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Texas electricity market saw a recent integration of electricity transmission as a part of Competitive Renewable Energy Zones (CREZ). Exploiting the commissioning date of CREZ based transmission integration as an exogenous shock, we analyze the effect of transmission expansion on market clearing prices of Congestion Revenue Rights (CRR). Reduced form estimates suggest that excess transmission led to a lowering of CRR prices for contracts at all Times of Use. We find strong evidence of spatial, distributional, and firm specific heterogeneity. The paper shows that transmission expansion enhanced efficiency of the CRR market in terms of a spatial convergence in prices and a decrease in aggregate auction expenditure of approximately $260 million over a period of 4.5 years post CREZ. Keywords: Congestion Revenue Rights, CREZ, Market Integration, Transmission Expansion, 1. INTRODUCTION Texas electricity market is marked by a substantial wind energy penetration that accounted for about 17 percent of energy use in 2017, (1) up from 9 percent in [...]

Electricity tariffs typically charge residential users a volumetric rate that covers the bulk of energy, transmission, and distribution costs. The resulting prices, charged per unit of electricity consumed, do not reflect marginal costs and vary little across time and space. The emergence of distributed energy resources--such as solar photovoltaics and energy storage--has sparked interest among regulators and utilities in reforming electricity tariffs to enable more efficient utilization of these resources. The economic pressure to redesign electricity rates is countered by concerns of how more efficient rate structures might impact different socioeconomic groups. We analyze the bill impacts of alternative rate plans using interval metering data for more than 100,000 customers in the Chicago, Illinois area. We combine these data with granular Census data to assess the incidence of bill changes across different socioeconomic groups. We find that low-income customers would face bill increases on average in a transition to more economically efficient electricity tariffs. However, we demonstrate that simple changes to fixed charges in two-part tariffs can mitigate these disparities while preserving all, or the vast majority, of the efficiency gains. These designs rely exclusively on observable information and could be replicated by utilities in many geographies across the U.S. Keywords: Tariff design, Socioeconomic status, Pricing, non-convex costs, 1. INTRODUCTION Residential electricity tariffs typically distort--and thus do not allow consumers to respond to--the marginal cost of energy consumption. Rates are typically constant across time and location, despite the [...]

A novel concept of the adaptive emergency transmission rates (ATR) is presented. Traditionally used discrete emergency rates developed for a fixed period of time are replaced by a continuous adaptive rate applicable for any interval of time after contingency. ATR permits increasing power transfer in normal states without degradation of system reliability by allowing the maximal safe loading of electrical facility post-contingency corresponding to the transmission loading relief available via real-time dispatch. The approach is applicable mainly to real-time operations and short term planning and allows to not only lowering the cost of the operation, but also increasing the consistency of the economic dispatch in terms of the operator's discretion. Index Terms--Adaptive, emergency rates, operations, power system security.

In market-based planning and operation, it is very useful to have the information of generation dispatch, congestion, and price as load increases. Therefore, it is beneficial to system planners if the congestion or locational marginal pricing (LMP) versus load is readily available. This can certainly be obtained by repetitively running an optimization model at different load levels. However, this approach is too brute-force to be practical. In this paper, an efficient algorithm is proposed to identify the new binding constraint and the new marginal unit set when the system load increases from the present load level. It addresses the challenge of step changes in generation dispatch when a generation or transmission limit becomes binding. The algorithm also gives the new sensitivity of the new marginal units. Therefore, the generation dispatch, congested lines, and LMP at a new critical load level (CLL) can be easily calculated. Test results are presented in matrix formulation to clearly demonstrate and verify the proposed algorithm. Since the proposed approach is based on linearized model, it should be particularly suitable for short-term planning or operation, although application to long-term planning is also possible. Index Terms--Congestion management, critical load level (CLL), energy markets, generation sensitivity, locational marginal pricing (LMP), optimal power flow (OPF), power markets.

In this paper, we continue to analyze optimal dispatch of generation and transmission topology to meet load as a mixed integer program (MIP) with binary variables representing the state of the transmission element (line or transformer). Previous research showed a 25% savings by dispatching the IEEE 118-bus test case. This paper is an extension of that work. It presents how changing the topology affects nodal prices, load payment, generation revenues, cost, and rents, congestion rents, and flowgate prices. Results indicate that changing the topology to cut costs typically results in lower load payments and higher generation rents for this network. Computational issues are also discussed. Index Terms--Mixed integer programming, power generation dispatch, power system economics, power transmission control, power transmission economics.

