Stakeholder Comments

Draft ISO Board Vision Paper

Electricity 2030: Trends and Tasks for the Coming Years

November 28, 2017

The California ISO has received Stakeholder comments regarding the Draft Board

Vision Paper - Electricity 2030: Trends and Tasks for the Coming Years, which was

released on October 4, 2017.

Please find attached the complete set of comments received by Stakeholders,

which will be shared with the ISO Board of Governors for consideration in the

evolution of the vision document.

SUBMITTED ELECTRONICALLY AT INITIATIVECOMMENTS@CAISO.COM

Joint Comments of Alliance of Automobile Manufacturers and Association of Global Automakers on Draft ISO Board Vision Discussion Paper

November 20, 2017

The Alliance of Automobile Manufacturers1 (Alliance) and the Association of Global Automakers2 (Global Automakers) appreciate the opportunity to provide these joint comments to the California Independent System Operator (ISO) Board of Governors and Management on the Draft ISO Board Vision Paper. The current draft document clearly lays out some of the major “Trends” and “Tasks” facing CAISO as the organization moves towards 2030.

Our two associations represent nearly every car and light-truck manufacturer and about 99% of the new vehicle market in California. Our manufacturers are offering a wide range of fuel-efficient and advanced-technology vehicles, including over 30 models in various vehicle segments of plug-in hybrid, battery, and fuel cell-electric vehicles. Based on manufacturer announcements, the California Air Resources Board estimates that by 2021, there will be 80 different electric-drive vehicles for sale in the market.3 There is an undeniable trend in both the market and in the regulatory environment toward greater electrification – hydrogen and grid-powered – of the vehicle fleet. Vehicle electrification will not happen in isolation, and dedicated efforts to create consumer awareness, provide consumer incentives, and develop hydrogen and electric grid infrastructure are critical to supporting and growing the market.

Based on the draft document, we would like to make the following recommendations:

The Paper Should Consider the Benefits of Hydrogen for Vehicles and Stationary Storage

Virtually every major car company is currently pursuing a variety of vehicle electrification strategies, including plug-in hybrids (PHEV), fully battery-electric vehicles (BEV), and hydrogen fuel cell-electric vehicles (FCEV). The California Energy Commission (CEC), Air Resources Board (ARB), and other stakeholders are supportive of this multi-faceted technology approach. The Alliance and Global Automakers believe that a variety of options and technology types are likely needed to support long-term environmental goals and thus have been working with legislators, regulators and other stakeholders to build markets that will support all electric-drive technologies. At present, the Draft Vision Paper does not address the potential impacts of hydrogen for vehicle electrification or stationary applications.

1 Alliance members are BMW Group, Chrysler Group LLC, Ford Motor Company, General Motors, Jaguar Land Rover, Mazda, Mercedes-Benz USA, Mitsubishi Motors, Porsche, Toyota, Volkswagen, and Volvo. 2 Global Automakers’ members include Aston Martin, Ferrari, Honda, Hyundai, Isuzu, Kia, Maserati, McLaren, Nissan, Subaru, Suzuki, and Toyota. For more information, please visit www.globalautomakers.org. 3 California Air Resources Board. “California’s Advanced Clean Cars Midterm Review Summary Report for the Technical Analysis of the Light Duty Vehicle Standards,” 2017, at ES-41.

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The Introduction and Trends 4, 7, and 8 should acknowledge that some portion of electric vehicles (EV) in the market will be fueled by electricity produced by hydrogen onboard the vehicles. This could include renewable hydrogen produced by electrolysis of renewable electricity or other means. The portion of the EV market that will be hydrogen fueled is readily available from the ARB and CEC through their ZEV regulations and annual AB-8 report. This inclusion ensures that stakeholders reading the Vision Paper understand that not all EVs will be BEVs or PHEVs, and will plan electricity grid upgrades, Integrated Resource Plans, etc. appropriately.

Similarly, Trends 4, 5, and 7 should acknowledge that stationary hydrogen fuel cells could provide equivalent benefits to batteries and other forms of energy storage. In some applications, stationary fuel cells could be a more appropriate solution. For example, stationary hydrogen fuel cells can provide essential energy storage solutions for intermittent renewable energy. This is especially true for energy storage or energy shifting that is necessary for periods of weeks and months, where the function is superior to batteries. As California approaches its 50% renewable target, the importance of these technologies will only continue to increase.

The Paper Should Encourage Dialogue with Automotive Companies on Vehicle-Grid Issues

Trend 7 discusses how EVs could charge intelligently in order to absorb excess renewable generation, reduce peak demand, and optimize the overall grid. While grid services could be a secondary revenue source for EVs, facilitating markets and services for low carbon and zero carbon transportation should be the ultimate driver.

An owner of an EV counts on it to provide reliable transportation. This is the case both for individually-owned vehicles, as well as vehicles operating as part of a fleet or shared mobility application. Grid services, such as controllable charging (V1G), are a potential secondary revenue source for vehicle owners that also provide a benefit to CAISO. Regardless of the specific technological application, CAISO’s approach should ensure that the needs and preferences of the vehicle owner, such as a full charge by a certain time, are paramount.

To this end, we propose that CAISO include collaboration and discussion with automotive companies as a bullet point in the Tasks section of Trend 7. In addition, the Guiding Questions section should also explore:

• What new or existing grid services would be most effective for EVs to participate in • What impact would time of use rates have on EV charging behavior, specifically at TOU off-peak

start times • How the CAISO could signal a need to demand increase (also called “reverse demand

response”) to EVs to help alleviate renewable energy curtailment and maximize carbon-free mobility

• How to minimize any impact grid services could have on EV owners use of their vehicles

By better understanding EV load and its potential for responding to renewable generation, CAISO will better understand its future market participants.

Additionally, the Alliance and Global Automakers recommend that CAISO consider adding a new Task to conduct consumer education and awareness activities. To help support the ongoing rollout of EVs in the market, there cannot be an assumption that consumers will learn on their own about grid services.

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There needs to be proactive consumer education about how consumers can leverage their EVs to benefit from grid services, and CAISO may be well positioned to help fulfill this role.

The Paper Should Balance CAISO’s Vision with Its Role as a System Operator

The paper acknowledges that “many of the actions suggested herein are not within the purview of the ISO.” Indeed, Trend 7’s Task and Guiding Question sections on incentives for EVs and EV infrastructure fall well outside of CAISO’s responsibility and authority. As explained above, vehicle electrification in California will include PHEV, BEV, and FCEVs, and will require incentives and investments for all types of infrastructure. CAISO’s recommendations on transportation incentives, infrastructure support mechanisms, etc. should acknowledge this reality.

Furthermore, CAISO should consider whether it is appropriate for a nonprofit grid operator to endorse subsidies and other support mechanisms that would have a direct impact on CAISO’s own market participants. We believe that CAISO should remain aware of the subsidies and study them on their own merits, but refrain from supporting those that favor one type of vehicle over another. Through these studies, CAISO can help policy makers, market participants, and other stakeholders better understand the impacts of vehicle electrification on electricity markets and transmission.

Thank you for your consideration of our comments.

Sincerely,

Steve Douglas Julia M. Rege Senior Director Director Alliance of Automobile Manufacturers Association of Global Automakers (916) 538-1197 (202) 650-5555 sdouglas@autoalliance.org jrege@globalautomakers.org

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Department of Energy

Bonneville Power Administration

P.O. Box 3621 Portland, Oregon 97208-3621

November 20, 2017

Stakeholder Comments on California ISO’s October 2017 Discussion Paper: Electricity 2030, Trends and Tasks for the Coming Years

Submitted by Company Date Submitted

Doug Marker Intergovernmental Affairs drmarker@bpa.gov

Bonneville Power Administration

November 20, 2017

Thank you for the opportunity to comment on the California Independent System Operator (CAISO) Discussion Paper, Electricity 2030 - Trends and Tasks for the Coming Years (2030 Paper). Bonneville Power Administration (Bonneville) submits the following comments for consideration. Bonneville appreciates the work of the CAISO leadership and staff to develop this framework of issues for decentralized, low-carbon grid. As the operator of a publicly-owned, neighboring balancing authority, it makes sense for CAISO and Bonneville to seek opportunities for coordination and collaboration across the region to develop compatible operational and commercial solutions to emerging regional electricity issues. It is important to acknowledge that California’s electric system is connected to the rest of the Western Interconnection and the solutions to issues described in the paper cannot be resolved in isolation. This is especially important as California experiences an increasingly decentralized electricity delivery model, and yet seeks to develop west-wide solutions to optimize the use of new carbon-free generating resources. Concerns for decentralized electric service delivery: Bonneville observes the accelerating trend in California for electricity service to be procured directly through local agencies, primarily Community Choice Aggregation, and through direct retail access. Similar initiatives are underway elsewhere in the West. Bonneville provides electric service at wholesale, and so does not have immediate involvement in this issue as a power marketer. However, Bonneville is concerned that such new service may not incorporate full costs of and responsibility for providing reliability services. It is common, for example, for comparisons of electric service pricing to be based on the current short-term market as if the provision of essential reliability services comes without charge from a

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“commons” of bulk system resources provided by the broader interconnected system. Such services have traditionally included operating reserves, regulation, and frequency response and have been the responsibility of traditional load serving entities. In an evolving model for highly decentralized service, essential reliability services will also include intra-hour flexibility and ramping capability. It is important that these services be secured through supply obligations of retail service contract providers. This type of structure will promote investment in generation resources, demand response, and market purchases from physical resources or the equivalent new technology (i.e. batteries), that can provide the service. It is also essential through regional collaboration to identify where responsibility for enforcement of this resource adequacy obligation resides. Market access for affordable, low-carbon, resources to reliably integrate variable renewable generation: The 2030 Paper recognizes that regional sharing of flexible resources holds promise for reducing the need for gas-fired generation to reliably integrate increased production of variable renewable generation. Existing out of state hydroelectric resources, including surplus output of the federal hydro system, could assist in providing a cost-effective resource to help meet these needs. It is increasingly important to incorporate efficient access to out of state hydroelectric resources in California’s market design. Bonneville continues to work with California’s energy agencies on new concepts and opportunities to match hydro resources’ unique capabilities with California’s needs to reliably integrate increasing amounts of variable renewable resources. Bonneville appreciates that CAISO included the importance of regional operational and policy coordination in the 2030 Paper. Carbon credits for imports: For some time, the CAISO and the Air Resources Board have sought a solution for reporting and crediting out-of-state resources imported through the Energy Imbalance Market (EIM). Bonneville urges the ISO to maintain attention and resources to solving how to accurately and equitably assign green house gas (GHG) emissions associated with out-of-state resources in the EIM. While the current solution is acceptable for the short term, a long-term approach that properly assigns carbon content is needed to appropriately credit resources of zero or very low carbon content and achieve the state’s desired GHG reduction goals.

November 20, 2017 California Independent System Operator Corp. 250 Outcropping Way Folsom, CA 95630 initiativecomments@caiso.com

Re: CalETC Comments on Cal ISO Discussion Paper – Electricity 2030, Trends and Tasks for the Coming Years

The California Electric Transportation Coalition (CalETC) appreciates the opportunity to provide feedback on the California Independent System Operator (Cal ISO) Discussion Paper: Electricity 2030, Trends and Tasks for the Coming Years (Discussion Paper). CalETC supports and advocates for the transition to a zero-emission transportation future as a means to spur economic growth, fuel diversity and energy independence, ensure clean air, and combat climate change. CalETC is a non-profit association committed to the successful introduction and large-scale deployment of all forms of electric transportation including plug-in electric vehicles of all weight classes, transit buses, port electrification, off-road electric vehicles and equipment, and rail. Our board of directors includes: Los Angeles Department of Water and Power, Pacific Gas and Electric, Sacramento Municipal Utility District, San Diego Gas and Electric, Southern California Edison, and the Southern California Public Power Authority. Our membership also includes major automakers, manufacturers of zero-emission trucks and buses, and other industry leaders supporting transportation electrification. Although California is leading the nation in ZEV adoption, our state still has a long way to go to reach the goals in the Governor’s Executive Order B-16-2012: 1.5 million ZEVs on California roads by 2025 and zero-emission vehicle infrastructure able to support 1 million vehicles by 2020. In addition, the state must implement SB 1275 (De León, 2014) and SB 1204 (Lara, 2014), which set targets for the deployment of 1 million zero- and near-zero-emission vehicles by 2023, access to these vehicles by disadvantaged and low- and moderate-income communities, and deployment of zero- and near-zero-emission medium- and heavy-duty vehicle technologies. In addition, SB 350 (De León) [Chapter 547, Statutes of 2015] authorizes and directs utilities to implement transportation-electrification programs, and recognizes the need for widespread transportation electrification in order to reach many of the state’s goals, such as reducing petroleum use, meeting air-quality standards, improving public health, and achieving greenhouse-gas emissions reductions. Achieving widespread electrification will require the Cal ISO, state agencies, automakers, third-party charging providers, electric utilities, and a broad coalition of stakeholders to work collaboratively to advance the market for plug-in electric vehicles (PEVs).

California Independent System Operator November 20, 2017 Re: Discussion Paper – Electricity 2030, Trends and Tasks for the Coming Years Page 2

We respectfully submit the following comments for your consideration: Demand: Considering Energy Usage and Grid Services of Plug-In Electric Vehicles We agree with and support Cal ISO’s emphasis on transitioning from fossil fuels to electricity in the transportation sector. We also agree with the assessment in Trends 4 and 7, that as the PEV market continues to grow, PEVs will become increasingly important to manage load, through smart charging and the ability to utilize and store excess renewable generation. The potential for PEVs, in all weight classes, to act as widely dispersed and dispatchable storage will continue to grow as adoption of these vehicles accelerates—using PEVs as grid resources will help reduce peak electricity demand, optimize and balance the electrical system, and allow the grid to more efficiently and effectively utilize higher levels of renewables. Utilities, automakers, and others are collaborating through the Vehicle-Grid Integration Communications Protocol Working Group, as well as through other forums, to determine how best to future-proof investments to support communications between electric vehicles and the grid, so that PEVs can provide enhanced grid services. Even without vehicle-to-grid (V2G) charging and discharging of PEV batteries, V1G (unidirectional power flow) smart charging and controllable demand (e.g., through time-of-use rates) are extremely valuable to manage grid conditions, including excess renewable generation. Regarding the idea to base state planning on total energy use, instead of electricity and non-electricity energy use, we recommend using greenhouse-gas (GHG) emissions as the primary and more accurate metric in state planning instead of energy use. Using GHG emissions as the primary metric will ensure that we continue to work toward our state GHG-reduction goals within all sectors. Energy use and GHG emissions often mirror each other, but they are not always the same. For example, in the electric sector, utility-specific GHG emissions are higher than for locations or customers that use 100 percent renewables. The California Air Resources Board has the emission factors for all types of fuels as part of their Low Carbon Fuel Standard. Electric Vehicle Growth: The Need for Public and Private Partnerships and Investment The Discussion Paper assumes that PEVs will rapidly replace internal-combustion engine vehicles, comprise the bulk of new vehicle sales, and represent a significant share of cars on the road in California by 2030. While our and others’ efforts seek to achieve these goals, we cannot take for granted that this transition will occur. To realize this goal, we must continue and expand public and private partnerships and investments. To achieve widespread transportation electrification, among the light-, medium-, and heavy-duty sectors, we will need a consistent commitment by the state to incentivize adoption of these vehicles and incentivize installation of charging infrastructure. Stable, predictable, and consumer-friendly funding is essential to incentivize customers, fleets, manufacturers, and others that are supporting the clean-transportation market. Private investment follows clear, consistent public

California Independent System Operator November 20, 2017 Re: Discussion Paper – Electricity 2030, Trends and Tasks for the Coming Years Page 3

commitment and investment. We support the Discussion Paper’s recognition of this important point. California’s utilities are currently investing millions, and the investor-owned utilities are proposing to invest over a billion, to support the transition to clean transportation. In addition, proper rate design also helps advance electrification of the transportation sector. Grid-integrated charging provides the price signals to incentivize customers to charge at the times of day that optimize the use of renewables and lower-cost resources, which saves customers money. We support the Discussion Paper’s proposed task for utilities to continue to support the transition to advanced transportation. Support from the utilities, automakers, charging-station providers, and others is and will continue to be imperative to reach our clean-energy and clean-transportation goals. In addition to investment, California must continue to adopt and implement policies to achieve and resolve barriers to widespread transportation electrification. The Discussion Paper mentions construction codes in quite a few places relating to energy efficiency and Zero Net Energy Buildings. In addition to achieving these goals, Building Codes are an appropriate mechanism to build out and increase access to charging infrastructure. The Green Building Code currently requires a certain level of “PEV-readiness,” or installation of the infrastructure to support future PEV charging stations, for new construction. Using the Building Code to require the infrastructure to support future charging stations in new and existing construction is one example of a way to reach our PEV targets. As policies to support Zero Net Energy Buildings are considered, they must ensure against dis-incentivizing on-site charging infrastructure, e.g. charging infrastructure cannot be a barrier to achieving Zero Net Energy Building status. Thank you for your consideration of our comments. We look forward to continuing to collaborate on ways to achieve our shared goals. Please do not hesitate to contact me if you have any questions.

Sincerely,

Hannah Goldsmith, Project Manager California Electric Transportation Coalition

Main Office: 18847 Via Sereno DC Office: 1211 Connecticut Ave NW, Ste 650 Yorba Linda, CA 92886 Washington, DC 20036

Phone: (310) 455-6095 | Fax: (202) 223-5537

info@californiahydrogen.org | www.californiahydrogen.org

California Hydrogen Business Council Comments on California ISO Electricity 2030 Trends and Tasks for

the Coming Years

Comments prepared and submitted on November 20, 2017

The California Hydrogen Business Council (CHBC) appreciates the opportunity to comment on the California Independent System Operator “Electricity 2030” Discussion Paper. The CHBC is a California industry trade association with a mission to advance the commercialization of hydrogen in transportation and stationary sources to reduce greenhouse gas, criteria pollutant emissions and dependence on fossil fuels. Our more than 100 members include fuel cell and electrolyzer companies, auto manufacturers, industrial gas companies, and natural gas companies with an interest in hydrogen and hydrogen infrastructure in California1.

We believe the California ISO’s Discussion Paper has identified key trends affecting the electricity sector. The paper would be strengthened by incorporating renewable hydrogen and fuel cell technology, which are important tools to help decarbonize, decentralize and regionalize California’s electrical system and energy

1 The views expressed in these comments are those of the CHBC, and do not necessarily reflect the views of all of the individual CHBC member companies. Members of the CHBC include Advanced Emission Control Solutions, Air Liquide Advanced Technologies U.S. LLC., Airthium, Alameda-Contra Costa Transit District (AC Transit), American Honda Motor Company, Anaerobe Systems, Arriba Energy, Ballard Power Systems, Inc., Bay Area Air Quality Management District, Beijing SinoHytec, Black & Veatch, BMW of North America LLC, Boutin Jones, Cambridge LCF Group, Center for Transportation and the Environment (CTE), CNG Cylinders International, Community Environmental Services, CP Industries, DasH2energy, Eco Energy International, LLC, ElDorado National – California, Energy Independence Now (EIN), EPC - Engineering, Procurement & Construction, Ergostech Renewal Energy Solution, EWII Fuel Cells LLC, First Element Fuel Inc, FuelCell Energy, Inc., GenCell, General Motors, Geoffrey Budd G&SB Consulting Ltd, Giner ELX, Gladstein, Neandross & Associates, Greenlight Innovation, GTA, H2B2, H2Safe, LLC, H2SG Energy Pte Ltd, Hitachi Zosen Inova ETOGAS GmbH, HODPros, Horizon Fuel Cells Americas, Inc., Hydrogenics, Hydrogenious Technologies, Hydrogen Law, HydrogenXT, HyET - Hydrogen Efficiency Technologies, Hyundai Motor Company, ITM Power Inc, Ivys Inc., Johnson Matthey Fuel Cells, Kontak, LLC, KORE Infrastructure, LLC, Life Cycle Associates, Linde North America Inc, Longitude 122 West, Inc., Loop Energy, Luxfer/GTM Technologies, LLC, McPhy Energy, Montreux Energy, MPL Consulting, Inc., National Renewable Energy Laboratory (NREL), Natural Gas Fueling Solutions – NGFS, Natural Hydrogen Energy Ltd., Nel Hydrogen, New Flyer of America Inc, Next Hydrogen, Noyes Law Corporation, Nuvera Fuel Cells, Pacific Gas and Electric Company - PG&E, PDC Machines, Planet Hydrogen Inc, Plug Power, Port of Long Beach, PowerHouse Energy, Powertech Labs, Inc., Primidea Building Solutions, Proton OnSite, RG Associates, Rio Hondo College, Rix Industries, Sacramento Municipal Utility District (SMUD), SAFCell Inc, Schatz Energy Research Center (SERC), Sheldon Research and Consulting, Solar Wind Storage LLC, South Coast Air Quality Management District, Southern California Gas Company, Sumitomo Corporation of Americas, Sunline Transit Agency, T2M Global, Tatsuno North America Inc., The Leighty Foundation, TLM Petro Labor Force, Toyota Motor Sales, United Hydrogen Group Inc, US Hybrid, Verde LLC, Volute, Inc., WireTough Cylinders, LLC, Zero Carbon Energy Solutions.

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transition. The document currently omits renewable hydrogen and fuel cells entirely, although these technologies are integral to state energy policy and have many relevant and versatile applications, including:

• Microgrids • Integrating renewable electricity generation • Energy storage • Zero emissions transportation • Decarbonizing gas power generation • Providing large scale, controllable demand • Zero greenhouse gas industrial uses • Ancillary grid services at any time scale

Note that renewable hydrogen can be produced from biogas, syngas made from bio-waste, or using renewable electricity via electrolysis that splits water into hydrogen and oxygen - a process called power-to-hydrogen or power-to-gas (P2G). While all these pathways have value, P2G holds the largest volume potential, due to the limited amount of available organic waste. Therefore, these comments focus mostly on the P2G pathway.

Summary The following is a summary of the multiple applications for renewable hydrogen, followed by specific proposed edits to the Electricity 2030 Discussion Paper. The major themes in the suggested changes are:

• To be consistent with state policy, we request that deployment of fuel cell electric vehicles and hydrogen stations be considered on equal footing as plug-in and battery electric vehicles and charging stations as the California ISO explores opportunities for a more secure, sustainable, and affordable electric service. More specifically:

1) While the term “electric vehicle” encompasses both fuel cell and battery technologies, “zero emissions vehicle (ZEV)” is a more appropriate term used by other state agencies, as it leaves less room to interpretation. When discussing a vehicle’s energy storage, we request you use the term “storage” instead of “batteries” in order to avoid any potential technology bias but remain technology neutral. 2) In several places, the report should also include hydrogen production to meet ZEV fueling requirements with efficient dispatching of grid resources. 3) Moreover, smart-charging and time-of-use incentives can apply to hydrogen stations, with either on-site production via electrolysis or by controlling compression equipment. In fact, these incentives can have a larger impact when used at a hydrogen station that supplies fuel for hundreds of vehicles rather than charging of an individual vehicle. 4) Lastly, deployment of hydrogen stations is as essential as deploying charging infrastructure, particularly in dense urban areas that lack private parking, in rural areas where people drive long distances, and for medium- and heavy-duty vehicles.

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• To be technology neutral, where biogas and biofuels are considered, such as for decarbonizing gas generation or heavy duty vehicles, so too should a broader range of renewable gases, including bio-based and electrolytic hydrogen, that are able to provide comparable services.

• When discussing system storage needs, clearly articulate the opportunity for hydrogen and other storage mechanisms to find their opportunities alongside battery storage, further supporting diurnal and seasonal fluctuations.

• When reviewing policies, rates structures and plans, be open and inclusive of hydrogen and FCEV related services for the system, to enable and support all market opportunities.

Overview of Multiple Applications of Renewable Electrolytic Hydrogen Application 1: Zero Emissions Transportation Hydrogen fuel cell vehicles (FCEVs) emits zero tailpipe air pollution or greenhouse gas, including in difficult use cases like medium and heavy duty trucks, and the more the electricity grid transitions to renewable sources, the more hydrogen produced with electrolysis will also help eliminate greenhouse gas and criteria pollution over the entire lifecycle of transportation fueling.

Hydrogen fuel cell technology is a cornerstone of California’s clean transportation policy. Governor Brown’s Executive Order B-16-2012 set a target of 1.5 million Zero Emissions Vehicles (ZEVs) on California roads by 2025, which includes vehicles powered by not only batteries but also fuel cells. Other state policies that support FCEVs include the Clean Vehicle Rebate Project, AB 8, and the Energy Commission’s Alternative and Renewable Fuel and Technology Program. As a result of these efforts, California is on its way to achieving its initial goal of 100 hydrogen fueling stations, and there are thousands of hydrogen fuel cell electric vehicles (FCEVs) on the state’s roads. There are three models of FCEVs on California’s roads today with more expected in coming years,2 there have been several recent OEM announcements on medium and heavy-duty vehicles,3 and adoption of hydrogen fuel cell options for non-vehicular industrial equipment like forklifts is also starting to boom.4

By 2030, the California Fuel Cell Partnership expects that up to 500,000 FCEVs will be in California fueling at hundreds of stations. They also expect to see up to 50% of hydrogen produced from renewables, much of that via electrolysis. Currently, hydrogen dispensed in California is already 44% renewable.

In that respect, EVs will not be the “bulk of new car sales” as suggested in this document without a suite of supportive policies in California and nationwide.

2 http://www.businessinsider.com/12-hydrogen-car-projects-2017-5/ - the-epa-recently-gave-the-car-an-estimated-range-of-366-miles-the-longest-range-of-any-zero-emissions-vehicle-honda-says-the-clarity-has-a-refuel-time-of-just-three-to-five-minutes-2 3 https://www.trucks.com/2017/05/08/hydrogen-fuel-cell-trucks-holy-grail/ 4 https://www.hygen.com/hydrogen-forklifts-new-home-amazon/

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Application 2: Decarbonizing Gas Power Plants Hydrogen could replace a large majority of the natural gas going into power plants, which are the biggest end users of natural gas in California.5 Replacing fossil fuel natural gas with renewable hydrogen could help reduce greenhouse gas emissions from a major source of electricity that helps stabilize the grid, lower air pollution from power plants that presents a health hazard to communities, and avoid electric generation stranded assets funded previously by California ratepayers.

Application 3: Energy Storage As the state advances toward ever-higher renewable electricity targets, curtailment is increasing.6 As the state progresses to 50% and higher penetrations of mostly variable renewable generation, like solar and wind power, over the coming years, there will be an increasing need for energy storage, including large scale, seasonal storage. The geographic limitations of pumped hydro and compressed air storage will require additional large scale storage solutions. Electrolytic hydrogen production is uniquely scalable from small amounts to the terawatt-hour-scale, making it a potentially critical resource in providing geographically flexible seasonal storage. Compared to lithium-ion batteries, it can store far more massive amounts of energy and can shift such energy over far longer periods of time (e.g. seasonally, annually), it can provide more capacity in less space, and modeling shows it can also be cost-competitive. 7

Application 4: Integration of Renewable Electricity and Other New Clean Energy Loads As the CAISO clearly knows, over the coming years, electricity grids increasingly must accommodate new intermittent generation resources and loads, like solar, wind and electric vehicles, which must be to maintain reliable, cost-effective service. Electrolyzers can be deployed as a flexible tool that are able to absorb surplus generation from short to continuous periods, using the electricity to make hydrogen via electrolysis for multiple possible applications – and conversely, supplying the grid with power as needed via fuel cells or power plants.

Application 5: Decarbonizing Industrial Processes Renewable hydrogen can replace conventional hydrogen production and help decarbonize refineries, which emit 31% of greenhouse gases from California’s industrial sector.8 For large emitters that use hydrogen, like refineries and fertilizer producers, options are limited for meeting greenhouse gas reduction requirements. Renewable hydrogen provides an important, greenhouse gas free, drop-in alternative.

5 https://www.eia.gov/dnav/ng/ng_cons_sum_dcu_sca_a.htm 6 http://www.utilitydive.com/news/prognosis-negative-how-california-is-dealing-with-below-zero-power-market/442130 7 See Economics of P2G, CHBC, June 27, 2017 http://docketpublic.energy.ca.gov/PublicDocuments/17-IEPR-10/TN219923_20170626T180524_Emanuel_Wagner_Comments_Economics_of_Power_to_Gas.pdf 8 Source: CARB; https://www.arb.ca.gov/cc/inventory/pubs/reports/2000_2014/ghg_inventory_trends_00-14_20160617.pdf

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Specific Edits to the Electricity 2030 plan Proposed edits are in red line.

Page 4 Transportation, buildings, electricity, the opportunities of a clean energy economy depend on addressing energy use holistically.

• Change “Batteries in electric vehicles,” to “Electrolyzers producing hydrogen and batteries in zero emission vehicles,”.

About this document:

• Change “accelerate EV deployment” to “accelerate ZEV deployment”.

Page 10 Biofuels play a larger role in the thermal generation fleet:

• Change “Biofuels play a larger role…” in the heading to “Renewable gas plays a larger role…” • Change “An increasing number of fast-start conventional resources are converted to use biofuels

instead of fossil fuels” to “An increasing number of fast-start conventional resources are converted to use renewable gas, such as biofuels and electrofuels, instead of fossil fuels.”

Page 11 Guiding Questions:

• Add #5: “What are the constraints and opportunities for use of electrofuels like electrolytic hydrogen and synthetic methane in electricity generation? What infrastructure upgrades would be required to access and biofuels for electricity generation?”

Page 14 Electric vehicles comprise the bulk of new car sales and represent a significant share of cars on the road in California.

• Change “Electric Vehicles” to “Zero-emission vehicles” and “EVs” to “ZEVs” • Change “Smart-charging and time of use incentives enable electric vehicles to provide thousands of

megawatts of controllable demand” to “Smart-charging and time-of-use incentives for charging plug-in vehicles and producing hydrogen for fuel cell electric vehicles to provide thousands of megawatts of controllable demand.

• Change “individually owned EVs” to “individually owned ZEVs”.

Customers become “prosumers”:

• Change “Microgrids incorporating battery storage” to “Microgrids incorporating energy storage”.

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Page 16 Falling battery costs and IT technologies encourage formation of local microgrids.

• Change to “falling storage costs” to encompass opportunities with fuel cells and power-to-gas in microgrids. Several microgrid pilots are already using electrolytic hydrogen and fuel cells9 and cost of electrolyzers has dropped by 80% since 2002.10

Electric vehicles and sophisticated building energy management technologies…

• Change “Electric vehicles” to “Zero emission vehicles” OR “Plug-in and fuel cell electric vehicles”

Page 20 Electric vehicles (EVs) rapidly replace internal combustion engine vehicles. EVs represent…

• Change “Electric vehicles (EVs)” to “Zero emissions vehicles (ZEVS) rapidly replace internal combustion engine vehicles. ZEVs represent…”

Public transportation is increasingly electric-driven.

• In the paragraph under this bullet heading, change “Electric buses” to “Zero emission electric buses” and “EVs” to “ZEVs”.

Electric vehicles provide a large volume of widely dispersed and dispatchable storage capacity.

• This section is very specific to charging battery cars and is written differently than the other sections. We recommend the following objective wording that encompasses both types of electric vehicles:

“Plug-in and fuel cell electric vehicles provide widely dispersed and dispatchable storage capacity.

Controlled battery charging and electrolytic hydrogen production provides multiple paths to absorbing excess renewable generation, reducing peak demand, and optimizing electrical system assets. Combined with time-of-using pricing for charging and using hydrogen fueling station equipment, plug-in vehicles and hydrogen equipment enables flexibility for load balancing by using excess renewables to fuel cars, and using the geographically-dispersed energy stored in batteries and hydrogen to provide power to the grid.”

Page 21 Task: Develop policies and programs to integrate transportation and building energy use with electrical service

• Bullet 4: Add—accelerated, widespread deployment of vehicle charging “and hydrogen fueling” infrastructure; Change “Electric Vehicles” and “EVs” to “Zero emissions Vehicles (or Battery electric and fuel cell electric vehicles)” and “ZEVs”.

9 See, e.g., https://www.energymanagertoday.com/uc-irvine-power-gas-storage-performs-lithium-ion-batteries-0168751/; https://microgridknowledge.com/fuel-cell-microgrids-fuelcell-energy/ 10 https://energy.gov/sites/prod/files/2017/10/f37/fcto-progress-fact-sheet-august-2017.pdf

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• Bullet 5: Change “behind-the-meter resources such as EVs and buildings” to “behind-the-meter resources such as ZEVs, hydrogen production, and buildings.”

• Add bullet: “Establish sustainable pathways to integrate power-to gas into the energy system, including for transportation, gas end uses for buildings, and industrial applications.”

Guiding questions

• #3: Change to - What programs and incentives are required to expand daytime BEV charging and hydrogen production and/or compression?

• Remove the question about EV owners that do not have access to home charging. This is a role that fuel cell electric vehicles and hydrogen stations fill.

• #4: Change “allow fleets of EVs and…” to “allow fleets of ZEVs and…”

CALIFORNIA MUNICIPAL UTILITIES ASSOCIATION

915 L STREET, SUITE 1460 ● SACRAMENTO, CALIFORNIA 95814 (916) 326-5800 ● (916) 326-5810 FAX ● www.cmua.org

A non-profit statewide association of publicly owned electric utilities and water agencies.

November 30, 2017

Richard Maullin Chairman, Board of Governors California Indpendent System Operator Corporation 250 Outcropping Way Folsom, CA 95630

RE: Comments on Discussion Paper, Electricity 2030 Dear Chair Maullin:

The California Municipal Utilities Association (“CMUA”) appreciates the opportunity to

comment on the “Discussion Paper, Electricity 2030, Trends and Tasks for the Coming Years,” (“Discussion Paper”) published by the California Independent System Operator Corporation (“CAISO”).

CMUA fully supports California’s energy policy objective to decarbonize California’s economy as directed by California statute and implemented through regulation. The Discussion Paper identifies many issues that may need to be addressed to achieve California’s policy objectives. It cannot be avoided, however, that most of these issues and related tasks have little to do with the core function of the CAISO. Energy efficiency standards and targets, vehicle electrification, statewide economic impacts, net metering, and the other issues identified in the Discussion Paper, may all have an indirect impact on how the CAISO operates the grid. But the policies and choices inherent in each of these issues are not the CAISO’s core function, which is critical and complex it is own right without these additional challenges.

The core function of the CAISO is to maintain grid reliability consistent with federally developed

reliability standards. The CAISO accomplishes this task by administering a highly comprehensive and complex market, that is also federally regulated. This is a tremendous responsibility due to the consequences that result from interruptions in reliable service, and the billions of dollars that flow through its market annually. These tasks are critical, and require all of the CAISO’s attention and resources.

Recent issues that have been brought to the Board’s attention illustrate this fact. The

discussions at the most recent Board meeting on gas plant Risk of Retirement policy and Reliability

Must Run designation illustrate the challenges faced by the natural gas fleet in California that is needed for the CAISO to fulfill its core function. While it may be true that “many fossil fuel plants are old, inflexible and inefficient,” (Discussion Paper at 4), it is equally true that many of these units are already set to retire, and it is also true that many natural gas plants are newer, efficient, clean, and flexible, and will be absolutely necessary to integrate renewable resources in a cost-effective manner. Thus, price formation, market design, and possibly reformed Resource Adequacy policy that affect these units must take center stage to achieve reliable renewable resource integration for the foreseeable future.

Similarly, the issue of Congestion Revenue Rights auction design has gained national attention; a House of Representatives Energy Subcommittee hearing on this and related topics was recently held and included testimony from the CAISO’s own Department of Market Monitoring. The Department of Market Monitoring has identified significant and persistent wealth transfers from consumers over the past several years due to fixable issues within the CRR auction design. This is a huge number when compared to the consumer consequences of several other matters that garner Board attention, and it deserves the full benefit of the CAISO’s considerable intellectual horsepower.

It is also important to remember that not all our neighboring states in the West are identical to

California. Even in states that have environmental policies that align with California’s, the mechanisms they choose to achieve these policies may differ completely. Virtually the entire West is comprised of vertically integrated utilities that applicable state regulators wish to continue into the future. They may not envision a grid that is disaggregated, or that sees a strong proliferation of microgrids or similar developments. The CAISO should be cautious when opining on these issues of industry structure, rather than focusing on its core functions, as it seeks to expand collaboration beyond California.

While we recognize the value of discussing broad issues of energy policy, it is inescapable that

the primary forums for these discussions are at the Legislature and with applicable state regulators. Reliability and affordability of energy are foundational to meeting California’s carbon goals. By achieving these critical goals, the CAISO will be doing its part to help fulfill the broader vision enunciated by the Governor, Legislature, and California policymakers. Sincerely,

Barry Moline Executive Director California Municipal Utilities Association cc: Steve Berberich, President and Chief Executive Officer

November 20, 2017

California Independent System Operator Corporation

250 Outcropping Way

Folsom, CA 95630

RE: California Independent System Operator Corporation Discussion Paper, “Electricity

2030: Trends and Tasks for the Coming Years”

Dear Mr. Richard Maullin,

On behalf Energy Independence Now (EIN), our Board of Directors, hundreds of

supporters and hydrogen vehicle and Infrastructure stakeholders, I am writing to

comment on the California Independent System Operator (CAISO) Corporation’s

discussion paper, “Electricity 2030: Trends and Tasks for the Coming Years.” EIN is the

only nonprofit organization dedicated to advancing fuel cell electric vehicles (FCEVs)

and the hydrogen-fueling infrastructure required to catalyze a rapid transition to a clean

energy and transportation economy. EIN engages in comprehensive research, strategic

policy advocacy and public outreach to promote the widespread adoption of fuel cell

electric vehicles as a key part of a zero-emission transport future. We appreciate the

opportunity to provide comments on the draft CAISO Board Vision Discussion Paper.

Based on our advocacy work and engagement programs with the hydrogen fuel cell

community, we provide the following comments:

1. Hydrogen Fuel Cell Vehicles (FCEV) and Fuel Cell Technology:

The auto manufacture industry, the energy sector, the tech community have been

investing more and more into the promising and proven technology of FCEVs and

hydrogen fuel cells. A growing number of auto manufactures are exploring ways

to approach and expand the hydrogen market. The California Energy

Commission’s and the California Air Resources Board’s work have

complemented the auto industry’s efforts to invest in the hydrogen infrastructure

in California and to study ways to incorporate hydrogen fuel cells into the

electrical grid and transportation infrastructure. Unfortunately, the CAISO

Discussion Paper does not mention hydrogen fuel cell technology, which is a

missed opportunity to support proven technology that can help curb greenhouse

gasses (GHG). We encourage the CAISO Board to include hydrogen fuel cell

technology in the CAISO Vision Paper and recognize the innovative technology

that already plays a pivotal role in California’s transition to a clean energy

economy. The paper should also highlight the efficiency of the energy storage

capabilities of stationary hydrogen fuel cell batteries.

2. CAISO Support for Hydrogen Fuel Cell Storage:

The 2030 Vision Paper highlights the need for a more efficient management of

energy storage with batteries. Towards that effort, CAISO should find ways to

collaborate with the hydrogen fuel cell storage industry. Hydrogen fuel cell

technology can be utilized to efficiently store energy and can be effectively

integrated in the electrical grid to stabilize the demand. We recommend that

CAISO supports ongoing efforts by industry and the hydrogen community to

incorporate hydrogen fuel cell storage and explore ways to incentivize and

encourage the expansion of the hydrogen fuel cell infrastructure.

3. Power-to-Gas:

To successfully and effectively decarbonize, decentralize, and regionalize

California’s electric service, CAISO should include an exploration on to how best

utilize power-to-gas. Electrolysis creates renewable hydrogen through renewable

electricity by separating water into hydrogen and oxygen. Renewable hydrogen

can replace fossil fuel natural gas, decrease air pollution, and help stabilize the

grid.

Thank you for your consideration of our comments. I would be happy to speak with you

or your staff further if you have any questions.

Sincerely

Brian Goldstein

Executive Director

1

Draft ISO Board Vision Discussion Paper

Stakeholder Comments

Submitted by Company Date Submitted

Mahesh Morjaria VP, System Development Mahesh.morjaria@firstsolar.com

First Solar, Inc. November 22, 2017

First Solar, Inc. (“First Solar”) applauds the CAISO Board of Governor’s effort to set out a

guiding vision for the strategic planning process and appreciates the opportunity to provide these comments.

First Solar agrees with the trends and solutions identified in the Vision Discussion Paper:

“Electricity 2030-Trends and Tasks for the Coming Years” (“Vision Paper”) that are key to building a more secure, sustainable and affordable energy grid. We appreciate the CAISO Board taking a leadership role in these areas and believe that cross-agency coordination will be required to address complex interrelated procurement and energy balancing issues. It will be particularly important for CAISO to coordinate with the California Public Utilities Commission (“CPUC”) to design procurement products that incentivize investment in renewable resources that can provide the flexibility needed to maintain grid reliability.

In particular, First Solar supports CAISO’s focus on regulatory policy to address Trend 2

(gas-fired generation declines significantly as the grid is modernized)1 and Trend 3 (the system is shaped by the variable output of wind and solar resources).2 We believe the following initiatives within CAISO’s identified priorities will be critically important:

• Develop a reliability-based plan for operating the grid with a majority of non-fossil

resources. Embed this plan into IRP based procurement, in order to minimize the risk of conventional generating assets becoming stranded.

• Implement policies that require all resources to operate flexibly, and conventional generators to have fast start, fast ramping and low Pmin capabilities.

• Renewables supply an increasing share of Essential Reliability Services, including Primary Frequency Response, regulation, voltage support and spinning reserves, all of which had previously been supplied by fossil, nuclear and hydroelectric power.

• New Power Purchase Agreements require renewables to bid into the market and compensate them for providing Essential Reliability Services (ERS) as well as energy and capacity.

1 Vision Paper, pg. 10. 2 Vision Paper, pg. 12.

2

Fortunately, there are some precedents that may be helpful to consider as CAISO begins to implement these initiatives. For example, the State of Hawaii has grappled with many of these issues as it has strived to reliably manage a closed system with high penetration of distributed energy resources. A recent report titled “Proactive Solutions to Curtailment: Identifying New Contract Structures for Utility-Scale Renewables” (“SEPA-ScottMadden Report”) addresses a number of the questions raised by the Board in its Vision Paper and offers useful solutions. A copy of the report is attached (see Attachment 1). Specifically, the report highlights the need for new contract structures that proactively address high curtailment scenarios by mitigating the risk of under-collected revenues and allowing renewables to provide ancillary services.3 These contract structures contemplate high levels of renewable integration and offer solutions that incentivize the type of flexibility attributes that can be provided by the renewable resources.

