News Article | April 19, 2017
When it comes to solar electric power, California has a good thing going – perhaps too good. Too much clean, affordable, abundant energy? It’s true because high levels of solar production from utility-scale facilities and widely distributed rooftop installations occur during daytime hours when demand may not be at its peak and grid-supplied electricity is plentiful. Seasonally, and under certain conditions, this leads to an oversupply of energy on the grid and requires curtailment of generation resources, including wind and solar. We should see this as an opportunity to further reduce fossil fuel generation and to build a more robust, resilient and efficient grid. The challenge is to match our daytime supply of clean renewable power with the actual demand for electricity, which now peaks in the evening. Fortunately, California is poised to turn this challenge into opportunity by putting power into battery storage for use when it’s needed. Oversupply can occur on a sunny day when solar production pushes demand for traditional baseload generation below forecasts during the day. This net load, or the difference between forecasted load and expected generation from known solar resources, is illustrated by what the California Independent System Operator (CAISO) has termed the “Duck Curve.” The “belly” of the duck shows the expected impact of solar generation during peak production hours. With increasing solar deployment, the duck’s belly may continue to expand, requiring costly curtailment of either the solar or the baseload resources. What’s more, peak demand increasingly occurs during the early evening hours after the sun has set. This requires CAISO to steeply ramp up generation, the “neck” of the duck, using fossil fuel-fired peaker plants until baseload resources can handle the load. This balancing of energy supply and demand must be continuous to mitigate the risk of both over- and undersupply, and the effect of solar as illustrated by the Duck Curve is a particularly costly and impactful scenario. What’s being done now? In response to the Duck Curve, utilities and the California Public Utilities Commission have started to design rates and tariffs to better reflect time-varying pricing, moving away from historic volumetric tier pricing to dynamic, time-of-use (TOU) rates. This means homeowners will pay significantly more for turning on their lights, running their dishwashers and doing laundry when they return home from work in the evenings. To take control of their utility bills, consumers can become more energy efficient and conserve, but they also can invest in self-generation to offset demand for grid power. Solar plus energy storage offers a solid solution to this dilemma. By storing solar energy produced during midday in batteries in their homes and using it later in the day, Californians can reduce dependence on grid-generated power during hours of peak usage and higher rates. When pairing solar with battery storage systems on a wide scale, Californians can not only save money, but also reduce strain on the grid and mitigate the Duck Curve. With nearly instantaneous response time, battery storage can smoothly ramp up and regulate supply, displacing peaker plants while simultaneously decreasing intermittency (power that is not continuously available). Energy storage also enhances resiliency, and defers utility transmission and distribution upgrades — all of which will save ratepayers in the long run. The potential social benefits are substantial, including cost savings, expanded consumer choice, a cleaner environment and robust clean-tech market and job growth. How policy can help California policy has long promoted solar energy, recognizing the threat of climate change and continued greenhouse gas emissions from fossil fuel combustion. Currently, attention is focused on energy storage with Senate Bill 700 (Wiener) working its way through the legislature to create a market transformation program aimed at fostering growth of solar plus energy storage. To maximize the benefits of combined solar plus storage and reduce greenhouse gas emissions, policymakers must continue the path of establishing appropriate price signals grounded in good utility rates and tariffs along with clear and transparent interconnection rules. But they also must deploy properly designed market transformation programs that effectively reach all businesses and residents, particularly low-income customers who pay a higher percentage of their total income toward their energy bills than other population segments. In this time of changing rates and higher utility bills, combining solar and energy storage improves stability for the power grid and will ultimately help Californians take more control of their energy usage and contribute equitably to the state’s clean energy future. An investment in incentivizing energy storage technology, just like California did for solar, will be well worth the effort. By Ben Airth, Senior Specialist, Distributed Energy Resources Co-author: Sachu Constantine, Director of Policy Center for Sustainable Energy About the Center for Sustainable Energy® Accelerating the transition to a sustainable world powered by clean energy. Founded in 1996, the Center for Sustainable Energy (CSE) is a mission-driven nonprofit dedicated to developing a clean energy future that addresses climate change, increases energy independence and generates lasting economic and environmental benefits. CSE empowers such innovation by leveraging its expertise in clean transportation, distributed energy resources, energy efficiency, energy engineering and regulatory and policy support. As a trusted advisor, CSE partners with clients of all sizes to achieve their sustainability objectives through a suite of energy services that include comprehensive program design and management, research and analysis, technical advising, incentive and rebate management, and education and outreach. CSE is headquartered in San Diego with offices in Boston, Los Angeles and Oakland, Calif. Learn more at EnergyCenter.org -Facebook - Twitter - LinkedIn.
