Power Markets
Subscribe to Power Markets's Posts

EPA Proposes CO2 Emission Limits for New Power Plants and on Track to Regulate CO2 Emissions from Existing Plants by 2015

by Jacob Hollinger and Bethany Hatef

The U.S. Environmental Protection Agency (EPA) has issued a proposed rule concerning carbon dioxide (CO2) emissions from new coal-fired and natural gas-fired power plants. The September 20 proposal meets a deadline set by President Obama in a June 25 Presidential Memorandum and keeps EPA on track to meet the President’s June 2015 deadline for regulating emissions from existing power plants. Once the September 20 proposed rule is published in the Federal Register, interested parties will have 60 days to comment on it. 

Under EPA’s September 20 proposal, which replaces an earlier, April 2012 proposal, new coal plants would be limited to 1,100 pounds of CO2 emissions per megawatt-hour (lbs/MWh) of electricity produced, with compliance measured on a 12-operating month rolling average basis.  The proposed rule would also require new small natural gas plants to meet a 1,100 lbs/MWh emission limit, while requiring larger, more efficient natural gas units to meet a limit of 1,000 lbs/MWh. 

EPA is required to set emission limits for new plants at a level that reflects use of the “best system of emission reduction” (BSER) that it determines has been “adequately demonstrated.”  For coal, EPA has determined that the BSER is installation of carbon capture and sequestration (CCS) technology that captures some of the CO2 released by burning coal.  In essence, EPA is saying partial CCS is the BSER for new coal plants. But for gas, EPA is saying that the BSER is a modern, efficient, combined cycle plant.  Thus, CCS is not required for new gas plants.

An important feature of the proposed rule is the definition of a “new” plant. Under the pertinent section of the Clean Air Act (CAA), a “new” plant is one for which construction commences after publication of a proposed rule. EPA’s regulations, in turn, define “construction” as the “fabrication, erection, or installation of an affected facility,” and define “commenced” as undertaking “a continuous program of construction” or entering “into a contractual obligation to undertake and complete, within a reasonable time, a continuous program of construction.” 

EPA has concluded that its new proposal will have “negligible” benefits and costs – it won’t reduce CO2 emissions and it won’t raise the cost of electricity. This is based on EPA’s conclusion that even in the absence of the new proposed rule, all foreseeable new fossil fuel plants will be either modern, efficient combined cycle natural gas plants or coal plants that have CCS. In essence, EPA is proposing emission limits that it thinks would be met even in the absence of new regulations.

But if the rule won’t reduce CO2 emissions, why issue it?  First, EPA is of the view that it is required by the CAA to issue the rule; having already determined that CO2 emissions are endangering public health and welfare, EPA is required by § 111(b) of the CAA to publish regulations to address those emissions.  Second, EPA thinks the rule will provide regulatory certainty about what is expected of new plants.  Third, and perhaps most importantly, the rule [...]

Continue Reading




United Kingdom Government Confirms Change to Sustainability Criteria for Biomass

by Caroline Lindsey

The Department of Energy and Climate Change (DECC) in the United Kingdom published its response to its “Consultation on proposals to enhance the sustainability criteria for the use of biomass feedstocks under the Renewables Obligation (RO)” on 22 August 2013 (the Response). The original consultation was published on 7 September 2012.

In the Response, the UK Government confirms that it will proceed with its proposals to revise the content and significance of the sustainability criteria applicable to the use of solid biomass and biogas feedstocks for electricity generation under the Renewables Obligation (RO). The RO is currently the principal regime for incentivising the development of large-scale renewable electricity generation in the United Kingdom. Eligible electricity generators receive renewables obligation certificates (ROCs) for each megawatt hour (MWh) of renewable source electricity that they generate. Biomass qualifies as renewable source electricity, subject to some conditions.

Changes to the criteria

The sustainability criteria associated with the RO is broadly divided into greenhouse gas (GHG) lifecycle criteria, land use criteria and profiling criteria. There will be changes to all of the criteria, but the significant changes relate to the first two criteria, and will take effect from 1 April 2014.

In general terms, the GHG lifecycle criteria are designed to ensure that each delivery of biomass results in a minimum GHG emissions saving, when compared to the use of fossil fuel. The savings are measured in kilograms (kg) of carbon dioxide equivalent (CO2eq) per MWh over the lifecycle of the consignment (sometimes referred to as “field or forest to flame”). The UK Government has confirmed that all generating plants using solid biomass and / or biogas (including dedicated, co-firing or converted plants and new and existing plants) will be on the same GHG emissions trajectory from 1 April 2020 (200 kg CO2eq per MWh). In the meantime, new dedicated biomass power will be placed on an accelerated GHG emissions trajectory (240kg CO2eq per MWh). All other biomass power will remain on the standard GHG emissions trajectory (285kg CO2eq per MWh) until 1 April 2020.

