FERC Order 848, cyber security and reliability

U.S. energy regulators have issued an order directing the nation's electric reliability organization to strengthen its standards for the mandatory reporting of cyber security incidents.

Federal law authorizes the Federal Energy Regulatory Commission to regulate significant aspects of the bulk electric system's reliability. The Commission's jurisdiction over reliability covers the nation's electric reliability organization, North American Electric Reliability Corporation (NERC), which is charged with developing and submitting mandatory reliability standards for the Commission for approval.

Following increased concern over cybersecurity and hacking affecting utilities, in 2017 the Commission issued a Notice of Proposed Rulemaking proposing to direct that NERC develop enhanced Cyber Security Incident reporting requirements. At that time, then-current reliability standards generally required responsible entities to report Cyber Security Incidents only if they have “compromised or disrupted one or more reliability tasks. But the Commission expressed a concern that this reporting threshold "may understate the true scope of cyber-related threats facing the Bulk-Power System, particularly given the lack of any reportable incidents in 2015 and 2016." As a result, the Commission proposed requiring NERC to develop and submit modifications to its reliability standards, to require the reporting of cyber security incidents that compromise, or attempt to compromise, certain security infrastructure.

On July 19, 2018, the Federal Energy Regulatory Commission issued its Order No. 848. Through that order, the Commission adopted its own proposal to "improve awareness of existing and future cyber security threats and potential vulnerabilities." As described by the Commission, Order No. 848's directive consists of four elements:

1. responsible entities must report Cyber Security Incidents that compromise, or attempt to compromise, a responsible entity’s Electronic Security Perimeter (ESP) or associated Electronic Access Control or Monitoring Systems (EACMS);
2. required information in Cyber Security Incident reports should include certain minimum information to improve the quality of reporting and allow for ease of comparison by ensuring that each report includes specified fields of information;
3. filing deadlines for Cyber Security Incident reports should be established once a compromise or disruption to reliable BES operation, or an attempted compromise or disruption, is identified by a responsible entity; and
4. Cyber Security Incident reports should continue to be sent to the Electricity Information Sharing and Analysis Center (E-ISAC), rather than the Commission, but the reports should also be sent to the Department of Homeland Security (DHS) Industrial Control Systems Cyber Emergency Response Team (ICS-CERT). Further, NERC must file an annual, public, and anonymized summary of the reports with the Commission.

The Commission directed NERC to submit these modifications to its reliability standards within six months of Order No. 848's effective date.

Report on US electric grid physical security

Since a 2013 rifle attack on a critical electric power substation in California, the U.S. electric power sector has generally moved toward greater physical security for critical assets, according to a report published by the Congressional Research Service. But the report says bulk power security "remains a work in progress," and suggests further investment -- and policy reforms -- may follow.

The report published on March 19, 2018 -- NERC Standards for Bulk Power Physical Security: Is the Grid More Secure? -- begins with the premise that securing the electric power grid is among the nation's highest priorities for critical infrastructure protection. It notes that a 2013 rifle attack on an electric transmission substation in California which caused widespread power outages also broadened policy attention from cybersecurity to encompass the physical security of assets critical to the power grid.

In response, Congress enacted legislation to strengthen power grid physical security and to facilitate its recovery from disruption. Section 1104 of the Fixing America’s Surface Transportation (FAST) Act contains provisions to protect or restore the reliability of critical electric infrastructure or defense of critical electric infrastructure during a grid security emergency. The Federal Energy Regulatory Commission (FERC) and the nation's electric reliability organization NERC also took action to develop new reliability standards for the physical security of bulk power critical infrastructure.

But physical security risks may persist. The report references a September 2016 rifle attack on a Garkane Energy Cooperative transformer substation in Utah as illustrating this persistence. The report notes that while it is probably accurate to conclude that the grid is more physically secure than it was in 2013, "it has not necessarily reached the level of physical security needed based on the sector's own assessments of risk.

The report notes Congress's continued concern about the physical security of the electric grid. It identifies possible areas for further policy focus as including "security implementation oversight, cost recovery, hardening vs. resilience, and the quality of threat information."

Meanwhile, cybersecurity has remained a priority. An October 2017 FERC report describing the results of its audits of regulated companies' cybersecurity protection processes and procedures noted that most met the applicable mandatory standards. But earlier this month, NERC fined an anonymous utility $2.7 million for alleged violations of reliability standards in connection with a data security breach, and the U.S. Department of Homeland Security issued warnings about Russian hackers targeting computer systems controlling energy and other critical infrastructure.

Interest in shoring up the security of energy infrastructure and systems -- both from physical attacks as well as cyber threats -- appears poised to drive continued discussions, regulation, and investment.

US warns of Russian Government Cyber Activity Targeting Energy and Other Critical Infrastructure

The U.S. Department of Homeland Security has warned that for at least two years, Russian government cyber actors have targeted government entities and multiple U.S. critical infrastructure sectors, including the energy, nuclear, commercial facilities, water, aviation, and critical manufacturing sectors.

In a joint Technical Alert issued March 15, 2018 by the Department of Homeland Security's U.S. Computer Emergency Readiness Team (US-CERT) and the Federal Bureau of Investigation, the agencies warned of a "multi-stage intrusion campaign by Russian government cyber actors." The report follows an October 2017 alert by computer security firm Symantec of a re-emergence of a sophisticated cyber espionage group known as "Dragonfly."