News Article | April 10, 2017
On March 11, utility-scale solar generation in the territory of the California Independent System Operator (CAISO) accounted for almost 40% of net grid power produced during the hours of 11:00 a.m. to 2:00 p.m. This is the first time CAISO has achieved these levels, reflecting an almost 50% growth in utility-scale solar photovoltaic installed capacity in 2016.01 The large and growing amount of solar generation has occasionally driven power prices on the CAISO power exchange during late winter and early spring daylight hours to very low, and sometimes negative, prices. However, consumers in California continue to pay average retail electricity prices that are among the highest in the nation. Utility-scale solar generation includes solar photovoltaic (PV) systems as well as a few solar thermal plants. Additional generation from customer-sited solar generators installed in California (such as those on residential and commercial rooftops) further adds to the total solar share of mid-day electricity generation, while displacing demand for power from the grid. As of December 2016, utilities in CAISO reported 5.4 gigawatts (GW) of net-metered distributed solar capacity. (EIA reports installed electric capacity data in alternating current terms, which are typically 10% to 30% lower than the direct current capacities sometimes reported for PV systems.) EIA estimates that this capacity would have generated approximately 4 million kilowatthours (kWh) during the peak solar hours on March 11. This level of electricity reduced the metered demand on the grid by about the same amount, suggesting that the total solar share of gross demand probably exceeded 50% during the mid-day hours. Total solar capacity in California (including both distributed and utility-scale systems) has grown from less than 1 GW in 2007 to nearly 14 GW by the end of 2016. Solar generation follows daily and seasonal sunlight patterns, peaking during the long summer days and reaching its annual minimum during the winter. Electricity demand in California also tends to peak during the summer months. However, in late winter and early spring, demand is at its annual minimum, but solar output, while not at its highest, is increasing as the days grow longer and the sun gets higher in the sky. Although the sun is at a similar angle in September and October, electricity demand is still relatively high, leading to lower solar generation shares than seen in March. Consequently, power prices on both the day-ahead and real-time CAISO markets were substantially lower in March compared with other times of the year or even March of last year. In March, during the hours of 8:00 a.m. to 2:00 p.m., system average hourly prices were frequently at or below $0 per megawatthour (MWh). In contrast, average hourly prices in March 2013–15 during this time of day ranged from $14/MWh to $45/MWh. Negative prices usually result when generators with high shut-down or restart costs must compete with other generators to avoid operating below equipment minimum ratings or shutting down completely. Large price spikes immediately before and after mid-day periods when both utility-scale and distributed solar generation reaches its peak level suggest a need for dispatchable generation sources to help cover ramping periods, when the need for power from the grid to meet load is rapidly changing. Beyond solar output, the mix of generation on the system also affects prices. Notably, above-average rain and snowfall this winter in California has supported high levels of hydropower generation that may also be contributing to recent pricing patterns. California grid operators have been concerned over the effects of the increase in solar generation on system operations for several years. The generation and pricing patterns that occurred in March and that may continue through the spring highlight some of the issues California grid operators will face in integrating large amounts of solar into their power markets.
News Article | April 17, 2017
FOLSOM, Calif. & EL CENTRO, Calif.--(BUSINESS WIRE)--As of April 3, 2017, ZGlobal Inc. Power Engineering and Energy Solutions (“ZGlobal”) has begun providing Silicon Valley Clean Energy (“SVCE”) with alternative energy services, resulting in the successful launch of SVCE’s Community Choice Aggregation (“CCA”) operations. ZGlobal provides SVCE 24/7 operation services enabling 100% Carbon Free Electricity. “We are very pleased to leverage our decades of experience to provide SVCE with value-added services at competitive prices,” stated Kevin Coffee, Vice President of Electric Operations at ZGlobal, and a veteran of Electric Operations at Pacific Gas and Electric (“PG&E”). SVCE is a Community Choice Energy (CCE) provider, whose purpose is to pool the electricity demand of its residents and businesses and buy carbon free power on their behalf outside of their local utility. SVCE is encouraging a type of competition that could result in additional utilization of renewable and carbon free energy sources at more competitive rates. “With partners such as ZGlobal, Silicon Valley Clean Energy customers will get the same reliable service they are used to, and 100% carbon-free electricity at competitive prices,” said Tom Habashi, CEO, SVCE. Silicon Valley Clean Energy is a community-owned agency servicing the majority of Santa Clara County communities by acquiring clean, 100% carbon-free electricity on behalf of residents and businesses. As a public agency, net revenues are returned to the community to keep rates low and promote clean energy programs. Member jurisdictions include Campbell, Cupertino, Gilroy, Los Altos, Los Altos Hills, Los Gatos, Monte Sereno, Morgan Hill, Mountain View, Saratoga, Sunnyvale and the unincorporated areas of Santa Clara County. SVCE is guided by a Board of Directors, which is comprised of a representative from the governing body of each member community. With Silicon Valley Clean Energy, residents and businesses in our communities will join thousands of Californians in choosing clean power at competitive rates. For more information please visit SVCleanEnergy.org. ZGlobal offers a wide range of services in the energy sector, including round-the-clock scheduling and operation services, in addition to reliability/compliance services for green energy such as solar, wind, energy storage, geothermal, and biomass facilities, CCAs and utilities throughout the western United States. ZGlobal manages over 12,600 GWh of energy annually and over 3,000 MW peak from California, Arizona, Nevada, and Utah with a transaction value exceeding $320 million. ZGlobal was formed in 2005 and is staffed by veterans from the California Independent System Operator (CAISO) as well as various western utilities. The group is led by Ziad Alaywan P.E., who served as the Manager of PG&E real time operations. As one of the first employees that led the rapid implementation and operation of the CAISO in 1998, Mr. Alaywan later became CAISO’s Managing Director of Grid and Market Operations. More information is available at www.zglobal.biz.
