Feds settle on final 2011 Southwest blackout penalty

Friday, May 29, 2015

Over four years after a major 2011 power outage in Southern California and parts of the Southwest, federal energy regulators have approved the sixth and final settlement of penalties for violations of law and reliability standards

After the September 8, 2011 blackout left more than 5 million people in Southern California, Arizona and Baja California, Mexico, without power for up to 12 hours, the Federal Energy Regulatory Commission began investigating what had happened.  After conducting that investigation jointly with electric reliability organization North American Electric Reliability Corporation (NERC), in an April 2012 report FERC found that the outage started when a 500-kilovolt transmission line owned by utility Arizona Public Service Company tripped.

The FERC continued its investigation into the 2011 Southwest blackout after its staff report was made public.  It identified six entities believed to have been involved: Arizona Public Service Company, the California Independent System Operator, the Imperial Irrigation District, Southern California Edison, the Western Area Power Administration, and the Western Electricity Coordinating Council Reliability Coordinator.

FERC's enforcement process typically offers the accused an opportunity to agree to a stipulation of facts (for example, that the utility violated a particular reliability standard) and to pay a civil penalty and perform mitigation measures.  In its enforcement actions related to the 2011 Southwest blackout case, all six entities ultimately agreed to stipulations and penalties that were accepted by the Commission.

In July 2014, the FERC accepted Arizona Public Service's stipulation with NERC and FERC's Office of Enforcement, under which APS agreed to pay $3.25 million and improve its system reliability.  In August 2014, California's Imperial Irrigation District agreed to a $12 million fine.  Utility Southern California Edison agreed to a $650,000 fine in October.  In December, FERC settled with federal power marketing agency Western Area Power Administration with no penalty.  Grid operator California ISO agreed to pay $6 million.

This week the FERC announced a settlement with Western Electricity Coordinating Council.  WECC promotes grid reliability in the Western Interconnection, a broad area of the western United States.  According to the FERC order, FERC enforcement staff and NERC determined that WECC as the Reliability Coordinator violated nine requirements of the Interconnection Reliability Operations and Coordination (IRO) and the Facilities Design, Connection and Maintenance (FAC) groups of Reliability Standards.  Enforcement staff and NERC concluded that WECC failed to identify and prevent violations of system operating limits and Interconnection Reliability Operating Limits and was unaware of the impact of protection systems, and used an inadequate system operating limit methodology that exposed its area to cascading outages.

As a result, the settlement calls for WECC to pay a $16 million civil penalty.  $3 million of this will be split evenly between the U.S. Treasury and NERC, and $13 million will be invested in reliability enhancement measures that go above and beyond mitigation of the violations and the requirements of the Reliability Standards.  WECC and its successor as Reliability Coordinator, Peak Reliability, also agreed to mitigation and reliability activities and to submit to compliance monitoring.

FERC has described the WECC settlement as marking "final resolution" of the investigation by FERC Enforcement staff and NERC into the 2011 Southwest blackout.

Vermont resets renewable energy program

Tuesday, May 26, 2015

The Vermont legislature has voted to create the state's first renewable energy standards for electric utilities.  The bill, H.40, changes the way Vermont encourages the generation and use of renewably derived electricity.

Like most states, Vermont law has encouraged renewable energy development for over a decade.  In 2005 the state legislature created the Sustainably Priced Energy Enterprise Development, or SPEED, program to promote renewable energy development.  Under SPEED, the state encouraged its 18 utilities to enter into long-term contracts for power from renewable energy sources, with a goal that utilities source 20% of their supply from qualifying SPEED resources by 2017.  The SPEED program's goal has been to promote the development of in-state energy sources which use renewable fuels to ensure that to the greatest extent possible the economic benefits of these new energy sources flow to the Vermont economy in general and to the rate paying citizens of the state in particular.

But between recent controversy over possible "double counting" of renewable energy attributes produced and sold by Vermont utilities, and perennial interest in refining state energy policy, this year the Vermont legislature pursued H.40 as an attempt to fix Vermont's renewable energy programs.  H.40 will replace the SPEED goals with a Renewable Energy Standard and Energy Transformation, or RESET, program.  The RESET program includes a renewable portfolio standard requiring that 55 percent of a utility’s electricity come from renewables, including large-scale hydro power, by 2017, increasing 4 percentage points every three years until reaching 75% by 2032.