Changes to the land use criteria will also be introduced. In particular, generating plants using feedstocks which are virgin wood or made from virgin wood will need to meet new sustainable forest management criteria based on the UK Government’s timber procurement policy principles.

The land use criteria set out in the European Union (EU) Renewable Energy Directive 2009 (RED) will continue to apply to the use of all other solid biomass and biogas, with some specific variations for energy crops. As is the current position, the land use criteria will not apply to the use of biomass waste or feedstocks wholly derived from waste, animal manure or slurry.

The new sustainability criteria will be fixed until 1 April 2027, except if the EU mandates or recommends specific changes to the sustainability criteria for solid biomass, biogas or bioliquids, or if changes are otherwise required by EU or international regulation.

Making compliance mandatory

Currently, whilst generators using [...]

Continue Reading




Possible UK Power Shortages Raise Concerns

by Thomas Morgan and David McDonnell 

A warning from the UK’s energy regulator, Ofgem, on 27 June 2013, that the ‘buffer’ capacity of spare electricity on the UK’s national power grid could drop to as little as 2% of national supplies by 2015, has raised concerns in relation to the possibility of widespread disruptions in service. This spare capacity currently stands at about 4%.

The warning was linked to an extensive Electricity Capacity Assessment Report, also published by Ofgem that same day. Revised studies have indicated that power supplies will shrink considerably by 2015, as electricity demand in the United Kingdom is not decreasing in the manner previously foreseen by successive governments. This is due to a variety of factors, among them, the low uptake by residential households of environmentally friendly incentives and energy-efficient practices.

Ofgem recommends the implementation of far-reaching market changes proposed by the Department of Energy and Climate Change (DECC). Among other things, DECC stated in a report, also published on 27 June 2013, that the UK electricity sector will require approximately £110 billion of capital investment in the next decade to modernise its infrastructure. This would create opportunities for investment which a range of market players are likely to monitor with interest.

DECC has also emphasised the need for a ‘Capacity Market’ – essentially an insurance policy against the possibility of future blackouts – which would work by providing financial incentives to generators to keep a certain percentage of energy capacity in reserve to cope with spikes in demand.

The British government has been quick to retort to concerns of service disruption, downplaying the risk of blackouts to domestic consumers and, while it is unlikely that blackouts reminiscent of those experienced in the United Kingdom in the 1970s will be relived, the very publication of a formal warning from Ofgem highlights the potential significance of the concern.




FERC Imposes Whopping Penalty Against Bank and Traders for Allegedly Manipulating Western Power Prices

by Dan Watkiss

In a July 16 order, the Federal Energy Regulatory Commission (FERC) assessed civil penalties of $453 million against a British banking conglomerate (BCL) and four of its power traders for manipulating western electricity markets from from November 2006 to December 2008 in violation of the Federal Power Act (FPA) and Commission regulation 1c.2.  The bank has 30 days to pay its $435 million penalty and disgorge $34.9 million in profits plus interest from its manipulative trades; likewise, the traders have 30 days to pay penalties ranging from $1 million to $15 million each.  The bank announced that it will not pay and instead will contest the finding of market manipulation in federal court.  The penalties are among the highest FERC has ever assessed under the authority Congress conferred on it in 2005 to police market manipulation.

FERC’s Office of Enforcement launched its investigation of BCL in July 2007, culminating in an October 2012 FERC order directing the bank and its traders to show cause why they should not be found guilty of market manipulation and assessed penalties.  Following the investigation, FERC concluded that the bank and traders traded fixed price products not to profit from the relationship between the market fundamentals of supply and demand, but rather to move the daily Index Price in favor of BCL’s long or short financial swap positions at the four most liquid western trading locations:  Mid-Columbia, Palo Verde, North Path 15 and South Path 15. According to FERC’s July 16 order, Enforcement Staff’s investigation unearthed a trove of communications among the BCL’s traders describing the allegedly manipulative scheme and affirming their intent to effectuate it, including so-called “speaking” documents in which traders describe their efforts “to drive price,” “move” the Index and “protect” their swap positions.

