Littérature scientifique sur le sujet « Electric utilities – Spain – Costs »

Historically, utilities have been granted a natural monopoly status through the regulatory process. Under such conditions, utilities need to prove to their regulators that their expenditures were necessary to comply with imposed “obligation to serve.” When these prudency arguments are successful, the utilities may recover their costs plus a rate of return.Some have argued that this structure has not created an environment that fosters productive efficiency. With deregulation on the horizon, the utility business is changing. To survive the 21st century, utilities need to find ways to improve their efficiency. One such avenue is strategic staffing.

It is likely that deregulation of the electric utility industry will force high-cost electric utilities to write off the “stranded” cost of plant and equipment that would be rendered obsolete in a competitive marketplace. In this paper, we examine the financial statement analysis implications of ongoing deregulation. Based on 1993 data for a sample of 111 large investor-owned electric utilities, our analyses suggest that it is possible to use financial statement data to form estimates of these potentially stranded costs. In addition, we find that recent trends toward deregulation are associated with an increase in the significance of the firm's cost structure in explaining the relation between market values and book values of equity.

The authors use survey and interview data from California homeowners to understand customers’ trust in their utility company. The authors find that customers’ beliefs about the reliability of electricity do not predict trust. Instead, what matters are beliefs that the utility company does a bad job managing customer service, costs, and wildfires. Distrust among survey respondents aligns with interview participants’ descriptions of utility companies as powerful, greedy monopolies that benefit themselves at the expense of helpless consumers. These results have implications for the energy transition and, more generally, understanding potential challenges experienced by technocratic institutions.

In Spain, the water supply service is a municipal responsibility and in general is a sector without competitors. For this reason, an efficiency analysis attains greater significance. This study uses Data Envelopment Analysis (DEA) to estimate the efficiency of different urban water utilities. An extensive data search, where several variables such as the capital expenditure, the cost of material, or the labor have been recorded, has allowed evaluating the relative efficiency of the most important Spanish water distribution networks in using their resources. Furthermore, their sustainable efficiency has also been evaluated by including a variable representing the percentage of water losses. Results reveal the weaknesses of inefficient utilities and help to detect potential aspects that these companies should improve. For instance, there is an evident incorrect management of the costs of material by many urban water utilities, which does not happen with the labor. Additionally, the most efficient water utilities regarding the sustainable efficiency help to discover target percentages of water losses for the inefficient ones.

In theory, regulators concerned about inequality will deviate from efficient two-part tariffs, charging lower-than-efficient fixed monthly fees and higher-than-efficient per-kilowatt-hour prices. To quantify that relationship, we develop a measure of the redistributive extent of utility tariffs: the “electric Gini.” Utilities with higher electric Ginis shift more costs from households using relatively little electricity to households using more. In practice, US utilities whose ratepayers have more unequal incomes have higher electric Ginis. But electricity demand is only loosely correlated with income, which means that electricity prices are an indirect and ineffective policy for countering income inequality. (JEL D31, L11, L94, L98)

Stranded costs in the electric utility industry—the past costs incurred by incumbent utilities that could not be recovered in a competitive market environment—have been a troubling and troublesome policy issue for electricity deregulation. Although electricity deregulation surely would have proceeded slowly in any event,1 the stranded cost question— who (customers? shareholder-owners?) will absorb the losses in the forthcoming competitive environment?—has clearly slowed the process even further.

Social costing refers to the regulatory practice of requiring electric utilities to incorporate external costs into utility decision making. This practice is being adopted by a growing number of state public utility commissions (PUCs). The effectiveness of this new regulatory approach in reducing the social costs of supplying electricity will depend on the range of utility decisions covered. We use a utility planning model and illustrative estimtes of environmental costs to analyze the implications of different social costing regimes for generation technology choice, social and private costs of electricity supply and electricity price. Due to large differences in private costs across technologies and fuel types, social costing regulation has little or no effect on the utility's investment decisions, dispatch of generators or output price for many of the external cost estimates considered. Applying social costing exclusively to new generating units could result in increased use of existing units and higher social cost electricity production.

Market responsive pricing is a fundamental requirement if natural gas is to play its full part in meeting Canada's energy needs. Regulation must be modified to enable flexibility in buying, transporting and selling natural gas in a market responsive manner. Taxes should be based on profits, not on revenues and, because utility costs, by definition, flow through to the customers, taxation of natural gas utilities should be equitable in relation to electric power utilities.

This study examines the relation between the market value of equity and nonfinancial pollution measures (sulfur dioxide emissions) that capture firms' exposure to future environmental liabilities. I find that a nonfinancial pollution proxy is value-relevant for high-polluting electric utilities targeted for air pollution abatement by Phase One of the 1990 Clean Air Act Amendments (CAAA). On average, these utilities' exposure to (unbooked) future environmental liabilities decreased their mean 1990 share price by 16 percent. Moreover, the value relevance of the nonfinancial pollution proxy (1) increased in response to the passage of the stringent 1990 CAAA environmental legislation, and then (2) declined as the market subsequently reduced estimated compliance costs in response to changing economic and technological factors. Utilities not targeted by Phase One of the 1990 CAAA faced minimal exposure to future environmental liabilities and I find no significant relation between their pollution indicators and share prices. I also find that investors in the high-polluting rate-regulated utilities that were targeted by Phase One positively value a favorable regulatory climate.

