Federal Energy Regulatory Commission Order Research Articles

Vehicle-to-Grid Revenue from Retail Time-of-Day Rates, Compared with Wholesale Market Participation under FERC Order 2222

This article compares potential revenue from electric storage in retail and wholesale electric markets. The retail value can be extracted when storage responds to time-of-day retail prices. The wholesale value is enabled by the recent US Federal Energy Regulatory Commission Order 2222, which requires regional transmission operators (RTOs) to allow distributed storage behind the meter to participate in wholesale electric markets. To quantify the value of these markets, we use realistic time-of-day rates and market prices in one RTO’s ancillary service market. Formulae are developed to estimate the value of behind-the-meter storage in wholesale and retail markets, using an example electric vehicle in a fleet setting. The formulae are also used to compare whether or not net metering is available and different charging rates. The aggregate national storage behind the retail meter is very large, given the projected growth of electric vehicles. Our findings indicate the revenue from wholesale markets can be significantly more than that of retail opportunities. However, the potential in either retail or wholesale markets is currently limited by both state policy and incomplete RTO implementation of FERC orders.

Aggregating Distributed Energy Resources: Efficiency and Market Power

Problem definition: The rapid expansion of distributed energy resources (DERs) is one of the most significant changes to electricity systems around the world. Examples of DERs include solar panels, electric storage, thermal storage, and combined heat and power plants. Because of the small supply capacities of these DERs, it is impractical for them to participate directly in the wholesale electricity market. We study in this paper the question of how to integrate these DER supplies into the electricity market, with the objective of achieving full market efficiency. Methodology/results: We study four aggregation models, where there is an aggregator who, with the knowledge of DERs’ utility functions and generations, procures electricity from DERs, and sells them in the wholesale market. In the first aggregation model, a profit-maximizing aggregator announces a differential two-part pricing policy to the DER owners. We show that this model preserves full market efficiency, that is, the social welfare achieved by this model is the same as that when DERs participate directly in the wholesale market. In the second aggregation model, the profit-seeking aggregator is forced to impose a uniform two-part pricing policy to prosumers from the same location, and we numerically show that there can be large efficiency loss. In the third (fourth) aggregation model, a uniform (semiuniform) two-part pricing policy is applied to DER owners, whereas the aggregator becomes fully regulated but is guaranteed nonnegative (positive) profit. It is shown that these models again achieve full market efficiency. Furthermore, we show that DER aggregation also leads to a reduction in the market power of conventional generators. Managerial implications: DER aggregation via profit-seeking and/or regulated aggregators has been investigated by California Independent System Operator and New York Independent System Operator, among others, and the recent Federal Energy Regulatory Commission Order No. 2222 paved the way for aggregators to bid in the wholesale market. Our four aggregation models may shed light on how DERs should be included in the wholesale electricity market. Funding: This work was supported by the King Fahd University of Petroleum and Minerals [Grant INML2106] and the National Science Foundation [Grant 1832230]. Supplemental Material: The online appendices are available at https://doi.org/10.1287/msom.2021.0539 .

Benefits of Local Government Aggregation of Clean Energy Resources: Emerging Opportunities Under FERC Order Number 2222

This paper discusses how U.S. local governments can make money and derive benefits from emerging market opportunities related to distributed energy resources (DERs), like rooftop solar, electric vehicles and water heaters, in the context of Federal Energy Regulatory Commission (FERC) Order Number 2222.

