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Foundation Energy Infrastructure Inc.
Submission to Alberta’s
Energy Efficiency and Advisory Panel
A Community Energy Strategy for Alberta
July 2016
Prepared by:
Kevin Heal
Director Business Development
Foundation Energy Infrastructure Inc. is a private investment firm in Alberta formed to build a portfolio of renewable energy
and low carbon utility and transportation infrastructure investments.
DISCLAIMER
This document was prepared as a submission to the Government of Alberta. Neither Foundation Energy Infrastructure Inc. nor the author:
(a) makes any warranty, expressed or implied, with respect to the use of any information, apparatus, method, or process disclosed in this
document or that such use may not infringe privately owned rights; or
(b) assumes any liability with respect to the use of, or damages resulting from the use of, any information, apparatus, method, or process
disclosed in this document.

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EXECUTIVE SUMMARY
“Across the board, the most successful states share certain policy components. Those
seeking to achieve success have adopted substantially similar policies. The result is a
clear, emerging consensus on best practices in many states, and a patchwork of
ineffective and heterogeneous rules — or non‐existent rules — in others.” (IREC, 2014,
p.5)
“Generally, states that have implemented three or four best practice policies that include
high quality foundational policies have been successful in creating robust solar markets.”
[NREL 2014B, p.12]
This submission concerns the policies needed to guide Alberta’s path to 2030 of widespread development
of community energy and evolution of a smart grid.
While community energy or distributed generation (DG) today consists mostly of solar photovoltaic (PV)
technology, it is not just rooftop solar. It includes all distributed energy resources (DER), defined here as
smaller scale renewable or low carbon power generation and storage systems connected to distribution
systems generally of up to 20 MW and 69 kV that can be shared or aggregated to provide power to meet
all or some of the regular demand of homes, commerce and industry. Community energy and DER is today
mostly solar PV and can be both behind-the-meter or within the distribution system of medium voltage
lines and sub-stations. It is not intended to serve large generation facilities, transmission lines and sub-
stations, but may, depending on the scale of the system, include direct transmission-connected industrial
customers.
Alberta has opted to create an agency, Energy Efficiency Alberta (EEA), to deliver energy efficiency and
community energy programs. This is a significant policy move as most jurisdictions in North America have
driven change via regulation of existing local electric distribution companies (LDC), leveraging their
established customer relationships and reach to provide new programs and tariffs to facilitate, incent and
enable renewable energy markets.
Nevertheless, Alberta’s regulated wire service providers (WSP), particularly the five utilities which serve
distribution connected generators (EPCOR, ATCO Electric, City of Lethbridge, ENMAX, FortisAlberta) and
energy retailers need to play an important role in the low carbon transformation of how and where
Albertans obtain their electricity. There is no doubt as Alberta phases out coal generation and the
electricity grid continues to modernize, the growth of DER will be disruptive to the traditional utility
business model. Utilities and regulators need to pay careful attention to the implication DER deployment
will have on rate design, cost structures and utility profitability. This transformation needs to see the
electric utilities invest in the new opportunities presented by site generated renewables, energy storage
and smart grid and smart inverter technologies.
Fortunately for Alberta, a major body of policy knowledge and experience exists about building healthy,
successful DER industries and markets in other jurisdictions. Alberta needs to learn and borrow liberally
from the large and growing number of U.S. states which have and are enacting best practice renewable
energy and DER policies.

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With sound, new foundational policies and forward-looking regulatory ratemaking, Alberta will be poised
to build a new era of electricity infrastructure characterized by steadily rising penetration rates and
financially healthy electric utilities that embrace the move towards low carbon distributed generation.
With effective energy efficiency and community energy policies implemented in parallel with the
announced Climate Leadership Plan, Alberta can become a world leader in climate action.
RECOMMENDATIONS
A community energy path for Alberta should:
1. Establish a target for Alberta of 1 GW of clean community energy by 2030. Preliminary economic
modeling suggests that committing half of the announced five year EEA budget of $645 million
($322.5 million) on performance incentives could kick start the development of approximately
500 MW of capacity and direct investment in community energy of $1. 5 billion by 2021.
2. Do not limit community energy narrowly. It is more than rooftop solar and shared energy.
Community energy should be equated with all distributed energy resources and defined as
smaller scale renewable or low carbon power generation and storage systems connected to
distribution systems generally of up to 20 MW and 69 kV that can be shared or aggregated to
provide power to meet all or some of the regular demand of homes, commerce and industry.
3. Allow the competitive power marketplace time to sort itself out. Today’s low power prices
inhibit new investment in generation. Absent a significant rise in electricity prices, the ability of
policymakers to engineer a significant growth in community energy will be restricted. However,
carbon pricing starting in 2017, coal retirements, recovery of natural gas prices, a return to
economic growth, combined with the increased market clout of the Balancing Pool as the new
operator of reassigned PPAs, are all factors which could provide upward pressure on wholesale
power prices to 2020.
4. Build on the foundation established over eight years of experience with the Micro-Generation
Regulation by rebooting the regulation to adopt best practice net metering and interconnection
standards effective January 1, 2017. The regulation should be updated thereafter as conditions
dictate. This includes basing any micro-generation system capacity limit on the customer’s regular
load and consumption, and allowing for meter aggregation and improving the application
processes from LDCs. Limits on project size, access to full value billing credits and cost uncertainty
of distribution system upgrades are significant barriers to the growth of community energy.
5. Alberta should review and amend the AUC regulatory and environmental permitting process to
ensure that community energy projects of less than 5 MW that are not sited in environmentally
sensitive or vulnerable locations should generally be subject to a streamlined screening and
review process.
6. Encourage third party ownership and leasing arrangements of community energy systems by
WSPs, retailers and other market participants while enacting consumer protection measures.

