Vol. 5: Issue 5 | December 2017
While the details of the program still need to be worked out, New York’s energy storage bill has been signed into law, making it the fourth state to set energy storage mandates, along with California, Massachusetts and Oregon. Although maybe it won’t be a mandate, after all. While the Legislature passed the bill in June, Governor Andrew Cuomo (D) waited nearly five months to add his signature, and did so only with guarantees that the Legislature would pass amendments in the coming session to remove specific deployment requirements and allow the Public Service Commission (PSC) to determine the right policy approach. Using a storage roadmap study developed by the New York State Energy Research and Development Authority as its starting point, the PSC is expected to develop its recommendations for an energy storage program by the end of 2018.
New Jersey has filed two identical bills (S.B. 3560 and A.B. 5330) that would offer financial support to nuclear plants. The proposed legislation would provide Nuclear Diversity Certificates (NDCs) to nuclear plants in—and possibly out of—the state, which contribute positively to the state’s electric diversity and air quality, and which provide documentation to support claims that they would shut down operations without support. The policy would function similarly to Zero Emissions Credits (ZECs) in Illinois and New York, although it comes with certain consumer protections that limit ratepayer exposure, while estimates also peg the rate of compensation to be over a third lower than the programs in Illinois and New York The average New Jersey ratepayer could pay between $2.50 to $3.30 more on their monthly electric bill through a charge to cover a program that could cost around $300 million annually. There has been some controversy over the timing, however, as a lame duck legislature and a lame duck governor consider legislation that could have a major impact on the state’s electric system and the regional wholesale market, PJM Interconnection.
Pennsylvania Governor Tom Wolf (D) signed legislation that will ensure solar renewable energy credits (SRECs) are produced locally and stabilize the state’s SREC market. House Bill 118 changes solar project eligibility under the state’s Alternative Energy Portfolio Standards, allowing only projects located in Pennsylvania to receive SRECs. The bill applies only to new solar PV projects, and includes grandfathering provisions to protect certain systems already certified as eligible. Previously, projects located anywhere in the PJM region were eligible for SRECs, however, credits generated in-state could not be sold outside Pennsylvania. This created a surplus of solar in Pennsylvania and depressed the value of the credits. In 2010, SRECs prices were at $325/megawatt-hour (MWh), but dropped as low as $3.50/MWh in late 2017. Wolf also announced recently that the state’s Solar Energy Program guidelines were updated to include grants in addition to loans. The program offers nearly $30 million in funding to promote solar energy in Pennsylvania.
While the Federal Aviation Agency (FAA) is working to establish more robust federal regulations for unmanned aerial systems (UAS), states continue to take the matter into their own hands when addressing drones. In 2017, at least 38 states considered legislation related to drones, with 17 states passing 23 measures. Florida, Nevada and Texas passed measures related to drone use near critical infrastructure—either establishing restrictions and assigning penalties, or updating laws by adding additional facilities where drones are prohibited from flying. Ten states have enacted laws restricting drone use near critical infrastructure. In addition, the FAA has announced a UAS Integration Pilot Program that will provide an opportunity for state, local and tribal governments to partner with private entities to test new and expanded commercial drone operations. A solar energy company, SunPower Corp., is the first to take part in another FAA program called Low Altitude Authorization and Notification Capability, which allows the company to fly its drones near four airports with only seconds of notification to air traffic officials. Waivers to fly near airports can take up to three months normally, but SunPower will be able to deploy its drones quickly to survey potential project sites and optimize layouts.
The Vermont legislative committee on Administrative Rules approved new noise limits on future wind development. In accordance with Senate Bill 260 enacted in 2016, the Public Utility Commission established the new noise limits that restrict wind projects to 39 decibels during the day and 42 decibels at night, measured 100 feet from residences near wind turbines. The committee reviewed the limits to ensure that they met the intent of the bill before approving them. Opponents of large-scale wind energy viewed the decision as a victory. Although the noise limits are not the most restrictive in the country, wind supporters anticipate the new limits will be a barrier to future wind development.
Innovation can be costly, and the failed coal-gasification facility at the Kemper power plant in Mississippi is no exception. The Mississippi Power project, which aimed to gasify lignite coal to burn it more cleanly, has more than doubled in cost—to $7.5 billion—trying to get the technology to work. In June, the Mississippi Public Service Commission ordered the utility to abandon coal gasification and run on natural gas. Now PSC staff have reached an agreement with the utility that will reduce the amount recovered from ratepayers, with Mississippi Power and its parent company, Southern Company, expected to absorb billions in losses. The PSC will need to approve the deal in January.
