Washington State Policy Roadmap

Washington State Energy Policy Roadmap
Washington State Energy Policy Roadmap:
Purpose of this document:

The Policy Roadmap will provide a long-term perspective for Distributed Generation (DG) and
Combined Heat and Power (CHP) policies, with detailed actions and milestones for implementing those
policies. The Roadmap will identify current and future policy issues for Washington State based on a
Pathway to a projected DG and CHP Vision.

Understanding the desired end-state for DG and CHP will provide context and a long-term perspective
for policy makers, regulators, legislators, and industry stakeholders. Therefore, the Roadmap will look at
policy initiatives aimed at achieving the Vision Statement.

The Vision Statement on page four and the policy recommendations highlighted in boxes are intended
to achieve a brighter future for Washington State by encouraging private investment in renewable
energy resources, stimulating the economic growth of this state and enhancing the continued
diversification of its energy portfolio.

Copyright 2011 – Cascade Power Group, LLC

Table of Contents
Introduction .................................................................................................................................................. 1
Key Terms .................................................................................................................................................. 3
Vision Statement................................................................................................................................... 4
Current State of Power Generation in Washington .................................................................................... 5
Hydroelectric Generation.......................................................................................................................... 6
Initiative I-937: Washington's Renewable Portfolio Standards ........................................................... 8
Decoupling ....................................................................................................................................... 9
Net Metering: A Key Issue......................................................................................................................... 10

California Case Study ............................................................................................................................ 12

New Jersey Case Study....................................................................................................................... 14
Grid Interconnection ...................................................................................................................... 15
Washington’s Current Challenge for Net Metering................................................................. 16
Energy Storage – A Solution of the Future ....................................................................... 17

Net Metering Policy Recommendations .................................................................... 18

Supporting CHP, WHR and DE .................................................................................................................... 19
The Clean Energy Standard Offer Program ........................................................................................... 21

Output Based Air Emissions Standards ............................................................................................. 23
Denmark Case Study .................................................................................................................. 24
Roadblocks to Achieving the Vision Statement...................................................................................... 26

Summary of Policy Recommendations................................................................................................... 27

Conclusion .............................................................................................................................................. 28


Key Terms:

Combined Heat and Power (CHP): a system that employs heat from power generation and applies it
toward useful work, typically heating. Also known as "cogeneration", CHP.....

Customer-generator: a customer of an electrical utility who also generates some portion of his or her
power onsite, e.g. via a solar or small wind installation, and uses a net metered system.

Distributed Generation (DG): localized electricity production that is on-site or close to a load center and
is interconnected to the utility distribution system. This definition includes such technologies as
photovoltaics; small wind; small biomass; small combined heat, and power (CHP)/ small cogeneration;
small combined cooling, heat, and power (CCHP); and smaller DG systems. Small is less than 20 MW.

District Energy (DE): the centralized recovery, storage, and/or generation of thermal energy at a central
plant or plant(s) and distribution of that energy to customers through a pipeline, or connected network
of pipelines.

Interconnection: the physical connection of a generating facility to the electric system so that parallel
operation may occur.

Kilowatt-hour (kWh): the standard unit of electricity or power consumption equal to 1000 watts over
one hour, and equivalent to about 3412 British thermal units (Btu).

Net metering: measuring the difference between the electricity supplied by an electric utility and the
electricity generated by a customer-generator’s system over a billing period.

Qualified Facility (QF): a generating facility of 80 MW or less whose primary energy source is renewable
(hydro, wind or solar), biomass, waste, or geothermal resources, or a generating facility that
sequentially produces electricity and another form of useful thermal energy (such as heat or steam) in a
way that is more efficient than the separate production of both forms of energy.

Renewable Energy Credit (REC): a credit issued by a government agency or third-party to a generator of
renewable energy and can in turn be traded and sold on the open market, providing an incentive to
companies that produce renewable energy.

Thermal energy: the heat energy transported by a medium such as water or steam.

Waste Heat Recovery (WHR): the recovery of heat discharged as a byproduct of one process to provide
thermal energy utilized by a second process.


Washington State Policy Vision Statement

2012

• Interconnection and permitting issues have been streamlined for renewable energy, CHP/District
Energy and waste heat-based energy systems.
• Output-based air emissions standards are implemented and enforced to encourage energy
efficiency and the use of CHP and waste heat recovery.
• The Net Metering facility capacity cap has been dissolved and capacity is limited by annual facility
consumption rate, with the aggregate cap is unnecessary but remaining at 5% and virtual net
metering deploys to and is limited to the facilities that it supplies.

2015

• A CESOP policy has been enacted, large cogeneration has increased its position as an important
resource to Washington, and these facilities can readily participate in the wholesale power market.
• A budget is established in a clean energy fund to support R&D in energy storage.
• All institutional and technological barriers to DG have been removed and all permitting is efficient
and environmentally responsible.

2020

• Net Metering and CESOP have expanded customer and utility owned DG and CHP, that they are
integral to procurement, transmission and distribution planning and operations.
• Large and small CHP is utilized in combination with all non-transport combustion engines and uses
District Energy systems to redistribute heating and cooling, so most stand-alone boilers and furnaces
are no longer used.
• Energy storage policy frameworks are in place, anticipating a viable energy storage technology.

2050

• DG makes up 70% of energy consumption with 30% obtained through ecologically responsible
hydroelectricity and nuclear energy.
• Energy storage is integrated into Washington’s energy infrastructure and provides reliable clean
energy and is managed by the state-regulated utility companies.
• The Renewables Portfolio Standard (RPS) mandates were satisfied, and there is no new RPS
mandate. Regulated incentive programs have been phased out, and no new incentives are being put
in place due to grid-parity for most renewable energy systems.


