DOE/EIA-0226(96/06) Distribution Category UC-950 Electric Power Monthly June 1996 With Data for March 1996 Energy Information Administration Office of Coal, Nuclear, Electric and Alternate Fuels U.S. Department of Energy Washington, DC 20585 This report was prepared by the Energy Information Administration, the independent statistical and analytical agency within the Department of Energy. The information contained herein should not be construed as advocating or reflecting any policy position of the Department of Energy or any other organization.
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DOE/EIA-0226(96/06)Distribution CategoryUC-950
Electric Power MonthlyJune 1996
With Data for March 1996
Energy Information AdministrationOffice of Coal, Nuclear, Electric and Alternate Fuels
U.S. Department of EnergyWashington, DC 20585
This report was prepared by the Energy Information Administration, the independent statistical andanalytical agency within the Department of Energy. The information contained herein should not beconstrued as advocating or reflecting any policy position of the Department of Energy or any otherorganization.
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Energy Information Administration/ Electric Power Monthly June 1996
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Energy Information Administration/ Electric Power Monthly May 1996
Energy Information Administration/ Electric Power Monthly June 1996
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Preface
The Electric Power Monthly (EPM)presents monthlyelectricity statistics for a wide audience includingCongress, Federal and State agencies, the electricutility industry, and the general public. The purposeof this publication is to provide energydecisionmakers with accurate and timely informationthat may be used in forming various perspectives onelectric issues that lie ahead. The EIA collected theinformation in this report to fulfill its data collectionand dissemination responsibilities as specified in theFederal Energy Administration Act of 1974 (PublicLaw 93-275) as amended.
Background
The Coal and Electric Data and Renewables Division;Office of Coal, Nuclear, Electric and Alternate Fuels,Energy Information Administration (EIA), Depart-ment of Energy prepares the EPM. This publicationprovides monthly statistics at the State, Census divi-sion, and U.S. levels for net generation, fossil fuelconsumption and stocks, quantity and quality of fossilfuels, cost of fossil fuels, electricity sales, revenue,and average revenue per kilowatthour of electricitysold. Data on net generation, fuel consumption, fuelstocks, quantity and cost of fossil fuels are also dis-played for the North American Electric ReliabilityCouncil (NERC) regions.
The EIA publishes statistics in theEPM on net gener-ation by energy source; consumption, stocks, quantity,quality, and cost of fossil fuels; and capability of newgenerating units by company and plant.
Coverage of Sources
The EPM contains information from six data sources:Form EIA-759, "Monthly Power Plant Report";Federal Energy Regulatory Commission (FERC) Form423, "Monthly Report of Cost and Quality of Fuels forElectric Plants"; Form EIA-826, "Monthly ElectricUtility Sales and Revenue Report with State Distrib-utions"; Form EIA-900, "Monthly Nonutility Sales forResale Report"; Form EIA-861, "Annual ElectricUtility Report"; and Form EIA-860, "Annual ElectricGenerator Report". Copies of these forms and theirinstructions may be obtained from the NationalEnergy Information Center. A brief summary of theseforms follows; Appendix B, "Technical Notes," con-tains a more detailed description.
Form EIA-759 is used to collect monthly data on netgeneration; consumption of coal, petroleum, andnatural gas; and end-of-the-month stocks of coal and
petroleum for each plant by fuel-type combination. Asof the January 1996 reporting period and as part ofEIA's continuing effort to reduce respondent burden,information on the Form EIA-759 is collectedmonthly from a cutoff model sample of plants withgenerating unit nameplate capacity of 25 megawattsor more (approximately 360 electric utilities).
FERC Form 423, a restricted-universe census, is usedto collect data from electric generating plants with atotal steam-electric and combined-cycle nameplatecapacity of 50 or more megawatts (approximately 230electric utilities). The FERC established the thresholdof 50 or more megawatts. Data collected on the FERCForm 423 include quantity, quality, delivered cost,origin, mine type, fuel type, supplier, and purchasetype of fossil fuel receipts.
Form EIA-826 is used to collect sales and revenuedata for the residential, commercial, industrial, andother sectors. Other sales and revenue data collectedinclude public street and highway lighting, other salesand revenue to public authorities, sales to railroadsand railways, and interdepartmental sales. Respond-ents to Form EIA-826 are based on a statisticallychosen sample and include approximately 260investor-owned and publicly owned electric utilitiesfrom a universe of approximately 3,250 utilities. Thesample, which is evaluated annually, was designed toobtain estimates of electricity sales, revenue, andrevenue per kilowatthour for all U.S. electric utilitiesby end-use sector. These estimates are provided at theState, Census division, and U.S. levels. Estimates ofcoefficients of variation, which indicate possible errorcaused by sampling, are also published at each level.