The locational marginal pricing (LMP)-based settlement results in a surplus collected by the system operator from the consumers. The nonlinear transmission losses and the constrained operation of the power system due to operating limits, such as power flow limits on transmission lines, cause the accumulation of this surplus. This accumulated revenue, referred to as the network rental in this paper, has two main components: loss rental and constraint rental. This paper develops a method to calculate these different rental components paid by each consumer, by combining the power flow tracing and KKT optimality conditions. This yields quantitative determination of how each consumer has overpaid in the form of loss rental and constraint rental, which in turn can be used to get a better insight of how the rental is accumulated. Simple three-and four-bus systems are used to demonstrate the proposed method. Index Terms--Independent system operator, locational marginal price, network rental, optimal power flow program.

Practical models of competition among power generators who possess market power have generally had to use simplified models of transmission costs and constraints in order to be tractable. In particular, the linearized dc load flow model has been popular in complementarity and other types of oligopoly models. In this paper, we show how such models can be generalized to include quadratic losses, controilable DC lines, and phase shifting transformers. These generalizations preserve convexity of the feasible region, a property that facilitates computation and proof of solution uniqueness and existence. Piecewise and successive linearization formulations are also provided that allow consideration of nonlinear losses in models that require linear constraints. A simple six-bus example illustrates the application of these generalizations. In that example, the impact of losses on prices is much greater under strategic behavior than under competition. Large-scale applications of these approaches to markets in western North America and the European Union illustrate how inclusion of nonlinear losses and controllable DC lines can affect estimates of prices, flows, and economic efficiency indices resulting from oligopoly models. Index Terms--Economics, optimization methods, power generation, power transmission economics.

This paper analyzes the implementability of locational marginal price (LMP) and financial transmission right (FTR) mechanisms in the presence of high voltage dc (HVDC) lines in the regulated (i.e., under the control of system operator) network. The established framework of LMP-FTR mechanism assumes that the system under regulation is fully ac. Unregulated (or private) HVDC lines are taken into account within this framework through proxy-transaction bids from the line owners. However, as the flow over a regulated HVDC line has to be controlled by the system operator himself, the existing LMP-FTR framework becomes insufficient if the system contains or is expanded with regulated HVDC lines. The augmentation that should be made to the existing framework to include regulated HVDC lines is explained in this paper. It is shown that the flow over a regulated HVDC line can be modeled as a non-chargeable bilateral transaction without causing any threat of negative congestion surplus. For this power dispatch model, revenue adequacy of FTRs can be still ensured by means of the conventional simultaneous feasibility test (SFT) model. By utilizing the capacities of dc lines, a more general SFT model is further developed. The modified auction problem is discussed and tested for the non-negativity of net auction collection. The process of revenue adequate issuance of auction revenue rights is explained. Finally, the relative merit of a regulated HVDC line over a private HVDC line is discussed through a case study. Index Terms--Congestion management, financial transmission right, high voltage dc transmission, locational marginal price.

Deregulated electricity markets in the U.S. currently use an auction mechanism that minimizes total supply bid costs to select bids and their levels. Payments are then settled based on market-clearingprices. Under this setup, the consumer payments could be significantly higher than the minimized bid costs obtained from auctions. This gives rise to 'payment cost minimization,' an alternative auction mechanism that minimizes consumer payments. We previously presented an augmented Lagrangian and surrogate optimization framework to solve payment cost minimization problems without considering transmission. This paper extends that approach to incorporate transmission capacity constraints. The consideration of transmission constraints complicates the problem by entailing power flow and introducing locational marginal orices (LMPs). DC power flow is used for simplicity and LMPs are defined by 'economic dispatch' for the selected supply bids. To characterize LMPs that appear in the payment cost objective function, Karush-Kuhn-Tucker (KKT) conditions of economic dispatch are established and embedded as constraints. The reformulated problem is difficult in view of the complex role of LMPs and the violation of constraint qualifications caused by the complementarity constraints of KKT conditions. Our key idea is to extend the surrogate optimization framework and use a regularization technique. Specific methods to satisfy the 'surrogate optimization condition' in the presence of transmission capacity constraints are highlighted. Numerical testing results of small examples and the IEEE Reliability Test System with randomly generated supply bids demonstrate the quality, effectiveness, and scalability of the method. Index Terms--Deregulated electricity markets, electricity auctions, locational marginal price (LMP), mathematical programs with equilibrium constraints, payment cost minimization, surrogate optimization, transmission constraints.