Current State of Power Generation in Washington

2007 Electricity Generation and Consumption by Fuel: Hydro 73%, Coal 8%, Nuclear 8%, Natural Gas
8%, Biomass 0.75%, Wind 2%, Waste 0.43%, Landfill Gases (and other biogas) 0.09%, Petroleum 0.04%.

More than two-thirds of the electricity generated and consumed in Washington in 2007 was produced
from hydroelectric dams. Coal, natural gas, and nuclear were the primary energy sources for the
remainder. Wind accounted for 2% of the electricity generated in Washington and total non-hydro
renewable sources (including wind) accounted for a little more than 3 percent.

Electricity generated from non-hydro renewable sources has been growing. Wind's share has grown
from essentially zero in 2000 to 2 percent in 2007, and the total share for biomass, wind, waste, and
landfill gas was 3.3 percent of the total generation. In 2007 power plants in Washington generated 21
percent more electricity than was consumed in the state. The diagram above, from the 2011
Washington State Energy Report, identifies waste heat from electric power generation as making up 145
trillion of 537 trillion BTU produced in 2007. That is almost half again more than the total amount of
electric power that Washington State exports to other regions (100 trillion BTU).

WA State Dept. of Commerce – Energy Strategy Update:
http://www.commerce.wa.gov/DesktopModules/CTEDPublications/CTEDPublicationsView.aspx?tabID=0&ItemID=
9107&MId=863&wversion=Staging


Large Hydroelectric Generation in Washington:

From the 2007 Washington State energy generation and consumption numbers above, we can see that
hydro is overwhelmingly the primary source of the state’s electricity generation. This could raise the
question: why should we invest in energy forms like
solar and wind when hydro makes up such a large
proportion of our electricity and is classified as a
renewable according to the EPA? The answer comes
back to environmental impacts and carbon emissions
associated with hydro, which I will discuss below.

Environmental Impacts:

Hydroelectric dams can block fish passage to
spawning grounds or to the ocean, although some
more environmentally conscious hydro plants have
measures in place to help reduce this impact. The
diversion of water can impact stream flow, or even cause a river channel to dry out, degrading both
aquatic and riparian habitats. Hydroelectric plants can also have an impact on water quality by lowering
the amount of dissolved oxygen. In the reservoir, sediments and nutrients can be trapped from
dispersing naturally downriver, while the lack of surface water flow can cause undesirable growth and
the spread of algae and aquatic weeds. The Low Impact Hydropower Institute (LIHI) created a voluntary
certification program whereby facilities are classified as low impact after passing a series of tests. In
2007, less than 30 facilities in the U.S. had earned the classification.

Carbon Emissions from Hydro facilities:

A large amount of carbon stored in trees and other plants is released when the reservoir is initially
flooded and the plants rot. Then, after this initial decay, plant matter settling on the reservoir's bottom
decomposes without oxygen, resulting in a build-up of dissolved methane. This potent greenhouse gas,
is released into the atmosphere when water passes through the dam's turbines. In effect, man-made
reservoirs convert carbon dioxide in the atmosphere that is absorbed by vegetation into methane. In the
dry season plants colonize the banks of the reservoir only to be engulfed when the water level rises later
on. For shallow-shelving reservoirs these "drawdown" regions can account for thousands of square
miles. Seasonal changes in water depth, as well as peak power demand, mean there is a continuous
supply of decaying material due to changing water levels.

Claiming that hydro projects are net producers of greenhouse gases is not new. , But in the past decade
the issue has been gaining more political recognition. In the 2006 IPCC discussions, the National
Greenhouse Gas Inventory Program, which calculates each country's carbon budget, included emissions
from artificially flooded regions, for the purpose of incorporating the impacts of hydroelectric dams into
the greenhouse gas calculations.


Bonneville Power Administration is the largest supplier of hydroelectric power
to Washington State and the Pacific Northwest region. Not only do the above
issues apply to the BPA-run hydroelectric systems on the Columbia and Snake
rivers, but these dams also affect threatened and endangered species unique to
this region. Salmon and steelhead runs in the Columbia Basin have decreased
from an estimated 11 to 16 million fish a year in pre-colonial times to around 2
million today. Three stocks of salmon that populate the Columbia River Basin have been listed as
threatened or endangered species, and habitat damage and overfishing are the main causes. Efforts to
preserve these listed stocks have already caused changes in operation of the dams on the Columbia and
Snake Rivers, but some ecologists are not convinced that these changes are enough to restore Salmon
and Steelhead populations.

EPA: http://www.epa.gov/cleanenergy/energy-and-you/affect/hydro.html

New Scientist – Environment: http://www.newscientist.com/article/dn7046

EIA: http://tonto.eia.doe.gov/ftproot/features/hydro.pdf

Pearce, Fred. Rotten Business. New Scientist: Aug. 28 1999. Pg 2121


Initiative I-937: Washington's Renewable Portfolio Standards: On Election Day, Nov. 7, 2006,
Washington State voters passed Initiative I-937. This initiative imposes targets for the state's utilities
that refer to energy conservation and use of eligible renewable resources. Eligible resources under the
initiative are wind, solar, ocean or tidal wave power, geothermal, landfill gas, gas from sewage
treatment facilities, biodiesel fuel that is not derived from crops raised on land cleared from old growth
or first-growth forests, and biomass energy based on animal waste or solid organic fuels from wood,
forest, field residues, or dedicated energy crops. Both public and private utilities are required to secure
15 percent of their power supply from non-hydro renewable resources by 2020. The utilities must also
set and meet energy conservation targets starting in 2010. Interim targets are included in the initiative.
• 3% of a utility’s load by January 1, 2012, and each year thereafter through
2015;
• 9% of its load by January 1, 2016, and each year thereafter through 2019;
• At least 15% of its load by January 1, 2020, and each year thereafter.
• If a utility has no load growth over three years, it is considered in compliance if it has spent at least 1
percent of its revenue requirement on renewables.
Seventeen of Washington’s 62 electrical utilities currently qualify, and they account for about 80 percent
of the state’s electricity market. I-937 sets energy conservation as a first priority in reducing the state’s
carbon footprint, placing economically viable technologies such as CHP and waste heat recovery as the
first that we should be investing in.

