Earlier this year, the CFTC and FERC announced an information sharing Memorandum of Understanding (MOU) between the two agencies. The agencies have now announced that they have begun sharing market data pursuant to this MOU. In addition, they have created an Interagency Surveillance and Data Analytics Working Group “to coordinate information sharing between the agencies and focus on data security, data sharing infrastructure, and the use of analytical tools for regulatory purposes.”
The MOU derives from the Dodd-Frank Act, which sought to resolve jurisdictional disputes between the two agencies regarding regulation of futures activity that affected energy markets. In recent congressional testimony, FERC Office of Enforcement Director Norman Bay identified the inability to access financial data from CFTC-regulated markets as creating a “gap in the Commission’s ability to conduct effective and comprehensive surveillance of the natural gas and electric markets” that “prevents Commission staff from seeing the complete picture of what is occurring in its jurisdictional markets and from fully integrating the financial information into its automated screens.” In his remarks, Bay identified the implementation of this MOU as a “first step” toward effective information sharing between the two agencies.
This close coordination by the CFTC and FERC means that energy companies must have effective programs in place to monitor their trade and market data, as this very data will be accessible by both agencies as part of their surveillance efforts.
On March 1, the Southwest Power Pool (SPP), transitioned to a more sophisticated electricity market design that, according to SPP, is expected to realize up to $100 million in annual net benefits. SPP is a FERC-regulated Regional Transmission Organization that administers the grid across a 370,000 square mile, nine-state footprint in the south central part of the U.S and serves more than 15 million customers. FERC gave final approval to SPP’s market in January.
Grid operators must assure that electricity supply and demand is balanced at all times. Previously, SPP assured this balance by securing resource commitments in a “real-time” auction market an hour before the system is dispatched. Under the new “integrated marketplace,” SPP will also operate a financially binding “day-ahead market” that secures commitments for each hour of the next day. This market helps assure the lowest-cost resources will be available and gives participants a heads up regarding the next day’s prices, which allows them to make desired adjustments in the real-time market to their day-ahead bids or offers. SPP will also administer a “congestion hedging” market for financial instruments that hedge against congestion costs (measured as price differences between locations on the grid).
SPP’s new market design is generally characterized as a “day-2 market.” All of the other RTOs and ISOs in the nation operate under a day-2 market design. Unlike the three RTOs in the northeast, however, SPP will not operate a forward capacity market to secure future resource commitments further into the future than the next day.
In the latest salvo in an ongoing controversy over state efforts to subsidize local generation capacity development, the Third Circuit in New Jersey Board of Public Utilities v. FERC
upheld a final FERC order
approving a PJM Interconnection
tariff governing its wholesale capacity market. The court denied appeals by the New Jersey and Maryland utility commissions, concluding that the challenged tariff provisions (which sought to prevent uneconomic entry by suppliers in the PJM capacity market that could be facilitated by the use of state subsidies) were a valid exercise of FERC’s jurisdictional authority over regional wholesale electricity markets. The state challengers had argued that the tariff constituted an illegal federal regulation of local generators. The Third Circuit’s decision affirming FERC’s order comes on the heels of two related but distinct district court opinions in New Jersey
which had struck down the state subsidy programs themselves as preempted by federal law.
Under the Federal Power Act (FPA), electric power regulation is divided between zones of federal and state authority. The federal government, through FERC, has exclusive authority over wholesale sales of electric energy in interstate commerce. State governments regulate local retail electricity sales, as well as the actual zoning and siting of individual power plants. When the FPA was passed in 1935, most electricity was sold at retail by vertically integrated utilities and there was relatively little interconnection amongst different state utilities, making it (relatively) easy to demarcate the line between areas of state and federal regulation. As the electricity grid became increasingly interconnected, and with the advent of robust wholesale electricity markets in the 1990s and regional auction market operators such as PJM, this division of authority has blurred, with state and federal actors regularly sparring over the precise boundaries of their respective authority over market activities.
This particular case arose out of the PJM regional wholesale electric capacity market. New Jersey and Maryland, seeking to promote the development of additional capacity resources in their respective states, offered guaranteed revenue streams to certain new generators that would allow them to offer their capacity into PJM markets at below-market prices. PJM’s tariff had a complicated test that would require certain sellers, which offered their capacity to PJM at prices below the net cost of new entry, to mitigate their prices upward toward a level closer to market value. Originally resources built in accordance with a state mandate were exempt
from these mitigation requirements, but once New Jersey and Maryland announced their subsidy plan PJM moved to alter its tariff to eliminate this exemption. FERC approved the tariff change, and the states petitioned for review.