Data on quantity, quality, and cost of fossil fuels lagdata on net generation, fuel consumption, fuel stocks,electricity sales, and average revenue per kilowatthourby 1 month. This difference in reporting appears inthe State, Census division, and U.S. level tables.However, for purposes of comparison, plant-level dataare presented for the earlier month.
Form EIA-900. The Form EIA-900, "Monthly Nonu-tility Sales for Resale Report," is used to collectmonthly data from a sample of nonutility power pro-ducers on sales for resale of electricity. The respond-ents (approximately 380) to the form represent acutoff model sample of facilities reporting on theForm EIA-867, "Annual Nonutility Power ProducerReport." Respondents with a facility nameplatecapacity of 50 megawatts or more are selected.
Form EIA-861 is a survey of electric utilities in theUnited States, its territories, and Puerto Rico. Thesurvey is used to collect information from the uni-
Energy Information Administration/Electric Power Monthly June 1996 v
verse of electric utilities (approximately 3,250). Datacollected on Form EIA-861 include information on theproduction, sales, revenue from sales, and trade ofelectricity.
Form EIA-860 is used to collect data annually fromall electric utilities in the United States and PuertoRico that operate power plants or plan to operate apower plant within 10 years of the reporting year.Generator-specific information is reported by approxi-mately 900 respondents.
Energy Information Administration/Electric Power Monthly June 1996vi
Division, and State, February 1996. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .�5141. Electric Utility Receipts of Gas by Type, Census Division, and State, February 1996. . . . . . . . . . . . . . . . . �5342. Receipts and Average Cost of Gas Delivered to Electric Utilities by Census Division and State. . . . . . . �5443. Receipts and Average Cost of Gas Delivered to Electric Utilities by Type of Purchase, Census Division,
and State, February 1996. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .�5544. U.S. Electric Utility Retail Sales of Electricity by Sector, 1986 Through March 1996. . . . . . . . . . . . . . . . �5945. Estimated Electric Utility Retail Sales of Electricity to Ultimate Consumers by Sector, Census Division,
and State, March 1996 and 1995. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .�6046. Estimated Coefficients of Variation for Electric Utility Retail Sales of Electricity by Sector, Census
49. Estimated Revenue From Electric Utility Retail Sales of Electricity to Ultimate Consumers by Sector,Census Division, and State, March 1996 and 19. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .�64
50. Estimated Coefficients of Variation for Revenue from Electric Utility Retail Sales of Electricity toUltimate Consumers by Sector, Census Division,. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .�65
51. Estimated Revenue From Electric Utility Retail Sales to Ultimate Consumers by Sector, CensusDivision, and State, Year-to-Date February 1996 and 19. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .�66
52. U.S. Electric Utility Average Revenue per Kilowatthour by Sector, 1986 Through February 1996. . . . . �6753. Estimated Electric Utility Average Revenue per Kilowatthour by Sector, Census Division, and State,
B1. North American Electric Reliability Council Regions for the Contiguous United States and Alaska. . . �156
Energy Information Administration/Electric Power Monthly June 1996 ix
Upgrading Transmission Capacity forWholesale Electric Power Trade
by Arthur H. Fuldner 1
On April 24, 1996, the Federal Energy Regulatory Com-mission (FERC) issued a final rule, Order No. 888,2 inresponse to provisions of the Energy Policy Act(EPACT) of 1992. Order No. 888 opens wholesale elec-tric power sales to competition. It requires utilities thatown, control, or operate transmission lines to file non-discriminatory open access tariffs that offer others thesame electricity transmission service they provide them-selves. The second final rule, Order No. 889,3 issued onthe same date, requires a real-time information systemto assure that transmission owners and their affiliatesdo not have an unfair competitive advantage in usingtransmission to sell power. It is expected that OrdersNo. 888 and No. 889 and other actions taken by StatePublic Service Commissions to promote competition inthe electric power industry will result in increaseddemands for transmission services.