After 16 years of effort, Cape Wind canceled its plans for a 468-megawatt (MW) offshore wind farm located five miles from Cape Cod, Mass. The project began in 2001 and developers were slated to install 130 3.8-MW wind turbines that would have supplied power to Martha’s Vineyard, Nantucket and other Cape Cod Islands. The project faced many years of delays, setbacks and opposition. Most notably, in 2015, two utilities, NStar and National Grid, cancelled their power purchase agreements for 460 MW of power from the project. Opponents were concerned about the project’s potential effects on navigation, marine life, birds, tourism and the local economy, while project supporters had hoped that it would create jobs and launch the country’s offshore wind energy industry. Cape Wind also terminated its Bureau of Ocean Energy Management (BOEM) lease on the 46-square mile area. Issued in 2010, the lease was the nation’s first commercial lease to construct and operate an offshore wind facility. Cape Wind’s project could have helped utilities to comply with Massachusetts’ 1.6 gigawatt offshore wind procurement mandate established by legislation in 2016.
The debate over net metering has been playing out in Arkansas for months. State regulators have been tasked with determining the future of the policy and recently held proceedings to hear comments from solar stakeholders, environmental groups, utility interests and public service commission staff. The proceeding follows requirements included in House Bill 1004, enacted in 2015, that called for net metering rates that recover utilities’ full cost of service within each customer class, while taking possible costs and benefits into account. The Public Service Commission (PSC) has several options it can take, including reducing compensation under net metering, continuing with the existing compensation rate and considering pilot programs and rates. The PSC also can postpone its decision until solar deployment in the state reaches a greater level—currently fewer than 1,000 customers participate in net metering in Arkansas. Solar supporters hold that compensation under net metering should be kept at the retail rate, while opponents are advocating for two-channel billing and lowering compensation rates under net metering to address potential cost shifts between net metered and non-net metered customers. The PSC could make a decision in early 2018. Additionally, the U.S. Department of Energy is conducting a study weighing the costs and benefits of net metering that was ordered by Congress as part of DOE’s Grid Modernization Initiative.
The California Public Utilities Commission released its annual report on the Renewables Portfolio Standard (RPS), which concluded that the program is ahead of schedule. The state’s current RPS requirements are 33 percent of retail sales by 2020 and 50 percent by 2030—one of the most ambitious in the country. As of this year, the state’s three large investor-owned utilities—Pacific Gas and Electric (PG&E), San Diego Gas & Electric (SDG&E) and Southern California Edison(SCE)—have surpassed their interim targets and are expected to exceed their 2020 requirements. PG&E has reached 32.9 percent of sales from renewable energy generation, SCE has reached 28.2 percent and SDG&E has reached 43.2 percent. The CPUC report also concluded that the aggressive RPS program contributed to decreasing the cost of renewable energy. The report found that between 2008 and 2016, the price of utility solar contracts decreased by 77 percent, and between 2007 and 2015, the price of wind contracts decreased by 47 percent. This year, the Legislature advanced a bill to increase the state’s RPS to 100 percent by 2045. However, the bill ultimately died in committee.
What started with a few states introducing policies to provide financial support to nuclear plants has now grown into a nationwide debate over how to accurately price electricity in the marketplace. In August, Energy Secretary Rick Perry asked the Federal Energy Regulatory Commission (FERC) to consider a Grid Resiliency Pricing Rule that would force markets to establish rate tariffs to allow coal and nuclear plants to recover costs beyond wholesale prices. The suggestion has been met with considerable skepticism, even from sitting FERC commissioners. But in November, PJM Interconnection, the market operator that serves 65 million people across the Mid-Atlantic, released a price formation proposal that would allow “inflexible” units, like nuclear and coal, to set prices, potentially raising costs in the region by up to 5 percent—something that could help at-risk plants increase revenues. The proposal will be discussed with stakeholders in the coming months and filed for approval with FERC in late 2018.
