TODAY’S STUDY: THE FUTURE OF RENEWABLE ELECTRICITY, PT. 4

Volume 4: Bulk Electric Power Systems: Operations and Transmission Planning

June 2012 (National Renewable Energy Laboratory)

Introduction

Today, the U.S. electric grid faces a number of technical and institutional challenges, including integrated management of both loads and generation, supporting wholesale electricity markets, facilitating customer participation in the marketplace, reducing carbon emissions, and reducing dependence on petroleum by electrifying transportation. Technical issues associated with these changes challenge legacy grid planning and operational practices, and they will likely require substantial, or perhaps even transformational, changes for the U.S. grid to respond effectively. The rapid deployment of renewable electricity—particularly the addition of 40,000 MW of wind generation—to the U.S. grid over the last 10 years is one driver of change. The Renewable Electricity Futures Study (RE Futures) examines the implications and challenges of renewable electricity generation levels—from 30% up to 90% of all U.S. electricity generation from renewable technologies—in 2050. Additional sensitivity cases are focused on an 80%-by-2050 scenario. At this 80% renewable generation level, variable generation from wind and solar resources accounts for almost 50% of the total generation. At such high levels of renewable electricity generation, the unique characteristics of some renewable resources, specifically resource geographical distribution, and variability and uncertainty in output, pose challenges to the operability of the U.S. electric system.

RE Futures is documented in four volumes. Volume 1 describes the analysis approach and models, along with the key results and insights. Volume 2 describes the renewable generation and storage technologies included in the study. Volume 3 presents end-use demand and energy efficiency assumptions. Volume 4 (this volume) focuses on the role of variable renewable generation in creating challenges to the planning and operations of power systems and the expansion of transmission to deliver electricity from remote resources to load centers. The technical and institutional changes to power systems that respond to these challenges are, in many cases, underway, driven by the economic benefits of adopting more modern communication, information, and computation technologies that offer significant operational cost savings and improved asset utilization. While this volume provides background information and numerous references, the reader is referred to the literature for more complete tutorials.1

This volume also provides an overview of today’s electric power system (the grid), including how planning and operations are carried out to ensure reliability. It then explores the challenges to the grid posed by high levels of variable renewable generation and some changes that are expected to occur in response to these challenges. Finally, this volume concludes with a discussion of the capacity expansion and production cost models used in RE Futures and how they represent the operational issues discussed earlier.

click to enlarge

The North American Electric Power System: The Grid

The electric power system is the infrastructure that converts fuel and energy resources into electric power (thus generating electricity) and carries and manages that electric power from where it is generated to where it is used.2 It is a system of systems that comprises physical networks that include fuel and resources; power plants of many different varieties; electric transmission and distribution line networks and measurement; information and control systems; and virtual networks of money, business relationships, and regulation. Achieving balance among all of these elements is a fundamental challenge for the planning, engineering, and operation of the overall system because of the variability and uncertainty of load and unexpected equipment failures that affect the generation and delivery of electricity. The system of systems is loosely referred to here as “the grid.”

The major physical elements of the grid are generation, transmission, distribution, and load. Generation is the collection of power plants electrically connected to the grid and ranging in size from very small, distributed units3 to central stations rated at over 1,000 MW (Casazza and Delea 2010). Transmission is the collection of networked high-voltage lines (above 100 kV) that tie generation to load centers. High-voltage lines also connect utilities to one another, reduce costs through sharing of resources, and provide enhanced reliability in case of events such as the loss of a large generator. The high-voltage transmission system also enables the wholesale marketplace for electricity. In general, the bulk or wholesale system refers to the network of interconnected generation and transmission lines, while the distribution system refers to the lower-voltage generally radial lines that deliver electricity to the final customer. The load—created by the electrical equipment on the customer’s side of the meter—is electrically part of the overall power system and affects its operation; load completes the system. The largest industrial and commercial customers may be served by transmission directly; the rest are served by the lower-voltage distribution system.

click to enlarge

When the development of electric power began more than 130 years ago, generating plants were isolated and served dedicated customers. Over the next several decades, “utilities” began linking multiple generating plants into isolated systems. By the mid-1920s, it was clear that connections among utility systems could provide additional reliability and savings with fewer cumulative resources. The connection of neighboring utilities provided access to generation reserves in times of equipment failure, unexpected demand, or routine maintenance, as well as improved economics through reserve sharing and access to diverse and lower-cost energy resources. The U.S. grid today is the result of a complex web of legacy designs developed from the early 1920s to the present. By the 1980s, the North American electric system had been transformed from isolated utilities to an interregional grid spanning the continent.