News Article | April 20, 2017
"These projects will add more flexibility to the system and help us to ensure reliability while providing greater levels of clean energy to all of our local communities," said Emily Shults, SDG&E's vice president of energy procurement. "By building these projects, SDG&E will remain at the forefront of helping the state achieve its bold clean-energy and carbon-emission targets." All five of the battery projects can store supplies of solar, wind and other traditional sources and release it when energy is in high demand. The California Public Utilities Commission (CPUC) has set targets for investor-owned utilities to procure large amounts of energy storage by 2020, including 165 MW by SDG&E. With these five new projects, SDG&E is on track to meet this goal. The new facilities are expected to come on line between December 2019 and late 2021. The demand response program run by OhmConnect will also add flexibility to the system. Beginning in early 2018, OhmConnect will request industrial and commercial customers who have enrolled in the demand-response program to reduce energy usage within 20 minutes of being called during certain days and hours. This process will be conducted by the California Independent System Operator and/or SDG&E as needed. SDG&E is an innovative San Diego-based energy company that provides safe, reliable, clean energy to better the lives of the people it serves in San Diego and southern Orange counties. More than 4,100 employees work to provide the cleanest and most reliable energy in the West. The company has been recognized by the U.S. Environmental Protection Agency for leadership in addressing climate change, was the first to meet California's goal of delivering 33 percent of energy from renewable sources, has fueled the adoption of electric vehicles and energy efficiency through unique customer programs, and supports a number of non-profit partners. SDG&E is a subsidiary of Sempra Energy (NYSE: SRE), a Fortune 500 energy services holding company based in San Diego. For more information, visit SDGEnews.com or connect with SDG&E on Twitter (@SDGE), Instagram (@SDGE) and Facebook. To view the original version on PR Newswire, visit:http://www.prnewswire.com/news-releases/sdge-seeks-more-storage-to-harness-clean-energy-and-enhance-reliability-300442398.html
News Article | October 28, 2016
Enbala Power Networks has been selected by General Electric Global Research as a key partner in its DOE-funded ARPA-E Network Optimized Distributed Energy Systems (NODES) project. The $3.9 million project’s objective is to create transformational distributed flexibility resource (DFR) technology that aggregates responsive flexible loads and distributed energy resources (DERs) to provide synthetic reserve services to the grid while maintaining high customer quality-of-service. Specifically, a fast reserve similar to a regulating/spinning reserve and a multi-hour, ramping reserve will be developed to provide the same kind of grid balancing flexibility now provided by power plants and large-scale demand response. Other project participants include GE Energy Consulting, the Lawrence Berkeley National Laboratory, Consolidated Edison, Inc., Southern California Edison, Sacramento Municipal Utility District and California Independent System Operator. The 12 NODES projects, including this one, aim to develop innovative and disruptive technologies for real-time management of T&D networks through system-wide control and coordination of flexible load and DERs. In a DOE press release ARPA-E Director Dr. Ellen D. Williams commented, “The research and development of these grid control technologies will make the concept of virtual energy storage a practical reality. The result will enhance the resiliency, security and flexibility of our nation’s electric grid and allow the U.S. to make the best use of its abundant renewable energy resources.” One novel aspect of the GE ARPA-E project is development of a tool that will use short-term and real-time weather forecasts along with other data to estimate the reserve potential of aggregate loads and DERs on a day-ahead basis. An optimization framework that will enable aggregation of large numbers of flexible loads and DERs and determine the optimal day-ahead schedule to bid into the market will also be developed. This will provide the flexible resources required to meet the transformational requirements of today’s evolving grid, while also opening up new opportunities for customers to monetize their assets. Using its Symphony by Enbala distributed energy resource management platform, Enbala is responsible for the project’s control infrastructure and for working collaboratively with Consolidated Edison to recruit a diverse set of customers and distributed energy assets. The advanced control functionality developed within the NODES project will be implemented as micro-services leveraging the GE Predix cloud platform. “This is an innovative project that will effectively demonstrate how grid edge assets can be effectively networked into virtual storage systems that manage the intermittency of renewable energy and help us meet the growing operational challenges of grid infrastructure management,” commented Enbala President and CEO Arthur “Bud” Vos. The DFR technology being created must be able to aggregate and control thousands of customer DERs in real time and match them with production projections. GE electrical engineer Naresh Acharya explained that this project will enable a grid that can reliably manage a power mix where nearly half or more is supplied by renewables. About Enbala Power Networks® Enbala Power Networks is focused on making the world’s power grids greener and more reliable, efficient and predictable by harnessing the power of distributed energy. Enbala’s real-time energy-balancing platform - Symphony by Enbala - is transforming energy system operations through its revolutionary, highly flexible approach for creating controllable and dispatchable energy resources. It unobtrusively captures and aggregates available customer loads, energy storage and renewable energy sources to form a network of continuously controlled energy resources. The platform dynamically optimizes and dispatches these resources to respond to the real-time needs of the power system – all without impacting customer operations. For more information, visit http://www.enbala.com or follow @enbala on Twitter.