“Summary of Initiative 937 to the People: Concerning energy resource use by certain electric utilities.
WA State Senate Committee Services (Aug. 25 2006):
http://www.leg.wa.gov/Senate/Committees/Documents/Initiatives/2006/I937Summary.pdf


Decoupling: In recent times decoupling has become an important issue to consider in Washington State
policy making. It refers to the disassociation of a utility's profits from its sales of energy. A state
government will allow a utility to achieve a certain target revenue when the utility helps its customers
upgrade to more efficient appliances so they will actually use less power. The utility might be allowed to
charge a flat monthly fee or raise its rates in order to guarantee the target revenue.

This makes the utility indifferent to selling less energy and improves the ability of energy efficiency and
DG to operate within the utility framework. The overall goal, therefore, is to remove both the incentive
to increase electricity sales and the disincentive to run effective energy efficiency programs or invest in
other activities that may reduce load. Decision-making then refocuses on making least-cost investments
to increase efficiency and reduce throughput. The result is a better alignment of shareholder and
customer interests to provide for more economically and environmentally efficient resource decisions.

During a January 14, 2011 Joint Washington State Senate EWE and House TEC meeting, Puget Sound
Energy (PSE) and Avista Corporation supported decoupling in Washington State, probably due to the
requirement for utilities to meet conservation goals. They expressed the opinion that conservation is
incentivized by the rate-payers under the decoupling mechanism even when conservation budgets
already come from rate-payers. Initiative 937 requires utilities to practice conservation first. Under the
current system, there is negative incentive for customers to conserve energy because the cost of their
bill per kWh rises if and when they do so. Increasing unrecovered fixed costs due to energy efficiency
needs to end in order to ensure fair rates and good incentives in customer-utility relations.

The second point made by Avista, and seconded by PSE, is that the rate-making process lags behind the
operating projections of utility companies and is also creating a disincentive against rapid conservation
actions. Energy efficiency data increases in the test year are applied 14 months later, at a time when
efficiency has continued to increase. This means that the actual drop in sales due to energy efficiency is
not accounted for in the rate-making estimate for that following year. This means that utility cost
recovery is insufficient when they conserve under this current scenario of lagging projections.

Policy recommendations:

 Decouple publically owned utility companies in Washington State

 Count the forecasted efficiency in the cost recovery during the rate-making process

National Renewable Energy Laboratory: http://www.nrel.gov/docs/fy10osti/46606.pdf

Committee Meeting documents- House TEC Committee 01/14/2011:
http://apps.leg.wa.gov/cmd/default.aspx


Net Metering: A Key Issue

Net Metering is a widely used policy mechanism in the United States. It applies to situations where
utility customers also generate some of their own power, for example through a renewable source like a
solar array. If the power supplied by the electric utility exceeds the electricity generated by the
customer-generator and fed back to the electric utility during the billing period, the customer-generator
is billed only for the net electricity supplied by the electric utility. If electricity generated by the
customer-generator exceeds the electricity supplied by the electric utility, the customer-generator is: (1)
billed for the appropriate customer charges for that billing period; and (2) credited for the excess
kilowatt-hours generated during the billing period, with the kilowatt-hour (kWh) credit appearing on the
bill for the following billing period. On April 30 of each calendar year, any remaining unused kWh credit
accumulated during the previous year is granted back to the electric utility, without any compensation
to the customer-generator.

The size of a qualifying facility is regulated in two ways: first, an overall cap may be placed on how large
a facility may be to qualify for net metering. A second option is to limit the facility capacity to the
average annual use of the customer’s premises or the average annual usage of all the buildings that the
facility supplies. Under Washington’s current policy, each net metering system is limited to 100 kilowatts
(kW) capacity. Qualifying technologies include Solar Thermal Electric, Photovoltaics, Wind,
Hydroelectric, Fuel Cells, CHP/Cogeneration, and Small Hydroelectric.

Net Metering in Washington State

Cumulative Generating Capacity of Net Metering Systems - Electric utilities must make net metering
available to eligible customer-generators on a first-come, first-served basis until the cumulative
generating capacity of net metering systems equals 0.25 percent of the utility's peak demand during
1996. On January 1, 2014, the cumulative generating capacity available to net metering systems
increases to 0.5 percent of the utility's peak demand during 1996.

If required by the electric utility in order to provide meter aggregation, the customer-generator must
purchase a production meter and necessary software. In calculating the bill of a customer-generator,
kWh credits earned by a net metering system during the billing period first must be used to offset
electricity supplied by the electric utility. Furthermore, any Renewable Energy Credits earned by the
customer generator are granted to the utility company and so are any unused credits from the previous
year.


Summary of near-term changes:

Through the Washington State House of Representatives: Technology, Energy & Communications
Committee of 2011, HB 1049 - Concerning net metering of electricity was read as a substitute bill for
current Net Metering legislation. The bill was sponsored by Representatives McCoy, Frockt, Morris and
Moeller. The bill was passed by the House TEC Committee and is now pending decision by the House
Rules Committee.

The bill increases the allowable electrical generating capacity of a net metering system to five
megawatts, and raises the aggregate generating capacity available to net metering systems in 2014
from 0.5% to 5% of the utility's peak demand during 1996. It also allows electric utility customers to
participate in virtual net metering. It also specifies that renewable energy credits produced from a net
metering system remain the property of the customer-generator.