The Evolution of the Multitier Hierarchical Energy Market Structure: The emergence of the transactive energy model

Over the last 10 years, a combination of policy directives and technological advances has led to a rapid and significant addition of distributed energy resources (DERs), such as renewable energy source (RES) generation, demand response (DR), storage, and electric vehicles (EVs), into the distribution grid and behind the meter (BTM) in many power systems around the world. At the same time, the Internet of Things (IoT) revolution has emerged as a major market force that is expected to create massive flexible capacity, which can be harnessed to solve grid problems and assist in the integration of RESs into the grid. The penetration of DERs across various levels of the power system has created a hierarchical market structure where DERs could participate, either individually or through aggregations, in the form of virtual power plants (VPPs) in BTM markets and in distribution and wholesale markets. The landmark Federal Energy Regulatory Commission Order 2222 has further created a high-level regulatory framework for allowing DERs to bypass the distribution grid and directly participate in wholesale energy markets. In this multitier market architecture, transactive energy (TE) markets are emerging by allowing customers, either as individuals or in aggregate, to actively engage in energy markets by negotiating and responding to "value signals," based on price, demand, time of day, and other grid and local market considerations.

Paying for performance: The role of policy in energy storage deployment

Energy storage has long been viewed as a solution to the growing challenge of intermittent electricity supply. However, energy storage deployment remains limited despite falling costs. One reason for this is current market rules that inadequately compensate storage for the value it can provide. A recent policy change in the United States (FERC Order 755) seeks to rectify this by requiring grid operators to compensate providers of frequency regulation services based on their speed and accuracy. This seemingly subtle change has a beneficial effect for fast-acting storage resources. Using a difference-in-differences method, exploiting the fact the Order covers only a subset of U.S. electricity regions, we find the order increases the likelihood projects are built to provide frequency regulation services by about 37%. While cost barriers remain to widespread storage deployment, our results suggest improving market rules to properly reflect the value of storage can overcome many regulatory barriers impeding investment. • In 2011, Federal Energy Regulatory Commission (FERC) introduced Order 755. • Order 755 modified compensation for ancillary services based on speed and accuracy. • This seemingly subtle change had a beneficial effect for fast-acting storage resources. • The Order caused new investments in energy storage that provide frequency regulation. • Lifting market barriers to properly reflect the value of storage can unlock its investment.

How to treat energy storage as a transmission asset?

ABSTRACT For energy storage to be part of the transmission solution, storage developers need to work with transmission owners and follow the Regional Transmission Organization (RTO) transmission planning protocols. Federal Energy Regulatory Commission (FERC) Order 841 mostly treats Electric Storage Resource (ESR) as a generation asset. To date, no FERC order lays out a path for treating energy storage as a transmission asset. One of FERC-jurisdictional RTOs – Midcontinent Independent System Operator (MISO) – has sent a “storage as a transmission-only asset” proposal to FERC, which FERC did not reject but did not approve either. This MISO filing begs the question – how to treat energy storage as a transmission project? The industry needs to understand how RTO cost allocation works for new and existing transmission projects. To appreciate cost allocation, stakeholders need to grasp the fundamentals of transmission project categories. Because to put together a business case for storage, modeling is essential. And modeling for reliability and economic projects vary. Getting into the weeds of transmission planning is what it takes to treat storage as a transmission asset.

Impacts of storage dispatch on revenue in electricity markets

Abstract As electricity storage deployments grow—due to decreasing costs and increasing grid flexibility requirements—market frameworks governing their dispatch and remuneration are a growing area of interest and importance. For example, the recent Federal Energy Regulatory Commission Order 841 instructs independent system operators to remove barriers of entry for storage assets. This paper reviews electricity market rules to inform an accurate representation of storage bidding behavior in day-ahead (DA) and real-time (RT) electricity markets. Storage dispatch strategies are explored using production cost and price-taker models to address two related research questions: (1) will storage assets receive the highest remuneration by bidding into DA markets, bidding into RT markets, or redispatching bids in both markets and (2) how accurate must forecast information be for a redispatch strategy to improve remuneration? Results show that with sufficient ability to forecast prices, redispatching a DA schedule in the RT takes advantage of both markets: a longer dispatch horizon as well as more volatile prices.

