Fifth Circuit Grants EPA’s Request for Power Plant Effluent Rule to Remain in Abeyance

Posted on September 5, 2017 by Katherine O'Konski

On August 22, the Fifth Circuit issued an order granting EPA’s motion to sever and hold in abeyance all judicial proceedings in Southwestern Electric Power Co. v. EPA relating to certain provisions of the Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category Rule (Effluent Rule).  While the Fifth Circuit held all proceedings related to the Effluent Rule in abeyance for 120 days this April, its August 22 order severs and holds in abeyance issues concerning the Best Available Technology Economically Available (BAT) effluent limitations and Pretreatment Standards for Existing Sources (PSES).

Published in November 2015, the Effluent Rule sought to update standards and limitations on various combustion waste discharges at steam-electric power plants, and has been subject to several challenges consolidated in Southwestern Electric Power Co.  EPA announced that it would reconsider the rule in April 2017, and, in an order issued April 24, the Fifth Circuit granted EPA’s request to hold the rule in abeyance until August 12, 2017.  The court also ordered EPA to file a motion to govern further proceedings at the conclusion of the initial abeyance period.

In a letter dated August 11, EPA Administrator Scott Pruitt announced that the agency will conduct a rulemaking proceeding to revise the rule’s BAT effluent limitations and PSES as they apply to bottom ash transport water and flue gas desulfurization wastewater.  A few days later, EPA submitted its Motion to Govern Further Proceedings, requesting that the court sever and hold in abeyance “all judicial proceedings as to all issues relating to the portions of the 2015 Rule concerning the new, more stringent BAT limitations and PSES applicable to (1) bottom ash transport water, (2) FGD wastewater, and (3) gasification wastewater.”  EPA also proposed to file status reports every 90 days and promptly upon the completion of further rulemaking.

With respect to issues in the Effluent Rule that will not be revised by the rulemaking, EPA proposed that litigation should continue, and that the court should direct the parties to file a revised briefing schedule.  The court’s August 22 order grants EPA’s requests, and directs the parties to propose a briefing schedule for the remaining issues within 21 days.

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NYISO, PJM Release Papers on Carbon Pricing in Wholesale Electricity Markets

Posted on September 1, 2017 by Amber Martin

In August, two regional grid operators for the mid-Atlantic region—the New York Independent System Operator (NYISO) and PJM Interconnection, L.L.C. (PJM)—released papers analyzing the feasibility of pricing carbon emissions in the wholesale electricity markets they administer.

NYISO’s paper, Pricing Carbon into NYISO’s Wholesale Energy Market to Support New York’s Decarbonization Goals, prepared by the economic consulting firm The Brattle Group, analyzes how New York State’s aggressive clean energy policies could be pursued through pricing carbon emissions in NYISO’s wholesale electricity markets.  After considering market design options, the report analyzes the customer cost impact of adding a $40/ton carbon charge. The Brattle Group’s analysis suggests that imposing a $40/ton carbon charge would result in very small cost impacts to customers within the -$1.50/megawatt-hour to +$4.60/megawatt-hour range, translating to a total of -1% to +2% change in total customer electric bills.  The report explains that the customer cost impact is limited because, under the scenario it modeled, “although average wholesale energy prices would increase, about 50% of the cost could be offset by returning carbon revenues to customers[,] another 18% would be offset by reduced prices for [Renewable Energy Credits] and [Zero-Emissions Credits] in the presence of higher wholesale energy prices,” among other things.

The PJM paper, Advancing Zero Emissions Objectives through PJM’s Energy Markets: A Review of Carbon-Pricing Frameworks, suggests that development of a carbon-pricing framework that complements PJM’s markets would enhance the policy goals of states seeking to reduce carbon emissions, minimize the impact of those policies on states not pursuing emissions reduction policies, and more directly address concerns over emissions leakage.  To that end, PJM’s paper examines two potential carbon-pricing models:  a regional and a subregional carbon-pricing framework.