EPACT states that when transmission capacity is con-strained, an electric utility must offer to enlarge itstransmission capacity, if necessary, to provide trans-mission services. However, obtaining approval to siteand build new transmission capacity is becoming moredifficult due to environmental concerns, potential healtheffects of electric and magnetic fields (EMF), specialinterest groups’ concerns, and the concern that propertyvalues would decline along transmission line routes.Currently, 10,126.8 line miles of transmission additionsare planned for the United States, Canada, and thenorthern portion of Baja California, Mexico, for 1995through 2004 (Table FE1) and are in different stages ofplanning and/or construction. Many of these lines maybe delayed for many years or may never be con-structed.
Due to the problems associated with constructing newtransmission lines, it is important to examine the
possible options for increasing the transmissioncapability on present sites and making maximum use ofexisting transmission systems through upgrades. Whenfeasible, upgrades are an attractive alternative, becausethe costs and leadtimes are less than those forconstructing new transmission lines. This articledescribes to policy makers and regulators the bulkelectric power system and identifies the thermal,voltage, and operating constraints on a system’s capa-bility to transmit power from one area to another. Someof the potential remedies for these constraints throughupgrades are presented along with a comparison of thecost to upgrade compared to the costs for new trans-mission lines.
Description of the BulkElectric Power System
The basic elements of an electric power system areshown in Figure FE1. (Note that the figure does notinclude all types of electric generation.) The electricgenerating plants or stations, transmission lines, andhigh voltage or bulk power substations that constitutethe bulk power system are shown above the dashedline. Subtransmission and distribution systems and siteswhere the electricity is consumed is shown below thedashed line. Transmission lines and distribution linesare categorized by their voltage rating. Transmissionlines are generally defined as 115 kilovolts (kV) andhigher (765 kV is the highest installed). Subtransmissionsystems are 69 kV to 138 kV. Distribution systems, thatfurnish power to retail customers, are less than 69 kV.
The transmission system usually designates the highestvoltage or voltages used on a given system and carries
1Mr. Fuldner is an operations research analyst with the Coal and Electric Analysis Branch in the Energy Information Administration’sOffice of Coal, Nuclear, Electric, and Alternate Fuels. Comments may be directed to Mr. Fuldner at 202/426-1125 or via Internet [email protected].
2“Promoting Wholesale Competition Through Open Access Non-discriminatory Transmission Services by Public Utilities; Recoveryof Stranded Costs by Public Utilities and Transmitting Utilities,” Docket Nos. RM95-8-000 and RM94-7-001, Order No. 888, April 24,1996.
3“Open Access Same-Time Information System (formerly Real-time Information Networks) and Standards of Conduct,” Docket No.RM95-9-000, Order No. 889, April 24, 1996.
Energy Information Administration/ Electric Power Monthly June 1996 xi
Table FE1. Total Proposed Transmission Line Additions for All NERC Regions, 1995-2004(Line Length Miles)
a161 operating voltage includes 69 kV, 115 kV, 138 kV, and 161 kV.bYear 2000 “230 operating voltage” total also includes 51 miles from “240 operating voltage” from Western Systems Coordinating
Council (WSCC) region.cYear 2000 “500 operating voltage” total also includes 275 miles from “525 operating voltage” from WSCC region.dYear 2002 “230 operating voltage” total also includes 45 miles from “240 operating voltage” from WSCC region.kV = kilovolts.NERC = North American Electric Reliability Council.Note: All United States, Canada, and the northern portion of Baja California, Mexico, transmission lines are included in these
projections.Source: Coordinated Bulk Power Supply Program, Reliability Council Reports of 9 Regions, U.S. Department of Energy Form
OE-411, “Coordinated Bulk Power Supply Program,” April 1, 1995.
electric energy from the power plants to the distri-bution system. Most transmission systems use overheadalternating current (AC) lines; however, some overheaddirect current transmission systems and undergroundand submarine cable exist as well. Power transformersare used in generating stations to raise the voltage ofthe produced power from the generation voltage totransmission voltage; in distribution substations toreduce the voltage of the power delivered to thedistribution system voltage; and elsewhere to connecttogether transmission systems designed at differentvoltages.
The bulk-power substation supplies power to the sub-transmission system, the part of the system betweentransmission and distribution systems. The distributionsystem carries the electricity to the residential andcommercial customers and some of the smaller indus-trial customers.
Switching stations and substations are used to trans-form the electrical energy to a different voltage, transferelectrical energy from one line to another, and to re-direct the flow of power whenever a fault occurs on thetransmission line or other equipment in the system, sosystem operation can be preserved. Circuit breakers dis-connect the flow of power from the faulted equipmentprotecting it from further damage.
