Total eclipses, solar PV and the grid

Utilities and electric grid coordinators are preparing for a total solar eclipse that is projected to temporarily reduce solar photovoltaic generation across parts of North America this summer. 

The 2017 total solar eclipse will be the first in the U.S. in 26 years (since Hawaii 1991), and the first in the lower 48 states since 1979.  While the duration of the total eclipse across the U.S. will be roughly 93 minutes, some areas in its path will experience up to 95% of the Sun being obscured.

The eclipse is projected to affect solar PV generation.  Solar resources occupy an increasing role in the U.S. electric generating portfolio. Between 2000 and 2016, total U.S. solar capacity increased from 5 megawatts (MW) to 42,619 MW.  But as more solar resources are connected to the grid, the potential impact of an eclipse on grid operations may change.

According to a May 1, 2017 presentation to the Board of Governors of the California ISO, the eclipse is projected to reduce solar output in the CAISO region by 4,194 megawatts, while gross load will increase by 1,365 MW.  Taking into account estimated wind production, the presentation projects a net load increase of 6,008 MW during the eclipse.

The ramp rate, or speed at which supply and demand will change, is also a factor.  The eclipse is projected to diminish solar output by about 70 MW per minute as it approaches totality, and about 90 MW per minute on the return.  By contrast, a typical average ramp rate for CAISO might be 29 MW per minute.  Thus the eclipse is projected to call for a greater degree of fast-ramping or flexible resources, compared to typical operating conditions.

But according to international electric reliability organization NERC, the August 21, 2017 total solar eclipse "is unlikely to cause any reliability issues to the North American bulk power system."  NERC documented its findings in an April 25, 2017 white paper, A Wide-Area Perspective on the August 21, 2017 Total Solar Eclipse.  NERC's report identifies California and North Carolina as the states most likely to experience the greatest impact from solar production fall-off from the eclipse. At the same time, NERC recommends "that utilities in all states perform specific studies of the eclipse’s impact of solar photovoltaic power output on their systems and retain necessary resources to meet the increased electricity demand requirements."  In particular, NERC notes that generation and system operators may greater visibility into utility-scale solar projects than into behind-the-meter or distributed solar photovoltaic resources, highlighting the need to model all scales of solar development.

Following the 2017 eclipse, the next total solar eclipse is projected to cross North America on April 8, 2024.

Vermont issues updated energy plan

Vermont energy regulators have completed an update of key energy and electricity plans for that state. The Vermont Department of Public Service has updated the Vermont Comprehensive Energy Plan (CEP) and Electric Plan, two plans required by law to be complete and adopted by January 1, 2016, and updated every six years thereafter. 

The updated Comprehensive Energy Plan reaffirms Vermont's overall goal of achieving 90 percent of its total energy needs from renewable sources by 2050, adds interim goals (including reaffirming the statutory goal of 25% by 2025), and provides greater detail on Vermont’s pathways towards achieving these goals.  In particular, the plan includes the following new and more detailed goals:

• Reduce total energy consumption per capita by 15% by 2025, and by more than one third by 2050.
• Meet 25% of the remaining energy need from renewable sources by 2025, 40% by 2 035, and 90% by 2050.
• Three end-use sector goals for 2025: 10% renewable transportation, 30% renewable buildings, and 67% renewable electric power.
• Greenhouse gas reduction goals include: 40% reduction below 1990 levels by 2030, and 80% to 95% reduction below 1990 levels by 2050.

Conversion of heat and transportation applications to "highly efficient electric technologies, such as heat pumps and electric vehicles," is one strategy highlighted in the plan.  The plan also includes a 20-year electric plan, based on the principles of least-cost planning, that serves as a basis for Vermont electricity policy.

House subcommittee holds hearing on FERC oversight

Members of the Federal Energy Regulatory Commission testify today before the House Energy & Commerce Committee, Subcommittee on Energy and Power, as that committee considers its oversight of the FERC.