According to PJM’s analysis, a regional carbon-pricing framework would apply a uniform carbon price across the PJM footprint to create a carbon cost for each resource, equal to the carbon price multiplied by the number of tons of carbon a resource emits per megawatt-hour, which would be considered part of each resource’s energy supply offer during system dispatch. PJM explains that this model would:

  • Utilize PJM’s current market design (which PJM notes already permits pricing of emission costs in cost-based energy offers),
  • Treat all resources equitably,
  • Align with PJM’s current resource dispatch model, and
  • Eliminate emissions leakage concerns within the PJM footprint (these challenges would still need to be addressed to a lesser extent for energy transfers to and from regions outside of PJM.

PJM’s analysis shows that pricing carbon in this way would decrease total emissions by shifting dispatch away from higher-emitting generation resources. PJM notes that the regional framework is the preferred option because it maximizes market efficiency, but notes that it also requires all of the states in PJM to agree on a carbon-pricing policy—an inherently difficult goal.  In recognition of this challenge, PJM also analyzes a subregional carbon-pricing framework, which PJM believes will adequately accommodate states that have not chosen to price carbon.  Under this framework, the PJM footprint would be split into subregions which either price or do not price carbon into energy offers.  A resource in a carbon-pricing subregion would incorporate its carbon-compliance costs into its energy offer, while a resource in the non-carbon-pricing subregion would submit its normal energy supply offer, as well as what its carbon-compliance costs would be if it were located in the carbon-pricing subregion (used to address the situation where a resource in a non-pricing subregion exports its production to the carbon-pricing subregion and minimize leakage).  PJM notes that this model, while more accommodating of state policy differences, would not prevent regional pricing impacts due to incorporating carbon-compliance costs.

PJM notes that further study is needed to analyze the potential effects of pricing carbon into the energy markets on capacity markets, ancillary services, and transmission congestion, among other things.

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NREL Reports on Demand Charges and Battery Storage Technology

Posted on August 29, 2017 by Jeff Bayne

The Department of Energy’s National Renewable Energy Laboratory (NREL) has issued a white paper on potential markets for behind-the-meter battery storage.  The paper focuses on demand charges, which are charges based on a customer’s peak level of demand.  Demand charges are designed to compensate utilities for the cost of providing sufficient electricity generation and distribution capability to their customers and typically make up 30% to 70% of a customer’s electric bill.

The paper explains that higher demand charges provide a greater opportunity for customers to use battery storage technology as a cost saving strategy.  Storage technology can consistently be deployed to reduce peak demand, in contrast with solar technology, which depends on the weather.

NREL’s analysis is based on an examination of more than 10,000 utility tariffs, covering about 70% of commercial buildings in the continental United States.  The paper notes that the demand charges in these tariffs vary widely.  For example, in New York, the greatest maximum demand charge is more than $50/kW, yet the median of all utility maximum demand charges in New York is just $4.30/kW.  According to NREL, five million commercial customers are currently eligible for tariffs with a demand charge of at least $15/kW, which Greentech Media Research found was a notable threshold for when demand charge management begins to make economic sense.  The state with the greatest number of such customers is California.  However, a geographically diverse range of states (including Georgia, New York, Michigan, and New Mexico) are among the top states in terms of customers with access to demand charges of at least $15/kW.

While this white paper provides a snapshot of market opportunities for battery storage systems, NREL projects that declining costs of solar and battery storage technologies will reduce demand charges in the future.  This could decrease the number of customers financially motivated to adopt these technologies.  NREL adds that increasing the use of demand charges in utility tariffs may unlock additional battery storage markets and strengthen existing ones.

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EPA Schedules Stakeholder Meetings on Defining Waters of the United States

Posted on August 29, 2017 by Jeff Bayne

EPA has scheduled ten teleconferences to solicit recommendations on how to revise the definition of “Waters of the United States.”  A February 2017 executive order directed the Administrator of the EPA and the Assistant Secretary of the Army for Civil Works to review this definition, which determines which bodies of water are subject to protections under the Clean Water Act.

EPA will hold nine issue-specific teleconferences and one that is open to the general public.  The dates and topics of the teleconferences are:

  • Tuesday, September 26, 2017—environment and public advocacy;
  • Tuesday, October 3, 2017—conservation, e.g., hunters and anglers;
  • Tuesday, October 10, 2017—construction and transportation;
  • Tuesday, October 17, 2017—agriculture;
  • Tuesday, October 24, 2017—industry;
  • Tuesday, October 31, 2017—mining;
  • Tuesday, November 7, 2017—scientific organizations and academia;
  • Tuesday, November 14, 2017—stormwater, wastewater management and drinking water agencies; and
  • Tuesday, November 21, 2017—open to general public.