We believe that the time is right for the CAISO to examine what market products and associated pricing structures are necessary to support greater grid-related flexibility and controllability so that renewable generators can provide these services. We see this as allowing renewable generators to play a greater role in assisting with grid support, thereby greening up ancillary services products. This would also help optimize deployment of controllable utility-scale solar generation to provide both energy and essential reliability services rather than exclusively relying on curtailment as a reliability tool. Those structures may be informed by the Renewable Dispatchable Generation product discussed in the SEPA-ScottMadden Report.4 We suggest that the CAISO initiative already under way, the Flexible Resource Adequacy Capacity and Must Offer Obligation Phase 2 stakeholder proceeding, could be a good vehicle for starting this examination, particularly with respect to designing ancillary service products that enhance grid flexibility. The CAISO, working in coordination with NREL and First Solar, already has shown that utility-scale solar can very capably provide essential reliability services. First Solar continues to work to demonstrate this through ongoing pilot projects in coordination with utilities, NREL and the CAISO.

Development of ancillary services markets, however, will not be sufficient to encourage

the construction of renewable generating resources that maximize grid reliability while meeting policy goals. To ensure that grid-enhancing ancillary services are coordinated with long-term power procurement products, it is necessary to coordinate market design discussions with the CPUC. With the opportunity presented by the CPUC’s Resource Adequacy proceeding and the on-going Integrated Resource Planning proceeding, the time is right to develop complementary procurement products that will encourage the deployment of renewable resources that maximize flexibility and controllability. The goal should be to work closely with the CPUC, utilities and other stakeholders to develop power purchase agreements that encourage investment in flexible resources.

3 SEPA-ScottMadden Report, pg. 20. 4 SEPA-ScottMadden Report, pg. 25.

3

As part of this examination of market products and associated pricing structures, First Solar also suggests that the CAISO Board consider how energy-only resources will fit within a changing paradigm. In particular, it will be necessary to understand the value that should be assigned to energy-only resources and how energy-only resources should be evaluated against newly emerging reliability-based products. There are many areas where alignment around the value and place for projects with energy-only deliverability is important, from procurement design to transmission planning and interconnection. We see resolving the uncertainty around energy-only as another issue of some urgency.

Again this year, the CAISO is not addressing additional policy-driven transmission projects in its Transmission Planning Process, creating potential problems for the increased interconnection of renewables required to meet California’s policy goals. First Solar asks the Board to consider whether the reduced need for transmission is being driven in part based upon an assumption that the market will accept energy-only projects. The Vision Paper only discusses the reduced need for transmission as a result of other trends, such as decentralization and regionalization. However, First Solar believes the CAISO should expand its assessment to incorporate how energy-only projects fit within a market that is being redesigned to incentivize reliability and controllability, rather than being designed solely to generate the maximum amount of energy at all times of the day and year. We suggest that, in coordination with the proceedings underway in the CPUC’s IRP proceeding, the CAISO examine the connection between the transmission system needs and the integration of more utility-scale generation needed to meet GHG targets. With the CAISO relying again on the 33% RPS scenarios for its transmission planning next year, we are growing concerned that the State may face a pinch on transmission capacity needed to meet targets going forward.

First Solar appreciates the CAISO Board considering these comments in the Vision Paper and looks forward to being a partner in creating the electric service framework of the future.

4

ATTACHMENT 1

Proactive Solutions to Curtailment Risk: Identifying New Contract Structures for Utility-Scale Renewables

Prepared for the Hawaiian Electric Companies by the Smart Electric Power Alliance and

ScottMadden, Inc.

February 2017

PROACTIVE SOLUTIONS TO CURTAILMENT RISK

IDENTIFYING NEW CONTRACT STRUCTURES FOR UTILITY-SCALE RENEWABLES

Prepared for the Hawaiian Electric Companies by:

John Sterling, Christine Stearn, & Ted Davidovich – Smart Electric Power Alliance

Paul Quinlan, John Pang, & Chris Vlahoplus – ScottMadden Inc.

Proactive Solutions to Curtailment Risk pg. 2

Table of Contents

Table of Contents ........................................................................................................ 2

Table of Figures .......................................................................................................... 3

Table of Tables ............................................................................................................ 3

Executive Summary .................................................................................................... 4

State of the State ........................................................................................................ 9

Challenges in Contracting for Utility-Scale Renewables ...........................................12

Impact of Curtailment Concerns ...............................................................................12

Translating Curtailment Risk into Project Economics ...............................................14

Grid Stability & Reliability in a Majority Renewable Future ......................................17

Potential Contract Structures for Utility-Scale Renewables .....................................20

I. Capacity & Energy PPAs .......................................................................................20

II. Time-of-Day Price Caps .......................................................................................22

III. Renewable Dispatchable Generation ..................................................................25

Identifying Minimum Availability Metrics .................................................................28

Long-Term Impacts to Dispatch and Curtailment Order ...........................................29

Impacts to Debt Service Coverage ............................................................................30

Next Steps .................................................................................................................32

Understanding Accounting Treatment ......................................................................32

Updating Procurement Practices ..............................................................................32

Leveraging New Technology .....................................................................................33

Conclusion .................................................................................................................34

Table of Acronyms.....................................................................................................37

References ................................................................................................................38

Appendix A: Additional Models Considered ...............................................................39

Proactive Solutions to Curtailment Risk pg. 3

Table of Figures Figure 1 - Renewable Energy Utilization, December 2015 ...................................................................... 9

Figure 2 - DG Penetration Forecast by Utility ...................................................................................... 10

Figure 3 - O‘ahu Net Load Potential .................................................................................................... 11

Figure 4 - Future Daily Load Profiles for Hawaiian Electric .................................................................... 13

Figure 5 - Curtailment Impact to DSCR ............................................................................................... 17

Figure 6 - Illustrative Time-of-Day Price Cap Curve ............................................................................. 23

Figure 7 - Average Day Solar Production Curve ................................................................................... 26

Figure 8 - Potential Ancillary Services Created by Renewable Dispatchable Generation .......................... 27

Figure 9 - DSCR @ Risk: 0% to 30% Actual Curtailment ...................................................................... 31

Figure 10 - Impact of New Structures on NPV @ Risk .......................................................................... 35

Figure 11 - Impact of New Structures on DSCR @ Risk ........................................................................ 35

Figure 12 - Impact of New Structures on Effective $/MWh for Energy Delivered to Utility ...................... 36

Table of Tables Table 1 - Preferred Contract Alternative................................................................................................ 6

Table 2 - Impacts to Project Economics with No Curtailment Anticipated .............................................. 15

Table 3 - Impacts to Project Economics with 20 Percent Curtailment Anticipated .................................. 16

Table 4 – 2014 Ancillary Services Pricing from Organized Markets ........................................................ 18

Table 5 - Approximate Opportunity Costs at Kahe and Kalaeloa Plants ................................................. 19

Table 6 – Project Economic Implications: 25 percent of Project Costs Recovered in Capacity Payment ... 21

Table 7 – Project Economic Implications: 75 percent of Project Costs Recovered in Capacity Payment ... 21

Table 8 - Project Economic Implications: Time-of-Day Alternatives ....................................................... 24

Table 9 - Customer Economic Impacts of Renewable Dispatchable Generation ...................................... 28

Table 10 - Additional Contractual Models Considered ........................................................................... 39

Proactive Solutions to Curtailment Risk pg. 4

Executive Summary

A basic principle of power system operation is that production and consumption of electric power must be equal to each other (i.e., balanced). Variable resources such as wind and solar produce power when wind and solar energy are available, which may not correlate to periods of electricity demand. With the substantial growth of variable renewable energy generation resources on each of the Hawaiian Islands’ autonomous systems, including relatively large numbers of distributed resources, Hawai‘i’s electric utilities are faced with increasing periods when electricity supply exceeds demand and actions are necessary to balance the system. Increasingly, system operators must reduce output of (curtail) renewable energy in order to preserve system reliability, because energy production capability exceeds each island’s net load. Continuing to add variable resources to these systems, which face increasing periods of over-supply, requires changes to the historical commercial and contractual terms for procuring energy from these resources, which this paper will consider. Historical procurement compensated variable renewable resources strictly based on energy delivered to the utility. Some certainty of sale was provided by a combination of increasing demand on the systems (increasing the need for the energy), the right to serve energy first by designation as “must-take” resources, and with the philosophy of implementing excess energy curtailments in reverse order of project connection dates. The goal of 100 percent renewable generation requires greater flexibility in the contracting and dispatch of future projects. As the Hawaiian Electric Companies transition to higher levels of renewable resources, optimizing use of such resources helps maintain grid reliability while managing costs.1 For purposes of this paper, curtailment is defined as a reduction in the output of a generator from what could otherwise have been produced, given the availability of the relevant variable renewable resource (e.g., solar and wind).

As the islands evolve to ever-increasing levels of renewable energy, the ability to treat any type of energy as must-take is increasingly limited. The islands serve only the demand on the island systems and cannot export excess production, as is done in other interconnected areas. Accommodating the renewable resources will displace existing generation that provides dispatchable energy, adjusted to meet demand, and affect many other characteristics to keep the power system stable and operable. Variable resources and firm renewable resources will increasingly need to provide these capabilities to adjust output to serve demand, respond to frequency, regulate voltage, etc., as the systems are transformed to economically and reliably serve the energy needs of the future with 100 percent renewable energy. This increasing contribution to grid management will necessitate changes to both procurement terms and technical and operational capabilities of all renewable resources, including distributed and variable energy resources such as solar and wind, as well as firm renewables such as biomass and geothermal resources.

1 “Hawaiian Electric Companies” refers collectively to Maui Electric, Hawaiian Electric Company, Inc., and

Hawai‘i Electric Light Company, Inc. (collectively the “Companies”).

Proactive Solutions to Curtailment Risk pg. 5

The inability of the systems to export excess generation to neighboring systems, as is commonly done in mainland interconnections, further limits options available for excess energy.

Under a traditional Power Purchase Agreement (PPA) arrangement, variable resources have been compensated based on actual energy delivered to the utility. The need for the utility to reduce energy output during periods of low net demand results in uncertainty about how much energy the utility will be able to purchase, resulting in a financial risk to the Independent Power Producer (IPP). Basing compensation on energy delivered to the utility can have a direct, negative impact on any IPP’s ability to finance projects, due to the risk of under-collected revenues resulting from curtailed energy (IPP Risk model). However, if a utility off-taker reduces the impact on the IPP by guaranteeing payments for undelivered/curtailed energy, the utility’s customers may experience a higher “effective price” for energy delivered than the stated unit price under the PPA (Customer Risk model). Contractual terms based solely on energy sales fail to allocate curtailment risk in a way that is equitable to all parties, transparent to all stakeholders, and sustainable in the future with increasing need to control energy production to match demand.

As Hawai‘i moves forward towards its Renewable Portfolio Standard goal of obtaining 100 percent renewable generation by 2045, all generation sources must contribute to grid management by providing not only the ability to match supply and demand (through curtailment), but also other grid services that conventional plants have historically provided. If procured with the appropriate technical and operational capabilities and the appropriate policies that allow system operators to leverage these capabilities, renewable resource utilization can be further increased while maintaining system reliability by providing the necessary capabilities to operate a grid without reliance on conventional fossil plants or costly supplemental technologies. To that end, new contractual approaches are needed for variable renewables that incentivize the dispatchability of these resources and preserve flexibility for future system needs, all while maximizing value for the utilities’ customers. This increased flexibility has the added benefit of allowing for common handling of future firm and variable resources. This report outlines some new concepts that may better achieve these objectives.

Proactive Solutions to Curtailment Risk pg. 6

Table 1 - Preferred Contract Alternative

Solution Description

Renewable Dispatchable

Generation

o Request for Proposals (RFP) requires bidders to break pricing into fixed

($/MW-month) and variable O&M ($/MWh) components o The $/MW-month covers the fixed cost of the facility, ensuring that the

project is financeable. o The variable $/MWh component is based on the variable O&M cost (if

any) to run the facility.

o Project selection is based on a “blended” levelized price that considers anticipated demand for the energy through a resource planning process.

o The seller guarantees a resource conversion factor (i.e., power curve) to convert solar irradiance or wind speed into energy production (MWh).

o The IPP is required to meet minimum availability metrics to ensure equipment is maintained and available for production.

o The IPP is required to meet technical and operational characteristics that

support grid operation, including voltage regulation, disturbance ride-through, frequency response, and active power control (curtailment).

o The IPP is required to provide an indication to the utility of the available energy.

o On a real-time basis, the utility controls the output of the facility (real and

reactive) based on impacts to system cost and grid reliability considerations. o Undelivered available energy provides system reserves

o The utility integrates the variable resource into system planning and operations as dispatchable energy, limited by available energy used by the

variable resource.

Source: SEPA & ScottMadden, 2016

For all proposed structures in this report, the long-term goal is to transition Hawai‘i away from treating resources as must-take energy, with the excess energy curtailment of resources on the basis of contract connection date, and towards treating all generation as dispatchable in nature. This paradigm shift places all generators on a more equal footing. With proper contract structures, technical and operational characteristics, and planning, this shift should lead to more economic- and reliability-focused dispatch.

Based on the work completed for this report, the Hawaiian Electric Companies’ preliminary preferred option is summarized in Table 1. New PPAs would no longer be curtailed in a sequential order based on the seniority of each project’s contract approval date; rather, the utility would dispatch the generating facility as required to operate the grid in a reliable manner. The fixed monthly payment would give developers more certainty of recovering the cost of the facility as long as it is maintained to meet predetermined criteria for availability; penalties would be assessed if the facility cannot meet the required metrics.2

2 Because this option provides for fixed cost recovery regardless of production, it would necessarily be used only after evaluation through a resource planning process to determine customer value from anticipated

energy delivered to the utility and ancillary services.

Proactive Solutions to Curtailment Risk pg. 7

This report considers two other options:

Capacity & Energy PPAs where under which bidders would propose pricing based on fixed

($/MW-month) and energy ($/MWh) components. Bidders would price their curtailment

risk outlook into the proposed breakdown between fixed and variable components. For

this model, the report contemplates two structures: (1) 25 percent of costs recovered via

a fixed payment; and (2) 75 percent of costs recovered via fixed payment. The report also

varies the amount of anticipated curtailment that is forecast in their proposal: 0 percent

and 20 percent. These options provide plausible bookends for how an IPP may approach

curtailment risk mitigation.

Time-of-Day (ToD) pricing in which the energy prices are lower (or negative) during

expected low-load periods, and energy prices are higher during peak load hours. The

uncertainty of predicting the long-term system load profile makes this option difficult to

align with forecast production costs, and therefore, appropriate energy prices.

When comparing potential pricing approaches for each of these scenarios with today’s current alternatives (where either the IPP or the utility owns all of the financial risk caused by the uncertainty in the amount of energy the systems can accept), identifying ways to spread the risk more equitably can lead to less price variability for the customer and less financing risk for the developer.3

The modeling included in this report contemplates the impacts on new solar projects; however, these structures could be translated to any new variable or firm renewable resource, including wind, biomass, or geothermal resources. For the Renewable Dispatchable Generation model, this report assumes for simplicity that there is no variable component and that all costs are recovered via the fixed payment.

The structures identified in this report resulted in less downside risk of revenues collected for IPPs on a net present value (NPV) basis. This reduced volatility should translate into stronger project financing due to the ability to better forecast stable revenues regardless of curtailment, as compared to the traditional IPP Risk Model. Such improved financeability can be further quantified by examining the resulting Debt Service Coverage Ratio (DSCR) for each structure under zero curtailment and high curtailment scenarios. DSCR represents the likelihood that a project’s future revenue streams can cover its debt obligations. Lenders frequently use this metric to set rates when financing a project. Reduced NPV risk translates into more stable DSCRs across these structures. In turn, this should lead to more attractive financing costs and, ultimately, lower PPA prices.

Lastly, the structures identified here would reduce variability for the utility’s customers in the effective price of the energy delivered, after factoring in fixed and variable payments. While none of the approaches are able to eliminate curtailment risk entirely, these structures limit the upside risk in the effective price paid for delivered energy. By more

3 All structures presented here, with the exception of the Time-of-Day Price Caps, do not assume the use

of energy storage technologies.

Proactive Solutions to Curtailment Risk pg. 8

equitably splitting economic risks with IPPs across the board, customer risk can be mitigated as well.

Continued research into how customers may be impacted by these new agreements is ongoing. Potential unintended consequences as a result of increased fixed payments and the curtailment conditions need to be identified and further discussed. One potential consequence identified is that if a PPA is considered a capital lease under current accounting guidance (or a lease under recently issued revised accounting rules), the present value of the estimated lease payments would need to be reflected as a liability on the utility company’s financial statements. The impact to the utility’s financial statements from having to recognize the present value of the estimated lease payments can be significant to the Hawaiian Electric Companies’ credit metrics and cost of capital. Recently revised accounting rules may increase this risk, and such assessment is ongoing.

Detailed conversations with key market participants are also needed to ensure that any future procurement practices are structured in a transparent, fair, and equitable manner.

The systems have finite quantities of demand, and as a result, have finite need for new resources to meet the demand. The procurement of resources through contracts that recover fixed costs requires careful resource planning to avoid fixed expenses for resources without consumer benefit. The mix of energy resources must be designed to cost-effectively meet customer demand, while maintaining acceptable reliability. The evaluation of resource type and location must include its correlation with net demand and total impacts on system interconnection and operational costs. Care must be taken to design a mix of resources whose fixed costs that result in a net cost-benefit from the energy production and grid services, compared to resource alternatives. Alternative resource considerations can include storage options, dispatchable renewable resources, demand response, and conversion of conventional fossil plants to renewable resources through fuel conversions.

Hawai‘i’s place as the nation’s leader in renewable energy adoption places an increasing importance on including these considerations, with a resource plan to meet 100 percent renewable energy goals while managing costs and ensuring grid stability. With time, as other states transition away from conventional generation and increase the amount of intermittent renewable resources on their systems, the lessons learned in Hawai‘i will be valuable to utilities and grid operators in much larger interconnected systems. The examples and successes from Hawai‘i that emerge from this effort will ripple across the industry and set the stage for a new way of thinking about renewable resources.

Proactive Solutions to Curtailment Risk pg. 9

State of the State

Hawai‘i is leading the United States with a vision of 100 percent renewable energy by 2045. This vision challenges the state’s utilities to tap plentiful, natural, clean sources of power, while building grids, interconnection infrastructure, and business models to make

these power sources accessible and affordable. As of December 2015, the Hawaiian Electric Companies, comprised of Hawaiian Electric Company, Inc. (Hawaiian Electric), Maui Electric Company, Limited (Maui Electric), and Hawaiʻi Electric

Light Company, Inc. (Hawaiʻi Electric Light), obtained over 23 percent of their generation from renewable energy sources4

Source: Hawaiian Electric Companies, 2016

The Hawaiian Electric Companies serve 95 percent of the state’s 1.4 million residents on the islands of Hawai‘i, Lana‘i, Moloka‘i, Maui, and O‘ahu. To meet the energy needs of Hawai‘i’s residents and integrate higher levels of renewable energy, the Hawaiian Electric Companies are working aggressively to empower their customers and communities with affordable, reliable, clean energy, and provide innovative energy leadership for Hawai‘i. To achieve that vision, through their resource planning process, the Hawaiian Electric Companies have produced a Power Supply Improvement Plan (PSIP) to reach the 2045 goal of 100 percent of renewable resources by:5

Implementing a smart grid foundation project;

Implementing a demand response management system (DRMS);

Pursuing market-based distributed energy resources (DER) for O‘ahu, Hawai‘i Island, and

Maui and high distributed generation (DG) in the form of solar photovoltaics (PV) for

Moloka‘i and Lana‘i;

Installing circuit level improvements on all islands;

4 Under Hawai‘i's Renewable Portfolio Standards, each electric utility company that sells electricity for consumption in Hawai‘i must establish the following percentages of "renewable electrical energy" sales by

December 31 in each of the following years: 10% by 2010, 15% by 2015, 30% by 2020, 40% by 2030,

70% by 2040, and 100% by 2045.

5 Hawaiian Electric Companies’ “April 2016 PSIP Update Report”, Docket No. 2014-0183 (April 1, 2016). All

references to the PSIP in this document refer to this version.

17.2%

35.4%

48.7%

23.2% consolidated

Figure 1 - Renewable Energy Utilization, December 2015

Proactive Solutions to Curtailment Risk pg. 10

Pursuing energy storage options;

Implementing community-based renewable energy;

Issuing RFPs to seek over 350 MW of additional renewable energy by 2022;

Researching alternative curtailment policies;

Deactivating generation not well suited to support the integration of renewables; and,

Improving flexibility of existing generation.

Electricity prices in Hawai‘i are the highest in the country at over twice the national average. This has incentivized utility customers to evaluate and often deploy their own customer-sited DERs, such as rooftop solar. To that end, the Hawaiian Electric Companies forecast nearly tripling the amount of DERs by 2030.

Figure 2 - DG Penetration Forecast by Utility

Source: Hawaiian Electric Companies, 2014 6

In conjunction with installed and planned DER generation, the Hawaiian Electric Companies also plan to significantly increase the amount of utility-scale wind and solar generation on each island. Because DERs meet a large portion of each islands’ load, and existing interconnection programs do not provide a capability to control the output of these resources, the amount of available load to serve with utility-scale renewable resources is increasingly limited during peak sunshine hours. The resulting net load profile

6 See Hawaiian Electric Companies’ Letter submitting its Distributed Generation Interconnection Plan

(“DGIP”), filed on August 26, 2014 in Docket 2011-0206, Reliability Standards Working Group.

Proactive Solutions to Curtailment Risk pg. 11

will require increased access to flexible generation resources to manage supply and demand.

As shown in Figure 3, representing load profiles for O‘ahu, gross and net system load are nearly identical and can be approximated by the 2010 load shape. From 2011 onward, however, net system load begins to exhibit the dip in mid-day due to behind-the-meter PV. Despite this challenge, the Hawaiian Electric Companies are committed to finding ways to maintain safe and reliable operations while reducing the amount of load that conventional generation serves.

Figure 3 - O‘ahu Net Load Potential

Source: Hawaiian Electric Companies, 2016

Proactive Solutions to Curtailment Risk pg. 12

Challenges in Contracting for Utility-Scale Renewables

Increasing penetration of distributed PV has created a surplus of daytime, non-dispatchable generation on all of the Hawaiian Islands.7 This generation, which utilities do not directly control, is effectively “must-take”; that is, the utilities must manage other conventional and renewable generation resources around the output of these systems.

The large amount of distributed PV that exports to the grid, relative to total system demand, exceeds levels in other parts of the country. Incorporating large amounts of non-dispatchable utility-scale renewable resources then becomes a challenge – the

system simply does not have the demand to accept all of the production at some times during the day. Subsequently, the Hawaiian Electric Companies are faced with the reality of needing to curtail utility-scale renewable resources to maintain grid stability and reliability.

The purpose of this report is to identify potential new approaches to contracting for utility-scale variable renewable energy resources that enable a focus on economic dispatch and system reliability going forward. Transitioning must-take resources into dispatchable resources (similar to conventional generators) could spur higher penetration levels of these assets without incurring an increased financial burden for customers or IPPs. Any outcome that mitigates those challenges will empower Hawai‘i to move towards its vision of an affordable and reliable 100 percent clean energy future.

Impact of Curtailment Concerns

Curtailment is the reduction of a given purchased power resource below its otherwise theoretical output level. Curtailment is largely an issue reserved for resources that do not rely on a stored fuel source (e.g., coal, natural gas, biomass, etc.). For conventional generation resources that have the ability to stockpile their fuel supply, a decrease in the dispatch of the resource from its maximum output level does not necessarily forego energy sales forever; rather, it likely just delays the conversion of their fuel source into electricity. For solar and wind assets, however, that electricity is permanently foregone. The reality of curtailment is becoming a recurring theme on many islands in Hawai‘i for its utility-scale wind and solar projects. Variable renewable resources such as wind and solar are not dispatchable by nature, meaning their production profile cannot be modified to meet system needs without forfeiting energy production. In other words, there is no ability to defer production to a more valuable time without the use of energy storage. The availability of sunlight or wind dictates energy production. The production can only be used or curtailed, resulting in the potential for lost sales for the asset owner.

7 Most distributed generation in Hawai‘i is contracted via Net Energy Metering (NEM), which historically has been compensated at retail rates. NEM systems and associated compensation are not within the scope of

this report, which focuses on utility-scale transactions only.

Proactive Solutions to Curtailment Risk pg. 13

A further complication for variable projects is that anticipated energy production (and, therefore, sales) requires an estimated availability of the wind or solar resource. The resulting capacity factor represents the amount of energy produced from the installed capacity. A project with a higher capacity factor than anticipated may experience greater curtailment risk than expected, although net energy sales could still be higher than planned.8

This issue is not isolated to the state of Hawai‘i. Concerns have arisen in states such as California where at high levels of distributed solar penetration, other large and low cost renewable assets may be curtailed during light load situations;9 however, due to its small islanded market and high penetration of distributed solar, the magnitude of curtailment necessary to balance supply and demand in Hawai‘i far outpaces that of other regions of the country. As shown in Figure 4, increasing distributed PV creates overgeneration in greater and greater quantities during sunny daytime hours, requiring other generators to modify dispatch.10

Figure 4 - Future Daily Load Profiles for Hawaiian Electric

Source: Hawaiian Electric Companies, 2016

8 For simplicity purposes, this report does not consider the implications of capacity factor forecast

inaccuracies on curtailment.

9 For a discussion on the frequency of this at different renewable penetration levels, see “Impact of High Solar and Energy Storage Levels on Wholesale Power Markets” (Black & Veatch / SEPA 2015).

10 See April 2016 PSIP Update Report, pages 5-11, 5-13, 5-15, and 5-17.

2045 2030

2021 2016

Proactive Solutions to Curtailment Risk pg. 14

Given the isolated nature of the independent grids on each of the Hawaiian Islands, the ability to dispatch the output of renewable generation is inherently an essential tool to manage system stability and is likely the lowest cost solution in many circumstances given the large quantities of DERs on this autonomous system. It is conceivable that curtailment levels on O‘ahu may be 10 percent (of a given generator’s output potential) or greater, and 20 percent possibly up to as much as 50 percent on Maui and Hawai‘i Island. If compensation for IPPs is based on energy sales only, these non-trivial curtailment levels will have a direct and measurable impact on the financeability of large renewable projects in Hawai‘i. Moreover, increasingly high levels of must-take energy creates operational constraints on system operators, creating challenges for balancing and managing costs to optimize the total resource portfolio.

Translating Curtailment Risk into Project Economics

Executing a PPA for large renewable resources is increasingly complicated by the uncertainty over curtailment. There are two main ways today that this curtailment risk has been captured, representing opposite ends of a risk spectrum:

Placing all risk on the developer (IPP Risk

Model); or,

Placing all risk on the utility and its customers (Customer Risk Model).

In the IPP Risk model, the PPA provides for energy purchases at a given $/MWh price point with no minimum required offtake (or minimum purchase commitment) by the utility. In essence, the utility can curtail the asset and not incur any financial penalty for doing so. The developer then must attempt to forecast the likelihood of curtailment into its energy price so that the project can be financed.

The alternative Customer Risk approach, sometimes known as the “take-or-pay” contract, is structured such that the utility must pay for any energy that is produced or could have been produced if not for being curtailed. For the IPP, this type of agreement is much easier to finance and can allow for lower PPA prices. For the utility and its customers, however, this type of agreement results in payment for energy that is never delivered –

a result that imputes a higher effective energy price for the resource in question.11 This approach can also be administratively complex, relying upon calculations of “available” versus “delivered” energy that can be challenging to calculate and verify.

11 Effective $/MWh does not include additional costs associated with the provision of electrical service, such

as delivery fees, grid services, etc.

PPA Price = The price stated in the PPA for energy produced by the solar asset; or, in a

take-or-pay contract, the price stated for

energy that is or could have been produced.

Effective $/MWh = The all-in price that

customers pay for energy delivered, after considerations for fixed and variable costs, and payments for undelivered energy.

Proactive Solutions to Curtailment Risk pg. 15

At times when there is greater certainty of energy purchases due to minimal need for curtailment, the difference in price bid to the utility should be minimal between these two structures. The price diverges, however, as curtailment risk appears.

But that is only half the story. The actual impact to developers and consumers is the delta between anticipated curtailment and experienced curtailment. Consider, for example, a utility-scale solar asset that would normally cost $100/MWh over the 20-year term of its PPA. This project has all assurances that the energy will be delivered and sold, with no risk of curtailment. If we insert the anticipation of curtailment at 20 percent, the price for the same project increases to $125/MWh so that the developer retains the revenue stream needed to finance the project. Even if it is a take-or-pay agreement and the price remains at $100/MWh, the utility and its customer base effectively pay $125/MWh for the energy that is ultimately delivered.

The challenge arises when the experienced curtailment varies significantly from what is anticipated at the time of contract execution. Continuing with the example above, consider two scenarios: (1) no anticipated curtailment, and (2) anticipated curtailment for a utility-scale solar asset.

Table 2 demonstrates the impacts to a project’s revenue stream when curtailment is unexpectedly introduced into a project.12 If the IPP owned all of the risk associated with curtailment, they could conceivably under-earn by several million dollars. In this example, the delta in revenue could pose severely negative implications on project finance, including the repayment of debt for the asset. For a take-or-pay contract, customers would be paying as much as 43 percent more per MWh for the energy delivered than was originally anticipated.

Table 2 - Impacts to Project Economics with No Curtailment Anticipated

IPP Risk Model

Customer Risk

Model

Project NPV Change in Project NPV

Take-or-Pay

Effective $/MWh

No Actual Curtailment $1.06 M $ - $100

10% Actual Curtailment

$0.15 M ($0.91 M) $111

20% Actual

Curtailment ($0.76 M) ($1.82 M)

$125

30% Actual Curtailment

($1.67 M) ($2.73 M) $143

Source: SEPA & ScottMadden, 2016

12 Assumes a 10-MW solar project and the anticipated revenues over a 20-year timeframe.

Proactive Solutions to Curtailment Risk pg. 16

When curtailment risk is known in advance, there is still the potential for significant impacts to the overall economics of the project. As shown in Table 3, if the solar developer anticipates 20 percent curtailment over the course of the project, they will adjust the price of the PPA to ensure revenues are maintained. A 10 percent swing in actual curtailment, however, can still negatively impact the developer (from an NPV perspective). For customers under a take-or-pay agreement, they would pay that higher PPA price for any energy delivered. Curtailment below 20 percent would still have an effective rate of $125/MWh, which is 10-25 percent higher than the price needed to meet the developer’s revenue requirements. Curtailment at the 30 percent level would again result in paying an effective price of $143/MWh for energy delivered.13

Table 3 - Impacts to Project Economics with 20 Percent Curtailment Anticipated

IPP Risk Model

Customer Risk

Model

Project NPV Change in Project NPV

Take-or-Pay

Effective $/MWh

No Actual Curtailment $3.33 M $2.27 M $125

10% Actual Curtailment

$2.20 M $1.14 M $125

20% Actual

Curtailment $1.06 M $ -

$125

30% Actual

Curtailment ($0.08 M) ($1.14 M)

$143

Source: SEPA & ScottMadden, 2016

Another metric that provides visibility into project health and financeability is the DSCR. DSCR measures a project’s ability to meet debt obligations with net operating income. In this analysis, DSCR is calculated using earnings before interest, taxes, depreciation, and amortization. A ratio greater than 1.0 indicates that net operating income exceeds debt obligations. A project becomes more attractive (from a financing perspective) as the DSCR increases. Figure 5 outlines the impact to a project’s DSCR based on the risk of curtailment. In the face of likely curtailment, a developer would need to raise its PPA price to maintain the targeted DSCR.

13 One natural reaction to addressing curtailment is to promote energy storage as part of projects. While this solution is discussed further below, at certain levels, curtailment of a resource may in fact be lower

cost than requiring storage. Based on the pricing assumptions used in this report, it is actually more cost

effective to curtail 60% or more of a project before its effective price reaches parity with solar plus storage. As storage costs decrease, however, including storage as part of future solar projects may warrant

consideration.

Proactive Solutions to Curtailment Risk pg. 17

Figure 5 - Curtailment Impact to DSCR

Source: SEPA & ScottMadden, 2016

Millions of dollars can shift between customers and developers depending upon the difference between anticipated curtailment at the time of contract execution and actual curtailment levels experienced over the life of the project. This swing represents a major unknown for all parties, and can significantly impact how developers seek to finance agreements and how the Hawaiian Electric Companies (and the utilities’ regulators) view the value proposition on behalf of customers.

Grid Stability & Reliability in a Majority Renewable Future

A certain combination of resources, which includes synchronous generation, is required to maintain system reliability. Disturbances in frequency, from either load fluctuations or generation trips, is an issue that must be actively managed on any system. For island systems such as exists in Hawai‘i, this issue is exacerbated. With no interconnected neighbors to provide support in the form of shared reserves or ancillary services, the grid is highly susceptible to system disturbances from generation trips or sudden load changes. As distributed solar penetration has increased, the potential for load and frequency fluctuations has been exacerbated – weather changes can cause generation

loss and increased load on a moment’s notice.

Maintaining a reliable system requires a delicate balance between load and generation. If load increases without a commensurate increase in generation, the frequency will drop. If generation is overproduced compared to load, frequency increases. With frequency, small changes can be problematic. Synchronous generation is critical to providing system inertia, which can be thought of as “frequency friction”. Inertia simply means that there

0.00 0.50 1.00 1.50 2.00

No Actual Curtailment

10% Actual Curtailment

20% Actual Curtailment

30% Actual Curtailment

DSCR

Curtailment Impact to DSCR

20% Curtailment Anticipated No Curtailment Anticipated

Proactive Solutions to Curtailment Risk pg. 18

is a large rotating mass generator that – if frequency drops unexpectedly – can help slow

that drop and ramp up its own generation levels to restore system frequency.

As renewable penetration increases, the amount of available synchronous generation has decreased in kind. In island systems such as Hawai‘i, more of one resource must translate into less of another, because there are no neighboring systems with which to exchange energy. The Hawaiian Electric Companies have already taken steps to reduce the minimum run levels of its conventional generation resources; however, as the state moves towards its 100 percent clean energy future, the ability to continue to run conventional generation to provide system inertia may become difficult if not impossible.

This factor also has important implications for the utilities’ ability to provide ancillary services. Ancillary services support the transmission of energy between generation and load and ensure that the system maintains reliable operational characteristics. Two key ancillary services warrant mention with relation to the Hawaiian Electric Companies’ systems:

Spinning reserves are generators that are synchronized to the grid but have available

headroom (unloaded generation) to respond to system needs on a moment’s notice by

increasing their generation level.

Regulation/frequency response are generators that ramp themselves both up and down

on a moment-by-moment basis to respond to the natural variations in supply and demand

in an effort to maintain frequency.

Ancillary services represent an added (and often hidden) cost to an energy system’s economics. In organized Regional Transmission Organization/Independent System Operator (RTO/ISO) markets such as the Electric Reliability Council of Texas (ERCOT) or the PJM Interconnection, active ancillary services markets create transparency around costs and pricing and incent resource owners to provide ancillary services to the grid.14

Table 4 – 2014 Ancillary Services Pricing from Organized Markets

Ancillary Service PJM ERCOT

Spinning reserves $4.21/MWh $12.89/MWh

Regulation $43.68/MWh $14.22/MWh

Source: SEPA & ScottMadden, 2016

Large markets such as PJM and ERCOT have a plethora of available generation that can bid in and provide these types of services to the grid. In Hawai‘i, each individual island’s available generation is all that can provide these supporting services for grid reliability. With a predominantly oil-fired fleet, Hawai‘i’s conventional generators likely have a higher

14 http://www.pjm.com/markets-and-operations/ancillary-services.aspx

https://www.potomaceconomics.com/uploads/ercot_documents/2014_ERCOT_State_of_the_Market_Report.pdf

Proactive Solutions to Curtailment Risk pg. 19

implied cost to provide spinning reserves and frequency regulation services than the natural gas-driven markets in PJM and ERCOT.

In 2012, GE Energy Consulting conducted a study for the Hawaiʻi Natural Energy Institute (HNEI) on the capability of certain generators to provide ancillary services.15 Examining only the Kahe and Kalaeloa plants on Oʻahu and their opportunity costs to provide 1 MW of regulation services, GE found an approximate range of costs from $20-85/MWh per unit.16

Table 5 - Approximate Opportunity Costs at Kahe and Kalaeloa Plants

Plant-Unit Nameplate – MW Approximate Opportunity Cost

Kahe-1 81.6 $20/MWh

Kahe-2 81.6 $25/MWh

Kahe-3 85.8 $30/MWh

Kahe-4 90.9 $25/MWh

Kahe-5 134.9 $30/MWh

Kahe-6 134.9 $20/MWh

Kalaeloa-1 119.2 $85/MWh

Kalaeloa-2 119.2 $85/MWh

Kalaeloa-3 61 $40/MWh

Weigthed Average $42/MWh

Sources: GE Energy Consulting & HNEI, 2012; EIA, 2016; SEPA & ScottMadden, 2016

While this specific study is a bit dated (and due to oil prices at the time of its publication may be inflated relative to operating costs today), it is illustrative of the fact that non-trivial costs are a natural part of maintaining system reliability in the provision of certain ancillary services. The actual cost of providing these services is dependent upon several factors, including the amount of reserves required, fuel costs, and available resources. To that end, the Hawaiian Electric Companies are in the process of filing ancillary services costs as part of a recent docket related to demand response.17 Until those more accurate values are available, the costs listed in the tables above can be considered proxies for the purposes of this report.

With ever-increasing penetration levels of distributed PV, and a desire to phase out oil-fired conventional generation over time, solutions must be developed so that utilities can continue to provide system inertia and ancillary services over the long term.

15 GE Energy Consulting. December 2012. Ancillary Services Definitions and Capability Study.

16 Id., Part 2, Task 3-4, Final Report (December 19, 2012). See slide 44.

17 Docket 2015-0412 – Application for Approval of Demand Response Program Portfolio Tariff Structure.

Proactive Solutions to Curtailment Risk pg. 20

Potential Contract Structures for Utility-Scale Renewables

Facilitating a future of 100 percent renewable energy in the most cost-effective manner will require a fundamental shift in thinking on how to contract for large scale renewable resources. This is driven by the need to proactively address and plan for high curtailment scenarios, while also identifying potential sources of ancillary services over the long term. This section of the report identifies three approaches to restructuring PPAs and redefining how curtailment is managed: Capacity & Energy PPAs; Time-of-Day Price Caps; and, Renewable Dispatchable Generation. 18 All three of these address curtailment risk allocation issues, and the latter also provides an avenue for renewable assets to provide ancillary services for the first time. For all of these structures, any new PPA would move away from reverse chronological curtailment decisions and towards curtailment based on economics or system reliability needs.

I. Capacity & Energy PPAs

Renewable energy projects are fuel-free resources, where virtually all of the costs of the assets are tied up in the cost to finance and construct the facility; however, the historical PPA payment stream for these resources is entirely variable in nature. When curtailment is introduced, the IPP loses revenue that will never be recovered, which has negative implications on project financing. Riskier projects inherently result in higher costs of borrowing, driving up the ultimate price offered to the utility.

The first model proposed for future contracts in Hawai‘i is targeted at creating more surety in revenues for IPPs so that projects become less risky – the Capacity & Energy

PPA. Under this contract structure, the utility creates an RFP that specifically requires bidders to allocate their pricing into two components: a $/MW-month fixed charge and a $/MWh energy charge. The fixed charge provides bidders the ability to identify a guaranteed cash flow stream for their project. Curtailment risk is limited to the energy charge only.

This structure provides the opportunity for the market to price its own risk outlook on curtailment into the bidding process. Rather than forcing either the utility and its customers or the IPP to own all risk, this revised contract structure creates a sharing of curtailment risks and associated costs. Further, it creates a more transparent way to monetize that risk. Executing a contract that allocates capacity and energy payments for a renewable resource necessarily also contains clauses that hold IPPs to minimum availability metrics or risk forfeiting some of the capacity payment each month. Overall, however, this approach should result in less price risk for customers than would be experienced in a take-or-pay arrangement; customers are only exposed to the fixed

18 These three main approaches were the result of a larger effort to identify a wide variety of approaches that could be pursued. A summary of the approaches considered but not included in the final analysis is

available in Appendix A: Additional Models Considered.

Proactive Solutions to Curtailment Risk pg. 21

portion of the project’s total revenue stream when curtailment occurs as opposed to the full take-or-pay PPA price.

For developers, the strategy behind how to bid into this type of RFP is likely founded in their view of curtailment risk and need for more predictable cash flows. Two main triggers are now available for the developer in bidding to the utility: (1) the amount of revenues recovered in a fixed manner; and (2) the level of curtailments that are anticipated over the contract life.

Table 6 – Project Economic Implications: 25 percent of Project Costs Recovered in Capacity Payment

0% Anticipated Curtailment 20% Anticipated Curtailment

Project

NPV

Change in

Project NPV

Customer

Effective $/MWh

Project

NPV

Change in

Project NPV

Customer

Effective $/MWh

No Curtailment

$1.06 M $ - $100 $2.76 M $1.70 M $119

10%

Curtailment $0.38 M ($0.68 M) $103 $1.91 M $0.85 M $122

20% Curtailment

($0.30 M) ($1.36 M) $106 $1.06 M $ - $125

30% Curtailment

($0.98 M) ($2.04 M) $111 $0.21 M ($0.85 M) $130

Source: SEPA & ScottMadden, 2016

Table 7 – Project Economic Implications: 75 percent of Project Costs Recovered in Capacity Payment

0% Anticipated Curtailment 20% Anticipated Curtailment

Project

NPV

Change in

Project

NPV

Customer

Effective

$/MWh

Project NPV

Change in

Project

NPV

Customer

Effective

$/MWh

No

Curtailment $1.06 M $ - $100 $1.63 M $0.57 M $106

10% Curtailment

$0.83 M ($0.23 M) $108 $1.34 M $0.28 M $115

20%

Curtailment $0.61 M ($0.45 M) $119 $1.06 M $ - $125

30%

Curtailment $0.38 M ($0.68 M) $132 $0.78 M ($0.28 M) $138

Source: SEPA & ScottMadden, 2016

As shown in Table 6 and Table 7, the customer’s Effective $/MWh upside risk has been reduced compared to today’s paradigm, while the NPV at risk for the IPP has also been limited. By allowing IPPs to factor their own risk profile into this structure, while providing for some floor level of revenue recovery, the Capacity & Energy PPA creates a platform

Proactive Solutions to Curtailment Risk pg. 22

for all participants to share the risk of curtailments equitably. It reduces the revenue at risk for the developer and reduces price fluctuations for the end customer. The ability for IPPs to manage two different levers (fixed cost recovery and anticipated curtailment) in their future bids to the utility allows the market to define curtailment risk much more effectively.

II. Time-of-Day Price Caps

The second model under consideration creates an avenue for prospective bidders to use innovative system technology and design in a much more transparent manner. Traditionally, RFPs are oriented towards identifying the least cost project over the course of the contract term, which is typically 20 years. In some cases, utilities signal to the market specific hours of delivery that are more valuable than others in order to provide signals on relative value of production. This same idea can be leveraged to create strong incentives for developers to engineer solutions to limit curtailment.

In the Time-of-Day Price Caps (ToD) contract structure, the utility issues an RFP that sets firm caps on the price it is willing to pay for energy delivered in each hour of the day, and potentially, for different months of the year. Bidders respond with prices up to, but not exceeding, the price caps by hour. Alternatively, the utility could establish a PPA price multiplier that limits what it would pay of the PPA price during each hour of the day (see Figure 6). Once the contract is executed, the utility pays the IPP based on those ToD price caps for energy delivered.