Why the vision of interregional electric transmission development in FERC Order 1000 is not happening

The Federal Energy Regulatory Commission (FERC) on March 19, 2020 announced a Notice of Proposed Rulemaking (NOPR)iiFERC Docket RM20-10-000. to further investigate how financial incentives might be used to encourage development of high-voltage electric transmission in the United States. An extension of previous efforts in FERC Order 679 issued in 2006, the NOPR-proposed incentives would consist of up to 250 additional basis points of equity return to be allowed on qualifying transmission projects. The NOPR was published in the Federal Register on April 2, and public comments were due back to FERC by July 1.Such incentives, if adopted, would be helpful to address prior FERC business that is yet undone. Issued in 2011, FERC Order 1000, “Transmission and Cost Allocation by Transmission Owning and Operating Utilities” among other things envisioned coordinated planning of interregional transmission developments spanning between individual Regional Transmission Organizations (RTO) and Independent System Operators (ISO), the operators of the FERC-regulated organized wholesale markets. In addition to traditional goals of generator interconnection and service reliability, the purpose of such interregional transmission development was to support public policy goals including renewable energy development, and lower costs for consumers.But little or no such interregional development has happened since Order 1000. Why? The authors have spent the last several years promoting development of one such interregional transmission project. While the effort is ongoing, the on-the-ground experience to-date clearly shows the reasons why interregional development envisioned by FERC Order 1000 is not happening. The authors offer solutions to the issues, including how the new FERC NOPR for transmission incentives can be helpful.

Valuing intra-day coordination of electric power and natural gas system operations

Increasing renewable energy penetrations and low natural gas prices have increased the reliance of U.S. power systems on natural gas-fired generation. Increased reliance has sparked concerns over and resulted in natural gas deliverability constraints. To mitigate these constraints, research and regulatory reform have tried to improve coordination between power and gas systems. The U.S. Federal Energy Regulatory Commission (FERC) issued Order 809 in 2015 to improve day-ahead and intra-day coordination of power and gas systems. Given little research on intra-day coordination and FERC's recent action, we quantify the value of improved intra-day coordination between gas and electric power systems. To do so, we co-simulate coordinated day-ahead, intra-day, and real-time operations of an interconnected power and natural gas test system using a dynamic natural gas simulation model and a power system optimization model. We find intra-day coordination reduces total power system production costs and natural gas deliverability constraints, yielding cost and reliability benefits. Sensitivity analysis indicates improved intra-day renewable energy forecasts and higher renewable energy capacities increase intra-day coordination benefits for gas network congestion. Our results indicate FERC Order 809 and other policies aimed at enhancing intra-day coordination between power and gas systems will likely yield cost and reliability benefits.

Positive demand response and multi-hour net benefit test

The Federal Energy Regulatory Commission in the USA defines demand response as a means of reducing energy consumption by customers from their expected consumption in response to high energy prices or to incentive payments. Conventional demand response that reduces demand is termed as negative demand response. In certain cases, positive demand response, which increases demand, might be more beneficial. For example, in systems with high peak to off-peak demand ratios, positive demand response can be used during low demand hours, as it reduces ramping needs and hence reduces prices during peak demand hours. Significant benefits may arise, as demand response services are paid proportional to prevailing hourly prices, with the positive demand response resources typically purchased at more economic rates. While positive demand response is used in power systems and other sectors of the economy, there are no current systematic and scientific ways to optimally procure positive demand response resources while ensuring that customer electricity rates are reduced. In this paper, the concept of positive demand response is mathematically formulated. A formal method for scheduling positive demand response is presented and validated on typical test systems to show the benefits. To quantify benefits to customers, as laid out in Federal Energy Regulatory Commission Order 745, a new multi-hour net benefit test is proposed that considers positive demand response in addition to negative demand response. This test is implemented in case studies and a sensitivity analysis is conducted. The paper shows ways to use the proposed formulation to design optimal positive demand response procurement programs.