Electricity Generating Cap on Net Metering Systems: The maximum electric generating capacity of a net
metering system is no more than five megawatts. For electric utilities that are full requirements
customers of the Bonneville Power Administration, a net metering system must either an electrical
generating capacity of no more than 199 kW and be metered by one meter; or an electrical generating
capacity of up to five megawatts and be metered by multiple meters with no meter measuring more
than 199 kW.

Requiring Virtual Net Metering: Electric utilities are required to provide virtual net metering to their
customer-generators. Multiple customers may receive fractional net-metering credits from the
production meter of a single net metering system, so long as the customers and meters are within the
same electric distribution system. Excess kWh credits earned by the virtual net metering system, during
the same billing period, must be credited by the electric utility to remaining meters in proportion to the
specified fraction for each customer-generator.

Renewable Energy Credits: All Renewable Energy Credits (RECs) produced from the generation of
electricity from a net metering system belong to the customer-generator. For RECs generated through
virtual net metering, the aggregator allocates assigned fractions of the RECs to customer-generators.

Bill Analysis: http://apps.leg.wa.gov/documents/billdocs/2011-
12/Pdf/Bill%20Reports/House/1049%20HBA%20TEC%2011.pdf


California Case Study

California leads the nation in solar energy, accounting for more than
65% of the all the solar installed in the U.S. and net metering has been
absolutely fundamental to that success. The realization of this means
continued green job growth, further energy bill savings, and progress in
the fight against climate change. The following is a list of leading "solar
states" for 2009, in terms of per capita installed capacity, measured by
Watts (DC) per person:

 20.8 California
 20.2 New Jersey
 14.6 Colorado
 13.8 Arizona
 11.8 Florida

Even with its large population, California continues to have the most capacity per person, with New
Jersey closely following.
Existing law requires California’s major electric utilities to make net metering available to customers
until the total aggregate capacity of the program exceeds 5% of the utility’s peak demand. California’s
net metering program serves more than 50,000 homes, schools and businesses. The recent legislation
doubling the net metering program capacity to 5% ensures that residents of California continue to have
fair access to this renewables program for the near term.

Because solar produces reliable power during peak hours when it is needed most, related investment
helps lower costs for all ratepayers. Net metering has no direct impact on the state’s budget and allows
government agencies and schools an incentive to install solar. California public agencies have already
installed over 51 MW of capacity, saving taxpayers more than $270 million in avoided utility payments.

The policy supports photovoltaics, wind, fuel cells, and biogas from manure or as a byproduct of the
anaerobic digestion of biosolids and animal waste. The system capacity limit is set at 1 MW, while the
aggregate capacity Limit is 5% of utility’s peak demand. Any exported energy from the customer-
generator is credited to customer’s next monthly bill at retail rate. After a 12 month period, the
customer-generator may opt to have any unused credits roll over indefinitely, or to have the utility pay
for any them at a nonretail rate. The customer generator also owns the RECs that are generated from
their clean energy facility.


Take-away message from the California case:

 Raising the QF cap and requiring annual credit payout or rollover is beneficial for private sector
investment.
 Raising aggregate capacity limit per utility creates confidence in California’s renewable energy
market.
 Ensuring that RECs stay with the customer generator further rewards private investment in
renewable energy.

These gestures creates confidence in the reliability of net metering legislation supporting DG, this grows
confidence in the large investment it takes to personally deploy renewable energy technologies.

Source: http://www.renewableenergyworld.com/rea/news/article/2010/02/california-legislature-raises-
solar-net-metering-cap

Freeing the Grid: pg. 43: http://www.newenergychoices.org/uploads/FreeingTheGrid2010.pdf


New Jersey Case Study:

New Jersey has received a grade of "A" on their Net Metering Policy since
2007; from the 2010 “Freeing the Grid” published by the Network for New
Energy Choices in collaboration with other industry authorities. In one
year, the state doubled the installed solar PV capacity from 1000 systems
in 2006 to 2000 systems installed in 2007. This was all set in motion due to the governor’s ambitious
goals for reduction of GHG emissions: 1990 level emissions by 2020, 80% below 2006 levels by 2050.

Under New Jersey’s Net Metering law, eligible renewable technologies are applicable in all sectors and
include solar thermal electric, photovoltaics, landfill gas, wind, biomass, geothermal electric, anaerobic
digestion, tidal energy, wave energy, and fuel cells using renewable fuels. The system Capacity Limit
must be sized not to exceed the customer’s electricity consumption during the previous year. There is
also no aggregate capacity limit but the commission may prescribe a limit of 2.5% of peak demand once
that limit is reached. Net excess generation is credited to customer’s next bill at retail rate and excess is
reconciled at the end of annual period at avoided cost. The customer generator also owns the RECs
generated from their QF.

New Jersey bypassed burdensome and complex requirements for self-generation and took an aggressive
path to encourage private investment in renewable energy. It is important to note that the program’s
success owed much to the successful collaboration with the state’s utilities. This is what has
differentiated New Jersey’s efforts from those in other states, the close collaboration between the state
and the utilities. The most critical step toward successful collaboration is to align their incentives with
those of the state. This is another reason that decoupling and effective rate-making strategies for
utilities are important focal points for state energy policy.
Jeanne Fox, commissioner for the Board of Public Utilities in New Jersey, provides an estimate
suggesting that, under the Net Metering law, solar investment in combination with state and federal
benefits will take only 5 years to pay for itself. This is quite significant considering that the average life of
the current solar PV technologies is estimated at around 20 years.

