With half of 2018 already in the rearview mirror, we check
in on the top public utility commission (PUC) actions and trends so far this
year.
Not surprisingly, the challenges PUCs are grappling with are
diverse: moving toward a cleaner grid, adopting foundational electric vehicle
policies, investigating utility business model reforms, exploring the
integration of new technologies such as energy storage, and increasing customer
choice when it comes to sourcing their energy, just to name a few. Without
further ado, here is a status check on the top 10 matters before PUCs in 2018
so far.
1. Moving toward a cleaner grid
2018 has continued the trend in recent years toward a
cleaner grid, with more utilities announcing coal plant retirements and large
investments in renewable energy. In the first quarter alone, there has
been over $10 billion of new investment in renewables.
Large investments have largely been driven by falling costs, strengthened state
energy and environmental policies, and increased desire from customers for 100
percent renewable energy offerings.
In February, the California Public Utilities
Commission (CPUC) adopted a reference
system planthat the state’s load-serving entities will use to file their
integrated resource plans (IRPs) by August. With the plans intended to optimize
the utilities’ portfolios of resources to reach a variety of public policy
goals – most notably the goal of reducing economy-wide greenhouse gas emissions
40% from 1990 levels by 2030 – the reference system plan outlined a portfolio
of new resources by 2030 that consisted of 63% solar, 22% energy efficiency, 9%
storage, and almost 4% wind resources.
In March, the Virginia State Corporation Commission (SCC) approved Virginia
Electric and Power’s (Dominion Energy) 2018 to 2032 IRP, which included, among
other things, the development of at least 3,200 MW of solar by 2032 and 12 MW
of offshore wind as early as 2021. In a similar vein, the Idaho Public
Utilities Commission in April accepted Rocky
Mountain Power’s (PacifiCorp) 2017 to 2036 IRP, which called for 3,500 MW of
coal retirements through 2036; 1,100 MW of new wind and 905 MW of
upgraded/retrofitted wind resources by 2020; 859 MW of additional wind
generation after 2020; and 1,040 MW of new solar by 2036.
In March, the Arizona Corporation Commission (ACC) voted
down the utilities' IRPs on the grounds that they over-relied on
natural gas without adequate price sensitivity analyses. Then the ACC opened
a new
proceeding in May to amend and review Arizona's current resource
planning and procurement rules and align them with Commissioner Tobin's
proposed 80% by 2050 Clean Resource
Energy Standard and Tariff.
This summer has seen several noteworthy announcements as
well, most notably in Michigan and Colorado. In June, Consumers
Energy Co. in Michigan filed an IRP out
to 2040 that calls for 6,350 MW of solar (including 5,000 MW by 2030), 450 MW
of energy storage, and the retirement of two coal units by 2023 and another two
by 2031. Also in June, Xcel in Colorado filed a
Clean Energy Plan Portfolio as part of its 2017 IRP plan that proposed to
retire early two coal plants and replace them with 1,100 MW of wind, 700 MW of
solar, 275 MW of storage (all paired with solar), and 383 MW of flexible
natural gas assets.
Planning for electric vehicles
Electric vehicle (EV) adoption and integration have risen to
the fore in many jurisdictions, as improvements in technology have dramatically
expanded the EV market, states are turning to vehicle electrification to reduce
carbon emissions, and utilities are looking for new ways to increase
electricity sales. Actions have included statewide EV investigations to adopt
foundational EV regulation and policies, widespread electrification programs,
and a range of demonstration projects.
In January 2017, the three big investor-owned utilities
in California (San Diego Gas &
Electric, Pacific
Gas & Electric, and Southern California
Edison) filed transportation electrification proposals with the CPUC
totaling over $1 billion in investments. In January of this year, the
Commission approved 15
of 17 proposed priority review pilots, totaling $41 million, and in May the
Commission approved $738
million in investments for standard review projects and two rate design
proposals. The May decision is a big boost for the future of the EV market in
California, as it allows, among other things, San Diego Gas & Electric to
propose a performance incentive mechanism for its residential charging program.