The case demonstrates the complexity of ascertaining precisely where federal authority ends and state authority begins under the FPA. The states contended that the PJM tariff was an attempt to regulate internal state efforts to promote the creation of additional generation resources, an area they argued was squarely within state jurisdiction under the FPA. FERC, on the other hand, argued that the state subsidies interfered with the FERC-jurisdictional wholesale capacity market auctions by artificially depressing wholesale prices. While the Third Circuit ruled in FERC’s favor and affirmed the Commission’s authority over wholesale prices and tariffs, it did not issue broad guidance
on the limits of state and federal power. The issue will likely remain contested in years to come as both state and federal actors continue to explore the outside edges of their respective regulatory authorities.
Yesterday the Supreme Court of the United States again delved into the world of climate change and greenhouse gas regulation, hearing oral argument in Utility Air Regulatory Group v. EPA. It is perhaps fitting that the Court’s consideration happened on the very same day that Congressman John Dingell announced that he would be retiring after nearly sixty years in the House of Representatives and having taken up the mantle of a balanced approach to environmental regulation during his tenure as the longest serving House Member in history. For it was Congressman Dingell who presciently warned back in 2008 of the “glorious mess” that could ensue if Congress did not take on and create a customized legislative approach to addressing climate change, but instead left these issues to regulatory action. All sides in yesterday’s argument would likely agree that the issues under consideration are indeed somewhat “messy”, due in large measure to the difficult challenge of fitting existing Clean Air Act authorities to crafting a comprehensive and reasonable solution to the unique problems posed by climate change.
The Court examined the planned next steps by the U.S. Environmental Protection Agency (EPA) in its efforts to regulate greenhouse gases. Building upon its 2009 finding that greenhouse gases endanger public health and the environment and its consequent regulation of automotive sector emissions, EPA in 2010 developed a suite of permitting rules for stationary sources of carbon emissions, such as refineries, manufacturing facilities, and power plants. Yesterday’s argument focused on whether EPA permissibly concluded that stationary sources of such emissions had to be regulated through state-administered permit programs under the Clean Air Act as a necessary consequence of this prior treatment of greenhouse gases as pollutants. The challenge facing EPA, though, is that the statute is designed with conventional sources of pollution in mind, and contains explicit thresholds reflecting those kinds of pollutants in requiring that larger emitting new facilities install the “best available control technology.” In the case of greenhouse gases, however, those thresholds could subject potentially millions of facilities to permitting requirements due to the high rate and pervasive character of greenhouse gas emissions — an admittedly unworkable outcome. So EPA crafted an administrative approach to “tailor” the permitting requirements to a more manageable and focused number of sources — those emitting 100,000 tons of carbon each year, rather than the statutory limits of 100 or 250 tons per year, depending on the affected industry.
A range of petitioners challenged the decision of the Court of Appeals for the District of Columbia Circuit that upheld EPA’s predicate finding that greenhouse gases endanger public health and the environment, EPA’s and the Department of Transportation’s regulation of motor vehicle emissions, and EPA’s Prevention of Significant Deterioration (PSD) permitting rules. The en banc Court of Appeals likewise did the same, although that consideration yielded a dissent focused on EPA’s lack of authority to rewrite the permitting thresholds. Despite a broad challenge to the Court of Appeals’ holdings, the Supreme Court allowed much of EPA’s construct to stand by declining to grant certiorari on most of the issues raised. The question for argument yesterday was limited to whether the EPA permissibly determined that its regulation of motor vehicles necessarily triggered new permitting requirements for greenhouse gases from stationary sources.
Having seen this issue unfold over many years during my tenure at the White House Counsel on Environmental Quality and earlier at EPA, upon hearing yesterday’s oral argument I was particularly struck by several features, including:
Earlier today, the U.S. Army’s Energy Initiatives Task Force announced that 20 new contractors have been awarded Multiple Award Task Order Contracts (“MATOCs”) for future renewable energy development projects at Department of Defense (“DoD”) installations. These contract awards by the Army Corps of Engineers are part of the Corps’ $7 billion “Renewable and Alternative Energy Power Production for DoD Installations” program, under which DoD hopes to procure reliable, locally generated, renewable, and alternative energy through power purchase agreements. The 20 new contractors join existing pools of pre-qualified contractors offering solar, wind, biomass, and geothermal technologies. Contractors in each pool will compete for individual task orders to develop and maintain green energy projects at DoD installations. The first task order under this program is expected to be issued in the coming months.
Carbon dioxide (CO2) capture and storage (CCS) technologies, used for decades in industries that could produce revenue from the use of CO2 to offset the high costs, have more recently come to the forefront of clean energy policy as a way to reduce CO2 emissions from new and existing coal-fired power plants. In 2013, President Obama announced a Climate Action Plan that included a Presidential Memorandum directing the EPA to work expeditiously to complete carbon pollution standards for the power sector. In response, the EPA has proposed requiring all new coal plants to trap some of their CO2 emissions.
Coal-fired power plants are a major source of man-made C02 emissions, and coal fueled approximately 37% of our domestic electricity production in 2012. Although new power plants may be designed to comply with the proposed EPA standards, implementing CCS technologies would lead to sharply higher costs.