Take-away message from the New Jersey case:

 A facility-based cap on QF capacity size promotes private sector investment and reduces the
need for an aggregate net metering cap per utility.
 Government collaboration with state utilities furthers progress.
 Supporting solar deployment through state incentives, coupled with net metering creates
renewable energy that acts as peak shave during afternoon peak demand.

Freeing the Grid: http://www.newenergychoices.org/uploads/FreeingTheGrid2010.pdf

Renewable Energy Choices:
http://www.newenergychoices.org/index.php?blog_entry_id=120&page=fullstory&rd=pages&sd=df

Jeanne Fox: Commissioner -
http://www.mitenergyconference.com/2010/files/EnergyConfPresentations/Workshops/SolarWorksho
p/SolarWkshp-Fox-5Mar10.pdf


Issues associate with net metering:

Grid Interconnection: An interconnection standard includes the technical requirements and the legal
procedures by which a customer-sited generator interfaces with the electricity grid. Generally, the utility
company must study and approve a proposed DG system within a framework established by the state’s
public utilities commission. Utility companies traditionally have determined which systems may connect
to the grid and under what circumstances. This arrangement presents a conflict of interest that can
result in significant barriers to private sector investment. For example, a utility company might apply a
complicated set of procedures which are better suited to a 1,000 MW nuclear power plant than to a 2
kW residential photovoltaic system, or impose steep fees, redundant safety requirements and other
obstacles.

According to the Federal Energy Regulatory Commission (FERC), interconnection standards should be
less stringent for small, simple systems and more stringent as system sizes increase. However, standards
should also permit systems that are sized to meet even large on-site loads, such as CHP or WHR. Office
parks, government buildings or college campuses can potentially accommodate installations of 2 MW or
more just to serve a portion of their load. Increasingly, forward thinking states are providing this option
through net metering and interconnection policies.

FERC is an independent agency that regulates the interstate transmission of electricity, natural gas, and
oil. FERC establishes standards for interconnection and encourages state development of a timeline for
each step of the application process, for each type of generator. For a device like a rooftop PV system,
where physical installation may take just two working days, paperwork and permits represent the single
largest obstacle to quick installation. There is room for improvement in this area, and some states have
decided to streamline the process.

Interconnection application fees, along with other fees, can create challenges, especially if these fees
are unknown at the onset of project development. Reasonable fee levels have been established in the
FERC procedures and have been subject to an extensive compromise and negotiation process.

Freeing the Grid: http://www.newenergychoices.org/uploads/FreeingTheGrid2010.pdf


Washington’s Current Challenge for Net Metering: At the January 12th 2011 work session titled “Utility
Perspectives on changing electricity market conditions in Washington,” held by the House Technology,
Energy and Communications and Senate Environment, Water and Energy Committees, utility company
lobbyists presented a dilemma facing renewable energy deployment in this state. They explained that
the existing interconnected wind power is injected into the grid whenever there is sufficient wind and
that this results in unpredictable variability such that hydroelectricity facilities fall into “negative prices.”
This is depicted in the graph below and occurs when a hydro dam reaches its lowest generation capacity
due to low demand and essentially starts paying for the energy to be exported because it is operating at
such a low efficiency. Note how the graph shows negative pricing in negative numbers along the right
margin and how periods of negative pricing correspond closely with elevated wind generation. The
graph shows the power drawn from the grid (Net Load in MW) at each point in time over the stated
interval (hours on the X axis).

Washington State Legislature: Committee Meeting Documents -
http://apps.leg.wa.gov/cmd/default.aspx?cid=TEC

This suggests that renewable energies cannot be used only to meet peak loads, since they will
fundamentally contribute to base load generation unpredictably unless energy storage exists to provide
control over the supply of power from renewable technologies. There is also evidence that the cycling
up and down of conventional coal- or gas-fired generators to compensate for erratic winds is inefficient.
These generators are designed for continuous operation, so intermittently powering them on and off


increases both fuel consumption and carbon emissions. It is even suggested that this effectively cancels
out any projected carbon emissions reductions, but these issues have yet to be scientifically resolved.

A View from the Right: http://aviewfromtheright.com/2010/09/05/wind-energy-just-a-bunch-of-hot-air/

Energy Storage – A Solution of the Future: The perspectives given by the utility companies in
Washington State have described an inherent problem with renewable energy and its role. Demand for
electricity fluctuates throughout the day, peaking around 4-5pm as everyone arrives home from work.
Renewable energy deploys whenever the elements allow, making it unreliable in meeting demand
levels. Developing technology to store electrical energy so it can be available to meet demand whenever
needed would represent a major breakthrough for renewable energy deployment and electricity
distribution. Electricity storage technology can manage the amount of power required to supply
customers at times when need is greatest, which is during peak load. Storage would also help make
renewable energy, whose power output cannot be controlled by grid operators, smooth and deployable.
From this, we may gather that the only large-scale solution for the variability of renewables is energy
storage on a significant scale, well beyond what batteries can provide. Currently, energy storage
technology is not market-ready, but the USDOE is investing in R&D through organizations such as the
Pacific Northwest National Laboratory to develop the science behind these concepts.

In sum, the advantages of large-scale energy storage include:

 Improved power quality and the reliable delivery of electricity to customers;
 Improved stability and reliability of transmission and distribution systems;
 Decreased costs for “peak-power” generation and delivery systems;
 Increased use of existing equipment, thereby deferring or eliminating costly upgrades;
 Improved availability and increased market value of distributed generation sources.