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7. In the near term of 2017-2020, offer new capacity rebate ($/kW) and performance based
incentive programs ($/kWH) for eligible parties that install distributed energy systems. These
programs should aim to reduce payback periods to 5-10 years with levels adjusted at intervals to
encourage uptake. It should be paid for out of the five-year funding commitment to Energy
Efficiency Alberta. Learnings obtained will guide next generation programs and new tariffs under
an evolving community energy regulation.
8. Create a community energy regulation that directs regulators and WSPs to provide new
community energy tariffs by 2019. To achieve wide spread use of DER at the community level
Alberta will need move away from strict adherence to traditional ratemaking principles and
towards a next generation regulatory model that allows WSPs to recover costs but is increasingly
based on performance and locational-valuation principles within the competitive power market.
9. Continue and accelerate the AESO study of Energy Storage Integration but expand the scope of
the process to evaluate the value of DER scale energy and battery storage to the electric system.
In the short term, establish an interconnection process for DER scale energy storage applications
that do not export power to the distribution system.
10. Longer term, facilitate the transition to a smarter more intelligent grid by developing an Alberta
approach to calculating the overall value of community energy to the electricity grid similar to
locational-valuation and value of solar tariff programs that are being developed in U.S. states.

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ACRONYMS
AESO Alberta Energy System Operator
AUC Alberta Utilities Commission
DER Distributed Energy Resources
DG Distributed Generation
EEA Energy Efficiency Alberta
FERC U.S. Federal Energy Regulatory Commission
GWH Gigawatt-hour
IEEE Institute of Electrical and Electronics Engineers
IREC Interstate Renewable Energy Council
kW Kilowatt
kWH Kilowatt-hour
LDC Local Distribution Company
MW Megawatt
MWH Megawatt-hour
NREL U.S. National Renewable Energy Laboratory
PBI Performance or production based incentive
PPA Power Purchase Agreement
PV Photovoltaic
REC Renewable Energy Credit
ROI Return on Investment
SEIA U.S. Solar Energy Industries Association
TOU Time of Use
TPO Third Party Ownership
WSP Wire Service Providers

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DISCUSSION
1. Setting an Achievable Community Energy Target
“Most photovoltaics (PV) in the United States are connected to the distribution system,
and this trend is expected to continue…. From 2010 through the first half of 2015, the
installed capacity of solar photovoltaics connected to the U.S. distribution system
increased six-fold, from approximately 1.8 GW to more than 11 GW.” [NREL, 2016, p.1]
The Panel should recommend that Alberta establish a target of 1 GW of clean community energy by 2030
that is connected with the distribution system. This can be achieved by:
a. Updating the existing Micro-Generation Regulation with best practice net metering and
interconnection rules effective January 1, 2017.
b. Implementing community energy incentive programs funded by EEA starting in 2017.
c. Creating a Community Energy Regulation that directs Alberta’s regulators and WSPs to provide
new community energy tariffs by 2019 and move Alberta towards Smart Grid evolution with next
generation of performance and locational-valuation based ratemaking within the competitive
power market.
Currently, Alberta has approximately 10 MW of community energy, mostly rooftop solar PV, representing
0.06% of all generating capacity in the province. Alberta requires a plan to move from this very low state
of market penetration to over 1% in the medium term and to over 5% by 2030. Figure 1 shows how the
evolution of DER integration can occur. Alberta’s challenge today is to institute new enabling policies and
incentive programs starting in 2017 to allow us to evolve to a much higher integration of DER and maturing
Smart Grid by 2030.
Figure 1 - Potential system characteristics of DER as Smart Grid evolves (RAP, 2011, p.15)
AESO’s 2016 Long-term Outlook foresees an “alternate” strong climate change policy scenario that results
in “1,000 MW of solar capacity supported and developed by 2030”. This is to be achieved by the addition
of 100 MW of solar annually beginning in 2020. [AESO, 2016, p.3&19]