Most recently, Southern California Edison in June proposed a
four-year, $760.1 million program focused on charging light-duty vehicles in
multi-unit dwellings and workplace settings that builds on their Charge
Ready Pilot approved in 2016.
In March, the Hawaiian Electric Companies (HECO)
filed an electrification
of transportation strategic roadmap to grow the EV market in Hawaii
and move the state closer to its goal of 100% renewable fuels in transportation
by 2045. Key parts of the roadmap include working with stakeholders to lower
the purchase price and educate customers on EVs, working with third parties to
facilitate the build-out of charging infrastructure, supporting a transition to
electric buses, creating grid service opportunities for demand response
participation and smart charging, and ensuring the smooth integration of EVs
through grid modernization investments.
Several states have also begun to investigate the role of
utilities in the EV market. In April, the New York Public Service
Commission opened a
proceeding to consider the role of electric utilities in providing
infrastructure, along with rate designs to accommodate the needs of and
electricity demand for EVs and electric vehicle supply equipment. In May,
the Nevada Public Utilities Commission adopted
rules allowing NV Energy to build EV charging stations and directed NV
Energy to use $15 million in existing incentive funds to help build out the
state's charging infrastructure. In June, the Vermont Department of Public
Service requested that the Public Utility Commission open
an investigation pursuant to H917 to examine issues related to EVs and
EV infrastructure.
Those are just a few examples, with developments over the
first half of 2018 also popping up in Colorado, Maryland, Michigan, Missouri, Oregon, and Pennsylvania.
Energy storage gaining momentum
The energy storage market has continued its recent momentum
into 2018. Driven by improving economics, a changing grid, and business model
and rate design changes, energy storage is increasingly being recognized as a
valuable and necessary asset for a 21st century grid.
Several states have opened broad rulemakings to refine their
energy storage frameworks or policies.
In late 2017, the Massachusetts
Department of Public Utilities opened an inquiry, with a subsequent straw
proposal issued in June, into the eligibility of energy storage
systems paired with distributed generation to net meter and whether these
facilities could be bid into the ISO New England Forward Capacity Market. In
January, California further refined its energy storage framework
by adopting rules to
govern the use of multiple-use energy storage applications (i.e., storage’s
ability to provide multiple value streams to the electricity grid). Also in
January, the Public Utility Commission of Texas dismissed
a request by AEP Texas North Company to install two battery storage
projects on their distribution system and announced it will open a new
rulemaking to look more broadly at how utilities can use non-traditional
technologies to solve distribution problems and the potential impact on the
competitive retail market and Texas’ wholesale market.
Most recently, in June, the New York Department of
Public Service and New York State Energy Research and Development
Authority (NYSERDA) filed a New
York energy storage roadmap to comply with Gov. Cuomo's 1,500 MW by
2025 target. The roadmap outlines the market-supported policy, regulatory, and
programmatic actions necessary to achieve the State’s near-term energy storage
installment goals and recommendations for the DPS to consider when designing
the energy storage program.
Changing the utility business model
We have seen continued conversation about the suitability of
the traditional cost-of-service regulatory model as the energy landscape
changes. Many states have already begun to move toward a system that better
reflects new market conditions, allows utilities to take advantage of the
growing service economy, and rewards performance against established goals
rather than inputs (see map for activity on performance-based regulation). At
AEE, we have been a part of the conversation (see our 21st century electricity system
issue briefs on performance-based regulation and optimizing capital
and service expenditures) to develop new utility business models that better
meet the changing expectations of consumers and society.
In May, the Pennsylvania Public Utilities Commission issued
a proposed
policy statement that invites utilities to explore alternative
ratemaking methodologies in their general rate cases to promote state and
federal policy goals, provide incentives to improve system efficiency, and
allow utilities to adequately recover their costs. The Commission also adopted
a motion by Vice Chairman Place that gives utilities the option to consider
alternative rate designs, performance incentive mechanisms, decoupling, and
demand-based and time-of-use pricing.
