent were on main, 23 percent were within 1/4 mile of an existing
natural gas main, and 20 percent were more than 1/4 mile away. WNG has compiled no similar data
yet for its service territory.
• Puget has plans to replace about 2,400 miles of existing underground distribution service over the
next several years. Were WNG to take advantage of the open trenches created by Pugefs project to
extend main, WNG could save 60 percent or more of main extension costs. '
i
These data might allow us to develop some hypothetical scenarios involving the possible impact of
measures to increase fuel choice and education, building on the cost/benefit analysis described in chapter
four. The working group agreed to develop some hypotheticals designed to make reasonable estimates of
potential results of the action items recommended in this report. Working group members could use the
results of these estimates for internal planning.
i
D-R8-01 W6 7-2
References
Anderson, R., A. Draper 1992, "Fuel Switching in Integrated Resource Planning: The Method and the
Madness."
Blackmon, G., S. Aos 1992, "Natural Gas End-Use conversion as an Electric Power Resource: An
Estimate of Potential and Cost."
Bloomquist G., J. Nimmons, and K. Rafferty 1988, District Heating Development Guide.
Lawrence Berkeley Laboratories, National Association of Regulatory Utilities Commissioners, "Survey
of State Regulatory Activities on Least Cost Planning for Gas Utilities.
Meyer, Charles E. 1992, letter regarding Bonneville Power Administration policy on fuel choice/fuel
substitution programs.
Northwest Power Planning Council 1993, "Staff Issue Paper: Natural Gas Supply and Price."
Northwest Power Planning Council 1994, "Draft Staff Issue Paper: Direct Use of Natural Gas: Analysis
and Policy Options."
Oregon Department of Energy/Oregon Public Utilities Commission Staff 1991, "ODOE/OPUC Fuel
Switching Analysis: Observations and Policy Implications."
Puget Sound Power and Light Company 1992, Integrated Resource Plan 1992-1993.
Puget Sound Electric Utilities Task Force 1992, "Regional GMA Inter-Utility Report."
Ross, D. and R. Byers 1993, Puget Sound Fuel Blind Integrated Resource Planning Project Report #1:
Description of Working Group Members; Identification of System Interaction.
Ross, D. and R. Byers 1994, Puget Sound Power and Light's Periodic Rate Adjustment Mechanism:
History and Selected Issues.
Ross, D. 1994, "Emerging Utility Approaches: Open Door for Expanded DHC Development."
Seattle City Light 1992, Energy Resources Strategy.
Snohomish County Public Utilities District 1991, "Cooperative Fuel Switching: A Joint Pilot Project
Involving Independent Electric and Gas Utilities."
Washington Energy Strategy Committee 1993, Washington's Energy Strategy: An Invitation to Action.
Washington Natural Gas 1993, Least Cost Plan.
Washington Water Power 1991, 1991 Switch Saver Test Program Impact Evaluation Report."
D-R8-O1 W6 R-1
Appendix A
Previous Publications Under Puget Sound
Fuel Blind Integrated Resource Planning
Project
Report #1: Puget Sound Fuel Blind Integrated Resource Planning Project: Description of Working
' Group. Members, Identification of System Interaction, April 1993, WSEO #93-153
Report #2: Puget Sound Power and Light's Periodic Rate Adjustment Mechanism: History and Selected
Issues, January 1994, WSEO #94-012
Report #3: Cost/Benefit Methodology and Preliminary Results, April 1994, WSEO #94-107
To obtain copies of any of these reports or to receive them in alternate format (large print, Braille, or
audio tape), contact:
The Washington State Energy Office
925 Plum St. SE.
P.O. Box 43165
Olympia, WA 98504-3165
(206) 956-2230
TDD: (206) 956-2218
i
D-R8-01 W6 A-1
Appendix B
Opportunities for Cooperation Identified
by Working Group
Fuel Choice/Fuel Substitution
Residential
water heat
space heat
cook/dry
multifamily
manufactured housing
Commercial
water, space heat
cook/dry
space cool
Transportation
electric versus natural gas
Line extension policy
Joint delivery of services
joint billing
meter reading
DSM program operation
Coordinated supply side resource planning
coordinated transmission and distribution planning
distributed generation (fuel cells, district heating)
pipeline capacity sharing
joint trenching
coordinated with local governments
Shared information
Geographic Information Systems
Maps of service territory
D-R8-01 W6 B-1
Appendix C
Fuel Choice and Fuel Substitution
Studies and Analyses Collected in
WSEO Project Library
Anderson, R., A, Draper 1992, "Fuel Switching in Integrated Resource Planning: The Method and the
Madness," ACEEE summer proceedings.
Blackmon, G., S. Aos 1992, "Natural Gas End-Use Conversation as an Electric Power Resource."
Boonin, D. 1992, "End-Use Fuel Switching: Is it Fair? Yes, it is!," Electricity J. June 1992.
Byers, R. 1989, "Analysis of Consumer and Marginal Costs for Electric and Natural Gas Space," WSEO
D-Policy-43.
Chamberlin, J., E. Mayberry 1991, "End-Use Fuel-Switching: Is it Fair?," Electricity J. October 1991.
Chernick, P., E Espenhorst 1990, "Analysis of Residential Fuel Switching as an Electric Conservation
Option, " BRIC Proceedings.
Gamble, J., M. Weedall 1991, "The Politics of Fuel Switching: A Vermont Case Study," ACEEE
proceedings.
Green, M. 1990, "Proposal for Electric to Propane Fuel Switching Program, Chelan PUD."
Hamilton, L., C., Milford, S. Parker 1992, "Fuel Switching Programs in Vermont: Issues and
Experiences," ACEEE proceedings.
Harrel, JKA et al. 1977, "A Comparison of Energy Options Gas or Electricity."
Kaul, J., S. Kihm 1992, "Fuel Switching: Why It Should be Done, Why It Isn't Done, and Ways
Regulators Can Address It," Fourth NARUC IRP Conference Proceedings.
Lazar, Jim undated, "Direct Use of Natural Gas for Residential Space and Water Heat Compared to Gas-
Fired Electric Generation for Hydro-Firming."
Leovy, Steven 1993, Fuel Switching as a DSM Measures--Promise, Problems, Possible Solutions."
Maine Public Utilities Commission 1992, "Order, Development of Proposals for Fuel Switching."
Northwest Power Planning Council 1994, "Draft: Staff Issue Paper: Direct Use of Natural Gas:
Analysis and Policy Options."
D-R&O1 W6 C-1
Oregon Department of Energy/Oregon Public Utilities Commission Staff 1991, "ODOE/OPUC Fuel
Switching Analysis: Observations and Policy Implications."
Pacific Energy Systems 1990, "Coordinated Energy Development in the Pacific Northwest."
Raab, J., R. Cowart 1992, "Fuel Switching in Vermont: Pragmatic Answers to Ideological Issues,"
Fourth NARUC IRP Conference Proceedings.
Snohomish County PUD 1991, "Cooperative Fuel Switching: A Joint Pilot Project Involving
Independent Electric and Gas Utilities."
Tempchin, R., D. White 1993, "The Slippery Slope of Fuel Substitution," Electricity J. July 1993.
Thompson, M., C. Eustic 1992, "Residential Fuel Substitution in Integrated Resource Planning: An
Economic Analysis, " ACEEE Proceedings.
Washington Water Power 1991, "1991 Switch Saver Test Program Impact Evaluation Report (2 vols.)."
Wiel, S., C. Goldman 1994, "End-Use Fuel Substitution: Review of Regulatory Approaches and Key
Policy Issues," Electricity J. March 1994.
D-R8-01 W6 C-2