The bill also gives utilities an entrance into financing thermal efficiency for heating and cooling.  It will require utilities to offer incentives and on-bill financing for projects like weatherization and heat pumps.  To monitor and protect against impacts to customer rates, H.40 requires annual reports starting in 2018 on the RESET program's impact on electric rates, including 10-year forward projections.  It also allows utilities to seek waivers if they can show that compliance would increase electric rates.
Previous efforts to institute a mandatory renewable energy standard in Vermont were not successful, but this year versions of H.40 have now been approved by both chambers of the state legislature.  The Vermont House of Representatives passed H.40 on March 10, and the Senate approved an amended version on May 15.

Coal power plants retiring in 2015

Thursday, May 21, 2015

The U.S. portfolio of electric power plants will continue to shift in 2015, according to a federal assessment projecting that nearly 16 gigawatts (GW) of generating capacity will retire in 2015.  Most of the capacity to be retired this year is coal-fired generation.  This continues a multi-year trend away from coal, and toward natural gas and renewable resources.

According to the U.S. Energy Information Administration, nearly 16 GW of generating capacity is expected to retire in 2015.  Of this, 81% (12.9 GW) is coal-fired generation.  Generator retirements are heavily composed of coal-fired generation, split between bituminous coal (10.2 GW) and subbituminous coal (2.8 GW).  Most of this retiring coal capacity is found in the Appalachian region, with slightly more than 8 GW combined in Ohio, West Virginia, Kentucky, Virginia, and Indiana.

New environmental regulations and struggles to remain cost-competitive explain most of these retirements.  This year, the Environmental Protection Agency's Mercury and Air Toxics Standards (MATS) take effect.  MATS requires existing large coal- and oil-fired electric generators to meet stricter emissions standards by retrofitting the units with new emissions control technologies.  While some units have been granted extensions to operate through April 2016, some power plant operators are choosing to retire units instead of making cost-prohibitive investments in pollution control.

Most of the coal-fired units slated for retirement are smaller and operate at a lower capacity factor than average coal-fired units in the United States.  According to EIA, the to-be-retired units have an average summer nameplate capacity of 158 MW, just 60% as big as the 261 MW average for other coal-fired units.  In 2014, the average capacity factor for all coal units was 61%, but the subset of coal units retiring in 2015 had an average capacity factor of just 36%.  The relatively small size and low capacity factor of these power plants make it harder for them to compete economically against other generation sources.  This competition is especially difficult if sufficient natural gas-fired generating capacity is available, as the cost of natural gas has fallen to levels not seen since 2012.

The coal capacity retiring in 2015 accounted for 1.6% of total U.S. generation during 2014.  At the same time, electric generating companies expect to add more than 20 GW of utility-scale generating capacity to the power grid.  This new capacity is dominated by wind (9.8 GW), natural gas (6.3 GW), and solar (2.2 GW), which together compose 91% of expected new capacity in 2015.

House subcommittee considers reliability draft

Tuesday, May 19, 2015

A congressional committee is considering legislation to assure reliability and security of the U.S. electricity grid.  The House Subcommittee on Energy and Power's discussion draft includes a series of provisions designed to harden the grid against disturbance.

To understand the discussion draft, you must first understand its context.  2015 is a time of great change for the U.S. electricity system.  The grid continues to shift away from coal-fired generation and towards use of natural gas and renewable energy sources.  New environmental regulations affecting power plants are taking effect.  Smart grid technology now enables real-time communication and coordination between supply and demand for electricity, but creates millions of potential access points for hackers to target the grid.  Meanwhile utilities plan to invest more than $60 billion in transmission infrastructure over the next decade. 

Faced with these shifts, the House Subcommittee on Energy and Power held a hearing today on a "discussion draft" of proposed measures to strengthen grid reliability, security and readiness to survive disturbance.  The discussion draft includes measures that would:
  • Resolve conflicts between choosing whether to comply with an emergency order from the Department of Energy or violate environmental obligations;
  • Require the Federal Energy Regulatory Commission to complete an independent reliability analysis of any proposed or final major federal rule that affects electric generating units;
  • Direct the Secretary of Energy to develop and adopt procedures to enhance communication and coordination between governmental entities and the private sector to improve emergency response and recovery;
  • Give the Secretary of Energy powers to address grid security emergencies, and facilitate information sharing;
  • Require the Energy Department to submit a plan to Congress evaluating the feasibility of establishing a Strategic Transformer Reserve for the storage, in strategically-located facilities, of spare large power transformers in sufficient numbers to temporarily replace critically damaged large power transformers;
  • Direct DOE to create a voluntary Cyber Sense program to identify cyber-secure products and technologies intended for use in the bulk-power system, like controls and SCADA systems;
  • Directs state public utility commissions and utilities to improve grid resilience and promote investments in energy analytics technology to increase efficiencies and lower costs for ratepayers while strengthening reliability and security; and
  • Require FERC to work with each regional transmission organization to encourage a diverse generation portfolio, long-term reliability and price certainty for customers, and enhanced performance assurance during peak period.
As noted in the opening statements of Chairmen Ed Whitfield and Fred Upton, elements from this discussion draft may be included in a bipartisan energy bill expected to emerge from the House committee later this session.