According to the government agencies' report, the Russian cyber threat actors seem to have deliberately targeted specific organizations, as opposed to pursuing targets of opportunity. In an initial "staging" phase, the campaign used tools like malware, watering holes, and spear phishing to gain access to small commercial facilities' networks -- typically peripheral organizations like trusted third-party suppliers whose networks may be less secure. For example, the threat actors sent emails with malicious attachments appearing to be personnel resumes or contract documents. Clicking on links in the attachments exposed the victims to malware or data harvesting. In a subsequent phase, the threat actors made further use of the staging targets' networks as "pivot points and malware repositories" for use in targeting their final intended victims.

The report says that these Russian government cyber actors used this hacked access for network reconnaissance and collection of information pertaining to Industrial Control Systems (ICS). It describes multiple instances of threat actors accessing workstations and servers on corporate networks that contained data output from control systems within energy generation facilities.

Cyber security is now a significant concern, both domestically and abroad. A February 2018 report by the U.S. intelligence community described the targeting of national security information and proprietary information from US companies and research institutions involved with defense, energy, finance, dual-use technology, and other areas as "a persistent threat to US interests." Last month, U.S. electric grid reliability regulators imposed a $2.7 million penalty on an unidentified utility for its violations of mandatory reliability standards in connection with a data security breach -- the largest fine to date associated with U.S. utility cybersecurity regulation. In that case, a third-party contractor hired by the utility allegedly copied protected data from the utility's network to the contractor's unsecured network -- where it was accessible online without the need to enter a user ID or password, and where it was in fact accessed by one or more unknown outside entities.

In 2014, reports emerged that Russian hackers had found flaws in solar panel monitoring software that, if left unfixed, could allow malicious actors to damage the electric grid. Foreign state-sponsored cyber attacks in 2016 and 2017 against Ukraine and Saudi Arabia targeted multiple sectors across critical infrastructure, government, and commercial networks, causing disruption to Ukrainian energy distribution networks.

ISO-NE files 12th capacity auction results

The organization responsible for New England's wholesale electricity markets has announced the results of its twelfth annual forward capacity auction. According to grid operator ISO New England, Inc., its FCA 12 concluded with sufficient resources to meet electricity demand in 2021-2022, at the lowest price in five years.

As in some (but not all) other organized electricity markets, New England's electricity market design includes a wholesale energy market as well as a forward capacity market. Operated by ISO New England, the Forward Capacity Market or FCM is designed to secure capacity resources sufficient to meet future demand. The capacity market is separate from the energy market, and can provide additional revenues for qualified resources.

The grid operator conducts annual Forward Capacity Auctions or FCAs, held three years in advance of each one-year operating period. Generation and other capacity resources such as load management or energy efficiency can compete in these auctions to obtain monthly market-priced capacity payments during the delivery year, in exchange for the obligation to supply capacity -- and supply energy or curtail demand when dispatched by the ISO in that future period. Capacity revenues can support the development of new resources as well as the retention of existing plants by providing predictable cash flows and incentivizing consistent resource availability.

ISO New England held its twelfth FCA on February 5 and 6, 2018, auctioning off capacity supply obligations for the capacity commitment period of June 1, 2021 through May 31, 2022. On February 28, 2018, ISO New England submitted its forward capacity auction results filing for FCA12 to the Commission. According to the filing, the descending clock auction commenced with a starting price of $12.684/kW-month, with resources in most zones to be paid at a clearing price of $4.631/kW-month based on the system sloped demand curve. About 1,100 megawatts of imports over certain interfaces with Canada will be paid at reduced capacity clearing prices. These prices are all below recent ISO-NE forward capacity auction results.

Through FCA12, ISO-NE procured 30,011 megawatts of generation, including 174 megawatts of new generation. The auction also acquired about 3,600 megawatts of energy efficiency and demand-reduction measures, 514 megawatts of which is new. The grid operator estimated the total cost of the capacity market in 2021-2022 to be approximately $2.07 billion.

ISO noted that it had rejected two "de-list bids", or requests by existing generators to leave the capacity market, for local reliability reasons. It identified those bids as coming from Exelon Generation Company, LLC with respect to its Mystic 7 and 8 units, totaling about 1,278 megawatts. As described in supporting testimony, ISO asserted that "allowing the resources to leave the market would have resulted in a violation of NERC, NPCC, or ISO criteria." According to a related press release, ISO found that "transmission lines in Greater Boston could be overloaded if Mystic 7 and Mystic 8 were not available during 2021-2022."

ISO described the results of the auction as just and reasonable, and asked the Commission to accept the filing.

NERC fines utility $2.7 million for cyber breach

The electric reliability organization responsible for the grid spanning much of North America has penalized an unidentified utility $2.7 million for its violations of mandatory reliability standards in connection with a data security breach. The penalty may be the largest fine to date associated with U.S. utility cybersecurity regulation.

NERC, or the North American Electric Reliability Corporation, is charged by U.S. law with ensuring the reliability of the nation's bulk power system. NERC establishes reliability standards for the bulk electric system, which are approved by the Federal Energy Regulatory Commission, and takes action to monitor and enforce compliance with its reliability standards.

On February 28, 2018, NERC filed with the Commission a Notice of Penalty regarding what it described as noncompliance by an "Unidentified Registered Entity (URE)", following a settlement between the anonymous utility and regional reliability group Western Electricity Coordinating Council (WECC).

Some of the details of the underlying fact pattern are protected from public disclosure as Critical Energy Infrastructure Information or CEII. But NERC's public filing says the settlement arose from WECC's determination and findings that the anonymous utility violated two of NERC's Critical Infrastructure Protection or CIP cybersecurity standards. According to NERC's report, the utility received a report that an outside "white hat security researcher" had found data publicly available online which appeared to be protected information associated with the utility.

