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 staff guidance for Clean Power Plan modeling

Staff of the U.S. Federal Energy Regulatory Commission have issued a white paper presenting guidance principles for modeling state plans to comply with the U.S. Environmental Protection Agency's Clean Power Plan carbon regulations from existing fossil fuel-fired electric power plants.

The EPA issued the Clean Power Plan on August 3, 2015 as a regulation under Section 111(d) of the Clean Air Act.  The Clean Power Plan limits carbon dioxide emissions from existing fossil fuel-fired electric power plants.  The final rule provides state specific goals for carbon dioxide emissions from affected electric generating units, including interim emissions goals from 2022 to 2029 and a final goal for 2030.

Due to congressional concern that environmental regulations not jeopardize the reliability of the electric grid, each covered state must demonstrate that it has considered reliability issues in developing its plan.  That consideration of reliability is certain to include modeling.  The Federal Energy Regulatory Commission has entered into an agreement with EPA and the U.S. Department of Energy to coordinate certain activities to help ensure continued reliable electricity generation and transmission during the Clean Power Plan's implementation.

In furtherance of that mission, on January 19, 2016, staff of the Commission released an 18-page white paper identifying four guiding principles that may assist transmission planning entities in conducting effective analysis of the Clean Power Plan and associated state, regional, or federal compliance plans.

These guiding principles address four areas:

• Transparency and stakeholder engagement: "transparency and stakeholder engagement in model development, model inputs and study designs can help identify policy alternatives and effectively evaluate assumptions, while also improving coordination across transmission planning regions."
• Study methodology and interactions between studies: "incorporating changes to current study methodologies can allow transmission planning entities to more effectively assess the impact of the CPP and associated compliance plans."
• Study inputs, sensitivities and probabilistic analysis: "using study inputs that account for uncertainty and test for sensitivity can help effectively assess the impact of the CPP and associated compliance plans."
• Tools and techniques: "adopting new modeling tools and techniques may help transmission planning entities better assess the overall impact of the CPP and associated compliance plans."

The FERC staff white paper notes that while "effectively evaluating the impacts of the CPP may present challenges, these challenges can be mitigated by using appropriate modeling tools and techniques."  Under the Clean Power Plan, states have until September 6, 2016, to submit either a final carbon-cutting plan or to request a two-year extension and to submit an initial plan for EPA review.

Maine explores non-transmission alternatives coordinator

Should Maine designate an entity to coordinate the development of lower-cost alternatives to new electric transmission lines?  The Maine Public Utilities Commission has opened an inquiry to obtain comments on the role of a non-transmission alternative (NTA) coordinator and the parameters for procuring the services of an NTA coordinator.

Modern society counts on electric utilities and power plants to supply consumers with electricity.  As consumer needs and plant economics change over time, utilities have traditionally looked to new infrastructure like transmission lines to meet new needs.  But in some cases, transmission development may not be the cheapest or best way to meet consumer needs; rather, "non-transmission alternatives" such as distributed generation, energy efficiency or microgrids may be able to achieve the same ends for a lower total cost.

Grid modernization -- and the tools needed to manage the process efficiently -- can be controversial.  By order dated May 11, 2015, the Maine Public Utilities Commission declined to designate a "Smart Grid Coordinator" to provide a broad array of services to the state, on the grounds that that the record before it did not support a finding that designate a coordinator to provide all these services was in the public interest.

But the Commission indicated interest in designating someone to provide the services of marketing, implementing, and possibly operating non-transmission alternatives.  To that end, the Commission found "there is the potential for benefits from an entity that has the relevant expertise and a commercial interest in the successful development and implementation of NTAs" -- provided that the entity can deliver its services in a way that provides value to ratepayers.

By a June 30 Notice of Inquiry, the Commission initiated the next phase of its exploration of designating an NTA coordinator.  The Commission requested comment on issues it had previously identified in its May 11 order as requiring further factual development to enable the Commission to determine whether it is in the public interest to designate an NTA coordinator:

1. What duties should be included in the scope of services offered by an NTA coordinator?
2. Should T&D utilities be allowed to bid on an NTA RFP and if so should such services be provided through an affiliate? 
3. If an RFP were seeking proposals for having a non-utility entity operate an NTA in a manner consistent with reliability and cyber security standards, how would the incremental costs to operate the NTA be determined?
4. What type of pricing structures should be considered in developing the RFP?
5. What factors should be considered in bid evaluation?
6. What should be the term of the NTA coordinator contract?
7. What entities should be the counterparties to the contract?
8. What enforcement mechanisms should be included in the contract?
9. What type/amount of financial security should be required?

The Commission also invited comment on any other issues relevant to its consideration of designating an NTA coordinator.  The Commission requests that comments be filed by July 21, 2015.  After comments are received, Commission staff will schedule a meeting to discuss the comments and discuss next steps in the development of a request for proposals.

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 2014 State of the Markets report

U.S. energy markets overseen by the Federal Energy Regulatory Commission in 2014 were impacted by extreme weather and changes in the mix of electric generation resources, according to a report by Commission staff.

The 2014 State of the Markets report issued on March 19 by FERC's Office of Enforcement’s Division of Energy Market Oversight presents Commission's staff’s assessment of recent developments in natural gas, electric, and other energy markets.

Extreme cold temperatures in the first quarter of 2014 affected natural gas infrastructure and power markets across the country.  The price of natural gas in the U.S. reached record high levels, driving corresponding spikes in the price of electricity.  For example, the price of natural gas at the Transco Zone 6 Non-NY pricing point hit $123/MMBtu in January -- about 33 times higher than the average 2013 U.S. price.  Largely due to these price spikes, the spot natural gas price at the Henry Hub pricing point averaged $4.32/MMBtu in 2014, a 16% increase over 2013.

Meanwhile, natural gas and renewable resources continued to displace coal as a fuel for electric power generation.  Total U.S. generating capacity increased 10.8 GW in 2014, with natural gas and renewable projects representing the bulk of new capacity.  At the same time, utilities retired coal-fired power plants, continuing a trend that started in 2012.  Commission staff projects continued coal retirements in 2015, particularly after the April effective date of additional air emissions regulations imposed by the Environmental Protection Agency's Mercury and Air Toxics Standards.

FERC's 2014 State of the Markets report also provides a quick look at 2015 year-to-date market performance.  Wholesale electricity prices rose again this winter, although not as sharply as in the first quarter of 2014.  FERC staff's report suggests factors helping to moderate winter prices included better cold-weather preparation of assets, programs like ISO New England's Winter Reliability Program, better coordination between operators of electric transmission and natural gas pipelines, record high levels of natural gas production, the development of new pipeline infrastructure, and low oil prices.