Because the Hawaiian Electric Companies’ systems currently have excess generation from distributed PV in the daytime hours, it is highly likely that a ToD RFP would set extremely low (or negative) prices for those same hours, with higher prices allowed for the delivery of energy in hours where net load is highest.19

19 The multipliers selected for Figure 6 and the associated modeling are illustrative in nature only and are

not the result of detailed system dispatch analytics. Rather, they are meant to approximate an exaggerated signal to developers to shift power to better match system net load. Actual PPA price multipliers would be

the result of a detailed system modeling exercise.

Proactive Solutions to Curtailment Risk pg. 23

Figure 6 - Illustrative Time-of-Day Price Cap Curve

Source: SEPA & ScottMadden, 2016

This structure, in which price transparency that proactively takes curtailment into consideration is presented to the market, should create strong incentives for IPPs to engineer innovative solutions that maximize their revenue potential while minimizing the likelihood of curtailed energy. One potential solution could be the incorporation of energy storage; another could be to focus on alternative renewable technologies such as fuel cells. A solar developer could still theoretically bid in and win the RFP, delivering only during hours that are likely lower on the ToD cap scale. If curtailment becomes necessary, this structure would dictate that the price paid for undelivered energy would be set at the ToD caps negotiated in the contract, with curtailment events prioritized towards the lowest caps. This cements the incentive for the developer to be flexible in shifting production away from periods when it can be anticipated that energy is less valuable. And it is not inconceivable that at some point in the future, negative price caps could be required to create enough economic incentive to shift production into the hours with the highest value.

To allow flexibility in the future, as net load patterns changes over time, the PPA may also allow for regular adjustments (e.g., every 5 to 10 years) to the ToD cap curve, as long as the utility maintains a commitment to keep the overall volume under the cap constant. For example, if distributed storage becomes prevalent at the residential level, the net load shape served by the Hawaiian Electric Companies would look substantively different from the illustrative load shape contemplated in Figure 6. Building in a refresh to the ToD price caps at specific intervals would significantly increase the flexibility offered

0%

25%

50%

75%

100%

125%

150%

175%

200%

PP

A P

rice

Mu

ltip

lier

Illustrative Hourly Price Signal

Proactive Solutions to Curtailment Risk pg. 24

by projects under this structure.20 One factor working against this structure is that it is extremely complicated, both for the utility in how it designs the price caps and subsequently reviews proposals, and for the IPP in how it attempts to shape production to meet the needs of the utility.

For simplistic purposes, assume two different approaches to building a project for this price structure. In the first approach, a solar developer builds a traditional south-facing project. Given the price multipliers outlined in Figure 6, the developer knows in advance that generation during the middle of the day, which coincides with solar DER production, would only be paid out at 25 percent of the applicable PPA price. To make their project financially viable, the PPA price would therefore need to be set at $192/MWh, so that production during periods that allow for higher pricing can generate enough revenue overall.

Table 8 - Project Economic Implications: Time-of-Day Alternatives

South-Facing Solar

PPA Price = $192/MWh

South-Facing Solar with Storage

PPA Price = $238/MWh

Project

NPV

Change in Project

NPV

Effective $/MWh

Project NPV

Change in Project

NPV

Effective $/MWh

No Actual Curtailment

$1.1 M $ - $100/MWh $2.7 M $ - $274/MWh

10% Actual Curtailment

$0.6 M ($0.5 M) $106/MWh $2.7 M $ - $275/MWh

20% Actual Curtailment

$0.2 M ($0.9 M) $113/MWh $1.5 M ($1.2 M) $284/MWh

30% Actual Curtailment

($0.2 M) ($1.3 M) $122/MWh ($0.2 M) ($2.9 M) $298/MWh

Source: SEPA & ScottMadden, 2016

To the utility’s customers, the same revenue stream and associated energy is delivered. Assuming no curtailment occurs, the Effective Price is $100/MWh. As curtailment is incorporated, revenue allocation is shifted to times of the day when curtailment is less likely. The IPP retains a positive project NPV across virtually all curtailment scenarios modeled. For the customer, their upward price risk (on an Effective $/MWh basis) is limited compared to today’s take-or-pay structure as well.

A second approach for the IPP is to incorporate energy storage into the project. For purposes of this report, a 17-MW lithium-ion battery, which is large enough to shift several hours of on-peak production, was incorporated into the project. The battery was modeled to shift energy out of the lowest tier price cap period and into the highest tier.

20 This flexibility would likely come at a cost, as it may necessarily require storage to be incorporated.

Alternatively, it could favor more dispatchable renewable technologies such as biomass and biogas.

Proactive Solutions to Curtailment Risk pg. 25

As shown in Table 8, this battery shifts enough energy in its base design to avoid up to 20 percent curtailment. To the customer, the result is a significantly higher Effective $/MWh; however, this approach did succeed in shifting energy outside of a window of time when there was excess generation on the system and into a window when the utility likely does need firm power supply. While not economic for the customer at present, continued reductions in storage pricing and increases in efficiency could make this a viable option in the future.21

This structure, incorporating solar and storage together and responding to a set of firm price signals from the utility, is functionally similar to the announced project between Kauai Island Utility Cooperative (KIUC) and SolarCity. In that agreement, SolarCity is developing a 13-MW-ac solar project coupled with a 13-MW/52-MWh battery, which will be dispatched based on KIUC’s preference. In its filing in support of this PPA, KIUC mentions intending to use 80-85 percent of the output to charge the battery so that it can be used for late afternoon ramping and evening peak shave purposes.22 This same concept and structure could arise organically out of a ToD RFP, in which developers have the opportunity to identify unique engineering solutions to a specific utility problem statement.

III. Renewable Dispatchable Generation

One of the fundamental issues with resources such as solar or wind is that they are, at their current state, non-dispatchable. The final new contract option for consideration leverages an agreement structure that is prevalent for natural gas contracts and transfers it to the world of renewable resources in an effort to create dispatchability. This new structure converts the utility’s role from a passive taker to a proactive asset manager.

In the world of natural gas generation, the tolling agreement is a structure in which the utility schedules in natural gas to the third-party-owned plant, providing a schedule for production.23 The third-party’s role is to guarantee a heat rate and availability for its plant. The utility pays the IPP a fixed capacity payment and then assumes all price volatility for the fuel.

Renewable Dispatchable Generation (RDG) takes a similar approach to dispatching generation; however, rather than basing the schedule and dispatch on the delivery of the fuel source under utility control, this structure schedules the percentage of potential production based on the solar or wind resource available on any given day, factoring in

21 Based on modeling, the cost of lithium-ion batteries would need to decline by 32 percent from today’s estimated levels for this approach to break even with the south-facing solar system modeled under the

ToD structure.

22 See Docket No. 2015-0331 application, filed September 10, 2015.

23 While not currently used in Hawai‘i, the tolling agreement is a relatively common contractual arrangement

in other U.S. markets.

Proactive Solutions to Curtailment Risk pg. 26

the needs of the system from both a cost and reliability standpoint. Under ideal circumstances the IPP would:

Guarantee minimum availability metrics to ensure the equipment is maintained

and available for production;

Meet technical and operational characteristics which support grid operation,

including voltage regulation, disturbance ride-through, frequency response, and

active power control; and,

Provide an indication to the utility of the available energy in the near real-time.

Similar to a tolling agreement for a conventional resource, these guarantees provide the basis for the energy production (MWh) expected for a given solar irradiance or wind speed. The utility, in turn, controls the output of the facility (both real and reactive power) on a real-time basis.

From an economic standpoint, the utility pays a fixed payment per month to ensure that the system is financeable and a variable $/MWh component to cover variable operations and maintenance (O&M) costs (if applicable, depending upon the resource). Any unscheduled energy, up to the amount capable of being produced given existing weather, becomes spinning reserves – unloaded generation that can be called upon in minutes –

or is deployed automatically according to defined frequency response parameters, in a manner similar to conventional plant droop response.

For example, assume a solar plant with a nameplate capacity of 10 MW. Figure 7 depicts an average day’s production curve for that plant.

Figure 7 - Average Day Solar Production Curve

Source: SEPA & ScottMadden, 2016

-

1,000

2,000

3,000

4,000

5,000

6,000

7,000

kW

Potential Production

Proactive Solutions to Curtailment Risk pg. 27

Now assume that under the RDG structure, the utility intentionally dispatches the resource at 50 percent production. Later, due to a need to serve greater demand, the utility increases the production to 100 percent in the late afternoon.

Figure 8 - Potential Ancillary Services Created by Renewable Dispatchable Generation

Source: SEPA & ScottMadden, 2016

As shown in Figure 8, the ability to ramp up that solar asset created over 3 MW of upward spinning reserves on this average day, with over 2 MW of increased generation actually leveraged from 3-4pm. This resource can also provide downward spinning reserves during all producing hours. Alternatively, that same unloaded generation could be used for regulation purposes, with the inverter allowed to vary output based on the system frequency at any given moment. By purposefully under-scheduling the solar asset, the solar generator can contribute to the provision of ancillary services. Historically, variable renewables resources have not provided these types of grid services. Adding the ability to provide spinning reserves and frequency response reduces the integration costs of adding these assets to the system, effectively increasing their overall value to the Hawaiian Electric Companies. With a push towards a 100 percent clean energy future, these added capabilities may become critical to system reliability.

From a purely economic perspective, the RDG must be measured against both nominal impacts and net impacts after factoring in the benefits associated with the provision of ancillary services from the renewable resource. Using the approximated weighted average opportunity cost for the Kahe and Kalaeloa plants outlined in Table 5, a proxy value for spinning reserves and regulation services of $42/MWh is assumed for any synchronized,

-

1,000

2,000

3,000

4,000

5,000

6,000

7,000

Pro

du

ctio

n (

kW

)

Creation of Reserves from RDG

Spinning Reserves Potential Production Signaled Production

Proactive Solutions to Curtailment Risk pg. 28

unloaded (rather than curtailed) generation from a RDG asset. 24 While increased unloaded generation results in a higher gross effective payment by customers, the ability to provide ancillary services from that facility provides a quantifiable value stream, creating a lower net effective price.25

Table 9 - Customer Economic Impacts of Renewable Dispatchable Generation

Project NPV Gross Effective

$/MWh

Ancillary

Services Impact

Net Effective

$/MWh

Full Asset

Utilization

$1.11 M

$100 $ - $100

10% Unloaded $112 ($5) $107

20% Unloaded $126 ($9) $115

30% Unloaded $144 ($18) $126

Source: SEPA & ScottMadden, 2016

From a financing perspective, the RDG provides guaranteed revenues (assuming the asset manager meets its minimum availability and energy production potential requirements), which should result in more certainty around debt service coverage and equity returns.

Challenges remain in transitioning directly to this new contract structure from today’s paradigm. There will likely be several iterations related to resource forecasting and associated availability metrics, as well as additional operational challenges to overcome.

The idea of limiting the production from a renewable resource may seem counterintuitive – the energy produced is clean and lacks any real fuel dispatch cost. In Hawai‘i, however,

this may be the exact type of solution needed to help the state achieve its 100 percent renewable energy goal. At some point renewable, non-dispatchable resources will have to contribute ancillary services to support grid reliability.

Identifying Minimum Availability Metrics

For both the RDG and the Capacity & Energy PPA approaches, the concept of minimum availability metrics was broached. For these structures to succeed, the IPP must be contractually obligated to guarantee a specific availability for, and maintenance of, the equipment used to transform the raw renewable resource into energy. For the Capacity & Energy PPA, this obligation becomes the foundation of the monthly fixed payment for

24 Net Effective $/MWh = Delivered Energy x Gross Effective $/MWh + Ancillary Services Impact. Ancillary

services impact is the levelized value of having the unloaded energy available for spinning reserves or

regulation services.

25 Because solar O&M costs tend to be more fixed/predictable in nature than variable costs, this example

assumes that all costs are recovered via the fixed payment, with no variable payment included.

Proactive Solutions to Curtailment Risk pg. 29

the resource. Failure to provide the capacity dictated in the agreement (with adjustments allowed for seasonal production differences and degradation) would result in IPP overpayment for the offered product. The RDG concept hinges on the ability to accurately predict potential renewable resource production at a given point in time, which becomes increasingly challenging as the forecast periods lengthens.

The agreed upon metrics for each of these structures may be different. In a contract that leverages the Capacity & Energy PPA structure, the peak hourly production each month is the basis of the capacity payment, and the minimum availability metric could be simply a monthly minimum MW guarantee for the plant’s production (with adjustments annually for natural degradation). The fixed capacity payment would be reduced if the contracted capacity is not available. This simple structure allows for transparency between the utility and the IPP.

In an ideal RDG structure, the parties must be able to calculate resource availability based not only on equipment condition but also on the availability of the renewable resource at any given moment; to be clear, a challenge exists in gathering the necessary data. Therefore, a more formulaic approach becomes necessary. The parties must have a transparent and agreed upon approach to understanding what the production in any given hour should be so that the percentage dispatch can be calculated and tracked accordingly. One approach could be for the IPP to monitor the hourly solar radiation on site and guarantee a solar panel yield and performance ratio (covering losses, panel-specific shading, and any temperature adjustments necessary). The IPP would be required to provide equipment status as well as all telemetry required for the utility’s energy forecasting purposes. Resource forecasting is performed today, and the same processes and calculations can become the foundation for codifying minimum availability metrics in the RDG contract.

Long-Term Impacts to Dispatch and Curtailment Order

Legacy renewable contracts have very stringent restrictions surrounding the ability to curtail those resources. Consequently, in Hawai‘i, curtailment order has been defined on a reverse-chronological basis, with the newest projects curtailed first, regardless of the relative costs or impacts to system reliability. As new contracts are executed and those legacy agreements term out, the curtailment order can be changed so it is based more closely on economics rather than execution date. For standard agreements, the PPA price is the most logical trigger for curtailment order, with flexibility outside of economic dispatch based on specific local system needs.

The same would hold true for the Capacity & Energy PPA structure. Contracts structured with a lower fixed cost and higher energy cost would be more likely to be curtailed. While this may motivate developers to bid high capacity costs and low energy costs, that approach may not align with how the Hawaiian Electric Companies value proposals in a competitive RFP process. However, placing the impetus on market players to determine

Proactive Solutions to Curtailment Risk pg. 30

how to best manage their risk surrounding curtailments should provide more certainty to the Hawaiian Electric Companies, as they pursue a least cost alternative for consumers.

For the ToD Price Caps structure, curtailment would actually start with the lowest energy priced deal. This is because the price signals embedded in the contract already encourage energy production outside the most likely window of time that curtailments occur. Developers seek to maximize energy production outside of that timeframe and recognize contractually that production during those hours is at risk.

The RDG reframes the discussion on curtailment completely, as it is designed to provide system reliability services first and deliver energy second; the system operator has the ability to consider the most optimal dispatch of the system. Therefore, it is more appropriate to consider how that type of project fits into the economic dispatch stack. There may be many days of the year when that asset should produce power at 100 percent of its capability at an effective dispatch cost of $0/MWh, because all costs associated with the project are fixed in nature. Other times of the year, that asset should be dispatched at a much lower level (e.g., 50 percent of its potential) so that it has headroom to move up and down based on system needs or because there is insufficient demand for the energy.

Impacts to Debt Service Coverage

DSCR was chosen as a key metric because it can act as a proxy measure for the riskiness of a project. Curtailment has a direct impact on the perceived risk of a project to financiers, which can translate directly into a higher required DSCR for the project to move forward. For each of the scenarios contemplated in this report, the downside risk for IPPs is less than they currently experience under contracts in which they “own” all curtailment risk.

Proactive Solutions to Curtailment Risk pg. 31

Figure 9 - DSCR @ Risk: 0% to 30% Actual Curtailment

Source: SEPA & ScottMadden, 2016

The range of possible DSCR values, based on the variety of curtailment scenarios modeled, narrowed considerably for several contract structures. The Capacity & Energy PPA structure provided less DSCR at risk for the scenario in which 25 percent of project costs were recovered via a fixed payment, with the 75 percent fixed payment structure providing significantly less variability overall. The RDG guaranteed the DSCR target was met because of the fixed nature of the revenues.

0.60

0.80

1.00

1.20

1.40

1.60

1.80

IPP Risk, NoAnticipatedCurtailment

IPP Risk, 20%AnticipatedCurtailment

25% CapacityPayment, NoAnticipatedCurtailment

25% CapacityPayment, 20%

AnticipatedCurtailment

75% CapacityPayment, NoAnticipatedCurtailment

75% CapacityPayment, 20%

AnticipatedCurtailment

ToD - South-Facing Solar

ToD - Solarwith Storage

RenewableDispatchableGeneration

DSC

R

IPP Risk0% Curtailment to 30% Curtailment

Proactive Solutions to Curtailment Risk pg. 32

Next Steps

To start down this path to innovation, the following items are suggested for additional discussion and review. These and many other conversations will help better identify “win/win” solutions for Hawai‘i.

Understanding Accounting Treatment

One issue that requires examination prior to transitioning to new contract structures is that, depending on the particulars of the agreement in question, utility accounting principles could require significantly different treatment of project costs. This is because certain PPAs could, for accounting purposes, be treated as a lease agreement. If the agreement is considered a capital lease under current accounting guidance (or simply a lease under ASU 2016-02), the utility must record a lease asset and a corresponding liability (i.e., lease obligation) on its financial statements. The lease obligation is considered a form of debt that results in the inclusion of additional leverage in the utility’s capital structure. This negatively affects the utility’s financial ratios. Under current accounting guidance, if the agreement is an operating lease, it is disclosed in the footnotes and not reported on the balance sheet.

Determination of whether a PPA constitutes an operating or capital lease is extremely contract-specific and project-specific, and two different solar assets could be classified differently based on their unique contractual terms and conditions. This determination is important, because the impact to the utility’s financial statements from recognizing a project as a capital lease rather than an operating lease can be significant. Because recently revised accounting rules that will become effective in 2019 may increase this risk, this assessment is ongoing.

Updating Procurement Practices

Moving from concept to execution on any of the above ideas requires a reshaping of the procurement process from one driven predominantly by lowest price for delivered energy, to one that balances multiple pricing and delivery options against long-term price risk for consumers. For each of the structures identified, IPPs, regulators, utility companies, and other major stakeholders need to work together to determine how future RFPs can be designed so that: (1) IPPs have a clear picture of how projects will be valued; and (2) the Hawaiian Electric Companies can receive clear, transparent, and detailed information from IPPs to expedite the review process. These parties also need to agree on how to manifest these new ideas into contract language.

Proactive Solutions to Curtailment Risk pg. 33

Leveraging New Technology

This report focuses on how to:

Modify existing contract structures with developers to both lessen their risk to finance

projects while also limiting the risk of severe price fluctuations to the end consumer; and,

Reduce the constraints on the system operator to manage available resources according

to their relative costs and reliability impacts on the system.

Other technologies, such as grid-facing solutions, that could meet similar end goals, were not examined here. One example to highlight is the integration of energy storage on a system level, rather than on a project level as contemplated in the ToD concept. Larger, centralized energy storage assets could help balance supply and demand more efficiently by storing solar generation for later dispatch. Storage could also be used to provide ancillary services. Indeed, the Hawaiian Electric Companies have already begun researching the potential for energy storage to provide synthetic inertia – near

instantaneous response to frequency fluctuations. This and other applications for energy storage warrant further discussion and research, as the best solution for Hawai‘i is most likely a holistic package of customer, developer, and utility investments that are collaboratively planned. These considerations and others can be part of a robust integrated resource planning process that weighs the relative pros and cons of different resources and contract structures for the benefit of all customers over the long term.

Proactive Solutions to Curtailment Risk pg. 34

Conclusion

The procurement of incremental utility-scale renewable resources will be critical to meeting Hawai‘i’s energy future; however, those resources will be called upon to become increasingly more flexible as they comprise larger portions of the total energy portfolio. The question that must be answered is how to address the need for flexible, renewable generation while mitigating the potential costs to consumers. This requires PPA structures that:

Provide flexibility to adjust to the changing nature of the grid;

Create adequate value to the developer;

Deliver energy at a reasonable price for the utility; and,

Meet the risk parameters amenable to regulators.

The goal of this report is to begin identifying new ways to contract for non-dispatchable renewable resources that meet each of these criteria; and with the complexities envisioned in the future, more than one alternative contract structure may be desired.

To varying degrees, both the Capacity & Energy and ToD contract structures shift the identification and quantification of curtailment risk away from the utility and onto the IPP. In this way, the development community can incorporate this major risk factor into how they structure proposals in future RFPs, creating the potential for the market to converge on a least-risk solution in a transparent manner. The RDG shifts the intent of contracting for utility-scale renewables away from an energy-only model and towards increasing system reliability while delivering clean energy. Large solar and wind projects mimicking the dispatchability of a conventional asset will be key in Hawai‘i to achieve its vision of 100 percent renewable energy.

While the applicability of any of these proposed contract structures could vary depending on the type of project, location, and developer risk profile, understanding the impacts of curtailment across a variety of payment structures to the IPP’s financing risk is important. The IPP’s incorporation of that risk, driven by issues such as curtailment, will be directly reflected in the price the customer sees. This report considers both IPP and customer risk in an effort to identify “win-win” solutions for future PPA negotiations. The results of this analysis are summarized in the below graphics.

Proactive Solutions to Curtailment Risk pg. 35

Figure 10 - Impact of New Structures on NPV @ Risk

Source: SEPA & ScottMadden, 2016

All identified contract structures have decreased NPV at risk for the IPP (see Figure 10). By agreeing to shift to any of these structures for new PPAs, the IPP can gain more confidence in cost recovery and their ability to earn their desired return on the project in question.

Figure 11 - Impact of New Structures on DSCR @ Risk

Source: SEPA & ScottMadden, 2016

($2.0)

($1.5)

($1.0)

($0.5)

$0.0

$0.5

$1.0

$1.5

$2.0

$2.5

$3.0

25% CapacityPayment, NoAnticipatedCurtailment

25% CapacityPayment, 20%

AnticipatedCurtailment

75% CapacityPayment, NoAnticipatedCurtailment

75% CapacityPayment, 20%

AnticipatedCurtailment

ToD - South-Facing Solar

RenewableDispatchableGeneration

Pro

ject

NP

V (

$M

)

Project NPV @ Risk

No Actual Curtailment 30% Actual Curtailment

Current State - No Curtailment Risk Current State - 30% Curtailment Risk

0.000.200.400.600.801.001.201.401.601.80

25% CapacityPayment, NoAnticipatedCurtailment

25% CapacityPayment, 20%

AnticipatedCurtailment

75% CapacityPayment, NoAnticipatedCurtailment

75% CapacityPayment, 20%

AnticipatedCurtailment

ToD - South-Facing Solar

RenewableDispatchableGeneration

DSC

R

Debt Service Coverage Ratio @ Risk

No Actual Curtailment 30% Actual Curtailment

Current State - No Curtailment Risk Current State - 30% Curtailment Risk

Proactive Solutions to Curtailment Risk pg. 36

All considered contract structures improved the project’s DSCR compared to the current state approach with high curtailment risk, with all but one scenario resulting in a DSCR higher than 1.0 under 30 percent actual curtailment (see Figure 11). This provides further comfort for IPPs and their financiers when determining how curtailment will impact project cash flows.

Figure 12 - Impact of New Structures on Effective $/MWh for Energy Delivered to Utility

Source: SEPA & ScottMadden, 2016

All modeled contract structures resulted in lower Effective $/MWh for energy delivered, meaning the customer is better off even under high curtailment situations (see Figure 12).

By proactively identifying and allocating the risk of curtailed energy, it is possible to create contract structures for utility-scale renewable generation that result in net benefits for all parties. Taking advantage of these types of innovative contract structures in Hawai‘i can lead to better integration of utility-scale projects that are both cost-effective and have the ability to support system reliability as the state moves towards 100 percent clean energy.

$0

$20

$40

$60

$80

$100

$120

$140

$160

25% CapacityPayment, NoAnticipatedCurtailment

25% CapacityPayment, 20%

AnticipatedCurtailment

75% CapacityPayment, NoAnticipatedCurtailment

75% CapacityPayment, 20%

AnticipatedCurtailment

ToD - South-Facing Solar

RenewableDispatchableGeneration

Net

Eff

ecti

ve

$/M

Wh

Effective $/MWh for Energy Delivered to Utility

No Actual Curtailment 30% Actual Curtailment

Current State - No Curtailment Risk Current State - 30% Curtailment Risk

Proactive Solutions to Curtailment Risk pg. 37

Table of Acronyms

BESS: Battery Energy Storage System

CEP: Curtailed Energy Price

DA: Day Ahead

DEP: Delivered Energy Price

DER: Distributed Energy Resources

DSCR: Debt Service Coverage Ratio

EIA: Energy Information Administration

ERCOT: Electric Reliability Council of Texas

GE: General Electric

HA: Hour Ahead

HNEI: Hawai‘i Natural Energy Institute

IPP: Independent Power Producer

ISO: Independent System Operator

KIUC: Kauai Island Utility Cooperative

kW: Kilowatt

MW: Megawatt

MWh: Megawatthour

NEM: Net Energy Metering

NREL: National Renewable Energy Laboratory

NPV: Net Present Value

O&M: Operations and Maintenance

PPA: Power Purchase Agreement

PV: Photovoltaic

RDG: Renewable Dispatchable Generation

RFP: Request for Proposals

RTO: Regional Transmission Organization

SDC: System Decremental Cost

SEPA: Smart Electric Power Alliance

ToD: Time-of-Day

Proactive Solutions to Curtailment Risk pg. 38

References

Energy Information Administration. April 2013. Updated Capital Cost Estimates for Utility Scale Electricity Generating Plants.

Energy Information Administration. Form EIA-861 data. https://www.eia.gov/electricity/data/eia861/.

GE Energy Consulting. December 2012. Ancillary Services Definitions and Capability Study.

GTM Research / SEIA. 2015. US Solar Market Insight Q3 2015 Report.

Hawaiian Electric Companies’ PSIPs Update Report, Docket No. 2014-0183, April 1, 2016.

Joe, B., Hong, M., and Sterling, J. 2015. Impact of High Solar and Energy Storage Levels on Wholesale Power Markets.

Kauai Island Utility Cooperative Application, Docket No. 2015-0331, September 10, 2015).

Lazard. November 2015. Levelized Cost of Energy Analysis v 9.0.

Lazard. November 2015. Levelized Cost of Storage Analysis v 1.0.

NREL. June 2012. Photovoltaic Degradation Rates – An Analytical Review.

NREL System Advisor Model, Version 2015.6.30.

PJM. 2014. Ancillary Services Market Results 2014 Excel Spreadsheet. http://www.pjm.com/markets-and-operations/ancillary-services.aspx

Potomac Economics, Ltd. July 2015. 2014 State of the Market Report for the ERCOT Wholesale Electricity Markets.

PricewaterhouseCoopers LLP. 2013. Guide to Accounting for Utilities and Power Companies.

Proactive Solutions to Curtailment Risk pg. 39

Appendix A: Additional Models Considered

Table 10 - Additional Contractual Models Considered

Solution Description Potential Implications

DEP / CEP PPAs

o Require bidders to provide a Delivered Energy Price (DEP) and a Curtailed

Energy Price (CEP), both in $/MWh o No floor or cap imposed on CEP pricing

o Could allow for tiered CEP pricing

o Curtailed energy compensated at CEP

o Bidders can price their risk outlook

into the breakout in payment streams, but not likely to result in

major cost savings

Curtailment

Bank

o For any curtailed energy that is paid for

by the utility, the same amount of

energy must be delivered after the end of the base contract term

o Proposed unsuccessfully in recent

PPAs

BESS for

Curtailment

o Require Battery Energy Storage

Systems (BESS) at all new non-dispatchable resources

o BESS is sized to meet a minimum curtailment window of storage

o Curtailment beyond BESS sizing paid at a predetermined rate

o Deploying BESS strictly for

curtailment is unlikely to be cost-effective; would need to

incorporate additional BESS value

streams like smoothing, frequency control, etc.

Rotating Monthly

Bands

o Create monthly min/max bands for

PPAs, where the bands differ based on anticipated curtailment issues in those

months

o Each new PPA is treated uniquely for the bands, allowing for the potential to

rotate which months are most curtailable at each

o Creates opportunity for curtailment diversity among

projects

SDC Curtailment

o For any curtailed energy, the utility pays

the developer their System Decremental Cost (SDC) rather than the PPA

stipulated price o SDC would be calculated based on a

cost-based rate formula that would be

approved and routinely updated

o Aligns cost borne by ratepayers with a measure more akin to the

value of that decremental energy o Unknown SDC introduces

additional risk for the IPP

Pro Rata

Decrease

o When curtailment is required, all applicable projects are required to back

down at the same percentage so that, in total, the needed curtailment is met

o May limit the magnitude of an

individual IPP’s curtailment risk, but may not reduce the nominal

risk across an individual island for

those customers

Source: SEPA & ScottMadden, 2016

1

“Electricity 2030: Trends and Tasks for the Coming Years” CAISO Vision Discussion Paper (October 2017)

Comments of the Independent Energy Producers Association (IEP)

November 20, 2017

The Independent Energy Producers Association (IEP) is pleased to provide these Comments in

response to the CAISO’s Vision Discussion Paper: “Electricity 2030-Trends and Tasks for the Coming

Years” (Vision Paper, October 2017). The CAISO’s Vision Paper is broad in scope, focusing on large state

and national trends. While delineating eight broad trends and suggesting a range of tasks to be

accomplished in light of these trends, the Vision Paper correctly notes that “many of the actions

suggested … are not within the purview of the ISO.” IEP concurs with this assessment.

Overall, we find the Vision Paper not particularly helpful in illuminating what, if anything, the

CAISO management will be “tasked” to accomplish over the near term, e.g. 1-5 years, related to the

CAISO’s primary function to maintain 60 Hz on the electric transmission grid and administer wholesale

markets in a just, reasonable and non-discriminatory manner in light of a dynamically evolving energy

sector. We ask that the CAISO Board revisit the Vision Paper to address more fully issues identified in

these comments, because policymakers, planners and certainly market participants would be best

served if the CAISO’s Vision Paper addressed issues for which it has primary responsibility, particularly

those issues that are front and center today.

In this regard, IEP offers the following comments within which we pose a number of important

questions that we believe should inform the CAISO’s Vision Paper.

I. What is the Role and Responsibility of the ISO?

“The specific purpose of this Corporation is to ensure the efficient use and reliable operation of the electric transmission grid

pursuant to the Statute”.1

As prescribed by its Articles of Incorporation, the CAISO’s primary purpose is to ensure a reliable

electric grid. The CAISO must ensure a reliable electric grid in spite of and because of an ever-changing

policy environment. To achieve this purpose, the CAISO manages the transmission grid and, equally

1 CAISO Articles of Incorporation, 5 May 1997

2

important, the CAISO administers wholesale markets in a just, reasonable and non-discriminatory

manner.

Yet, as noted above, the CAISO’s Vision Paper veers into areas and issues residing outside its

purpose and, arguably, outside the CAISO’s core competency. As a result, scarce CAISO (and

stakeholder) resources are diverted from critical issues that deserve greater attention. The Vision

Paper, for example, focuses extensively on trends related to distributed energy resources (DER)

primarily interconnected to the distribution system. In this context, the Vision Paper implies that it is

the role of the CAISO to pick-and-choose wholesale market winners (e.g. actively work to phase out gas

generation) while significantly favoring a distribution-based model not under its domain.

On the other hand, the Vision Paper barely mentions transmission, transmission planning or

wholesale market reforms. For example, the Vision Paper does not discuss what, if anything, the CAISO

plans to do over the next 1-5 years to facilitate access to low-cost, GHG-free transmission-

interconnected renewables needed to help de-carbonize the electric and transportation sectors.

Typically, the cost of these utility-scale renewable resources is less than distributed resources ($/kWh)

and these resources are positioned well to serve load located throughout California. As a practical

matter, the primary impediment to expanding access to these low-cost resources is the availability of

transmission.

In the context of discussing a CAISO Vision, it would be helpful for the CAISO to address the

following:

• What is the CAISO Plan for accessing low-cost, transmission-interconnected renewable

resources over the next 1-5 years? Where are the market signals to these resources that, if

they develop the resource, they will have a transmission path to load?

• What is the transmission plan if distributed resources don’t emerge in a timely and cost-

effective manner to support the grid and/or serve load?

II. What is the “vision” on for sustaining existing resources determined to be needed to achieve the de-carbonized world of 2030?

The primary role of the CAISO is to ensure a reliable grid. In this regard, the CAISO administers

wholesale markets in a just, reasonable and non-discriminatory manner; thereby, enabling greater

3

competition among all available resources to provide needed services. In this context, IEP couldn’t help

but note that one of the major trends identified in the Vision Paper is “Gas-fired generation declines

significantly as the grid is modernized.”2 While it is true that the gas-fired generation fleet may decline

over the next decade, the Preliminary Reference Plan in the CPUC Integrated Resource Plan (IRP)

proceeding indicates under the baseline resource assumption scenario that all thermal plants (17,635

MWs CCGT and 12,376 MWs Peaker) not scheduled for OTC retirement remain available and on-line in

2030.3

It is important to note that California has worked to develop a mixed portfolio of resources to

ensure grid reliability and help de-carbonization the electric sector over the past 17 years. This

portfolio includes renewables, expanded energy efficiency, as well as clean natural, along with

increasing amounts of storage and advanced inverters as the become increasingly competitive. Indeed,

California has been heavily invested in modernizing. California’s aged thermal fleet has been replaced or

repowered with relatively clean, natural gas electric generation wherever and whenever possible. For

example, 9,400 MWs of aging gas facilities retired and shut-down between the years 2001-2014.

The evidence clearly recognizes a need for this type of generation (flexible capacity), yet the

market provides little if any means to ensure that competitive resources that can provide these

necessary services are available to the CAISO when and where needed. Importantly, the Vision Paper is

silent on what, if anything, the CAISO intends to do to address this matter.

4 Many

of these plant retirements have occurred in disadvantaged communities such as Hunters Point, Potrero,

and South Bay. By 2025, an estimated 15,479 MWs of generation will have retired [e.g. once-thru-

cooling (OTC) units and the Diablo Canyon Nuclear Generating Facility].5 By 2030, an additional 1,615

MWs of older, OTC units owned by the Los Angeles Department of Water and Power (LA DWP) are

planned to repower or be replaced.6 As a result of the fleet make-over, air quality analyses show that

Natural Gas Generation is not a major source of criteria air pollution (NOx, PM2.5 and SOX). Indeed,

the CAISO SB 350 Study notes that “Electricity production by natural gas represents~1% of the entire

California inventory.”7

2 CAISO Vision Discussion Paper, p. 10

Moreover, the California Energy Commission (CEC) has concluded that “motor

3 CPUC Preliminary Resource Plan, November 2, 2017, Slide 33. 4 Thermal Efficiency of Gas-Fired Generation in California: 2015 Update, California Energy Commission Staff Paper, page 7. 52017 Draft Integrated Energy Policy Report (IEPR), California Energy Commission, page 103 6 Tracking Progress: Once Through Cooling, California Energy Commission, March 8, 2017, p. 7 7 Clean Energy and Pollution Reduction Act Senate Bill 350 Study: Preliminary Results, [CAISO Presentation], May 24, 2016, Aspen Environmental Group, slide 118

4

vehicles represent the largest source of air pollution that harms human health, accounting for nearly

80% of the nitrogen oxide emissions and 90% of diesel particulate matter emissions in the state.”8

With regards to that gas-fired generation fleet that is expected to be available to the CAISO

throughout the transition to the 2030 de-carbonized environment, the wholesale markets administered

by the CAISO provide only short-term pricing signals to these resources.

9

It is noteworthy that the lack of a long-term capacity procurement structure affects not just gas-

fired generation. Other resources, such as Demand Response and Storage face the same economic

challenges as gas-fired generation. For example, studies have concluded that “By far the number one

barrier to entry for direct participation of demand response in the ISO, after completion of Electric Rule

24, is the lack of revenues available to resource owners from the wholesale market.”

Yet, within this context, the

trend is to undermine revenue sufficiency for needed resources, because CAISO mid-day energy prices,

which historically supported these needed resources with critical revenue(s), are increasingly

suppressed and often are negative due to 10,000 MWs of utility-scale solar, 5,000 MWs of distributed

solar, etc. As a result, CAISO wholesale markets currently undermine critical signals for capital

investment and, thus, are inadequate for ensuring the availability of needed generation.

10

In response to this economic reality, many parties including CAISO management have raised

concerns about the viability of the existing resource adequacy (RA) framework serving California. In the

context of proposing solutions for a known problem, some parties believe a multi-year forward RA

Framework ought to be implemented. Other parties have suggested the need for centralized capacity

market. Whatever the ultimate solution is adopted, the evidence clearly indicates that different

capacity framework is needed to compliment the energy-only markets that prevail today.

Yet, the Vision Paper is silent on this critical issue even though this issue falls squarely within the

CAISO’s domain. In order to address this matter, IEP recommends that the Vision Paper be revised to

address the following critical issues:

• What is the CAISO’s Vision for addressing revenue insufficiency faced by resources that studies

show will be needed over the next decade? What is the “bridging” mechanism to ensure that the

8 2017 Draft Integrated Energy Policy Report, California Energy Commission, page 3 9 Short-term pricing signals derive from CAISO Day-Ahead and Real-Time energy markets. Short-term pricing signals also derive from one year resource adequacy (RA) contracts; one-year Reliability-Must-Run (RMR) contracts; and/or CAISO real-time ancillary service (AS) markets. 10 Olivine, “Distributed Energy Resources Integration: Summarizing the Challenges and Barriers,” January 24, 2014.

5

resources identified as available, online, and needed have a reasonable means to a revenue

stream to ensure this planned outcome?

• Is the perceived “surplus” of capacity in the CAISO service area real and persistent (i.e. if real,

will it persist through 2030);

• What is the risk that market corrections (e.g. plant closures) occur over a short period of time

impacting the availability of system, local and /or flexible RA?

o Is system reliability undermined by the current Resource Adequacy Framework? If so,

what new framework should be considered?

o Is the re-emergence of Reliability –Must –Run (RMR) contracts and/or increasing use by

the CAISO of the backstop, Capacity Procurement Mechanism (CPM) clear evidence of

the failure in addressing the capacity needs of the system?

The CAISO should focus on making wholesale market changes that facilitate the 2030 “vision”

but the CAISO must not assume that the 2030 world is here yet. Reliability and affordability are

foundational elements in meeting California’s de-Carbonization Goals. In the context of de-carbonizing

the electric and transportation sectors, multiple agencies and entities such as the CAISO are chartered

under the laws of California (and FERC) to perform certain essential functions. The CAISO should focus

on those near-term and mid-term wholesale market reforms that help maintain the reliable and

efficient use of the transmission grid in an ever-changing competitive market, including how best to

provide resources competing in the CAISO’s wholesale markets a reasonable assurance of revenue

sufficiency for needed resources to plan necessary investment needed over a short- to mid-term time

horizon (e.g. 3-5 years). In addition, the CAISO Vision Paper should address what the CAISO

management will be tasked to accomplish over the next 5 years related to needed transmission

infrastructure to realize the 2030 de-carbonization goals which l maintaining overall grid reliability. In

summary, the CAISO should explain in the Vision Paper what, if anything, it will be doing in the near-

term (e.g. 1-5 years) to address these critical matters.

We look forward to working with the CAISO on these critical issues.

Respectfully submitted,

6

Jan Smutny-Jones, Chief Executive Officer Independent Energy Producers Association [Former Chair, CAISO Board, 1997-2001]

November 20, 2017 The Honorable Richard Maullin, Chair Mr. Steve Berberich, President and CEO California Independent System Operator 250 Outcropping Way Folsom, California 95630 RE: Linde’s Comments on the CAISO Board’s Vision Paper, Electricity 2030 Dear Chair Maullin and Mr. Berberich: Thank you for the opportunity to provide comments on the California Independent System Operator’s (CAISO) Vision Paper, Electricity 2030. Linde’s comments focus on Trend 7, specifically the absence of fuel cell electric vehicles (FCEV) in the discussion of integrating transportation with electric service. Linde North America (Linde) is a member of the Linde Group, a world leading gases and engineering company operating in the U.S. since 1907. Linde manufactures and supplies industrial, specialty and medical gases and related equipment. The company also builds and operates hydrogen fueling facilities in California. Linde has three retail fueling stations, located in West Sacramento, San Juan Capistrano, and San Ramon. The company has also built and is operating two hydrogen fueling stations for California’s AC Transit to fuel twelve hydrogen fuel cell buses in Emeryville and Oakland. Linde expects to open another 2 stations in California during the coming year.

Linde appreciates that the CAISO is exploring ways to speed up the process of electrifying the transportation sector and is looking at the future needs of the electrical grid as more zero emission vehicles enter the marketplace. However, the CAISO’s document is missing a key technology that could be used to absorb excess renewable energy and provide energy storage services to the electrical grid. By using the phrase “electric vehicles”, the CAISO is limiting electrification to vehicles powered by batteries and ignoring the benefits of FCEVs. This omission could result in policies being developed by the CAISO and other state agencies that omit the use of FCEVs or favor the development of electric charging infrastructure over the buildout of California’s hydrogen fueling infrastructure. In order to capture the full benefits of transportation electrification and to understand how FCEVs could positively impact and support the grid, the CAISO’s Vision Paper should be technology neutral and specifically include FCEVs and the development of hydrogen fueling infrastructure. Governor Brown’s vision to increase the adoption of zero-emission vehicles (ZEVs) to reach 1.5 million ZEVs by 2025 doesn’t just focus on plug-in ZEVS, it includes vehicles powered by batteries and fuel cells. Both types of ZEVs are essential for reaching California’s ambitious greenhouse gas (GHG) reduction goals. As you know, FCEVs create electricity from hydrogen. Unlike plug-in ZEVs, they offer fast fueling and long driving ranges that are similar to a gasoline vehicle. The production and dispensing of hydrogen fuel can play a role in grid management that is equal to, or greater than, charging a battery

Linde’s Comments on CAISO Vision Paper, Electricity 2030 Page 2 of 3

car. Additionally, because hydrogen is dispensed at a station that can fill 100 or more vehicles a day and each vehicle stores onboard energy, the opportunity to absorb more excess renewable energy or provide energy back to the grid is significantly greater than that of a fleet of battery electric vehicles. By 2030, the FCEV industry expects that up to 500,000 FCEVs will be in California fueling at hundreds of stations. In order for the State of California to have the best chance of achieving its zero-emission vehicles goal and subsequent greenhouse gas reduction goals will require more flexible definitions and options for multiple technologies to compete to realize the goal. In the pre-mature market years, it is all the more important to enable new renewable technologies until the market is developed. This includes enabling renewable pathways, as opposed to restricting them. Measures such as considering waste gas from processes as renewable or allowing flexible credit trading between alternative fuel markets (Landfill to CNG to Hydrogen) would assist in the endeavor to increase the renewable options available today. Furthermore, the California Hydrogen Highway Blueprint plan contemplates renewable resources such as biomass. This multi stakeholder effort was a key element in developing SB 1505. “Other factors that affect the GHG rating are the energy inputs required for the production from natural

gas or biomass through reforming or gasification. The carbon in renewable feedstocks such as biomass

or biogas was recently captured from the atmosphere. This carbon will eventually enter the atmosphere

either when the biomass is burned (i.e. agricultural burning) or if the feedstock is converted to hydrogen.