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A key component of a community energy strategy for Alberta should be the encouragement of MW-scale
commercial/industrial DER applications that will accelerate uptake. The Panel should not equate
community energy with shared energy. Whereas community energy and DER are essentially the same,
shared energy is a subset business model that includes “only those systems that allocate the electricity of
a jointly owned system, or a third-party-owned (TPO) system, to offset multiple individual businesses’ or
households’ consumption” [NREL, 2015A, p.2].
“Solar power, despite the fact that it generally correlates better with periods of higher-
priced electricity than does wind, would still likely require prices well-above $100/MWh
to guarantee construction of new projects. As a result, any substantial new renewable
generation in Alberta will likely require incremental financial support.” (CLRM, 2015, p.
56)
When determining community energy incentive levels, policy makers should seek to create payback
outcomes of 5-10 years taking into account system investment requirements and avoided electricity costs.
Preliminary economic modeling shown in Table 1 suggests that by committing half of the announced five
year EEA budget of $645 million (e.g., total of $322.5 million) to performance based community energy
incentive programs of $0.12 to $0.15 per kWh for 5 to 10 years, the province could kick start the
development of up to 500 MW of capacity and direct investment in community energy of approximately
$1. 5 billion in Alberta by 2021.
Table 1 - Potential Impact of Community Energy Incentive Programs (Foundation Energy Infrastructure Inc.)
Year Program
Funding
($‘000)
Incentive
($/kWh)
New
Generation
(GWH)
New Capacity
(MW)
Cumulative
New Capacity
(MW)
2017 $22.5 $0.15 150 115 115
2018 45 $0.15 150 115 231
2019 82.5 $0.12 313 240 471
2020 85 $0.12 21 16 487
2021 87.5 $0.12 21 16 503
Note: Additional post-2021 funding required to complete 5 to 10-year program duration. This incentive should be
considered additive to customer’s power cost savings or net metering credits. No economic analysis has been
attempted of the level or duration of incentive necessary to encourage uptakes.
2. Destabilizing Impact of Volatile Power Prices
In considering community energy program design, Alberta policy makers need to take into account that
meaningful market penetration of DG systems such as behind-the-meter rooftop and ground mounted
solar will be unachievable so long as market conditions persist that has led to the collapse of Alberta
wholesale power prices since 2014.
“if costs are very low for competing electricity, the influence of market-enabling policy,
such as interconnection and net metering, is weakened due to reduced economic
motivation.” [NREL, 2014A, p.ix]

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Albertans in 2016 are benefitting from historically low electricity prices caused by rapid expansion of
merchant natural gas generation followed by a collapse of natural gas prices. The reassignments this year
of Power Purchase Agreements (PPA) to the Balancing Pool are reflective of a competitive market that is
operating as intended. It is hollow to argue low energy prices are not in the interests of consumers, but
they will deter investment in all types of generation, including community energy and likely lead to larger
price volatility in the future. Absent a significant rise in electricity prices, the ability of policymakers to
engineer a significant growth in community energy will be severely restricted.
Fortunately, Alberta’s competitive market place will move to correct unsustainable situations. Carbon
pricing starting in 2017, coal retirements, recovery of natural gas prices, a return to economic growth,
combined with the increased market clout of the Balancing Pool as the new operator of reassigned PPAs,
are all factors which could provide upward pressure on wholesale power prices in the medium term to
2020.
3. Best Practice Enabling Policies
“Designing economically sustainable renewable energy markets requires the
coordination of complementary policy and regulatory mechanisms. While financial
incentives are the engine of market development, interconnection and net metering
policies are the road. It is much easier for a market to accelerate on the smooth, finished
roads of Colorado, New Jersey and California, for example.” (IREC, Freeing the Grid, 2014,
p.6)
Experience in the U.S. states suggests jurisdictions with the most success in achieving robust renewable
markets have first implemented a suite of sound enabling policies such as net metering and
interconnection best practices. As Alberta has learned over the past 8 years with its Micro-generation
Regulation, these are not enough by themselves to spur market growth. Effective foundational programs
such as rebates, incentives and third party financing that remain in place for a number of years are
important to lead to successful outcomes. A favorable economic climate that includes high competing
electricity prices, a good solar resource, and a population interested in energy efficiency and renewable
energy are critical to success. [NREL 2014B, p.18]
Key expert resources for evaluating policy and program alternatives include the publications and staff of
the Regulatory Program at the Interstate Renewable Energy Commission near Albany, New York and the
State and the Municipal policy team at the National Renewable Energy Laboratory in Golden, Colorado.
Net Metering is bill crediting that returns full value to micro-generators for the electricity they add to the
grid. Alberta should amend the Microgeneration Regulation to include updated best practices most
associated with strong renewable markets.
As suggested by IREC and SEIA, net metering best implementation practices include:
a. Individual System Capacity: Any individual system size limitation should be based only on the
host customer’s annual load or consumption. Many states limit sizes to a present of load, such as
125%, to prevent intentional oversizing. Capacity limits can also vary by customer type (retail,
commercial/industrial, farm).