Following this tipoff, an investigation by the utility and regional reliability group WECC revealed that a third-party contractor hired by the utility had copied data from the utility's network environment to the contractor's network environment, where it was no longer subject to the utility's visibility or control -- in violation of the contractor's authority. While the data was on the contractor's network, a subset of live utility data including over 30,000 records was accessible online without the need to enter a user ID or password for a period of 70 days. These records included some associated with the utility's Critical Cyber Assets, such as servers storing user data, systems controlling physical access within the utility's control centers and substations, and supervisory control and data acquisition or SCADA systems. System logs showed unauthorized access to this data set by both the white hat researcher and unidentified IP addresses.

According to the Settlement Agreement, the anonymous utility neither admitted nor denied the violations, but agreed to pay a $2,700,000 penalty and take other compliance actions. This may represent the largest fine to date for violations of NERC's CIP standards. While federal penalty policy encourages self-reporting of violations and having an internal compliance program in place -- as the anonymous utility did -- the settlement notes that the utility "was not fully transparent and forthcoming with all pertinent information detailing the data exposed in the incident." In particular, the settlement says the utility did not initially provide WECC with all the data fields exposed in the incident. These factors, combined with a finding that the violations posed a serious and substantial risk to the reliability of the bulk power system, led WECC to set the penalty amount at $2.7 million, which NERC subsequently approved.

By federal rule, the penalty will be effective upon expiration of the 30-day period following the penalty notice's filing with the Federal Energy Regulatory Commission or, if FERC decides to review the penalty, upon final determination by FERC.

GAO report on electric grid geomagnetic disturbances

A report released by the U.S. Government Accountability Office found that U.S. and Canadian electricity suppliers have taken steps to prepare for potential electromagnetic disruptions to the electric grid such as from solar storms or high-altitude nuclear detonations -- but that more research is needed on both geomagnetic disturbances and high-altitude electromagnetic pulses.

Under some circumstances, a severe solar storm or high-altitude nuclear blast could damage the U.S. electric grid and potentially cause extensive outages. Federal energy regulators have used both regulatory and more informal collaborative approaches to address the threat to the electric grid posed by electromagnetic pulses and geomagnetic disturbances. Regulatory approaches to electromagnetic disturbance readiness include mandatory reliability standards adopted by electric reliability organization NERC, which require some electricity suppliers to assess their vulnerability to extreme solar storms, and developing procedures for responding to grid security emergencies.

In this context, the Government Accountability Office was asked to review electricity industry actions to prepare for and mitigate electromagnetic risks. Its 95-page report, Critical Infrastructure Protection: Electricity Suppliers Have Taken Actions to Address Electromagnetic Risks, and Additional Research is Ongoing, examines topics including the degree to which U.S. and Canadian electricity generation and transmission owners and operators have identified information about the effects on the grid caused by geomagnetic disturbances and high-altitude electromagnetic pulses (HEMP), steps some suppliers have taken to protect against GMD and HEMP, and opportunities for U.S. suppliers to recover costs for protecting against GMD and HEMP.

According to the report, there is "general agreement that more research is needed on both GMD and HEMP." Risks identified include potential voltage instability leading to collapse of the bulk power system and blackouts, as well as possible damage to key system components. But more information is needed, according to the report -- especially on HEMP effects, given that previous studies have focused on impacts to military equipment as opposed to the commercial electric grid.

The cost of addressing reliability concerns can be significant. The GAO report describes some suppliers' reports "that costs they have incurred to protect against GMD and HEMP have been relatively small so far and they expect to recover those costs through customer rates." But the report warns that suppliers could face future increased costs, as a second regulatory standard phases in through 2022. For example, the report cites one supplier serving about 4.5 million retail customers as estimating "the cost of hardening a planned control center against HEMP to be at least $10 million." GAO calculated that fully passing this cost on to customers in a single year would add $2 to the average customer ’s electric bill for that year.

While regulated U.S. suppliers may be able to recover GMD protection costs through rates, the report notes that recovery is less certain for protection against HEMP because less is known about HEMP risks. The report also presages challenges for any kind of reliability-driven cost recovery for independent owners of power plants, who must recover reliability improvement costs through their sales of electricity without assurances about market prices.

FERC ends DOE resilience rulemaking, opens new proceeding

U.S. energy regulators have terminated a fast-tracked proceeding opened last fall to consider rules proposed by the Department of Energy that would have compensated certain electric generating plants for reliability and resilience values; instead, the Federal Energy Regulatory Commission has opened a broader case to examine the resilience of the bulk power system.

On September 29, 2017, Secretary of Energy Rick Perry directed the Commission to consider a proposed rulemaking to ensure that "traditional baseload resources, such as coal and nuclear" are rewarded for their reliability and resilience attributes. As proposed, the rule would have required grid operators to set rates for compensation paid to certain "grid reliability and resiliency resources" with a 90-day fuel supply on site and capable of providing "essential energy and ancillary reliability services, including but not limited to voltage support, frequency services, operating reserves, and reactive power."

The request under Section 403 of the Department of Energy Organization Act bore an expedited timeline. The Commission solicited public comments on the proposed rulemaking, and Commission staff issued a series of questions to frame the discussion. Many comments expressed concerns that rapid changes to wholesale markets could have harmful or perverse effects, and prior to yesterday's most seated Commissioners had publicly expressed reservations.

On January 8, 2018, the Commission issued its Order Terminating Rulemaking Proceeding, Initiating New Proceeding, and Establishing Additional Procedures.  In doing so, it recognized "that we must remain vigilant with respect to resilience challenges, because affordable and reliable electricity is vital to the country’s economic and national security." The order recites a history of the evolution of the electric power industry and the Commission's efforts to help ensure bulk power system resilience, including the adoption of NERC reliability standards, reforms to capacity markets and gas-electric coordination.