News Article | January 20, 2016
It’s been a busy first few weeks of the new year for the clean energy sector. Net energy metering has quickly emerged as a defining issue for 2016, with predictions that disagreements over the state-level policy will get worse now that solar incentives are locked in at the federal level. Nevada’s net metering battle has dominated headlines. Meanwhile, New Hampshire, Ohio, Maine and other states are also reassessing net metering compensation. (More on that in our roundup below.) Renewable portfolio standards (RPS) are also up for debate in several states, such as Michigan and Oregon, while Vermont has just released a strategy document outlining its path to get to 90 percent renewable energy by 2050. A recent report found that the benefits of RPS targets far outweigh the costs. Outside of renewables, a few states have already taken steps this year to promote electric-vehicle adoption. Most notably, California regulators approved Southern California Edison’s proposal to build 1,500 EV charging stations in its service territory, with the long-term goal of installing 30,000 stations. The full slate of state updates is below. Click a region to jump to news from the West, Northeast, Midwest or South. You can read our previous state bulletin here. On January 14, the California PUC approved a settlement agreement allowing Southern California Edison to incentivize the deployment of 1,500 electric-vehicle charging stations and build public awareness on electric transportation. SCE is authorized to spend $22 million on the first implementation phase of its Charge Ready and Market Education Programs. The programs are intended to support California’s goal of putting 1 million zero-emission vehicles on the road by 2020. The new agreement has received widespread support, including from the Electric Vehicle Charging Association, the Sierra Club and the Environmental Defense Fund. EV charging companies recently took issue with a separate infrastructure proposal from Pacific Gas & Electric, which sought to build 7,500 charging stations at a cost of $29,600 per station. The SCE plan puts the cost of each station at $14,666. The SCE program also gives site owners more control over the equipment they choose to operate, which was a sticking point in the PG&E debate. This is how the program economics break down, according to the CPUC: “The customer participant will own and operate the charging station and will be responsible for all related operating costs, including maintenance and electricity usage. Ratepayers will fund the cost of all paneling, conduits, and wiring, up to the charging station itself. Edison will also provide charging station rebates to site owners to cover a predetermined percentage of the charging system ‘base cost.’ Rebate levels will be 25 percent of the base cost for all non-residential market segments, 50 percent of the base cost for Multi-Unit Dwellings, and 100 percent of the base cost for any charging stations located within disadvantaged communities, regardless of market segment.” Once the pilot phase of the program is complete, SCE will seek authority from the CPUC to deploy another 28,500 charging stations for a total estimated program cost of $355 million. In other California news, the state’s three investor-owned utilities recently announced contracts with nine different companies under California’s Demand Response Auction Mechanism, or DRAM. The auction is the state’s first attempt to use distributed energy resources -- from EV chargers to smart thermostats to commercial load control -- to create grid-edge flexibility. Ohmconnect, EnergyHub, Green Charge Networks, EnerNOC, eMotorWerks and Stem were among the companies selected. In addition, the California Energy Commission approved $9.6 million in funding from the Electric Program Investment Charge (EPIC) Program last week. The vast majority of the funding -- four grants totaling $6.2 million -- went toward testing energy storage systems. The four recipients are: Fuel Cell Energy, EOS Energy Storage, LightSail Energy, and Amber Kinetics. California’s clean energy sector hit a major milestone in 2015 with solar energy surpassing both wind and hydropower as the number-one renewable energy source in the state, KQED reports. According to figures from the California Independent System Operator (CAISO), utility-scale solar made up 6.7 percent of the system’s total power generation. Wind made up 5.3 percent, and hydro, which suffered during a drought year, contributed 5.9 percent. Solar actually generated even more electricity for California than those figures suggest, because CAISO does not track generation from rooftop solar projects. Meanwhile, the state continues to experience a months-long methane leak -- dubbed the worst environmental disaster since BP’s Deepwater Horizon oil spill in 2010. Last week, the Nevada Public Utility Commission voted unanimously to deny a stay on new rates for rooftop solar customers. The decision upholds the PUC’s December ruling to eliminate retail-rate net metering over four years and increase fixed fees for both new and existing solar customers. The new policy took effect on January 1. Solar companies and solar customers have pushed back against the new policy. Because the rule will apply retroactively to Nevada’s 17,000 existing solar customers, many of them will see their savings wiped out, and some may even see an increase in their monthly electricity bills. At the same time, by erasing most if not all of the savings from rooftop solar, the changes essentially kill the Nevada rooftop solar market. As a result, several solar companies have already pulled out of the state. A group of solar customers are now pursuing a class action lawsuit against NV Energy for providing incentives to encourage customers to go solar, and then lobbying to change a key solar policy. Solar companies have filed another motion for reconsideration with the PUC and are starting to consider legal action in the event that the petition fails. In early November, Tucson Electric Power filed its next rate case (E-01933A-15-0322). The utility has proposed doubling the fixed charges for residential customers form $10 to $20, instating a demand charge on solar customers and reducing the net metering credit from the retail rate (11 cents per kilowatt-hour) to the utility’s avoided cost for energy (6 cents per kilowatt-hour). Motions to intervene must be filed by April 29, 2016. Testimony submissions continue through the summer, with a pre-hearing conference scheduled for August 25, 2016 and a hearing scheduled for August 31, 2016. On December 29, the Utah Public Service Commission rejected a request from pro-solar groups for a rehearing on the state’s new methodology for determining the costs and benefits of net metering (14-035-114). The framework released in November relies heavily on PacifiCorp’s cost-of-service study, and did not adopt a specific set of costs and benefits to be considered. Lawmakers in Oregon are considering new legislation that would require electricity provided by the state’s largest utilities (Pacific Power and Portland General Electric) to be coal-free by 2030. The bill would also boost the state’s RPS from 25 percent renewable energy by 2025 to 50 percent renewable energy by 2040. Both major utilities support the bill, which includes a safety valve that allows the Oregon PUC to pause the RPS if it threatens service reliability. The House Committee on Energy and Environment