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b. Program Capacity Limits: Arbitrary limitations on the total amount of clean energy that customers
may generate and contribute to the electric grid runs counter to best practices. To address utility
worries about lost revenue, some states establish total program limits for each utility or statewide.
Concerns that distributed generation represent lost revenue or cause adverse system limits are
not straightforward and require analysis.
c. Restrictions on “rollover”: Indefinite rollover of excess DG to a future month, credited at retail
rates, should be an option. The only exception is allowing for payments for annual net excess
generation. Rollover limitations leads to undersizing of system to load.
d. Metering equipment: Consistent with all retail applications, the utility shall provide a meter that
is capable of net energy metering. Retail electric customers utilizing net energy metering must
not be required to purchase new energy metering equipment.
e. Time of Use (TOU) Metering: Excess generation in one time period within a day should be able to
be carried over into other time periods.
f. REC ownership: The owner of a net energy metered system should retain ownership of renewable
energy credits (RECs) produced by their owned system, unless transferred to the utility or another
party in exchange for acceptable compensation.
g. Customer classes: All types of customers including residential and non-residential should be able
to participate in net energy metering.
h. Meter Aggregation: Customers should be able to group all the meters on their contiguous
property and tie them to a central DER system for purposes of net metering. Benefits multi-unit
dwellings, farms and businesses.
i. Virtual Net Metering: Allows customers to receive bill credits tied to generation from an off-site
DG system.
j. Shared Energy: Customers should be able to subscribe to a shared energy system not physically
located on their property. Virtual net metering must be allowed to enable shared energy systems.
[IREC, 2014 and IREC, 2015 and SEIA, 2016A]
Interconnection is the technical rules and procedures that allow customers to connect to the grid.
Consistency across jurisdictional boundaries in distributed generation interconnection standards is crucial
for consumer understanding, safe and efficient operations and lowering costs. [IREC, 2014, p.6]
Consensus has emerged in the U.S. on FERC and IEEE 1547 interconnection technical standards.
Interconnection policy issues include [IREC, 2014 and IREC, 2013]:
a. Eligible Technologies: Inclusion of renewable and low-carbon generation facilities.
b. System Capacity: All systems up to 20 MW should be included.
c. Application Breakpoints – Procedures should be more stringent as system capacity increases.
IEEE 1547 allows four review paths for generating facilities with capacities of:
a. Level 1 – 25 KW or less
b. Level 2 – up to 5 MW
c. Level 3 – up to 10 MW
d. Level 4 – all other.
d. Timelines: LDCs should not exceed application completeness reviews, initial screens and
supplemental reviews within established number of business days for each review level.
e. Interconnection Charges: Application and review fees should be waived for systems under 25
kW and be reasonably related to the complexity of the request recognizing that systems less
than 1 MW are unlikely to present undue challenges.

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f. Certification: Electrical safety and operation of the grid must be a primary concern and remain
an engineering standard, not a policy choice.
g. Technical Screens: Provision of penetration screens to limit amount of aggregate generation
allowed on a line section.
h. Rule Coverage: Consistency within the province creates efficiency and reduces confusion
i. Network and Distribution Upgrade Cost Exposure: Cost certainty of non-binding utility cost
estimates is a central concern for project developers and financing.
j. Data Provision: Early access to distribution system information and structured means for project
developers to obtain available capacity and location data to facilitate site assessment and
project queue placement.
In June 2016, California issued Rule 21, a major decision that sets a very high bar for interconnection best
practices. Rule 21 defines new rules to address cost certainty including a “cost envelope” approach to
improve the accuracy, predictability and certainty around the costs associated with upgrades necessary
to interconnect projects. [IREC, 2016]
4. Permitting, Environmental Screening and Community Engagement
“Solar energy technologies present tremendous environmental benefits when compared
to the conventional energy sources. In addition to not exhausting natural resources, their
main advantage is, in most cases, total absence of almost any air emissions or waste
products. In other words, solar energy can be considered as an almost absolute clean
and safe energy source” [Tsoutsos, 2005, p.295]
Alberta should review and amend the AUC regulatory and environmental permitting process [AUC, 2016]
to ensure that community energy projects less than 5 MW that are not sited in environmentally sensitive
or vulnerable locations should generally be subject to a streamlined screening and review process.
The environmental impacts of community energy will vary depending on the technology used. The
impacts of ground mounted solar PV deployment are generally benign as they create no noise, emissions
or glare. Impacts most considered are associated with land use, habitat loss, visual impacts and control of
noxious weeds. [Tsoutsos, 2005, p.292-294].
Ground mounted solar PV projects over 50 kW should ideally utilise previously developed brownfield,
contaminated or lesser quality agricultural crop land. They should avoid affecting the visual aspect or
natural beauty of landscapes, usually be screened by hedges or treelines and not cause undue impact to
nearby residential properties or roads. [BRE, 2013, p.5]
Regardless of the scale of a community energy project, community engagement should be carried out and
follow the general principles common to most developments including timeliness, transparency,
constructiveness and being inclusive, fair and evidence-based. [BRE,2015, p.2]
“A key difference between small and large projects is the inability of small projects to
absorb engineering review costs. The expedited permit process is intended to simplify the
structural and electrical review of a small PV system project and minimize the need for
detailed engineering studies and unnecessary delays.” [SABCS, 2012, p.6]

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Despite the rapid decline in the cost of solar panels, non-equipment soft costs make up more than half
the cost of most solar PV projects. Soft costs are the finance and non-hardware costs including
engineering, permitting, interconnection, marketing and profit. Alberta should ensure WSPs,
municipalities and counties provide a standardized and expedited permitting process for solar PV systems
up to 25 kW and higher.
5. Third Party Ownership
Most renewable and community energy is financed through utilities or third parties. Encouraging TPO or
leasing of DER is an important way for Alberta to achieve higher rates of market penetration in just a few
years if combined with stronger enablement rules, foundational incentive programs and rising power
prices. In this model, end-users put up little or no system capital in return for entering into a firm PPA
with a third party who is usually responsible for maintaining the system.
“In a physical sense customer-owned and third-party distributed generation systems are
often indistinguishable. Yet the third-party ownership option is a critical factor in that it
provides financing flexibility to customers interested in on-site generation. Recent
activities in states that allow third parties to provide distributed generation resources
reveal that permitting this alternative substantially increases the penetration of
distributed generation, thereby magnifying the impacts that the utilities experience.”
(ECW, 2014, p.1)
TPO should be eligible for net-metering. Figure 2 shows a typical bi-directional net-metering power flow
between LDC and an end-user with a behind-the-meter TPO arrangement.
Figure 2 - Third Party Distributed Generation Leasing Structurel (NREL, 2010, p.18)
TPO has proven to be a powerful means of achieving growth in DER markets and is characteristic of the
U.S. states which have achieved the most success. Table 2 presents different models for organizing
community energy systems, included shared energy.