But the Commission found that neither the Department of Energy's proposed rulemaking nor the record in the case satisfied a key legal standard for Commission action under Section 206 of the Federal Power Act. Specifically, it concluded that the existing tariffs had not been demonstrated to be unjust, unreasonable, unduly discriminatory or preferential.

The Commission also noted potential problems with the proposed rule. For example, it said that allowing all eligible resources to receive a cost-of -service rate regardless of need or cost to the system had not been demonstrated to be just and reasonable, and that the proposed rule's on-site 90-day fuel supply requirement hadn't been shown not to be unduly discriminatory or preferential -- but that it would exclude some resources with resilience attributes.

At the same time, the order states, "The resilience of the bulk power system will remain a priority of this Commission." It continued, "Although the Proposed Rule failed to satisfy the fundamental legal requirements of section 206 of the FPA, the Proposed Rule and the record developed to date have shed additional light on resilience more generally and on the need for further examination by the Commission and market participants of the risks that the bulk power system faces and possible ways to address those risks in the changing electric markets." Noting "a variety of economic, environmental, and policy drivers that are changing the way electricity is procured and used," the Commission said these changes "present new opportunities and challenges regarding the reliability, affordability, and environmental profile of each region’s electric system."

To address these changes, the Commission initiated a new proceeding, Docket No. AD18- 7-000, to take additional steps to explore resilience issues in organized wholesale electricity markets. According to the order, the goal of this proceeding is: "(1) to develop a common understanding among the Commission, industry, and others of what resilience of the bulk power system means and requires; (2) to understand how each RTO and ISO assesses resilience in its geographic footprint; and (3) to use this information to evaluate whether additional Commission action regarding resilience is appropriate at this time."

The Commission directed six regional transmission organizations and independent system operators to respond within 60 days with comments on the definition of resilience, plus how they assess and mitigate threats to resilience. The Commission also solicited public comment within 30 days of the grid operators' due date.

California grid prepares for solar eclipse

As a total solar eclipse approaches for North America, California electricity regulators have launched a voluntary demand response program designed to reduce power consumption during the eclipse while solar panel output is reduced.

The eclipse will occur on August 21, 2017, and is projected to reduce solar photovoltaic production in the California ISO region by 4,194 megawatts.  Taking gross load increases and estimated wind production into account, CAISO has been told to expect a net load increase of 6,008 MW during the eclipse.

According to the nation's electric reliability organization, NERC, the August 21 eclipse "is not expected to impact the reliability of the bulk power system."  But as NERC also noted, "As the number of photovoltaic generators on the power system increases, the risk created by solar eclipses to reliable system operations will increase as well."

Now, the California Public Utilities Commission has launched a "Do Your Thing for the Sun" or "Cal Eclipse" program.  On its website, the Commission asks, "While our utilities and grid operator have all the tools necessary to manage the grid during the eclipse, what if millions of Californians stepped in to allow our hard working sun to take a break, rather than relying on expensive and inefficient natural gas peaking power plants?"

The website asks consumers to "Take the Pledge", emphasizing the value of "joining a movement of Californians who are taking action during the eclipse to give the sun a break by saving energy and reducing GHG emissions." According to a two-page FAQ posted on the website, consumers can reduce electricity consumption by turning off electronics when leaving, and permanently decrease electricity consumption with energy efficiency measures.  Actions suggested on the pledge website include replacing light bulbs with LEDs, reducing lighting use and electronics charging, unplugging unused appliances, and increasing air conditioning temperature setpoints by 2-5 degrees.

According to the Commission's FAQ, "There is no reason to anticipate any eclipse-related electric service outages because of the reduced solar generation."

FERC's approach to EMP and GMD threats

Federal energy regulators have used both regulatory and more informal collaborative approaches to address the threat to the electric grid posed by electromagnetic pulses and geomagnetic disturbances, according to testimony delivered on May 4, 2017, to the U.S. Senate Committee on Energy and Natural Resources.

Last month, Federal Energy Regulatory Commission acting chairman Cheryl LaFleur spoke to the Senate committee on the Commission's work in protecting the reliability of the U.S. grid against naturally-occurring and manmade threats.  In her testimony, she noted the Commission's role in approving mandatory reliability standards developed by the North American Electric Reliability Corporation (NERC), as well as its support for grid security through voluntary and collaborative efforts like sharing best practices, participating in grid reliability exercises, and briefing state policymakers.

Acting chairman LaFleur's testimony focused on the threats posed by man-made electromagnetic pulses (EMP) and naturally-occurring geomagnetic disturbances (GMD).  As she categorized it, EMP are bursts of energy designed to disrupt, damage or destroy electronics such as those found in control systems on the electric grid.  GMD are naturally occurring solar magnetic disturbances which periodically disrupt the earth’s magnetic field; these disturbances can induce currents on the electric grid that may simultaneously damage or destroy key transformers over a large geographic area.  According to Commissioner LaFleur, a severe EMP or GMD event "has the potential to cause voltage problems and instability on the electric grid, which could lead to wide-area blackouts."

She next noted FERC's actions to address EMP threats, including both regulatory and informal approaches.  Regulatory actions include FERC's direction and approval of NERC's two-stage GMD reliability standards, which require responsible entities to develop and implement operational procedures to mitigate the effects of GMDs and to conduct initial and on-going assessments of the potential impact of a benchmark GMD event on bulk-power system equipment and the bulk-power system as a whole and to mitigate any assessed vulnerabilities.