In April, the Public Utilities Commission of Hawaii opened
an investigation into performance-based regulation (PBR) policies for
HECO, specifically focusing on aligning utility incentives with performance on
desired outcomes, such as increased renewable energy, lower cost, and improved
customer service. And in June, National Grid in Rhode Island submitted
a settlement
agreement with Commission Staff, the Office of Energy Resources, and
several other parties that, if approved, would establish new performance
incentives for system efficiency and integration of renewable energy. The
settlement also includes, among other things, a commitment by National Grid to
make refinements to the business case for an advanced metering functionality
(AMF) roll-out, the adoption of data access rules, approval of $13.6 million in
grid modernization investments, and a three-year EV initiative.
Equalizing the treatment of capital and operating
expenditures
A key stumbling block in the traditional utility business
model is the inability of utilities to earn a return on operating expenditures,
such as fuel, labor, maintenance, and service expenditures (e.g., commonly
referred to as non-wires alternatives) – disincentivizing utilities from
procuring service-based solutions provided by third parties. This limits the
ability of utilities to take advantage of, and customers to benefit from, many
new technologies that are solely offered through service contracts with
specialized third party providers. States are starting to recognize these
obstacles and are exploring methods to overcome them. (See AEE Institute’s
recent report on Optimizing Incentives
for Capital- and Service-Based Solutions.)
In December, the Illinois Commerce Commission (ICC) initiated
a rulemaking on the regulatory accounting treatment of cloud-based
computing solutions (including software as a service [SaaS], platform as a
service [PaaS], and infrastructure as a service [IaaS]). In April, the ICC
issued a preliminary
proposed order (published in the Illinois
Register on July 6) on rules for the regulatory accounting treatment
for cloud-based computing solutions that offers more equitable financial
treatment of cloud-based solutions utilities use to manage delivery, operations,
and customer service.
In December, based on the Smart
Grid Policy Act of 2010, and following a multi-year stakeholder process,
the Maine Public Utilities Commission designated Central Maine Power
and Emera Maine as non-transmission alternatives coordinators, in order to
develop cost-effective substitutes for traditional transmission projects in the
Pine Tree State. As a result, in June the utilities filed recommendations for
a rate incentive proposal that would eliminate the existing incentive for them
to favor transmission and distribution investments over NWAs.
Distribution system planning
States have recently begun to reconsider how they undertake
distribution-level resource planning, spurred on by rapid improvement in
advanced energy technologies and an influx of distributed energy resources. By
expanding distribution planning to consider distributed energy resources, in
addition to traditional infrastructure investments, and by properly valuing
those distributed assets for both their costs and the benefits they provide,
the grid can become more flexible, reliable, resilient, and clean, all while
saving money for customers.
In April, staff of the Missouri Public Service
Commission submitted a report in
the
Commission’s comprehensive modernization proceeding with recommendations to
develop a more detailed analysis on the needs, costs, and benefits associated
with distributed energy resources and the development of an integrated
distribution system planning process. Following the report, the Commission
issued for comment draft
rules regarding the treatment of distributed resources to facilitate a
more holistic distribution system planning process.
Also in April, the Minnesota Public Utilities
Commission staff issued a report that
proposes draft integrated distribution plan processes for the state's
utilities. Filing requirements differ by utility but include: 1) planning
objectives, 2) processes for developing distribution plans, including
stakeholder engagement, 3) baseline distribution system, distributed energy
resource (DER) deployment, and financial data requirements, 4) hosting capacity
and interconnection requirements, 5) DER futures analysis, 6) long-term
distribution system modernization and infrastructure investment requirements,
and 7) non-wires alternatives analyses.
Finally in May, the Connecticut Public Utilities
Regulatory Authority set the scope of its distribution planning
process. Specifically, the process will cover the key cost drivers of
maintaining and modernizing the distribution system, how demand and consumption
patterns are changing and how distribution system planning can change to
address these needs, and the current state of the grid and what is needed to
optimize the grid of the future.