Therefore, the GHG impact of the CO2 is zero. The electric power required for reforming or gasification,

as well as the diesel fuel required for hydrogen delivery, also affect the total GHG emissions and rating

of the various pathways.”1

In order to plan for and fully realize the benefits of ZEVs, the CAISO’s Vision Paper needs to be modified to do the following:

• Replace “electric vehicle” with either “zero-emission vehicle,” which is consistent with State of California use, or specify “battery and fuel cell electric vehicles.” While electric vehicle is encompassing, it leaves less to interpretation to plainly state that you are talking about including both types of vehicles.

• When discussing a vehicle’s energy storage, use the term “storage” instead of “batteries.”

• When discussing system storage needs, clearly articulate the opportunity for hydrogen and other storage mechanisms to find their opportunities alongside battery storage, further supporting diurnal and seasonal fluctuations.

• When reviewing policies, rates structures and plans, should be open and inclusive of hydrogen and FCEV related services for the system, to enable and support all market opportunities.

• Smart-charging and time-of-use incentives should be created or modified to apply to hydrogen stations, with either on-site production or by controlling compression equipment.

1 California Hydrogen Highway Benefit Report, Page xiii

Linde’s Comments on CAISO Vision Paper, Electricity 2030 Page 3 of 3

• Real-time pricing or time of use incentives should be used to encourage hydrogen production to occur during times of excess generation. Additionally, excess renewable power could be used to power bio-methane based steam reforming and liquefaction.

• Encouraging and incentivizing the deployment of hydrogen stations is as important as encouraging the buildout of electric vehicle charging infrastructure, particularly in dense urban areas that lack private parking, in rural areas where people drive long distances, and for medium- and heavy-duty vehicles. It’s important for California to continue to provide grants or incentives for the development of hydrogen fueling infrastructure. It would also be beneficial for the state to look at ways to develop a program for hydrogen fueling infrastructure that is similar to what the California Public Utilities Commission and the investor-owned utilities are doing for the development of electric vehicle charging infrastructure. The program would need to preserve the ability for competition among market participants but could also look at building out fueling infrastructure in rural or underserved areas of the state that are not likely to be built without incentives.

In closing, Linde believes it makes sense for the CAISO to consider the positive impact and benefits of both FCEVs and battery electric vehicles. The combination of both technologies will have a bigger impact on electricity use and the CAISO’s goals of decarbonizing, decentralizing and regionalizing California’s electrical system and energy transition than just one type of technology. It behooves the CAISO to consider all of the tools that are available to it. Sincerely, Nitin Natesan Business Development Manager Linde LLC

MCE | 1125 Tamalpais Avenue, San Rafael, CA 94901 | 1 (888) 632-3674 | mceCleanEnergy.org

November 20, 2017

California Independent System Operator P.O. Box 639014 Folsom, CA 95630

Subject: MCE Comments on Draft ISO Board Vision Discussion Paper

Marin Clean Energy (MCE) appreciates the opportunity to provide the CAISO with comments on its Draft “Vision” Discussion Paper issued by the Board in October.

MCE is the first operational Community Choice Aggregator (CCA) in California, currently serving over 250,000 customer accounts within the counties of Marin and Napa, the cities of Richmond, San Pablo, El Cerrito, Benicia, Walnut Creek, and Lafayette. In 2018, MCE will start serving additional customer accounts in unincorporated Contra Costa County, and the communities of Concord, Danville Martinez, Moraga, Oakley, Pinole, Pittsburg, and San Ramon. Customers in MCE’s service area have several electricity offering options, including MCE’s default 50% renewable Light Green product, MCE’s 100% renewable Deep Green product, MCE’s 100% local solar Local Sol product, and PG&E’s electricity offerings. In addition to electricity generation services, MCE also administers California Public Utilities Commission (CPUC) approved Energy Efficiency (EE) funding, as well as innovative pilot programs.

MCE focuses its comments on Trend 5: “Electricity is increasingly decentralized.” The CAISO envisions a world with customers having the options to choose their electricity offerings from new entrants competing to provide these newly-minted “prosumers” with innovative products and services. MCE concurs that electricity markets seem to be trending in this direction. MCE also concurs with the task specified for Trend 5: “Develop a framework for coordinating decentralized electric service with the bulk power system.” That framework will be essential and must be designed to maximize local government's ability to administer innovative local energy programs, including community choice aggregation.

California can ensure that state energy and climate goals are achieved by establishing clear, reasonable, and workable standards and requirements for the load-serving entities (LSEs). Policies and regulations should be streamlined to accommodate load migration and fairly assign reliability responsibilities. Concerns related to reliability and climate goals should be addressed through existing regulatory avenues, such as the Integrated Resource Planning effort, to ensure that LSEs plan and procure to meet their own loads. Moreover, CAISO’s rules and markets must ensure competitive neutrality among market participants. For instance, policies that direct procurement by one LSE on behalf of the customers of another LSE are incompatible with a

MCE | 1125 Tamalpais Avenue, San Rafael, CA 94901 | 1 (888) 632-3674 | mceCleanEnergy.org

market built on customer choice. Such policies include directing the IOUs to procure renewable resources to take advantage of the expiring tax credits for all customers. This would result in potential triple procurement for customers: IOU procurement on behalf of customers before they depart for other LSEs, CCA procurement for their customers, and further procurement before the tax credits expire. This would lead to unreasonable increase in costs for all customers, and should be discontinued to encourage competition and innovation.

In enabling a wide range of energy service provider business models, MCE urges the CAISO to focus on the reality that customers will be managing their own energy choices. The CAISO should explore what that fundamental shift will mean for the CAISO’s markets, market design, and rules. The CAISO should be evaluating every proposed market design and rule change through this prism and ensuring that its proposals encourage customers’ energy choices.

In addition, the CAISO and regulatory agencies should seek to understand and account for the differences among LSEs. For example, smaller LSEs, such as CCAs, face different barriers than the large utilities when considering deployment of innovative technologies for grid reliability. Besides the economies of scale, regulations and rules that have been designed for vertically integrated utilities also provide barriers in adopting new distributed energy resources for smaller LSEs. Engaging CCAs and other LSEs early can better diagnose problems that need to be addressed, and truly enable customers’ choices.

MCE encourages the CAISO to explore how customers managing their own energy futures might intensify decentralization and to ensure that its rules and markets foster innovation. MCE looks forward to working with the CAISO and other interested parties in addressing the expected challenges.

Sincerely,

C.C. Song Senior Policy Analyst csong@mceCleanEnergy.org (415) 464-6018

1

California ISO Board Vision Discussion Paper, Electricity 2030

Subject: Board Vision Paper, Electricity 2030

Trends and Tasks for the Coming Years

To: initiativecomments@caiso.com

The National Hydropower Association (NHA) appreciates the opportunity to comment on the

California Independent System Operator (CAISO) Board Vision Paper, Electricity 2030 Trends

and Tasks for the Coming Years (Vision Paper). Hydropower and pumped storage are an

indispensable part of the future grid, and should be recognized as California policy makers

evaluate actions that could strengthen its transition to a reliable, low-carbon grid. While the

Vision Paper occasionally mentions hydropower - generally in the context of regional grid

operation – NHA believes that hydropower has a clear role to play in accomplishing the

outcomes that the Board describes, and therefore hydropower should be a featured discussion

point under Trend 2, Trend 3 and Trend 6.

NHA represents more than 240 companies, from Fortune 500 corporations to family-owned

small businesses. The hydropower industry is diverse, with NHA’s members including public

and investor-owned utilities, independent power producers, developers, equipment

manufacturers and other service providers. NHA is a national association, including members in

California and the Pacific Northwest that stand to be significantly affected by California’s

electricity policies. We hope these comments will be helpful as you look toward 2030 and

beyond.

Overview

Hydropower, while a proven resource with a long history of success providing renewable

electricity and grid reliability services, has mostly been taken for granted in public policy

debates. Additionally, hydropower is a multipurpose resource that provides a suite of public

benefits. Its infrastructure helps to manage and balance river flow for flood control, drought

management, water supply, irrigation and ecosystem purposes. It also protects air quality by

avoiding greenhouse gas emissions from fossil fuels in the electric and transportation sectors. A

least-cost option for maintaining a low-carbon electric sector, hydropower is also poised to

support the electrification of the buildings and transportation sectors. Contrary to popular belief,

hydropower has significant growth potential, with the Department of Energy’s (DOE) 2016

Submitted by Company Date Submitted

Jeff Leahey

202.750.8403

jeff@hydro.org

National Hydropower Association November 20, 2017

2

Hydropower Vision report1 estimating that close to 50 gigawatts of new capacity is available by

2050, with the right conditions and policy support in place.2

Hydropower also is capable of providing all of the services generally recognized as crucial for

maintaining electric grid reliability, including energy, peak capacity, voltage support, regulation,

spinning and non-spinning reserves, storage, black start capability, and inertia. Hydro generators

and pumped storage resources can normally be operational very quickly to support grid

restoration. Continued investment and re-investment in the hydropower system is critical to our

energy future.

Trend 2: Gas-fired generation declines significantly as the grid is modernized.

Trend 2 should be expanded to incorporate a discussion of: 1) modernizing the hydropower fleet

and; 2) an evaluation of whether the wholesale market appropriately prices reliability services

sufficiently to retain existing hydropower and incentive investments.

Under Trend 2, the Vision Paper describes a modernized natural gas fleet with retrofitted or

replaced resources that can start and ramp quickly. It also suggests a managed phase-out of gas

generation and envisions incentives to replace fossil units with non-fossil technologies. The

Vision Paper should encourage consideration of retrofitting and modernization at existing

hydropower projects. As a non-fossil technology, hydropower can provide the load following

and fast-start resources needed to complement variable renewable resources. Likewise,

California policy makers should contemplate incentives for hydropower upgrades or unit

replacements to avoid early retirements of these non-fossil generators that can provide needed

grid services and continued support for water supply requirements. Incentives for upgrades at

hydropower projects could also encourage investments at existing projects that might otherwise

have been foregone.

Another comment under Trend 2 is that the wholesale energy market “ensures financial viability

of gas-fired generators that remain necessary.” The Vision Paper should recognize that

hydropower, like gas-fired generation, can provide valuable services to the wholesale energy

market and should be appropriately compensated. DOE recognized in its 2016 Hydropower

Vision report that “not all benefits provided by hydropower facilities are readily quantifiable or

easily attributable to hydropower in a market framework” and “[I]t’s possible that no value or

inadequate value may be placed on some services, such as those provided by hydropower

generators with characteristics that allow for rapid and precise response to instability in the

grid."3 In addition, DOE has pointed out that there is a very real risk of underinvestment in, or

1Hydropower Vision, A New Chapter for America’s 1

st Renewable Electricity Source. U.S. Department of Energy,

2016. Overview. https://energy.gov/eere/water/articles/hydropower-vision-new-chapter-america-s-1st-renewable-

electricity-source 2 Potential growth in the hydropower industry comes from a variety of sources. They include: efficiency

improvements and capacity additions at existing hydropower facilities; adding generation to non-powered dams

(only 3 percent of U.S. dams generate power); pumped storage; conduit/irrigation power projects; as well as some

new greenfield hydropower development. 3 Hydropower Vision Report. Section 2.3.1.

3

retirement of, generating resources like hydropower due to depressed prices and costly

regulatory barriers.4

NHA encourages CAISO to examine how the wholesale market will ensure the viability of

existing non-fossil technologies to ensure that hydropower units do not retire prematurely.

Also addressed under Trend 2 is regional sharing of flexible resources, which reduces the need

for gas-fired generation. Here, the Vision Document acknowledges the benefits of sharing

flexible resources across much of the West. In order to incentivize coordinated use of regional

hydropower resource and storage capabilities, however, wholesale markets must send

appropriate price signals. Such signals would better incentivize the availability of flexible

hydropower resources. For example, out-of-state hydropower should be eligible under

California’s evolving policies to reduce carbon emissions.

Trend 3: The system is shaped by the variable output of wind and solar resources.

Trend 3 addresses how California’s system is shaped by the variable output of wind and solar

resources. It goes on to describe how access to a large pool of resources both within and outside

of California (including hydroelectric) helps supply the electric characteristics necessary for

reliable electric service. As previously stated, hydropower is well-suited to cleanly provide

flexibility and essential reliability services as California introduces ever-greater amounts of wind

and solar onto the electric grid. However, proper price signals—specifically, pricing tailored to

accurately value flexibility and essential reliability services—will be needed to incentivize

regional resources like hydropower to help support California’s goals. In the draft California

Energy Commission’s (CEC) 2017 IEPR report, several recommendations are made to support

California’s long-term greenhouse and renewable energy goals. The hydropower industry is well

positioned to support California’s evolving electric sector.5 As the report points out, hydropower

is ready to support regional diversity, increasing resiliency in the electricity sector, and zero

greenhouse gas emission solutions.6

NHA is encouraged by the “Beyond the RPS” bullet under Trend 3. Putting all clean resources

on a comparable footing from a public policy perspective is the correct approach. Policies that

are not technology-dependent should allow California to meet its decarbonization goals more

cost-effectively. NHA does not support future RPS standards or federal7 or state tax policies that

put hydropower at a competitive disadvantage with other generating resources.

4 U.S. Department of Energy, Staff Report to the Secretary on Electricity Markets and Reliability, at 60 (August

2017). Available at:

https://energy.gov/sites/prod/files/2017/08/f36/Staff%20Report%20on%20Electricity%20Markets%20and%20Relia

bility_0.pdf 5 California Energy Commission (CEC) Draft Integrated Energy Policy Report (IEPR), page 6.

http://docketpublic.energy.ca.gov/PublicDocuments/17-IEPR-

01/TN221520_20171016T153945_Draft_2017_Integrated_Energy_Policy_Report.pdf 6 For additional discussion on experiences and challenges of variable supply, see IEA’s 2011 report, Harnessing

Variable Renewables, available at:

http://www.iea.org/publications/freepublications/publication/Harnessing_Variable_Renewables2011.pdf 7 For example, hydropower has only ever received half-credit under the production tax credit (PTC); the PTC itself

often results in the over-generation of wind seeking to capture the full value of the PTC. Further, the PTC and

4

Guiding Question No. 2 asks: To what extent can Primary Frequency response substitute for

mechanical inertia in ensuring reliable system operation?

NHA notes that hydropower can supply BOTH of these core aspects of reliability. Hydropower

projects are best suited to provide this service by adjusting the volume of water passing through

turbines using autonomous governor control and the stored potential energy stored as inertia in

the large rotors typical of hydroelectric machines. California is currently experimenting with the

use of static inverters for primary frequency control. This source of control, while not as

effective as mechanical stored primary frequency control backed by energy stored as inertia, can

supplement the grid during the 20% of the day when solar energy is available8. By combining

solar and wind energy sources with pumped storage technology and battery technology, primary

frequency control can be achieved both at the gird level and in distributed application as the

distribution grid is updated to efficiently manage distributed resources. The inertia stored in

hydropower units are important for grid resiliency to help avoid widespread blackouts. Inertia

provided by the large rotating mass of traditional generators has historically stabilized the

Western Interconnection’s frequency by slowing frequency decline, supporting voltage and, with

the help of power system stabilizers, dampening the cascading oscillations that can occur when

there is a disturbance (such as the sudden loss of large generation). Hydropower resources have

a lot of mass that provides significant inertia. Maintaining hydropower resources, and the inertia

they provide, decreases the need to substitute primary frequency response for mechanical

inertia.9

Guiding Question No.3 asks: To what extent can non-carbon resources supply Essential

Reliability Services, including spinning and non-spinning reserves?

Hydropower is a non-carbon resource that can supply all essential reliability services. In

addition to frequency response and inertia (described above), hydropower provides:

Flexible Capacity. As the grid becomes increasingly reliant on variable output, non-

dispatchable energy resources, there is an increasing need for flexible capacity that can

respond, given the production and timing uncertainty of resources such as wind and solar.

Many hydropower projects are flexible enough to change an individual generation unit’s

output during the day to provide dispatchable generation and use it to assure that loads and

resources remain in balance. As natural gas fired plants are retired and are phased out to

support California’s increasing goals for greenhouse reductions, existing hydropower and

new off-stream pumped storage facilities are ready today to supply this critical resource. As

stated the CEC’s 2017 IEPR: “Although natural gas remains an important resource used for

investment tax credit for hydropower and marine technologies has lapsed, while the credits for wind and solar have

been extended for years longer. 8 North America Reliability Council (NERC) Announcement – Solar Loss Disturbance Report Uncovers Reliability

Gap in Frequency Measurement Errors, June 8, 2017.

http://www.nerc.com/news/Headlines%20DL/Inverter%20060817.pdf 9 For additional discussion on the challenges of maintaining reliability while integrating variable energy resources,

see NERC and CAISO 2013 Report, Maintaining Bulk Power System Reliability While Integrating Variable Energy

Resources –CAISO Approach, available at: http://www.nerc.com/pa/rapa/ra/reliability%20assessments%20dl/nerc-

caiso_vg_assessment_final.pdf

5

heating, electricity production, and increasingly in transportation, the use of natural gas will

need to decline dramatically for California to meet its long-term climate goals.”10

As an example, the California grid depends on flexible resources like hydropower to come

online in the heat of the afternoon to meet increasing air conditioning and consumer demand

when the sun sets and solar generation rapidly declines. Resources like hydropower must

quickly ramp up to meet demand in the evening after net load (load minus variable energy

resources) has bottomed out during the middle of the day. Most pumped storage units can be

changed from generation to pump mode and vice versa in minutes to seconds and this

provides system dispatchers with another tool to use in response to system events.

Furthermore, unlike baseload coal and nuclear generation facilities, hydropower can be

available to rapidly respond to changes in net load without burning fuel to be kept in a ready

state. Additionally, pumped storage can move baseload generation during periods of lower

need to these periods of higher reliability need.

Annual Energy. Even though streamflows can vary based on hydrologic conditions,

hydropower is a reliable and dispatchable resource that continuously produces energy

throughout the year, and has traditionally been considered part of the baseload. Electric

power systems use energy from hydropower to both avoid construction of new peaking-only

generation plants and reducing the reliance on existing fossil fuel resources to manage

variable loads. Furthermore, hydropower resources can easily be incorporated into a dispatch

schedule for an optimized hydro-thermal generation portfolio, which in turn make other

generation resources run more efficiently.

Peak Capacity. Hydropower systems are generally designed to take advantage of a broad

range of streamflows and hence have available capacity that can be called upon (i.e.

dispatched) at virtually no additional cost to meet peak system demands often associated with

severe low or high temperatures. Meeting these extreme events is one of the most significant

costs for any electric power system, and hydropower resources have helped grid managers

successfully navigate them for decades.

Voltage Support and Reactive Power. Reactive power is necessary to keep voltage at levels

to maintain reliability under a wide range of conditions. Hydro generators are very well

suited by design and inherent capability to maintain system voltage, providing substantial

increase or decrease in voltage as necessary. When operated in synchronous condenser mode

a hydro unit can make a significant contribution to voltage regulation in the transmission grid

in proximity to the hydro plant.

Spinning and Non-Spinning Reserve. On a sub-hourly basis, generating units are maintained

in a “spinning reserve” status ready to rapidly respond to unanticipated changes in load or

unscheduled loss of a large generator in a region. Spinning reserves can respond to load

changes and subsequent decline in frequency in a matter of seconds up to 10 minutes. These

resources restore system frequency and area control error during emergency operating

conditions, unforeseen load swings, and major transmission outage events. Many

10

California Energy Commission (CEC) Draft Integrated Energy Policy Report (IEPR), page 11.

6

hydropower projects generally have multiple turbines that are operated at less than full

capacity so that the undispatched capacity is available for fast response when needed and are

a natural fit for supplying reserves including over extended periods of time. Non-spinning

resources are units that can respond in less than 10 minutes, maintaining output for at least

two hours. Offline hydropower can provide even faster than 10-minute response from an

offline state – a potential value for consumers though not yet valued in the competitive

market. As noted previously, these operating conditions can require increased maintenance

and upgrade investment and highlight the need for appropriate market compensation.

Storage. Many large conventional hydropower projects can provide storage capability

through the use of reservoirs, providing opportunities to better balance loads and generating

resources. It’s important to note, however, that pumped storage is particularly well positioned

to reduce curtailment of excess generation by providing large-scale dispatchable load and

energy storage. Pumped storage includes both a load (to pump water uphill) and generation.

These units can rapidly increase generation or load as needed for grid stability and economic

efficiency – a shock absorber for the grid. Storage gives hydropower projects the fuel (water)

to provide all the various reliability services. Regarding security, the “fuel” is as secure as the

electric grid itself, such that hydropower plants can be integral components needed to achieve

resilience and specifically to move the off-peak baseload generation to more useful service in

the on-peak hours. In addition, there are three types of advanced pumped storage

technologies that are in commercial service in the world today, including converter fed

single-speed synchronous units, ternary units with separate pump and turbines, and the

doubly fed induction adjustable speed units. These advanced technologies can provide all

ancillary services in both the pumping and generating modes.

Black Start Capability. This is a clear example of how hydropower can contribute to grid

resiliency. During outages, hydropower and pumped storage units help restart the power

system without support from the transmission grid, enabling other generators to come online.

Hydro generators and pumped storage resources can normally be operational very quickly to

support grid restoration. They typically have adequate fuel supply (in the reservoir), and can

provide a sustained response. Thermal plants typically have stand-by diesel generators with a

limited on-site fuel supply that provide necessary power to qualify as “black start” units.

Since hydro plants, with reservoir storage, can operate for periods long enough to stabilize

the grid, then they are most desirable as “black start” facilities.

In the CAISO 2017 Market Monitoring Report11

several recommendations were made that would

support the transition from a fuel-based energy markets to a capacity based market as described

in Trend 3. NHA agrees with the CAISO’s observation that as some generation is retired and

new sources of carbon free capacity are required, like investments in hydropower resources, a

longer-term capacity payment or contracting mechanism will be needed.12

11

California Independent System Operator 2016 Annual Report on Market Issues and Performance, May, 9 2017,

http://www.caiso.com/Documents/May9_2017_DMM_2016_AnnualReport_MarketIssues_Performance_ZZ17-

4.pdf 12

California Independent System Operator 2016 Annual Report on Market Issues and Performance, May, 9 2017,

page 16.

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Trend 6: Regional collaboration supports efficient grid operations.

NHA agrees that regional coordination supports efficient grid operations. The Northwest and

California have a long history of synergistic grid operations and regional bulk power exchanges.

Going forward, the basis for these synergies may change as more solar and wind power enters

the grid. Yet regional markets will continue to improve liquidity and capture benefits associated

with peak load diversity. To best capture these shared opportunities, NHA encourages

California policy makers to develop technology-neutral carbon policies and greater participation

of external resources in the California energy market that do not discriminate against out-of-state

hydropower and new pumped storage resources.

Conclusion

NHA and the hydropower industry stand ready to help meet California’s clean energy goals.

Greater recognition of our nation’s hydropower infrastructure is needed to prompt continued

investment in the system. To achieve decarbonization in the west in a cost-effective, reliable

manner, hydropower must be a central part of the solution. We look forward to the state and its

regional stakeholders finding pathways to fully maximize and unlock hydropower’s potential.

Finally, NHA strongly encourages CAISO to clearly define the carbon-free flexibility needs of

the future grid with 50% renewables and beyond. NHA recommends a comprehensive study that

addresses the current flexible capacity in the system and the replacement strategy for the

sustained, orderly retirement of the natural gas fleet. This study should also identify market

barriers that can be relaxed to provide ramping capability cost-effectively and reliably.

NHA appreciates the Board’s consideration of these issues and would happily answer any

questions from the Board.

Sincerely,

/s/ Jeff Leahey

Jeff Leahey

Deputy Executive Director

National Hydropower Association

601 New Jersey Avenue, Suite 660

Washington, DC 20001

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California ISO Board Vision Discussion Paper, Electricity 2030

Subject: Board Vision Paper, Electricity 2030 Trends and Tasks for the Coming Years

To: initiativecomments@caiso.com The Northern California Power Agency (NCPA) appreciates the opportunity to comment on the Board Vision Paper, Electricity 2030: Trends and Tasks for the Coming Years (Vision Paper). NCPA is a California Joint Powers Agency comprised primarily of locally owned electric utilities, established nearly 50 years ago to make joint investments in energy resources that would ensure an affordable, reliable, and sustainable supply of electricity for customers in its member communities. NCPA’s 16 members include municipalities in Northern and Central California, a rural electric cooperative, and other publicly owned entities for which the not-for-profit agency provides such services as the purchase, aggregation, scheduling, and management of electrical energy.1 The agency owns, operates and maintains a fleet of power plants that is among the cleanest in the nation, providing reliable and affordable electricity to approximately 700,000 Californians. NCPA’s mix of geothermal, hydroelectric, solar, and natural gas resources is well positioned to help its members achieve California’s Renewable Portfolio Standard (RPS) and greenhouse gas (GHG) reduction goals. NCPA members also access power that flows through three different balancing authorities (CAISO, BANC, and NV Energy). NCPA is pleased that the CAISO has prepared a draft energy vision that recognizes the complexities associated with developing an energy framework for 2030 driven with the overarching objective of reducing statewide greenhouse gas (GHG) emissions by 40% below 1990 levels. While many of the policy pieces are in place to move California in this direction, the challenges underlying implementation of these policies are significant, requiring unprecedented coordination between multiple energy agencies, state and local government, as well as a wide range of stakeholders.

                                                            1 NCPA is a nonprofit California joint powers agency established in 1968 to construct and operate renewable and low-emitting generating facilities and assist in meeting the wholesale energy needs of its 16 members: the Cities of Alameda, Biggs, Gridley, Healdsburg, Lodi, Lompoc, Palo Alto, Redding, Roseville, Santa Clara, Shasta Lake, and Ukiah, Plumas-Sierra Rural Electric Cooperative, Port of Oakland, San Francisco Bay Area Rapid Transit (BART), and Truckee Donner Public Utility District—collectively serving nearly 700,000 electric consumers in Central and Northern California.

 

Submitted by Company Date Submitted

Scott Tomashefsky 916.781.4291 scott.tomashefsky@ncpa.com

Northern California Power Agency

November 20, 2017

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In these comments, we offer our initial thoughts on several of the trends outlined in the CAISO Vision Paper, and look forward to a productive dialogue as stakeholder feedback is incorporated into CAISO’s upcoming strategic planning process. With unprecedented state agency coordination required to drive down the path to 2030, it is critical that this initial round of stakeholder input be factored into important energy policy work being undertaken at the California Energy Commission (CEC), the California Public Utilities Commission (CPUC), the California Air Resources Board (CARB), as well as the Governor’s Office and the State Legislature. We agree with the Vision Paper’s assertion that CAISO “cannot, nor should not, lead this discussion alone.”

Trend 1: Electricity is used far more efficiently. NCPA does not offer any comment on Trend 1 at this time.

Trend 2: Gas-fired generation declines significantly as the grid is modernized. NCPA agrees that gas-fired generation will decline as grid modernization evolves and the state pursues a higher share of renewables. As California moves forward to 2030, it is imperative that the state develop policies recognizing that natural gas power plants provide critical support for a grid that is becoming increasingly reliant on higher levels of intermittent resources. NCPA supports the vision of a modernized fleet of natural gas generating facilities that provides operational flexibility for the grid, essentially reducing “oversupply conditions and curtailment risk.” As California develops a strategy to reduce reliance on fossil-fuel generation resources, the Vision Paper correctly calls for implementing policies that “require all resources to operate flexibly, and conventional generators to have fast start, fast ramping…capabilities.” Removing barriers that preclude the most efficient facilities from being dispatched and operated means that when natural gas fired generation is necessary – and it will be at certain times – the plants that are operating will be those that provide the least adverse impacts on air quality and emit the fewest GHGs. For these reasons, NCPA highlights the importance of the following recommendation recently included in the California Energy Commission’s draft Integrated Energy Policy Report (IEPR):

Establish mechanisms to retain power plants that increase the resiliency of the electricity system. The CEC, the California Public Utilities Commission (CPUC), and the CAISO should work together to develop a thoughtful and comprehensive plan to retain generation that is needed for reliability. 2

It is important that this effort be undertaken in conjunction with the CPUC and CAISO, as well as in consultation with the State’s other balancing authorities, because of the myriad different factors that affect the dispatch of natural gas fired electric generation facilities. For example, differences in the rates for gas transportation to the electric generation facilities can impact which facilities are called upon to run when needed, which could mean that cleaner plants are                                                             2 CEC, 2017 Draft Integrated Energy Policy Report, p. 121.

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shuttered while higher-emitting facilities are called upon to firm renewable resources, and/or gas fired power plants are priced out of the market altogether because of rapidly rising gas transportation costs which are themselves, a rapidly growing component of the variable cost of gas fired generation. To the extent gas generators exit the market, the fixed costs of the gas transmission and distribution system that are currently covered by gas fired generators will be shifted to the remaining core and non-core gas customers, and this cost shift is an issue that has not received sufficient regulatory or legislative attention.. This is not to say that there should be recommendations of “environmental” over “economic” dispatch, but the interaction of gas transport costs as a component of market electricity prices, and ultimately total consumer energy costs, highlights the complications inherent in addressing this issue. Additionally, to the extent that exploration of mechanisms to retain the cleanest and most efficient plants needed to facilitate deliverability of renewables and increase the overall resiliency of the electricity system determines that the State should streamline the total number of plants being operated, the heat rate of the plants being run more often may decrease, reflecting greater efficiency and lower GHG emissions, providing even greater overall statewide benefits.3 Because of considerations such as these, it is incumbent upon that the agencies fully deliberation this issue immediately. The CEC’s draft IEPR also notes, despite California’s aggressive climate and energy goals, there continues to be a vital role for natural gas fired electric generation in California’s electricity market, and particularly low-GHG emitting power plants. As the State transitions towards a cleaner electric grid, there will still be a vital role for clean, low-GHG emitting electric generation facilities. As the Draft IEPR notes, even “[r]ecognizing that California must move away from its reliance on fossil fuels, including natural gas in the electricity sector to meet its climate goals . . ., natural gas power plants still play an important role in maintaining grid reliability.” 4 That is because in order to achieve our climate goals while still maintaining the reliable provision of reasonably priced electricity for California’s and businesses will require the State to look not only at the end goal, but the technological manner in which to achieve those goals. This further underscores the importance of having strategically located natural gas plants operating in California. Those natural gas plants are needed for grid reliability and resiliency, and will be a part of ensuring that the energy from renewable resources not located close to the electricity customers can still be delivered to end-users. Retaining the cleanest and most efficient electric generation facilities does not mean that the State is compromising on its objective of reaching near-zero GHG generation, but rather, reflects the technological and practical certainties of operating the State’s integrated electric grid.

Trend 3: The system is shaped by the variable output of wind and solar resources. NCPA does not offer any comment on Trend 3 at this time.

Trend 4: Demand becomes as important as supply in balancing the system.                                                             3 2017 Draft IEPR, p. 103. 4 2017 Draft IEPR, p. 102.

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NCPA does not offer any comment on Trend 4 at this time.

Trend 5: Electric service is increasingly decentralized. NCPA does not offer any comment on Trend 5 at this time.

Trend 6: Regional collaboration supports efficient grid operations. NCPA agrees that regional coordination supports efficient grid operations. In this regard, we support CAISO Task 6, which calls for the state “to explore ways to share resources across the West for the benefit of all states.” The early success of the Energy Imbalance Market have been well documented by CAISO, providing benefits to customers located in the service territories of the eight entities now participating into the program. As the Los Angeles Department of Water and Power and the Balancing Authority of Northern California join EIM in 2019, and Salt River Project in 2020, the benefits of EIM will grow even further in the West. To that end, NCPA agrees with the vision of strengthening and expanding EIM. NCPA, however, has concerns with the broader concept of regionalization and cautions against moving forward without careful consideration. Any proposal to make CAISO a multi-state entity must safeguard the ability for California consumers to reliably access environmentally-friendly and affordable electric power. Rushing through a “regionalization” effort is ill advised, as California policymakers need to make sure that California consumers and system reliability are fully protected from potential unintended consequences:

Increased electricity rates A lack of clarity in how aging transmission infrastructure projects will be included or

excluded from regional projects that may qualify for regional cost allocation Stranded investments in California power generation Ceded authority to other states and the Federal Energy Regulatory Commission Compromised grid reliability Increased GHG emissions, and No compensation for the substantial investment California consumers have made in

CAISO infrastructure. Indeed, a broader regionalization effort cannot move forward until outstanding CAISO governance issues are resolved. During each of the past three years, regionalization proponents have attempted an end-of-session strategy to change CAISO governance, which was met each time by significant resistance, including other states in the west that could be potentially impacted by the broader regionalization effort. Last year’s legislative session ended with a proposal to remove the Governor and Senate from the role of controlling who sits on the CAISO board. The potential environmental and consumer risks associated with grid regionalization are significant, and any change to CAISO governance must provide adequate safeguards for California consumers.

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Such a debate must be done through the normal state legislative process, especially since once California loses its authority over CAISO, there will be no turning back.   

Trend 7: Transportation and building energy use is integrated with electric service.

NCPA concurs with many of the points raised with respect to transportation and building energy use in the Vision Paper. From a technological perspective, electrification offers new opportunities to manage the grid as grid management becomes more complicated. The notion of intelligent electric vehicle charging is promising, but EV deployment at the scale of what is needed to support the state’s GHG reduction efforts will impact electric utility operations across the state. Simply stated, electrification of the transportation and building sectors will place added burdens on the power sector to balance the needs of growing demand with aggressive reductions of GHG emissions. While we support the outlined task under this trend, calling for the development of policies and programs to integrate transportation and building energy use with electric service, the agencies will need to fully assess the impacts such policies can have on the safe, reliable, and affordable operation of the power grid, and particularly how distribution electric service is impacted. Public outreach will be important to make customers aware of the various programs and incentives that are available as electrification activities are deployed. Consistent with the successes of the “Flex-Your-Power Program, any public outreach campaign that California developed should be undertaken at the state level. In terms of potential funding sources for such programs, the state could turn to the Low Carbon Fuel Standard Program, the Greenhouse Gas Reduction Fund from the cap-and-trade program, or even consider expanding the range of programs that are eligible to rely on electric utility public goods programs.

Trend 8: Develop ways to contribute to, and benefit from, the transition away from fossil fuels.

The transition away from fossil fuels will require contributions from all aspects of the state’s economy. The Vision Paper identifies a wide range of benefits, including the creation of well-paying jobs, improved air quality and public health, the development of community solar and energy efficiency retrofit programs, as well as opportunities for disadvantaged communities to participate in programs previously not available before. NCPA applauds these objectives, including the desire to support public and private sector investment to make these programs successful. As CAISO moves toward its strategic planning efforts, NCPA cautions state policymakers to refrain from imposing prescriptive mandates that will not provide local governing boards with the ability they need to fund and develop programs that best serve the needs of the communities they serve.

NRG Energy, Inc. Comments on CAISO “Electricity 2030 Trends and Tasks for the Coming Years” November 21, 2017

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Introduction NRG Energy, Inc. (“NRG”) provides the following comments on the CAISO’s “Electricity 2030 Trends and Tasks for the Coming Years” discussion paper (“Discussion Paper”). NRG urges the CAISO to leverage this vision to develop next-generation electricity markets that co-optimize environmental dispatch with reliability in a manner that delivers maximum decarbonization at the least cost to California consumers. The Discussion Paper is largely consistent with NRG’s recommended Four Product Future, which suggests that the cost-effective and practical way to decarbonize the grid is to rely on renewables and demand response to meet the majority of electricity demand, while using battery storage and fast-start natural gas as backup resources. To accomplish this low carbon future in an affordable manner, the CAISO needs to focus on redesigning its markets to incent the products it is going to need in 2030. NRG suggests that the CAISO’s focus on eliminating fossil fuels from constrained areas is incorrect. NRG suggests that relying on rarely-dispatched existing natural-gas fired resources – particularly in local areas – is environmentally preferable to spending large amounts of money to eliminate those resources, as suggested in the Discussion Paper. In most cases, it is simply less expensive and more environmentally beneficial to continue relying on existing local resources and devoting scarce ratepayer carbon abatement dollars to more impactful investments. Finally, NRG suggest that this proceeding should focus on sending tangible price signals to distributed resources, which can significantly speed up adoption of distributed resources and transfer financial risk from ratepayers to private entities deploying shareholder dollars. Comments on Stakeholder Involvement in Crafting the 2030 Vision: The Discussion Paper is the first step to fully defining the CAISO’s vision for California’s energy grid in 2030. The CAISO should rely on stakeholder input as it continues to flesh out this vision. However, it is not immediately clear how the CAISO intends to incorporate stakeholder comments into its strategic planning process. NRG recommends that the CAISO make clear that it will incorporate comments from stakeholders into it strategic planning processes. Stakeholders would benefit from knowing how their comments will inform the CAISO’s strategic and initiative planning process. Further, many of the tasks laid out in the Discussion Paper involve things outside the CAISO’s traditional role in implementing state energy policy (e.g., “Develop a Net Zero Energy Building implementation plan to meet requirements of California law” under Topic 1.) Clearly, the CAISO has a role in informing such discussions, which will be facilitated by other state agencies. It does not seem, however, that the CAISO has any role in shaping or executing that process. More recently, the CAISO has taken on a larger, unexpected role with regards to establishing

NRG Energy, Inc. Comments on CAISO “Electricity 2030 Trends and Tasks for the Coming Years” November 21, 2017

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state procurement policy – a role which the CAISO asserted of its own initiative and which was not sought by other agencies. As it develops its vision, the CAISO should distinguish between those things for which its role is designing, those things for which its role is informing and those things for which its role is implementing. The CAISO’s central role is to ensure the reliability of the transmission system under its operational control. The CAISO does this primarily through the operation of markets under its direct control and by sharing its operational and reliability expertise in other appropriate regulatory fora. In these roles, the CAISO has considered itself to be a policy taker, not a policy maker. To the extent the CAISO envisions taking on a larger role with regards to setting policy, the CAISO should ensure such a role does not conflict with or detract from its essential role in ensuring reliability and reducing costs to consumers through its design and operation of markets. NRG’s Proposed Four-Product Future: NRG envisions the electric grid of the future as comprising four major elements, depicted in the graphic below. While California’s grid is unique, it also includes many features that are compatible with this four product future. First, the foundation of the clean energy grid is renewables, such as wind and solar, to provide the vast majority of the energy needs of the system with no emissions. Second, storage, both at grid scale and in distributed applications, will store renewable energy when renewable production exceeds that needed to serve demand and to serve demand when renewable energy production is not sufficient. Third, load management at the end-user level, in the form of dispatchable behind-the-meter generation as well as load-shifting and other load-shaping strategies will greatly enhance the ability to match demand to variable supply. Finally, a complement of flexible and fast-responding peaking plants will provide the additional balancing capability for short-term ramping and dependable contingency supply to address reliability needs.

NRG Energy, Inc. Comments on CAISO “Electricity 2030 Trends and Tasks for the Coming Years” November 21, 2017

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Responses to Specific Questions NRG’s responses are below. Where no response is provided, NRG has no response to that question. Trend 1: Electricity is used far more efficiently.

1. How can state and local programs best be focused to make energy efficiency upgrades and savings benefits available to low-income Californians, including those living in disadvantaged communities?

Low-income individuals do not typically have the credit profile necessary to finance the capital costs associated with energy efficiency or clean energy investments. While this is complex issue, the CAISO could facilitate the investment of private capital in these communities by initiating programs that provides a stable source of revenue tied to such investments. For example, a feed-in tariff program open to low-income individuals could provide sufficient “reservation payments” over a period of years may encourage third-party financing of such investments. The payments would be tied to residence (or ownership) of the underlying property to maximize the stability of the program.

2. How can policies unlock efficiency savings in multifamily housing? How can efficiency programs overcome the "split incentive" problem? Eighty-eight percent of multifamily households are renters; most pay utility bills but do not have control over building or equipment improvements that could lower them. Building owners

NRG Energy, Inc. Comments on CAISO “Electricity 2030 Trends and Tasks for the Coming Years” November 21, 2017

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typically pay for common area utilities (garage, lobby, landscape) but may not be able to influence tenant behavior that could help control costs.

Multifamily housing presents many of the same issues as low income customers. Again, the solution is to create an attractive market structure that encourages green investment by providing for a long-term financeable income stream tied to the underlying property.

3. How should the California ISO collaborate on the Integrated Resource Plan (IRP) to help prioritize the most effective procurement of efficiency, demand response and other clean programs over fossil energy supply options?

The CAISO should not “prioritize” one technology over another. Instead, the CAISO should design markets that align investment incentives with the State of California’s environmental goals.1 NRG recommends that the CAISO will utilize the 2030 Vision Process to define market products that will co-optimize dispatch of renewables and conventional resources to minimize carbon emissions. A technology neutral market-based approach ensures that California consumers receive the maximum carbon reduction for the lowest possible price. Additionally, the Integrated Resource Planning (“IRP”) makes a number of flawed assumptions about the continued economic viability of existing gas-fired resources. The initial Reference System Plan (“RSP”) correctly notes that once-through-cooled (“OTC”) generation resources will retire in compliance with OTC rules. However, it then goes on to assume that 100% of the remaining gas-fired generation – 32.5 gigawatts in all – remain operating in 2030. This is true under both the proposed Reference System Plan (“RSP”)’s “recommended” and “aggressive” carbon reduction scenarios (of 42 million metric tons or 30 million metric tons, respectively). The assumption that 32.5 GW of gas-fired generation remains in service in 2030 is highly unrealistic, given the rapidly deteriorating wholesale energy and ancillary services markets conditions. Indeed, the CAISO is already noting a significant up-tick in its reliance on un-contracted natural gas resources, including those resources recently issued Reliability Must-Run agreements for local reliability reasons. Notably, California achieves its GHG reduction goals in both the recommended and aggressive carbon reduction cases, even with the 32.5 GW of existing gas-fired generation in service. The RSP demonstrates, therefore, there is no need for the CAISO to prioritize the procurement of non-gas-fired resources. The CAISO would be better served collaborating with the CPUC and others to determine how to preserve the operation of existing needed gas-fired generation. Further, the sluggish adoption of demand response in California provides an excellent case study in how California is falling behind in securing preferred resources. The CAISO’s 2016 Annual Report on Market Issues & Performance notes that:

1 The CAISO may wish to specifically avoid “prioritizing” one technology over another, as that raises the specter

that such priorities would violate the Federal Power Act’s prohibition against undue discrimination or preference.