Pacific Northwest National Laboratory: http://efrc.pnl.gov/challenges/

US Dept. of Energy website: http://www.oe.energy.gov/storage.htm


Net Metering Policy Recommendations:
Short term - pass HB 1049 regarding the net metering of electricity to accomplish:

 5MW QF facility cap.
 Raise the aggregate renewable energy capacity per utility to 5% in 2014.
 Allow Virtual Net Metering.
 Ensure that RECs remain with the customer generator.
Long term:

 Replace QF facility cap with limitations based on size of the facility and annual
usage levels.
 Eliminate aggregate cap on renewable energy capacity per utility.
 Allow that Virtual net metering must deploy to surrounding facilities first and
be limited to the annual usage of those facilities in order to protect grid
reliability.
 At the time when energy storage is widely deployed, revise Net Metering
policy to couple with energy storage and revert back to QF capacities cap
unlimited by facility usage.

Interconnection:
 Prohibit requirements for redundant external disconnect switch
 Prohibit requirements for additional insurance

Preparing for Energy Storage:

• Reshuffle a portion of green technology R&D funding in the State to support
research into energy storage technologies
• Establish policy frameworks in anticipation of this technology. These frameworks
should address questions like:
o Who is responsible for energy storage, the producers of DG or the
utility companies?
o Is storage small and distributed or large and centralized?
o Will WA State subsidize energy storage deployment when it is viable
and if so, where will this budget come from?


Supporting Combined Heat & Power, Waste Heat Recovery and District Energy

Combined heat and power (CHP): A typical U.S. power plant is roughly 35% efficient. The other 65% of
the starting energy content in the fuel is lost mainly to waste heat that’s vented into the atmosphere.
Most plants cannot recycle this heat because they’re located remotely, far from consumers, and heat
cannot travel far before insulation costs become high. This kind of energy production comes from so-
called ‘central-station thermal power generation plants’ and is the dominant way of making electricity in
the U.S.

CHP, also called cogeneration, provides an efficient, clean, and reliable approach by generating
electricity and heat energy from a single fuel source and at the same site. CHP plants generate energy
on-site at manufacturing facilities and other large industry and this enables these plants to recycle their
waste heat into clean electricity and useful steam. This steam can then be used to warm nearby
buildings or to assist with various industrial processes.

Instead of throwing away two-thirds of the energy, CHP plants utilize two-thirds or more of the energy
they have at their disposal. “By installing a CHP system designed to meet the thermal and electrical base
loads of a facility,” the EPA says, “CHP can greatly increase the facility’s operational efficiency and
decrease energy costs.”

Waste heat recovery (WHR): Waste heat recovery is related to combined heat and power. Like CHP, it
turns excess heat into clean electricity and useful steam. The difference is that it captures the waste
heat a manufacturer is already emitting rather than producing all of the energy in-house.

A waste heat recovery boiler contains a series of fluid-filled tubes placed throughout the area where
heat is released. When high-temperature heat meets those tubes, a vapor (traditionally steam) is
produced, which in turn powers a turbine that creates electricity. This process is similar to that of other
fired boilers, but in this case, waste heat replaces a traditional flame as the initial source of energy. No
fossil fuels are used in this process. Metals, glass, pulp and paper, silicon and other production plants
are typical locations where waste heat recovery can be effective.

The potential for energy recycling: Widespread use of energy recycling could cut U.S. greenhouse gas
pollution by an estimated 20%. As of 2005, about 42% of U.S. emissions came from the production of
electricity and 27% from the production of heat. Achieving greater efficiency in these areas is thus
crucial to curbing climate change, and the first priority according to Initiative-937.

A 2007 U.S. Department of Energy study found untapped potential for 135,000 MW of combined heat
and power in the U.S. Meanwhile, a Lawrence Berkley National Laboratory study identified another
64,000 megawatts that could be obtained from industrial waste energy recycling, not counting CHP.
Together, these two forms of energy recycling could provide 40 percent of total U.S. electricity needs.


During their work session, the Senate EWE committee was presented with this graph on 01/25/11 called
“Complying with federal air quality standards.”

Committee Meeting Documents (01/25/11):
http://apps.leg.wa.gov/cmd/default.aspx

This slide identifies home heating devises as making up the great majority of fine particulates air
pollution in Tacoma. These devices could be replaced by district heating systems and large and small
cogeneration in both industrial and commercial sectors in Tacoma if the policy incentives were there to
do so. It is also relevant to mention that the costs to US society from medical complications that occur
due to air pollution are rising. This implies that it is not only more efficient to deploy district energy
systems, but a public health measure that would reduce air pollution and the social costs associated
with it.

EPA on CHP: http://www.epa.gov/chp/

Source: Tanjima Pervin, Ulf-G Gerdtham and Carl H Lyttkens. Cost Effectiveness and Resource Allocation
- Societal costs of air pollution-related health hazards: A review of methods and results:
http://www.resource-allocation.com/content/6/1/19


The Clean Energy Standard Offer Program (CESOP): The Clean Energy Standard Offer Program is a
regulatory approach designed to provide clean energy at a discount and to incentivize private sector
investment in the electric grid, while still protecting utility companies. The CESOP is structured to
accelerate the deployment of any generation technology that significantly reduces greenhouse gas
emissions and saves 15% relative to the cost of delivered electricity from the best fossil fueled central
generation plant.

Overview: Distribution utilities offer qualifying clean-energy plants long-term contracts for power at
85% of the delivered cost from the best electric-only power plant. Qualifying clean-energy plants must
be at least 60-percent annual fossil efficient or be non-carbon-emitting power plants such as renewables
or nuclear. Distribution utilities keep retail customers, fund interconnection facilities to qualified clean-
energy plants, and earn returns on up-front investment. Qualified CESOP plants will not be considered a
major modification to industrial processes under the Clean Air Act, thus removing any threat of losing an
operating permit.