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Table 2 - Financing and Purchasing Methods for Community Energy Systems (NREL, 2015A, p.3)
In the U.S. there have been issues of utility ownership of DER in competitive power marketplaces
relating to performance and exercise of market power. [NREL, 2010] Utility owned and non-utility
owned TPO models are both able to enable positive outcomes as long as the value proposition for each
party is in the public interest as shown in Table 3.
In the Alberta competitive power marketplace, it will be important to ensure WSP-owned DER does not
crowd out competitors or provide inferior performance. Additionally, Alberta should ensure consumer
protections, particularly for retail and smaller scale community energy systems by considering certain
standardized contract requirements. Enmax’s Home Solar and Lease program is an example of utility
owned, leased, sold and installed TPO in Alberta.
Table 3 - Third Party Ownership Revenue Sources (EI-APP, 2015, p.12)

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6. Rebate and Incentive Programs
In early stages, jurisdictions most successful in increasing the amount of distributed or solar energy in
their generation mix typically adopt incentive programs to kick start system installations. An important
consideration is setting policy goals has often been to reduce the large upfront capital cost. Despite the
dramatic reduction in solar PV costs over the last 10 years, addressing the extremely low penetration rate
of community energy in Alberta by reducing upfront costs and shortening paybacks should remain central
policy goals.
Ideally, programs should provide longevity, stability and predictability in order to encourage a viable
renewable industry that is sustainable over the long term. Generally, incentives should decrease over
time to minimize the cost to taxpayers. Consumer protection measures need to ensure customers
purchase an appropriately sized system at a fair price that performs with minimal maintenance over
decades.
The two most common incentive programs are capacity rebates and performance or production based
incentive (PBI) systems.
Capacity Rebates – Rebates make an up-front payment to the customer to offset some of the cost of
installing a system. They are generally offered on a $/watt capacity basis for smaller scale systems of less
than 1 MW. They vary by the amount of the payment offered, eligible project size, and maximum payment
per project. Saskatchewan’s Net Metering Rebate, Alberta’s Municipal Solar Program and On-Farm Solar
Management Programs are examples of capacity rebate incentives.
PBI - Production incentives are based on actual electricity generated from a system and are usually paid
as a monthly billing credit per kWH generated over a defined period of anywhere from 5 to 20 years. They
are normally used to stimulate both kW and MW scale system sizes. Ontario’s FIT and microFIT programs,
SaskPower’s Small Power Producers Program and BC Hydro’s Standing Offer programs are examples of
PBI in Canada.
Rebates reduce the cost to the customer but does not guarantee output. PBI incents production and
provides a predictable revenue stream to the customer but does not reduce the upfront cost. Payments
need to be sufficient in amount and duration to encourage uptake. Figure 3 summarizes the strengths
and weaknesses of both types of programs. [NREL, 2012]

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Figure 3 - Capacity Rebates vs. Performance Based Incentive Programs (NREL, 2013)
Best Incentive Practices –
NREL has developed a list of best incentive practices for designing solar programs (NREL 2012):
a. Rebates coupled with performance guarantees: For smaller customer owned systems. Ensures
systems are properly designed, procured and installed.
b. Moderate term PBIs with on-bill crediting: For commercial/industrial scale and third party owned
systems. Helps to finance installations, while spreading payments over future years (e.g., aligns
with collection of carbon pricing revenues). Providing higher $/kWh incentives while keeping
terms to 5 years provides enhanced revenue streams during critical early years of project life and
reduces administrative burden. Key considerations include payment frequency and method of
distribution (e.g., LDC on-bill crediting, direct deposit, or cheque).
c. Use multiple approaches and data sources to set and evaluate incentive levels: Incentive levels
can be benchmarked against neighboring jurisdictions. Installation cost data can be used to
calculate paybacks and ROI. Payback targets should be 5 to 10 years. Program incentives provide
some revenue certainty but non-program incentives such as avoided cost, power price forecasting,
inflation, rising carbon pricing should be considered when setting levels. Value of Solar Tariffs and
Locational Valuation are newer methods of establishing incentive levels that are gaining attention.
d. Different incentive structures to encourage various market segments: A combination of
approaches is generally required. Market segments differentiated by customer class, tariffs, and
financing can be catered to with targeted programs influenced by ratepayer interest, grid benefits,
market diversity, advancing public support, and cost.
e. Modify incentive levels in response to changed conditions: Institute processes to modify
incentive levels periodically. Most common measure for community energy scales is pre-