The three large areas or “interconnections” that operate as synchronous4 interconnected systems in the contiguous United States, Canada, and a small portion of Mexico are the Western Interconnection, the Eastern Interconnection, and Electric Reliability Council of Texas (ERCOT) in Texas (Figure 22-1). The three interconnections are connected by a small number of DC connections with very limited transfer capacity.5 Quebec is also connected to the United States and neighboring Canada with HVDC ties. Alaska and Hawaii have their own systems.

Many entities—balancing authorities, regional entities, utilities, power pools, independent system operators (ISOs), regional transmission organizations (RTOs), and other transmission organizations—are involved in running the grid today. At the federal level, the Federal Energy Regulatory Commission (FERC) has regulatory authority over interstate sale of electricity and the operation of regional markets. The North American Electric Reliability Corporation (NERC) has the responsibility, under FERC authority, for power system reliability, operating, and planning standards in the United States, and coordinates with Canada. Every utility in the United States and Canada participates in the NERC reliability assessments to ensure that the transmission system meets standards and will perform reliably. Most criteria for planning of transmission are based on the NERC standards.

click to enlarge

Balancing Authorities

From a system perspective, the balancing authority6 is the critical management element. As defined by NERC, the balancing authority (formerly called control area) is the responsible entity for ensuring the electrical balance between load and generation; the balancing authority maintains frequency and ties to neighboring balancing authorities. Within the balancing authority’s area, generation schedules are established to meet the changing demand. Deviations from this balance result in changes to system frequency and net imports from, or exports to, neighboring balancing authorities. Generally, these imports and exports are scheduled in advance, but deviations from the schedule are common, with limitations on how often these deviations can occur and persist.

Regional Entities

Eight regional entities provide a mechanism to address the differences across the regions in North America (see Figure 22-1). NERC works with the regional entities to improve the reliability of the bulk power system while acknowledging the differences between regions. Membership of the regional entities comes from all segments of the electric industry and accounts for virtually all the electricity supplied in the United States, Canada, and a portion of Baja California Norte, Mexico.

Utilities and Power Pools

From the approval of the Federal Power Act in 1935 to the start of restructuring following enactment of the Energy Policy Act of 1992, the grid was designed to provide reliable electric power at minimum costs to customers and was regulated to ensure “just and reasonable” rates. The dominant business model for U.S. electric power during this period was that of a vertically integrated, investor-owned, and state-regulated local utility monopoly.7 In addition to the investor-owned utilities, there were (and still are) federal, state, and municipal utilities, and rural cooperatives, totaling more than 3,000 load-serving entities. In a few regions—Pennsylvania, New Jersey, and Maryland (PJM); New England; and New York—utilities are organized into power pools to share savings through cooperation with neighbors. In general, utilities that controlled generation also owned and operated the transmission systems. Local utility companies and their customers benefited from the economic exchange of electric energy in power pools across regional networks.

click to enlarge

ISOs, RTOs, and other Transmission Organizations

The Energy Policy Act of 1992 mandated open access to the transmission system. Further access to the transmission system resulted from FERC Orders 888/889 with the creation of ISOs and subsequently in Order 2000 with the creation of RTOs to satisfy the requirement of providing non-discriminatory access to the transmission system. With Order No. 2000, FERC encouraged the voluntary formation of RTOs to operate the transmission grid on a regional basis throughout the United States. Order No. 2000 delineated 12 characteristics and functions that an entity must satisfy to become an RTO (Figure 22-2). In the Eastern Interconnection, the development of RTOs and organized wholesale power markets has transferred a large part of the resource procurement function from states to FERC jurisdiction. The operation and responsibilities of ISOs and RTOs are very similar.

Regions without ISOs and RTOs (such as the Pacific Northwest and the majority of Southeastern states) must conform to FERC’s open access mandate; the power exchange among utilities is mostly facilitated through bilateral contracts and power purchase agreements that limit the scope of market between buyers and sellers.

In addition to ISOs and RTOs, there are three other types of “transmission organizations” in the United States:

• Traditional utilities that participate in ISOs/RTOs can also consist of utilities from one or several states, and can have planning processes and market functions that incorporate the RTO footprint

• Traditional utilities that do not participate in an RTO, and have their own regional planning

• Merchant transmission organizations that plan transmission and seek participants to help fund the transmission project.