The FERC is an independent administrative agency within the Department of Energy.  Its mandate includes regulating the transmission, reliability, and wholesale sale of electricity in interstate commerce pursuant to the Federal Power Act; the transmission and sale of natural gas for resale in interstate commerce pursuant to the Natural Gas Act; the transportation of oil by pipeline in interstate commerce pursuant to the Interstate Commerce Act; and evaluating proposals to build liquefied natural gas (LNG) terminals and interstate natural gas pipelines, as well as the licensing of non - federal hydropower projects.

As described in a committee background memorandum for today's hearing, the Subcommittee on Energy and Power is exploring whether FERC’s statutory authorities require modernization to reflect current energy realities.  Chief among those statutory authorities are the Federal Power Act and the Natural Gas Act.  The committee memorandum also notes an interest in evaluating "whether FERC is overstepping its existing statutory boundaries to pursue policy goals not intended by Congress."

Specific issues expected to be examined at the hearing include:

• Potential impacts of the U.S. EPA's Clean Power Plan rule on electricity markets, fuel diversity, and electric reliability;
• Commission oversight of organized wholesale electricity markets and their operation
• Risks to the security of the electric grid, including physical and cyber security, geomagnetic disturbances, electromagnetic pulse, and severe weather;
• How to integrate renewable, intermittent resources and distributed generation;
• The role of demand response and other demand-side management technologies in wholesale markets, at issue in the EPSA v. FERC case pending before the U.S. Supreme Court; 
• Electric transmission operations and planning, including implementation of Order No. 1000;
• Natural gas pipeline permitting, LNG siting, and hydropower licensing;
• FERC market manipulation authorities and enforcement practices; and
• FERC’s implementation of the mandatory purchase obligation from qualifying facilities (QFs) under section 210 of the Public Utility Regulatory Policies Act of 1978.

Based on prefiled documents, today's hearing features:

• testimony by FERC Chairman Norman Bay
• testimony by Commissioner Cheryl LaFleur
• testimony by Commissioner Tony Clark
• testimony by Commissioner Colette Honorable

More information about today's hearing can be found on the committee's webpage.

ISO-NE files IRC-related values for 2019-2020

In advance of an upcoming auction to sell electric generating capacity into the New England market, regional grid operator ISO New England Inc. has submitted key information about its plans to the Federal Energy Regulatory Commission.

ISO New England is the private, non-profit entity that serves as the regional transmission organization for New England.  In this role, ISO-NE plans and operates the New England bulk power system, administers New England’s organized wholesale electricity market, and has some responsibility over system reliability.  Reliability can be stated in terms of a loss of load expectation or “LOLE”, which measures how often non-interruptible customers are disconnected.

New England has adopted a capacity market as part of its wholesale electricity market structure.  One aspect of system reliability is ensuring sufficient generating capacity is available to meet consumer demand.  Pursuant to Section III.13 of the Tariff, the ISO administers periodic Forward Capacity Auctions, or FCAs, in order “to procure the amount of capacity needed in the New England Control Area.”

ISO-NE will hold its tenth Forward Capacity Auction in February 2016, covering the 2019-2020 Capacity Commitment Period.  To do so, ISO-NE must first identify how much generation will be needed to meet reliability standards in light of total forecasted load requirements for the New England Control Area and to maintain sufficient reserve capacity to meet reliability standards.  One key value characterizing this need is the "Installed Capacity Requirement" or ICR.  ICR refers to the amount of resources needed to meet the reliability requirements defined for the New England Control Area of disconnecting non-interruptible customers no more than once every ten years.  Under Section 205 of the Federal Power Act, ISO-NE files with the FERC proposed ICR-Related Values for the each auction.

On November 10, 2015, ISO New England submitted to the FERC its Installed Capacity Requirement, Local Sourcing Requirement for the Southeastern New England Capacity Zone, Hydro Quebec Interconnection Capability Credits, and Demand Curve Values for the 2019-2020 Capacity Commitment Period.  In that filing, ISO-NE proposed an Installed Capacity Requirement (net of certain credits for imports) of 34,151 MW.

ISO-NE noted that for the most part, this and other key values were calculated using the same Commission-approved methodology that has been used to calculate the values submitted and accepted for other recent Capacity Commitment Periods. One key difference for the tenth FCA is the inclusion of behind-the-meter photovoltaic (“PV”) resources that are not yet reflected in historical loads as a reduction in the load forecast. This change addresses a requirement imposed by the FERC in its January 2, 2015 Order accepting the Installed Capacity Requirement and related values for the ninth FCA.