As amended to include an anti-manipulation rule modeled on the Securities and Exchange Commission’s Rule 10b-5, the Federal Power Act and FERC’s implementing regulations prohibit an entity from: (1) using a fraudulent device, scheme or artifice to defraud or to engage in a course of business that operates as a fraud or deceit; (2) with the requisite intent; (3) in connection with the purchase, sale or transmission of electric energy subject to the jurisdiction of the Commission.  The Act also empowers FERC to assess a civil penalty of up to $1 million per day, per violation against any person who violates Part II of the FPA (including section 222 of the FPA) or any rule or order thereunder.  As it has in other prosecutions for market manipulation, FERC rejected BCL’s defense that “open market” trading is per se not manipulative.

The July 16 order is noteworthy not only for the amount of penalties FERC assessed, but also for the procedural history of the BCL investigation.  The bank and traders chose to forego their right to an evidentiary hearing before a FERC judge and instead had the Office of Enforcement’s proposed findings of manipulation submitted directly to the Commission for its determination.  The [...]

Continue Reading




California Proposes Energy Storage Procurement Requirement

by Melissa Dorn

The California Public Utilities Commission (CPUC) recently released a proposal that would require the major investor-owned utilities (IOUs) in the state to procure approximately 1.3 gigawatts (GWs) of energy storage by 2020.  Consistent with state’s energy storage bill, Assembly Bill 2514, which passed in 2010, the CPUC’s proposal aims to reduce market barriers and incentivize development of viable, cost-effective energy storage methods.  The CPUC hopes that the rapid growth of energy storage in California will support the state’s renewable energy industry as the state seeks to meet the legislature’s mandate to have one third of California’s energy generated from renewable sources by 2020.  Many renewable energy sources are intermittent, making energy storage technologies important for the integration of a large quantity of renewable energy into the existing electric system.

Central to the CPUC’s proposal are biannual procurement targets for the three major IOUs, Pacific Gas & Electric, Southern California Edison and San Diego Gas & Electric. The CPUC’s proposed aggregate procurement targets for each IOU are divided into three different “use cases” based on the end uses of the energy storage:  transmission-connected storage systems, distribution-connected storage systems, and customer-sited storage systems. The initial proposed procurement targets are: 

* The Totals include the additional interim targets for 2016 and 2018 that were intentionally omitted from this table.

To procure third-party owned energy storage to meet the targets, the CPUC proposed a “reverse auction” market mechanism, similar in structure to the state’s existing Renewable Auction Mechanism for renewable power sources. Under a reverse auction, energy storage providers would bid non-negotiable price bids, and the IOUs select projects starting with the lowest cost. The first auction, proposed for June of 2014, will require the IOUs to procure an aggregate 200 MW of storage. Subsequent auctions will be conducted every two years. The procurement targets are subject to change if the IOUs can demonstrate, among other things, that the energy storage resources bid into the reverse auction are not reasonable in cost, are not cost effective, or were insufficiently competitive.

The CPUC anticipates releasing its final order in October of this year.




NYISO the Next Battlefield for Behind-the-Meter Generation Demand Response

by William Friedman

The Federal Energy Regulatory Commission’s (FERC) approval of the New York Independent System Operator’s (NYISO) demand response compensation program left out a mechanism for compensating demand response from behind-the-meter generation, which prompted the latest outcry from demand response providers.   The demand response providers filed a complaint with FERC claiming discrimination between methods of demand response and seeking to compel the NYISO to compensate behind-the-meter generation demand response.  On the other side of the controversy are power producers who fear that compensating behind-the-meter generation would take money from power generation on the other side of the meter.

Demand response is a reduction in electricity consumption by customers from their expected consumption in response to an increase in the price of electricity or incentive payments designed to induce lower consumption.  In Order No. 745, FERC established a compensation approach for demand response resources by requiring that each regional transmission organization (RTO) and independent system operator (ISO) pay a demand response resource the market price for energy when the resource has the capability to balance supply and demand and when doing so would provide a net economic benefit to consumers.

The NYISO’s Order No. 745 compliance filing was approved by FERC without providing for compensation to behind-the-meter generation.  In other words, consumers with behind-the-meter generation, usually large industrial facilities, will not be compensated for relying on their own generators as an alternative to purchasing power from the market, while other demand response resources that do not generate power will be compensated solely for decreasing consumption.  In response, a number of facilities and aggregators that provide demand response recently complained to FERC seeking an order compelling the NYISO to compensate behind-the-meter generation as part of its demand response program.  The complainants point to neighboring RTOs/ISOs, including ISO-NE, PJM and MISO, which do compensate behind-the-meter generation and argue that excluding behind-the-meter generation violates FERC policy and constitutes undue discrimination.