NRG Energy, Inc. Comments on CAISO “Electricity 2030 Trends and Tasks for the Coming Years” November 21, 2017

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Demand response programs operated by the major utilities met about 4 percent of the ISO’s overall system resource adequacy capacity requirements. However, the amount of overall system resource adequacy requirements met by demand response dropped about 30 percent during the last three years. This was driven largely by a decline in enrollment in price-responsive programs, as program requirements resulted in customer fatigue during that time. During the summer, there was a significant increase in proxy demand response capacity bid economically in the real-time market, but only a fraction of this capacity was dispatched.

This compares unfavorably with the demand response programs in the Eastern RTOs such as PJM, where PJM meets between 6 - 10% of its resource mix from demand response and energy efficiency programs (not including utility-run programs), depending on the year.2 The main difference is that the Eastern markets purchase demand response and energy efficiency through a centralized market structure, with clear, forward price signals. These price signals provide the certainty needed for companies, like NRG Curtailment Solutions, to enter the market and provide demand response aggregation services. Trend 2: Gas-fired generation declines significantly as the grid modernized

1. What are the major obstacles to meet local reliability capacity needs with non-fossil resources? How can those obstacles be removed?

NRG respectfully submits that the CAISO needs to better distinguish between capacity from natural gas-fired resources and the dispatch of such resources. NRG agrees that dispatch of natural gas resources should naturally decrease as renewables become a larger part of the system. However, NRG is concerned that the CAISO’s focus on eliminating fossil fuel generation from local reliability areas may not be well-aligned with the State’s goals of decreasing total carbon emissions. One major obstacle to eliminating fossil fuels from local reliability is clearly cost. NRG urges the CAISO to be guided by economics and utilize market mechanisms designed to reveal the lowest cost of carbon abatement – which or may not involve elimination of conventional generation in local reliability areas. Another obstacle is to demonstrate that non-fossil resources can be procured, deployed, and dispatched at scale to support local capacity needs on their own. For example, in the case of the Moorpark subarea, the CAISO stepped outside its long-standing role of defining the reliability need and instead opined on whether there was sufficient time to procure preferred

2 See, e.g., 2017/2018 RPM Base Residual Auction Results at p. 15 (available at: https://www.pjm.com/-

/media/markets-ops/rpm/rpm-auction-info/2017-2018-base-residual-auction-report.ashx?la=en). DR participation has fluctuated over the years, but the consistent theme has been that DR investment accelerated after the advent of the PJM capacity market.

NRG Energy, Inc. Comments on CAISO “Electricity 2030 Trends and Tasks for the Coming Years” November 21, 2017

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resources instead. The CAISO, however, does not (i) conduct such solicitations itself; (ii) has no market mechanism designed to attract the necessary investment in non-traditional resource; and (iii) does not authorize LSEs to conduct such solicitations. Thus, these types of recommendations put the CAISO in the potentially uncomfortable position of recommending against retaining existing conventional generation (or procuring new conventional generation) without the ability to deliver on its reliability promises. Given all of this, and in light of the RSP’s finding that California can meet the most aggressive GHG reduction goals even with 32.5 GW of gas-fired generation remaining in operation, the CAISO should build on this vision paper to articulate exactly what future role it intends to take with regards to future procurement of resources needed to meet local capacity requirements and to justify whether targeting new and existing conventional resources for elimination, based on their location in a load pocket, is a good use of decarbonization dollars.

2. What kinds of market mechanisms can ensure the financial viability of gas-fired generators as they run fewer and fewer hours? How do infrastructure financing models need to adapt to a paradigm of reduced reliance on fossil resource?

California does not currently have a reliable means of contracting with existing natural gas resources beyond one year. And as recent retirements of relatively new and efficient gas fired generation has demonstrated, the current one-year market does not provide an appropriate investment horizon for retaining existing resources. This is particularly true when existing resources incur major maintenance expenses, which are large capital expenditures that are typically recovered over many years. To ensure the long-term reliability of the system, the CAISO must ensure that gas-fired generators are revenue-adequate. The best way of doing this would be to allow existing resources the right same ability to enter into longer-term (e.g., multi-year) contracts – the same structure that underlies the state’s procurement of preferred resources. Enabling generators to amortize capital improvements over longer periods of time will both reduce the cost to consumers of ensuring reliability and provide the CAISO with a more accurate accounting of the resource mix, more than 12 months into the future.

3. What changes in ISO and CPUC policies and practices can best align transmission planning and procurement to promote deployment of the most reliable and cost-effective grid solutions?

The CAISO should identify future transmission and distribution investments and then see if those investments can be avoided by contracting with battery or other distributed solutions.

4. What are the constraints on use of biofuels in electricity generation? What are the limits of a sustainable biofuel supply? What infrastructure upgrades would be required to access and biofuels for electricity generation?

NRG Energy, Inc. Comments on CAISO “Electricity 2030 Trends and Tasks for the Coming Years” November 21, 2017

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Trend 3: The system is shaped by the variable output of wind and solar resources

1. What constraints limit meeting Local Capacity Resource needs with non-carbon resources?

In addition to the obstacles noted in Trend 2, Question 1 above:

Energy duration. Apart from pumped storage hydro, the gas delivery system remains the most effective form of bulk energy storage today.

Guaranteed availability. Variable intermittent resources cannot ensure that the wind or sun will shine when needed.

Dispatchability. While energy storage systems hold great promise for addressing predictable and limited duration operational challenges (e.g., the duck curve) energy storage systems will be less effective at addressing unpredictable, longer duration operation needs (i.e. extended heat-waves or long periods of cloudy & wind-free weather patterns). Significant tradeoffs remain. For example, while inverter-based energy storage systems may be able to respond much more quickly to changes in frequency, which means the CAISO could assure the same system performance by holding much less frequency response on faster inverter-based machines than on conventional generation, holding batteries charged to provide frequency response degrades battery performance and holding headroom on wind or solar resources means giving up carbon-free energy. Finally, managing state of charge for energy storage resources that the CAISO is depending on to provide reliability services (like local capacity reserves) will bring significant state-of-charge management challenges – challenges that will unquestionably affect the economics of such energy storage devices, which will be trying to leverage multiple revenue streams.

2. To what extent can Primary Frequency Response substitute for mechanical inertia in

ensuring reliable system operation?

Because of its speed of deployment, inverter-based frequency response is a technologically superior product to that provided by mechanical means. The challenges of transitioning to inverter-based frequency response are both economic (holding headroom on variable resources) and technical (battery degradation or state of charge management, in the case of taking primary frequency response from energy storage).

NRG Energy, Inc. Comments on CAISO “Electricity 2030 Trends and Tasks for the Coming Years” November 21, 2017

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3. To what extent can non-carbon resources supply Essential Reliability Services, including spinning and non-spinning reserves?

See the answer above.

4. What market products and associated pricing structures are necessary to support the transformation from fuel-based energy markets to capability-based products?

The CPUC and CAISO RA programs needs to be transitioned from a focus on single months or even single years to look multiple years forward to assess operational and reliability needs. Generators that have longer periods of financial certainly across multi-year horizons are able to plan staffing, fuel-contracting and transport designations and general maintenance to improve turbine capabilities in advance of need. Additionally, allowing a longer time horizon allows generators to offer more competitively into the RA market, decreasing costs to California consumers while at the same time, increasing long-term reliability. Trend 4: Demand becomes as important as supply in balancing the system 1. What practices and regulations must be removed, replaced or adapted to enable a broader

range of customer demand to provide grid services?

A. The role of the investor-owned utilities: In the Discussion Paper, CAISO has already started to refer to the distribution utilities in terms of their function as Distribution System Operators (“DSOs”). However, these utilities are not independent entities, and have no obligation to provide non-discriminatory access to their grids as part of their obligations to ensure grid reliability. Absent regulatory initiatives to establish “Independent Distribution System Operators”, CAISO should advocate for a specific regulatory obligation for non-discriminatory access. Such an obligation, combined with specific obligations to ensure a secure, reliable distribution grid similar to those placed on CAISO, should make it easier to ensure overall grid reliability and security.

B. Aggregation only within a single sub-LAP: This is a barrier to participation by 3rd party DR providers and to customer acquisition in general. CAISO has justified the need for this restriction as being necessary in order to avoid creating additional congestion. In addition, Resource Adequacy is determined on a Local Capacity Area level, not on a sub-LAP level. CAISO should re-examine that justification, and weigh any potential additional congestion costs against the costs of DR foregone due to that sub-LAP restriction.

C. Notification: Requirements for 30-minute notification, without a menu of longer-term requirements, reduce the pool of eligible customers who can participate in a demand response program. CAISO and CPUC have begun the process of integrating slower-response resources as local capacity; such work needs to continue.

NRG Energy, Inc. Comments on CAISO “Electricity 2030 Trends and Tasks for the Coming Years” November 21, 2017

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D. Baseline: The recommendations of the Nexant report California ISO Baseline Accuracy Work Group Proposal approved in the Baseline Analysis Working Group and ultimately by the CAISO Board of Governors, significantly expands the variety of DR resources whose baseline loads can be accurately estimated by approved baseline calculation approaches. Currently, the only CAISO-accepted baseline was the 10-in-10 baseline with a 20% same-day adjustment; this approach is generally appropriate only for a subset of medium-to-large commercial and industrial customers. While CAISO should be commended for considering these additional baselines and submitting these changes in its FERC filing, it should also recognize the need for customized, customer-specific baselines to be tested and evaluated.

E. Extremely frequent dispatch: Some utilities have significantly increased their dispatch of DR resources, with little to no warning. Customers participating as DR resources have expressed dissatisfaction, as expressed in the customer attrition indicated in the IOUs’ monthly DR reports. There must be greater coordination of expectations between CAISO and the IOUs dispatching DR, and the 3rd part DR providers and their customers.

F. DRAM implementation: There continues to be a lack of information regarding the utilities’ criteria for bid selection and for determining when this selection process within the auction is completed. There is also insufficient information available to potential bidders regarding the utilities’ actual supply requirements by product type (e.g., system or flexible). Such uncertainty is a disincentive to DRAM participation, and makes the transition of the utilities’ DR products into the CAISO wholesale market more difficult.

G. Prohibited Resources: CPUC Decision 16-09-056 and the IOUs’ Advice Letters still leave some implementation issues unresolved or unclear. Two examples are: (1) detail regarding the resources prohibited, especially if the fuel itself is renewable; and (2) lack of uniformity among IOUs regarding Attestation Letters acceptable to the IOUs and the CPUC.

H. Insufficient coordination of CAISO business process changes with CPUC. The CAISO, like other ISO/RTOs, proposes Business Practice Manual changes and discusses them with stakeholders. However, the recent example of a change to a Protocol Revision Request updating the availability assessment hours for Resource Adequacy Availability Incentive Mechanism calculations, which was inconsistent with the CPUC’s RA counting rules, created unnecessary uncertainty. While NRG commends the CAISO for not seeking to move forward with its conflicting proposed BPM changes, CAISO must account for CPUC policy when contemplating all such changes.

I. Short-term view of Resource Adequacy: Although Resource Adequacy is the CPUC’s responsibility, its timeframe is essentially an annual procurement to meet near-term projected reliability needs. The CPUC’s shorter-term procurement timeline has been incorporated into the report prepared by the Lawrence Berkeley National Laboratories 2025 California Demand Response Potential Study (“the LBNL Report”), which finds that

NRG Energy, Inc. Comments on CAISO “Electricity 2030 Trends and Tasks for the Coming Years” November 21, 2017

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DR curtailment services (“Shed”, in LBNL’s services taxonomy) are undervalued. The conclusion that DR’s curtailment value to CAISO only reflects the short-term capacity position (“long” or “short”) of the CAISO system is a barrier to longer-term DR customer acquisition. CAISO’s longer-term planning horizons should be appropriately included in developing market-based mechanisms for procuring the combinations of DR services necessary to meet CAISO’s needs to ensure compliance with its reliability and security mandates.

J. Separate identification of system and flexible RA. These are separate services and their market values should be determined as such. To the extent that the lack of price transparency inherent in the current RA construct makes such pricing difficult, CAISO should cooperate with the CPUC to make the necessary changes to the RA construct.

2. How can data security and customer data privacy be protected as electric service evolves to

rely more and more on two-way information flows? 3. What are the most effective ways of building public understanding of and support for

making portions of customer energy use controllable by system operators? Ideally, sophisticated customers should be encouraged to adjust their own energy use through properly designed tariffs and rates without the need for operator intervention. For other customers, ensuring proper compensation for, and minimizing the commercial/lifestyle impact on, the customer will be key to them agreeing to allow their energy use to be controlled by a third party. 4. What are the most effective ways for Demand Resource aggregators, DSOs and Energy

Service Provider to earn public trust? What safeguards are needed to ensure new service providers are responsive, responsible and accountable?

Ensuring that the public trusts DR and other providers of distributed energy resources is critical to the acceptance of these technologies in California. While the specific rules should be developed as part of a formal proceeding, NRG recommends that the CPUC consider requiring sellers of DERs targeting the mass-market customers (i.e., residential customers) to:

o Demonstrate that they have adequate financial resources; o Provide measurable demonstration of expertise in distributed energy finance,

supply hedging, and customer service; o Require dedicated, full‐time regulatory compliance as well as sales quality

assurance resources; and o Establish registration and complaint tracking of vendors.

Larger entities (C&I) typically do not need these types of protections. 5. How will adoption of consumer storage devices change customer engagement?

NRG Energy, Inc. Comments on CAISO “Electricity 2030 Trends and Tasks for the Coming Years” November 21, 2017

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Energy storage devices are most likely to be used by individual customers to manage their own electricity costs. Currently, peak shaving and avoiding demand charge ratchets represent a significant part of the value stream necessary to justify installation of behind-the-meter batteries. The proliferation of energy storage devices to manage customer costs may result in higher customer engagement in and of itself, or it may encourage the establishment of third party aggregators who will operate these devices on the customers’ behalf to earn revenues for the customer while also minimizing customer impacts. Trend 5: Electric service is increasingly decentralized

1. What policies can best encourage and support monopoly distribution utilities to adopt energy service provider business models?

The key to getting monopoly utility companies to embrace distributed energy outcomes is to ensure that earnings are tied to those outcomes. To accomplish this alignment, the CPUC must financially incent utilities to maximize competitive investment and minimize ratepayer expense. Specific proposals include:

Interconnection Processing Times: Utility earnings should be tied to a requirement that the utility markedly improve interconnection processing times for small- to medium-sized DERs. As a minimum benchmark, each utility should improve process times by 20%, with an extra bump to earnings if the utility reduces interconnection processing times by greater than 50%, or, alternatively, for completing 90% of distribution level interconnection requests within one week.

Information Access: A new category of rate incentives and rate demerits would promote a utility’s information transparency. In order to avoid a decrease in earnings, the utility would have to: (1) make real-time meter information available to third-parties with less than a 24 hour lag, and (2) allow customers and their agents improved access to historic meter data.

Competitive DER Market: Utility earnings should be tied to enhanced adoption of competitive DERs. Top performing utilities (i.e., those that attract the largest number of DERs on a load-ratio share) should receive full earnings, while bottom performing utilities should receive a demerit.

Transparent Reservation Price for DER Capacity: Rates of return should be tied to each utility’s adopting clear locational price signals on the distribution system to signal the value of additional DER on constrained portions of its system.

While the universe of potential rate reforms is large, all these ideas have in common the goal of aligning utility incentives with the stated goal of removing barriers to bring end-user and third-party DER resources onto the system.

NRG Energy, Inc. Comments on CAISO “Electricity 2030 Trends and Tasks for the Coming Years” November 21, 2017

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2. What policies are necessary to ensure that state energy and climate goals can be

achieved as electric services is decentralized? See above.

3. What safeguards are necessary to ensure decentralized service meets highest standards for safety, reliability, and customer support and supplier accountability?

The CPUC should establish these safeguards as specified above.

4. What standards can ensure that decentralization of electric service advances grid modernization?

See above.

5. How should the evolving decentralization be incorporated into the transmission planning process?

First, the CAISO should use rigorous, defensible and granular forecasts of the deployment of distributed energy resources. Second, as discussed above, the CAISO should identify future transmission and distribution investments, and then establish a “price to beat” to see if DERs or other preferred resources can allow the utility to defer (or cancel) the T&D investment. Trend 6: Regional Coordination Supports Efficient Grid Operations

1. How should states evaluate the potential benefits of regional markets and regional

electric system operation against pressures to maintain current practices? NRG recommends that states look at the potential benefits through both the lens of carbon emissions and through an assessment of expected cost savings. Additionally, states may wish to provide rate incentives for utilities to voluntarily join the regional market.

2. How can states best coordinate infrastructure planning to inform investment decisions and ensure access to low cost regional resources?

Engaging in regional transmission planning is one potential benefit. The other obvious answer – by coordinating the development of clean energy standards and procurement between states, which may or may not be politically feasible, but would certainly maximize carbon reductions.

3. How can RSO operation respect differing state environmental policies? The CAISO should consider how to modify its market structures to “achieve” each state’s preferred outcomes.

NRG Energy, Inc. Comments on CAISO “Electricity 2030 Trends and Tasks for the Coming Years” November 21, 2017

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NRG has no response to the questions posed in Trend 7: Transportation and building energy use is integrated with electric service. Trend 8: Develop ways to enable everyone to contribute to, and benefit from, the transition away from fossil fuels:

1. Which investment opportunities promise the largest return in moving to clean energy?

2. How can investor confidence in clean energy projects be strengthened?

3. What regulations and standards are necessary to ensure that clean energy programs benefit all customers, in every part of the state?

As Governor Olsen noted during his remarks at the Stakeholder Symposium, nothing will disrupt the transition to clean energy faster than a blackout. The CAISO can best promote the transition towards clean energy by focusing on its core mission to ensure reliability by operating transparent, well-designed markets that provide accurate price signals and help ensure revenue adequacy for the generation that will be needed to maintain reliability.

Ratepayer Advocates in the Gas, Electric, Telecommunications and Water Industries

ORAOffice of Ratepayer Advocates

California Public Utilities Commission505 Van Ness Avenue

San Francisco, California 94102

http://ora.ca.gov

THE OFFICE OF RATEPAYER ADVOCATES’ COMMENTSON THE CALIFORNIA INDEPENDENT SYSTEM OPERATOR’S (CAISO’S)

DISCUSSION PAPER ELECTRICITY 2030 TRENDS AND TASKS FOR THE COMINGYEARS ISSUED ON OCTOBER 2017, AND THE CAISO’S ELECTRICITY 2030 –

VISION FOR A LOW CARBON GRID DISCUSSION AT THE CAISO STAKEHOLDERSYMPOSIUM ON OCTOBER 19, 2017

November 20, 2017

The Office of Ratepayer Advocates (ORA) is the independent consumer advocate within

the California Public Utilities Commission (CPUC), with a mandate to obtain the lowest possible

rates for utility services, consistent with reliable and safe service levels, and the state’s

environmental goals.

ORA submits the following responses to the questions in the Discussion Paper

Electricity 2030 Trends and Tasks for the Coming Years, (Electricity 2030 Plan) prepared by the

CAISO Board of Governors and Management, issued October 2017, and comments on the

CAISO Board of Governors’ Electricity 2030 - Vision for a low carbon grid discussion (2030

Plan Discussion) held on October 19, 2017 at the CAISO Stakeholder Symposium.

Trend 1: Electricity is used far more efficiently

1. How can state and local programs best be focused to make energy efficiency upgradesand savings benefits available to low-income Californians, including those living indisadvantaged communities?

Energy efficiency is an important component of California’s clean energy plan and

improving its programs, particularly for low income customers, should be part of this effort. The

CAISO should continue to refine its planning process to better incorporate energy savings into its

forecasts. Specifically, the CAISO should continue to refine its integration of utility load and

energy forecasts into its planning and market models as levels of energy efficiency increase and

new technologies emerge. The CAISO should provide data on a confidential basis on pricing

points for existing generation to help state regulators determine elasticity of supply and demand.

This information will help in the development of cost curves for energy efficiency.

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Also, the CAISO should look to existing energy efficiency efforts for focusing energy

efficiency savings and upgrades available to low-income Californians, including energy resource

programs that have “set-asides” for disadvantaged communities (DACs) and/or resources

directed to low-income customers. These include programs in the energy efficiency portfolios of

the large investor-owned utilities (IOUs). Economic development must also be provided in

DACs. ORA supports these programs, while also recommending further oversight for the cost

effectiveness of various measures. ORA discusses the various statutes that provide for economic

development and programs that target both DACs and low-income households in its response to

Trend 8, Question 3. ORA also recommends a continuing emphasis on building efficiency and

appliance efficiency programs for all customers due to their capacity to reduce energy usage.

According to Innovation Electricity Efficiency, aggressive building codes (regarding building

insulation, air conditioning and lighting) and appliance standards (i.e., water heaters) could

achieve a 17 percent reduction in electric usage by 2035.1

2. How can policies unlock efficiency savings in multifamily housing? How can efficiencyprograms overcome the “split incentive” problem? Eighty-eight percent of multifamilyhouseholds are renters; most pay utility bills but do not have control over building orequipment improvements that could lower them. Building owners typically pay forcommon area utilities (garage, lobby, landscape) but may not be able to influencetenant behavior that could help control costs.

Since building owners typically have control over equipment improvements in

multifamily buildings, it is important to engage the owners/landlords. Some efforts to unlock

multifamily housing savings by engaging the landlord/owner of the buildings currently are

underway. For example, the utilities have employed a Single Point of Contact (SPOC) Model to

simplify the landlord interaction process, with the aim to streamline the engagement process.

Common area measures for multifamily buildings were approved by the CPUC in its most recent

decision on the California Alternative Rates for Energy (CARE)/Energy Savings Assistance

(ESA) Program. 2 The issue of incentive payments to owners and managers of multifamily

1 Factors Affecting Electricity Consumption in the U.S. (2010-2035), March 2013, Innovation ElectricityEfficiency and Institute of the Edison Foundation. p. 9-23. Assumes that newly constructed buildings use60 percent less energy, compliance with Title 24 Building regulations. Assumes that a new federalstandard will raise the minimum SEER rating for air conditioning. Assumes adoption of Energy STARrecommendations for commercial and residential appliances. Assumes compliance with InternationalEnergy Conservation Code.2 Decision 16-11-022 issued November 22, 2016.

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buildings to encourage participation in ESA was left unresolved. ORA discusses these efforts in

its response to Trend 8, Question 3. ORA’s response to Trend 8, Question 3 addresses how the

CAISO can enable these efforts. ORA recommends work continue on this issue, including

ensuring that tenants share in the benefits of energy efficiency upgrades.

3. How should the California ISO collaborate on the Integrated Resource Plan (IRP) tohelp prioritize the most effective procurement of efficiency, demand response and otherclean programs over fossil energy supply options?

ORA requests that the CAISO forecast grid needs with higher penetrations of renewables

out to 2030 and identify any reliability issues on a system and local basis. The CAISO should

provide information to the CPUC in the Integrated Resource Planning (IRP) proceeding on its

forecasts of different types of reliability issues based on higher renewable penetration. In

addition, the CAISO should provide information on how non-fossil resources can address those

reliability issues in order to allow the CPUC to properly evaluate distributed energy resources

(DERs) and avoid the over procurement of fossil options.

ORA also recommends that the CAISO provide local area constraint information in the

IRP proceeding based on higher penetrations of renewables, such as voltage stability, thermal

overloading of transmission lines, etc. Currently, there is little information available on how

DERs can meet reliability needs based on transmission issues and not just megawatt (MW)

capacity needs. The CAISO’s analysis is essential to determine whether and how DERs can

meet grid reliability needs. The CAISO will need to provide technological and locational data to

the IRP proceeding to determine the appropriate and effective resource procurement.

The CAISO could provide information similar to what was included in its Moorpark Sub-

Area Local Capacity Alternative Study.3 In that study, the CAISO identified the needs of the

Moorpark Sub-Area and determined how different sets of resources could meet reliability needs

without the Puente Power Project. The CAISO should conduct similar analysis to inform the

IRP proceeding so that the CPUC can plan for procurement of DERs in a way that is consistent

with meeting reliability needs and avoid procurement of fossil generation.

3 Moorpark Sub-Area Local Capacity Alternative Study. August 16, 2017, CAISO, pp. 11-42, available at:http://docketpublic.energy.ca.gov/PublicDocuments/15-AFC-01/TN220813_20170816T165328_Moorpark_SubArea_Local_Capacity_Study.pdf.

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Trend 2: Gas-fired generation declines significantly as the grid is modernized

1. What are the major obstacles to meet local reliability capacity needs with non-fossilresources? How can those obstacles be removed?

A. The CAISO Should Clearly Identify How Non-Fossil Resources Can Meet LocalReliability Needs and Replace Fossil Resources

Fossil resources meet the transmission-constrained demands of their local area by

providing on-demand, variable levels of generation at any time of the day, subject to emission

constraints. The phase-out plan of fossil resources must take into account the capability of non-

fossil resources to meet the same local needs of fossil resources and be located within the same

local area. Recently, the CAISO prevented retirement of some fossil resources in order to meet

local sub-area capacity standards,4 contingency voltage issues,5 or both6 through Reliability

Must-Run (RMR) contracts. Non-fossil solutions capable of addressing operational needs in

constrained regions should be considered.

Currently, load-serving entities (LSEs) are required to procure resources within local

areas to meet specific local capacity reliability requirements. Historically, these requirements

have been met with fossil resources. As California works towards meeting its GHG emissions

reduction goals, non-fossil resources will take up a larger share of meeting the reliability need.

CPUC, California Energy Commission (CEC), and the CAISO must coordinate to ensure that

procurement of non-fossil resources will actually displace the fossil resources.

A plan should be devised and implemented by the CPUC, the CEC, and the CAISO to

phase-out fossil fuel resources while maximizing opportunities for non-fossil resources and

mechanisms such as demand response and energy efficiency to satisfy grid reliability needs,

4 Yuba City Energy Center; Calpine Peakers Retirement Assessment, March 6, 2017, CAISO, p. 4,available at:http://www.caiso.com/Documents/Presentation_PotentialReliabilityMustRunDesignation_YubaCityEnergyCenter_FeatherRiverEnergyCenter.pdf.5 Feather River Energy Center; Calpine Peakers Retirement Assessment, March 6, 2017, CAISO p. 5,available at:http://www.caiso.com/Documents/Presentation_PotentialReliabilityMustRunDesignation_YubaCityEnergyCenter_FeatherRiverEnergyCenter.pdf.6 Metcalf Energy Center; Metcalf Energy Center Retirement Assessment, September 26, 2017, CAISO, p.3, available at:http://www.caiso.com/Documents/Agenda_Presentation_MetcalfEnergyCenterRetirementAssessment-Sep262017.pdf.

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including the RMR process. Information is needed on those resources’ capabilities to be

comparable to those of a natural gas plant and allow planners to devise a procurement plan that

accounts for fossil fuel retirement. The phase-out process should compare the costs of a variety

of non-fossil solutions, such as distributed energy resources (DERs) or transmission upgrades,

and determine the best solution for ratepayers. Such considerations of retiring fossil plants

within a local area must be a part of a phase-out plan devised by the CPUC in conjunction with

the CEC and the CAISO.7

B. Resource Planning Must Consider Regional Characteristics of Non-Fossil Resources

Local areas, especially sub-areas identified by the CAISO, are located across diverse

rural and urban areas with different climates and landscapes. The performance of non-fossil

resources can depend on the characteristics of different regions, such as residential or industrial

customer bases, population density, and weather. For example, a region of residential customers

would not have the same energy efficiency, demand response, or behind-the-meter (BTM) solar

potential as a region of industrial customers. Future procurement planning must take into

account how various non-fossil resources perform in different regions to determine the most

effective resources to meet local needs.

Defining and modeling the particular characteristics of each DER will aid cost-effective

procurement of resources for different local areas. Suites of resources which provide the best fit

to replace retired fossil generation in unique local areas will help to ensure efficient and cost

effective procurement.

2. What kinds of market mechanisms can ensure the financial viability of gas-firedgenerators as they run fewer and fewer hours? How do infrastructure financing modelsneed to adapt to a paradigm of reduced reliance on fossil resource?

The CPUC’s Resource Adequacy (RA) program was adopted in 2004 in order to ensure

electric service reliability in California. Load Serving Entities (LSEs) have to meet RA

obligations established by the CPUC. These RA obligations include system, local and flexible

capacity requirements. The CPUC and the CAISO should continue to work together to refine

7 During the 2017-2018 CAISO Transmission Planning Process, PG&E presented a reliability assessmentsolution for the East Bay that included DERs to replace local generation at risk of retirement and toeliminate the reliance on Special Protection Systems. The solution included a combination of substationupgrades and distributed energy resources, energy storage and operational solutions to provide the least-cost best-fit solution program.

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and reevaluate capacity requirements, in order to ensure that gas-fired generators that are

essential reliability are retained while ratepayer costs are minimized.

In addition to capacity market solutions, the CPUC and the CAISO should coordinate on

energy market solutions for needed gas-fired generators. The CAISO is currently developing a

mechanism, the Commitment Cost Default Energy Bid Enhancement (CCDEBE) initiative,

which will raise the commitment cost bid cap by 200 percent in order to allow generators to

recover costs not currently captured. This type of initiative seeks to keep gas-fired generation

competitive with renewable resources and is likely to result in additional revenues for gas-fired

generators. The CAISO should coordinate with the CPUC to identify market costs associated

with this initiative and any other proposals that focus on retaining gas-fired generation to meet

reliability needs.

3. What changes in ISO and CPUC policies and practices can best align transmissionplanning and procurement to promote deployment of the most reliable and cost-effective grid solutions?

The CPUC, the California Air Resources Board (CARB), the CEC, and the CAISO

should collaborate to meet California’s goals on electric sector safety, GHG emissions

reductions, reliability and affordability. Senate Bill (SB) 3508 mandates the CPUC to establish

an IRP framework to ensure that LSEs meet GHG reduction targets through optimal resource

portfolios that ensure reliability and minimize impacts on ratepayers’ bills. The CPUC’s IRP,

the CARB’s Scoping Plan, the CAISO’s Transmission Planning Process (TPP), and the CEC’s

Integrated Energy Policy Report (IEPR) processes should continue to be coordinated and

aligned, with any necessary updates implemented jointly. These processes should utilize

consistent planning assumptions, scenarios and inputs, and allow for meaningful stakeholder

participation. Furthermore, the CPUC’s IRP Preferred System Plan and Preferred System

Portfolio should be used as inputs into the CAISO’s TPP and the CEC’s IEPR processes.

8 Senate Bill 350: Clean Energy and Pollution Reduction Act (de León, Chapter 547, Statutes of 2015)(SB 350).

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4. What are the constraints on use of biofuels in electricity generation? What are thelimits of a sustainable biofuel supply? What infrastructure upgrades would be requiredto access biofuels for electricity generation?

California’s RPS features two main procurement programs for bioenergy: the Bioenergy

Market Adjusting Tariff (BioMAT) for small scale projects,9 and the Bioenergy Renewable

Auction Mechanism (BioRAM) that was ordered pursuant to the Governor’s Emergency

Proclamation on tree mortality for the purposes of contracting with bioenergy facilities that

source their fuel stock from forest material found in high hazard zones.10 Currently, only the

large IOUs11 are required to participate in BioMAT and BioRAM. Eligible bioenergy

technologies under the BioMAT and BioRAM programs include: (1) biogas from landfills,

organic waste, food processing, and co-digestion; (2) biogas and biomass from dairy and

agricultural operations; and (3) biomass from byproducts of sustainable forest management.12

While the IOUs have met their mandated BioRAM procurement targets,13 for the BioMAT

program, only 10.4 megawatts (MW) of the required 250 MW procurement target have been

subscribed.14

9 California Public Utilities Code Section 399.20 establishes BioMAT program eligibility for RPS-eligiblebioenergy generation facilities of up to 5 MW nameplate capacity, while limiting BioMAT-eligiblepayment to delivery volumes of no more than 3 MW.10 The Governor’s Proclamation of a State of Emergency, issued October 30, 2015, Ordering Paragraphs8-9, states that the “CPUC shall utilize its authority to extend contracts on existing forest bioenergyfacilities receiving feedstock from high hazard zones” and that the “CPUC shall take expedited action toensure that contracts for new forest bioenergy facilities that receive feedstock from high hazard zones canbe executed within six months.” Available at:https://www.gov.ca.gov/docs/10.30.15_Tree_Mortality_State_of_Emergency.pdf.11 Pacific Gas and Electric Company (PG&E), Southern California Edison Company (SCE) and SanDiego Gas & Electric Company (SDG&E) (collectively, the IOUs).12 Eligible BioMAT technologies are listed in Decision 14-12-081, pp. 8-32. For BioRAM technologies,the Governor’s Proclamation of a State of Emergency, issued October 30, 2015, Ordering Paragraphs 8-9,states that the “CPUC shall utilize its authority to extend contracts on existing forest bioenergy facilitiesreceiving feedstock from high hazard zones” and that the “CPUC shall take expedited action to ensurethat contracts for new forest bioenergy facilities that receive feedstock from high hazard zones can beexecuted within six months.” Available at:https://www.gov.ca.gov/docs/10.30.15_Tree_Mortality_State_of_Emergency.pdf.13 Resolution E-4770, issued March 17, 2016, p. 5. IOUs ordered a procurement target of 50 MW.Resolution E-4805, issued October 13, 2016, p.2. Required an additional procurement target of 125 MW.14 Status of Bioenergy Market adjusting Tariff (BioMAT) Feed-in Tariff Program, October 11, 2017;Energy Division’s presentation to the Commissioner Committee on Emerging Trends (BioenergyPresentation), slide 3.

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Bioenergy procurement seems to be constrained by three challenges: (1) high project

costs; (2) project siting; and (3) the IOU’s RPS procurement that currently exceeds RPS targets.

With regard to BioMAT, these small bioenergy projects may experience high capital costs due to

unique equipment and interconnection requirements.15 Compared with other renewable

technologies, BioMAT contracts are expensive. For example, depending on the bioenergy

category, BioMAT program category price levels currently range between approximately

$127/megawatt hour (MWh) to $198/MWh.16 This is two to three times more expensive than

other solar photovoltaic (PV) RAM contracts executed in 2016-2017, which range in price from

approximately $40/MWh to $60/MWh.17 In addition, project siting presents a challenge because

some BioMAT technologies’ air permits can be difficult to obtain, or interconnection to the

electric grid is difficult due to the siting of the project in a remote location.18 These high costs

and project siting challenges have resulted in minimal bioenergy project contracting in the

BioMAT program. Finally, because the IOUs are exceeding their RPS requirements, the IOUs

do not need to procure additional renewables until 2030.19 Due to the reported over procurement

of RPS resources, the IOUs are not conducting general renewables solicitations where larger

15Bioenergy Presentation, slide 6.16Bioenergy Presentation slides 3 and 5.17 Bioenergy Presentation, slide 5. 2016-2017 Solar PV RAM contract examples include both large andsmall project sizes.18Bioenergy Presentation, slide 6.19 According to Pacific Gas and Electric Company’s (U 39 E) Draft 2017 Renewable EnergyProcurement Plan, filed July 21, 2017, p.1, PG&E asserts that it “is well-positioned to meet its RPScompliance requirements and does not have an incremental need for RPS resources until after 2030.PG&E projects that under the 50 percent RPS by 2030, it is well-positioned to meet its RPS compliancerequirements through the fifth (2025-2027) compliance period.” Similarly, according to SouthernCalifornia Edison Company’s (U 338-E) 2017 Renewables Portfolio Standard Procurement Plan, filedJuly 21, 2017, pp. 8-9, “SCE forecasts a net short position in the year 2030 with the use of bank under theCommission’s assumptions. But SCE forecasts a net long position in the year 2030 with the use of bankunder SCE’s assumptions. Under the 50% by 2030 target and using SCE’s assumptions, SCE forecasts anet short position starting in 2027 without the use of bank (as shown in Appendix C.2). But with the useof bank, SCE forecasts a net long position at the end of 2030 (as shown in Appendix C.4). Using theCommission’s assumptions, SCE forecasts a net short position starting in 2024 without the use of bank(as shown in Appendix C.1) and a net short position starting in 2030 with the use of bank (as shown inAppendix C.3). Accordingly, SCE currently does not have a need for additional RPS-eligible energy.”According to “San Diego Gas and Electric Company (U 902 E) Draft 2017 Renewables PortfolioStandard Procurement Plan,” filed July 21, 2017, pp. 1-2 and 18, “SDG&E achieved 43% renewableenergy in 2016”… “SDG&E is forecasted to reach 49% renewable energy in 2021”, … and “it is likelythat SDG&E will not seek to hold an RPS RFO for the next several years given its current forecastedposition.”

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scale bioenergy projects (that are ineligible for BioMAT) would be able to compete with other

technologies for power purchase agreements (PPAs).

Trend 3: The system is shaped by the variable output of wind and solar resources

1. What constraints limit meeting Local Capacity Resource needs with non-carbonresources?

ORA’s response to Trend 2 Question 1 regarding obstacles to meeting local reliability

capacity needs with non-fossil resources is also applicable to addressing this question.

A. The CPUC Will Coordinate Procurement Among LSEs To Address ReliabilityNeeds

Multiple LSEs may exist within and procure resources in some local areas to meet

demand, especially as more Community Choice Aggregators (CCAs) develop. As discussed

above, non-fossil resources provide benefits in different ways based on their operational

characteristics, and must be procured in a coordinated manner that addresses reliability needs and

avoids the need for fossil resources. The phase-out planning process for fossil resources would

be impacted by resources procured outside of a coordinated planning process. The CPUC IRP

and other proceedings will coordinate future LSEs’ procurement plans to complement one

another to ensure local reliability.

B. Continue Work to Minimize Local Curtailment

Congestion of renewable generation can occur when energy cannot be delivered because

local transmission facilities do not have sufficient capacity for energy delivery.20 During times

of congestion, local renewable generation that cannot be exported to the grid must be curtailed.

Such local curtailment is already a common problem on today’s grid.21 In locally constrained

areas, future procurement of solar and wind and the growth of BTM solar could exacerbate the

issue if procurement planning fails to account for local congestion. Curtailment of renewables

20 Wind and Solar Curtailment June 26, 2017, June 26, 2017, CAISO, p. 1 (CAISO description of localcongestion causing curtailment, under “Economic – Local”), available at:http://www.caiso.com/Documents/Wind_SolarReal-TimeDispatchCurtailmentReportJun26_2017.pdf.21 Briefing on renewable curtailments and the relationship between EIM transfers, February 3, 2017,CAISO, p. 1 (annual local to system curtailments), available at:http://www.caiso.com/Documents/Briefing-RenewableCurtailmentsandtheRelationshipBetweenEIMTranfers.pdf.

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can address reliability concerns, but should be minimized and employed as a grid integration

strategy only if it results in savings to ratepayers. The CAISO has identified alternatives to

curtailment, but the phase-out plan should also consider solutions from a local perspective since

solar and wind generation are anticipated to increase within locally constrained areas.

Infrastructure projects and DERs can help address high levels of generation limited by local

congestion.

2. To what extent can Primary Frequency Response substitute for mechanical inertia inensuring reliable system operation?

Primary Frequency Response22 could substitute for mechanical inertia23 if there is a significant

and sufficient quantity of wind or storage on the grid. At this time the level of storage in service

on the grid is not significant enough to be a substitute for mechanical inertia.24 In 2020, this

issue should be revisited based on current and pending CPUC decisions on energy storage.

There are three battery storage pilot projects underway that are testing the performance of

storage for reliability services; Yerba Buena (4 MW), Vaca-Dixon (2MW), and Brown Valley

(0.5 MW). An Electric Program Investment Charge (EPIC) report was prepared for the Yerba

Buena and Vaca-Dixon projects that reviewed the effect and cost of Day Ahead markets,

Frequency Regulation, and Spinning Reserves. The results demonstrated that Frequency

Regulation provided the best financial use of PG&E’s Vaca-Dixon and Yerba Buena Battery

Energy Storage Systems.25 Solar as a generation resource has not been considered as a

22 Primary Frequency Response is the first response when there is a system disturbance. Usually it ishandled through the governors on generators.23 Mechanical Inertial refers to generators that have the capacity to respond to outages because they keepturning (spinning) even when they are not producing energy and through this activity they maintain thesystem voltage within tolerance.24 Per D.13-10-040 the current energy storage target is 1,325 MW by 2020 (online by 2024). AB 2868increased the target by up to 500 MW of additional energy storage. In Rulemaking 15-03-011, theCommission issued D.17-04-039 that, in part, recognized AB 2868’s direction to order the procurementof up to 500 MW of additional storage (D.17-04-039, FOF 11, p. 63). The Commission concluded thatthe IOUs should host workshops and an application preview to allow discussion of AB 2868implementation (D.17-04-039, COL 7, p. 65). The IOUs will incorporate their proposals to collectiveprocure up to the 500 MW in their 2018 energy storage procurement plans, which file around March 1,2018 (D.17-04-039, p. 20).25 Electric Program Investment Charge Final Report (EPIC) EPIC Project 1.01 – Energy Storage EndUses Energy Storage for Market Operations, September 13, 2016, PG&E Electric Asset Management.p.38.

11

mechanical inertia resource. Solar could be considered a substitute for mechanical inertia during

certain times of day with a significant amount of solar power that can be aggregated and

controlled with improvements in Smart Inverters (i.e., smart inverters may control ramp time of

the DERs and help maintain voltage and frequency on the distribution system).

3. To what extent can non-carbon resources supply Essential Reliability Services,including spinning and non-spinning reserves?

Generally, spinning reserves are needed to decrease the ramp up of carbon resources. If

non-carbon resources are used to supply spinning and non-spinning reserves, then the current

concept of reserves may need to change. To explain, with renewables, the ramp up time is

almost zero, especially for solar and battery storage in comparison to carbon resources that have

varying ramp up time frames. Both wind and solar have some limitations in that they are not

available at all times. Wind as a resource has greater capacity to provide spinning and non-

spinning services than solar. Wind generally peaks at night and solar peaks in mid-day. Neither

peak during peak load time which is from 6pm to 8 pm. Wind coupled with battery storage

would offset its temporal limitations and could supply spinning and non-spinning reserves 24/7.

Also, hydro could be another renewable resource that could provide Essential Reliability

Services such as spinning and non-spinning for part of the year. Therefore, the CAISO should

seek to optimize these various non-carbon resources to meet Essential Reliability Services,

including spinning and non-spinning reserves.

4. What market products and associated pricing structures are necessary to support thetransformation from fuel-based energy markets to capability-based products?

Efforts currently underway at the CPUC aim to better integrate energy storage and

demand response into wholesale markets. These efforts will allow load reduction and load shift

resources to compete with traditional fuel-based generation resources. For example, the Supply

Side Working Group created under Decision (D.) 17-10-017 will explore development of

demand response products that can both increase and decrease energy consumption at key times

of the day, as needed for reliability or economic purposes.

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The CAISO can support this transformation and facilitate market integration of these

resources by participating in the CPUC initiatives, and taking leadership roles where appropriate.

The CAISO should consider models for resource capability that differ from the 24/7 model that

currently exists for some generators, and instead focus on system needs with high penetration of

solar output.

Trend 4: Demand becomes as important as supply in balancing the system

1. What practices and regulations must be removed, replaced or adapted to enable abroader range of customer demand to provide grid services?