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established step-down schedules which provides simplicity, transparency, and certainty to market
participants as well as a motivation to act before the incentive is shortened.
f. Use multiple step-downs and communicate progress: Encourage customers to act before the
next decline. Ensure remaining funding levels in the current step are published and updated
regularly. Convey information via websites and advertising.
g. Manage project flow and incentive offer periods to encourage stable market: Help nurture a
stable renewable energy industry by ensure funding does not run out mid-year. Offer incentives
more frequently than annually. Modify funding and levels in response to program uptake and
market conditions.
h. Customer protection measures encourage reputable business practices: Most common
measures educate consumers about appropriately sizing their system and ensure proper system
performance. Better measures protect against price gouging by compiling and publishing data on
installed costs and encouraging multiple quotes.
i. Valuing incentives for providing ancillary grid benefits: Some jurisdictions have more recently
been developing VOST and Locational Valuation incentives that calculate system wide benefits of
distributed generation.
j. Ensure equitable access through fair queuing processes: Transparent queuing processes and fair
administrative processes that reduce opportunities for “gaming”.
k. Require modest, refundable “skin in the game” fees: Levy modest, refundable application fees
to encourage only serious project applications and reduce administrative burden.
In Alberta, the goal of PBI incentives should be to reduce payback periods to between 5-10 years and
provide sufficient revenue certainty for individuals, communities, businesses to obtain financing and make
investments. They should be of five to 10 year duration to provide additionality to other cost savings
components such as avoided grid power purchases and non-demand related variable transmission and
distribution charges.
7. Community Energy Regulation
“Public policy development is ultimately a process of synthesis, not analysis. This requires
stepping back to see a broader picture, one that considers multiple, often conflicting,
objectives. …. a rate design should:
a. Allow utilities to collect sufficient revenues to recover their costs and attract capital
from investors;
b. Send price signals that lead to economic rationing of resources
c. Be fair to consumers and the utility” (ECW, 2014, p.3)
Traditional ratemaking principles suggest fixed cost rate design provides stable revenue streams for
utilities allowing them to recover costs at low risk. This enables them to obtain low cost capital the
benefits of which with regulatory oversight are passed on to the ratepayers. From the standpoint of
utilities this is fair because they provide a standby energy service that is ready to meet customer needs at
the flip of a switch. However, high fixed charge rate design performs poorly in sending economic price

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signals for users to conserve. Customers, in turn, consider it unfair that reducing their consumption has
little impact on the bills they pay and the pollution their usage creates. [ECW, 2014, p.3-4]
Consistent with the goal of evolving towards a smarter grid, Alberta needs to move away from strict
adherence to traditional ratemaking principles and towards a next generation regulatory model that
allows WSPs to recover costs and make a reasonable return but is based on performance and locational-
valuation principles within the competitive power market.
“When designing PV property tax policies, policy makers must confront several
challenges. One is the diversity of PV technology and how it is employed by its owners.
Different technical configurations and ownership models may compel different property
tax treatments, and these variations need to be understood by policy makers and
reconciled with a range of potentially competing policy objectives (e.g., increasing local
revenue vs. decreasing tax burdens).” [NCSC, 2013, p.98]
Property taxes often represent a decisive cost for community energy projects and have been a thorny
issue for policymakers and solar system owners. [NCSC, 2013, p.6] Most states in the U.S. offer local
property tax exemptions or abatements for community energy in order to make them more affordable or
economically viable for retail, farm or commercial/industrial sites. Some exemptions apply when the
system is used to meet on-site electricity, heating, cooling, or general energy needs. An Alberta
community energy regulation should allow for exemptions from municipal or county property taxes or
other levies based on added value. [SEIA, 2016C]
SEIA has suggested the following rate design principles intended to properly value and encourage DER
and intended to provide a balance of fairness to both utilities and users. [SEIA, 2016C]:
a. Cover cost of service: Rates should allow utilities to recover approved costs and earn a
regulated return. The benefits of distributed generation should be properly calculated and
incorporated.
b. Right to reduce grid electricity use: Reductions in customer grid use due to onsite generation
should not be recovered as a utility cost. Exit fees or other charges that discourage
deployment of DER should not be allowed.
c. Rates should be based on marginal costs: Variable costs should be recovered through
volumetric (kWh) charges. Calculation of marginal cost-based rates should emphasize a long-
term perspective in which a utility can gradually upgrade with Smart Grid technologies.
d. Rates should be based on cost-causation principles: Costs should be related to the reason
they were originally incurred.
e. Properly price externalities: Market participants should bear the full environmental costs of
electricity service, including GHG emissions.
f. Cost allocation: Each customer class should be assigned its cost of service, consistent with
principles of equity and affordability. Cost shifts among and within classes should be avoided.
g. Reduce energy consumption and peak loads: Rates should provide incentive for customers
to reduce demand during higher-cost hours.
h. Send accurate and understandable price signals to customers: Rates should include accurate
price signals for peak, shoulder, and off-peak energy usage. Any use of dynamic pricing for
critical peak periods (as an overlay on TOU rates) should be well-defined and transparent to

