Papers

Multi-settlement electricity markets typically permit firms to bid increasing supply functions (SFs) in each market, rather than only a fixed price or quantity. Klemperer and Meyer’s (1989) single-market supply function equilibrium (SFE) model extends to a computable SFE model of a multi-settlement market, that is, a single forward market and a spot market. Spot and forward market supply and demand functions arise endogenously under a closed-loop information structure with rational expectations. The closed-loop assumption implies that in choosing their spot market SFs, firms observe and respond optimally to the forward market outcome. Moreover, firms take the corresponding expected spot market equilibrium into account in constructing their forward market SFs. Subgame-perfect Nash equilibria of the model are characterized analytically via backward induction. Assuming affine functional forms for the spot market and an equilibrium selection mechanism in the forward market provides for numerical solutions that, using simple empirical benchmarks, select a single subgame- perfect Nash equilibrium.

Incentives for a supplier in the forward market decompose into three distinct effects: a direct effect attributable solely to the forward market, a settlement effect due to forward contract settlement at the expected spot market price, and a strategic effect arising due to the effect of a firm’s forward market activity on the anticipated response of the firm’s rival. Comparative statics analysis examines the effect of small parameter shocks on the forward market SFs. Shocks that increase the elasticities of equilibrium supply and demand functions tend to make firms more aggressive in the forward market, in that they bid higher quantities at most prices. Expected aggregate welfare for the multi-settlement SFE model is intermediate between that of the single-market SFE model and that of the perfectly competitive case.

Summary: 

There is growing evidence that the cost savings potential of the Title IV SO2 cap-and-trade program is not being reached. PUC regulatory treatment of compliance options appears to provide one explanation for this finding. That suggests that PUCs and utility companies should work together to develop incentive plans that will encourage cost-minimizing behavior for compliance with the EPA’s recently issued Clean Air Interstate Rule.

McBride Johnson, Philip. Turf Wars" - an Essay. Distributed to the Harvard Electricity Policy Group, Fifty-Ninth Plenary Session. Cambridge, MA. May 20, 2010. 4 pages."

Venkataraman, G. et al. Cost-Benefit Analysis of Flexibility Retrofits for Coal and Gas-Fueled Power Plants August 2012-December 2013." NREL. December 2013."

Excerpt from the Introduction:

In January 2004, a World Bank (WB) mission, including both WB staffers and two outside consultants, visited Moscow to review the proposal of RAO-UES, , the stateowned electric utility, to restructure the Russian power sector in ways that would promote competition and render the sector more efficient. The objective of the WB mission was to produce two Policy Notes, one on market design, and the other on regulation. After extensive review of documents and meetings with a broad array of critical players in the market, as well as interaction with Russian counterparts, the Policy Notes were written in June 2004. Those papers, based on the submissions of the two outside consultants (Larry Ruff for market design and Ashley Brown for regulation), were distributed within the Russian power sector.

Excerpt from the Background section:

 

The Brazilian Power Sector, Latin America's largest, unique among energy suppliers to the world's leading economies, is almost completely dependent on one resource for its energy supply: water. Of its 65, 134 MW of installed generating capacity, in 1998 more than 90% was hydro. A substantial amount of that hydro capacity is located on only a few rivers. The sites for the generating facilities, by virtue of the nature of the resource, are generally far removed from major load centers, leaving the country highly dependent on long transmission lines to move electricity from the producer to the consumers. This dependence greatly complicated Brazil’s coordination and optimization in the use off its resources. Seasonal and regional differences in precipitation and water levels, coupled with the fact that most dams are multi-purpose facilities, providing irrigation and navigation as well as energy production, gave rise to a very sophisticated national model for coordination and dispatch. The model worked quite well in operating the generation and transmission sectors in a reasonably efficient manner.

Historically, the ownership of the power sector has changed from private to state and then back to private ownership. Indeed, the nationalization of the industry was only completed in the late 1970's, and even then it was not 100% nationalized. State ownership, however, did not necessarily mean ownership by the national government. Although the Brazilian Constitution vests responsibility for the electricity sector with the national government, in fact, much of the distribution sector was owned by state governments. In some states, including major ones such as Sao Paulo, Minas Gerais, Parana, Rio Grande do Sul, and Rio de Janeiro, the state government-owned utilities were at least partially vertically integrated. By the early to mid 1990’s when restructuring came on the agenda, the industry structure was clear. With the exceptions of nationally owned distribution companies in Rio de Janeiro, Espirito Santo, Brasilia and a few scattered, privately owned companies, the distribution companies were, as noted, owned by state governments. The part of the industry owned by the national government was generally housed under the umbrella of the government holding company, Eletrobras. These entities included four large generating and transmission companies: Chesf, FURNAS, Eletronorte, and Eletrosul (later Gerasul); the industry research arm, CEPEL; and the energy efficiency program, Procel. The huge Itaipu hydro plant was operated by an independent governmental authority, created pursuant to a treaty with Paraguay, with whom the facility is shared. The entire electric sector was, nominally, at least, subject to the “regulatory” authority of the National Department of Water and Energy (DNAEE). DNAEE’s staff was almost entirely composed of employees of regulated entities on loan to the regulator for stated periods of time, and was anything but independent. While it had a role in approving tariffs and was often consulted on industry related matters, it lacked an independent governing board, any independent and final authority of its own, and functioned generally as only a small piece of the overall bureaucratic structure of the industry. Overseeing DNAEE and responsible for policy within the sector was the Ministry of Mines and Energy.