will hold a hearing on the proposal in early February, the Statesman Journal reports. In early January, a Hawaii court shot down a lawsuit solar advocates brought against the state PUC, after the commission ended Hawaii’s net metering program. Hawaii Circuit Court Judge Gary Chang determined there was “no abuse of discretion in the PUC’s decision,” the Honolulu Star-Advertiser reports. The Alliance for Solar Choice said it plans to appeal the decision. Five years ago, Vermont set a goal to have renewable energy generation make up 90 percent of the state’s electricity mix by 2050. This week, Gov. Peter Shumlin and the Department of Public Service released an update to the state’s Comprehensive Energy Plan that lays out steps for meeting that goal. “When we set the goal in 2011 of achieving 90 percent renewable energy by 2050, it was ambitious,” Gov. Shumlin said. “Today, after years of work together to chart a new energy future, we see a path to achieve that ambitious goal. But to do so, we must continue to make the necessary and sound investments in our energy future that will save Vermonters money, put Vermonters to work, and help combat climate change.” The CEP includes the following new and more detailed goals: Vermont’s clean energy sector has already seen rapid growth. There is 10 times more solar in the state today than in 2010, and 20 times as much wind energy. State leaders also want to attract innovative, low-carbon solutions. “This CEP embraces the idea of Vermont as a starting point, and as a test bed for new technologies,” the report states. On the regulatory side, the Vermont Public Service Board has opened a docket to consider a request from Green Mountain Power to offer customers net metering above the statutory cap. GMP informed regulators in November that it had met the cap, which is defined as 15 percent of a utility’s peak load. Under the proposal, GMP will continue to accept net-metering applications for systems that are 15 kilowatts and under, and would allow for 7.5 megawatts of community solar projects. This would be a short-term solution while the PSB considers a new net-metering program to begin in 2017. Finally, to boost Vermont’s use of wind and hydro, the PSB recently approved the 1,000-megawatt Clean Power Link Transmission Line to carry renewables from Canada to the Northeast. The high-voltage direct-current transmission line will travel 150 miles under Lake Champlain. Legislators in New Hampshire have started holding hearings on a controversial bill to raise the state’s solar net metering cap, the Union Leader reports. Under current state law, the cap is set at 50 megawatts (for reference, New Hampshire consumes more than 4,000 megawatts on a hot summer day). SB 333 would raise the cap from 50 megawatts to 75 megawatts in the interim, while the Public Utilities Commission conducts a series of hearings to develop a more permanent solution. It’s anticipated that a long-term solution from the PUC would lower net-metering compensation overall. Stakeholders are sharply divided on the issue. Utilities say the current net metering program amounts to a $3 million to $4 million annual subsidy for solar customers at the expense of non-solar customers. At the same time, solar advocates argue that solar is a boon to state’s economy. Gov. Maggie Hassan (D) wrote a letter to lawmakers earlier this month warning that failure to lift the cap could damage a promising new industry in New Hampshire. “New Hampshire’s families and businesses have invested millions of dollars in our local economy by installing solar arrays and other renewable generation facilities that make us more independent and keep our money closer to home,” Hassan wrote. “This consumer-driven progress must continue, and I support efforts to lift the cap on net metering as soon as is possible.” Some solar advocates are pushing for lawmakers to remove the cap altogether. Work continues in Maine on a new distributed solar policy, guided by Office of the Public Advocate's white paper, "A Ratepayer-Focused Strategy for Distributed Solar in Maine.” The solution hinges on entering into a long-term contract with a “Standard Buyer” that will aggregate and monetize the benefits of distributed solar. Regulators must submit a final proposal to the state legislature by January 30. Separately, the Maine legislature is scheduled to take up a bill this week (LD 1413) that calls for suspending the state's renewable energy portfolio requirements if suppliers cannot provide electricity at a 10-cents-per-kWh rate, while still meeting the portfolio requirements, the Sun Journal reports. The author of the bill, Senate President Michael Thibodeau (R), said the law would serve as a “safety valve” to ensure customers don’t overpay for clean energy. Standard electricity rates in Maine are currently below 7 cents per kilowatt-hour. Maine stakeholders are also starting to review the state’s net metering policy as solar approaches the state’s cap at 1 percent of peak load. A spokesperson for Central Maine Power told local NPR affiliate MPBN that continued growth in the rooftop solar sector could put investor profits at risk. On January 21, Governor Andrew Cuomo announced a 10-year, $5 billion Clean Energy Fund to accelerate the growth of solar, wind, energy efficiency and other clean tech industries in New York State. The investment is expected to leverage more than $29 billion in private sector funding, and result in more than $39 billion in customer bill savings over the next 10 years. In his recent State of the State address, Cuomo underscored his commitment to a 50 percent renewable energy mix in the state by 2030. He said he will also “eliminate all use of coal in New York state by 2020.” A policy handbook released along with the speech explains that the governor plans to close the state’s three remaining coal plants and help the coal industry employees transition to jobs in the clean energy sector. In order to meet the state’s renewable energy goals, PSEG has issued an RFP that seeks to procure a total of 210 megawatts of new renewables capacity. The proposal includes an RFP for renewable projects larger than 1 megawatt, and a feed-in tariff for rooftop and carport PV projects greater than 200 kilowatts but less than 1 megawatt. Meanwhile, the New York State Energy Research and Development Authority (NYSERDA) announced the Competitive Greenhouse Gas Reduction Program, which offers $13.5 million for projects that reduce greenhouse gas emissions from the state’s power sector “beyond reductions expected from compliance with existing regulations.” The deadline for proposals is March 31, 2016. NYSERDA also recently announced $6 million in incentives for solar projects in certain NY-Sun Solar Megawatt Block programs. Last week, the Department of Energy Resources announced $2 million in new funding for the Massachusetts Offers Rebates for Electric Vehicles (MOR-EV) program, which grants purchasers and lessees of an electric vehicle a rebate of up to $2,500. The new commitment brings the total allocation for the program to $5.72 million, with 1,606 rebates already issued. Massachusetts has a goal to register 300,000 electric vehicles in the state by 2025. Massachusetts has taken several other steps in recent weeks to boost clean energy deployment in the state. At the end of December, the Department of Energy Resources awarded six western Massachusetts communities $3.1 million in state grants for energy efficiency and clean energy