FERC proposes geomagnetic disturbance reliability standard

Thursday, May 14, 2015

Is the U.S. electric grid ready for solar storms and other geomagnetic disturbances?  Today the Federal Energy Regulatory Commission proposed approving a new reliability standard for the grid to address its vulnerability to these hazards.

A utility substation near Treasureton in southeast Idaho.

Periodic activity on the Sun's surface sends powerful waves of energetic particles toward the Earth.  These solar events can distort the Earth's magnetic field, affecting the flow of electricity on Earth.  While serious geomagnetic disturbances are expected to be infrequent, they can cause blackouts and damage key utility infrastructure.

The Federal Energy Regulatory Commission has jurisdiction over the reliability of the U.S.'s bulk electric power system.  To this end, it has designated the North American Electric Reliability Corporation (NERC) as the nation's electric reliability organization.  In May 2013, FERC directed NERC to develop and submit new standards for protecting the grid against geomagnetic disturbances (Order No. 779)

FERC and NERC have proceeded in a two-stage process.  First, in June 2014 FERC approved a standard on implementation of operating plans, procedures and processes to mitigate effects of geomagnetic disturbances (Order No. 797).

Reserved for the second stage were further requirements that transmission planners and owners assess the vulnerability of their systems to a theoretical benchmark event.  NERC subsequently proposed such a standard, calling for an evaluation of what would happen in a “one-in-100-year” benchmark event.

In a Notice of Proposed Rulemaking issued today, the FERC proposes to largely adopt NERC’s proposed second-stage standard.  The standard would require covered entities to have system models needed to complete vulnerability assessments, to have criteria for acceptable steady state voltage performance during a benchmark event, and to complete a vulnerability assessment once every 60 calendar months. If the assessment indicates that a system does not meet the performance requirements, the entity would have to develop a corrective action plan addressing how the requirements will be met.

The proposed rulemaking would direct NERC to further modify its standard to require that the study and benchmarking of geomagnetic disturbance events is based on a more complete set of data and a reasonable scientific and engineering approach.

Comments on today’s Notice of Proposed Rulemaking are due 60 days after its publication in the Federal Register.

Geomagnetic disturbances, and their impacts to the grid, are a hot topic in energy regulation at the present. States are considering laws regulating utility readiness for and response to geomagnetic disturbances; for example, next week the Maine Legislature’s Joint Standing Committee on Energy, Utilities, and Technology will consider LD 1363, An Act To Secure the Maine Electrical Grid from Long-term Blackouts.

ISO-NE projects slow growth in electricity demand

Wednesday, May 13, 2015

New England's electric grid operator predicts slow growth in annual energy usage in the region over the next decade, with slightly quicker growth in peak demand.

A Maine power plant -- the ecomaine Waste-to-Energy plant in Portland, Maine.

ISO New England, Inc. develops an annual long-term load forecast using factors including state and regional economic forecasts and 40 years of weather history.  Its most recent baseline forecast projects a compound annual growth rate of 1.0% in total energy usage in New England from 2015 to 2024.  For 2015, ISO-NE projects 138,745 gigawatt-hours (GWh) of load, growing to 152,280 GWh in 2024.

ISO-NE's forecast also projects future peak demand, a measure of the highest amount of electricity used in a single hour in New England.  Often, peak demand drives the need for constructing and maintaining power plants and transmission lines (and energy efficiency investments).  According to the latest ISO-NE forecast, New England's peak electricity demand is projected to rise by a compound annual growth rate of 1.3%, from 28,395 MW this year to 31,905 MW in 2024.

These baseline projections for future peak demand and energy usage take into account load reductions that can be expected from future installations of distributed solar photovoltaic facilities.  ISO-NE has prepared a separate Distributed Generation Forecast to estimate the load-reducing effects of distributed solar facilities developed as a result of state policy goals.

ISO-NE's baseline projections do not account for significant energy-efficiency savings, neither those committed through the region’s three-year Forward Capacity Market (FCM) nor future savings that can be expected beyond the FCM timeframe.

Report on Maine renewable portfolio standard in 2013

Wednesday, May 6, 2015

The Maine Public Utilities Commission has issued a report on Maine's use of renewable electricity in 2013.  The report shows the impact of Maine's renewable portfolio standard, a state law requiring electricity suppliers to source specified percentages of their electricity from “new” renewable resources.