The demand response providers are opposed by a consortium of independent power producers who argue that including behind-the-meter generation is economically inefficient and creates an improper incentive to move generation behind the meter where it is outside the reach of the RTO/ISO.  The NYISO also filed an answer to the complaint, arguing that forcing the ISO to compensate behind-the-meter generation as a demand response resource raises grid reliability and monitoring concerns.  The NYISO states in its pleading that it is already exploring revisions to its demand response program and the ISO’s internal stakeholder process should be allowed to run its course.  Answers to the complaint were filed last week.  A FERC ruling should be handed down in two to three months.




U.S. Pledges Support for Investments in Sub-Saharan African Power Projects

by Ari Peskoe

Last week President Obama announced a package of programs that aim to increase electricity generation and transmission in Ghana, Kenya, Liberia, Nigeria and Tanzania.  Headlined by $7 billion in U.S. government support and $9 billion in commitments from the private sector to invest in new generation projects, Obama’s initiative aims to “double access to power in Sub-Saharan Africa.” Although details are still forthcoming, the initiative is evidence of the enormous demand in Sub-Saharan Africa for new generation.  New supply supported by the President’s initiative is likely to primarily be large-scale natural gas-fired and hydro generation, and it is not clear how such projects will “double access.”    

Less than a third of people living in Sub-Saharan Africa have access to electricity.  Excluding South Africa, Sub-Saharan Africa has only 28 gigawatts (GW) of generation capacity for a population of approximately 850 million people.  (For context, the Netherlands has 26 GW of capacity for a population of less than 17 million).  With the exception of Nigeria, the five target countries have very low population densities and lower than average urban populations as a percent of the total population.  In other words, dispersed populations either have no electric grid at all or have access to a grid with only meager capacity.

New large-scale generation located near urban centers and industrial zones can be helpful in supplying stressed grids, and such projects are also likely to be the most feasible.  The more daunting task, however, is to provide electricity to dispersed rural populations, 85 percent of whom in Sub-Saharan Africa have no access to electricity.  Obama’s initiative includes $2 million in grants to African-owned and operated enterprises “to develop or expand the use of proven technologies for off-grid electricity benefitting rural and marginal populations.”  The initiative’s private sector commitments also include “installation of 200 decentralized biomass-based mini power plants in Tanzania.”  Such small-scale projects demonstrate that sub-Saharan Africa presents a range of opportunities, but that Obama’s initiative is focused on large-scale projects rather than reaching rural populations with decentralized alternatives.

Of the $9 billion in private sector commitments, just over $1 billion is for wind generation; fuel source for the balance has yet to be specified.  Natural gas and hydro projects, however, are well-positioned to receive the bulk of the support.   According to the most recent statistics (which are a bit out of date and incomplete), the five target countries currently get the majority of their power from natural gas and hydro, and oil is the third most common fuel, providing almost twenty percent of the countries’ electricity.  New investments may include some oil-fired generation, but that fuel is generally more valuable for transportation than power generation.

Coal-fired generation is also unlikely to see major support from Obama’s initiative.  Coal is used for electricity generation only in Tanzania, which is otherwise dominated by hydro and natural gas generation.  Furthermore, in his recent Climate Action Plan, Obama committed to “end to U.S. government support for public financing of new [...]

Continue Reading




Italy: Government Extends Scope of Application of “Robin Hood Tax”

by Carsten Steinhauer

Law Decree no. 69 of 21 June 2013 (theDecree), published in the Official Gazette on 21 June 2013  would expand significantly the application of the “Robin Hood Tax” on electricity production companies, including renewable energy companies (solar, wind and biomass) originally exempt from the tax, by lowering the turnover and taxable income thresholds.

The “Robin Hood Tax” was originally introduced by Section 81, Paragraph 16 of Law Decree no. 112 of 2008, converted by Law no. 133 of 2008.  It provided for a 6.5 per cent increase of the corporate income tax rate (IRES) payable by electricity production companies other than renewables with annual gross revenues exceeding Euro 25 million.

Earlier, Law Decree no. 138 of 2011, converted by Law no. 148 of 14 September 2011, eliminated the exemption for renewable energy companies and reduced the annual gross revenue threshold to Euro 10 million, provided the electricity production company had a taxable income of Euro 1 million.

The new Decree further reduces the gross revenue and taxable income thresholds so that the “Robin Hood Tax” would apply to any energy production company, including renewable energy companies, with:

  • gross revenues in the preceding year of more than Euro 3 million
  • taxable income for the same year of more than Euro 300,000

The additional tax only applies to legal entities that are organised as corporations and are therefore taxable pursuant to Article 73 of the Consolidated Income Tax Code, but does not apply to special purpose vehicles (SPVs) that are organised as limited partnerships.