projects. Earlier this month, the Massachusetts Clean Energy Center (MassCEC) announced plans to provide $650,000 in funding for critical service community microgrids -- the Massachusetts version of the NY Prize. The funding commitment is intended to attract private investors to finance later-stage project development. The MassCEC also announced $530,000 in grants this month for four small business incubators in an effort to accelerate the development of cleantech startups in the state. According to the 2015 Massachusetts Clean Energy Industry Report, there are nearly 100,000 employees in the clean energy sector, at more than 6,400 companies across the state. Clean energy jobs rose by 11.9 percent from 2014 to 2015. Overall, clean energy employment in the state has grown by 64 percent since 2010. Opposition continues to mount against “bailout” proposals from Ohio-based investor-owned utilities, Midwest Energy News reports. Last week, the independent power producer Dynegy offered to beat the costs in both FirstEnergy’s (14-1297-EL-SSO) and American Electric Power’s (14-1693-EL-RDR) pending cases by $2.5 billion each over the proposed eight-year agreement term. Two weeks earlier, Exelon Corporation said it could provide the same amount of energy for $2 billion less with 100 percent carbon-free resources. FirstEnergy and AEP are both seeking special deals that would guarantee revenues for their aging coal plants. The utilities claim the agreements are needed to maintain resource diversity and electricity reliability in the state. Both utilities have dismissed Dynegy’s proposal, Cleveland.com reports. "There is no basis for Dynegy's claims of cost savings. They are suggesting that they can provide generation at a lower cost based on inflated assumptions that do not reflect current market realities,” said AEP spokesperson Melissa McHenry. Meanwhile, PJM Interconnection has also filed testimony opposing FirstEnergy’s plan to the extent that a settlement could involve the PUC in PJM’s affairs. An independent market monitor for grid operator PJM filed a claim stating that FirstEnergy’s proposal is inconsistent with competition in PJM wholesale power markets. Like many other states, Ohio is also reassessing its net energy metering policy, with reply comments filed with the PUC earlier this month. One point of contention is how much power will be net-metered under the new policy. The commission’s draft rule proposed limiting production from a net-metered generator to 120 percent of the customer's three-year average consumption at the time of the installation, Smart Grid Today reports. Investor-owned utilities are pushing for a 100 percent limit. Wisconsin’s state assembly has passed a bill that would do away with the state’s moratorium on nuclear power plants, despite opposition from Democrats that warned of dangerous meltdowns and radioactive waste. The measure now heads to the state senate, the AP reports. In late December, Valerie Brader, executive director of the Michigan Agency for Energy, and Dan Wyant, director of the Michigan Department of Environmental Quality, announced modeling results that show Michigan is well positioned to comply with the U.S. Environmental Protection Agency’s Clean Power Plan (CPP). Even without taking action, Michigan would remain in compliance until 2025-2028. The state will launch a dedicated carbon rule website this month. Meanwhile, the Michigan legislature will soon restart its work in updating the state’s 2008 energy laws. Republican majorities in both the House and Senate are pushing to repeal Michigan’s renewable energy and energy efficiency standards in exchange for more detailed planning requirements for utilities, Midwest Energy News reports. Clean energy advocates argue that the standards have been a boon for the state and will help meet Michigan’s CPP requirements. Under the carbon rule, Michigan is required to reduce its emissions 31 percent by 2030. Duke Energy has filed a $1.83 billion, seven-year electrical system upgrade plan in Indiana that includes self-healing system technology, the installation of smart meters, and time-of-use rates. Duke has asked to set a hearing schedule by January 21. Floridians for Solar Choice, a grassroots group championing a ballot initiative to allow for third-party-owned solar in the state, filed briefs with the Florida Supreme Court earlier this month opposing a utility-supported ballot initiative that would maintain the regulatory status quo on solar. Solar supporters say the utility-backed amendment was launched with the sole purpose of confusing voters and countering the successful grassroots campaign to expand solar financing options in Florida. The opposing campaign, led by a group called Consumers for Smart Solar, has raised $5.9 million since last summer -- half of which came from utilities. Floridians for Solar Choice claims the multimillion-dollar “misinformation” initiative has succeeded in preventing Solar Choice from gaining a slot on the 2016 ballot. The pro-solar coalition is now examining options to qualify for the 2018 ballot. “The Floridians for Solar Choice coalition is stronger today than ever before, and we remain unwavering in our focus to open the solar market in the Sunshine State,” said Stephen A. Smith, executive director of the Southern Alliance for Clean Energy, in a statement. “Yes, the utilities have more money, but their positions are on the wrong side of this issue. Deception and unethical manipulation of Florida’s voters will not win in the end. We trust the Supreme Court will see through the monopoly utilities’ chicanery and deny the false petition from ballot access.” As solar advocates reassess their strategy, the Consumers for Smart Solar’s constitutional amendment looks poised to make the 2016 ballot. Separately, the Florida state legislature is considering a bill that would exempt electric and hydrogen vehicles from tolls, certain parking violations, and sales and use tax. On December 20, wind provided 45 percent of Texas’ total electricity needs -- setting a new record for the state -- Scientific American reports. At its peak, wind produced 13.9 gigawatts of power. High output was also sustained for several hours, with energy production above 10 gigawatts for almost the entire day. In other Texas news, on January 19 and 20 the PUC will hold the last two of its four public hearings on Hunt Consolidated’s request to acquire Oncor, the largest T&D utility in Texas. If approved, there are plans to convert Oncor (valued at $17.6 billion) into a real estate investment trust (REIT). Commissioners have raised concerns over the REIT structure, however. On December 23, the public comment period closed in the Pepco/Exelon merger proceeding before the Public Service Commission of the District of Columbia. While many residents continue to oppose the deal, a new package of benefits has won more support for the merger. Ahead of the comment deadline, the two utilities underscored the benefits of the deal, which includes $25.6 million to offset distribution rate increases for residential customers through March 2019, $14 million for a direct bill credit, and $16.15 million for low-income customer energy assistance, among other items. The PSC is expected to rule on the merger in the first quarter of 2016. Policy developments are tracked in partnership with EQ Research, which offers in-depth subscription services covering regulatory developments, legislation and general rate cases in all 50 U.S. states.