She also pointed to FERC's approval of NERC's physical reliability standard, which requires responsible entities to mitigate assessed vulnerabilities to critical transmission facilities through resiliency or security measures designed collectively to deter, detect, delay, assess, communicate, and respond to potential physical threats and vulnerabilities, as helping to address the use of small, portable EMP devices that require close proximity to their intended target.  However, as she noted, "FERC has not directed NERC to develop a standard specifically targeting EMP."

Acting chair LaFleur also noted collaborative efforts, including coordination and information-sharing with the Department of Energy, Department of Homeland Security, Department of Defense, interagency task forces, and foreign governments.

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.

Waterbury hydro need and economics

A recent order issuing a new hydropower license to Green Mountain Power Corporation's Waterbury Hydroelectric Project sheds insight into the project's operations and economics.

The Waterbury project is located at a dam built in 1938, and licensed for hydropower development since 1954.  After a 16-year relicensing process, the Federal Energy Regulatory Commission issued a new license for the project in February 2016, authorizing 5.52 megawatts of generating capacity.  That relicensing process illustrates how the Commission considers the need for power from the project, as well as project economics, when considering whether to relicense a hydropower project.

By regulation, the Commission's process for reviewing a license application includes an evaluation of the "need of the applicant over the short and long term for the electricity generated by the project or projects to serve its customers."  In the Waterbury project's relicensing case, this consideration of the applicant's "need for power" involved observations about the project's expected output as well as the regional power market.  The order notes historic average generation from the Waterbury Project of 17,562 MWh annually, but observes that under the new license average annual generation will be reduced to 14,767 MWh.

The order then states, "Electricity generated from the Waterbury Project will help supply the power needs in northern Vermont."  It also cites a 10-year forecast by electric reliability organization North American Electric Reliability Corporation (NERC) showing summer peak demand in the region is expected to increase at an average rate of 0.84 percent per year between 2014 and 2023.  Based on this, the order concludes that "the project's power will help meet the regional need for power."

The Commission's process for determining whether to issue a new license for an existing hydroelectric project also includes consideration of public interest factors, such as the economic benefits of project power.  A 1995 decision established the Commission’s approach to evaluating the economics of hydropower projects.  Under that approach, the Commission uses current costs to compare the costs of the project and likely alternative power with no forecasts concerning potential future inflation, escalation, or deflation beyond the license issuance date.  The Commission has described the basic purpose of this economic analysis as to provide a general estimate of the potential power benefits and the costs of a project, and of reasonable alternatives to project power, "to support an informed decision concerning what is in the public interest with respect to a proposed license."

For the Waterbury project, as ultimately licensed with mandatory conditions and staff measures, the Commission concluded that:

• the levelized annual cost of operating the project is $711,735, or $48.20/MWh
• the proposed project would generate an average of 14,767 MWh of energy annually.
• average generation is multiplied by the alternative power cost of $44.12/MWh, for a total value of the project’s power is $651,520, in 2015 dollars.

Therefore, the Commission concluded that in the first year of operation, the project would cost $60,215, or $4.08/MWh, more than the likely alternative cost of power.  As the order notes, "Although staff’s analysis shows that the project as licensed herein would cost more to operate than the estimated cost of alternative power, it is the applicant who must decide whether to accept this license and any financial risk that entails."

The Commission did note that its consideration of public interest factors also considers that "hydroelectric projects offer unique operational benefits to the electric utility system", including ancillary services like stability and rapid response.  The order also notes that while staff did not explicitly account for the effects inflation may have on the future cost of electricity, hydropower generation is relatively insensitive to inflation compared to fossil fueled generators -- illustrating why "project economics is only one of the many public interest factors the Commission considers in determining whether or not, and under what conditions, to issue a license."

NERC suggests Clean Power Plan reliability considerations

The electric reliability organization for North America has issued an assessment of reliability considerations it thinks state electricity and environmental regulators should take into account in crafting state plans to comply with the Clean Power Plan.

The North American Electric Reliability Corporation (NERC) is a not‐for‐profit regulatory authority whose mission is to assure the reliability of North America's bulk power system.

Last year, the U.S. Environmental Protection Agency (EPA) issued its Clean Power Plan, a final rule limiting carbon dioxide emissions for existing electric generation facilities.  States are expected to prepare individual or collaborative plans to comply with the regulation.  Because reducing the carbon intensity of electric power generation is the goal, EPA expects that some plans will include a shift from coal-fired power plants to less carbon-intensive sources.  As NERC wrote in its assessment:

The BPS is already undergoing a broad transformation with retirements of coal units and some nuclear units, and additions of resources fueled by natural gas, wind, and solar. Distributed generation, energy efficiency, and demand response are also changing the way in which system planners must account for resources. The CPP has the potential to hasten the transformation of the electric system started by market and political factors such as natural gas supply and pricing and federal and state policy decisions with respect to renewables and energy efficiency and other environmental regulations.

But reliability is a key issue at stake in any shift in the portfolio of generating resources.  The Clean Power Plan rule explicitly requires that states consider reliability as part of their plans.