South African electricity tariffs were relatively low compared to the rest of the world. The average South African business has for long taken this advantage for granted and is now surprised to realise that electricity is becoming an expensive and scarce commodity. The South African electricity supply industry is far more complex than the average person may think. The infrastructure supporting this industry is extremely costly; takes long to develop and build and requires careful planning and management. There are many sources of energy and many technologies for generating electricity. However, many of these do not appear quite ready to serve the needs of the industry. The manufacturing industry depends heavily on electricity. The recent power outages and tariff increases have served as a cruel reminder of this fact. The automotive sector has lost many days of production and the increasing electricity costs erode the profitability of the affected companies. The automotive suppliers and vehicle manufacturers have expressed their concerns. Indications are that some have reduced the number of employees and may even face bankruptcy. This research aims to gain the perspective of senior managers in the automotive industry regarding the impact of the increased electricity tariffs on their manufacturing costs. Naturally, all electricity consumers will be affected by this. However, this research aims to investigate the significance of the effect on the automotive industry as well as obtain some indication of which factors determine the level of dependency. Each company has to react strategically to the situation and apply those measures which are available to them. This research determines how strongly the industry feels about reacting and which strategic measures they will apply. The outcome is descriptive of the circumstances in the industry and indisputably serves as an indication of the financial impact of electricity tariff increases.

Marginal pricing is the traditional pricing method in pool based electricity markets, however pay-as-bid is an alternative that has been the focus of recent studies. One way of comparing the outcomes of these two pricing schemes is by examining their market equilibria. These equilibria have been analyzed in depth for both pricing methods under the assumption of a perfect market. Marginal pricing market equilibria has also been examined under oligopolistic markets, however, the same attention has not been given to oligopolies based on pay-as-bid pricing.
In this thesis, we study the possible outcomes of an oligopolistic electricity market under pay-as-bid pricing. For this purpose, we introduce, develop and test a new concept called defensive Nash equilibrium, which combines the risk adverseness of power suppliers with the traditional notion of Nash equilibrium. The test cases studied compare market outcomes between pay-as-bid and marginal pricing under various market power assumptions.

This dissertation investigates the perceived riskiness of electric utilities based on their mix of residential and industrial customers. While previous studies have attempted to develop a simple measure of the total riskiness of individual customer classes, this study examines the relative riskiness of the total utility as impacted by customer mix. Because the cost of risk is an element in the determination of the utility's revenue requirement, it impacts the set of optimal tariffs derived from a constrained welfare-maximization problem. The null hypothesis that investors do not base their perception of the riskiness of a utility on the customer mix is tested against the alternatives that residential customers decrease and that industrial customers increase the perceived riskiness of a utility. The hypothesis is examined using cross-sectional data for 1981. The weighted-average, after-tax cost of capital is used to measure the relative riskiness of the utility. In addition to the customer mix variables, the explanatory variables include operational and regulatory variables. The analysis provides support for the hypothesis that investors do not differentiate the riskiness of a utility based on the size of the residential class. Further, the analysis permits rejection of the alternative hypothesis that investors perceive a utility to be more risky when its customer mix is heavily industrial. The results suggest that, in fact, investors may associate greater risk with an absence of industrial customers.
Ph. D.

In an electricity market cleared by merit-order economic dispatch we identify necessary and sufficient conditions under which the market outcomes supported by pure strategy Nash equilibria (NE) exist when generating companies (Gencos) game through continuously variable incremental cost (IC) block offers. A Genco may own any number of units, each unit having multiple blocks with each block being offered at a constant IC.
Next, a mixed-integer linear programming (MILP) scheme devoid of approximations or iterations is developed to identify all possible NE. The MILP scheme is systematic and general but computationally demanding for large systems. Thus, an alternative significantly faster lambda-iterative approach that does not require the use of MILP was also developed.
Once all NE are found, one critical question is to identify the one whose corresponding gaming strategy may be considered by all Gencos as being the most rational. To answer this, this thesis proposes the use of a measure based on the potential profit gain and loss by each Genco for each NE. The most rational offer strategy for each Genco in terms of gaming or not gaming that best meets their risk/benefit expectations is the one corresponding to the NE with the largest gain to loss ratio.
The computation of all NE is tested on several systems of up to ninety generating units, each with four incremental cost blocks. These NE are then used to examine how market power is influenced by market parameters, specifically, the number of competing Gencos, their size and true ICs, as well as the level of demand and price cap.

Thesis (Ph. D.)--Georgia State University, 2005.
Title from title screen. Arun Rai, Johnathan Wareham, committee co-chairs; Subhashish Samaddar, Joseph Katz, committee members. Electronic text (249 p. : ill. (some col.), col. maps) : digital, PDF file. Description based on contents viewed July 13, 2007. Includes bibliographical references (p. 239-247).