News Article | September 14, 2016
The 20-year struggle to create a cohesive Western power grid has entered a new phase, with a strong push by the California Independent System Operator (CAISO) to expand membership to other utilities in the West. CAISO brought together over 800 stakeholders from across the region in Sacramento last week to talk about regionalization. While speakers agreed that the engineering rationale and cost benefits are clear, the political process creates a formidable obstacle to achieving the dream. “The topography of the western grid follows the power flows, but the politics follows all kinds of weird things,” lamented Michael Picker, chair of the California Public Utilities Commission. Advocates of grid expansion are inspired by the success of the energy imbalance market (EIM), which has saved $88 million since it began in 2014. The EIM allows member utilities -- currently the three California IOUs plus Pacificorp and NV Energy -- to share resources to balance the grid. More utilities are scheduled to join over coming years, including Idaho Power and Arizona Public Service. But spurred by legislation (SB350), CAISO is pushing for a more comprehensive regional partnership, extending the market to cover day-ahead bids. This regional system operator (RSO) would facilitate wholesale competition across the region, similar to regional markets in the East. A big driver for the RSO is the growth of wind and solar across the region. Wind and solar made up 14.2 percent percent of California’s supply last year, and are among the least costly sources of new generation. All states except Wyoming and Idaho have renewable energy goals, with both California and Oregon expanding their own targets to 50 percent. A bigger grid would be a low cost way to integrate renewables, by spreading out the variability and tapping the best resources, as well as a way to capture operating efficiencies in general. But the technical benefits of a regional grid will have to overcome the political barriers Governor Jerry Brown was a surprise guest at the symposium, telling the crowd that California is committed to climate action, but acknowledging the difficulties of regional action. “We will continue innovating in this state,” he told the crowd. “We think we’ll get to 50 percent renewables sooner than 2030. To make it work we need a grid that is highly sophisticated.” “It’s true that different states have different needs and perspectives, but the efficiency of a wider grid is unmistakable,” he said. “I hope you can work all that out." The issue is that the CAISO board is appointed by Governor Brown with the advice and consent of the state senate. An expanded regional system operator would include utilities from across the region, and their state regulators will expect to have a say in management The idea reveals the anxieties of stakeholders both in California and in other states. Mark Schiavoni, with Arizona Public Service, pointed to the lingering effects of the 2000-2001 power crisis. “Regulators and politicians fear that California will control my state, and we won’t allow that to happen,” he said. “There are a lot of people with long memories.” Other market models also inspire trepidation. PJM officials have been making presentations in the region to educate people about the market -- to mixed reactions, apparently. “In my neck of the woods PJM is the antichrist,” said Doug Hunter with Utah Associated Municipal Power Systems. This prompted another panelist to ask “if PJM is the antichrist, what is California?” Hunter replied, “It’s potentially the good witch of the West.” A fear from Californians is that an RSO would provide new markets for existing coal plants, undermining California’s climate goals. Travis Ritchie of the Sierra Club said a regional market will make lowest cost the dominant goal, rather than carbon reductions. “I don’t think that’s what California wants,” he said. “I don’t think California will be comfortable putting at risk all the things we’ve done. We’ve done policies that have taken a lot of money and sweat and tears to get right.” But Carl Zichella of NRDC disagreed. “These markets really put the squeeze on legacy plants,” he argued. “The only thing keeping these coal plants alive is a bilateral contract.” Being exposed to competition from lower cost wind and solar would hasten their demise, said Zichella. Steven Greenlee, a spokesman for CAISO, pointed out two additional issues that have to be addressed. First, how will new RSO members pay for the grid? Transmission access charges are paid by generators to use the grid and pay off past investments. Hunter from Utah confirmed this concern. “Our biggest concern is paying for overheads and costs,” he told the audience. “It could quadruple the transmission access charge in Utah.” Resource adequacy is a second concern. California doesn’t have a capacity market to guide future year investments, like PJM and New England have. Instead, it requires regulated utilities to procure 100 percent of load, plus a 15 percent reserve margin. There is no mechanism in CAISO for acquiring future capacity, and therefore no mechanism for the RSO. CAISO has open dockets now on both these issues. The governance issue raised enough concern in the legislature that Gov. Brown announced in August he would go slower, with a possible vote in January. The regional grid concept is hardly new. It began with INDEGO -- the independent grid operator -- that was discussed by 21 Western entities over 20 years ago. “Implementation problems and tariff design disputes led to the official demise of the plan,” according to a 1998 study. Next came RTO West in the late 1990s, just in time for the great Western power crisis in 2000. As prices exploded due to market manipulation by Enron and others, anything related to California and competition became toxic. The idea was revived in 2003 as Grid West, in response to a strong push from FERC for standard market design, championed by then-chair Pat Wood. But the scars from the crisis were too fresh, and a push from the feds was seen as a top-down power grab, and fared poorly in the independent West. There are some major differences this time, according to Doug Larsen, former executive director of the Western Interstate Energy Board. Previous attempts started from scratch, and would have cost hundreds of millions of dollars for software and systems. “This time the CAISO has already developed everything,” said Larsen. “That’s why the EIM was successful -- it was plug and play for new participants.” A second major difference is the maturity of wind and solar power. “They have changed the realities, and more is coming,” he said. “There are real operational reasons to join now, not just a theoretical benefit.” The RSO is not the only option on the table. Seven utilities -- including Xcel, Western Area Power Administration and Basin Electric -- are discussing terms for a Mountain West Transmission Group, a regional entity that would create uniform transmission tariffs in Colorado, Wyoming, and neighboring states. And parties in the Pacific Northwest have been talking about a pooled operation since 2012, through the Northwest Power Pool’s Market Assessment and Coordination Committee. Their footprint includes 14 of the 38 balancing authorities in the Western Interconnect.