If confirmed by the Italian Parliament, these changes will increase the IRES for a great number of renewable energy production companies that initially had been exempt from the “Robin Hood Tax.”   In order to become definite, the Decree—which was enacted by the Italian Government—must be converted into law by the Italian Parliament.  The timeline for conversion is 60 days, i.e., 20 August 2013, and the Italian Parliament is entitled to make amendments to the Decree.  Provided that the Italian Parliament confirms the current wording of Section 5, Paragraph 1 of the Decree, renewable energy companies that exceed the new turnover and income thresholds in 2014 will have to pay the increased IRES of 34 per cent, instead of 27.5 per cent.

It is worth noting that the compatibility of the “Robin Hood Tax” with the Italian Constitution has been challenged and an action is currently pending before the Constitutional Court.  In particular, the “Robin Hood Tax” would seem to be in breach of the principles of equality and contribution pursuant to economic capabilities.  The Constitutional Court has not yet scheduled a date for the hearing so that it is impossible to foresee when a decision will be made.




REMIT Set to be Enforced in the UK

by Prajakt Samant and Simone Goligorsky

If the UK Government meets the implementation deadline of 28 June 2013, then the United Kingdom will be one of the first EU Member States to implement the EU regulation on wholesale market integrity and transparency (REMIT). Market participants should ensure that all compliance procedures and trading functions are kept fully up to date with the stricter market abuse regime.

To read the full article, click here.




Southwest Power Pool to Finalize New Integrated Marketplace

by Christopher S. Bloom

The Southwest Power Pool’s (SPP) deadline for revising its tariff to add day-ahead and real-time energy to its Integrated Marketplace is this Friday, February 15.  Federal Energy Regulatory Commission (FERC) granted conditional acceptance of SPP’s revised tariff in October, contingent upon SPP submitting various complying revisions.

The Integrated Marketplace is a change of course from the Energy Imbalance Service (EIS) market that SPP launched in 2007. The EIS market has served as a real-time platform for generators to sell excess energy and for load servers to purchase that energy. EIS reduced dependence on bilateral contracts, and enabled competition between generators to provide the lowest-priced energy, using locational imbalance pricing. The new Integrated Marketplace revamps the EIS by creating a day-ahead market along with a real-time energy and operating reserve market. To reduce energy and transaction costs, the new marketplace will consolidate 16 balancing authorities into a single SPP-operated balancing authority. The Integrated Marketplace will also utilize locational-marginal pricing and will include virtual transactions, auction revenue rights, and a market for transmission congestion rights.

The new day-ahead market will allow generators to submit offers to sell energy and operating reserves, and load-servers to submit bids to purchase energy. After the day-ahead submissions, SPP will clear the offers and bids via security-constrained unit commitment and security-constrained economic dispatch algorithms. The end product will be a financially binding schedule that matches sale offers with demand bids and satisfies operating reserve requirements. For day-of energy sales, settlement will be based on the differences between quantities cleared in the Real-Time Balancing Market and the day-ahead market clearing.

The Integrated Marketplace will also bring virtual bidding to the SPP. For a fee and subject to meeting credit requirements, market participants can enter into transactions that essentially short the price of the day-ahead market. Should those virtual transactions clear, the market participant will be obligated to purchase or sell the energy at the real-time locational marginal price, at a profit or loss. The benefit of virtual transactions is that they allow for convergence of day-ahead and real-time prices, allowing a more accurate reflection of the true value and price of the energy. Market participants will be limited to a single offer or bid per hour at each settlement location for each asset owner it represents.

An additional feature of the Integrated Marketplace is its incorporation of auction revenue rights (ARR) and the related transmission congestion rights (TCR) auction. ARRs are awarded to market participants based on firm transmission rights on the SPP grid. ARR holders can choose to retain their rights and receive a share of the revenue generated in the TCR auction, or ARR holders can convert their ARRs to TCRs. TCRs are tradable and TCR holders are entitled to revenue streams or charges based on the cost of congestion in the hourly day-ahead market associated with the TCRs.

In its October 18 order in Docket No ER12-1179, FERC addressed a number of issues raised in protests to SPP’s proposed Tariff Revisions, conditionally approving the Integrated Marketplace, subject to SPP submitting a compliance filing incorporating [...]

Continue Reading




STAY CONNECTED

TOPICS

ARCHIVES