The treatment of balancing authorities, regional entities, utilities and power pools, transmission organizations, interconnections, and other such aspects of the U.S. grid within RE Futures is described in Chapter 28.

click to enlarge

Summary and Conclusions

Today’s power system has evolved over the past 130 years from isolated, distributed power plants that serviced local load into three large regionally interconnected systems in the contiguous United States and Canada. Traditionally, the resource adequacy of the system has been based on dispatchable generation under the control of system operators. In addition, with the notable exception of hydroelectric generation, location-constrained resources have not been used. Maintaining balance between demand and generation at all times is a fundamental need. Additionally, system frequency and voltages must be maintained within defined, extremely tight tolerances. Initial studies examining the feasibility of a project are normally followed by more detailed, reliability-focused studies. RE Futures is an initial analysis that requires follow-up studies to analyze in greater detail how the power system will operate to ensure reliability of the bulk power system.

Renewable electricity is available from a very diverse set of resources and technologies. Some are dispatchable, and others—primarily wind and solar PV technologies—are generally non-dispatchable in that system operators can curtail output but cannot increase it if the wind or solar resource is not available. Both wind and solar PV technologies present challenges to power system operators, owing to variability and uncertainty of their generation output on the timescales relevant to the task of maintaining system reliability. However, generation from these variable renewable resources is being added to the electric system now. In particular, wind generation is expanding rapidly in some regions of the United States. As a result, significant operational challenges are emerging, including curtailment resulting from transmission and minimum generation constraints, relatively rare rapid ramps in wind generation resulting from passage of large footprint storm fronts, and increased need for operational reserves due to uncertainty of generation output. Of course, electricity demand also varies and is uncertain, but its behavior is generally well understood based on decades of experience and the developed ability to forecast load with reasonable accuracy a day in advance.

Revised operating procedures and strategies are needed—and are being adopted —to accommodate the characteristics of variable generation. Actual operating experience to date indicates that it is technically feasible to operate an electric power system with wind energy penetrations of 10%–20% of energy generated, albeit with changes in current operational practice to provide increased flexibility and expanded cooperation over longer distances.62 However, operating challenges are leading to curtailment of wind plant outputs during periods of low system demand or transmission congestion. In addition, in some regions, LMPs for electricity have sometimes fallen to values too low to sustain either variable or conventional generation over the mid- to longer term. It is becoming clear that not only must operating procedures evolve to better accommodate variable resources, but also market transformation must ensure appropriate payments for needed energy, capacity, and ancillary services. RE Futures explores some of the operational implications of very high levels of renewable generation (up to 80% renewable generation by 2050).

In many cases, more cost-effective, higher-quality renewable resources are located far from major load centers. Expansion of the electrical transmission system is needed to access and deliver location-constrained renewable resources. Typically, transmission costs averaged across the United States constitute only approximately 10% of the final delivered cost of electricity and are responsible for a relatively small portion of the investment needed to bring energy from a remotely sited generator to load. However, siting and permitting of transmission, particularly lines spanning multiple jurisdictions, is a challenging and lengthy process.

click to enlarge

Future transmission planning needs to be done proactively, looking many (20–40) years into the future, to pursue a broad range of long-term goals, including:

• Maintaining system reliability

• Ensuring adequate dynamic power transfer capability

• Ensuring just and reasonable rates

• Providing access to the most cost-effective renewable (and other) resources

• Electrifying transportation

• Supporting functional electricity markets by minimizing congestion

• Planning for future transmission corridor capacity needs, not just those immediately apparent

• Considering all options, including extra-high-voltage AC and DC, and technology advances such as superconductors and “undergrounding”

• Ensuring non-wire options are fully considered (e.g., efficiency and local distributed generation)

• Minimizing local, regional, and global environmental impacts, including reduced emissions of greenhouse gases, criteria pollutants, mercury, and other harmful pollutants.