As with the CAISO’s Slow Demand Response (DR) initiative, the CAISO should explore

slower response rates for different resources to allow more types of demand-side resource types

to participate in various markets. The IRP proceeding has discussed the development of

dynamic modeling techniques for demand-side resources. Including these resources in planning

could lead to greater procurement of those resources that cost-effectively reach environmental

goals. The CAISO’s TPP must also account for these resources more dynamically.

The CAISO’s role in this transformation includes creating models and communication

systems to provide avenues for participation for these resources. Currently, the CAISO systems

are not designed to accommodate these resources.

2. How can data security and customer data privacy be protected as electric serviceevolves to rely more and more on two-way information flows?

The CPUC has issued multiple decisions that address customer privacy and security to

reflect the changing nature of the use of customer data to provide energy. These decisions are

discussed below. ORA supports maintaining existing policies on data security, and recommends

that any additional discussion regarding sharing customer data refer to these previous CPUC

proceedings. ORA also recommends that additional data security policies continue to address

the types of entities that should have access to customer data, and define the specified purposes

for the data access. Current data sharing regulations also do not provide a common data sharing

method and/or protocol. ORA recommends continued discussions on data sharing to address

these issues as well.

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Public Utilities Code Section 8380 provides the initial framework for the sharing of and

protection of customer data. CPUC Rulemaking (R.) 08-012-009 included multiple decisions

detailing the proper rules to govern the sharing of data for Smart Grid deployment. D.11-07-056

developed rules to protect the privacy and security of customer data generated by IOU Smart

Meters. D.12-08-045 extended those same access and protection policies to customers of Gas

corporations, CCAs, and to residential and small commercial customers of electric service

providers.

D.14-05-016 adopted additional rules to provide access to energy usage and related data

to local government entities, researchers, and state and federal agencies that is consistent with

State laws and CPUC consumer protection procedures.

In addition, D.13-09-025 adopted criteria that third parties must meet in order to be

eligible to receive customer data. R.14-08-013, the CPUC’s DRP proceeding, is currently slated

to further develop customer energy data sharing policies and rules as they apply to the continued

development of the utilities’ DRPs.

3. What are the most effective ways of building public understanding of and support formaking portions of customer energy use controllable by system operators?

ORA recommends that new programs targeted at controlling customer load also explain

and include all available safe guards to reduce risks of inadvertent data releases. As expressed in

ORA’s reply to Trend 4, Question 2, ORA recommends that all communication regarding

sharing customer data comply with existing data sharing safeguards and regulations.

New programs should leverage existing marketing and outreach (M&O) channels that

have been created to reach customers for other purposes. These M&O channels include demand

side and customer programs and channels created for the implementation of time variant electric

pricing.

New programs could also work with appliance vendors and vendors of other products

that contribute to electrical loads to collaborate on ways for the vendors to have a proactive

interest in informing customers of the financial opportunities that may become available through

allowing load control by a system operator. Utilities could also play a role in presenting

information on new services and technologies, such as controllable loads and home area

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networks, objectively. Utilities can track and summarize performance results from products and

services used for load control and objectively present those results to customers.

4. What are the most effective ways for Demand Resource aggregators, DSOs and EnergyService Provider to earn public trust? What safeguards are needed to ensure newservice providers are responsive, responsible and accountable?

An effective M&O campaign can establish a level of public trust, but any earned trust

must be maintained through excellent customer service and the implementation of market

designs and regulatory structures that ensure real consequences, including penalties, for fraud

and abuse of customers. The pursuit of the state’s energy sector goals needs to start with

unambiguous, tested, transparent, and proven market rules that ensure providers cover their

operating costs and net benefits flow to ratepayers. Market designs must also be based on a

foundation that ensures Demand Resource aggregators, Distribution Systems Operators (DSOs),

and Energy Service Providers (ESPs) cannot leave customers with liabilities if vendors go

bankrupt or fail to remain in business and uphold their service obligations to customers.

Rigorous oversight of the market actors must be part of an effective market design.

Please see the response to Trend 5, Question 1 regarding ORA’s concerns about the

significant risks of an ESP business model. Demand Resource aggregators, DSOs, and ESPs

could partner with utilities to promote services in a way that benefits both the technology

provider and the utility’s customers. Utilities could play a role in assessing and working with

providers to present their product to customers.

5. How will adoption of consumer storage devices change customer engagement?

Customer adoption of energy storage devices can yield multiple benefits to the grid and

to ratepayers if done strategically. The CPUC is actively considering general policies and

specific use-cases that may facilitate customer adoption of energy storage as described below.

The utilities have solicited customer-sited energy storage to serve critical grid reliability

needs. For example, in the 2012 Long-Term Procurement Plan (LTPP) proceeding, the CPUC

determined that energy storage may provide reliability benefits to the electrical grid.

Specifically, the CPUC ordered Southern California Edison Company (SCE) to procure at least

50 MW of energy storage resources for its Local Capacity Requirement (LCR) in the Los

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Angeles Basin (LA Basin)26 stating, “[w]e view this as a reasonable and modest level of targeted

procurement of an emerging resources, and as an opportunity to assess the cost and performance

of energy storage resources.”27 In response, SCE procured approximately 263.64 MW of

behind-the-meter (BTM) energy storage,28 which the CPUC authorized to satisfy SCE’s LCR

needs.29

Further, in the Distributed Resources Plan (DRP) proceeding, the CPUC ordered the

utilities to execute use-cases to test whether DERs, including energy storage, are able to provide

grid and economic benefits such as deferring the costs of traditional distribution and transmission

level upgrades.30 The CPUC determined that these “use cases shall employ services obtained

from customer and/or Third party DERs.”31 The CPUC is examining similar deferral use-cases

in its Integrated Distributed Energy Resources (IDER) proceeding.32 Assuming the use-case

results show the deferral of traditional upgrades is possible and cost-effective, there may be an

incentive for customers to adopt DER, such as energy storage, to help alleviate grid needs and

avoid utility requests for capital upgrades.

Customer adoption of energy storage may also allow customers to realize the benefits of

pairing energy storage with other resources. For example, the CPUC found that energy storage

may be beneficial when paired with generating resources, including renewable resources.

Specifically, the CPUC stated that “storage devices paired with NEM [(Net Energy Metering)]-

eligible generating facilities can provide a broad range of benefits to host customers and the

utility grid.”33 These benefits include, but are not limited to “supplying back-up power during

grid outages, reducing a customers’ peak demand, shifting a customer’s electricity needs to align

26 D.13-02-015, Ordering Paragraph (OP) 1(b), pp. 130-131.27 D.13-02-015, p. 62.28 Testimony of SCE on the Results of Its 2013 LCR Request for Offer (LCR RFO) for the Western LosAngeles Basin, Table VII-24, p. 74 (served November 21, 2014); in A.14-11-012.29 D.15-11-041, Finding of Fact (FOF) 17, p. 35.30 Assigned Commissioner’s Ruling on Guidance for Public Utilities Code Section 769 – DistributionResources Planning (DRP Ruling), Attachment, pp. 6-13 (issued February 6, 2015); in R.14-08-013.31 DRP Ruling, pp. 6-7.32 D.16-12-036, p. 2; in R.14-10-003.33 D.16-04-020, p. 5; in R.12-11-005.

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with grid supply, reducing a customer’s total energy purchases, and supplying reliability service

to the grid”.34

Promoting cost-effective policies that encourage customers to adopt energy storage may

result in a broader understanding of the benefits associated with energy storage, such as the

financial benefit of storing and relying upon onsite renewable generation.

ORA supports the state’s policy of employing energy storage to reduce the emissions of

GHG by deferring or eliminating the need for traditional generation.35 In addition to the benefit

of reducing GHG emission, energy storage may provide crucial benefits to specific segments of

the utilities’ customers such as those who reside in disadvantaged communities. Facilitating and

encouraging customer adoption of energy storage in disadvantage communities and/or

surrounding service territories may advance the CPUC’s procurement objective of “minimizing

localized air pollutants and other GHG emissions, with early priority on disadvantage

communities.”36

ORA supports a strategic approach to promote customer engagement and customer

adoption of energy storage devices that may maximize the benefits to both the customer and the

electric grid.

Trend 5: Electric service is increasingly decentralized

1. What policies can best encourage and support monopoly distribution utilities to adoptenergy service provider business models?

The context of trend 5 is a vision of a future where DERs play a far more central role in electric

supply, reliability, and grid management. ORA agrees that there is a need to create better market

and regulatory mechanisms to integrate DERs for a broad array of grid and ratepayer

benefits. These opportunities are being pursued in a number of current proceedings at the

CPUC, including DRP, IDER and the Rule 21 Interconnection proceeding, as well as through

CAISO wholesale tariffs. However, Trend 5 also asserts that an ESP business model is

34 D.16-04-020, p. 5.35 Public Utilities Code Section 2835(a) (3).36 Order Instituting Rulemaking to Develop an Electricity Integrated Resource Planning Framework andto Coordinate and Refine Long-Term Procurement Planning Requirements (IRP OIR), p. 9; in R.16-02-007.

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desirable. ORA has concerns about the current functioning of the Direct Access (DA) program,

which is what ORA understands to be the approximate equivalent to an ESP business

model. Specifically, the DA program is capped by statute because a large amount of DA

contributes to market and price volatility, and its growth was a major contributor to the

California energy crisis. This cap protects ratepayers from price spikes and maintains grid

stability. ESPs are not obligated to enter into long-term contracts, and their customers often

move between ESPs to find better rates. Increasing the amount of ESP-like market participants

is risky and should be scrutinized very closely for weaknesses in customer protection, grid

protection, and market stability. Furthermore, a business model providing for full customer

choice may not lead to optimal energy and resource adequacy portfolios. ORA recommends that

the CAISO provide more detailed information on the ESP business model it envisions, the

rationale supporting the business model, the benefit of such model to utility ratepayers and the

State’s environmental goals in comparison to current policy. Without this information, ORA

cannot evaluate the CAISO’s proposed ESP business model.

2. What policies are necessary to ensure that state energy and climate goals can beachieved as electric services is decentralized?

The policies that ensure that the state’s energy and climate goals will be realized are

currently being developed in the CPUC’s IRP proceeding. The CPUC’s IRP process, mandated

by SB 350, is designed to meet California’s GHG emissions reduction targets for the electric

sector, consistent with the statewide goal of achieving a 40 percent reduction in GHG emissions

below 1990 levels by 2030, while maintaining reliability, minimizing ratepayer bill impacts, and

prioritizing air quality benefits in disadvantaged communities. As electric services are

decentralized, these mandates will still be in place and every LSE will have to submit an IRP

designed to meet California’s goals. The CPUC and the CEC will determine whether the LSEs’

plans meet their pro rata SB 350 requirements, or whether the CPUC and the CEC will order

additional or alternative procurement to meet California’s energy and climate goals.

3. What safeguards are necessary to ensure decentralized service meets highest standardsfor safety, reliability, and customer support and supplier accountability?

All electric service providers should be held accountable for providing safe and reliable

service consistent with Public Utilities Code Section 451, but this does not require compliance

with the “highest standards.” Increasing levels of reliability and customer choice come at a cost,

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and there are no standards defining adequate or superior levels of reliability for the distribution

grid.37 While safety and reliability are typically referenced together, distribution automation

such as reclosers improve reliability, but raise concerns regarding safety.38 Effective

decentralization of electric service requires careful balancing to simultaneously maximize

environmental benefits, minimize costs, maintain system reliability and safety, and minimize

barriers to customer choice.39 State law as expressed in Assembly Bill (AB) 327 40 establishes

that DERs should provide net ratepayer benefits, and the CPUC and stakeholders are actively

engaged in the DRP proceeding to develop tools and processes to ensure that the intent of AB

327 is realized.41 Within this context, ORA recommends the following safeguards.

First, the CPUC has existing General Orders and Electric Rules that guide quality of

electric service as well as safety and reliability.42 These should apply equally to all service

providers. Second, grid investments have real costs that are included as rate increases as quickly

as the regulatory process allows, but rate reductions based on forecast DER benefits are much

less certain. CPUC approval of grid investments justified based on a prospective forecast of net

benefits should include an oversight process that ensures that promised net-benefits are realized.

Third, the CPUC should consider establishing minimum reliability standards, including

definitions of how outages are measured and counted in metrics such as System Average

Interruption Duration Index (SAIDI) and System Average Interruption Frequency Index (SAIFI),

to ensure a consistent, reasonable, and predictable reliability targets. Such standards would

provide a baseline for customers seeking higher levels of reliability through microgrids than

deemed reasonable for the average customer. ORA recommends that cost-effective integration

37 SCE response to ORA discovery in the test year (TY) 2018 General Rate Case (GRC), application(A).16-09-001. See ORA opening testimony, Exhibit ORA-9 workpapers, Book 1, pp. 38-41.38 SDG&E TY 2019 GRC, A.17-010-007, SDG&E Opening Testimony Exhibit SDGE-15, pp. WHS-92to WHS-96. Also, see http://www.sfchronicle.com/bayarea/article/Power-line-restart-device-implicated-in-past-12324764.php.39 ORA workpaper in SCE TY 2018 General Rate Case (GRC), application (A).16-09-001. See ORAopening testimony, Exhibit ORA-9 workpapers, Book 2, pp. 382.40 Assembly Bill 327: Electricity: Natural Gas: Rates: Net Energy Metering: California RenewablePortfolio Standards (Perea, Chapter 611, Statutes of 2013) (AB 327 2013).41 Rulemaking (R.) 14-08-013.42 For example, General Order 95, “Overhead electric line construction,” and Rule 21, “GeneratingFacility Interconnections.”

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of DERs, while maintaining adequate reliability and safety, should precede any efforts to

increase system wide reliability.43 Finally, California agencies such as the CPUC should

proactively establish data gathering requirements for all service providers to measure customer

satisfaction and hold service providers accountable for poor performance.

4. What standards can ensure that decentralization of electric service advances gridmodernization?

As posed, this question incorrectly presumes that “grid modernization” is the only option,

when instead grid modernization is one of many tools intended to realize the forecast benefits of

DER. This is an important distinction since stakeholders including grid equipment vendors and

IOUs will financially benefit if grid modernization investments are authorized and funded by

ratepayers, whether or not they lead to the realization of benefits associated with DER.

The CPUC DRP proceeding is explicitly addressing grid modernization and other facets

of distribution planning to ensure that the intent of Assembly Bill 327 (AB 327)44 is achieved. A

key decision including a definition of grid modernization is expected by the end of 2017. The

CPUC IDER proceeding compliments the DRP proceeding in developing comprehensive

mechanisms to maximize the cost-effective integration of DER, including business models for

the procurement and control of DERs.45 These active proceedings provide a venue for

development of California-specific guidelines and standards with active stakeholder

participation. Within these proceedings ORA has made many recommendations including 1)

learn from Hawaii, Germany, and other regions that are further along the DER integration

learning curve than California, and 2) leverage existing investments such as smart meter

infrastructure and third-party communication systems where possible.

This question also presumes that decentralization will be a long-term reality based on

short term trends from a time when DERs and CCAs are relatively new. It is premature to

assume that decentralization is the best solution for customers or achieving state policies. For

example, customer interest in CCAs may fade if the first wave of CCAs fail to provide cheaper

43 Utilities are required to reduce outages on their most unreliable circuits, per AB 66 (Muratsuchi, 2013)and Public Utilities Code Section 2774.1. ORA generally supports these efforts.44 AB 327 2013.45 R.14-10-003.

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and cleaner electricity with better service than IOUs. Also, while costs are falling for DERs like

rooftop solar PV and storage, subsidies are also declining. Customer uptake of DER depends in

part on the financial metrics such as payback period, and it is not certain how typical payback

periods change over time, particularly given changing rate structures. We should continue to

optimize the integration of DERs in the most cost effective manner. The CPUC and California

IOUs are also participating in developing national standards to ensure that the benefits of DER

are realized without sacrificing safety or reliability. For example, the Institute of Electrical and

Electronics Engineers (IEEE) 1547 and 2030 series of standards46 provide necessary guidance

for the interconnection and interoperability of DERs.

5. How should the evolving decentralization be incorporated into the transmissionplanning process?

ORA recommends continued consideration of DERs in distribution planning and

California energy markets. Recognizing DER capacity and advancing technologies in the

distribution planning process and energy markets will influence the outcome of the CAISO

transmission planning processes going forward.

Distribution Planning Enhancements

Utility Distribution Companies (UDCs) currently consider DER output in their

distribution plans to determine their net load needs. UDCs report net load needs to

the CEC. ORA recommends that UDCs enhance their distribution plan reporting to

include the expected output from DERs along with their net load needs.47

ORA recommends that UDCs share distribution planning results with the CAISO.

ORA recommends the consideration of DERs as cost-effective reliability solutions in

the transmission and distribution planning processes.

46 IEEE standards are available for a fee at http://standards.ieee.org/. A summary of IEEE 1547 and 2030is available at https://www.nrel.gov/docs/fy15osti/63157.pdf.47 Western Electricity Coordinating Council, Production Cost Model (PCM) Data Working Group,November 14, 2018 meeting, PCM staff requests that Balancing Area Authorities validate assumptions onbehind the meter solar output for the regional anchor data set.

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DER Market Participation Enhancements

The CAISO has established interconnection requirements for DERs through recent

CAISO tariff revisions. These requirements are consistent with existing interconnection

requirements for carbon-based generators. ORA recommends continued refinements to the DER

Interconnection Process to address the following issues:

Policies and rules for DER compensation.

Coordination and communication protocols between UDCs and the CAISO, and

UDCs and DERs for DER market participation. These protocols should be

established through workgroups with DERs providers, the CAISO and UDCs.

UDC distribution interconnection and market participation implementation

requirements for DERs.48

CAISO market performance reviews of DERs annually.

ORA asserts that it is not necessary for the CAISO to have visibility down to the end user, but

agrees that the CAISO must have visibility to resources at the Transmission and Distribution

interface.

Trend 6: Regional Coordination Supports Efficient Grid Operations

1. How should states evaluate the potential benefits of regional markets and regionalelectric system operation against pressures to maintain current practices?

To assist state evaluation of potential benefits of regional markets, the CAISO should

provide more details on the design of regional markets and produce data related to cost savings.

State practices adhere to policies designed to fit varying needs and should not be expected to

change without convincing evidence of benefits that exceed potential risks and negative impacts

associated with changing current state policies. For example, California’s RA program seeks to

support the state’s GHG goals by specific rules to address the contributions of demand response

and renewable resources.

48 UDCs must assess DERs or DER aggregation compliance with UDC tariff requirements forparticipation, and confirm that their operations do not pose a threat to the reliable operation of thedistribution system.

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Trend 6 of the Electricity 2030 Plan claims that Californians will realize an annual

savings of one billion dollars from regional operations.49 This projection, along with projections

for other states, must be vetted by the states and the analysis supporting the projected cost

savings should be made available by the CAISO. The claim that regionalization “enables

unneeded power plants to retire, makes low-cost power available everywhere and increases

security of supply”50 needs to be supported by detailed assumptions and analysis by the states in

order to substantiate the savings the CAISO projects. For example, how many power plants will

no longer be needed and retire as a result of regionalization beyond the amount of retirements

that will already occur in California with the planned reduction of fossil fuel sources? Along

with cost savings, the CAISO analysis should include any potential costs incurred by states from

regionalization. The cost savings for California should also be put in the context of savings for

other states to ensure that Californians would receive a fair and equal savings from a regional

market.

The question notes a perceived “pressure to maintain current practices.” However,

California is seeking to significantly redefine future procurement in multiple venues, such as the

CPUC IRP and RA proceedings. Therefore, California must compare the CAISO’s cost analysis

for regionalization savings against the projected costs and benefits of California’s rapidly

evolving procurement practices. For California, or any state, to support a future procurement

path, it must consider regionalization and the various paths it might take along with alternatives

within the current grid system operations. The value assessment also needs to consider trade-

offs and impacts on state policies. While the Electricity 2030 Plan contends that “procurement

remains each state’s prerogative,”51 that issue remained unresolved in prior CAISO

regionalization forums.52 In Regional RA comments submitted to CAISO, ORA discussed

ongoing concerns over issues that would impact California ratepayers.53 Additionally, the

49 Electricity 2030 Plan, p. 18.50 Electricity 2030 Plan, p. 18.51 Electricity 2030 Plan, p. 18.52 Regional Resource Adequacy Draft Regional Framework Proposal Stakeholder Comments and CAISOResponses, March 1, 2017, CAISO, pp. 65-84.53 ORA comments on CAISO Regional Resource Adequacy Initiative, January 11, 2017, available at:http://www.caiso.com/Documents/ORAComments-RegionalResourceAdequacyDraftRegionalFrameworkProposal.pdf

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CAISO has not addressed questions regarding the full impacts of ceding authority to a regional

system operator when California seeks a very ambitious climate agenda. These questions must

be resolved prior to California weighing the full benefits and impacts of regionalization.

ORA has also raised concerns that the CAISO Energy Imbalance Market (EIM) quarterly

benefit reports do not allow EIM participants to understand the benefits of selling and receiving

low-cost energy resources through the EIM, or the benefits of the EIM’s “flexible ramping

procurement diversity savings.” The benefits of these activities are not quantified in the EIM

benefits reports; these reports provide the total estimated benefits from all EIM transactions

through a counterfactual calculation.

2. How can states best coordinate infrastructure planning to inform investment decisionsand ensure access to low cost regional resources?

Regional infrastructure planning should evaluate the total cost and benefits of accessing

regional resources through new regional transmission projects in comparison to the total cost and

benefits of accessing in state resources with existing or enhanced in-state transmission projects.

The benefits analysis should consider the expected economic benefits from new transmission

projects to regions such as employment and sales tax increases.

3. How can RSO operation respect differing state environmental policies?

ORA recommends that the proposed Regional System Operator (RSO) mechanisms

acknowledge state environmental policies without resulting in greater costs to ratepayers for

compliance. ORA remains concerned that the current proposed framework for recognizing

California’s GHG targets in the EIM will lead to additional costs to ratepayers for accessing

energy through EIM.54 This mechanism has the potential to require California ratepayers to pay

for GHG emissions in other states if these emissions can be attributed to the delivery of energy

into California through the EIM.

54 CAISO EIM Greenhouse Gas Enhancement Revised Draft Final Proposal, June 23, 2017, CAISO, pp.6-17.

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Trend 7: Transportation and buildings energy use is integrated with electric service

1. Which agency or agencies should guide the shift in California energy planning totracking and reporting total energy use on an integrated, holistic basis, rather thanseparated into electricity use and non-electricity energy use?

The CARB, in coordination with other state agencies, provides a statewide analysis in its

Scoping Plan that evaluates GHG reduction opportunities and costs across all sectors of the

California economy. This analysis shows the interactive effects of different actions in the

electric and other economic sectors. As part of this effort, the CARB, the CPUC, and the CEC

coordinate in establishing GHG planning targets for the electric sector and individual LSEs and

publicly owned utilities (POUs) to be used in the IRP process. Building on this existing valuable

information and analysis, state agencies should be successful in tracking and reporting total

energy use on an integrated, holistic basis across all sectors of the California economy.

2. What key design elements will enable state government and utility incentive andsupport programs to accelerate adoption of Electric Vehicles? What funding sourcesare available to incentivize rapid EV adoption, in all transportation sectors?

There are many forms of funding and support through proceedings and policies already

underway to address this trend through the state legislation, the CPUC, the CEC, and the CARB.

Each of these programs and pilots can and will help to inform further incentives and support

program design based on the most effective strategies. Some examples are shown in Table 1

below.

Table 1. CPUC and Interagency Programs/Pilots

Senate Bill 350 Transportation electrification (TE) applications from Pacific Gas and

Electric (PG&E), Southern California Edison (SCE), and San Diego Gasand Electric (SDG&E), as well as Bear Valley Electric, PacifiCorp, andLiberty Utilities

Plug-in electric vehicle (PEV) phase 1 and phase 2 pilots from the IOUs Statewide PEV submetering program EV iCharge Forward pilot with BMW and PG&E Electric vehicle storage accelerator (EVSA) pilot with Honda and UCSD Vehicle grid integration (VGI) communications protocol working group California gas tax increase

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The state agencies continue to coordinate on transportation electrification goals, which

includes leveraging the results of these programs to inform further programs, policies, and

investment decisions. The following state programs, regulations, and other initiatives were

identified in the Assigned Commissioner’s Ruling regarding the filing of the transportation

electrification applications pursuant to Senate Bill 350.

Table 2. Non-CPUC TE programs, regulations, funding sources, and other initiatives55

CARB CEC State Transportation

Authority, Caltrans, etc.

2016 Mobile SourceStrategy

Draft Scoping Plan(Concept 3)

Low Carbon FuelStandard

Advanced Clean Transit Advanced Clean Cars SB 375 Sustainable

Communities Strategy

Electric ProgramInvestment Charge AppliedResearch & Developmentand TechnologyDemonstration &Deployment Projects

Alternative and RenewableFuel Vehicle TechnologyProgram Investments

POU TE Initiatives

Sustainable FreightAction Plan

Fixing America’sSurface Transportation(FAST) Act-Designation ofAlternative FuelCorridors

SustainableTransportation PlanningGrants

Ongoing regional and local efforts are also underway, for which the most recent

transportation electrification applications were guided to “consult with Metropolitan Planning

Organizations and Regional Transportation Planning Agencies within their service territories to

understand local priorities and differences in transportation needs and design infrastructure

programs accordingly.”56 Other suggested sources of funding for program design include:

private, federal, state or local sources, mass transit, highway funding, TE, or to mitigate air

pollutant or greenhouse gas emissions, and Federal and Private Sector Actions to Accelerate

Electric Vehicle Adoption in the United States such as the Renewable Energy and Efficient

Energy’s Loan Program Office. The results of these programs should be reviewed and revised as

more hard data becomes available to inform effective decisions.

55 Assigned Commissioner’s Ruling Regarding the Filing of the Transportation ElectrificationApplications Pursuant to Senate Bill 350, September 14, 2016, p. 26.56 Assigned Commissioner’s Ruling Regarding the Filing of the Transportation ElectrificationApplications Pursuant to Senate Bill 350, September 14, 2016, p. 26.

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3. What programs and incentives are required to expand daytime EV charginginfrastructure at workplaces and multifamily dwellings? How can EV owners who donot have access to at-home charging be served?

There are three large-scale pilots well underway designed to expand and discover the

most effective methods as well as the specific challenges for workplaces and multi-unit

dwellings (MUDs). These pilots are: PG&E Charge Ready, SCE PEV Workplace Pilot, and

SDG&E Power Your Drive Workplace Program.

PG&E’s EV Charge Network Program was approved through the CPUC for $130 million

to increase access to charging for electric vehicles for workplaces and multi-unit dwellings. The

Program authorizes PG&E to install 7,500 charging ports over a three-year period while testing

alternative ownership options for effectiveness.57 Significant interest in the program has

developed, but several major hurdles remain such as site challenges for Americans with

Disabilities Act requirements as well as metering. SCE’s Charge Ready Program is much further

along with SCE pilots such as Workplace Charging (2014) and PEV Smart Charging (2016).

Over 38 sites (512 ports) have completed construction with 29 (505) more in design or

construction.58 SDG&E’s Power Your Drive program is also underway, with a different design

around utility ownership of charging stations. Because all of the IOUs have slightly different

programs, the effectiveness of each can be compared and optimized going forward. These

programs are still in the early stages with much of the funds still unused, yielding opportunity to

carry forward cost efficient pilot elements with the remaining funding. Program stakeholders

and administrators can address challenges reported in the quarterly Program Advisory Council

meetings to most effectively address the premise of this question.

4. What data analytics and control protocols and technologies are required to allow fleetsof EVs and behind the meter stationary storage to provide local distribution andwholesale grid services?

The data analytics, control protocols and technologies that are required to allow fleets of EVs

and behind the meter stationary storage to provide local distribution and wholesale grid services

are continuously evolving and being explored through several pilots and discussions. The

57 PG&E Electric Vehicle Charge Network Quarterly Report, Report Period April 1, 2017 - June 30,2017. August 2017, PG&E p.1.58 SCE Charge Ready Advisory Board Meeting Presentation. November 7, 2017, p.7.

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CPUC, the CEC, and CARB are facilitating how to address this question in detail through the

following programs: BMW iCharge Forward, the IOU Plug-In Electric Vehicle (PEV) programs,

the Electric Vehicle Storage Accelerator, the California submetering program, and the

interagency Vehicle Grid Integration (VGI) Communications Protocol Working Group. This

question is particularly central to the goals of VGI Communications Protocol Working Group,

scheduled to produce a report by the end of the year. More information on the data analytics,

control protocols, and technologies can be found on the working group website.59 The primary

focus is to enable as many market-driven technological solutions as possible while providing any

overarching protocol to ensure systems have VGI capabilities. ORA suggests the EV

infrastructure equipment be modular and allow for upgrades with technology advances to

minimize stranded assets and the equipment from being obsolete. At a basic level, data

communication and control between the Utility, EV Service Provider, the EVSE, the vehicle, and

any potential aggregator can be achieved through many different means such as Open ADR

Internet, telematics, Open Charge Point Protocol, or IEEE 2030.5 Smart Grid communications.

The work of this group, which includes the CPUC, the CEC, CARB, electric vehicle supply

equipment (EVSE) providers, auto manufacturers, IOUs, energy management aggregators,

among other stakeholders, should be followed closely to determine the optimum path forward.

Challenges remain with inelastic demand and expensive technology and infrastructure that

currently outweigh any potential value streams, particularly for the concept of vehicle-to-grid

(V2G) charging. The challenges associated with this technology are being uncovered through

the Electric Vehicle Storage Accelerator on the University of California, San Diego’s campus by

SDG&E, Nuvve, and other partners. This pilot should be followed closely to address the

question at hand about required technologies and protocols but also to address the costs and

benefits to evaluate the potential of this technology going forward. There is a high potential for

fleets and Medium Duty/Heavy Duty (MD/HD) vehicles to leverage flexible charging

capabilities where there is aggregation of charging to significant amounts, more coordinated

scheduling, and the bottom line is much more closely monitored. The results of the

59 Vehicle-Grid Integration Communications Protocol Working Group Website. 2017; California PublicUtilities Commission, available at: http://www.cpuc.ca.gov/vgi/.

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aforementioned programs can help to inform how to optimally allocate any research, time, and

investments for enabling charging grid services.

Trend 8: Develop ways to enable everyone to contribute to, and benefit from, the transitionaway from fossil fuels

1. Which investment opportunities promise the largest returns in moving to clean energy?

SB 350, the Clean Energy and Pollution Reduction Act of 2015, mandates the CPUC and

the CEC to design and implement an IRP framework in California. SB 350 requires the IRP

process to meet California’s GHG emissions reduction targets for the electric sector while

maintaining reliability, minimizing ratepayer bill impacts, and prioritizing air quality benefits in

disadvantaged communities. The CPUC’s IRP process seeks to identify the optimal portfolio of

supply and demand-side resources to reduce GHG emissions and ensure reliability while meeting

the state’s other policy goals. This includes guiding resource investment decisions across all

types of LSEs and resource programs. Therefore, the CPUC’s IRP process will offer guidance

on which investment opportunities in clean energy provide the largest return for California’s

electric sector. The current IRP cycle (2017-2018) is expecting a final decision in 2018.

Public Utilities Code Section 454.52(a) (1) (D), requires the CPUC to minimize impacts

on ratepayers’ bills. While ORA supports cost-effective procurement of clean energy resources

that provides value to ratepayers, the CPUC must also carefully design reasonable cost-

effectiveness methodologies and place significant emphasis on minimizing impacts on

ratepayers’ bills. In moving to clean energy, ratepayers should ultimately see the largest returns

and value on their investments. Furthermore, the CPUC should also prioritize renewable energy

projects that provide environmental and economic benefits to disadvantaged communities

(DACs) and improved access for DACs to energy efficiency, solar photovoltaic, renewable

energy, contracting opportunities for local small businesses and zero-emission or near zero-

emission transportation options.

2. How can investor confidence in clean energy projects be strengthened?

ORA recommends regulatory efficiency to remove or mitigate regulatory uncertainties

among renewable energy investors.

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3. What regulations and standards are necessary to ensure that clean energy programsbenefits all customers, in every part of the state?

ORA strongly supports clean energy programs that benefit all customers particularly low-

income and customers in DACs. The CPUC has used two general approaches in seeking to

provide more equitable access to clean energy programs. One approach has used geographically

targeted programs, focusing on DACs. Another approach has been to focus on low-income

households, or low-income and/or affordable housing, seeking to increase access to clean energy

resources for low-income households. Both of these approaches focus on geographical areas and

low-income households which are needed to ensure that clean energy benefits all customers, in

every part of the state. Some of the programs administered by the CPUC direct that clean energy

programs provide economic benefits to disadvantaged communities in addition to environmental

benefits

Various clean energy programs prioritize or set aside a percentage of resources for areas

that have been identified as DACs. Generally, DACs are defined as areas that are overburdened

by environmental pollutants, or that demonstrate unfavorable socio-economic indicators, such as

household income and educational attainment. The Office of Environmental Health Hazard

Assessment (OEHHA), on behalf of the California Environmental Protection Agency and

pursuant to Section 39711 of the Health and Safety Code, developed a tool referred to as

CalEnviroScreen that can be used to identify California communities that are disproportionately

burdened by multiple sources of pollution, as well as communities that demonstrate unfavorable

socio-economic indicators.60 OEHHA has developed various scoring mechanisms to identify

DACs. The most commonly used scoring method utilizes indicators based on both

environmental and socio-economic indicators. Generally, OEHHA identifies the 25 percent of

census tracts that exhibit the worst environmental and socio-economic indicators as DACs.

OEHHA has also identified the census tracts that score in the top 5 percent of CalEnviroScreen’s

pollution burden indicators, but that do not necessarily demonstrate unfavorable socio-economic

indicators in their overall score.61

60 The CalEnviroScreen tool is available at https://oehha.ca.gov/calenviroscreen61 Designation of Disadvantaged Communities Pursuant to Senate Bill 535 (De Leon), April 2017,CAEPA, available at: https://calepa.ca.gov/wp-content/uploads/sites/34/2017/04/SB-535-Designation-Final.pdf. The rationale for this additional designation of DACs is explained in this document.

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Below are several examples of programs administered by the CPUC that seek to direct

clean energy benefits to marginalized communities. The CPUC should continue to assess the

needs of low income customers and DACs, and design and implement programs that best address

these needs.

California Climate Investments to Benefit Disadvantaged Communities

Funds received from California’s GHGs cap-and-trade program are deposited in the

Greenhouse Gas Reduction Fund to be used for programs that reduce emissions of GHGs.

Assembly Bill 155062 requires that at least 25 percent of funds go to projects within and

benefitting DACs,63 at least five percent of funds go to projects benefitting low-income

households within or adjacent to DACs, and at least five percent of funds go to projects

benefitting individuals living in low-income communities that are adjacent to DACs.64 ORA

recommends this comprehensive approach, which seeks to direct clean energy benefits to

geographically designated areas, as well as more granularly to low-income households.

The Self-Generation Incentive Program Equity Budget

Recently, the Commission issued D.17-10-004, which established an Equity Budget

within the Self-Generation Incentive Program (SGIP). California’s SGIP was established in

2001 by the CPUC in D.01-03-073 in response to AB 970.65 AB 970 directed the CPUC to

provide incentives for distributed generation resources to reduce peak energy demand. The SGIP

Equity Budget directs clean energy resources to marginalized communities in a comprehensive

manner, focusing both on geographic areas, as well as low-income households.

62 Assembly Bill 1550: Greenhouse Gases: Investment Plan: Disadvantaged Communities (GomezChapter 369, Statutes of 2016) (AB 1550 2013).63 California Health and Safety Code Sections 39713(a) and 39711. DACs are defined as the census tractsidentified by OEHHA that exhibit the worst environmental and socio-economic indicators statewide.64 California Health and Safety Code Sections 39713 (d) (1), (2). “Low-income households” are thosewith household incomes at or below 80 percent of the statewide median income or with householdincomes at or below the threshold designated as low income by the Department of Housing andCommunity Development’s list of state income limits. “Low-income communities” are census tracts withmedian household incomes at or below 80 percent of the statewide median income or with medianhousehold incomes at or below the threshold designated as low income by the Department of Housingand Community Development’s list of state income limits.65 Assembly Bill 970: Electrical Energy; Thermal Power plants: Permits (Ducheny, Chapter 329, Statutes2000) (AB 970)

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The CPUC ordered that 25 percent of funds collected for SGIP be reserved for projects

eligible under the Equity Budget.66 To be eligible under the Equity Budget, a project must either

be 1) located in a DAC67 or a “low-income community”68; 2) located within multi-family “low-

income residential housing,”69 or 3) in a single-family “low-income residence,” regardless of

location.70

In developing the SGIP Equity Budget, the CPUC chose to direct clean energy resources

both to geographically defined DACs and low-income communities, as well as to low-income

housing. The CPUC recognized that geographically defined disadvantaged census tracts should

be the focus of benefits. The CPUC also recognized that low-income residences, regardless of

location, should also have access to Self-Generation Incentive Program (SGIP) Equity Budget.71

Green Tariff Shared Renewables Environmental Justice Reservation

SB 4372 enacted the Green Tariff Shared Renewables (GTSR) program. The GTSR

program allows customers from the large electricity IOUs to pay a premium price in order to

receive between 50 to 100 percent of their electricity demand from solar generation. GTSR

66 D.17-10-004, Decision establishing equity budget for self-generation incentive program, issued October12, 2017; in R. 12-11-005.

67 D.17-10-004, p. 11. For the SGIP Equity Budget, a DAC is defined as the statewide top 25 percentmost affected census tracts by environmental and socio-economic indicators in the CalEnviroScreen, aswell as census tracts that score the highest 5 percent of CalEnviroScreen’ s pollution burden, regardless oftheir overall score.

68 D.17-10-004, pp. 13-14, citing California Code, Health and Safety Code Section 39713(d) (2). A “low-income community” is defined as census tracts with median household incomes at or below 80 percent ofthe statewide median income or with median household incomes at or below the threshold designated aslow-income by the Department of Housing and Community Development’s list of state income limits.69 D.17-10-004, pp. 14-15 citing Public Utilities Code Section 2852 and Health and Safety Code Section50052.5. “Low-income residential housing” is defined as a multifamily residential building of at leastfive rental housing units that is operated to provide deed-restricted low-income residential housing,located in a DAC, or where 80 percent of the households have incomes at or below 60 percent of themedian income.

70 California Public Utilities Code Section 2852(a) (3) (C) for the definition of a “low-income residentialhousing.”71 D.17-10-004, pp.12-15.

72 Senate Bill 43: Electricity: Green Tariff Shared Renewables Program (Wolk, Chapter 413, Statutes of2013).

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subscriber demand should result in the development of “additional” incremental renewable

energy facilities, than would have been developed independent of the GTSR program.73 The

GTSR Program is capped at 600 megawatts (MW) statewide.74 Of that total capacity, 100 MW

of renewable energy facilities must be part of the Environmental Justice (“EJ”) Reservation.75

The EJ Reservation facilities must be located in DACs, defined by census tracts as the most

impacted 20 percent of communities demonstrating the most unfavorable environmental and

socio-economic indicators in the CalEnviroScreen tool.76 In the case of the GTSR Program,

program benefits cannot be easily directed to individual low-income residences. Thus, it is

appropriate to direct clean energy benefits geographically, to census tracts identified as DACs.

Integrated Resource Planning

SB 350 directs the CPUC to administer the IRP process for LSEs in its jurisdiction.77 As

the primary venue for SB 350 requirements related to resource planning for the electric sector,78

IRP is an “umbrella” planning proceeding that considers all of the CPUC’s electric procurement

policies and programs in order to ensure that California receives a reliable, safe, and cost-

effective electricity supply. Pursuant to SB 350, the CPUC is to ensure that as part of the IRP

process LSEs should “minimize localized air pollutants and other greenhouse gas emissions,

with early priority on disadvantaged communities identified pursuant to Section 39711 of the

Health and Safety Code.”79

73 D.15-01-051, Decision Approving Green Tariff Shared Renewables Program for San Diego Gas &Electric Company, Pacific Gas and Electric and Southern California Edison Company pursuant to SenateBill 43, issued February 2, 2015.

74 D.15-01-051, p. 4, implementing Public Utilities Code Section 2833(d).75 D.15-01-051, pp. 51-52, implementing Public Utilities Code Section 2833(d) (1) (A).76 D.15-01-051, p. 54, implementing Public Utilities Code Section 2833(d) (1) (A).77 Senate Bill 350 is codified by Public Utilities Code Section 454.52 (b) (1) et seq.78 Rulemaking 16-02-007, Assigned Commissioner and Assigned Administrative Law Judge’s RulingIdentifying Issues and Schedule of Review for 2017 Renewables Portfolio Standard Procurement Plansand Inviting Comments on Renewable Auction Mechanism Proposal, issued May 26, 2017, p. 20.79 California Public Utilities Code Section 454.52(a) (1) (H), emphasis added. The definition of DACs isstill being developed.

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In addition, SB 350 directs LSEs to meet the requirements of the California RPS as an

integral part of the IRP process.80 Public Utilities Code Section 399.13(a)(7) requires LSE give

preferences to RPS projects that provide environmental and economic benefits to DACs.81 The

benefits of clean energy resources include not just environmental benefits, but economic benefits

such as jobs and increased tax revenue. These economic benefits should be equitably distributed.

Increasing Access for Low-Income Households to Clean Energy Resources

Many ratepayer-funded programs overseen by the CPUC are designed to provide low-

income households access to clean energy resources. These programs may serve as a model for

rules and regulations to ensure that clean energy benefits all Californians. Affordability is often

the main barrier to low-income customers accessing clean energy resources.

Energy Savings Assistance Program

The Energy Savings Assistance (ESA) program provides in-residence weatherization and

energy efficiency services to low-income households at no cost.82 Statute requires the CPUC to

ensure that all eligible low-income households have an opportunity to participate in the ESA

program by December 31, 2020.83 Thus, the legislature requires that all eligible low-income

households have access to a reasonable level of energy efficiency benefits. Rules and

regulations should establish that all low-income households receive at least some level of clean

energy benefits.

80 California Public Utilities Code Section 454.52(a) (1) (B), directing that IRPs guide renewableprocurement consistent with the California Renewables Portfolio Program (Article 16 (commencing withSection 399.11) of Chapter 2.3).81 California Public Utilities Code Section 399.13(a)(7) states:

In soliciting and procuring eligible renewable energy resources for California-based projects,each electrical corporation shall give preference to renewable energy projects that provideenvironmental and economic benefits to communities afflicted with poverty or highunemployment, or that suffer from high emission levels of toxic air contaminants, criteria airpollutants, and greenhouse gases.

82 California Public Utilities Code Sections 382(e), 2790and Section 739.1(a).

Low-income households are defined as having household incomes no greater than 200 percent of thefederal poverty guidelines.83 California Public Utilities Code Section 382(e), emphasis added.

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Programs Providing Access to Solar Resources to Low-Income Customers

There are a number of programs that provide increased access to a solar powered electric

system. These programs generally offset some of the upfront costs of installing a solar electric

system, as long as at least some portion of the benefits of the system are directed to low-income

households. These programs generally have a set budget and are available to applicants until

funds are depleted. These programs include the Single-Family Affordable Solar Housing

program and the Multi-Family Affordable Solar Housing Program.