Each meeting will take place from 1:00-3:00 P.M. ET.  Registration will close a week before the date of the teleconference, and EPA will select participants to provide verbal recommendations on a first-come, first-serve basis.

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DOE Releases Study on Electricity Markets and Grid Reliability

Posted on August 24, 2017 by Amber Martin

On Wednesday, August 23rd, the Department of Energy (DOE) issued its Staff Report to the Secretary on Electricity Markets and Reliability.  The report, undertaken at the direction of DOE Secretary Rick Perry, is the result of a months-long effort by DOE staff to assess the reliability and resilience of the electric grid.

Key findings from the report include:

  • Wholesale electric markets are currently functioning as designed—to ensure reliability and minimize the short-term costs of wholesale electricity—despite pressures from flat demand growth, federal and state policy interventions, and the massive economic shift in the relative economics of natural gas compared to other fuels.
  • The recent emergence of natural gas as a top electricity generation resource, coupled with increased wind and solar penetration, flat electricity demand growth, and a host of regulations, mandates, and subsidies at the state and federal levels have negatively impacted traditional baseload generation, particularly coal and nuclear power plants.
  • Although Americans and their elected representatives value the various benefits specific power plants offer, such as jobs, community economic development, low emissions, local tax payments, resilience, energy security, or the national security benefits associated with a nuclear industrial base, these benefits largely are not recognized or compensated by wholesale electricity markets, resulting in state and private efforts to retain established baseload generators and incentivize the development of wind and solar generation.

In addition, the report offers several policy recommendations, including:

  • Wholesale markets: FERC should expedite its efforts with states, Regional Transmission Operators (RTOs), Independent System Operators (ISOs), and other stakeholders to improve energy price formation in centrally-organized wholesale electricity markets.
  • Valuation of Essential Reliability Services (ERS): Where feasible and within its statutory authority, FERC should study and make recommendations regarding efforts to require valuation of new and existing ERS by creating fuel-neutral markets and/or regulatory mechanisms that compensate grid participants for services that are necessary to support reliable grid operations. Pricing mechanisms or regulations should be fuel and technology neutral and centered on the reliability services provided. DOE should provide technical and policy support that strengthen and accelerate these efforts.
  • Bulk Power System resilience: DOE should support utility, grid operator, and consumer efforts to enhance system resilience. Transmission planning entities should conduct periodic disaster-preparedness exercises involving electric utilities, regional offices of federal agencies, and state agencies. The North American Electric Reliability Corporation should consider adding resilience components to its mission statement and develop a program to work with its member utilities to broaden their use of emerging ways to better incorporate resilience. RTOs and ISOs should further define criteria for resilience, identify how to include resilience in business practices, and examine resilience-related impacts of their resource mix.
  • Support federal and regional approaches to electricity workforce development and transition assistance: In partnership with other agencies and the private sector, DOE should facilitate programs and regional approaches for electricity sector workforce development.
  • Hydropower: Encourage FERC to revisit the current licensing and relicensing process and minimize regulatory burden, particularly for small projects and pumped storage.
  • Nuclear Power: Encourage the Nuclear Regulatory Commission to ensure the safety of existing and new nuclear facilities without unnecessarily adding to the operating costs and economic uncertainty of nuclear energy. Revisit nuclear safety rules under a risk-based approach.
  • Coal Generation: Encourage the Environmental Protection Agency to allow coal-fired power plants to improve efficiency and reliability without triggering new regulatory approvals and associated costs. In a regulatory environment that would allow for improvement of the existing fleet, DOE should pursue a targeted research and development portfolio aiming at increasing efficiency.
  • Electric-gas coordination: Utilities, states, FERC, and DOE should support increased coordination between the electric and natural gas industries to address potential reliability and resilience concerns associated with organizational and infrastructure differences. DOE and FERC should support well-functioning commodity markets for natural gas by expeditiously processing liquefied natural gas export and cross-border natural gas pipeline applications.
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