On February 11, 2014, Energy Department official Julio Friedmann, deputy assistant secretary for clean coal, reported to the House Energy and Commerce Oversight and Investigations Subcommittee regarding the Department’s coal research and development activities, including CCS technologies. In connection with his report, Mr. Friedmann remarked that the first generation of CCS technologies would have an estimated captured cost of CO2 of between $70 to $90 per ton if installed at new plants, although a second generation of technologies coming online within a decade could drop the carbon capture costs to $40 to $50 per ton. The overall impact on costs would depend on a number of factors, including the coal used, the CCS technology installed, and the size and type of power plant.
Such extra costs for coal-fired plants would likely price them out of the market in some regions. Many lawmakers and utility groups criticize requirements to install CCS technologies as not commercially viable, arguing that it would make it impossible to build a new coal power plant in the U.S. Friedmann agreed that utilities likely would not invest in CCS technologies without a mandate under the Clean Air Act, but sees the government’s role as enabling the reduction of costs as they enter the market, not commercialization or the determination of economic viability.
The EPA will accept written comments on its proposed CO2 emission standards for new power plants until March 10, 2014.
The unprecedented spikes in natural gas prices due to the recent harsh winter weather have led FERC to approve temporary yet significant waivers of the pricing rules in the mid-Atlantic and New York organized wholesale electricity markets.
Both the PJM Interconnection and the New York ISO attract the resources to keep supply and demand in balance through hourly auctions in which a single market-clearing price is set. And both markets have traditionally capped resource bids at $1,000/mega-watt hour as a means of mitigating potential market power. However, recent gas prices have been so high that the cost of operating some gas-fired generators exceeded the bid cap. Accordingly, some generators could lose money by running.
FERC recently approved temporary rule waivers requested by the market administrators to address this problem. For New York, generators may bid higher than $1,000, but any higher bids selected will not set the market price. Instead, generators with costs higher than $1,000 that are selected in the auction to run will recover the difference in side payments (known as “uplift”). In granting the waiver, FERC observed that not being able to recoup incremental operating costs “would discourage generators from offering service at a time when they are needed.” The waiver will remain through February 28, 2014.
For PJM, the fix is more significant. Cost-justified bids above $1,000 will be allowed and if accepted will set the market price, meaning that all generators, regardless of their bids, will receive a market price above $1,000. In approving the measure, FERC said its action “will ensure that marginal prices paid by consumers appropriately equal the incremental cost of servicing them, and efficient price market signals — not constrained by a cap — should provide market participants with the information necessary to make informed business decisions, including hedging fuel risk.” This waiver will remain through March 31, 2014.
Governments globally are grappling with difficult decisions about green energy policies: maintain green initiatives or remove the strains on economic growth? It is interesting to look across the globe for examples of how different Governments are reacting.
In recent months, the UK has opted to “tweak” its green levies to save households an anticipated average of £50 per year. This has been a highly political issue, with domestic gas and electricity costs becoming a major factor in the increased cost of living in the UK. In particular, the government said it would adjust the Energy Company Obligation scheme (ECO) to give large energy suppliers an extra two years to hit targets and relax some of the scheme’s targets by 33%, subject to the outcome of a consultation by the Department of Energy & Climate Change (DECC).
So, what is the proposed change? First, it is helpful to recall ECO’s original targets and objectives. Effective 1 January 2013, the ECO obliges gas and electricity suppliers to improve the energy efficiency of domestic customers’ buildings by meeting three targets:
After years of controversy, EPA has announced it is planning to approve Texas’ Clean Air Act State Implementation Plan (SIP). EPA had previously rejected Texas’ SIP, contending that is program was incompatible with federal requirements. In particular, Texas objected to EPA’s requirement that they install a permitting regime for Greenhouse Gas (GHG) emissions. However, in a December 2013 submission Texas agreed to revise its Prevention of Significant Deterioration program to grant the state express authority to regulate GHG emissions. The state also clarified its definition of Best Available Control Technology (BACT) to confirm that it incorporated federal BACT standards.
The agreement between Texas and the EPA likely does not mean Texas will drop its legal challenges to the agency’s requirement that SIPs include GHG regulations. However, while those challenges are pending, the agreement allows the state greater latitude to control the permitting process. EPA’s previous refusal to approve Texas’ SIP had caused EPA to install a Federal Implementation Plan, which placed permitting decisions directly in the hands of EPA. This federal program applicable to Texas would be rescinded following the approval of the Texas SIP program.
An earlier post discussed a complaint by the New England Power Generators Association (NEPGA) arguing that the inclusion of a large, high-cost generating plant in an upcoming capacity market auction will artificially suppress clearing prices. NEPGA has withdrawn its complaint because the generating plant’s owner has decided to retire it and, accordingly, the plant will not be included in the upcoming auction. NEPGA says that the market administrator, ISO New England, will address in a stakeholder process the issues that gave rise to the complaint.