Identifying Barriers to Clean Energy Benefits for Low-Income Customers.

Pursuant to SB 350, the CEC published a study identifying the following barriers to clean

energy for low-income customers:84

Barriers for low-income customers to energy efficiency and weatherization investments,

including those in disadvantaged communities, as well as recommendations on how to

increase access to energy efficiency and weatherization investments to low-income

customers.

Barriers to and opportunities for solar photovoltaic energy generation, as well as barriers

to and opportunities for access to other renewable energy by low-income customers.

Barriers to contracting opportunities for local small businesses in disadvantaged

communities.

Barriers for low-income customers to zero-emission and near zero-emission

transportation options, including those in disadvantaged communities, as well as

recommendations on how to increase access to zero emission and near zero emission

transportation options to low-income customers, including those in disadvantaged

communities.

84 Final Staff Report Low-Income Barriers Study, Part A: Overcoming Barriers to Energy Efficiency andRenewables for Low-Income Customers and Small Business Contracting Opportunities in DisadvantagedCommunities. December 2016, California Energy Commission, p. 1, available at:http://docketpublic.energy.ca.gov/PublicDocuments/16-OIR-02/TN214830_20161215T184655_SB_350_LowIncome_Barriers_Study_Part_A__Commission_Final_Report.pdf.

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This study is an important resource identifying barriers that must be addressed in order

for low-income households to have equitable access to clean energy resources. Rules and

regulations seeking to ensure that clean energy programs benefit all customers should address

these barriers.

If you have any questions on this submittal, please contact Kanya Dorland atKanya.Dorland@cpuc.ca.gov or (415) 703-1374

Comments submitted by:

Laura Trolese, ltrolese@publicgeneratingpool.com, (360) 513-6465

Therese Hampton, thampton@publicgeneratingpool.com, (360) 852-7366

CAISO Board Vision Discussion Paper

Electricity 2030 – Trends and Tasks for the Coming Years

Public Generating Pool Comments November 20, 2017

Public Generating Pool (PGP) appreciates the opportunity to comment on the California ISO Board’s Vision Discussion Paper that identifies trends and suggested actions as California drives towards meeting its carbon emissions reduction goals. PGP represents ten consumer-owned utilities in Oregon and Washington that own more than 6,000 MW of generation, 96% of which is carbon-free.

Role of CAISO in Implementation of Vision

PGP appreciates the transparency the Vision Discussion Paper provides into the CAISO’s

thinking on the challenges and policy solutions facing California in meeting current policy goals

for 2030 and 2050. We understand the Vision Discussion Paper’s purpose to inspire discussion

on strategies and issues involved in decarbonizing and decentralizing California’s electric

service. This is a large task and will involve numerous California state agencies and

organizations that bear the responsibility of certain actions suggested to support movement

toward the outcomes outlined in the document’s Trends and Tasks.

The CAISO has many important functions as market operator, balancing authority, regional

transmission planner, etc., including providing feedback to policy makers about the system

requirements associated with different policy options. The broad nature of this document and

the numerous recommendations for policy, however, do not seem to fit the expected role of

the CAISO as an independent system operator. If there are future versions of this document, it

would be helpful for the CAISO to be more specific about its role relative to California

legislature and state agencies.

CAISO Role in Trends 2, 3, and 4

The Trends in the document provide a useful perspective of the future electricity sector

landscape within which all of us operate. The Trends are thoughtful and are very useful in

anticipating where there may be stress points or opportunities on the system. PGP believes it is

important for an independent system operator to objectively design and operate a market that

is non-discriminatory, achieves least-cost solutions, and assures reliable service to load.

Relative to this document, we believe that it is the role of the CAISO to ensure that their market

design and market rules are agile enough to send proper price signals, and it is the role of the

energy planning bodies and other entities to establish the energy policy priorities and

incentives to achieve the broader vision.

2

Chelan County PUD / Clark Public Utilities / Cowlitz County PUD / Eugene Water & Electric Board / Grant County PUD

Klickitat County PUD / Lewis County PUD / Pend Oreille County PUD / Snohomish County PUD / Tacoma Power

PGP finds Trends 2, 3 and portions of 4 to be the Trends that are directly relevant to CAISO’s

grid operations and provides comment on elements of those Trends.

Trend 2: Gas-fired generation declines significantly as the grid is modernized.

• PGP recommends a more technology neutral approach to the issue of financial viability of

resources that provide Essential Reliability Services. The current draft focuses on helping

gas-fired generators remain viable. Proper market design should appropriately

compensate resources based on resource capability and location such that they remain

financially viable, independent of resource type.

• PGP understands the intent behind “regional sharing” to assure efficient use of existing

capability across the West. To assure that any type of shared approach is reliable and

equitable, common definitions of resource adequacy and demonstration of adequacy are

required and could be noted as an important first step.

Trend 3: The system is shaped by the variable output of wind and solar resources.

• PGP finds the tasks under Trend 3 to be state policy oriented actions that we believe to be

outside the scope of the CAISO. However, the Guiding Questions are important for the

CAISO to address.

Trend 4: Demand becomes as important as supply in balancing the system.

• PGP finds the Tasks and Guiding Questions to fall into the category of state policy.

However, given the importance of the issue of evolving and changing demand, it would

seem appropriate that the CAISO offer key issues or questions they need to address or be

prepared for in operating the grid if these changes in demand occurred.

Independent Governance continues to be important in Regionalization

As Balancing Authority Areas and resource owners external to the CAISO, PGP takes specific interest in Trend 6: Regional Coordination Supports Efficient Grid Operations. We agree there may be benefits that can be gained with regionalization, however the Vision Discussion paper is explicitly focused on the benefits of regionalization to the state of California. For many years, the NW parties have indicated that independent governance will be an important issue in determining the approach to more formalized coordination. Future versions of this document or discussions of regionalization should highlight what is needed to assure benefits are realized by other states as well as California and highlight the actions the CAISO is taking or can expand to balance different regional policies and resources.

Near-term actions the CAISO can take to increase regional participation

While regionalization is a long-term endeavor, there are near-term market design options that can be explored by the CAISO that may better incent the use of existing resources in the West.

3

Chelan County PUD / Clark Public Utilities / Cowlitz County PUD / Eugene Water & Electric Board / Grant County PUD

Klickitat County PUD / Lewis County PUD / Pend Oreille County PUD / Snohomish County PUD / Tacoma Power

• Focus on market design that provides proper price formation, strong price signals for the capability that is needed on the system, and market rules that ensure reliable non-discriminatory access to resources.

• Clean, flexible hydroelectric resources of the Pacific Northwest (PNW) can provide immense benefits to the CAISO in reducing renewable curtailment and meeting flexible ramping needs. In addition to offering flexibility, PNW hydro can provide storage capability by taking energy during the middle of the day and providing energy during the morning and evening ramp periods. However, the CAISO would need to advance initiatives that provide appropriate compensation for opportunity costs and a market structure that considers the planning timelines for large PNW hydroelectric systems.

• CAISO, in coordination with the California Public Utilities Commission, would need to remove current barriers in the CAISO’s current flexible resource adequacy framework that prohibit external resources from participating.

Finally, PGP encourages the CAISO Board of Governors, leadership and stakeholder processes to find ways to hold public meetings in other states. California relies heavily on imports from the Desert Southwest and the Northwest to meet load and this Vision paper advances the idea of expanding the ISO into those areas. Additional time spent in these states could only be helpful in developing mutual understanding and working relationships that are necessary for continued coordination.

PGP appreciates the opportunity to comment on this very thoughtful and well-designed document. We look forward to continued coordination with the CAISO.

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Comments of Powerex Corp on Electricity 2030 Discussion Paper

I. Introduction

Powerex appreciates the opportunity to submit these comments on the discussion paper entitled Electricity 2030: Trends and Tasks for the Coming Years. The paper identifies eight specific trends shaping the electricity sector, and articulates eight tasks to support the ongoing transformation of the sector to achieve the state’s policy objectives.

California has been the preeminent environmental policy leader in the western United States. It has led the way with the nation’s most ambitious renewable portfolio standard, seeking to produce half of the state’s energy from renewable resources by 2030. California was also a pioneer in developing a US “cap

and trade” program for greenhouse gas (GHG) emissions, driving reductions in state GHG emissions

through a market-based framework.

The electricity sector has been a major focus of California’s environmental policy initiatives, reflecting the

sector’s importance as the second-largest emitter of GHGs in the state. The electricity sector has also accounted for the majority of the state’s reductions in GHG emissions, demonstrating the extent of the

transformation of the electricity grid, and the effectiveness of those changes in meeting the state’s

environmental objectives.

Over the past decade, California has achieved great success in increasing the use of renewable resources and reducing GHG emissions. California is now at a critical point in the transformation of its electricity grid. The initial approaches responsible for the state’s success cannot be scaled indefinitely, and signs of growing renewable integration challenges are already present. At the same time, California’s successes to date have led to setting more ambitious goals for the future, going beyond encouraging the expanded use of clean and renewable resources, to fundamentally seeking to transform the sector away from reliance on fossil resources and toward a low-carbon grid.

Electricity 2030 takes on the important challenge of articulating a vision for “what comes next” in the

transformation of California’s electricity sector. That longer-term vision appears to include the following key elements:

Continued expansion of renewable and non-emitting resources to meet California needs;

Support the orderly retirement of California fossil resources;

Maintain and strengthen grid reliability and resilience;

Reduce the long-term cost of energy; and

Harness the modernization, job creation and investment benefits of California’s energy transition.

There will be multiple steps needed to achieve these objectives, but one of the themes of Electricity 2030 is a focus on “regionalization.” Regionalization can take many forms, ranging from a voluntary real-time energy market, like the Energy Imbalance Market (EIM), to a formally-constituted multi-state Regional Transmission Organization. Regardless of the structure, all forms of regionalization entail closer coordination and electricity trade with neighboring power systems. Increased inter-regional trade can undeniably provide important economic and environmental benefits to California. Economic benefits include removing barriers to trade between adjacent systems, and using modern software and information systems to identify opportunities to serve customer load using the lowest cost resources available, and deliverable, over an expansive geographic area. Environmental and economic benefits include greater

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diversity of variations in load and in renewable output, which can reduce the capital investments needed to reliably balance and backstop the growing fleet of renewable resources.

At the same time, the pursuit of increased coordination and trade with neighboring systems must recognize that each state in the west has its own set of economic and environmental policies and objectives. In some cases, these policies may be aligned with those of California, but in other cases they clearly are not. The authors of Electricity 2030 express their deep respect for each state’s prerogative to

establish its own strategies. Powerex agrees that this is appropriate and necessary, but it is equally important to be fully cognizant of how increased trade with areas that pursue different policies can affect California’s ability to meet its own environmental objectives.

In these comments, Powerex reviews publicly available data and draws lessons from California’s trade

through the EIM over the past year, as a real-world indicator of the type of patterns that might be expected in the future from continued expansion of regional organized markets. The EIM data shows that increased inter-regional trade supports important elements of California’s environmental objectives—and should be a vital part of California’s future vision. But this data also shows that increased inter-regional trade, on its own, can also result in outcomes that may not be fully consistent with California’s policy

objectives. In Section IV, Powerex proposes specific measures that it believes will be valuable in supporting California’s transition to a lower-carbon grid. These measures include:

Establishing a “Clean RA” requirement to support California’s transition to relying on clean

resources to meet its capacity and flexibility needs;

Aggressively pursuing storage solutions, as these can simultaneously address California’s needs

for flexible capacity and for managing oversupply, and do so using non-emitting resources;

The need for forward commitment and procurement—in addition to expanding short-term markets—to more effectively unlock the flexible capacity and storage potential of northwest hydro utilities to provide flexible capacity and renewable integration services to California; and

Ensuring that short-term organized energy markets are consistent with California’s environmental

policies by accurately recognizing GHG emissions associated with serving California loads from out-of-state resources.

II. As California Renewable Growth Matures, New Challenges Emerge

The introduction and rapid growth of renewable resources has been highly effective at reducing output from California GHG-emitting resources, and can be viewed as the “first phase” of California’s energy

transition. But the growth of renewable resource capacity has also exposed some of the challenges to the continued expansion of California’s renewable fleet. Overcoming those challenges will be necessary

in order to achieve further reductions to California GHG emissions, and will help define the “second

phase” of California’s energy transition.

A. The “First Phase” of California’s Energy Transition is Largely Complete

Perhaps the single most influential driver of California’s electricity transformation has been California’s

renewable portfolio standard. The renewable portfolio standard initially required 20% of California’s electricity to be produced from renewable resources by 2010; the standard was increased to 33% by 2020, and increased again to 50% by 2030. CAISO grid-scale renewable resources now total over

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21,000 MW in installed capacity, of which approximately 11,000 MW is solar.1 This growth in renewable resources has provided broad environmental and economic benefits to California, but it has also exposed some of the limitations of the pre-existing California grid and resource mix in integrating renewable resources. Powerex discusses its understanding of two of these key limitations below.

1. Renewable Oversupply - Limits to the California Grid’s Ability to Use Renewable Energy to

Reduce California’s GHG Emissions in a Growing Number of Hours

When renewable resources begin to be added to a power grid that consists primarily of fossil resources, these renewable resources are virtually certain to reduce GHG emissions. This is because, at any given time of the day or night, it is highly likely that flexible fossil resources will be producing electricity. Consequently, it is highly likely that flexible fossil resources will be able to reduce output by the same amount that is being produced from the renewable resources. In this manner, renewable resources are initially well-suited to displace GHG-emitting fossil resources whenever the renewable resources produce energy. But as the output from renewable resources expands, it encounters operational limitations on the ability of the grid to displace fossil resource production, in order to absorb its variable output in all hours.

Figure 1 below shows the electricity demand for the CAISO area for a day in April 2017.2 The level of demand—which generally determines the required amount of generation—is shown in dark blue, and varied from a low of approximately 19,000 MW overnight to a high of approximately 27,000 MW during the evening peak. During the middle of the day, demand was generally constant at approximately 24,000 MW.

Figure 1. CAISO Demand and Net Demand for April 3, 2017

Source: Hourly average value from CAISO production and curtailments data. Available at:

http://www.caiso.com/informed/Pages/ManagingOversupply.aspx

1 California ISO Monthly Stats – October 2017 available at www.caiso.com/Documents/October2017MonthlyStats.pdf 2 All figures in these comments are derived from public data sources, and are based on Powerex’s understanding of the underlying data. Powerex would appreciate any validation or clarification of the information presented.

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Production from solar and wind resources on this same day is shown in Figure 2 below. The combined result of the level of customer demand and the level of renewable production is the “net load” that must

be produced from other resources, including from fossil generation. The resulting net load is shown as the green line in Figure 1, above.

Figure 2. CAISO Solar and Wind Production for April 3, 2017

Source: Hourly average value from CAISO historical production and curtailments data. Available at:

http://www.caiso.com/informed/Pages/ManagingOversupply.aspx

The above charts show that, even though the total need for electricity was close to 24,000 MW in the middle of the day, the large quantity of energy produced by solar and wind resources sharply reduced the need for energy from other types of generating resources to 12,000 MW or less. Low levels of net load can present an operational challenge, however, as most fossil resources have a minimum level of output below which they cannot be operated in a stable manner. Once all fossil resources have been backed down to their minimum operating level, any further reductions in output require a unit to be turned off completely. And once a unit is turned off, it may be required to remain off for several hours before being re-started. In other words, if a fossil unit will be required to meet customer needs later in the day, then it must often remain online and producing at least at its minimum output level in the hours prior to when it is needed. The California grid also requires a minimum level of production from fossil resources for a variety of local reliability reasons. In a 2016 stakeholder process document, CAISO estimated that it expected its minimum generation levels to be approximately 12,000 to 14,000 MW during the midday hours.3

3 CAISO Supplemental Issue Paper on Flexible Resource Adequacy Criteria and Must Offer Obligation – Phase 2, November 8, 2016, at 10. Available at: http://www.caiso.com/Documents/SupplementalIssuePaper-FlexibleResourceAdequacyCriteria-MustOfferObligationPhase2.pdf

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This “minimum generation” level effectively limits the amount of renewable energy (and imports) that can be used to displace production from other resources within the CAISO area.4 For example, if demand is 20,000 MW and the minimum generation level for the system is 14,000 MW, then the maximum amount of renewable generation that can be used to displace other resources is 6,000 MW (i.e., the amount of demand above the system minimum generation level).

The significance and impact of minimum generation levels on the ability of the CAISO grid to absorb energy from renewable resources is confirmed by data from the EIM for the twelve months ending September 30, 2017. Figure 3, below, shows the average value of net hourly CAISO EIM transfers in the Fifteen-Minute Market, plotted at different levels of CAISO net load experienced throughout the year.

Figure 3. CAISO EIM Imports and Exports vs. CAISO Net Load, October 1, 2016 - September 30, 2017

Sources: Net load data available from http://www.caiso.com/informed/Pages/ManagingOversupply.aspx. Data on

EIM transfers in Fifteen-Minute Market available from CAISO OASIS. All data was aggregated to hourly level.

The chart shows that when CAISO net load is approximately 20,000 MW, EIM imports and exports are approximately equal in average size when they occur.5 But as CAISO net load falls, EIM imports decline and eventually disappear altogether, while EIM exports rise sharply. In other words, once CAISO net load reaches approximately 14,000 MW – 16,000 MW, it appears that the CAISO grid may frequently be unable to make further reductions to the output of dispatchable resources. Consequently, any additional energy from renewable resources cannot reduce California GHG emissions during such hours, and

4 Additionally, a fossil resource operating at or near its minimum stable output level typically also operates at a higher GHG emission rate. 5 At net load of approximately 20,000 MW, CAISO EIM imports occurred more frequently than CAISO EIM exports. At net load of approximately 18,000 MW, CAISO EIM imports occurred with almost the same frequency as CAISO EIM exports, but the quantity of the latter was larger, on average. Whichever metric is used, a net load of approximately 18,000 MW to 20,000 MW appears to correspond to the CAISO BAA’s transition from EIM exports to EIM imports.

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instead is likely to be exported to serve load in other states. If additional exports to other systems are not possible, then the output of the renewable resource may need to be curtailed.

2. Flexible Capacity - Emerging Flexibility Challenges to Balance Renewable Output and Load

A separate operational challenge related to the growth of renewable resources on the CAISO grid is keeping up with the speed and magnitude of changes in output from renewable resources. In some cases, the rapid changes are predictable—such as when the sun rises or sets. But in other cases, renewable output can change rapidly with little notice—such as when wind changes speed or direction, or when clouds obscure the sun. To safely and reliably operate the grid, the CAISO must have access to flexible resources that can move up or down quickly, with a significant portion able to respond on short notice.

When there are relatively low levels of renewable resources on a system, this is generally not a problem. Power systems that are planned to meet peak load and variations in load often have sufficient latent flexibility to follow variations in the output of some amount of renewable resources. It is clear, however, that the quantity of renewable resources in California has now crossed a threshold, requiring dedicated measures to attempt to ensure that sufficient flexible resources are procured and available to reliably operate the system in real-time.

The multiple steps taken by CAISO and the CPUC over the past several years are a testament to the growing flexibility challenge posed by higher levels of renewable resources on the CAISO grid. In 2011, for example, CAISO enhanced its real-time market to deliberately set aside flexible capacity to be available to meet unanticipated needs; this approach was enhanced in 2016 by creating a formal real-time flexible ramping product. CAISO is currently exploring enhancements to its day-ahead market to better recognize the need to maintain flexible capacity on stand-by. The CPUC in 2015 expanded its Resource Adequacy requirements to include a requirement for flexible capacity; improvements to that program are currently under consideration.

B. Entering the “Second Phase” of California’s Energy Transition

The foregoing indicates that the “first phase” of California’s energy transition, consisting primarily of increased levels of renewable resources, has been highly successful. Indeed, it appears to have largely progressed to the full extent that could be accommodated by the existing mix of resources in the California grid. This is particularly true for solar resources. With approximately 11,000 MW of grid-scale solar, and over 5,000 MW of behind-the-meter solar, the grid operated by the CAISO appears to be reaching a critical threshold in its ability to integrate solar resources into the current resource mix. Specifically, as additional solar resources are now added, a growing proportion of this additional solar output will need to be exported and/or curtailed, and additional flexible resources will also need to be added to respond to the evening ramp-down of solar output each day.

The success of the “first phase” thus also highlights an important question: how can California achieve further reductions to California’s GHG emissions and further reduce its reliance on fossil resources? Three challenges in particular characterize this “second phase” transition period.

As an initial matter, simply adding more of the same type of renewable resources already in use, on its own, is unlikely to achieve these objectives. As discussed above, in a large and growing number of hours, the California grid is already absorbing as much renewable output as it can, and even the existing level of renewable resources is associated with operational challenges. The first challenge of the

“second phase” is therefore to identify ways to continue to increase the amount of renewable

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energy that serves California load and reduces California GHG emissions, in light of California’s

growing oversupply and flexible capacity challenges.

The “second phase” will also seek to achieve a more fundamental transition away from fossil resources, through the orderly retirement of portions of California’s fossil-fueled generating capacity. This must be achieved without reducing reliability or grid resilience, meaning that other resources will need to be identified and secured to be available to meet California’s electricity needs. But it would be difficult to see a large environmental benefit of retiring an in-state fossil resource if this simply leads to greater reliance on out-of-state fossil resources, which may well result in more total GHG emissions. The second

challenge will therefore be to ensure that the orderly retirement of in-state fossil resources is

accompanied by a shift to a greater reliance on clean resources, not on out-of-state fossil

resources.

The steps necessary in this “second phase” should also be consistent with other policy objectives

contained in Electricity 2030. In particular, the strategies pursued in this “second phase” will deliver the greatest benefit to California by encouraging investment and resource development in a manner that also provides economic stimulus and employment. California ratepayers also will benefit from strategies that seek to achieve these objectives at least cost. The third challenge is continuing to pursue California’s

environmental policy objectives in a manner that maximizes the economic benefits to California

and its ratepayers.

III. The Benefits and Limitations of Regionalization for California’s Energy Transition

A significant focus in recent years, and in Electricity 2030, is the potential to expand organized electricity markets to include power systems outside of California. In particular, Electricity 2030 cites the benefits of regional coordination, including the ability to share resources, reduce costs, and “facilitate access to the

huge supply of clean resources across the western U.S.”6

Electricity 2030 also recognizes that “regionalization” is a general concept that can take many different

forms. The clearest recent example of regionalization has been the western EIM, in which six balancing authority areas in addition to CAISO already participate, with additional participants set to join in each of the next three years. The EIM is a voluntary energy-only market, and involves no consolidation or change in the core reliability, transmission, or integrated resource planning functions of the participating entities. At the other end of the spectrum would be the creation of a formal, comprehensive multi-state RTO, which would consolidate balancing authorities, transmission service, and resource planning.

With respect to the key objectives of reducing California GHG emissions, and doing so at least cost to ratepayers, there can be little doubt that improved inter-regional trade offers important benefits. By combining geographic areas that experience peak demand at different times, for instance, the total generating capacity needed to meet the needs of the larger footprint can be less than the capacity needed if each system meets its needs on its own. Similarly, by combining variations in renewable resource output across a wider geographic area, a regional market can reduce the flexible capacity needed to integrate renewable resources. Both of these “diversity benefits” can increase the quantity of renewable resources that can be integrated into the grid using existing resources, and reduce the need for new investment to integrate additional renewable resources or to meet load growth.

6 Electricity 2030 at 18.

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In addition to the environmental and economic benefits associated with diversification of peak load and of renewable resource output, there are also opportunities to increase the efficiency of trade between systems, particularly in shorter term transactions. Trade has occurred for decades in the west through bilateral transactions, with physical delivery arranged under the contract-path transmission service framework. While bilateral trading is robust and active, especially in forward and day-ahead standard products, trading in carefully designed organized markets has the potential to achieve additional efficiencies through three key features. First, organized markets automate the process of identifying opportunities for efficient transactions. Second, most organized markets rely on a model of physical flows on the transmission grid to ensure the grid is operated within applicable limits. And third, organized markets usually eliminate so-called “hurdle rates” associated with transmission service. While these features could be pursued outside of an organized market—and some already exist in the bilateral market framework—the implementation of an organized market is an established way to leverage all three attributes in pursuit of more efficient inter-regional trade.

The benefits from increased inter-regional coordination and trade are evident in the performance of the EIM. The EIM’s expanded geographic footprint enables participants to realize benefits from diversification of variation in load and in renewable resource output, requiring fewer resources to be set aside for intra-hour balancing purposes, resulting in both economic and environmental benefits. The economic benefits of additional sub-hourly trading activity are also evident in the EIM, where the elimination of pancaked transmission charges and the use of centralized economic dispatch tools allow the lowest- cost deliverable resources to be used to meet energy needs.

A review of EIM data for the period October 1, 2016 through September 30, 2017 highlights the patterns of sub-hourly trading that have been enabled by extending organized markets beyond California. Figure 4, below, shows the total quantity of EIM exports out of California, as well as the total quantity of EIM imports into California, over the one-year period, grouped by hour of the day.7

Figure 4. Total CAISO EIM Exports and Imports by Hour of Day, October 1, 2016 - September 30, 2017

Source: CAISO OASIS.

7 “Exports” refers to the sum of EIM transfers out of the CAISO BAA during all intervals in which the CAISO BAA was a net exporter in the EIM. “Imports” refers to the sum of EIM transfers into the CAISO BAA during all intervals in which the CAISO BAA was a net importer in the EIM. The data discussed in this section refers to the EIM-related results from the Real Time Pre Dispatch (RTPD) process, also referred to as the 15-minute market.

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The above chart reveals that the expansion of sub-hourly organized markets has resulted in two key types of outcomes for California. First, during the mid-day hours, California engages in substantial sub-hourly exports through the EIM. Second, during the early morning and nighttime hours, California engages in substantial sub-hourly imports through the EIM.

The EIM exports during the mid-day hours correspond to the hours of California solar production; the so-called “belly of the duck.” These EIM exports occur at a volume-weighted price of approximately $6/MWh,8 implying that it is solar energy that is being exported (as opposed to, say, natural gas production, which would typically be uneconomic to sell at that price). The EIM, in other words, has been highly effective at facilitating exports of California renewable energy production (primarily from solar resources) that could not be used to meet California load. This is a clear environmental benefit, since renewable production would likely have been curtailed without these exports. Moreover, the EIM is enabling California renewable resources to be exported to serve load in other states, thereby displacing the out-of-state resources that otherwise would have been used for that purpose. During the mid-day intervals that the CAISO BAA was a net exporter in the EIM, the BAAs with the greatest net imports were NV Energy and Arizona Public Service Company, as shown below in Figure 5.

Figure 5. EIM Imports During "Belly of the Duck" Intervals of CAISO EIM Exports, by Entity

Sources: EIM transfers and prices in Fifteen-Minute Market from CAISO OASIS. Resource mix from public resource

planning documents for each entity.

Given the resource mix of those entities, shown in the pie charts in Figure 5, it is highly likely that the EIM imports of California renewable energy displaced production from GHG-emitting resources. Thus, not only has the EIM reduced the need to curtail production from California renewable resources, but the sub-hourly exports arranged through the EIM very likely have reduced GHG emissions from resources outside of California.

8 This refers to the average LMP for SP15 in the RTPD during intervals in which the CAISO BAA is a net exporter in the EIM, weighted by the volume of those net exports.

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During the early morning and the evening hours—that is, before 9 a.m. and after 5 p.m.—California’s

trade through the EIM looks sharply different. Rather than being characterized by EIM exports, the CAISO BAA becomes a recipient of sub-hourly EIM imports from the other areas participating in that market. In fact, the total quantity of EIM imports into the CAISO BAA is approximately 1.5 times the total quantity of EIM exports out of the CAISO BAA. CAISO’s EIM imports occur at a volume-weighted price of approximately $44/MWh, are most pronounced during the morning peak and the evening peak, and help serve California load at a lower price than the price of using additional in-state resources. That is, the EIM has expanded opportunities for sub-hourly imports that reduce the cost of meeting California’s

needs, providing important economic benefits. During the early morning and evening hours that the CAISO BAA was a net importer in the EIM, the BAAs with the largest net exports were PacifiCorp East and Arizona Public Service Company, as shown in Figure 6, below.

Figure 6. EIM Exports During Early Morning and Evening Intervals of CAISO EIM Imports, by Entity

Sources: EIM transfers and prices in Fifteen-Minute Market from CAISO OASIS. Resource mix from public resource

planning documents for each entity.

Powerex believes that the activity observed in the EIM provides a strong indication of some of the types of potential benefits that can be realized through organized markets. While the above data illustrates some of the environmental and economic benefits of the EIM, it is also important to recognize what these short-term markets do not accomplish. In particular, it should be recognized that there are a number of reasons why a regional organized electricity market will not, on its own, resolve the key challenges identified in the previous section.

First, a regional organized market, on its own, will not enable greater amounts of California renewable resources to serve California load and reduce the output from California’s fossil resources. As seen in the EIM data above, an organized market can help identify opportunities for California renewable resources to be exported to serve load in other states, and to reduce GHG emissions in other states. And while this outcome is clearly preferable to curtailing the output of those renewable resources, it falls short of the goal of investing in renewable resources to meet a greater portion of California’s energy needs, or to further reduce California’s GHG emissions.

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In order to achieve these goals, California does not need a way to dispose of renewable energy that it cannot use—which is what EIM exports effectively represent. Instead, California would benefit from identifying avenues to utilize that surplus renewable energy in a way that makes additional clean energy available to be returned to the California grid in hours of the day when it can be used to meet California load and thus to reduce production from California GHG-emitting resources. The EIM, or any organized spot market, is simply not designed, on its own, to provide such a battery-like service. However, as discussed later in Section IV, an organized market, such as the EIM, can be a key enabling framework that can help facilitate the efficient scheduling of energy deliveries under longer-term contractual arrangements for battery-like renewable integration services.

Second, a regional organized market, on its own, will not help California shift away from a reliance on fossil resources and toward a greater reliance on clean resources. During the early morning and evening hours that the CAISO BAA was a net importer in the EIM, the BAAs with the largest net exports were PacifiCorp East and Arizona Public Service Company. Both the volume-weighted price of $44/MWh and the resource mix in these areas strongly suggests that EIM imports into California were supported by increased production from fossil resources.9 Put succinctly, the data indicates that California’s sub-hourly imports through the EIM likely represent a substitution of in-state fossil resource production with lower-price out-of-state fossil resource production. This implies economic benefits, but does not necessarily reduce (and may actually increase) the GHG emissions associated with serving California load during these hours.

Moreover, there is reason to believe that sub-hourly EIM imports into California are likely to continue to be supported by additional production from out-of-state fossil resources, even as the EIM expands to include greater participation supported by non-emitting hydro resources. The northwest is home to several large hydro systems with substantial storage, but it is critical to understand that much of the energy, flexibility, and capacity of these systems is typically committed in advance. Large hydro systems are generally planned on a forward basis taking into consideration numerous factors, including the potential range of future inflows, domestic load, environmental and operational constraints on the system, and contractual commitments with other entities that are also entered into on a forward basis. Consequently, without a forward commitment, there may be very limited residual capability available on a day-ahead or real-time basis to support transactions with California.10

Expanded inter-regional trade through well-designed organized markets can be expected to make more efficient use of the resources that are made available in that market. But it will not, on its own, fundamentally alter the forward planning and optimization of coordinated hydro systems in the northwest such that a significantly larger portion of hydro capability can be accessed through those markets. As discussed later in Section IV, ensuring that the capacity, flexibility and storage attributes of northwest hydro systems are available to assist California in its transition to a low-carbon grid requires forward procurement commitments that support changes to the way these hydro systems are planned and operated.

9 While these areas have a relatively small amount of renewable resources, these resources likely would have produced energy anyway, even without the exports through the EIM. The resources most likely to be available to be economically dispatched in the EIM are the coal and natural gas units owned by PacifiCorp and Arizona Public Service. 10 See, e.g., Bonneville Power Administration presentation in CAISO workshop on intertie liquidity, October 6, 2015, at 7 (“~90% of BPA Power Services revenues and FCRPS Flexibility is committed prior to Trading Floor transactions.”) Available at: http://www.caiso.com/Documents/BPAPresentation_Import-ExportLiquidity_15-MinuteMarket_Workshop_Oct6_2015.pdf

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Additionally, inter-regional organized markets (including the current EIM) encompass participation by a mix of different resources, located in jurisdictions with a range of different approaches toward GHG emissions. The same highly-effective economic dispatch software and information systems responsible for achieving economic benefits from electricity trade and unlocking load and renewable resource diversity benefits also have the potential to create unintended consequences by exacerbating differences in the treatment of GHG emissions. The core objective of market optimization software is to reduce the cost of meeting load (subject to a variety of constraints), and advanced algorithms are employed to identify all possible opportunities to reduce those costs. To the extent the cost of using a resource to serve California load properly accounts for any additional GHG emissions in its dispatch decisions, then the cost savings indeed represent genuine economic benefits. But if the GHG emissions associated with using out-of-state resources to meet California load are not properly recognized, then environmental benefits may not be realized, the trade may not truly be efficient, and the full costs of meeting California load may not be reduced.

This poses what Powerex considers to be the fourth key challenge in California’s energy transition:

Ensuring that expanded organized markets provide genuine efficiency gains by properly

recognizing GHG emissions associated with serving California load from out-of-state resources. By the same token, a regional organized market must not force California’s GHG policies on other

jurisdictions. That is, while California has sought to ensure its electricity prices reflect the cost of GHG emissions, other states may decide not to take this approach, and may resist participating in a regional organized market that requires them to accept market prices that include GHG-related costs. More generally, a regional organized market should be designed to accommodate a variety of different GHG-related policies, ensuring those policies are properly applied in the relevant locations.

Powerex reiterates its belief that increased coordination and electricity trade between California and neighboring systems—that is, “regionalization”—can provide substantial economic and environmental benefits. Data from the EIM provides insight into some of the specific benefits already being realized through greater hourly and sub-hourly trade. But meeting California’s environmental policy goals will

require more than just increased opportunities to export or import energy on a day-ahead or real-time basis; it will require specific types of resources to be committed ahead of time to meet California’s needs,

whether to integrate additional renewable resources or to be available to meet load as California’s fossil resources are retired. The expansion of organized markets therefore needs to be pursued as one part of a broader set of strategies, as discussed in the next section.

IV. Four Potential Strategies to Support California’s Energy Transition

This section outlines measures that Powerex believes can help address the specific challenges identified in the prior sections.

A. Reduced Reliance on Fossil Resources Requires Increased Commitment of Clean Resources

Powerex believes that California’s energy transition is likely to require the procurement of substantial

amounts of flexible capacity. This is the result of two factors: the need for flexible capacity to integrate additional renewable resources to meet the state’s 2030 RPS objective of 50%; and the need to replace existing flexible capacity provided by in-state fossil resources that will retire. Procuring the necessary flexible capacity is currently addressed through California’s resource adequacy (RA) and flexible resource adequacy (Flexible RA) programs, as well as through its integrated resource planning and procurement programs. However, the current RA and Flexible RA programs do not include any requirements

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associated with California’s environmental policy objectives. That is, RA and Flexible RA capacity

requirements are currently permitted to be satisfied without regard to the type of resource (i.e., fossil resources as opposed to non-emitting resources). Given this latitude, Powerex believes that the growing need for flexible capacity is likely to be met, under the current design of the RA and Flexible RA programs, either by building new fossil resources within California, or by contracting with fossil resources located outside of California. Powerex also expects that the resources that receive additional compensation under the RA and Flexible RA programs to remain operational and to be placed on stand-by (as a result of the “must offer” commitment associated with the RA and Flex RA programs) are highly likely to be the physical resources that actually produce energy to serve loads in California. In other words, procuring flexible capacity from fossil resources should be expected to lead to the production of electricity—and GHG emissions—from fossil resources. If, instead, California seeks to increasingly rely upon and utilize non-emitting resources to serve California load, then it will be important to take steps to ensure that RA and Flexible RA are increasingly procured from non-emitting resources.

Powerex believes that defining a portion of RA and Flexible RA requirements that is procured from clean resources will be both helpful and necessary to support California’s transition toward greater reliance on

clean energy resources. “Clean RA” and “Clean Flexible RA” could be provided by new flexible resources such as in-state pumped storage projects and battery storage facilities, and also by existing in-state hydro resources and by the storage hydro systems that exist in the northwest. Powerex anticipates that procuring Clean RA or Clean Flexible RA from both new non-emitting resources inside California and from existing external storage hydro systems will generally be more expensive options than procuring conventional (i.e., non-“Clean”) RA and Flexible RA products from external, existing fossil resources. This is due to the additional capital investments associated with new flexible resources and to the forward planning and hydro system efficiency considerations associated with positioning external hydro systems to provide capacity, flexibility and storage capabilities to California, as discussed more fully in Section IV.D, below. Hence, Powerex believes that Clean RA and Clean Flexible RA requirements will be necessary in order for RA and Flexible RA to be increasingly procured from clean resources.

B. Renewable Integration Through Storage and Battery-Like Service Arrangements

The above recommendation seeks to address the growing need for flexible capacity through Clean RA and Flexible RA requirements. But this alone will not address the oversupply challenge associated with integrating additional renewable resources. The specific resource type that can best address both California’s growing need for flexible capacity as well as its growing need to manage renewable oversupply is clean storage. A storage resource can “consume” surplus California renewable production

during the midday hours, enabling it to return clean energy to the California grid at a different point in time when the energy can be used to reduce California GHG emissions. This approach appears preferable to the two most likely alternatives to addressing renewable oversupply. The first alternative is to continue to build solar resources but export the associated surplus energy or curtail the output of these resources altogether. Achieving reductions to California GHG emissions and meeting the state’s 50% renewable portfolio standard through more solar additions will likely require the “overbuilding” of solar capacity, thereby increasing the cost to ratepayers. A second alternative is to reduce the future buildout of in-state solar resources, and instead purchase additional out-of-state renewable resources that produce most of their output in the hours that imports into California can be used to further back down fossil generation in the state. However, developing out-of-state renewable resources is likely to be more expensive, take longer, and be subject to greater uncertainty than developing in-state solar resources, due primarily to the need to also build new interstate transmission facilities to deliver the energy to California. Developing out-of-state renewable resources is also likely to provide fewer benefits to California’s economy. In contrast to these two alternatives, developing new in-state storage resources to manage renewable

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oversupply enables California to continue to build cost-effective solar resources in California, avoids the need to “overbuild” solar resources, avoids the need to export surplus solar power at low prices to California’s neighbors, and instead permits solar energy to be produced, stored, and returned to the grid

during hours when it can be used to serve California load and reduce California GHG emissions.

Storage resources also provide flexible capacity, since the timing of when these resources are used to receive surplus energy or to deliver energy to the grid can be directly controlled. Storage resources provide not only capacity that can be relied upon to be available when needed, but can also provide some of the fastest-responding resources on the grid, as large changes in output can be achieved very quickly and with minimum lead time.

Due to the ability of storage resources to simultaneously address both the need for flexible capacity and the need to manage oversupply, Powerex views storage solutions as perhaps the most desirable type of resource for supporting California’s energy transition. Powerex recognizes, however, that the amount of storage resources that would ideally be added to the California grid likely poses significant challenges due to both cost and lead time. There are currently a limited number of utility-scale storage technologies—primarily pumped storage hydro and battery storage facilities. Pumped storage projects require suitable sites, which are limited, and generally have long lead times. Utility-scale battery technology is still at an early stage, with costs that are currently relatively high but that are expected to decline substantially over the next decade. It may therefore be prudent for California to undertake investments in storage projects in phases; with initial levels sufficient to accelerate technological and cost improvements while reserving some investments to be able to capitalize on future lower costs and more advanced technology.

The foregoing suggests that, while storage solutions appear to be an ideal fit to meet California’s needs,

meeting all of those needs in the near term by building new storage facilities is likely to be either infeasible, cost-prohibitive, or both. The temporary gap between the storage solutions that the California grid will need and the pace at which new cost-effective storage resources can be built creates an opportunity for increased coordination and trade with northwest hydro utilities. These utilities may be able to plan and operate their storage hydro systems in a manner that allows them to provide battery-like services to California. An external storage hydro system can be planned ahead of time to be able to receive energy from California during hours of renewable energy surplus, much like a battery storage facility. The energy-limited nature of storage hydro means that energy received from California can directly increase the energy that is available from the hydro system. This energy can then be returned to California during other hours, when it can be used to serve California load and reduce the output from GHG-emitting resources in California. An arrangement for battery-like services from northwest storage hydro utilities can therefore provide both flexible capacity services and oversupply management services to California. And since such arrangements would utilize northwest hydro resources that exist today, the lead time necessary to put such an arrangement in place could be very short. Powerex expects that the ability of northwest hydro systems to provide battery-like services will decline over time, as the underlying system capability will increasingly be needed to meet the needs of native load customers in the applicable service territory where these resources exist. But given the project rates of demand growth in the region, this still provides a window for battery-like services to be used to support California’s energy transition

while the costs and performance of dedicated in-state storage resources improve.

C. Unlocking the Flexible Capacity and Storage Potential of Northwest Hydro Utilities

Northwest hydro resources are mentioned in the prior sections as a potential part of ensuring California has access to sufficient flexible capacity as well as for managing oversupply. The potential to make greater use of existing northwest hydro resources is also recognized in Electricity 2030, as well as in

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various studies regarding how California might benefit from greater inter-regional coordination and trade. Some specific, and unique, features of northwest hydro storage systems can inform the types of arrangements that will be most effective in enabling these resources to support California’s energy

transition. In particular, large storage hydro systems are generally planned well in advance of the day-ahead and real-time timeframes of organized markets. That is, the amount of hydro system capability that is accessible through voluntary participation in day-ahead and real-time markets is simply the residual capacity remaining as a result of the planning and operational decisions made farther in advance. In order to substantially increase the capacity, flexibility, and energy that can be accessed through day-ahead and real-time markets, large hydro systems will need to be deliberately planned in advance to achieve this result.

The forward planning of hydro systems has two important implications for finding ways to unlock the flexible capacity and storage capabilities of existing northwest hydro resources. First, the energy, flexible capacity, or battery-like services will need to be procured in advance in order to be incorporated into the forward hydro system planning process. Powerex believes that forward contracting of at least a year in advance will be most effective in terms of unlocking hydro system capability. Forward contracting on at least this timeframe would also appear to be needed to ensure that California’s future needs will be met,

and hence to enable California to defer or avoid capital investments that would otherwise be required.

Second, the changes to forward hydro planning decision necessary to provide the committed energy, flexible capacity or battery-like services will likely cause the hydro utility to incur significant costs in terms of foregoing more efficient operation of the system and foregoing alternative forward commercial transactions. Powerex believes that the compensation necessary to make such forward commitments mutually beneficial is likely to exceed the cost of similar types of arrangements with fossil resources. However, since such arrangements leverage existing large-scale investments, Powerex also anticipates that long-term forward contracts with northwest hydro utilities will generally be less expensive than obtaining similar services from new clean storage resources.