NERC's assessment, Reliability Considerations for Clean Power Plan Development, presents its view of "aspects of plan design that need to be considered to reliably accommodate this broad transformation."  NERC's ten key reliability considerations are:

• State coordination with system planning entities - planners and coordinators working together
• Essential reliability services - "In order to maintain an adequate level of reliability through this transition, generation resources need to provide sufficient voltage control, frequency support, and ramping capability — essential components to the reliable operation of the BPS. It is necessary for policy makers to recognize the need for these services by ensuring that interconnection requirements, market mechanisms, or other reliability requirements provide sufficient means of adapting the system to accommodate large amounts of variable and/or distributed energy resources (DERs)."
• Timing considerations for energy infrastructure development - "Retirements can happen quickly, but adequate replacement facilities must be in service prior to retirement. As natural gas‐fired generation replaces coal‐fired generation the requisite timeline for natural gas pipeline infrastructure becomes even more relevant."
• Electricity imports and exports - "If a state intends to use resources from nearby states as part of a compliance strategy, it is important to determine if the necessary transmission capability is available to reliably transport electricity from those resources."
• Change in generator cycling and operations - coal plants may serve more seasonal peak demands, so "states should take account of changes in maintenance requirements likely due to cycling and the risk of increased forced outages of these coal‐fired plants. Additionally, increased and sufficient coordination between gas and electric system operators becomes much more critical to ensure adequate amounts of fuel are available."
• Reserve margin assessment - "As more variable and energy ‐ limited resources are added, the system will likely require additional reserve capacity to maintain a similar level of reliability compared to a system with all conventional generation."
• Energy efficiency - "Given that EE can be used as a potential CPP compliance tool, it is important that states evaluate the realistic potential for EE to displace load and the likely duration of those impacts. Shorter term EE measures may serve as a potential bridge to meet CPP requirements."
• Emissions trading - "In general, emissions trading promotes additional reliability compliance options by effectively broadening the compliance region as well as the availability of allowances and credits. However, some resource options that might be assumed available through emissions trading may not be, due to another state’s plan. Because trading is optional, states should coordinate to ensure the most beneficial approach of trading is considered."
• Reliability safety valve - "States must understand how the Reliability Safety Valve works and its limits, recognizing that it cannot be used as a planning tool to meet CPP requirements."
• North American and European precedents - states should review carbon market precedents like RGGI and shifts in Canada and Europe toward renewable and distributed resources as case studies for potential strategies, lessons learned in implementation, and insights as they develop their plans.

Some states are already developing Clean Power Plan compliance plans.  Meanwhile, judicial challenges have been filed.  Initial plans are due to the EPA later this year.

FERC considers geomagnetic disturbance standards

U.S. energy regulators examining reliability standards for the electric transmission grid relating to geomagnetic disturbances have scheduled a technical conference for March 1, 2016.

Geomagnetic disturbance, or GMD, events occur during solar storms when the sun emits charged particles whose magnetic field interacts with that of the Earth.  GMDs can affect transformers, transmission lines, and other electric grid infrastructure.  As the Federal Energy Regulatory Commission noted in its Order No. 779, "there is a general consensus that GMD events can cause wide-spread blackouts due to voltage instability and subsequent voltage collapse, thus disrupting the reliable operation of the Bulk-Power System."

In 2013, the FERC issued Order No. 779 directing NERC to propose Reliability Standards that address the impact of geomagnetic disturbances (GMD) on the reliable operation of the Bulk - Power System.  In 2015, NERC made its proposal, which the FERC has proposed to largely accept.

But the case before FERC, docketed as RM15-11, remains ongoing.  Grid operators, utilities, trade groups, and others have filed comments or otherwise participated in the case.

The Commission has now scheduled a GMD technical conference on March 1, 2016, as a forum for "a structured dialogue on GMD-related topics."  Items specifically identified for discussion at this stage include what kind of GMD event should be used as the "benchmark" for planning purposes, vulnerability assessments, and monitoring of related parameters.

Feds settle on final 2011 Southwest blackout penalty

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.

FERC proposes geomagnetic disturbance reliability standard

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.

4th California blackout FERC enforcement case settles

Federal regulators have approved a settlement with another federal agency over its role in a 2011 blackout in California, Arizona, and Mexico.

On September 8, 2011, the Southwest's electric grid was hit with a widespread power outage that left over 5 million people in California, Arizona and Baja California, Mexico, without power for up to 12 hours.  Previous investigations by the Federal Energy Regulatory Commission (FERC) and the North American Electric Reliability Corporation (NERC) found that the blackout occurred when Arizona Public Service Company's 500-kilovolt Hassayampa-N.Gila transmission line tripped out of service, overloading the remaining elements of the regional grid. 

Earlier this year, FERC approved stipulations and consent agreements among its Office of Enforcement, NERC, and three public utilities.  Arizona Public Service agreed to pay $3.25 million in civil penalties, California's Imperial Irrigation District agreed to a $12 million settlement, and  Southern California Edison Company agreed to pay a $650,000 civil penalty and undertake additional compliance actions.

FERC approved a fourth settlement on November 24, 2014, with the Western Area Power Administration – Desert Southwest Region (Western-DSW).  One of four power marketing administrations within the United States Department of Energy, the Western Area Power Administration (WAPA) markets and transmits electricity to a fifteen-state region from hydroelectric power facilities at the Hoover, Parker, and Davis dams. Western-DSW is one of four regions carrying out this mission for WAPA, serving customers in Arizona, Southern California, and Southern Nevada. It sells more than ten billion kilowatt hours of hydroelectric power to approximately seventy municipalities, cooperatives, federal and state agencies, and irrigation districts. Western-DSW also operates and maintains more than forty substations and 3,100 miles of transmission lines.