And if electricity market reform wasn’t big enough, FERC is also working its way through more than 40 pipeline proposals. Many of these projects are near the East Coast, where the issue is particularly fractious. In October, FERC approved two of the more controversial pipelines—the Atlantic Coast and Mountain Valley projects, both of which would move natural gas out of Appalachia. Both pipelines still need state permits—a sticking point for three FERC-approved pipelines in New York. The state has used water permit denials to thwart developers, who are challenging those decisions in court. FERC is expected to continue reducing the backlog of pending pipeline projects, some of which filed applications two years ago.
Congress introduced legislation in early December that would make changes to the Public Utility Regulatory Act. The nearly 40-year-old act requires utilities to purchase energy from “qualified facilities” that produce energy at the avoided cost—which is equal to or below what the utility would have to pay for a traditional power plant. House Resolution 4476 would lower the threshold requiring utilities to enter into contracts with small power producers and allow state regulators to waive a utility’s mandatory purchase obligation if the power producer has access to a competitive power market or if the producer’s electricity is not needed by the utility. Bill supporters view the legislation as an opportunity to better align PURPA with modern-day realities. Although renewable energy supporters agree that it is necessary to review PURPA, given today’s changing conditions, they fear that the bill could harm renewable energy development and favor utilities. PURPA has also been widely discussed among states, and several have taken legislative or regulatory action to modify state interpretation of the act. Recently, the Michigan Public Service Commission set a new avoided cost formula for Consumers Energy Co. to use when buying power under PURPA.
The Bureau of Land Management (BLM) and the U.S. Department of Energy (DOE) each approved major transmission lines—the Northwest-Intermountain West Line and the Northern Pass Line. The Northwest-Intermountain West Line will stretch 300-miles and improve electric transmission from the Pacific Northwest to the Intermountain West. The 500-kilovolt high-tower line will run from Boardman, Ore. to the Hemingway Substation near Melba, Idaho, and will have a capacity to transport approximately 1 gigawatt of electricity. BLM anticipates that the project will allow for more intermittent, renewable energy resources—such as wind and solar—to connect to the grid. The project may also provide a potential route for electricity generated from several planned wind projects in the region. Construction is expected to begin in 2021 and will take about three years to complete. The DOE-approved Northern Pass Line will be a 192-mile system that will run above and below ground and will bring electricity from hydropower plants in Quebec to New England. Construction on the project could begin as early as 2018. While the project has been approved by DOE, the New Hampshire Site Evaluation Committee still has an opportunity to weigh in. Project developers estimate that the Northern Pass line will create more than 2,600 jobs and provide more than $600 million in energy cost savings for New England customers.
The U.S. Department of Transportation (DOT) announced in December that it will rescind a mandate requiring railroads to add advanced, electronically controlled pneumatic (ECP) braking technology to certain trains hauling flammable liquids. DOT cited a study conducted by the National Academy of Sciences that was unable to conclude that ECP brakes were any safer than other braking systems in an emergency. The move has been applauded by rail and energy industry groups that have questioned the data that ECP braking systems are safer. Other rail safety advocates, however, question the move and cite a series of recent train crashes and explosions, including a July 2013 oil train derailment that killed 47 people in Lac-Mégantic, Quebec.
This year’s NCSL Capitol Forum took place Dec. 10-13 in Coronado, Calif. The meeting brought together top national experts to discuss several important policy topics of interest to state legislators. NCSL’s Task Force on Energy Supply met Dec. 10 to discuss a variety of energy-related issues, including the response to recent natural disasters and the impact on critical energy infrastructure, how the U.S. can remain competitive in a rapidly global energy market, advancements in wind energy technologies, recent actions related to the future of U.S. nuclear waste storage, and more. View the agenda and presentations from the meeting.
As threats to the U.S. electric grid grow, states and federal agencies attempt to strike a balance between maintaining open governance and providing adequate security to the systems and infrastructure that are critical to everyday life. More than half of state legislatures and the U.S. Congress have created open government law exemptions that restrict the release of sensitive information about critical infrastructure. View NCSL’s latest web brief to read more about exemptions and state statutes pertaining to open government laws.
U.S. waters contain an estimated 2 terawatts of potential offshore wind capacity—equivalent to approximately twice the capacity of current U.S. electricity generation, and enough energy to power roughly 1.6 billion homes. Increased global adoption and technological advances have driven state policymakers to explore offshore wind development in domestic waters. A new LegisBrief explores the opportunities and challenges presented by offshore wind and discusses state efforts to encourage offshore wind development.