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the customer. Rates should be understandable, enabling customers to respond by reducing
usage, shifting load profile, or installing on-site generation.
i. Enable Innovative Technologies: Offer TOU pricing for all customer classes to enable and
encourage consumers to take invest in DER and other smart grid technologies.
j. Provide Customer Education: Customer outreach and education regarding energy use, rates,
and energy options should be robust and validated.
k. Rate Transitions: Rate design changes should minimize impacts to existing customers. Net
energy metering customers should be allowed to remain on their current rate form, with the
option to move into new rate forms.
l. Transparency, access to data: Customers and third party owners should have access to data
regarding their own electricity consumption (e.g. hourly load profiles), with transparency into
the available tariffs. Customer class data including consumption, monthly coincident and non-
coincident peak demands, and load profiles should be available to aid in managing electricity
use and designing workable rate structures.
m. Consistency: Where possible, create consistency and predictability across the province by
implementing any changes uniformly for all WSPs whether investor owned, municipal or co-
operative
As Alberta moves beyond its current low stage of DER penetration, tension over the ability of WSPs to
recover costs and keep rates low for remaining customers is likely. Legislation and regulation that directs
the Alberta Utility Commission, AESO and WSPs to provide new community energy tariffs is required.
Alberta should create a community energy regulation by 2019 with rules that direct and incent Alberta’s
regulators, WSPs and other market participants to offer new tariff options to retail, commercial and
industrial users with features that will drive growth of DER. The regulation should be in place by 2019 and
evolve as learnings are acquired and Alberta catches up to successful North American jurisdictions that
have had a head start.
In the longer term beyond 2020, Alberta needs to fully embrace a modern electric utility regulatory cost
recovery and ratemaking model that is performance based and incents utilities to adapt to much higher
penetrations of community energy. This includes developing rate structures that use time-variant pricing
and locational valuation principles, integrating DER into resource planning processes and incorporating
new smart-grid technology and emerging standards into network operations.
8. Energy Storage
Energy storage systems interconnected to the grid are different from generation because in conjunction
with DG they will serve both load and generation functions with potential for providing ancillary services.
The interconnection process should reflect this distinction. Although still expensive, the cost of storing
energy in batteries and other technologies is rapidly falling and energy storage is becoming an important
pillar of DER, along with energy efficiency, demand response and solar PV.
“Distributed energy resources such as behind-the-meter battery energy storage have
matured faster than the rates, regulations, and utility business models needed to support
them as core components of the future grid.” [RMI, 2015, p.9]

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Integrating storage to a solar PV array adds tremendous value to community energy systems. At the retail
level it allows an alternative to net metering by charging during the day when usage is low and discharging
during spikes or in the evening when demand is highest. At the commercial/industrial level it allows for a
number of economic and load management strategies.
“Mandates and subsidies for energy storage, including customer-sited, behind-the-meter
installations, are on the rise. Where utilities employ demand charge rate structures, the
most economic use of energy storage for customers is often to reduce monthly maximum
demand.” [NREL, 2015B]
The range of value-added services that energy storage adds to users and the electric system is shown in
Figure 4. Fundamentally for customers, storage allows customers to lower power costs and achieve
independence from the grid. The reasons for adding storage [Enphase, 2016] include:
a. Self-consumption: Store generated energy to use later when needed. Changes in net metering
rates can make this worthwhile.
b. Time of use bill management: Store generated energy you generate or energy from the grid when
rates are low to use when electricity rates are higher. Shift energy demand away from utility
provided electricity when it costs the most. It can also mean selling electricity to the utility when
it is paying the most for its energy.
c. Demand Response and Peak Shaving: Reduce electricity use from grid during times of peak
demand by using energy stored in the battery. Demand charge reduction is the most compelling
business case for commercial/industrial users to install DER with storage. Some utilities charge
higher rates during extreme demand spikes or offer incentives to users who can decrease their
grid reliance at those times.
d. Backup service: Storage is used by a grid-tied system to provide energy during a power outage. In
general, batteries optimized for backup are different than those used for economic reasons, as
they require fewer cycles and should be fully charged at all times. In most cases, generators are a
better choice if customers are concerned about prolonged outages.
e. Off-grid: For areas without access to the grid.
At the community energy scale, customer behind-the-meter storage can provide a large number of
services to the grid, but may not be the lowest cost option. New interconnection processes with
implications for regulators and utilities will be needed depending on:
a. If the stored energy is intended to be exported into the grid or is non-exportable.
b. Whether the storage system is able to be charged from the grid or from a DG source, or both.
The Panel should consider regulatory barriers to DER scale energy storage. An important question will be
what role energy storage should have in in the medium term as community energy starts to grow in
Alberta but also in the longer term as the Smart Grid evolves? DER-scale energy storage can be deployed
behind the meter in or near residential and commercial/industrial sites. They can also be deployed within
the distribution system.

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Figure 4 - Energy Storage Services to BTM Distribution and Transmission Functions (RMI, 2015, p.19)

20. 20
California’s issued Rule 21 issued in June 2016 established a new process for reviewing interconnection
applications for non-exporting energy storage systems (i.e., storage systems connected to the grid that
do not provide stored electricity back to the grid). [IREC, 2016]
It is recommended the province continue with and accelerate the AESO study of Energy Storage
Integration but expand the scope of the process to include the value of DER scale energy and battery
storage. The province should establish processes for reviewing storage interconnection applications
related to DER scale energy storage systems that do not export power to the distribution system.
9. Valuing Community Energy
Under current technology, community energy is expected to consist primarily of solar photovoltaics (PV),
but also energy storage, electric vehicles (EV) and charging infrastructure, demand response, combined
heat and power, and other non-solar types of distribution generation. A recent survey shown in Figure 5
of electric utilities in the U.S “ranked solar photovoltaics as the technology with the highest potential
impact, with battery storage, demand response and electric vehicles also on their radar.”. [B&V-SEPA,
2016, p.3]
Figure 5 - Survey of U.S. Electric Utilities on which DER will be most impactful (B&V-SEPA, 2016, p.4)
“Rather than paying the customer the retail rate for power supplied to the utility, the
value-of-solar approach credits customers with the present value of the long-run system
costs that solar PV facilities help the utility avoid.” (ECW, 2014, p.4)
As the cost of solar PV has fallen and usage has increased, efforts to determine the overall long term value
to the grid of community energy are accelerating. Alberta’s regulators and industry players need to
evaluate the value of locating community energy close to where it is used. The tension between
regulators and utilities, caused by fears of net metering leading to cost recovery shortfalls and pushing
system costs unfairly onto a decreasing pool of legacy customers, may be giving way to new approaches.
“Value of Solar Tariffs” (VOST) in Texas and Minnesota goes beyond Net Metering by giving solar users a
credit that reflects the “present value of avoided costs that community energy brings to the overall electric
system while allowing utilities to recover fixed costs. VOST avoided cost components are shown in Table
4.