Executive Summary:

Electricity markets employ open access and non‐discrimination to foster competition, market entry, and innovation.    The physical characteristics of the electricity system require explicit consideration of key elements in electricity market design.  Pricing and settlement rules for the real‐time market must provide efficient incentives, both for short‐term operations and long‐run investment. The ERCOT energy‐only market design emphasizes the need to get the real‐time prices right.    The recent innovation of the ERCOT Operating Reserve Demand Curve (ORDC) addressed the fundamental problem of inadequate region‐wide scarcity pricing that has plagued other organized markets, which have exhibited inadequate incentives both for reliable operations and efficient investment. 

ERCOT employs an open wholesale electricity market as the basis for short‐term reliable electricity supply as well as for long‐term investments to maintain reliability in the future.  A review of energy price formation in ERCOT leads to two important conclusions: (i) while the ORDC is performing consistently within its design, scarcity price formation is being adversely influenced by factors not contemplated by the ORDC; (ii) other aspects of the ERCOT market design must be improved to better maintain private market response to energy prices as the driver of resource investment, maintenance expenditure and retirement decisions.   

The paper identifies three general issues that have affected ERCOT energy prices in recent years, and recommends policy and price formation improvements consistent with efficient market design. These recommendations cannot reverse the impact of broader economic trends, such as low natural gas prices, or national policies, such as subsidies for investments in renewable resources.  However, the stress of these forces has exposed areas where there is a need for adjustments to pricing rules and policies within ERCOT.  

Excerpt from the Executive Summary

Background

The Environmental Protection Agency’s proposed Clean Power Plan (CPP), published in June 2014, raises substantial operational challenges for regional transmission organizations (RTOs). In the CPP, EPA specifies emission reduction targets for 49 of the 50 states, based on EPA’s modeling that purportedly shows that each state can achieve the specified reduction targets through the use of four “building blocks.” States are to develop plans to meet the targets between 2020 and 2030, and are offered “flexibility” to use any combination of the four building blocks specified and/or other means (if approved by EPA) to achieve these targets. The State plans – required by June 30, 2016 (unless an extension is granted) - must specify how each state intends to meet the targets.

While there are many issues, questions and concerns with the ability of states and utilities to meet EPA’s emission reduction targets based on the use of EPA’s four building blocks (or through other means), building block 2, in particular, raises substantial issues for systems operators and RTO/ISO market operations because it involves changing the current methods of how electricity is dispatched throughout the nation’s bulk power systems.

Either FERC or the states have always overseen how security constrained economic dispatch is conducted to maintain reliability while cost-effectively serving customers. But, if EPA’s proposed rule becomes final, it, and not the system operators that federal and state regulators have entrusted, will make such critical decisions for our nation’s utility customers regardless of costs.

SUMMARY

Taking action to address climate change by reducing U.S. emissions of greenhouse gases (GHGs) is among President Obama’s major goals. At an international conference in Copenhagen in 2009, he committed the United States to reducing emissions of greenhouse gases 17% by 2020, as compared to 2005 levels. At the time, 85 other nations also committed to reductions.

Since U.S. GHG emissions peaked in 2007, a variety of factors—some economic, some the effect of government policies at all levels—have brought the United States more than halfway to reaching the 2020 goal. Getting the rest of the way would likely depend, to some degree, on continued GHG emission reductions from electric power plants, which are the largest source of U.S. emissions.

In June 2013, the President released a Climate Action Plan that addressed this and other climate issues. At the same time, he directed the Environmental Protection Agency (EPA) to propose standards for “carbon pollution” (i.e., carbon dioxide, the principal GHG) from existing power plants by June 2014 and to finalize them in June 2015. Under the President’s timetable, by June 2016, states would be required to submit to EPA plans to implement the standards.

On June 2, 2014, EPA responded to the first of these directives by releasing the proposed standards.

The proposal relies on authority given EPA by Congress decades ago in Section 111(d) of the Clean Air Act (CAA). This section has been little used—the last use was in 1996—and never interpreted by the courts, so a number of questions have arisen regarding the extent of EPA’s authority and the mechanisms of implementation. EPA tends to refer to the regulations as “guideline documents”—although that term is not used in the statute—perhaps to indicate that the section is intended to give primary authority to the states. The proposed guideline document would set interim (2020s averages) and final (2030) emission rate goals for each state based on four “building blocks”—broad categories that describe different reduction measures; in general, however, the policies to be adopted to reach these goals would be determined by the states, not EPA.