Proactively planning and operating energy storage for decarbonization: Recommendations for policymakers

Energy storage is poised for explosive growth as a result of technological innovation, expanded state mandates and incentive programs, and new participation models developed under Federal Energy Regulatory Commission Order 841. If storage is done right – charged using clean power, and discharged when grid needs are high and dirtier power can be displaced – it can be a key part of a low-cost, clean grid. But a growing body of literature suggests that storage could actually increase greenhouse gas (GHG) if not managed and incentivized properly.Optimizing storage to drive decarbonization, particularly in states with climate goals and renewable portfolio standards (RPS), will require a coordinated effort from grid operators, policymakers, utilities, developers and other stakeholders. Some key actions that need to be taken include incorporating carbon pricing into state and Independent System Operator (ISO) actions, developing market products to reward storage for supporting renewable energy, tailoring instruments like rate design, incentive programs, regulation, and grid planning/procurement, and providing storage with a GHG signal for co-optimization.These recommendations leverage findings and lessons from existing studies and can be applied to ensure other innovations like electric vehicles, distributed energy resources and thermal storage also have a pathway to decarbonization.

Performance Accuracy Scores in CAISO and MISO Regulation Markets: A Comparison Based on Real Data and Mathematical Analysis

This letter investigates the fundamental differences between how California Independent System Operator (ISO) and Midcontinent ISO calculate performance accuracy scores in their performance-based regulation markets. Both ISOs tend to follow the Federal Energy Regulatory Commission order 755 to pay regulation resources—whether conventional generators or distributed and demand side resources—based on their actual performance. The advantages and disadvantages of each method are systematically explained. First, real-world ISO data are used to show that there may exist major differences between these two methods in scoring accuracy under similar regulation performance scenarios. Next, the root causes for the observed differences are studied mathematically. Finally, some suggestions are made to improve these scoring methods; should these or other ISOs seek to refine their scoring formulas.

An Enhanced Network-Constrained UC Model for Leveraging System Operation Cost and Financial Profitability of Incentive-Based DR Loads

Demand response (DR) programs provide consumers opportunities to play an active role in electricity market operation by encouraging them to reduce and/or shift their electricity usage during peak periods and/or when system security is jeopardized. There are primarily two types of DR programs, including incentive-based DR and price-based DR. This paper focuses on the incentive-based DR. For this type of DR program, although shifting peak loads to off-peak periods could reduce system operation cost, it may raise off-peak electricity prices and the incentives may not be enough to cover the increased payments of DR loads. This would diminish consumers' enthusiasm to the continued participation in DR programs. Federal Energy Regulatory Commission Order 745 states that when dispatching a DR resource as an alternative to a generation resource is cost-effective, which is determined by the Independent System Operator's (ISO) net benefits test, the DR must be compensated at full locational marginal price (LMP) value. However, the order focuses more on load curtailment, but not load shifting. In addition, the net benefits test mainly focuses on consumers' savings, while ignoring operation costs and the value lost by consumers, which may cause system inefficiency. This paper proposes a systematic model for leveraging system operation cost and consumer payment concerns in electricity market operation. The proposed model minimizes the system operation cost, while incorporating explicit LMP formulations and consumer payment requirements into the network-constrained unit commitment formulation. Thus, it determines the proper amount of DR loads to be shifted from peak hours to off-peaks under the ISO direct load control for reducing the operation cost and ensuring that DR load payments will not deteriorate significantly after load shifting. The proposed model is solved in its original mixed-integer nonlinear programming formulation and the mixed-integer linear programming reformulation via piece-wise linear approximation. Numerical case studies illustrate the effectiveness of the proposed model and compare the computational performance of the two formulations.