Thesis (MBA)--Stellenbosch University, 2000.
ENGLISH ABSTRACT: The South African Electricity Distribution Industry is riddled with tariffs. Every utility in South Africa probably uses some method for allocating cost, whether it is theoretically founded or not. There are currently over 2000 different tariffs in South Africa and the need for rationalisation has been widely recognised and acknowledged. Many of these tariffs have not been the outflow of accepted methodologies but rather a function of individual utility policy and practices. There is however a dire need to standardise such methodologies in the future. A standardised methodology might be the only way to eventually rationalise the thousands of tariffs that exist in the electricity industry. Government has emphasised the importance of tariffs to be cost reflective in the future. The only possible way to reach this objective would be to determine clear and concise methods of allocating cost that can be utilised by the entire industry. This study project describes a standardised methodology for determining the cost to supply different customer categories in an electricity distributor. The methodology offers enough flexibility not to bind any party into laboursome, complex and time consuming costing activities. It does however require that the costs of a distributor are carefully investigated and all functions performed in the utility are isolated. This is referred to as ringfencing of costs.
AFRIKAANSE OPSOMMING: Die Suid-Afrikaanse Elektrisiteitverspreidingsbedryf het veelvuldige tariewe. Elke utiliteit in Suid-Afrika gebruik waarskynlik 'n metode vir kostetoedeling, wat nie noodwendig teoreties gebaseer is nie. Huidiglik is daar meer as 2000 verskillende tariewe in Suid-Afrika en dit word alom besef en erken dat gronde vir rasionalisering bestaan. Baie van die tariewe het nie ontstaan uit die gebruik van aanvaarbare berekeningsmetodes nie, maar was eerder die gevolg van individuele beleid en praktyke van utiliteite. Daar is 'n dringende behoefte om hierdie berekeningsmetodes in die toekoms te standardiseer. 'n Standaard metode mag die enigste manier wees om uiteindelik die duisende tariewe wat in die elektrisiteitsbedryf bestaan te rasionaliseer. Die regering het die belangrikheid dat tariewe in die toekoms koste reflekterend moet wees benadruk. Die enigste moontlike manier om hierdie doelwit te bereik, is om helder en duidelike metodes vir koste toedeling te bepaal vir gebruik deur die hele bedryf. Hierdie verhandeling beskryf 'n standaard metodologie om die koste te bepaal om verskillende klantegroepe in 'n elektrisiteitsverspreider van krag te voorsien. Die metodologie bied voldoende plooibaarheid om geen party aan arbeidintensiewe, kompleks en tydrowende kostebepalings te verbind nie. Dit vereis egter dat die koste van 'n verspreider noukeurig ondersoek word en dat alle funksies wat verrig word uitgelig word. Hierna word verwys as afbakening van kostes.

Electricity prices in competitive markets are extremely volatile with salient features such as mean-reversion and jumps and spikes. Modeling electricity spot prices is essential for asset and project valuation as well as risk management. I introduce the mean-reversion feature into a classical variance gamma model to model the electricity price dynamics as a mean-reverting variance gamma (MRVG) process. Derivative pricing formulae are derived through transform analysis and model parameters are estimated by the generalized method of moments and the Markov Chain Monte Carlo method. A real option approach is proposed to value a tolling contract incorporating operational characteristics of the generation asset and contractual constraints. Two simulation-based methods are proposed to solve the valuation problem. The effects of different electricity price assumptions on the valuation of tolling contracts are examined. Based on the valuation model, I also propose a heuristic scheme for hedging tolling contracts and demonstrate the validity of the hedging scheme through numerical examples. Autoregressive Conditional Heteroscedasticity (ARCH) and Generalized ARCH (GARCH) models are widely used to model price volatility in financial markets. Considering a GARCH model with heavy-tailed innovations for electricity price, I characterize the limiting distribution of a Value-at-Risk (VaR) estimator of the conditional electricity price distribution, which corresponds to the extremal quantile of the conditional distribution of the GARCH price process. I propose two methods, the normal approximation method and the data tilting method, for constructing confidence intervals for the conditional VaR estimator and assess their accuracies by simulation studies. The proposed approach is applied to electricity spot price data taken from the Pennsylvania-New Jersey-Maryland market to obtain confidence intervals of the empirically estimated Value-at-Risk of electricity prices. Several directions that deserve further investigation are pointed out for future research.

Thesis (MDF)--Stellenbosch University, 2014.
The recent transformation in the Ugandan energy sector has led to a significant surge in private electricity generation companies in the country. These companies have a heterogeneous capital structure and they tend to charge different tariff rates for the electricity generated. While the capital structure might have an important role to play in differential tariff setting, it is not clear to what extent it influences the tariff structure of electricity generation projects. Thus, the objective of this study was to examine the effect of capital structure on the tariff of electricity generation projects in Uganda after controlling for other factors such as operation and maintenance costs, technology used for generation, project development costs, and installed capacity of generation plants on the generation tariffs. Using cross-sectional data from 29 companies as at September 2014, a bootstrap linear regression analysis was used for estimation. The results of the study indicated that the higher the debt portion in the capital structure, the lower the generation tariff. However, the impact of debt in the capital structure was not statistically significant. What stood out is that renewable technologies have a much lower generating tariff than non-renewable technologies.

Defence date: 20 June 2003
Examining board: Prof. Dr. Joam Carmona, Universidad de Santiago de Compostela ; Prof. Dr. Giovanni Federico, Instituto Universitario Europeo ; Prof. Dr. Jaime Reis, Instituto Universitario Europeo ; Prof. Dr. Luciano Segreto, Università degli Studi di Firenze
PDF of thesis uploaded from the Library digitised archive of EUI PhD theses completed between 2013 and 2017

The concept of “Cloud computing” became very interesting in recent years because it enables optimization of resources used and costs paid for it. Considering all advantages, this approach is applied widely in business systems of general purpose. In recent years, in literature it is possible to find considerations related to application of this approach in corporate systems as electric power utilities. Having in mind that such types of systems represent infrastructure ones that have great impact to the security of people and utilities, a very important question related to information security should be seriously considered. This chapter discusses advantages and disadvantages of application of cloud computing in electric power utility systems.

Electric utilities over the domain affected with ecological issues associated with standard fossil fuel-established plants are examining more within the potentiality of interposing energy sources type of plants into the system as an alternative. Integration of Demand Side Management (DSM) and Supply Side Management (SSM) is required in a rational power system planning that implies concurrent deliberation of both qualitative and quantitative problems like costs, fuel mix, and reliability of power supply. This chapter examines the economic and environmental ability of power supplies initiation into an existing peak deficit power system, incorporating both DSM and SSM plans. The Generation Expansion Planning (GEP) study is carried out in the power system for the period of 24 years planning horizon.