In the FERC Order Approving Stipulation and Consent Agreement, the Commission notes that Western-DSW violated four Requirements of three Reliability Standards in the Transmission Operations (TOP) and Voltage and Reactive Control (VAR) categories. These groups of standards cover the responsibilities and decision making authority for reliable operations and maintenance of Bulk Power system facilities within voltage and reactive power limits to protect equipment and ensure reliable operation of the interconnection.  In particular, FERC Enforcement staff and NERC found that Western-DSW failed to operate its portion of the transmission system within voltage system operating limits and to maintain sufficient situational awareness prior to and during the event, undermining reliable operation of the Bulk Power System.

Western-DSW stipulated to the facts in the agreement and agreed to implement compliance measures necessary to mitigate the violations and improve overall reliability, including improving its models, better coordination with neighboring entities, and improving its situational awareness by adding a real-time monitoring tool that analyzes and alerts operators to potential contingencies. Western-DSW also agreed to make semi-annual compliance reports to Enforcement staff and NERC for at least one year.  Notably, the stipulation does not require Western-DSW to pay a civil penalty.

FERC's general investigative report on the incident identified six potential targets for enforcement action.  With cases settled against Western-DSW, SoCal Edison, the Imperial Irrigation District, and Arizona Public Service, only the California Independent System Operator and the Western Electricity Coordinating Council Reliability Coordinator have not yet been parties to a stipulation and consent agreement.

FERC adopts grid physical security reliability standard

As expected, federal regulators have approved a new physical security standard for the high-voltage electricity grid.

On November 20, the Federal Energy Regulatory Commission approved Reliability Standard CIP-014-1 (Physical Security).  The standard, proposed by Commission-certified Electric Reliability Organization North American Electric Reliability Corporation (NERC), is designed to enhance physical security measures for the most critical parts of the nation's "bulk-power system," the high-voltage backbone of the nation's electric grid.

In the wake of a 2013 California incident in which a major substation was damaged by gunfire, in March 2014 the FERC directed NERC to prepare a draft standard to protect the physical security of the grid.  In response, NERC proposed a standard requiring owners and operators of transmission facilities toidentify and protect critical transmission stations, substations, and control centers whose damage through physical attack could result in spreading outages or other reliability problems.

On November 20, 2014, the FERC issued its Order No. 802 approving the physical grid reliability standards.  In a press release, the Commission described Order No. 802 as enhancing the physical security for the most-critical Bulk-Power System facilities and reducing the overall vulnerability of the grid to attacks.

As described by the FERC in Order No. 802, Reliability Standard CIP-014-1 has six requirements:

• Requirement R1 requires applicable transmission owners to perform risk assessments on a periodic basis to identify their transmission stations and substations that, if rendered inoperable or damaged, could result in widespread instability, uncontrolled separation , or cascading within an Interconnection. Requirement R1 also requires transmission owners to identify the primary control center that operationally controls each of the identified transmission stations or substations.
• Requirement R2 requires that each applicable transmission owner have an unaffiliated third party with appropriate experience verify the risk assessment performed under Requirement R1. Requirement R2 states that the transmission owner must either modify its identification of facilities consistent with the verifier’s recomme ndation or document the technical basis for not doing so. In addition, Requirement R2 requires each transmission o wner to implement procedures for protecting sensitive or confidential info rmation made available to third - party verifier s or developed under the Reliability Standard from public disclosure.
• Requirement R3 requires the transmission owner to notify a transmission operator that operationally controls a primary control center identified under Requirement R1 of such identification to ensure that the transmission operator has notice of the identification so that it may timely fulfill its obligations under Requirements R4 and R5 to protect the primary control center.
• Requirement R4 requires each applicable transmission owner and transmission operator to conduct an evaluation of the potential threats and vulnera bilities of a physical attack on each of its respective transmission stations, transmission substations, and primary control centers identified as critical in Requirement R1.
• Requirement R5 requires each transmission owner and transmission operator to develop and implement documented physical security plans that cover each of their respective transmission stations, transmission substations, and primary control centers identified as critical in Requirement R1.
• Requirement R6 requires that each transmission owner and transmission operator subject to Requirements R4 and R5 have an unaffiliated third party with appropriate experience review its Requirement R4 evaluation and Requirement R5 security plan. Requirement R6 states that the transmission owner or transmission operator must either modify its evaluation and security plan consistent with the recommendation, if any, of the reviewer or document its reasons for not doing so. Requirement R6 also requires each transmission owner to implement procedures for protecting sensitive or confidential information made available to third-party reviewers or developed under the Reliability Standard from public disclosure

While the Commission adopted the standard, it directed NERC to submit an informational filing within 2 years that addresses whether the physical security reliability standard should be applicable to additional control centers.  It also gave NERC 6 months to propose modifications to clarify the use of the phrase "widespread" instability in Requirement R1.

The FERC's rule will become effective 60 days after its publication in the Federal Register.

FERC considers Physical Security Reliability Standard

Federal energy regulators are considering a new national standard for protecting the physical security of the U.S. electric grid.  Given the importance of electric reliability and concern over terrorist attacks and sabotage, electric reliability organization NERC has proposed a Physical Security Reliability Standard known as CIP-014-1.  If adopted by the Federal Energy Regulatory Commission (FERC), the standard would become enforceable against transmission owners and operators.

Under U.S. law, the FERC has jurisdiction over the network of wires and transformers that make up the nation's bulk transmission system.  The Energy Policy Act of 2005 expanded the Commission's authority to impose mandatory reliability standards on the bulk transmission system.  Working with the nation's chief electric reliability organization (North American Electric Reliability Corporation, or NERC), the Commission has adopted a series of reliability standards covering matters including communications among utilities, cybersecurity, and interconnections.