Prioritizing Demand Response: How Federal Legislation and Technological Innovation Changed the Electricity Supply Market and the Need to Revitalize FERC Order 745

Traditional barriers to entry in the electricity supply marketplace are crumbling due to recent federal legislation and new technology. The Federal Energy Regulatory Commission (FERC)'s Order 745 prioritizes the use of demand response via a uniform pricing mechanism. Through it, demand response is able to provide the same benefit as traditional electricity generation - at a reduced cost - and improve service, reliability, and market development. Consequently, the increased use of demand response reduces prices for regional grid operators, as well as commercial, institutional, and residential consumers. This Note discusses the legal, economic, and policy reasons for upholding Order 745 in the face of transformative change in the electricity supply market and evaluates the history of smart grid legislation leading up to the issuance of Order 745 in 2011. Next, it analyzes how energy intelligence hardware and software allow new entrants into the wholesale electricity supply market in hopes of capitalizing on inefficiencies in regional power distribution and the revolutionary opportunities for residential consumers through new technologies. Most importantly, this Note argues for a reversal of the D.C. Circuit’s decision to vacate Order 745 in the case EPSA v. FERC, decided in May 2014. Such a reversal is necessary because Order 745 falls within FERC’s authority under the Federal Power Act and the loss of a uniform pricing mechanism for demand response resources sold at capacity auctions will harm electricity markets.

Demand Response after EPSA v. FERC Now FERC Can't Do It Alone

Flipping on a light switch calls upon the electric grid for power, and the grid responds by supplying it—a supply response. A demand response reverses this relationship: the end-user changes her electricity usage in response to a price change or in return for compensation. Since the 1970s, state and federal regulatory authorities have slowly opened electricity markets’ doors to participation by demand- as well as supply-side resources. The resulting incremental growth in demand-side participation has shown that all manner of electricity end-users, ranging from large industrial facilities to individual residential consumers, will change their pattern of electricity consumption if doing so can save them money. Further, it is generally understood that such participation would not only reduce the volume of electricity generated and consumed but could also greatly reduce the aggregate cost of generating it. Nonetheless, the electricity sector’s business models and rate designs continue to ignore many potential demand-side participants.One form of demand-side participation, called economic demand response (DR), involves specifying a baseline for a particular end-user’s electricity consumption at a particular time, then providing compensation for a reduction in actual consumption below that baseline. Electricity system operators can often make use of such reductions in much the same way as additional generation resources—meaning that DR can substitute for turning on or even building power plants. In addition, DR is also cheaper than many forms of generation.Demand-side participation, which debuted in the 1970s, has since become more sophisticated and prevalent. Congress endorsed DR with the Energy Policy Act of 2005 and the Federal Energy Regulatory Commission (FERC) pushed it forward in 2008 with Order No. 719 and again in 2011 with Order No. 745. That latter push encountered a major legal hurdle, however, because it entailed FERC arguably exceeding its jurisdiction under the Federal Power Act of 1935 (FPA). The FPA assigns FERC jurisdiction over interstate wholesale sales and transmission of electric energy, as well as services “affecting” rates within FERC’s jurisdiction. However, the FPA reserves to state jurisdiction the regulation of generation facilities, local distribution facilities, and “any other sale of electric energy”—that is, other than at wholesale—including retail sales. When the question of FERC’s jurisdiction to set compensation levels for DR purchased from retail market participants was put to the D.C. Circuit, two judges said that FERC Order No. 745 impermissibly crossed the FPA’s jurisdictional dividing line; the third judge disagreed. FERC was rebuffed after seeking a rehearing en banc to challenge the majority’s interpretation of the FPA. It remains to be seen whether a majority of FERC’s commissioners will decide to seek certiorari, whether the Supreme Court will hear the case, and what the Court will decide if it does—in short, the ultimate fate of the D.C. Circuit’s decision remains unclear. This article describes DR and other demand-side resources before addressing what FERC can do to promote DR now, in the aftermath of the D.C. Circuit’s decision. Of course, the question of what to do now should also be put to other stakeholders, including Congress, the regional transmission organizations (RTOs) and independent service operators (ISOs) that administer wholesale electricity markets, state legislatures, state regulatory authorities, utilities, and DR providers. But this article proposes an ambitious answer for FERC under the current FPA. Its proposal can be summed up in this way: because FERC can’t give up but also can’t go it alone, it should insist that wholesale market participants support DR and it should make DR part of the solution to the problem that states face in having to comply with EPA’s new Clean Power Plan.