Nations are facing today the transition to cleaner, more reliable and affordable energy systems where power grids are becoming less centralized, more flexible and digitalized, and where not only power utilities, but also consumers are playing a significant role. Distributed Energy Systems (DES) constitute a key element in such transition, with decentralized renewable energy generation near the consumption points, energy storage, electric vehicles, and energy management systems, with the potential to ensure continuous supply and achieve higher efficiency, while reducing costs and adverse environmental impacts. This chapter presents a review of the recent advances in the design and development of DES, focusing on the effect of taking into consideration the consumption profile and behaviour of the end-users. The chapter also revises the limitations of DES and summarizes the future directions of DES development.

Innovative technologies such as OTEC achieve commercial development when potential investors decide that the return on the investment will repay the estimated development costs plus a profit, with an acceptably low risk of cost overruns. Industrial experience shows that the estimated cost to complete development of a new technology generally increases as development proceeds from the conceptual design through pilot development, demonstration, field testing, and final commercial manufacture (Merrow et al., 1981). The ratio between final cost and initial design estimate is strongly dependent on the extent to which the manufacturing process employs already developed equipment, procedures, and facilities. New projects that require “high technology” for their success, such as jet engines or nuclear power plants, have been characterized by large underestimates of the final costs, whereas the costs of projects that are firmly based on existing technology, such as the development of “supertankers,” have been accomplished well within the usual industrial uncertainty margin of ± 15 to 20%. The accuracy of the estimate is also strongly dependent on the thoroughness of the systems engineering evaluation that is done before development proceeds. Commercial applications of OTEC have been proposed in three principal categories. The first includes OTEC power plants mounted on floating platforms that would generate 50- to 400 MWe (net) of onboard electric power. The need to minimize plant size makes it mandatory to use closed-cycle OTEC for these applications. The second category includes land-based or shelf-mounted plants designed to supply power in the 50- to 400-MWe range to municipal utilities. Either open- or closed-cycle systems could be suitable. The third category comprises small (5- to 20-MWe) land-based or shelf-mounted OTEC plants designed for island applications where electric power generation, mariculture, fresh-water production, supply of cold water for air-conditioning systems, and fuel production could be combined to offer an economically attractive OTEC system despite the relatively high cost of power for small OTEC installations. Open-cycle OTEC plants may be the preferred choice for the third category. The estimated investment costs of installed complete OTEC systems, measured in dollars per kilowatt of net OTEC electric power generated, differ significantly among the three categories.

The Walter C. Beckjord Generating Station sits on the banks of the Ohio River, less than twenty miles southeast of Cincinnati, in Clermont County, Ohio. Beckjord offers a near-perfect case study of the costs of grandfathering. Construction of the plant was announced in November 1948, and its first 100-megawatt coal unit was operational by June 1952. Five additional units came online between 1953 and 1969. Because the units were constructed prior to 1971, all were exempt from the EPA’s New Source Performance Standards. For most of the 1970s, they also managed to avoid complying with any emission limitation under Ohio’s implementation plan for meeting the sulfur dioxide NAAQS, even though Ohio’s original plan, approved by the EPA in 1972, would have subjected Beckjord to a state emission standard—1.6 pounds of SO2 per million Btus of heat input—that was only 33 percent less stringent than the federal new-source standard of 1.2 lbs/MMBtu. In 1973, Ohio utilities convinced the U.S. Court of Appeals for the Sixth Circuit to invalidate the Ohio plan on procedural grounds. The court ordered the EPA to hold an additional hearing at which regulated plants could voice their objections, but before the agency could oblige, the governor of Ohio withdrew the plan from consideration. A year later, Ohio submitted a far less stringent proposal that would have allowed Beckjord to continue emitting at its uncontrolled level: 4.8 lbs/MMBtu. But that plan, too, was struck down on procedural grounds, this time by a state environmental review board. In 1976, after Ohio failed to offer any replacement for its second proposal, the EPA stepped in with a federal plan that would limit Beckjord’s emissions to 2.02 lbs/MMBtu. (This, according to the latest EPA computer modeling, was the level necessary for Ohio to attain the sulfur dioxide NAAQS.) After yet more litigation by Ohio utilities—including Beckjord’s owner, Cincinnati Gas & Electric—the bulk of the federal plan was upheld in 1978. (In rejecting the utilities’ challenge, the Sixth Circuit noted that Ohio was the only state in the country that still lacked an enforceable SO2 implementation plan.)

Plug-in hybrid electric vehicles (PHEVs) have the potential of substantially reducing petroleum consumption and vehicular CO2 emissions relative to conventional vehicles (CVs). The analysis presented in this article first ascertains the cost-effectiveness of PHEVs from the perspective of the consumer. Then, the potential effects of PHEVs to an electric utility are evaluated by analyzing a simplified hypothetical example. When evaluating the cost effectiveness of a PHEV, the additional required premium is the most important financial parameter to the consumer. An acceptable amount for the additional upfront costs will depend on the future costs of gasoline and the on-board battery pack. The need to replace the on-board battery pack during the assumed vehicle lifetime also affects the allowed premium. A simplified unit commitment and dispatch model was used to determine the costs of energy and the CO2 emissions associated with PHEVs for different charging scenarios. The results show that electricity can be used to charge PHEVs during off-peak hours without an increase in peak demand. In addition, the combined CO2 emissions from the vehicles and the electric generation facilities will be reduced, regardless of the charging strategy.