ISO-NE asked FERC to accept the proposed ICR-Related Values for the tenth FCA to be effective on January 9, 2016 (i.e. 60 days after filing), to enable their use in the tenth FCA scheduled for February 2016.

NH explores electric grid modernization

New Hampshire regulators are considering whether and how to modernize the state’s electric grid. In a recently opened investigation, the New Hampshire Public Utilities Commission seeks to educate stakeholders about grid modernization and to explore to what extent that grid modernization is workable in New Hampshire.

Last year, the New Hampshire Office of Energy & Planning issued its 10-Year State Energy Strategy.  In that document, the administration called for "a more flexible and resilient electric grid to support new technologies, increase consumer participation in energy management, and fortify our resiliency in the face of price and supply volatility and extreme weather events."  The first step identified in the Energy Strategy was to open a PUC docket on grid modernization:

The electric grid is aging, and changing consumer use patterns, a new generation mix, and increased threats from severe weather events require a more modern system. The New Hampshire Public Utilities Commission should open a docket to determine how to advance grid modernization in the state. In light of the potential breadth of the topic, which could include dynamic pricing, better consumer access to technology, and even rethinking the role of utilities, an investigation or information ‐ gathering proceeding may be an appropriate first step. This less formal proceeding would give all stakeholders a chance to learn about grid modernization and could inform the specific areas that should be pursued within future dockets. This would allow the PUC and stakeholders to determine which approaches will benefit New Hampshire consumers, and when and how they should be implemented.

Earlier this summer, the New Hampshire legislature enacted House Bill 614, implementing the recommendations in the Energy Strategy.  As Governor Hassan noted in her signing statement, the bill requires the Public Utilities Commission to "begin a process focused on modernizing our electric grid to ensure that we are prepared for an innovative energy future and to set an electricity peak time reduction goal, which can help lower the high costs of producing electricity when demand is greatest."

That process is now underway.  The New Hampshire Public Utilities Commission opened its investigation by order dated July 30, 2015.  The Commission gave interested parties until September 17, 2015 to provide comment on the definition, or elements, of grid modernization that should be included in its investigation.  The Commission directed its staff to schedule a technical session following a review of comments submitted, and to develop a procedural schedule for the rest of the case.

NYISO solar study announced

Solar power is booming in the U.S. -- but how will growth in solar photovoltaic generating capacity affect the electricity grid?  The operator of the state of New York's electric grid has announced a study of the potential for growth in solar power resources to determine their impact on grid operations over the next 15 years.

Solar panels recently developed in a farm field in Massachusetts.

The New York Independent System Operator (NYISO) operates New York State's high-voltage transmission network, runs the state's wholesale electricity markets.  NYISO also evaluates trends in utility infrastructure development and usage, and what changes in these patterns imply for future infrastructure needs.

One such trend is the recent rapid growth in installed solar electric generating capacity.  In New York, a state government initiative known as NY-Sun aims to reduce solar installation costs by stimulating demand and increasing the number of solar PV systems installed in the state.  The NY-Sun program envisions the installation of more than 3,000 megawatts of customer-sited solar capacity by 2023, supported by about $150 million in annual state funding for solar PV projects.  Already, in the first two years of NY-Sun, a total of 316 megawatts of solar electric has been installed or is under contract.

Unlike standalone utility-scale solar development, the solar buildout directly triggered by the NY-Sun program will occur “behind the meter” — that is, on the customer's side of the utility meter, as opposed to a typical power plant sited remotely from customer load.  Nevertheless, increased consumption of power produced by distributed generation might affect NYISO's load forecasts or grid operations.  So too might the collective impacts of many generators with variable but correlated output.

To prepare for this future, NYISO has announced a "solar study" to evaluate the growing impact of sun-powered generation.  The study will focus on the following objectives:

• Developing solar forecasting tools and preparing 15-year forecasts of solar PV capacity for each of the 11 load zones in New York State
• Researching how other independent system operators and regional transmission organizations have integrated solar resources into their grids
• Evaluating solar generation variability and its impact on customer load served by the NYS electric systems.
• Reviewing operational impacts of various levels of solar and wind resources.