On July 17, 2014, the FERC issued a notice of proposed rulemaking proposing to approve NERC’s proposed Physical Security Reliability Standard (CIP-014-1).  NERC has described this standard as designed to enhance physical security measures for the most critical Bulk-Power System facilities and thereby to lessen the overall vulnerability of the Bulk-Power System to physical attacks.  The standard requires owners and operators of transmission facilities to identify and protect critical transmission stations, substations, and control centers whose damage through physical attack could result in spreading outages or other reliability problems.

The proposed physical security reliability standard also includes provisions protecting sensitive or confidential information from public disclosure, calling for third party verification and periodic reevaluation of critical facility identification, threats assessment, and security plans.

The FERC solicited public comment on the proposed physical security reliability standard through September 8, 2014.  Over 30 parties filed comments, with additional reply comments filed by September 22.

With the proposed Physical Security Reliability Standard now pending before the FERC, we may soon see its adoption.  The FERC has scheduled the matter for its November 20 deliberations.  Assuming CIP-014-1 is adopted, owners and operators of regulated facilities will need to comply with the new standard, and to plan for further tightening up of the physical security of the electric grid in the coming years.

FERC settles 3rd Southwest blackout case

A California public utility has settled claims by federal electricity regulators related to the September 8, 2011, blackout in the southwestern United States.  Following an investigation by the Federal Energy Regulatory Commission (FERC) and electric reliability organization North American Electric Reliability Corporation (NERC), Southern California Edison Company has agreed to pay a $650,000 civil penalty and undertake additional compliance actions.

According to previous investigative reports, the 2011 blackout started when a 500-kilovolt transmission line owned by Arizona Public Service Company tripped out of service, causing cascading power outages through automatic load shedding as other equipment quickly overloaded.  In the end, the outage affected over 5 million customers, shedding 7,835 megawatts of peak demand and over 30,000 megawatt-hours of energy.

Following the blackouts, both FERC and NERC launched investigations into what had happened.  As a federal agency, FERC has regulatory authority over the reliability of the electric bulk power system.  NERC is a not-for-profit international regulatory authority whose mission is to ensure the reliability of the bulk power system in North America, and has been designated by FERC as the nation's electric reliability organization.

In July, FERC announced a $3.25 million settlement with Arizona Public Service.  In August, FERC announced a $12 million settlement with California's Imperial Irrigation District.

Today, FERC announced that it has approved a stipulation and consent agreement between FERC’s Office of Enforcement, NERC, and Southern California Edison Company.  Through a joint investigation, FERC Office of Enforcement staff and NERC determined that the utility violated the Protection and Control group of NERC's Reliability Standards.  In particular, the investigation found that Southern California Edison failed to adequately coordinate its intertie separation scheme at the San Onofre nuclear generating station switchyard with certain other protection systems.  Enforcement staff and NERC found this violation to be a serious deficiency that undermined reliable operation of the Bulk Power System.

Through the settlement, Southern California Edison will pay a civil penalty of $650,000.  Of this penalty, $125,000 will be paid to the U.S. Treasury, $125,000 will be paid to NERC, and $400,000 will be invested in additional reliability enhancement measures.

With Southern California Edison's case resolved, all three of the vertically integrated utilities known to be implicated by FERC's investigation have now settled their alleged violations by agreeing to pay penalties.  Will further penalties be forthcoming?  Will the penalties and ordered reliability measures keep the lights on the next time the grid is stressed?

FERC approves second Southwest blackout penalty

A California irrigation district has agreed to pay a $12 million penalty to settle its role in a 2011 power outage affecting over 5 million people in California, Arizona, and Mexico.

The September 8, 2011 outage started when a 500-kilovolt transmission line owned by Arizona Public Service Company tripped out of service, causing cascading power outages through automatic load shedding as other equipment quickly overloaded.  In the end, the outage deprived customers of 7,835 megawatts of peak demand and over 30,000 megawatt-hours of energy.

Swiftly on the heels of the outage, the Federal Energy Regulatory Commission and electric reliability organization NERC launched an investigation into what had happened -- and whether any laws or regulations had been violated.  That investigation focused on APS and five other entities believed to have been involved: 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.  Last month, the Commission approved a $3.25 million settlement with APS.

Today, the Commission issued an order approving a stipulation and consent agreement resolving  Imperial Irrigation District's role in the blackout.  Imperial Irrigation District is a not-for-profit, publicly owned, vertically integrated utility and political subdivision of the State of California.  The sixth largest utility in California, Imperial Irrigation District Electricity provides electric power to more than 145,000 customers in the Imperial Valley and parts of Riverside and San Diego counties.

Through their investigation, Commission enforcement staff and NERC found Imperial Irrigation District violated 10 requirements of four Reliability Standards on transmission operations and transmission planning, including a failure to coordinate its operations planning with neighboring systems.  The Commission noted that these violations were serious deficiencies that undermined reliable operation of the Bulk Power System.

Through that stipulation, Imperial Irrigation District agreed to pay a civil penalty of $12 million.  Of this amount, at least $1.5 million will go to the U.S. Treasury and another $1.5 million will go to NERC, and at least another $9 million will be invested in reliability enhancement measures that go beyond mitigation of the violations and the requirements of the mandatory Reliability Standards.  These reliability enhancements will include construction of one or more utility-scale battery energy storage facilities within IID’s transmission operations area, with the money spent by December 31, 2016.

Two of the six entities known to be targeted by the Commission's investigation have now settled their alleged violations by agreeing to pay penalties.  Perhaps more significantly, APS and Imperial Irrigation District represent two of the three vertically integrated utilities implicated.  Will the FERC/NERC investigation lead to further settlements soon?  What impact will the Imperial Irrigation District settlement and penalty agreement have?