Abstract This study builds a decision support tool to evaluate when it is a good economic decision (least cost with minimum discomfort) for the residential customer to invest in distributed energy resources (DERs) based on different electricity rate structures, DER ownership frameworks, and DER rebates offered by electric utilities. The tool is demonstrated using empirical electricity consumption data from Pecan Street Inc. (a non-profit entity based on Austin, Texas), residential rates from Austin Energy (the municipal electric utility in Austin, Texas), DER ownership costs from various nationwide pilot programs, and incentives offered by electric utilities in the United States. Results show that for constant electricity rates, the overall expenditure is least when the customer owns solar panels without storage, while for time-varying pricing structures, the least expensive scenario is one where the customer does not own any DERs. As the capital costs for DERs decline, utilities incentivize customer ownership of DERs, and more residential customers face the decision of whether to invest in DERs, this study aims to be a key tool in aiding that decision-making process.

In the United States, installation of emission-free sources of power generation, such as wind and solar photovoltaics, has increased recently. Unfortunately, these generation technologies present unique challenges to utilities and grid operators because they are variable and not dispatchable. While energy storage can provide capacitance to the system and thereby make renewable power more dispatchable, storage implementation at the municipal scale is poorly understood. This paper examines future applications of energy storage to reduce costs and improve system reliability for electric utilities at the local level. The city of Austin, Texas was selected as the study area because the city has set aggressive targets of 30–35% of total electricity generation from renewable sources, primarily wind and solar photovoltaics, by 2020. For this analysis, generation assets currently used and those planned for future development by the local utility, Austin Energy, are treated in a unit commitment model using a mixed integer programming (MIP) approach. The model has been developed such that it can be provided any objective function and generation portfolio, and the results can be used by whatever stakeholder has generated those particular inputs. To best simulate operational dispatch conditions, the model includes ramp rate constraints, generator turn-on penalties, and minimum operation levels. Energy storage is included by allowing the model to assign an unconstrained asset throughout the study period, 24 hours, to whatever values will minimize the objective function. For this initial analysis, storage system efficiency, capital and marginal costs were not included, though they may significantly affect total allocated storage. Modeling results indicate that storage availability yields a reduction of as much as $600,000/day in marginal costs for the study area, based primarily on improved utilization of more efficient generating units. This result does not consider savings associated with NOx reductions. Such reductions were studied with a second objective function. While NOx reductions of approximately 9–23% were observed, these emission reductions were accompanied by significant increases in operating costs. Energy storage requirements and potential cost savings under the scenarios examined might be beneficial to researchers interested in grid-scale storage. These results can also be used to determine appropriate cost targets for storage researchers and manufacturers.

Component deterioration is observed in fleet gas turbine units during overhaul and maintenance activities of utilities providing electric power, co-generation or mechanical drive operations. Affected components include those provided by Original Equipment Manufacturers (OEM) and newly-manufactured and repaired hardware from OEM or aftermarket suppliers. This study details: i) the gas turbine flow path component deterioration and distress typically observed from operation, ii) some of the typical reasons (expected and abnormal) for the component damages, iii) the resulting effects and detriment to the utilities, and iv) a means for reducing the potential for component damages and operational risk to the utilities. Abnormal gas path component deterioration is one of the leading causes for forced opening of IGT units. Unscheduled opening of production gas turbine units during normal and critical operating time periods can result in significant costs to the utilities and insurance providers due to unplanned overhaul and maintenance costs, replacement components costs, and lost production revenue during the outage. Often the majority of the premature component deterioration within a set can be attributed to the quality of manufacturing or repair processing and inadequate inspections of the components. Escapes in quality assurance can occur resulting in components being supplied to utilities that do not meet design intent, such as debris contamination, coatings issues, and mis-machined features. Additionally, component suppliers are often pressured to meet production deadlines and provide delivery of the components to the utilities to avoid contractual penalties. This scenario can result in the potential for reduced focus on the quality of the components and quality-control escapes of design-deviated components delivered to the utilities for unit operation. Any uncontrolled deviations, damage, and discrepancies that result from hardware manufacturing and repair processes can have a significant impact on the long term durability of turbomachinery components. These component “damages” and manufacturing defects can be reduced or eliminated through proper functional quality inspections and component assessment, prior to unit installation. Additional issues concerning, improper tooling and methods employed during component removal and re-installation during maintenance activity can also result in damage to components and premature deterioration. This study focuses on how utilities can perform or audit the functional checks on components prior to unit installation in an effort to reduce component degradation, operational risk and potential of forced outage of units resulting in additional maintenance costs and lost revenue.

Freeport Electric is one of only three Long Island-based, New York State municipal electric utilities that self-generate its electrical needs. A member of the New York Association for Public Power, the utility serves a community of over 45,000 people with a diverse customer base of approximately 15,000 residential, commercial and municipal customers. Freeport Electric’s energy costs are among the lowest on Long Island.

Since the early 1960’s, the use of aero-derivative and industrial gas turbines on TransCanada’s natural gas transmission system has been the norm, with a total of 245 units installed to date. In 1996 and 1997 the company installed six high-speed, 30.6 MW, variable speed, electric drive systems. In the same time period eight aero-derivative gas turbines of similar power, with Dry Low Emissions, were installed. After an elapse of three years running time we now have enough data to compare the performance of the two different compressor drivers. A comparison of the performance of the two prime movers is made in a number of different ways. Operation and maintenance costs of the two different systems are considered, including the fuel costs of the natural gas and electricity, from three different Canadian electric power utilities.