News Article | February 23, 2017
A new study, jointly conducted by the California Independent System Operator (CAISO) – the entity responsible for overseeing much of California’s electric grid – First Solar, and the National Renewable Energy Laboratory (NREL), demonstrates the untapped potential of utility-scale solar. The study shows that utility-scale solar can provide key services needed to ensure electric grid stability and reliability – better known as ancillary services – at levels comparable to conventional, fossil fuel driven resources. California needs to reduce reliance on natural gas for ancillary services In CAISO’s market, ancillary services are overwhelmingly provided by natural gas-fired resources, and their share of the pie has been increasing in recent years. This growing reliance on natural gas for ancillary services merits attention for many reasons. As renewables penetration increases, so will the need for ancillary services The findings of the new CAISO- First Solar-NREL study have significant implications for the integration of all renewables (not just solar) on California’s grid. California’s renewable portfolio standard mandates that at least 50% of electric generation be driven by renewables by 2030. Given their inherent variability, as more renewables come online, grid operators will need additional ancillary services to ensure grid stability. In particular, we are likely to see steep increases in ramping needs in the afternoon and evening hours, driven by mid-day solar generation. Solar generation in the middle of the day leads to a drop in net electricity demand, followed by a sharp increase in the afternoon/evening, as people come home from work and school, switch on their lights and appliances, and solar generation falls with the setting sun. This is reflected in the “duck curve” (see figure below) which underscores the need for flexible resources, that are capable of quickly responding to sudden fluctuations in renewable output. CAISO has an ancillary services scarcity pricing mechanism that is triggered when it is unable to procure the targeted quantity of one or more ancillary services. In 2015, CAISO experienced its first ancillary service scarcity event, signaling a mismatch between the demand and supply of ancillary services. To follow up on the study, CAISO plans to identify barriers to the provision of grid services by renewables and explore incentives to harness this potential. This is a welcome next step. Because of the unique characteristics of clean energy resources, there are challenges to their participation in ancillary services markets. What’s more, these markets were not designed keeping renewable resources in mind. Studies such as the CAISO-NREL-First Solar joint study demonstrate that renewables can provide essential grid reliability services needed to support the transition to a cleaner grid. Now, the challenge is to develop the market design features that will allow California to harness these capabilities.
News Article | September 7, 2016
The mix of energy sources used for power generation in California this summer changed from last summer, as renewables and imported electricity offset lower natural gas use. During summer 2016 (June, July, and August), thermal generation (almost all from natural gas) in the area serviced by the California Independent System Operator (CAISO) was down 20% from the previous summer, while generation from hydroelectricity, other renewables, and electricity imports was higher than the same period last year. The overall level of electricity consumption was 2% higher this summer as temperatures were slightly warmer than the previous summer. Hydroelectric generation in CAISO increased from last summer because the West Coast drought situation has improved. According to the U.S. Drought Monitor, 59% of California experienced a severe, extreme, or exceptional drought during July 2016. In contrast, 95% of the state experienced similar conditions last July. These improved water conditions have also helped increase hydroelectric generation in the Pacific Northwest, some of which is imported into CAISO. The addition of new generating capacity has also contributed to the change in generation mix. Data from CAISO indicate that nonhydro renewables, mainly solar and wind, represented 26% of capacity in June 2016. Utility-scale solar photovoltaic (PV) capacity has shown the most growth in CAISO recently, increasing by 1.4 gigawatts (27%) between June 2015 and June 2016. This increase in utility-scale solar capacity has reduced the need for summer thermal generation in CAISO, especially during the daylight hours. California also has added a significant amount of distributed solar PV capacity. EIA’s latest data show that distributed solar PV increased from 2.8 gigawatts in June 2015 to 3.8 gigawatts in June 2016. Distributed generation reduces the amount of electricity that utility-scale power plants need to supply.
News Article | February 6, 2016
California lawmakers expressed concerns in a letter Thursday that allowing a utility of Warren Buffett's Berkshire Hathaway Inc. to join the state's power grid may undermine the state's clean energy goals by connecting it to coal plants. Adding Berkshire Hathaway Energy's PacifiCorp utility to the grid run by California Independent System Operator Corp. would bring with it states "heavily invested in coal and other high greenhouse gas emitting resources," according to the letter to California Governor Jerry Brown.