Important Benefits of CESOP:

1. Induces profitable greenhouse-gas emission reductions.

2. Stimulates private-sector investments in cleaner, cheaper heat and power.

3. Provides benefits to all stakeholders, including the distribution utilities, manufacturers, and all
retail customers.

4. Improves U.S. manufacturing competitiveness and preserves and adds industrial jobs.

A number of WA state utility companies have expressed the concern that CESOP will interfere with the
federal Public Utility Regulatory Policy Act PURPA regulations. A case was settled in California in
October/2010 that addressed this specific issue. Their conclusions are as follows:

The July 15 order found that the California Public Utilities Commission’s (CPUC) decision to require
California utilities to offer a certain price to CHP generating facilities of 20 MW or less that meet energy
efficiency and environmental compliance requirements would not be preempted by the FPA, PURPA, or
Commission regulations, as long as the program meets certain requirements. The CPUC’s AB 1613 feed-
in tariff would not be preempted by the FPA, PURPA, or Commission’s regulations as long as: The CHP
generators from which the CPUC is requiring the Joint Utilities to purchase energy and capacity are QFs
pursuant to PURPA; and the rate established by the CPUC does not exceed the avoided cost of the
purchasing utility.


CESOP vs. Public Utility Regulatory Policy Act (PURPA) and the Clean Air Act: PURPA offers no benefit
to consumers since utilities are required to pay QF’s the full avoided costs of new generation. CESOP
provides a 15% discount for QF power versus best new central generation. PURPA’s avoided cost
calculation omits the costs of delivering power. CESOP avoided costs include this cost. CESOP raises the
PURPA minimum efficiency requirement from 45 to 60-percent. This is important for encouraging CHP
and WHR retrofit. PURPA requires qualified facilities to sell electricity to their host, which reduces the
distribution utility’s sales and can cause rate increases to other utility customers. CESOP plants are not
allowed to sell electricity except through the distribution utility. Industrial facilities fear that recycling
their waste energy could jeopardize their operating permit under the Clean Air Act. CESOP specifies that
wasted energy recycling plants will not threaten the industry’s operating permit.

PURPA provided further encouragement for developers of cogeneration plants. Section 210 requires
utilities to purchase excess electricity generated by QFs and to provide backup power at a reasonable
cost. QFs included plants that used renewable resources and/or cogeneration technologies to produce
electricity. PURPA CHP operators must use at least 5% of their thermal output for process or space
heating (10% for facilities that burn oil or natural gas). In many cases, this forced independent CHP
operators to accept very low rates for their steam production in order to become a qualifying facility
under PURPA. Another problem is the rate at which utilities purchase a CHP operator’s excess power
production.

Most states set the price at “avoided cost,” or the cost to the utility of producing that extra power.
Utilities with excess power generation capacity are often allowed to have very low avoided costs. This
practice has created barriers to CHP.

Policy recommendations:

 Implement a CESOP program with rates that incentivize investment (15%
reduction on energy costs)
 Dissolve any barriers to CHP or WHR investment due to institutional
permitting or interconnection.

Source - Recycled Energy Development Website: http://www.recycled-energy.com/main/cesop


Output-Based Air Emissions Standards:

The State of Washington 62nd Legislature 2011 Committee on Environment, Water & Energy are
considering SENATE BILL 5118, sponsored by Senators Rockefeller, Ranker, Fraser, and Kline.

This bill concerns output-based air emission standards, which are used to increase energy efficiency,
improve air quality, and reduce greenhouse gas emissions. They require the department of ecology to
consider an output-based air emission standards approach when issuing decisions regarding permits,
orders, and regulations.

Since 2004 new fossil fueled power plants, or those facilities that increase capacity by 25MW or more,
must mitigate 20% of their CO2 emissions over a 30 year period. Three options exist for this: 1. Pay an
independent qualified organization such as Climate Trust; 2. Directly purchase Carbon Credits (1.60/Mt
of CO2); 3. Invest in clean energy projects, which, in the mentioned bill, include cogeneration or waste
heat recovery from industrial or commercial sources. Emission standards have typically been input-
based (limit the amount of emissions that may be produced per unit of fuel burned), while the output-
based method relates CO2 emissions to the productive output of the process (emissions per unit of
product). It focuses on more efficient production of electricity and heat. This must be considered in
permitting, orders and regulations.

These standards are necessary to ensure that CHP and WHR are recognized by governmental agencies as
greenhouse gas mitigating technologies in a way that input-based standards cannot.

Policy recommendation:

 Implement output-based air emission standards as a required consideration
by the US Dept. of Ecology in all permitting that can potentially require CHP or
Waste Heat Recovery in the industrial or commercial sectors.

Source from WA State Legislature Website:
http://apps.leg.wa.gov/billinfo/summary.aspx?bill=5118&year=2011


Case Studies in CHP:

DENMARK

The widespread use of combined heat and power in Denmark is one of the most
important reasons that they have been able to reduce their carbon emissions
while maintaining fairly consistent fuel consumption.

Today, more than half of all electricity produced in Denmark is at CHP plants. Around 1.5 million houses
and buildings are heated in this way, making them the largest share of electricity from CHP in the
European Union, at 55% of all electricity produced. The CHP plants are localized all over Denmark,
ranging in size from small to large and in ownership from municipalities to industries and energy
companies. This diversity in location, scale and ownership has strengthened the overall security of
supply. The net efficiency ratio of CHP plants in the country has reached 90-98% and alternative fuels
are also being explored, such as the world’s most efficient straw-fired CHP plant.

With district energy systems in place, 9 out of 10 families pay less for their heating than the cost of
owning their own oil or natural gas boiler. The use of cleaner, diversified fuels in combination with CHP
has also reduced the carbon footprint of the country significantly, lowering CO2 emissions by 8-11
million tons per year, which is 20% of the total national emissions from 2004.