Another important feature of northwest hydro systems is that each system is differently situated. Some systems may only be able to provide flexible capacity a few months of the year, whereas other systems may currently be able to provide flexible capacity year-round. Still other systems may be able to provide both flexible capacity and battery-like services to manage California oversupply. Given these diverse circumstances, Powerex believes it will be important for California to design is RA and Flexible RA programs—as well as any new programs related to battery-like services—in a way that enables all hydro utilities to provide valuable services to support California’s continued transition to a low-carbon grid.

D. Ensuring the Benefits of Expanded Inter-regional Trade are Consistent with California’s

Environmental Policies and GHG Program

Powerex believes that properly designed organized markets can provide significant economic and environmental benefits to California, particularly for shorter-term transactions. In addition to the stand-alone benefits of organized markets, regional organized markets can also be an enabling mechanism for long-term arrangements for capacity and battery-like services with resources located outside of California. For example, once a resource’s availability is secured through forward arrangements, its efficient short-term utilization and dispatch can be enabled by participation in the EIM.

However, the power of organized markets to realize efficiency benefits also brings with it the potential for unintended consequences. The elimination of hurdle rates and other “frictions” to trade between

California and other western systems can lead to large quantities of trade, even in response to relatively limited differences in the price of energy at different locations. As organized markets continue to

11/20/2017 16

expand— and especially if they eventually extend to the day-ahead timeframe, in which volumes are substantially larger than in real-time—it becomes absolutely critical to ensure that organized markets do not have the unintended effect of undermining California’s environmental policies. If serving California

load from imported energy results in additional output from an out-of-state fossil resource, it is imperative that the market optimization software accurately recognizes the additional GHG emissions associated with serving California load in that manner. This is a challenging problem—as evidenced by the extensive efforts of CAISO and CARB to improve the accuracy of GHG recognition in the existing EIM software—but one of great importance if organized markets are truly to support California’s energy

transition.

DATE: November 20, 2017

TO: Tom Cuccio, Sr. Stakeholder Engagement & Policy Specialist/CAISO

CC: California ISO (CAISO), Board of Governors and Management Richard Maullin, Chair Ashutosh Bhagwat Mark Ferron Angelina Galiteva David Olsen

FROM: Shirley F. Rivera, Principal/Resource Catalysts

SUBJECT: Comments on the California ISO (CAISO) Discussion Paper – Electricity 2030 – Trends and Tasks for the Coming Years

As one of the many stakeholders who attended the October Stakeholder Symposium, thank you for the opportunity to comment on the CAISO’s discussion paper, Electricity 2030 – Trends and Tasks for the Coming Years (October 2017). Below I provide:

• Understanding of Discussion Paper • R|CAT Comments • Attachment • Background

Please do not hesitate to contact me at sfr@r-cat.com for questions, clarifications, or comments. Best regards. UNDERSTANDING OF DISCUSSION PAPER CAISO is accepting comments on its draft vision (aka discussion paper) as part of its ongoing strategic planning process. Eight trends are described through a series of bullets. For each trend, listed are foundational assumptions, a task with prospective activities, and guiding questions. As stated in the discussion paper introduction (excerpts below) –

“About this document: California is setting its course for 2030 and 2050. Meeting current policy goals requires significant changes in regulatory policies and commercial practices. Meeting longer-term goals will require even more policy innovation and infrastructure investment—for example, to accelerate EV deployment, build public acceptance of electrifying building energy use, and create public support for development of a clean energy economy. Without a shared understanding of the challenges involved, there is real risk that investment can be misdirected, assets

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stranded, and major opportunities frustrated or lost.

We have identified eight trends likely to shape the transformation of the electric sector. With each trend, we also identified actions or tasks likely to help support movement toward the outcomes outlined in the trends. It is important to note that many of the actions suggested herein are not within the purview of the ISO. In those cases where lead authority lies with a state agency or other organization, we will support or otherwise collaborate with the appropriate entities to help find the best ways forward. The guiding questions accompanying each trend are intended to begin dialog about both the nature of the challenges and the policy solutions that California faces.

. . .

This paper is intended to help focus discussion on both technical and policy issues involved in decarbonizing and decentralizing electric service. The ISO cannot, nor should not, lead this discussion alone. Electricity represents just one dimension of the transition to a clean energy economy. The Legislature, Governor, California Public Utilities Commission, California Energy Commission, California Air Resources Board, other agencies, industry, neighboring states and the public all have critical interests and perspectives for shaping this evolution. The ISO will engage with all these interests as we seek to fulfill our mission of operating the grid to ensure reliable electric service.

We look forward to working with policymakers, agencies and stakeholders to further develop a clear and broadly-supported view of a clean energy future—in California and across the region. The health and prosperity of western states are intertwined, and all of us stand to benefit from closer coordination and the sharing of resources.

R|CAT COMMENTS The following represent my comments and perspectives as Principal of Resource Catalysts (R|CAT) – a stakeholder – who has served the environmental and energy field since 1987 ( ~30 years), providing service in the federal government, with energy and environmental consulting firms, in the utility industry (IOU), and as an independent business owner. R|CAT’s perspective is primarily from understanding and navigating the complex air quality regulatory, compliance management, and policy landscape, as it intersects with energy and community involvement. Given R|CAT’s areas of expertise and interests, R|CAT comments are provided on one page for select CAISO trends as described via:

• foundational basis and assumptions (e.g., the first set of bullets), • task activities, and/or • guiding questions.

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In other words, comments are not provided on the totality of a trend but rather on individual items.

TREND DESCRIPTION COMMENTS? 1 Electricity is used far more efficiently. Yes 2 Gas-fired generation declines significantly as the grid is

modernized. Yes

3 The system is shaped by the variable output of wind and solar resources.

No

4 Demand becomes as important as supply in balancing the system. No 5 Electric service is increasingly decentralized. No 6 The grid is coordinated regionally. No 7 Transportation and building energy use is integrated with electric

service. No

8 Transition to a Clean Energy Economy creates new industries and jobs, benefitting all citizens statewide.

No

It should be noted that, as part of providing these comments to CAISO’s paper, comments that R|CAT provided during the 1996 California Public Utilities Commission (CPUC) Scoping for its Draft Environmental Impact Report (DEIR) were reviewed for reference and are being submitted as part of these comments. (These comments are attached at the end of this submittal.) They discuss:

• Renewables in the resource mix • Power generation sources in compliance to contribute to attainment efforts • Power supply from transmission line or generation siting and FERC’s Order

888/889 • Emission Valuation: Offsets, Reductions, Allowances, Externalities, Caps • Air quality and energy management policies

R|CAT understands the distinction among the roles and responsibilities of the various California environmental and energy agencies. In fact, it is understood that agencies may have competing objectives. And because of this, it is understood that the objectives of the attached 1996 comments were specific to CPUC’s public process at the time during electric restructuring and not necessarily intended to address competing objectives among the various agencies. Why attach these comments? R|CAT believes that several of the questions posed more than 20 years ago remain relevant as part of furthering CAISO’s discussion and vision. Some questions are comparable to those included in CAISO’s “Guiding questions”. In other words, this provides one snapshot for a perspective of what has and has not changed. While there are many issues that have evolved (e.g., regulatory landscape, policy issues, greater acceptance and prevalence of renewables, agencies’ roles and

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responsibilities, increased community impacts and involvement considerations) and some issues that are no longer relevant (FERC Order 888/889), there are some issues that remain the same or are simply reframed with little to no shift in progress. Nonetheless, R|CAT requests that the CAISO also consider these 20-year old comments, given that, to some extent, this provides an understanding of R|CAT’s context and perspective, as well as demonstrating R|CAT’s continued desire and commitment not only to address these topics but also to be part of how air quality, the environment, and energy will be addressed in California.

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TREND 1: Electricity is used far more efficiently. Foundation / assumptions

• Renters, low-income customers and disadvantaged communities are given access to energy efficiency gains.

• Distributed Energy Resources (DERs), layered system architecture and Microgrids increase options for reducing on-site electricity consumption.

Guiding question

• How can state and local programs best be focused to make energy efficiency upgrades and savings benefits available to low-income Californians, including those living in disadvantaged communities?

COMMENTS / PERSPECTIVES

• Environmental Justice, Social Justice Inventory: It will be useful to inventory land use planning agencies, air quality agencies, and other environmental agencies that have active environmental justice and/or social justice endeavors, as well a conventional community outreach endeavors. At a minimum, these existing programs can serve as outreach portals for renters, low-income customers, and disadvantaged communities.

• Public Health-Focused Organization Inventory: It has been discussed that public health is typically a primary concern of these target communities. Similar to taking an inventory of governmental and/or regulatory agencies (mentioned above), conducting an inventory of those non-profit, non-governmental public health related organizations that serve the target communities can be helpful. At a minimum, these existing organizations can serve as outreach portals.

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TREND 2: Gas-fired generation declines significantly as the grid is modernized. Foundation / assumptions

• By 2030, gas generation is used mainly when clean resources are not available. o The gas generation fleet is modernized. o The wholesale energy market ensures financial viability of gas-fired generators

that remain necessary. o Biofuels play a larger role in the thermal generation fleet:

• Regional sharing of flexible resources reduces the need for gas-fired generation. Task: Develop a comprehensive strategy for reducing reliance on fossil resources for power generation

• Implement policies that require all resources to operate flexibly, and conventional generators to have fast start, fast ramping and low Pmin capabilities.

• Determine the constraints that must be addressed to permit the use of biofuels as dispatchable resources.

• Develop regional capacity planning and regional system operation to maximize use of non-fossil flexible resources across the West.

COMMENTS / PERSPECTIVES

• Biofuels: Biofuels’ emission profiles – greenhouse gases, criteria pollutants, air toxics pollutants – vary across fuel type, fuel mix, and combustion sources. Similar to conventional natural gas fired sources, the emissions profile can vary greatly depending on load.

• Flexible operations: Fast start, fast ramping, and low Pmin capabilities are unique to each manufacturer. As a result, the emissions profiles (e.g., NOx, particulates, etc.) will vary. It is important to account for site-specific design and operations when characterizing the benefits (e.g., efficiency, emissions, load-following, etc.) of such units.

• Frequency response: Flexible operations must also consider the primary, secondary, and tertiary dynamic frequency responses. This key metric is the ability of a gas turbine or engine unit to respond with sufficient speed to control the frequency of power generated. This varies across manufacturers. This is relevant for any discussions regarding renewables, load-following, and the grid. These discussions are part of international efforts (i.e., EU) toward an increase in renewables.

• 1996 comments attachment: In the attachment, information in Issues (A), (B), (C) and (E) are related to this topic. Please refer to the attached.

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ATTACHMENT

Copy of May 28 1996 R|CAT Scoping Comments to the CPUC

• Cover letter/transmittal • Renewables in the resource mix • Power generation sources in compliance to contribute to attainment efforts • Power supply from transmission line or generation siting and FERC’s Order

888/889 • Emission Valuation: Offsets, Reductions, Allowances, Externalities, Caps • Air quality and energy management policies

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Cover letter/transmittal

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Issue (A): Renewables in the resource mix

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Issue (B): Power generation sources in compliance to contribute to attainment efforts

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Issue (C): Power supply from transmission line or generation siting and FERC’s Order 888/889

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Issue (D): Emission Valuation: Offsets, Reductions, Allowances, Externalities, Caps

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Issue (E): Air quality and energy management policies

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BACKGROUND I am the founder and principal of Resource Catalysts (R|CAT), established in 1994 (after leaving San Diego Gas & Electric’s (SDG&E’s) Corporate Environmental Department) in San Diego, CA – an independent consulting practice that has provided air quality services for the energy industry. While at SDG&E, served as the Environmental Department’s representative and primary air quality team member of the South Bay Repowering Project. As California’s electric utility restructuring activities emerged from its initial 1994 proposal, R|CAT evolved into a consulting community, where project teams often formed to provide multi-disciplinary, environmental decision-making support services for energy-related development projects and programs. Project examples from 1994 to 2007 include:

• Addressing Emerging Power Generation Issues: Air Pollution Control Technologies, Bioenergy Fuels, Renewable Energy, and Climate Change

• Environmental Communications: Presenting the Environmental Attributes of Energy Products and Services (e.g., principal investigator of EPRI’s air quality controls and regulations for gas turbines, CHP/DG air quality permitting,

• Responding to Energy and Natural Gas Issues in San Diego County (e.g., directly involved in air quality permitting for projects that underwent the CEC’s 21-Day Emergency Peaker licensing, obtained air quality variances for select cogen units)

• Ensuring Environmental Compliance for Existing Gas Turbine Facilities (e.g., supported five cogen assets’ air quality compliance management issues, risk management plans anhydrous ammonia SCR-equipped plants)

• Emission Reduction Credits, Mitigation Strategies, and Emission Offsets • Construction, Operations, and Renewals for Natural Gas-Fired Facilities (e.g.,

simple- and combined-cycle gas turbines, rich and lean burn reciprocating engines, small distributed generation sources)

• Asset Acquisition and Development Projects: Working with Project Developers and Due Diligence Teams (e.g., baseload and peaking plants, evaluation of environmental issues – air quality, land use, water quality, technology alternatives)

• Diesel-Fired Reciprocating Internal Combustion Engines: Project Feasibility, Permitting and Compliance Management (e.g., early grid-reliability project feasibility in San Diego, peak shaving implications evaluation)

When I relocated to Northern California in 2006, I re-established R|CAT’s consulting practice in 2014, after having served nearly seven years with the U.S. EPA, Region 9’s Air Division. While with Region 9 since September 2007, as a Behavior Designer/Anthrocubeologist, R|CAT provided coaching and behavior design consulting and continues to do so since leaving the government.

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Project examples while with U.S. EPA from 2007 to 2014 include: • Federal PSD air quality permitting for several power generation projects which

underwent CEC licensing, including the Avenal Energy Project • Oversight of state and local Arizona air quality permitting, including gas, gas/oil,

and coal fired power plants • Technical and inter-agency support for several power generation projects that

underwent CEC licensing, including Hydrogen Energy California (IGCC), Pio Pico, Palmdale Hybrid, and Blythe II

• Understanding of power generation impacts on visibility impairment, soils and vegetation, Class I and II (e.g., national parks, state parks), nearby air quality impacts of criteria pollutants, and endangered species

• Led multiple intra- and inter-agency collectives that included federal, state, and local agencies (e.g., US Fish & Wildlife Service, US Forest Service, DOE, California Energy Commission, California Air Resources Board, select California local air agencies)

• Participated in other U.S. Region 9 Divisions’ efforts involving combined heat and power and distributed generation, including bioenergy and biofuels-based pursuits

• Worked with EPA headquarters on Title VI (Civil Rights Act) related complaints and with the select Environmental Justice endeavors.

Recent projects include:

• One of two Principal Investigators for - Emission Control Technologies and Regulatory Issues Handbook for Simple- and Combined- Cycle Plants. EPRI, Palo Alto, CA: 2016. 3002007540 - a report on state-of-the-art environmental controls for gas turbine power plants (simple- and combined-cycle), including air quality regulatory, permitting, and compliance issues in the U.S. and select countries.

• Summary and interpretation EU regulations (air quality) affecting gas turbines and reciprocating engines. Other international regulations reviewed for gas turbine air quality standards include Mexico, Canada, Chile, Brazil, China, Korea, and Japan.

= = = END = = =

1

Stakeholder Comments

Draft ISO Board Vision Discussion Paper

Submitted by Company Date Submitted

Aditya Chauhan – (626) 302-3764 Southern California Edison 11/20/2017

Southern California Edison (SCE) offers the following comments on the Draft ISO Board Vision

Discussion Paper of the California Independent System Operator (CAISO)1.

The CAISO’s paper has raised a number of good topics that are items worthy of further

consideration. These issues are relevant to the future of the grid and relevant to meeting the

State’s objectives. SCE has been thinking about these very topics as well, and has issued a

whitepaper that addresses these topics2.

1 http://www.caiso.com/Documents/Electricity2030-TrendsandTasksfortheComingYears.pdf 2 https://www.edison.com/content/dam/eix/documents/our-perspective/g17-pathway-to-2030-white-paper.pdf

1

CAISO’s Discussion Paper “Electricity 2030: Trends and Tasks for the Coming Years”

Submitted by Company Date Submitted

Pamela Mills

San Diego Gas & Electric December 4, 2017

Pursuant to the California Independent System Operator’s (“CAISO”) request for comments on

its Discussion Paper entitled “Electricity 2030: Trends and Tasks for the Coming Years,”

(hereinafter “Discussion Paper”) San Diego Gas and Electric (“SDG&E”) Company offers these

comments.

Introduction

SDG&E appreciates the effort CAISO has undertaken to assess the dynamics that are driving the

development of California’s Clean Energy Economy. CAISO’s Discussion Paper provides a

comprehensive high-level picture of what CAISO sees as the eight trends that are likely to shape

the transformation of the electric sector to a clean energy economy. In addition to identifying the

trends that will shape this transformation, the Discussion Paper identifies the tasks that will need

to be addressed that can help to support the outcome outlined in each respective trend. SDG&E

supports the CAISO’s efforts to outline strategies for achieving California’s carbon reduction

goals to year 2030.

While the eight trends and their related tasks identified in the Discussion Paper align with the

State’s goals for a clean energy economy, many of the trends and task will require input and

actions from outside CAISO. SDG&E agrees with the CAISO that achieving these goals

requires participation by all sectors of California’s economy, especially from the transportation

sector which dominates fossil fuel consumption and associated greenhouse gas (“GHG”)

emissions in the San Diego region.

Comments

Regional Coordination Supports Efficient Grid Operations

The Discussion Paper identifies regional coordination as one of the trends that will facilitate

California’s transition to a clean energy economy. SDG&E agrees that expansion of centralized

electricity markets across the Western Electricity Coordinating Council (“WECC”) will facilitate

absorption of higher levels of renewable energy production and thereby reduce the need for

fossil-fired generation.

Regional coordination, if implemented properly, has the potential to lower costs for California’s

electric ratepayers. Regional coordination should make it easier for California’s utilities to

access lower-cost clean renewable energy sources in other western states. Regional coordination

will also lower costs by creating an opportunity for improved market operations. Lower

ratepayer costs will also lead to greater economic activity and an increase in jobs, including in

economically disadvantaged communities.

2

SDG&E strives to deliver clean, reliable, energy safely. We also want to do this at an affordable

cost for our customers. Our focus with CAISO Expansion engagement is moving toward more

clean energy while also securing ratepayer savings through enhanced operating efficiencies and

protecting our ratepayers from additional costs where offsetting benefits are not demonstrated.

Specifically, this plays out with regard to two key issues: The Western States Committee

governance proposal, efforts to ensure transmission cost allocation is fair; and the overarching

policies that govern GHG emission attribution.

Western States Committee: SDG&E believes that an independent committee should select the

expanded CAISO board members, who should be free to make independent governing decisions;

and The Western States Committee should serve as an advisory body.

GHG Regulation: There should be a state GHG emissions policy aligning methodologies across

California energy programs which achieves the following:

California’s GHG inventory should only include emissions from energy used in

California.

If the Cap-and-Trade program allows an offset to reduce a compliance entity’s obligation,

that offset also should be eligible to reduce the California GHG inventory.

Demand Response is Unlikely to Provide the Magnitude of Control Envisioned by the

Discussion Paper

The Discussion Paper relies heavily on demand response, suggesting that “Demand becomes as

important as supply in balancing the system.” SDG&E believes the CAISO is over-stating the

role of demand response in achieving the state’s carbon-reduction goals, particularly within the

12-year period (2018-2030) that the Discussion Paper focuses on.

According to the California Energy Commission’s (“CEC’s”) July 26, 2017 preliminary “mid”

demand forecast for the San Diego area, on-peak residential and commercial electric vehicle

charging load in the San Diego area at the time of the system peak is projected to grow by 33

MW from 2018 through 2028, reaching 48 MW in 2028. (Form 1.3)

For the same time period, the CEC forecasts an additional 132 MW of “Non-PV Self Genr.,” 310

MW of “PV” and 6 MW of “DR” added on the customer side of the meter, effective at the time

of the San Diego area peak load. By year 2028, these three categories of customer-sited load

reduction are projected to reduce customer load by 1037 MW. (Form 1.4) This stands in contrast

to the large amount of customers, over 4500 MW, that remain to be met by supply sources.

The CEC’s demand forecast indicates that the combined result of electric vehicle (“EV”)

charging load and customer-sited load reduction programs is to maintain San Diego area’s peak

loads basically flat between years 2018 and 2028, reaching 4557 MW in year 2028.

At the same time, the CEC’s 2017 Draft Integrated Energy Policy Report (“IEPR”) states that:

3

“Forecasting staff continues to refine a method for peak shift and to account for

changes in customer consumption patterns due to factors such as the economy,

weather, and other demand modifiers. For the revised CED 2017, the forecast

adjustments will reflect projected changes to peak hour and magnitude as the result

of customer side PV generation by California residents and businesses – the

primary driver of this shift – as well as AAEE.” (page 173)

SDG&E understands that this “peak shift” will move the time of the San Diego area peak load

into an early evening hour when PV output is effectively zero. Accordingly, customer-sited PV

will not be available to reduce the peak load. SDG&E believes most of the “Non-PV Self Genr.”

is comprised of customer-located storage devices. It is possible that, in aggregate, these storage

devices could provide more than 132 MW of incremental capacity given a shift in the peak load

hour to the early evening. It is also possible that some portion of the 48 MW of projected

electric vehicle charging load could be shifted away from the peak load hour.

Still, it is hard to see that by year 2030 demand will be “as important as supply” in balancing the

system. According to the CEC’s preliminary IEPR load forecast, the reality is that there will be

something like 4557 MW of San Diego peak load in year 2028 that will need to be served with

supply sources. Similar conclusions apply to loads in the SCE and PG&E distribution service

areas.

In making this observation, SDG&E is not suggesting that growth in controllable customer-side

loads and resources is unimportant. However, as the CEC’s load forecast suggests, there is a

very long way to go if demand is to become as important as supply in balancing the system in

year 2030. While the Discussion Paper mentions “widespread adoption” of controllable loads;

management of loads, including EV loads, by “DSOs/ESPs;” new EV purchases comprising “the

bulk of new car sales;” and electrification (with controllable devices) of existing non-electric

energy uses; it is unclear where the economic incentives and/or mandates for such activities will

come from, especially on the scale contemplated by the Discussion Paper.

Efforts are Already Underway to Integrate Transportation and Building Energy Use with

Electric Service

The Discussion Paper identifies the integration of transportation, building heating and cooling

and industrial use as a necessary trend that must be met if California’s GHG reduction goals are

to be reached. The Discussion Paper also recommends using a holistic approach.

SDG&E agrees. The transportation sector is key to meeting GHG and air quality goals. The

transportation sector accounts for 50% of all GHG emissions in San Diego, that is more than the

state average of 36%. Additionally, light-duty vehicles comprise 99% of all registered vehicles in

San Diego County and are responsible for 80% of combined on-road and off-road GHG

emissions. The State must reduce transportation sector emissions if it is to successfully meet the

goals of Senate Bill (“SB”) 350.

SDG&E’s transportation electrification initiatives are championing and accelerating many of

CAISO’s identified trends and tasks. SDG&E’s commitments go beyond helping meet Gov.

4

Jerry Brown’s bold vision of having 1.5 million zero-emission vehicles on the road in California

by 2025.

SDG&E’s Power Your Drive program is installing charging infrastructure for over 3,000 EVs

across our service area in apartments, condominiums and businesses. At least 10 percent of the

charging stations will be installed in disadvantaged communities. Power Your Drive enables

grid-integrated charging with the dynamic hourly Vehicle-Grid Integrated rate tied to the

CAISO’s day-ahead energy market prices.

In addition, to the Power Your Drive program, SDG&E’s proposed SB 350 projects and program

proposals under consideration by the CPUC provide for additional EV charging infrastructure

that aligns with the ISO’s vision by:

Encouraging transportation electrification and improving air quality in disadvantaged

communities;

Providing grid integrated dynamic pricing for EV charging at 60,000 residential, 4 public

charging locations and 5 fleet delivery locations;

Establishing grid integrated dynamic pricing for EV charging of shuttle fleets; and

Incentivizing EV adoption and time-of-use rate participation through EV dealerships

outreach.

SDG&E is also working on plans to expand the EV charging market and encourage innovation

with future proposals for CPUC consideration. Finally, SDG&E has an Electric Program

Investment Charge (“EPIC”) project proposal under consideration by the CPUC to repurpose

second-life EV batteries.

The Discussion Paper’s conclusion that electrifying the fossil fueled energy in buildings and

vehicles is the only way to reach GHG reduction goals is inconsistent with the approach set forth

by the California Air Resources Board’s (“ARB”) Scoping Plan. ARB’s Scoping Plan has laid

out how California will meet the 2030 GHG reduction goals and it does not include a complete

phase out of natural gas or full-scale electrification. The Scoping Plan incorporates

recommendations from SB 350, such as doubling energy efficiency savings in electricity and

natural gas end users statewide; ARB’s Short-Lived Climate Pollutant (“SLCP”) Reduction

Strategy mandated by SB 1383, which encourages using methane as a renewable source of

natural gas to fuel vehicles or generate electricity; and ARB’s Mobile Source Strategy, which

counts natural gas buses and low-NOx natural gas engines for the heavy-duty sector among its

clean transit options. To conclude at this juncture, when the ARB has not, that the only way to

meet GHG reduction goals is by completely electrifying buildings and vehicles by 2030 is

premature.

The Discussion Paper further states that, “The more of the economy we electrify, the easier and

more affordable it becomes to manage total energy use.” (page 4) The Discussion Paper fails to

acknowledge the implications of expanding electrification for utilities. While GHG emissions

from buildings and vehicles will be reduced, GHG emissions will increase for utilities. Although

increased generation from renewables will counteract some of that, the utilities will not be at

5

100% renewable or carbon-free electricity for some time. Moreover, achieving that will come at

a cost, and 100% renewable electricity does not equal 100% GHG free.

A Well-Designed Cap-and-Trade Program is Essential to GHG Reduction

A well-designed Cap-and-Trade program is an essential and flexible component of the State’s

GHG reduction efforts. With the 2017 extension of the Cap-and-Trade program under Assembly

Bill (“AB”) 398, the program will continue to be one of the primary strategies in the State’s

ongoing efforts to achieve cost-minimizing GHG reductions for the following reasons:

California’s Cap-and-Trade program is working to keep cost impacts for utility customers

reasonable. After four years of successful compliance, Cap-and-Trade has proven to be a

flexible, low-cost and reliable mechanism for reducing GHG emissions. Since the

beginning of this program, recorded GHG emissions have been below the required levels

every year and the State is projected to beat its 2020 GHG reduction targets. At the same

time, the State’s economic output has steadily expanded through additional clean energy

jobs and increased investment in clean technologies.

For several years, the electric investor-owned utilities (“IOUs”) have distributed a

household climate credit to residential and small business customers on their utility bills.

This climate credit is funded by the allocation of allowances provided by the State and is

already helping customers adapt to the Cap-and-Trade costs they bear. Natural gas IOUs

will also distribute a credit in the near future when the California Public Utilities

Commission (“CPUC”) finalizes their direction on how to distribute this climate credit.

California’s Cap-and-Trade program provides an effective mechanism for meeting GHG targets

through a declining emissions cap and includes provisions to ensure the environmental integrity

of this program. California’s Extended Cap-and-Trade program continues to drive reductions via

its annually decreasing cap and create incentives to pursue low cost GHG reductions, thereby

minimizing the overall economic impact to California.

The Discussion Paper’s References to Existing Fossil-Fueled Resources Needs to be Further

Nuanced.

The Discussion Paper states that “many fossil fuel plants in service today are old, inflexible and

inefficient.” (page 4) It would be helpful to provide some statistical support for this statement.

How many is “many?” How “old” are these units? In what sense are these units “inflexible?”

What is the criteria for determining when a generating unit is “inefficient?”

SDG&E notes that most of the gas-turbines in service today, at least within the CAISO balancing

authority, are relatively new – depending, of course, on where the line between “old” and “new”

is drawn. These units were built within the last 15 years, can be quickly started (typically within

ten minutes) and have heat rates that are much better than the prior generation of gas turbines.

Similarly, most of the combined cycle units in service today were built within the last 15 years

and have heat rates and performance characteristics that are much improved over prior

generations of combined cycle units. In SDG&E’s view, these gas-fired units are “flexible” in

6

that they can either start quickly, provide upward and downward ramping services, and/or

respond to Automatic Generation Control (“AGC”) signals.

By year 2030, many of these gas-fired generators will be approaching the end of their

conventional life-cycles. It would be logical to pursue strategies that would allow replacement

of this flexible generation with other non-conventional sources of flexibility. In particular,

SDG&E believes there is merit in developing a centralized clearing market for primary

frequency response where all generators, including solar and wind, can bid-in a capacity price

that allows the generator to recover the opportunity costs associated with maintaining the head-

room necessary to provide primary frequency response in the upward direction. Centralized

clearing markets for spinning reserves, non-spinning reserves and regulation capacity already

exist. These centralized clearing markets allow all sources of generation to compete to provide

flexibility services on a technology-agnostic basis. In this context, it is worth considering

whether it would be economical to retain some gas-fired generation as a low-cost source of

flexible and dependable generating capacity.

The more important issue, in SDG&E’s opinion, is the fate of coal-fired generators in other areas

of the WECC. These units are relatively inflexible in that they take a long-time to start and are

generally not well-suited to ramping (although recent data shows an increase in cycling for these

units). Compared to gas-fired units, the fuel-conversion efficiency of coal-fired units is

mediocre at best and, of course, coal-fired generation has a high CO2 footprint. A key issue will

be the extent to which further retirement of coal-fired generation can be accommodated through

additional renewable generation and/or retention of some existing gas-fired generation.

Engage Municipal Utilities, Cooperatives, Irrigation Districts and Federal Power

Marketing Authorities in Climate Change Actions

Understandably, the Discussion Paper focuses on the trends and strategies involving the CAISO

and several state agencies, including the CPUC. SDG&E understands that municipalities outside

the CAISO, such as the Los Angeles Department of Water & Power (“LADWP”) and the City of

Glendale, are considering constructing new gas-fired resources (e.g., combined cycle units to

“replace” coal units at the Intermountain Power Project (“IPP”) and combined cycle and simple

cycle gas turbines to “repower” existing gas-fired generators at Glendale’s Grayson power

plant).

These proposals are being made at a time when relatively new existing gas-fired combined cycle

units within the CAISO balancing authority are struggling to find revenue streams sufficient for

the units to avoid retirement. It is illogical to spend valuable capital on new gas-fired generation

when, by all accounts, existing gas-fired resources would be happy to meet the needs of these

municipal entities. Barriers to such transactions are institutional, not physical. Several

municipal utilities are also maintaining in their resource mix, old and highly inefficient gas

turbines and coal generators.

In SDG&E’s view, the non-Investor Owned Utilities (non-IOUs)1 have been comparatively slow

to embrace the initiatives necessary to achieve the state’s carbon reduction goals. The

1 With the possible exception of certain municipal utilities in southern California which have joined the CAISO.

7

Discussion Paper should address this recalcitrance head-on. SDG&E believes it would be

constructive to specifically engage the non-IOUs in identifying institutional and policy changes

which would better align these organizations’ efforts with those of the CAISO, the CPUC and

the IOUs.

Realizing the Discussion Paper’s Bold Vision Requires a Periodic Review of Progress Along

the Identified Trends

The Discussion Paper outlines eight trends that it believes represent “opportunities for evolving a

more secure, sustainable and affordable electric service” by 2030. All of these trends are

important if California is to reach its carbon-reduction goals at an acceptable cost. SDG&E

suggests that the CAISO periodically review each trend; and the assumptions, expectations and

drivers behind each trend; to assess the extent to which the trend is actually coming to fruition.

Where a trend identified in the instant Discussion Paper is not evolving as expected, the CAISO

could explain the reasons and propose recommendations that would provide mid-course

adjustments necessary to achieve the desired end-state. The periodic assessments could be

performed annually, or perhaps biannually.

Shell Energy North America (US), L.P. comments on:

CAISO Board of Governors Discussion Paper:

“Electricity 2030 Trends and Tasks for the Coming Years”, October 2017

Mike Evans, Shell Energy, michael.evans@shell.com, 858-526-2103

November 20, 2017

Shell Energy North America (US), L.P. (Shell Energy) appreciates the efforts the CAISO Board took to

generate the discussion paper “Electricity 2030” and its interest to further the dialogue on what a future

state looks like and how we can get there. Shell Energy supports state goals to reduce the carbon

intensity of the energy sector and efforts to reduce carbon in other sectors. We provide the following

general and trend comments in hopes of furthering a constructive dialogue to move closer to a

competitive market which reflects innovation and consumer choice.

General Comments:

• Benefits of Direct Access: The paper discusses the future role of the IOU in several places.

AB1890 provided for the monopoly transmission and distribution function to remain with the

utility, while procurement of energy could be obtained in a competitive market. The structure

under direct access keeps the fundamental revenue stream in place for the utility, while

providing for innovation, choice and quicker response by consumers if the caps on direct access

were removed. In 1999, the WECC had 29,000 MW of new generation planned or under

construction in the west, anticipating a robust retail energy market, reflecting significant

interest. Suspension of direct access in 2001 (with subsequent legislation) has temporarily

halted consumer choice, although some form of consumer choice is moving forward with 18

CCAs planned for operations by the end of 2018. A forward look at the market could benefit if a

discussion about reinstatement of direct access for all customers were included.

• Cost-Benefit Criteria – The discussion could be enhanced with a more robust discussion of

which paths result in greater carbon reduction for the investment cost. For example, E3 has

recommended hydrogen production as a mechanism to manage the oversupply, which can

store the energy for later use, in addition to reducing vehicle emissions. Alternately, increasing

EVs can provide a supply of “used” batteries for stationary use for managing the ramp created

from significant supplies of solar PV. Net zero energy homes can reduce or eliminate the 7%

losses currently experienced on the transmission grid. These decisions could be enhanced by

careful evaluation of which paths created the most cost effective carbon reductions.

• Real Carbon Reductions – If carbon policies only result in shifting carbon intensive

manufacturing processes to other states or other countries, a thoughtful discussion should be

part of the process to ensure that the cost to consumers is truly reflective of the actual carbon

reduction benefits. Possibly, the timeline could be addressed to ensure that businesses can

adapt with cost effective improvements in manufacturing that enact true reductions in carbon.

If high costs simply drive business to other states without benefits (leakage), the state should

adapt its implementation process to ensure real carbon reductions. While this applies to cap-

and-trade, utility rates can have a similar effect and too aggressive efforts may result in higher

rates which drive away business.

• Provider of Last Resort (POLR) – The existing utility providing T&D services has been tasked with

being the “Provider of Last Resort”, and is required to accept any customer that chooses to

“switch back” from a non-utility ESP to the local utility. While typically direct access customers

don’t go back to the utility, this requirement places an enormous burden on the utility. The

discussion about the future state could benefit from a discussion about how the POLR function

should be handled, which a review of how this function o is handled in other states. For

example, this function could be bid to non-IOU ESPs, and there could be a cost premium to

switching customers who do not proved adequate lead time.

• Lessons from other RTOs – Are there lessons from other RTOs, such as ERCOT or NYISO that

provide good examples of how customers have been able to successfully choose rate structures

and ESPs that we should incorporate into this policy analysis?

Trend 1 – Electricity is used far more efficiently.

• Move energy efficiency programs to third parties through limited reinstatement of direct access

- Energy efficiency is critical to carbon reduction efforts. While state goals have been difficult to

achieve under utility programs, third party providers have aggressively pursued innovative

retrofits, such as variable speed fans and chiller drives. A phase in of direct access could be a

driver to facilitate and hasten EE solutions, if customers had the ability to see direct savings and

carbon reductions associated with their specific projects. Use of third parties could be a more

effective means to aggressively pursue EE advancements.

• Revise tariffs to allow netting of solar PV in multifamily dwellings - Tariffs that restrict netting of

solar PV in multifamily housing could be adapted to allow multiple meters to net against a single

large solar PV installation, increasing the incentive to move to a renewable supply of energy at

multifamily dwellings.

Trend 2 – Gas Fired generation declines significantly as the grid is modernized.

• Procure RA on an equal basis. – The CPUC has approved many new power plants which are paid

under long term PPAs at rates significantly higher than RA revenues provide in bilateral markets

to existing “merchant generation”. This discrepancy creates a “hybrid” market, in which some

generation is assured fixed cost recovery and other generation is not. ISO DMM annual report

data show merchant generation obtains between 20% and 40% of their fixed costs. An initial

effort to manage a phase out of gas generation, as proposed in the paper, would be to stop the

out of market procurement of new generation and ensure that all LSEs procure RA in bilateral

markets on an equal basis. Next steps should include a robust discussion with market

participants of how to manage a process which selects which generation units remain in

operation.

• Create a Flexible Reserve Product - Peakers and other remaining fast start resources, including

batteries, flywheel storage and pumped hydro storage, should be treated on an equal basis and

compensated for services provided, such as flexible capacity. The current markets do not

adequately compensate flexible capacity nor do they reward low or no minimum generation

requirements. A market based flexible capacity reserve product, used to provide to the ISO

flexible ramping capability, could both compensate generation needed for ramps and incent

LSEs to procure this reserve product on a forward basis, helping with the “missing money” that

generation facilities are lacking.

Trend 3 – The system is shaped by the variable output of wind and solar resources.

• Expand consumption of the oversupply through direct access – It appears that “matinee tariffs”

intended to increase the use of energy mid-day both lag and will be difficult to align with the

varied needs of customers. It is likely that reinstatement of direct access would give those

customers the opportunity to procure energy during projected oversupply conditions, and put

that energy to useful purposes, potentially employing state residents and creating goods for

resale. Much of this energy is currently exported to other neighboring states. A mechanism to

allow productive use of this oversupply could benefit the state in many ways. A reinstatement

or partial reinstatement of direct access could make “solar strip” energy available for in-state

productive purposes.

Trend 4 – Demand becomes as important as supply in balancing the system

• Demand Resources should be compensated on an equivalent basis to Supply Resources – The

discussion that demand is as important as supply is taken in the context of being an asset both

for ramping up and ramping down, and that it should be compensated on an equivalent basis.

Historically, demand response has been viewed as a decremental resource, effective for about

5% of the overall asset base, reflecting the typical load duration curve. For a peak of 50,000 MW

within the ISO, the ISO has about 2500 MW of demand response, which can effectively manage

that portion of time in which most peaking resources are dispatched. However, we are

transitioning away from “typical”, and it is expected that more inc and dec needs can be

supplied from “dispatchable” demand resources. The state should consider how innovation

through the use of DR resources can be encouraged, either though third-party provisions or

(partial) direct access implementation. Further, ISO standards on DR dispatch and measurement

need to be consistent and realistic.

Trend 6 – Regional Coordination supports efficient grid operations

• Move more energy schedules into the DA market – The ISO through implementation of the EIM

has in a very short time moved a significant amount of energy to RT dispatch. It is now heavily

dependent on capacity from EIM participants, capacity which could move to the Mountain West

RTO in a very short timeframe. It appears that the most viable approach to regionalization

would be to examine and make appropriate changes to the DA scheduling process such that

market participants are encouraged to schedule energy in the DA timeframe. This is both a grid

reliability issue and a long-term sustainability issue.

California CAISO CAISO 2030 Vision Paper Comments

Comments of Pacific Gas & Electric Company

Electricity 2030: Trends and Tasks for the Coming Years

Submitted by Company Date Submitted

Greg Rybka (415) 973-3861

Pacific Gas & Electric Company March 2, 2018

Pacific Gas and Electric Company (PG&E) appreciates the opportunity to provide thoughts on the CAISO’s Discussion paper titled “Electricity 2030: Trends and Tasks for the Coming Years” published in October, 2017. In general, PG&E supports the effort put forth by the CAISO to lay out its vision through 2030, and the CAISO’s paper provides insight into the main issues PG&E believes will be affecting the electric and gas sectors as we move towards 2030. PG&E agrees with the CAISO that issues surrounding decarbonization will shape the electric system of the future. As the state moves towards decarbonization, CAISO appropriately highlights the role of gas in supporting a reliable grid and enhancing the ability of the grid to support more renewable resources. It is important that the CAISO and statewide load serving entities work together to ensure that we move towards a decarbonized grid while maintaining customer affordability, safety and reliability. Safety and Reliability As we move towards 2030, PG&E believes that safety and reliability of our electric grid must remain at the forefront of the state’s and CAISO’s vision. PG&E has always believed that safety is the highest priority in our electric and gas operations and planning, and continues to believe that maintaining reliability must be a principal focus for any action taken by the state and CAISO. Moving to a Low-Carbon Future In 2017, 33 percent of PG&E’s portfolio consisted of RPS-eligible renewable resources and PG&E is well-positioned to reach 50 percent in 2030. In 2017, PG&E already delivered nearly 80% of our energy from greenhouse gas (GHG) free sources. PG&E is focused on providing least-cost sources of GHG-free energy to contribute to the state’s GHG reduction goals while maintaining reliability and affordability. There are numerous challenges in meeting California’s energy needs through policies focused primarily on renewable resources. The impact of excess generation, the integration of intermittent renewable resources, and the need for an efficient market (that provides the optionality to balance the key issues of customer affordability, environment and reliability) must be addressed going forward. Continued advances are needed to promote the economic dispatchability of renewable resources and ensure that they are cost-effective, responsive to reliability needs, and capable of providing the full suite of services of traditional generation (e.g., ramping capability). Additionally, renewable resources are an essential component, but not the only component, to reduce GHG emissions. Statewide, 20 percent of GHG emissions come from the electric sector, while the remaining 80 percent come from sources in other sectors (e.g., transportation). As the state moves toward ambitious electric sector GHG goals, we need to keep a focus on reducing GHG emissions in all

California CAISO CAISO 2030 Vision Paper Comments

sectors. PG&E believes that all sectors must contribute to achieve statewide GHG reductions and work towards a low carbon future. Future of Gas Generation As we move towards higher and higher levels of statewide renewables, PG&E believes that our natural

gas system will continue to be a critical part of the energy future, by integrating renewable natural gas

and helping to integrate high levels of renewable electricity onto the grid. We look to the CAISO to work

with transmission operators, load-serving entities, and gas system operators as it explores the role of

gas-fired generation and dynamically changing electric load.

Increased Electrification Transportation is the largest contributor to greenhouse gas emissions in California – about 40 percent. California aims to have 1.5 million zero-emission vehicles on the road by 2025 and 5 million by 2030 . Today, there are over 300,000 EVs in California including 150,000 in PG&E’s service area. PG&E customers register around 3,000 new EVs per month, more than any other energy company in the nation. Beyond passenger cars, there are opportunities to accelerate electric infrastructure for medium to heavy vehicles to address air pollution and GHG emissions. PG&E’s goal remains to make it easy and affordable for customers to adopt EVs. Conclusion PG&E thanks the CAISO for laying out a future vision for the electricity sector. PG&E agrees with the CAISO that the electric system of the future will be shaped by issues surrounding decarbonization. PG&E is eager to work with the CAISO on these important issues to help build the safe, affordable and reliable grid of the future.