A 35 kW roof top photovoltaic (PV) system has been installed at the National Institute of Standards and Technology (NIST) in Gaithersburg, Maryland. The system, located on the flat roof that connects NIST’s Administration Building to its adjoining conference and cafeteria facilities, produced NIST’s first site-generated renewable energy on September 14, 2001. In addition to providing electrical energy and reducing monthly peak electrical loads, the rear surface of each module is laminated to 51 mm of extruded polystyrene enhancing the thermal performance of the roof. A unique ballast system secures the photovoltaic system, eliminating the need for roof penetrations. An instrumentation and data acquisition package was installed to record the ambient temperature, wind speed, solar radiation, and the electrical energy delivered to the grid. Additional solar radiation instruments were installed after determining that the original solar radiation sensor was influenced by reflections from the south-facing wall of the Administration Building’s tower. NIST’s electric utility billing schedule includes energy and peak demand charges. The generation charges vary significantly depending upon the time interval — off-peak, intermediate, and on-peak — during which the energy is consumed. The schedule is divided into summer billing months (June-October) and winter billing months (November-May). During the winter billing months, the distribution, transmission, and generation peak demand charges are based on the greatest power demand imposed by the site on the grid. During the summer billing months an additional demand charge is imposed to capture electrical demand during the onpeak time interval. This paper summarizes the monthly and annual measured performance of the photovoltaic system. The monthly energy produced by the system is tabulated. Conversion efficiencies — computed using solar radiation measurements from a single photovoltaic cell radiation sensor, four thermopile-based radiation sensors located around the perimeter of the photovoltaic array, and a remotely located thermopile-based radiation sensor, are presented. Using the electric utility’s rate schedule, the monetary savings credited to the photovoltaic system is determined by combining the cost of the displaced energy with the reduction in peak demand charges attributable to the photovoltaic system. Finally, using utility provided data and the Environmental Protection Agency’s (EPA) Environmental Benefits Calculator, estimates are made of the avoided emissions of the photovoltaic system over its projected life span.

This paper presents an assessment of the failure modes, operation and maintenance (O&M) costs, and system lifecycle costs for 77 photovoltaic (PV) water pumping systems installed during a fourteen year period from 1990 to 2004. These systems were supplied, installed, operated and maintained through a customer lease program by two rural utilities, Northwest Rural Public Power District in Nebraska and Verendrye Electric Cooperative in North Dakota. Field records have been tracked and analyzed to capture maintenance events, component failure experience, repair/replacement costs and installation cost histories. The results of these analyses including annual O&M cost, failure rates, and economic comparisons with grid extension options are presented and discussed.

A comparison between power plants built according to the HAT (Humid Air Turbine) and SCGT/CC (Semi-Closed Gas Turbine/Combined Cycle) concepts is presented, ranging from thermodynamic performance (efficiency and specific power output) to projected data for plant construction and operating costs. Both options appear to be of potential interest to electric utilities considering advanced gas turbine power plants, with significant differences form the point of view of plant size, water consumption, and adaptability to advanced developments for the limitation of environmental impact (CO2 emissions).

We consider a scenario where self-interested Electric Vehicle (EV) aggregators compete in the day-ahead electricity market in order to purchase the electricity needed to meet EV requirements. We propose a novel decentralised bidding coordination algorithm based on the Alternating Direction Method of Multipliers (ADMM). Our simulations using real market and driver data from Spain show that the algorithm is able to significantly reduce energy costs for all participants. Furthermore, we postulate that strategic manipulation by deviating agents is possible in decentralised algorithms like ADMM. Hence, we describe and analyse different possible attack vectors and propose a mathematical framework to quantify and detect manipulation. Our simulations show that our ADMM-based algorithm can be effectively disrupted by manipulative attacks achieving convergence to a different non-optimal solution which benefits the attacker. At the same time, our proposed manipulation detection algorithm achieves very high accuracy.