Moving to time varying rates
New technologies – especially the rise in customer-sited
distributed generation such as rooftop solar – and the rising differential
between average and peak demand in many states and service territories have led
utilities to propose new rate designs that better align with the changing
energy landscape. Specifically, states have been looking to more sophisticated
rate designs that send price signals to customers that align with public policy
goals.
Just before the new year, the big three investor-owned
utilities in California (Pacific Gas and Electric, San Diego Gas and
Electric, and Southern
California Edison) all proposed plans to move to default residential
time-of-use rates, albeit on a different time horizon than originally planned
by the Commission. An earlier decision ordered
the utilities to move to default time-of-use rates by 2019; however, not all
utilities followed suit (and the Commission subsequently
approved alternative rollout plans in May). Pacific Gas & Electric
proposed a preferred October 2020 roll-out, saying it would allow it to conduct
a less rushed and more thoughtful marketing campaign. Southern California
Edison proposed a 15-month transition plan to move customers to the default
time-of-use rate, starting in October 2020 – asking for a later start to allow
for replacing an obsolete billing and customer care system with a modern
platform before implementing a new rate design. Finally, San Diego Gas &
Electric proposed a 10-month migration (marketing, education, and outreach)
plan to move customers to the default time-of-use rate starting in 2019.
In one of the more innovative rate design pilots developed
to date, the Minnesota Public Utilities Commission approved Xcel
Energy’s two-year residential time-of-use rate design pilot in May. The pilot
will be an opt-out program to be rolled out as early as 2020 in two communities
in the Minneapolis area for a maximum of 10,000 customers including deployment
of advanced meters for participants. The pilot will include three different
rates – an on-peak rate (average of 23.82 cents per kWh), a mid-peak rate
(average of 11.07 cents per kWh), and an off-peak rate (average of 5.68 cents
per kWh).
Valuing net metering
Net energy metering (NEM) has been widely successful in
spurring the adoption of distributed solar across the country. However, as the
number of NEM customers increases, pressure has been building in various
jurisdictions to consider alternative rate designs and successor tariffs for
NEM customers. Over the past couple of years, we have seen several states take
different approaches to successor tariffs to NEM, including reductions in net
metering rates for exported electricity and development of more granular
methodologies for determining the value of distributed generation on the grid.
This year, we are seeing much the same thing, with mixed results for customers.
In March, NorthWestern Energy in Montana filed a cost-benefit
analysis, prepared by Navigant Consulting, calculating the value of
solar energy put back on the grid at $0.04 per kWh, significantly lower than
the $0.12 per kWh that NorthWestern Energy currently credits customers. NEM advocates,
including distributed solar companies and their customers, will likely contest
this assessment in the utility’s next rate case.
In Arizona – long ground-zero in the NEM debate –
an Administrative Law Judge issued a recommended decision in April in
both Tucson
Electric Power (TEP) and UNS Electric’s solar
rate cases, which would establish solar export rates (9.64 cents per kWh for
TEP and 11.5 cents per kWh for UNS Electric) for NEM customers, with these
rates reset in the future based on a five-year average of utility-scale solar
generating costs (with decreases capped at 10% per year and new customers locked
into their rates for 10 years from interconnection); also recommended was a new
$2.33 monthly meter fee for residential customers with solar. After a backlash
from solar advocates, the Commission has still not voted on the recommended
decision.
There have been actions to reassess NEM in other states as
well, for example in Idaho, where the Public Utilities Commission announced it
will open a new docket to study the costs and benefits of net metering on Idaho
Power's system (including all net metered assets and not just on-site solar),
proper rates and rate design, and compensation for net excess energy provided
back to the grid. Also, in April, the Michigan Public Service Commission approved a new
residential distributed generation tariff that requires new NEM customers to
purchase energy from the grid at the retail rate but receive credit for excess
electricity generated only at the utility avoided cost rate. The new tariff
directly resulted from a February
2018 legislatively mandated study on the costs and benefits of
distributed generation.