Regional transmission organizations: FERC Order 2000

The US Federal Energy Regulatory Commission (FERC) has changed its world. On 20 December 1999, it issued Order 2000, its final rule on regional transmission organizations (RTOs). On 25 February 2000, it followed this with Order 2000-A, which responded to requests for rehearing from many parties with "We meant what we said", and it also clarified a few fine points. Order 2000 calls for, but does not quite require, companies owning transmission systems to put the grid under the control of RTOs. FERC requires transmission-owning companies under its jurisdiction to file certain papers by late 2000 or early 2001. These papers can be either proposals to form RTOs or progress reports on the development of RTO proposals. RTOs will have sole responsibility for operation and expansion of the transmission system, maintaining short-term reliability, establishing and managing tariffs, and responding to requests for service.

Executive summary of the 2000 US regional transmission organization study

Over the past year, the future makeup of the US electric transmission industry has become better defined, although a number of unresolved issues still remain. The Federal Energy Regulatory Commission (FERC) has articulated its vision of a national transmission grid controlled by large entities, which it calls regional transmission organizations (RTO). FERC Order 2000 provides the latest piece of architecture to help define and drive the development of competitive markets for electricity generation and its transmission across the system.

OASISNET: an OASIS network simulator

This paper describes a Web-based simulator of the Federal Energy Regulatory Commission (FERC) mandated Open Access Same-Time Information System (OASIS) network. OASIS is the real-time information network/electronic bulletin board whose specification are spelled out in FERC Order 889. The purpose of the simulator is to provide a tool for study of the various aspects of a multi-node OASIS network and to gain a strong intuitive feel for its operations. For a specified simulation period, the OASISNET simulator reproduces the behavior of an OASIS network using the same communications medium as the actual system, the Internet, and with multiple players using the simulator simultaneously. Users dynamically interact with the simulator through World Wide Web (WWW) browsers. Salient features of the simulator are its modular architecture, the ability to simulate multi-node OASIS network operations and to accept simultaneous access from remote users through the use of client/server technology. The simulation focuses on the dissemination and use of the available transmission capability information. Sample applications of the new simulator are discussed.

The natural gas industry and interest rates: FERC Order 636

In discussing the impact of Federal Energy Regulatory Commission (FERC) Order 636, the latest rule on the restructuring and deregulation of the US natural gas industry, the effect of interest rates on the success of the FERC policy is often overlooked. The thesis of this paper is that interest rates play an important role in integrating seasonal gas markets and in stimulating investment in storage infrastructure. We propose a model to analyse the equilibrium condition for an efficient gas market. Also analysed are the implications of pipeline rate design of FERC 636 for gas despatch decisions.

CROSS‐CONTRACT CREDITING UNDER FERC ORDER 500

In remanding Federal Energy Regulatory Commission (FERC) Order 436, the US. Court of Appeals for the District of Columbia Circuit did not require the FERC to issue a new policy on “take‐or‐pay” contracts between interstate pipelines and natural gas producers. The court asked only that the FERC meet the standard of “reasoned decision making.” FERC Order 500, in proposing the mechanism of cross‐contract crediting to reformulate take‐or‐pay contracts, went far beyond the court's decision.Take‐or‐pay contracts are but one component of an interrelated set of long‐run commitments by both pipelines and gas producers upstream and downstream. The FERC's abrogating take‐or‐pay contracts would reverberate beyond the immediate consequences for pipelines and producers. Implementing Order 500 would change the conditions under which gas producers explore, develop, and extract. It would influence the terms of future lease and royalty contracts with owners of mineral rights, and it would have adverse consequences for end users of gas. Evidence exists that promulgating Order 500 increased spot gas prices. Most take‐or‐pay problems have been resolved through voluntary renegotiation by the parties. Nullifying the remaining contracts through regulation will not accomplish the pro‐competitive goals that have guided the FERC's natural gas policy during the 1980s.