21. 21
Table 4 - Minnesota Value of Solar cost components (MDC, 2014, p.4)
“While still relatively rare, value-based approaches to determining bill credits represent
an intriguing means of arriving at a bill credit pricing mechanism that moves away from
utility embedded costs drawn from retail rates and towards approaches that rely more
on the value of the facilities to the utility and its ratepayers.” (IREC, 2013C, p.11)
California and New York have built on the VOST approach and have very recently introduced even newer
“Locational Valuation” rules that take into account not just solar but other forms of DER such as storage,
EV charging, energy efficiency, and demand response. It will also account for the additional value obtained
from investing in new data technology architectures, bringing DER onto the local distribution system and
integrating into grid and network operations. Figure 6 portrays the progression in generation valuation
that is taking place.

22. 22
Figure 6 - Evolution of Power Generation Resource Valuation (GTM Research, 2016B)

23. 23
10.Electric Utility Regulation in a Smart Grid World
“As DERs become more competitive, that fact alone will increasingly override the dominant role
of the utility and reduce the ability of regulators to influence the utility’s financial health. It will
increasingly be up to the utilities themselves to make business decisions that will enhance their
customers’ well-being while acting as responsible stewards for the capital entrusted to them by
their investors. Now is the time to carefully anticipate and prepare for the impacts of competitive
alternatives on traditional utility services, business practices and their regulation.” [LBNL, 2015,
p.48]
Community energy represents a large opportunity for utilities, retailers and other market participants to
offer new services and generate new revenue streams by actively participate in DER aggregation and
investing in smart grid network and communications technology, including smart PV inverters with robust
data collection and grid-support capabilities. A model portraying these opportunities is shown in Figure
7. The grid infrastructure in a DER world must become more resilient and intelligent to supply, gather and
distribute electricity flowing in a stable, consistent and reliable manner.
Recent economic analysis by the Future Electric Utility Regulation series published by the Lawrence
Berkeley National Laboratory suggests three major structural changes for the role and regulation of
electric utilities which will be forced by the wide-scale deployment of DER:
a. First, the emergence of competitive alternatives to energy and capacity supplied by the bulk power
system—the “grid”—will dramatically increase customers’ elasticity of demand for power, leading
to downward pressure on both utility profitability and cost structures. After a century of utility
concerns over whether rate increases will be high enough to allow full cost recovery, the
emergence of elastic demand for electricity will shift the focus to whether utility costs are simply
too high to be recoverable.
b. Second, while we see the bulk power system enduring, albeit with little growth, the natural
monopoly of the distribution utility will be eroded. However, even as distribution utility economies
of scale are undercut by new technologies capable of being offered by multiple firms, economies
of scope and coordination among these technologies will become increasingly important. DERs
will not only improve customers’ energy costs, resilience and power quality, they can help utilities
avoid risky capital expenditures and operate their systems more efficiently. By facilitating DERs,
utilities can both lower their costs and increase the benefits they can offer customers who deploy
DERs, providing an incentive to remain connected to the distribution system rather than defect
from it.
c. Third, the fundamental role of the utility will evolve to support this lower cost, higher value service
that can be provided when customer-facing DERs are coordinated to not only provide customer
services, but to create value for the distribution utility and grid as well. However, that evolution
may occur in different directions. One points towards a major utility presence in sourcing, financing
and optimizing DERs for customers. The other points towards a major role for competitive firms in
not only providing DERs through competitive channels, but also in competing to tailor DERs’
performance and optimize the total value they can create in this emerging, three-sided market
comprised of customers, distribution utilities and the grid itself. [LBNL, 2015, p.1]

24. 24
Figure 7 -DER Aggregation Opportunities for Utilities and Market Participants (GTM Research, 2016C)

25. 25
CONCLUSION
This submission has looked to the U.S state experience to suggest specific community energy
recommendations for that Alberta’s Energy Efficiency and Community Energy Panel can make. The Panel
is urged to take an expansive view of community energy that encompasses all distributed generation and
storage resources that will connect to the distribution system. Alberta is starting in 2016 from a very low
level of about 10 MW of DER.
Low prices for electricity are a major barrier to investment in renewable energy and DER. In the short
term until 2020, Alberta needs to modernize its enabling regulations and implement and experiment with
a variety of targeted rebate and incentive programs to kick start this industry. In the next decade, as coal
generation is phased out, Alberta will need to adopt new regulatory approaches and invest in smart grid
technology to create a cleaner and more locally generated electricity grid.
Whether Alberta’s electricity LDCs in the future play merely a passive, enabling role, or a more active one
in developing, owning and aggregating DERs, utilities will see their dominant role in the electricity system
diminished as DER deployment increases and becomes more competitive in cost.

26. 26
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