1.1 Macroeconomic summary Economic recovery has consistently outperformed the technical staff’s expectations following a steep decline in activity in the second quarter of 2020. At the same time, total and core inflation rates have fallen and remain at low levels, suggesting that a significant element of the reactivation of Colombia’s economy has been related to recovery in potential GDP. This would support the technical staff’s diagnosis of weak aggregate demand and ample excess capacity. The most recently available data on 2020 growth suggests a contraction in economic activity of 6.8%, lower than estimates from January’s Monetary Policy Report (-7.2%). High-frequency indicators suggest that economic performance was significantly more dynamic than expected in January, despite mobility restrictions and quarantine measures. This has also come amid declines in total and core inflation, the latter of which was below January projections if controlling for certain relative price changes. This suggests that the unexpected strength of recent growth contains elements of demand, and that excess capacity, while significant, could be lower than previously estimated. Nevertheless, uncertainty over the measurement of excess capacity continues to be unusually high and marked both by variations in the way different economic sectors and spending components have been affected by the pandemic, and by uneven price behavior. The size of excess capacity, and in particular the evolution of the pandemic in forthcoming quarters, constitute substantial risks to the macroeconomic forecast presented in this report. Despite the unexpected strength of the recovery, the technical staff continues to project ample excess capacity that is expected to remain on the forecast horizon, alongside core inflation that will likely remain below the target. Domestic demand remains below 2019 levels amid unusually significant uncertainty over the size of excess capacity in the economy. High national unemployment (14.6% for February 2021) reflects a loose labor market, while observed total and core inflation continue to be below 2%. Inflationary pressures from the exchange rate are expected to continue to be low, with relatively little pass-through on inflation. This would be compatible with a negative output gap. Excess productive capacity and the expectation of core inflation below the 3% target on the forecast horizon provide a basis for an expansive monetary policy posture. The technical staff’s assessment of certain shocks and their expected effects on the economy, as well as the presence of several sources of uncertainty and related assumptions about their potential macroeconomic impacts, remain a feature of this report. The coronavirus pandemic, in particular, continues to affect the public health environment, and the reopening of Colombia’s economy remains incomplete. The technical staff’s assessment is that the COVID-19 shock has affected both aggregate demand and supply, but that the impact on demand has been deeper and more persistent. Given this persistence, the central forecast accounts for a gradual tightening of the output gap in the absence of new waves of contagion, and as vaccination campaigns progress. The central forecast continues to include an expected increase of total and core inflation rates in the second quarter of 2021, alongside the lapse of the temporary price relief measures put in place in 2020. Additional COVID-19 outbreaks (of uncertain duration and intensity) represent a significant risk factor that could affect these projections. Additionally, the forecast continues to include an upward trend in sovereign risk premiums, reflected by higher levels of public debt that in the wake of the pandemic are likely to persist on the forecast horizon, even in the context of a fiscal adjustment. At the same time, the projection accounts for the shortterm effects on private domestic demand from a fiscal adjustment along the lines of the one currently being proposed by the national government. This would be compatible with a gradual recovery of private domestic demand in 2022. The size and characteristics of the fiscal adjustment that is ultimately implemented, as well as the corresponding market response, represent another source of forecast uncertainty. Newly available information offers evidence of the potential for significant changes to the macroeconomic scenario, though without altering the general diagnosis described above. The most recent data on inflation, growth, fiscal policy, and international financial conditions suggests a more dynamic economy than previously expected. However, a third wave of the pandemic has delayed the re-opening of Colombia’s economy and brought with it a deceleration in economic activity. Detailed descriptions of these considerations and subsequent changes to the macroeconomic forecast are presented below. The expected annual decline in GDP (-0.3%) in the first quarter of 2021 appears to have been less pronounced than projected in January (-4.8%). Partial closures in January to address a second wave of COVID-19 appear to have had a less significant negative impact on the economy than previously estimated. This is reflected in figures related to mobility, energy demand, industry and retail sales, foreign trade, commercial transactions from selected banks, and the national statistics agency’s (DANE) economic tracking indicator (ISE). Output is now expected to have declined annually in the first quarter by 0.3%. Private consumption likely continued to recover, registering levels somewhat above those from the previous year, while public consumption likely increased significantly. While a recovery in investment in both housing and in other buildings and structures is expected, overall investment levels in this case likely continued to be low, and gross fixed capital formation is expected to continue to show significant annual declines. Imports likely recovered to again outpace exports, though both are expected to register significant annual declines. Economic activity that outpaced projections, an increase in oil prices and other export products, and an expected increase in public spending this year account for the upward revision to the 2021 growth forecast (from 4.6% with a range between 2% and 6% in January, to 6.0% with a range between 3% and 7% in April). As a result, the output gap is expected to be smaller and to tighten more rapidly than projected in the previous report, though it is still expected to remain in negative territory on the forecast horizon. Wide forecast intervals reflect the fact that the future evolution of the COVID-19 pandemic remains a significant source of uncertainty on these projections. The delay in the recovery of economic activity as a result of the resurgence of COVID-19 in the first quarter appears to have been less significant than projected in the January report. The central forecast scenario expects this improved performance to continue in 2021 alongside increased consumer and business confidence. Low real interest rates and an active credit supply would also support this dynamic, and the overall conditions would be expected to spur a recovery in consumption and investment. Increased growth in public spending and public works based on the national government’s spending plan (Plan Financiero del Gobierno) are other factors to consider. Additionally, an expected recovery in global demand and higher projected prices for oil and coffee would further contribute to improved external revenues and would favor investment, in particular in the oil sector. Given the above, the technical staff’s 2021 growth forecast has been revised upward from 4.6% in January (range from 2% to 6%) to 6.0% in April (range from 3% to 7%). These projections account for the potential for the third wave of COVID-19 to have a larger and more persistent effect on the economy than the previous wave, while also supposing that there will not be any additional significant waves of the pandemic and that mobility restrictions will be relaxed as a result. Economic growth in 2022 is expected to be 3%, with a range between 1% and 5%. This figure would be lower than projected in the January report (3.6% with a range between 2% and 6%), due to a higher base of comparison given the upward revision to expected GDP in 2021. This forecast also takes into account the likely effects on private demand of a fiscal adjustment of the size currently being proposed by the national government, and which would come into effect in 2022. Excess in productive capacity is now expected to be lower than estimated in January but continues to be