The first combined heat and power plant in Denmark was built in 1904 and supplied a large hospital with
electricity and heat. By the 1970s, around 30% of homes were heated from CHP district systems. After
two oil crises in the 1970s, expansion of the fuel-efficient combined heat and power system to medium
and small-sized cities created a network of decentralized CHP plants throughout most of country. The
past hundred years of development has meant that today Denmark has a total of around 670 centralized
and decentralized CHP plants. The largest plants are owned by large energy companies, while the
smaller plants typically are owned by production companies, municipalities or cooperative societies. In
addition, 10% of all power in Denmark is generated from biomass and organic waste in these CHP plants

Centralized and decentralized CHP plants differ because centralized plants initially produced electricity
and were located in large Danish cities, whereas decentralized power plants were originally heat plants
located in medium-size and smaller cities. Since the 1980s Danish energy production has been subject to
decentralization, which means the production of electricity and heat has come to be more fully
distributed throughout the country. The Danish Energy Agency has laid down the general conditions for
establishing and operating district heating systems. These are to ensure fair prices on heating for
consumers and the economy in general. According to Danish legislation, district heating is to be sold at a
price corresponding to the cost of producing and distributing, meaning that heat consumers benefit
from the low costs.


Take-Away Message from the Denmark Case:

• This example proves that decentralized CHP and District Energy systems may be realized with
the correct incentives in place.
• The incentives need to come from not only the method with which we analyze a plant’s
efficiency, but also from an extra monetary incentives and market mechanisms to reduce
emissions and conserve energy.

Danish Energy Authority Source: http://www.ambottawa.um.dk/NR/rdonlyres/C3F9F1D4-BEA9-4C29-
A1FD-1D7CC8617B84/0/combinedheat.pdf

More DEA, Source: http://www.ens.dk/en-
us/info/news/factsheet/documents/kraftvarme%20170709.pdf


Roadblocks to Achieving the Vision Statement

Disincentives within the energy industry to engage in major improvements or changes in operation form
the largest roadblock to the realization of the policy vision presented here.

Specific hurdles include:

• The current regulation of utility companies creates resistance to policies that encourage efficiency
improvements, energy conservation, transition to renewables and pollution control.
• Governing agencies and departments are unmotivated to spearhead institutional improvements or
take on additional tasks like more permitting or paperwork.
• Poor stakeholder and taxpayer representation at UTC, TEC and EWE committee public hearings
means that the most consistent feedback that the committees receive is from full-time utility
company lobbyists.
• Concerning Net Metering:
o Cost recovery for customer generators is not guaranteed if incentives are inadequate or
policies are unreliable.
o Cost of electricity can increases because of increases in aggregate net metering systems,
but this can be offset by decoupling the utility company incentives to favor
conservation.
• Concerning CHP and WHR:
o Inadequate inclusion of CHP and WHR into existing state policy vocabulary, causing
roadblocks for such facilities from permitting and interconnection applications.
o Monetary incentives are not implemented in policy because I-937 requires efficiency
measures to be deployed as a priority, but so far has not encouraged CHP or WHR.


Summary of Policy Recommendations

Decoupling:

 Decouple publically owned utility companies in Washington State

 Count the forecasted efficiency in the cost recovery during the rate-making process

Net Metering:

Short term - pass HB 1049 regarding the net metering of electricity to accomplish:

 5MW QF facility cap.
 Raise the aggregate renewable energy capacity per utility to 5% in 2014.
 Allow Virtual Net Metering.
 Ensure that RECs remain with the customer generator.
Long term:

 Replace QF facility cap with limitations based on size of the facility and annual usage levels.
 Eliminate aggregate cap on renewable energy capacity per utility.
 Allow that Virtual net metering must deploy to surrounding facilities first and be limited to the annual usage of
those facilities in order to protect grid reliability.
 At the time when energy storage is widely deployed, revise Net Metering policy to couple with energy storage
and revert back to QF capacities cap unlimited by facility usage.

Interconnection:
 Prohibit requirements for redundant external disconnect switch
 Prohibit requirements for additional insurance

Preparing for Energy Storage:

• Reshuffle a portion of green technology R&D funding in the State to support research into energy storage
technologies
• Establish policy frameworks in anticipation of this technology. These frameworks should address questions like:
o Who is responsible for energy storage, the producers of DG or the utility companies?
o Is storage small and distributed or large and centralized?
o Will WA State subsidize energy storage deployment when it is viable and if so, where will this budget
come from?
CESOP:

 Implement a CESOP program with rates that incentivize investment (15% reduction on energy costs)

 Dissolve any barriers to CHP or WHR investment due to institutional permitting or interconnection.

Output Based Air Emissions Standards:

 Implement output-based air emission standards as a required consideration by the US Dept. of
Ecology in all permitting that can potentially require CHP or WasteLLC Recovery in the industrial or
Copyright 2011 – Cascade Power Group, Heat
commercial sectors.

Conclusion:

Purposeful policy decisions are needed in Washington to improve the energy situation in the
state. Such improvement should involve private investment in renewable energy sources, stimulating
the state's economic growth, and enhancing the continued diversification, flexibility, and affordability of
energy produced and consumed. Policies should be sensitive to the context of the energy mix in
Washington and the Pacific Northwest, as well as stakeholder perspectives. Emissions measurement
techniques and institutional norms are not infallible. Adaptation requires questioning and improving
upon the status quo. Market mechanism policies such as Net Metering and CESOPs should reflect the
current characteristics of the energy industry, while also pressing for improvements through targeted
incentives. Washington has a hydro-powered head start on transforming the U.S. energy industry into
an efficient and renewably focused system. By 2050, a carbon neutral power grid in Washington is
achievable with smart and proactive policy decisions.


Washington State Policy Roadmap

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