A few other states are investigating NEM frameworks that are
structured to account more precisely for the value that DER provides to the
system – both locational and temporal – to address concerns about impacts on
non-DER customers without depriving DER customers and the system as a whole of
the value they bring. Most
notably, New York has been deep in the weeds investigating a
“value stack” methodology that moves beyond some of the aforementioned
transitional net metering-style rate designs. New York Commission staff is
expected to issue a whitepaper by the end of July with recommendations on a
successor compensation methodology.
Raising energy efficiency targets
Energy efficiency has undergone significant changes in
response to developments in technologies, markets, and public policies, with
states continuing to see its value. Energy efficiency is most commonly thought
of as ways to reduce energy use relative to traditional technologies, such as
LED lighting and high efficiency appliances and heating and cooling equipment.
But today, energy efficiency can be accomplished through a variety of means,
including the use of sophisticated energy management systems,
internet-connected thermostats, and data analytics.
In April, New York Gov. Cuomo announced a
new energy efficiency target, reducing energy consumption by 3% of annual
utility sales by 2025 – a 40% acceleration of energy efficiency compared with
business as usual. In May, the CPUC approved new
rolling energy efficiency business plans through 2025 for California’s eight
program administrators, including the large investor-owned utilities. In
June, Ameren Missouri filed a $550 million demand-side
management portfolio and plan through 2024 that, if approved, would be
the largest energy efficiency program in Missouri history.
However, in one special case, a state’s energy efficiency
efforts were put on ice. In January, the Kentucky Public Service
Commission issued a final
order discontinuing all of Kentucky Power's demand-side management
(DSM) programs except one, totaling about $2 million, targeting low-income
customers, until there is shown to be need for additional generation to meet
demand. The region has been in a sustained economic decline and the cost of
Kentucky Power's DSM programs has increased from $0.51 per month to $10.61 per
month for average customers because of a 2013 decision allowing Kentucky Power
to acquire a stake in a large coal plant provided it increased DSM spending to
at least $6 million in 2018 and beyond.
Increasing access to renewable energy
As renewable energy has become more competitive on price and
more corporations have set sustainability targets, large customers are looking
for ways to power their operations with 100% renewable energy. To give these
customers the renewable energy they want, utilities in vertically integrated
markets are developing new direct access programs and renewable energy tariffs.
In January, Public Service Co. of New Mexico filed
an application, which was approved in
March, for three power purchase agreements (PPAs) – 50 MW of wind power and 1
MW of storage from Casa Mesa Wind for 25 years, 166 MW of wind from Avangrid
Renewables for 20 years, and 50 MW of solar from Route 66 Solar Energy Center
for 25 years – to power Facebook’s data center in Los Lunas through a special
services contract. In its approval, the Commission cited the various benefits
of the special contract, most notably $72 million in investment for New Mexico
from Casa Mesa Wind, $75 million for the Route 66 Solar Energy Center, $500
million for the Avangrid Renewables project, as well as $1 billion for the data
center itself.
Also in January, Duke Energy Carolinas and Duke Energy
Progress jointly filed a petition for
a 600 MW Green Source Advantage Program in North Carolina, meeting HB
589's requirement to develop a renewable energy program for the
state's military, University of North Carolina System, and large nonresidential
customers.
In March, the Virginia Corporation Commission approved Dominion
Energy’s proposed RF tariff, targeting commercial and industrial customers for
a five-year period. The tariff will allow Schedule RF customers to pay for and
receive the environmental credits associated with new renewable energy that is
developed for their incremental energy needs, with the remaining output used as
a system resource. In May, the Oregon Public Utilities Commission opened
a new proceeding to address Portland General Electric Company's proposed green
tariff filed in UM-1690,
which would allow large businesses and municipal customers to source their
energy from new renewable sources under five, 10, 15, or 20-year contracts.
Finally, in June, Ameren Missouri, Commission Staff and
several other parties filed a non-unanimous stipulation
(subsequently approved)
that adopted a voluntary renewables program open to large customers with at
least 2.5 MW of peak annual demand and any governmental entity regardless of
size. Customers will be able to subscribe for up to 100% of their load for a
15-year contract at a fixed price based on the wholesale market price in that
month.
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