Pursuant to Subtitle A (Reliability Standards) of the Electricity Modernization Act of 2005, which added a new section 215 to the Federal Power Act (FPA), the Commission is proposing to amend its regulations to incorporate:
(1) Criteria that an entity must satisfy in order to qualify to be the Electric Reliability Organization (ERO) that will propose and enforce Reliability Standards for the Bulk-Power System in the United States, subject to Commission approval;
(2) Procedures governing enforcement actions by the ERO and the Commission;
(3) Criteria under which the ERO may enter into an agreement to delegate authority to a Regional Entity for the purpose of proposing Reliability Standards to the ERO and enforcing Reliability Standards;
(4) Procedures for the establishment of Regional Advisory Bodies that may provide advice to the Commission, the ERO or a Regional Entity on matters of governance, applicable Reliability Standards, the reasonableness of proposed fees within a region, and any other responsibilities requested by the Commission;
(5) Regulations governing the issuance of periodic reliability reports by the ERO that assess the reliability and adequacy of the Bulk-Power System in North America; and
(6) Regulations pertaining to the funding of the ERO.
Excerpt from the Introduction:
The ERCOT Independent System Operator (ISO) is the independent, not-for-profit organization responsible for the reliable transmission of electricity across Texas' interconnected 37,000-mile power grid. The ERCOT ISO has the responsibilities of ensuring reliable power grid operations in the ERCOT region jointly with the electrical energy industry organizations that operate within that region, ensuring open access to transmission ERCOT wide and distribution systems in areas permitting competition, ensuring the timely conveyance of market information to market participants, and ensuring accurate accounting of power produced and delivered.
To support these roles the ERCOT ISO focuses on the development, implementation, and ongoing management of reliable market and operating systems, transmission planning, retail mechanics supporting retail choice, accountable and reliable wholesale settlement and billing systems, and financial risk strategies. 4 ERCOT members serve about 85% of the electrical load in Texas, and have an overall generating capacity of approximately 75,000 Megawatts (MW). Because ERCOT is located entirely within Texas, the Public Utility Commission of Texas (PUCT) is the principal regulatory authority. As of January 2005, ERCOT membership consists of 17 Industrial Consumers, 3 Retail/Commercial Consumers, 41 Electric Cooperatives, 16 Independent Generators, 19 Independent Power Marketers, 36 Independent Retail Electric Providers, 8 Investor Owned Utilities, and 19 Municipal Owned Utilities.
Excerpt from the Executive SummaryL
The California Independent System Operator (Cal ISO) proposal for its electricity Market Redesign and Technology Upgrade (MRTU) builds on basic principles of efficient use of electric networks and the associated locational marginal pricing (LMP). The present report reviews the details of the still evolving design to compare it against related features of other markets, identifies potential problems or internal inconsistencies, and suggests directions for future modifications. In addition to a review of the documents identified below, there has been extensive discussion with the CAISO as the design evolution has continued. The comments here reflect the MRTU design as specified in the documents we reviewed, as clarified in discussions with ISO staff.
The starting principles of the MRTU embrace the essential foundations of a successful electricity market design including bid-based, security-constrained, economic dispatch with locational prices, license plate access charges, bilateral schedules, financial transmission rights, a consistent network model for commercial transactions recognizing actual physical conditions, consistent day-ahead and real-time markets, unit commitment with simultaneous optimization of energy and ancillary services, and a multi-settlement system. The MRTU will be a major and important reform needed to address the difficulties inherent in the original market design that is to be replaced. The MRTU is also a complex package with many interconnected details developed through a lengthy process of analysis and interaction with stakeholders. The present report highlights problematic features of several of these details, ranging from serious matters that require immediate attention to improvements that should be considered for future implementation. The critical problems can be fixed to produce a highly effective market design.
Importantly, this evaluation is limited to the LMP market design and has not reviewed operational elements of the MRTU. In addition, this evaluation is limited to the conceptual description of the LMP market design and has not reviewed the proposed implementation of this market design.
As distributed generation (DG) becomes more widely deployed distribution networks become more active and take on many of the same characteristics as transmission. We propose the use of nodal pricing that is often used in the pricing of short-term operations in transmission. As an economically efficient mechanism, nodal pricing would properly reward DG for reducing line losses through increased revenues at nodal prices, and signal prospective DG where it ought to connect with the distribution network. Applying nodal pricing to a model distribution network we show significant price differences between busses reflecting high marginal losses. Moreover, we show the contribution of a DG resource located at the end of the network to significant reductions in losses and line loading. We also show the DG resource has significantly greater revenue under nodal pricing reflecting its contribution to reduced line losses and loading.
This paper examines a number of issues associated with alternative analytical approaches for evaluating investments in electricity transmission infrastructure and alternative institutional arrangements to govern network operation, maintenance and investment. The economic and physical attributes of different types of transmission investments are identified and discussed. Alternative organizational and regulatory structures and their attributes are presented. The relationships between transmission investments driven by opportunities to reduce congestion and loss costs and transmission investment driven by traditional engineering reliability criteria are discussed. Reliability rules play a much more important role in transmission investment decisions today than do economic investment criteria as depicted in standard economic models of transmission networks. These models fail to capture key aspects of transmission operating and investment behavior that are heavily influenced by uncertainty, contingency criteria and associated engineering reliability rules. I illustrate how the wholesale market and transmission investment frameworks have addressed these issues in England and Wales (E&W) since 1990 and in the PJM Regional Transmission Organization (RTO) in the U.S. since 2000. I argue that economic and reliability-based criteria for transmission investment are fundamentally interdependent. Ignoring these interdependencies will have adverse effects on the efficiency of investment in transmission infrastructure and undermine the success of electricity market liberalization.
Excerpt from the Executive Summary:
This report reviews and evaluates the outcomes of the ERCOT wholesale electricity markets in 2004. It includes assessments of the incentives provided by the current market rules and procedures, and analyses of the conduct of market participants. We find improvements in a number of areas over the results in prior years that can be attributed to changes in the market rules or operation of the markets. However, the report generally confirms prior findings that the current market rules and procedures are resulting in systematic inefficiencies.
In this paper we propose a method for the allocation of fixed (capital and non-variable operation and maintenance) costs at the medium voltage (MV) distribution level. The method is derived from the philosophy behind the widely used MW- mile methodology for transmission networks that bases fixed cost allocations on the “extent of use” that is derived from load flows. We calculate the “extent of use” by multiplying the total consumption or generation at a busbar by the marginal current variations, or power to current distribution factors (PIDFs) that an increment of active and reactive power consumed, or generated in the case of distributed generation, at each busbar, produces in each circuit. These PIDFs are analogous to power transfer distribution factors (PTDFs).
Unlike traditional tariff designs that average fixed costs on a per kWh basis across all customers, the proposed method provides more cost reflective price signals and helps eliminate possible cross-subsidies that deter profitable (in the case of competition) or cost-effective (in the case of a fully regulated industry) deployment of DG by directly accounting for use and location in the allocation of fixed costs. An application of this method for a rural radial distribution network is presented.
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.