US ELECTRIC UTILITIES FINANCIAL PRESSURE
2018, March, 14, 11:45:00
OIL PRICE: NOT ABOVE $65
REUTERS - U.S. West Texas Intermediate (WTI) crude futures CLc1 were at $60.77 a barrel at 0753 GMT, up 6 cents, or 0.1 percent, from their previous settlement. Brent crude futures LCOc1 were at $64.62 per barrel, down just 2 cents from their last close.
2018, March, 7, 15:00:00
ЦЕНА НЕФТИ: ПОКА ВЫШЕ $65
РЕЙТЕР - К 9.17 МСК фьючерсы на североморскую смесь Brent опустились на 0,85 процента до $65,23 за баррель. Фьючерсные контракты на американскую лёгкую нефть WTI к этому времени торговались у отметки $62,07 за баррель, что на 0,85 процента ниже предыдущего закрытия.
2018, March, 7, 14:00:00
OIL PRICES 2018 - 19: $62
EIA - North Sea Brent crude oil spot prices averaged $65 per barrel (b) in February, a decrease of $4/b from the January level and the first month-over-month average decrease since June 2017. EIA forecasts Brent spot prices will average about $62/b in both 2018 and 2019 compared with an average of $54/b in 2017.
2018, March, 5, 11:35:00
ЦЕНА НЕФТИ: ПОКА ВЫШЕ $64
РЕЙТЕР - К 9.28 МСК фьючерсы на североморскую смесь Brent поднялись на 0,33 процента до $64,58 за баррель. Фьючерсные контракты на американскую лёгкую нефть WTI к этому времени торговались у отметки $61,44 за баррель, что на 0,31 процента выше предыдущего закрытия.
2018, March, 4, 11:30:00
ЦЕНА URALS: $ 65,99
МИНФИН РОССИИ - Средняя цена нефти марки Urals по итогам января – февраля 2018 года составила $ 65,99 за баррель.
2018, February, 27, 14:15:00
ЦЕНА НЕФТИ: ОПЯТЬ ВЫШЕ $67
РЕЙТЕР - К 9.18 МСК фьючерсы на североморскую смесь Brent опустились на 0,15 процента до $67,40 за баррель. Фьючерсные контракты на американскую лёгкую нефть WTI к этому времени торговались у отметки $63,80 за баррель, что на 0,17 процента ниже предыдущего закрытия.
2018, February, 27, 14:05:00
ЦЕНА URALS: $66,26457
МИНФИН РОССИИ - Средняя цена на нефть Urals за период мониторинга с 15 января по 14 февраля 2018 года составила $66,26457 за баррель, или $483,7 за тонну.
US ELECTRIC UTILITIES FINANCIAL PRESSURE
By John Wolfram Principal Catalyst Consulting LLC
The first step of any electric utility rate analysis is to determine the amount of revenue that the customer rates must generate annually. Utilities are entitled to recover their prudently incurred costs and to earn a reasonable return on their investments, so the revenue requirement should include annual expenses, for purchased power, O&M, depreciation, taxes and other costs. This includes pro forma adjustments to capture any costs expected when rates will be in effect. It must also include a total margin that will allow the utility to achieve the target debt service coverage or other objective financial metric. This allows the utility to pay the interest on long term debt and prepare for contingencies related to weather events, consumption changes, or variations in wholesale power supply costs. In this way the revenue requirement best represents the total annual revenue that the utility must produce in order to meet or exceed its financial goals.
Under the current pandemic circumstances, utilities may ultimately adjust the revenue requirement to account in some way for the costs of suspended disconnections and waived late payment charges. At this juncture both utilities and regulators are actively considering possible solutions to this challenge.
Cost of Service Study (“COSS”)
The COSS is used to determine the cost to provide service to customers, both in total and by individual rate class. The COSS is an effective tool for assessing whether each rate class is paying its fair share of total costs and for designing rates that fairly assign costs to each rate class. The electric utility should prepare a COSS using standard methods that have been established by industry experts, accepted by regulators, and/or approved by the courts – even if the electric utility is not subject to state jurisdiction. These methods must determine as accurately as possible what it costs for the electric utility to serve each class of customers.
The first step is to Functionalize all of the utility’s costs into major functional groups, e.g. production, transmission or distribution. This answers the question, to what function does a particular cost relate? The second step is to Classify all functionalized costs as related to energy, demand, or the number of customers. This answers the question, how does the particular cost vary? The third step is to Allocate the functionalized, classified costs to the rate classes. This answers the question, which customers cause the utility to incur the particular cost? The COSS can then be used to show the actual per-unit costs to serve each rate class, separated or unbundled into demand, energy, and customer components. Those actual costs can then be adjusted to reflect the target revenue requirement, so that unbundled, cost-based rates for each rate class may be calculated. These unbundled, cost-based rates provide essential guidance for designing rates that are fair, just and reasonable.
The Revenue Requirement shows whether an overall rate increase is needed. The unbundled, cost-based rates from the COSS show which rate classes are subsidizing or being subsidized by other rate classes, and provide guidance on how the particular rate schedules should be adjusted. When the cost-based rates are unbundled by component – including purchased power demand, purchased power energy, transmission demand (if applicable), distribution demand, and distribution customer – the utility can assess whether the existing charges (customer charge, energy charge, and demand charge where applicable) send the appropriate price signals to consumers, or whether revisions are needed to correct that and/or to afford the utility sufficient protection against revenue erosion.
Significant rate changes can be difficult to adopt in a short period of time. The ratemaking principle of gradualism is applied when electric utilities adjust rates in smaller increments over time to avoid dramatic rate increases all at once.
Utility margins should be included in fixed charges whenever possible, so that variations in weather or conservation do not adversely impact utility margins. Typical rate designs are referred to as Two-Part Rates (comprised of per-customer and energy charges) and Three-Part Rates (comprised of customer, energy, and demand charges).
The rate design should (a) allow the electric utility to secure the target revenue requirement, (b) align with the wholesale power rate structure, (c) minimize subsidies within and between rate classes, (d) encourage efficient usage, and (e) properly charge and credit consumers with distributed generation resources. The rates must also be understandable, be stable, and avoid undue discrimination. If a consumer causes the utility to incur a particular cost, the consumer should pay that cost. Rates designed on the basis of unbundled, cost-based rates are an effective way to achieve all of these objectives.
In the current pandemic, and during periods of any rapid change, it is especially important for electric utilities to review their rate structure, to ensure continued financial stability while also addressing the changing economic and social interests of the community they serve. Electric utilities must be flexible, because there is no one perfect rate design – conditions change, and corresponding changes to the rate structure may be warranted. Utilities must also be alert, and continue to monitor emerging trends, customer interests, best practices of other utilities, and the associated impact of all of these dynamic elements on the future financials of the utility. In this way the electric utility will remain best positioned to manage and indeed thrive in whatever environment the future brings.
This thought leadership article was originally shared with Energy Central's Utility Management Community Group. The communities are a place where professionals in the power industry can share, learn and connect in a collaborative environment. Join the Utility Management Community today and learn from others who work in the industry.