All of these goals are driven by the need to optimize societal benefits of the power system relative to costs incurred.

click to enlarge

In addition to transmission, greater operational flexibility will be needed to support high levels of renewable generation. Means to provide this include the following options, some of which are already emerging in practice:

• Enhanced balancing authority cooperation, coordination, or consolidation (as has occurred in Texas, PJM, and MISO)

• More efficient markets with shorter clearing periods, down to 5–10 minutes (as is the case already in MISO, PJM, and other regions)

• New ancillary service markets covering a wider range of needs (e.g., flexibility—faster ramp rates) beyond regulation and reserves markets already operating in much of the United States

• Unit commitment adjustments within the day

• New conventional generation technologies or modifications to existing generators that allow faster ramp rates, lower minimum output levels, quicker start times and shorter minimum-off times

• Improved wind and solar forecasting—along with efficient use of forecasts (as is now occurring in many regions)

• Increased connectivity among neighboring and distant regions

• Expanded electricity flow across the Eastern, Western, and ERCOT Interconnections

• Increased use of demand response (as is occurring now in PJM, ERCOT, California, and other regions)

• New, manageable electrical loads such as electric vehicle charging

• Increased use of storage options.

As described in Volume 1, RE Futures has found that at the hourly simulation level and for the cases examined, the system can meet projected loads with high levels of renewable electricity, including high levels of variable renewable generation. However, the investigation of system reliability—which requires detailed analysis down through the level of a few minutes to a few seconds and the investigation of system security (e.g., through stability and AC power flow analysis) for these high levels of renewable generation—remains to be done. As indicated in this volume, additional studies and experience are needed to examine in more detail, particularly at the sub-hourly level, the quantitative impacts of high renewable generation futures and then validate the measures suggested for addressing the electric power system operating challenges arising from these impacts.

click to enlarge

Additional Research and Analysis Needed

RE Futures examined long-term planning issues, including transmission and generation issues stemming from operation of the electric power system with renewable energy penetrations of 80% and higher. The modeling was done with a standard industry production simulation model that runs on an hourly time step, observing transmission constraints, minimum up-times and downtimes, minimum turndown levels, and unit ramp rates. The model performs economic unit commitment and economic dispatch, based on an optimization that meets load and reserve obligation at minimum cost, subject to various constraints on the system. However, more work must be done to ensure the reliable operation of a system, including the following activities, listed by category:

click to enlarge

• Model Development

o Developing true stochastic planning and operations tools and models that can better address the increased stochastic nature of high penetration levels of variable generation

o Developing detailed dynamic models of current and anticipated load to marry with improved and detailed models of supply technologies

o Improving understanding and developing better models of the operation of conventional power generation technology operating with greater demands on ramp rates and minimum turndown levels; also needed are approaches to retrofit high ramp rates and minimum turndown levels into existing plants as well as develop new fossil energy and nuclear energy units with improved flexibility

o Developing improved models for forecasting day-ahead and hourly performance of weather-dependent variable renewable resources, as well as longer-range forecasts, and incorporation of these models into system operations

• Data Development

o Acquiring more detailed data on the output of variable and renewable resources over large footprints and the correlation of these resources with load. To provide good statistics, years of data are desired, as are new techniques for scaling limited data

click to enlarge

• Analysis

o Conducting sub-hourly feasibility analyses under a wide variety of conditions, including the impact of potential changing weather patterns.

o Studying interconnection-wide power system dynamics and system reliability and stability under high renewable generation scenarios, with variable and renewable resource models that have frequency and inertial response built into their representation of control systems; the same studies need to include HVDC lines with full converter control capability

o Understanding the potential impacts of balancing authority consolidation (and/or seamless coordination) on system reliability, economics, and access to remote resources

o Assessing required evolution of methodology to identify appropriateness and accuracy of required resource reliability standards

click to enlarge

• Market, Business Model, and Regulatory Practice Evolution

o Addressing technical and institutional issues to permit sub-hourly scheduling to access the flexibility of the markets so that regulation, the most expensive ancillary service, does not have to be relied on to balance within the hour

o Conducting research on market changes that may be needed to deal with generation that has near-zero marginal costs

o Exploring alternative business models and regulatory practices for transmission planning, siting, and permitting to enable necessary and economic development of transmission; a particularly important issue to explore is methods to improve collaboration for the planning, siting, permitting and cost allocation of transmission lines that cross multiple states.

RE Futures provides a foundation for future studies that explore further the various sensitivities and scenarios associated with renewable electricity that could impact the electricity sector’s future. This analysis of bulk power issues in high renewable electricity futures identifies the significant opportunities that such futures open, the challenges that they pose, potential pathways to addressing these challenges, and future analytical needs to better understand and address them.

Tweet