Since 2000, Maine law has required electricity suppliers to include renewable energy in their portfolio of supply sources.  Maine’s original electric industry restructuring legislation included a 30% eligible resource portfolio requirement. The eligible resource portfolio requirement, now referred to as Class II, mandated that each retail competitive electricity supplier meet at least 30% of its retail load in Maine from “eligible resources.”  Eligible resources are defined in statute as either renewable resources or efficient resources.  Renewable resources are defined in statute as fuel cells, tidal power, solar arrays, wind power, geothermal installations, hydroelectric generators, biomass generators, and municipal solid waste facilities. Renewable resources may not exceed a production capacity of 100 megawatts. “Efficient” resources are cogeneration facilities that were constructed prior to 1997, meet a statutory efficient standard and may be fueled by fossil fuels.

During its 2007 session, the Maine Legislature enacted an Act to Stimulate Demand for Renewable Energy.  This Act established a new "Class I" standard, requiring Maine electricity suppliers to source specified percentages of their electricity from “new” renewable resources.  Generally, new renewable resources are renewable facilities that have an in-service date, resumed operation or were refurbished after September 1, 2005.  The Act set the initial renewable percentage requirement at 1% in 2008, increasing in annual one percentage point increments to 10% in 2017.  Pursuant to the Act, the renewable requirement will remain at 10% thereafter, unless the Commission suspends the requirement.

The Commission's March 31, 2015 report, Annual Report on New Renewable Resource Portfolio Requirement, reports on renewable portfolio standard compliance activity in calendar year 2013.  This lag between the study period and the report's issuance is driven by the timing of the most recently filed Competitive Electricity Provider (CEP) annual compliance reports, which were filed in July 2014 for calendar year 2013.  In 2013, the Act required suppliers to source 5% of their power from new renewable resources.  Suppliers can comply either by acquiring sufficient renewable energy certificates or RECs to cover their compliance obligation, or by paying an "alternative compliance payment".

According to the report, in 2013 suppliers purchased 727,291 Class I RECs from 21 certified generating facilities to meet the portfolio requirement.  Nearly 97% of these RECs came from biomass facilities located in Maine.  According to the report, 17 of the 21 facilities are biomass, three are hydro, and one is a wind facility.  18 of the 21 facilities are located in Maine, one is located in Connecticut, one is located in Massachusetts and one is located in Vermont.

The Commission's report also documents the cost of compliance in 2013.  During 2013, the cost of RECs used for compliance with the Class I requirement ranged from approximately $1.50 per MWh to $60 per MWh, with an average cost of $19. 8 7 per MWh and a total cost of $14, 292,438.  As noted in the report, the cost of Maine Class I RECs has dropped substantially since 2013, with the report citing a current trading range of $3.00 to $5.00.  With minor use of the alternative compliance mechanism by two suppliers, the total cost to ratepayers during 2013 was $14,296,249, which the Commission's report translates into an average rate impact of about 0.12 cents per kWh (about 60 to 65 cents monthly for a typical residential bill, or a residential customer bill impact of about 1%).

The report also documents the 2013 costs of RECs used to satisfy the "Class II" eligible resource portfolio requirement as ranging from $0.00 per MWh (some RECs were included as part of an energy transaction at no specified extra cost) to $1.00 per MWh, with an average cost of $0.16 per MWh and a total cost of $589,386. This translates into less than three cents per month on a typical residential bill.

Champlain Hudson Power Express gets Army Corps permit

Monday, May 4, 2015

The Champlain Hudson Power Express, an electric transmission line proposed from Quebec to New York, has completed its federal permitting process according to project developer Transmission Developers Inc.

Project developer TDI is a Blackstone portfolio company, with an apparent focus on HVDC lines.  First proposed in 2008, the current incarnation of the Champlain Hudson Power Express is a 333-mile high voltage direct current (HVDC) transmission line to be installed underground and underwater, from the U.S.-Canada border to New York City, running down Lake Champlain and parts of the Hudson River.  The line is slated to be able to import up to 1,000 megawatts of power from Canada to the U.S. 

In a press release issued last month, TDI announced that the U.S. Army Corps of Engineers has issued a permit that allows the Champlain Hudson Power Express project to be placed in waters of the United States along its proposed route.  The permit authorizes TDI to construct the project pursuant to Section 10 of the Rivers and Harbors Act and Section 404 of the Clean Water Act.

According to TDI, the Army Corps permit represents the final federal or state permit necessary to begin construction.  According to the permit, the work authorized must be completed by December 30, 2019.