The results of NYISO's solar study are expected to be released in a report later this year.

Report: climate change poses risks to US energy sector

Climate change poses significant risks to U.S. energy infrastructure, and the reliability and cost of the services it enables, according to a report released yesterday by the U.S. Department of Energy.

The report - U.S. Energy Sector Vulnerabilities to Climate Change and Extreme Weather Report (4.2MB PDF) was developed as part of the Obama Administration’s efforts to support national climate change adaptation planning and to advance the U.S. Department of Energy’s goal of promoting energy security. These efforts are embodied by the Interagency Climate Change Adaptation Task Force and Strategic Sustainability Planning process established under Executive Order 13514.

The report is predicated on the findings that the U.S. climate is changing, and that these changes impact energy resources and infrastructure. As the report states, "Climatic conditions are already affecting energy production and delivery in the United States, causing supply disruptions of varying lengths and magnitude and affecting infrastructure and operations dependent upon energy supply." The report provides over 30 recent examples of energy infrastructure adversely impacted by climate change-related events such as power plant outages due to high temperatures or low water availability, storm damage to transmission lines, oil wells, pipelines and generators, and flooding-related disruption of fuel transportation systems.

Building on these findings, the report identifies a broad set of risks posed by climate trends, including increasing temperatures, decreasing water availability, and increasing storms, sea level rise, and flooding, as well as the current and potential future impacts of these climate trends on the U.S. energy sector. According to the report, each of these trends will independently, and in some cases in combination, affect the ability of the United States to produce and transmit electricity from fossil, nuclear, and existing and emerging renewable energy sources. These changes are also projected to affect the nation’s demand for energy and its ability to access, produce, and distribute oil and natural gas.

In particular, significant risks identified include:

• Thermoelectric power generation facilities are at risk from decreasing water availability and increasing ambient air and water temperatures, which reduce the efficiency of cooling, increase the likelihood of exceeding water thermal intake or effluent limits that protect local ecology, and increase the risk of partial or full shutdowns of generation facilities
• Energy infrastructure located along the coast is at risk from sea level rise, increasing intensity of storms, and higher storm surge and flooding, potentially disrupting oil and gas production, refining, and distribution, as well as electricity generation and distribution
• Oil and gas production, including unconventional oil and gas production (which constitutes an expanding share of the nation’s energy supply) is vulnerable to decreasing water availability given the volumes of water required for enhanced oil recovery, hydraulic fracturing, and refining
• Renewable energy resources, particularly hydropower, bioenergy, and concentrating solar power can be affected by changing precipitation patterns, increasing frequency and intensity of droughts, and increasing temperatures
• Electricity transmission and distribution systems carry less current and operate less efficiently when ambient air temperatures are higher, and they may face increasing risks of physical damage from more intense and frequent storm events or wildfires
• Fuel transport by rail and barge is susceptible to increased interruption and delay during more frequent periods of drought and flooding that affect water levels in rivers and ports
• Onshore oil and gas operations in Arctic Alaska are vulnerable to thawing permafrost, which may cause damage to existing infrastructure and restrict seasonal access, while offshore operations could benefit from a longer sea ice-free season
• Increasing temperatures will likely increase electricity demand for cooling and decrease fuel oil and natural gas demand for heating

Looking on the brighter side, the report notes that while climate change will, on balance, create challenges and costs for the energy sector, there are potential benefits to the energy sector as well. Examples include reduced average heating loads during the winter in parts of the United States, such as New England, and the opening of new regions to offshore oil and gas exploration due to shrinking sea ice cover in the Arctic. The report also covers adaptation actions underway, as well as other major opportunities to prepare for climate change through adaptation. Nevertheless, on balance, the report finds that the magnitude of the challenge posed by climate change on an aging and already stressed U.S. energy system could outpace current adaptation efforts, unless a more comprehensive and accelerated approach is adopted. Will the U.S. follow that path? What measures will it include? Will it make a difference?