EPA faced a number of issues in developing the proposed regulations:

• How large a reduction in emissions would it propose, and by when?

• What year would it choose as the base against which to measure progress?

• How flexible would it make the regulations? Would it adopt a “mass-based” limit on total emissions or a rate-based (e.g., pounds of carbon dioxide per megawatt- hour of electricity) approach?

• What role might allowance systems play in meeting the goals?

• Will compliance be determined only by the actions of power companies (i.e., “inside the fence” actions) or will actions by energy consumers (“outside the fence”) be part of compliance strategies?

• Would states and power companies that have already reduced GHG emissions receive credit for doing so? What about states and power generators with high levels of emissions, perhaps due to heavy reliance on coal-fired power? Would they be required to reduce emissions more than others, less than others, or the same?

• What role would there be for existing programs at the state and regional levels, such as the Regional Greenhouse Gas Initiative (RGGI), and for broader greenhouse gas reduction programs such as those implemented pursuant to California’s AB 32?

This report summarizes EPA’s proposal and answers many of these questions. In addition to discussing details of the proposed rule, the report addresses a number of questions regarding the reasons EPA is proposing this rule; EPA’s authority under Section 111 of the CAA; EPA’s previous experience using that authority; the steps the agency must take to finalize the proposed rule; and other background questions.

Electricity, supplied reliably and affordably, is foundational to the U.S. economy and is utterly indispensable to modern society. The National Academy of Engineering has called electrification the greatest engineering achievement of the 20th century (Constable and Somerville, 2003). Generating electricity also creates pollution, however, especially emissions of air pollutants. While the most severe and life-threatening pollution from electric power plants is largely a thing of the past in America, power plant emissions of particulates as well as oxides of nitrogen and sulfur (NOx and SOx) 1 still cause harms and contribute to increases in morbidity and mortality (Bell et al., 2008; Laden et al., 2006; Pope et al., 2009). Those harms include premature deaths, contributions to illnesses such as asthma, and increased hospitalizations, and electricity prices do not fully incorporate the costs of those harms (NRC, 2010b). Harms from greenhouse gas (GHG) emissions—to which the power sector is an important contributor, accounting for nearly 40 percent of all domestic emissions (EPA, 2016)— remain almost completely unpriced and thus above the level they would be if market prices reflected their full costs.

EXCERPT:

On June 2nd, the Obama Administration’s Environmental Protection Agency (EPA) released its long-awaited proposed regulation to reduce carbon dioxide (CO2) emissions from existing sources in the electricity-generating sector.  The regulatory (rule) proposal calls for cutting CO2 emissions from the power sector by 30 percent below 2005 levels by 2030.  This is potentially significant, because electricity generation is responsible for about 38 percent of U.S. CO2emissions (about 32 percent of U.S. greenhouse gas (GHG) emissions).

 

On June 18th, EPA published the proposed rule in the Federal Register, initiating a 120-day public comment period.  In my previous essay at this blog, I wrote about the fundamentals and the politics of this proposed rule (EPA’s Proposed Greenhouse Gas Regulation: Why are Conservatives Attacking its Market-Based Options?).  Today I take a look at the economics.

On the occasion of President Xi’s State Visit to Washington, D.C., the United States and China today marked another major milestone in their joint leadership in the fight against climate change with the release of a U.S.-China Joint Presidential Statement on Climate Change. The Statement, which builds on last November’s historic announcement by President Obama and President Xi of ambitious, respective post-2020 climate targets, describes a common vision for a new global climate agreement to be concluded in Paris this December. The Statement also includes significant domestic policy announcements and commitments to global climate finance, demonstrating the determination of both countries to act decisively to achieve the goals set last year.

Hogan, William. Illustrating two models of locational operating reserve demand curves. Presentation to the Harvard Electricity Policy Group, October 1, 2009. 62 pages.

EXCERPT FROM THE INTORDUCTION:

On June 2, 2014 the U.S. Environmental Protection Agency (EPA) announced its proposed performance standards for reducing carbon dioxide (CO2) emissions from existing power plants under the Clean Air Act Section 111(d).1 The proposed rule requires each state to reduce its CO2 emissions rate from existing fossil fuel plants to meet state-specific standards (in pounds per MWh) starting in 2020, with a final rate for 2030 and beyond.2 The EPA estimates that the rule will achieve a 30% reduction in CO2 emissions from the U.S. electric power sector in 2030 relative to 2005 levels. Once the rule is finalized in 2015, states will have until June 2016 to submit initial state implementation plans, to be finalized by June 2017 for stand-alone plans, and by June 2018 for multi-state plans.