significant and affected by high levels of uncertainty, as reflected in the wide forecast intervals. The possibility of new waves of the virus (of uncertain intensity and duration) represents a significant downward risk to projected GDP growth, and is signaled by the lower limits of the ranges provided in this report. Inflation (1.51%) and inflation excluding food and regulated items (0.94%) declined in March compared to December, continuing below the 3% target. The decline in inflation in this period was below projections, explained in large part by unanticipated increases in the costs of certain foods (3.92%) and regulated items (1.52%). An increase in international food and shipping prices, increased foreign demand for beef, and specific upward pressures on perishable food supplies appear to explain a lower-than-expected deceleration in the consumer price index (CPI) for foods. An unexpected increase in regulated items prices came amid unanticipated increases in international fuel prices, on some utilities rates, and for regulated education prices. The decline in annual inflation excluding food and regulated items between December and March was in line with projections from January, though this included downward pressure from a significant reduction in telecommunications rates due to the imminent entry of a new operator. When controlling for the effects of this relative price change, inflation excluding food and regulated items exceeds levels forecast in the previous report. Within this indicator of core inflation, the CPI for goods (1.05%) accelerated due to a reversion of the effects of the VAT-free day in November, which was largely accounted for in February, and possibly by the transmission of a recent depreciation of the peso on domestic prices for certain items (electric and household appliances). For their part, services prices decelerated and showed the lowest rate of annual growth (0.89%) among the large consumer baskets in the CPI. Within the services basket, the annual change in rental prices continued to decline, while those services that continue to experience the most significant restrictions on returning to normal operations (tourism, cinemas, nightlife, etc.) continued to register significant price declines. As previously mentioned, telephone rates also fell significantly due to increased competition in the market. Total inflation is expected to continue to be affected by ample excesses in productive capacity for the remainder of 2021 and 2022, though less so than projected in January. As a result, convergence to the inflation target is now expected to be somewhat faster than estimated in the previous report, assuming the absence of significant additional outbreaks of COVID-19. The technical staff’s year-end inflation projections for 2021 and 2022 have increased, suggesting figures around 3% due largely to variation in food and regulated items prices. The projection for inflation excluding food and regulated items also increased, but remains below 3%. Price relief measures on indirect taxes implemented in 2020 are expected to lapse in the second quarter of 2021, generating a one-off effect on prices and temporarily affecting inflation excluding food and regulated items. However, indexation to low levels of past inflation, weak demand, and ample excess productive capacity are expected to keep core inflation below the target, near 2.3% at the end of 2021 (previously 2.1%). The reversion in 2021 of the effects of some price relief measures on utility rates from 2020 should lead to an increase in the CPI for regulated items in the second half of this year. Annual price changes are now expected to be higher than estimated in the January report due to an increased expected path for fuel prices and unanticipated increases in regulated education prices. The projection for the CPI for foods has increased compared to the previous report, taking into account certain factors that were not anticipated in January (a less favorable agricultural cycle, increased pressure from international prices, and transport costs). Given the above, year-end annual inflation for 2021 and 2022 is now expected to be 3% and 2.8%, respectively, which would be above projections from January (2.3% and 2,7%). For its part, expected inflation based on analyst surveys suggests year-end inflation in 2021 and 2022 of 2.8% and 3.1%, respectively. There remains significant uncertainty surrounding the inflation forecasts included in this report due to several factors: 1) the evolution of the pandemic; 2) the difficulty in evaluating the size and persistence of excess productive capacity; 3) the timing and manner in which price relief measures will lapse; and 4) the future behavior of food prices. Projected 2021 growth in foreign demand (4.4% to 5.2%) and the supposed average oil price (USD 53 to USD 61 per Brent benchmark barrel) were both revised upward. An increase in long-term international interest rates has been reflected in a depreciation of the peso and could result in relatively tighter external financial conditions for emerging market economies, including Colombia. Average growth among Colombia’s trade partners was greater than expected in the fourth quarter of 2020. This, together with a sizable fiscal stimulus approved in the United States and the onset of a massive global vaccination campaign, largely explains the projected increase in foreign demand growth in 2021. The resilience of the goods market in the face of global crisis and an expected normalization in international trade are additional factors. These considerations and the expected continuation of a gradual reduction of mobility restrictions abroad suggest that Colombia’s trade partners could grow on average by 5.2% in 2021 and around 3.4% in 2022. The improved prospects for global economic growth have led to an increase in current and expected oil prices. Production interruptions due to a heavy winter, reduced inventories, and increased supply restrictions instituted by producing countries have also contributed to the increase. Meanwhile, market forecasts and recent Federal Reserve pronouncements suggest that the benchmark interest rate in the U.S. will remain stable for the next two years. Nevertheless, a significant increase in public spending in the country has fostered expectations for greater growth and inflation, as well as increased uncertainty over the moment in which a normalization of monetary policy might begin. This has been reflected in an increase in long-term interest rates. In this context, emerging market economies in the region, including Colombia, have registered increases in sovereign risk premiums and long-term domestic interest rates, and a depreciation of local currencies against the dollar. Recent outbreaks of COVID-19 in several of these economies; limits on vaccine supply and the slow pace of immunization campaigns in some countries; a significant increase in public debt; and tensions between the United States and China, among other factors, all add to a high level of uncertainty surrounding interest rate spreads, external financing conditions, and the future performance of risk premiums. The impact that this environment could have on the exchange rate and on domestic financing conditions represent risks to the macroeconomic and monetary policy forecasts. Domestic financial conditions continue to favor recovery in economic activity. The transmission of reductions to the policy interest rate on credit rates has been significant. The banking portfolio continues to recover amid circumstances that have affected both the supply and demand for loans, and in which some credit risks have materialized. Preferential and ordinary commercial interest rates have fallen to a similar degree as the benchmark interest rate. As is generally the case, this transmission has come at a slower pace for consumer credit rates, and has been further delayed in the case of mortgage rates. Commercial credit levels stabilized above pre-pandemic levels in March, following an increase resulting from significant liquidity requirements for businesses in the second quarter of 2020. The consumer credit portfolio continued to recover and has now surpassed February 2020 levels, though overall growth in the portfolio remains low. At the same time, portfolio projections and default indicators have increased, and credit establishment earnings have come down. Despite this, credit disbursements continue to recover and solvency indicators remain well above regulatory minimums. 1.2 Monetary policy decision In its meetings in March and April the BDBR left the benchmark interest rate unchanged at 1.75%.