A control center coordinates the operation of bulkpower system components and is responsible for oper-
ating the power system within a geographic regioncalled a control area. One or more utilities make up acontrol area. A control center is connected to othercontrol centers with transmission tie lines. Throughproper communications (metering and telemetry), thecontrol center is constantly informed of generatingplant output, transmission lines and ties to neighboringsystems, and system conditions. A control center usesthis information to ensure reliability by followingreliability criteria and to maintain its interchangeschedule with other control centers.
For the bulk power system to operate reliably, it mustbe designed and operated based on the following prin-ciples:
• The total generation at any moment must be keptequal to total electricity consumption and losseson the system including transmission and distri-bution.
• The electricity is allowed to flow through thetransmission system in accordance with physicallaws and cannot be directed to flow throughspecific lines.
• The system must be designed with reserve capa-city in generation and transmission to allow foruninterrupted service when contingencies occur.
Energy Information Administration/ Electric Power Monthly June 1996xii
IndustrialCustomers
RuralLine
Distribution Substations
X
X X
X X
X X
X
X X
X X X X
X X
ResidentialCustomers
SecondaryDistribution
Distribution Transformers
Network
DistributionSubstation
DistributionSubstation
DistributionSubstation Distribution
Substations
SubtransmissionSystem
69-138 kV
Subtransmission & Distribution System
LargeIndustrialCustomer
NuclearStation
Transmission Lines115 kV to 765 kV
VeryLarge
IndustrialCustomer
SwitchingStation
Bulk Power Supply System
High Voltageor Bulk PowerSubstations
Hydro Station Combined CycleStation
NonutilityStation
Fossil FuelThermal Station
Figure FE1. Basic Elements of a Modern Power System Showing Several Types of Electric Generation
kV = Kilovolts.Source: Homer M. Rustebakhe, ed., Electric Utility Systems and Practices (New York: John Wiley & Sons, 1983), p. 14.
Energy Information Administration/ Electric Power Monthly June 1996 xiii
Constraints on theTransmission System
The amount of power on a transmission line is theproduct of the voltage and the current and a hard-to-control factor called the “power factor.”4 Additionalpower can be transmitted reliably if there is sufficientavailable transfer capability on all lines in the systemover which the power would flow to accommodate theincrease and certain contingencies or failures that couldoccur on the system. There are three types of con-straints that limit the power transfer capability of thetransmission system: thermal/current constraints,voltage constraints, and system operating constraints.
Thermal/Current Constraints
Thermal limitations are the most common constraintsthat limit the capability of a transmission line, cable, ortransformer to carry power. The transmission lineresists the flow of electrons through it, causing heat tobe produced. The actual temperatures occurring in thetransmission line equipment depend on the current,that is the rate of flow of the electrons, and also onambient weather conditions, such as temperature, windspeed, and wind direction, because the weather effectsthe dissipation of the heat into the air.5 The thermalratings for transmission lines, however, are usuallyexpressed in terms of current flows, rather than actualtemperatures for ease of measurement.
Thermal limits are imposed because overheating leadsto two possible problems: (1) the transmission line losesstrength because of overheating which can reduce theexpected life of the line, and (2) the transmission lineexpands and sags in the center of each span betweenthe supporting towers. If the temperature is repeatedlytoo high, an overhead line will permanently stretch andmay cause its clearance from the ground to be less thanrequired for safety reasons. Because this overheating isa gradual process, higher current flows can be allowedfor limited time periods. A “normal” thermal rating fora line is the current flow level it can support indefi-nitely. Emergency ratings are levels the line cansupport for specific periods, for example, several hours.
Underground cables and power transformers are alsolimited by thermal constraints. Operating underground
cables at excess temperatures shortens their servicelives considerably due to damage to their insulation.Power transformers are likewise designed to operate ata maximum temperature rise to protect insulation.
Voltage Constraints
Voltage, a pressure-like quantity, is a measure of theelectromotive force necessary to maintain a flow ofelectricity on a transmission line. Voltage fluctuationscan occur due to variations in electricity demand and tofailures on transmission or distribution lines. Con-straints on the maximum voltage levels are set by thedesign of the transmission line. If the maximum isexceeded, short circuits, radio interference, and noisemay occur. Also, transformers and other equipment atthe substations and/or customer facilities may bedamaged or destroyed. Minimum voltage constraintsalso exist based on the power requirements of thecustomers. Low voltages cause inadequate operation ofcustomer’s equipment and may damage motors.
Voltage on a transmission line tends to “drop” from thesending end to the receiving end. The voltage dropalong the AC line is almost directly proportional toreactive power flows and line reactance6. The linereactance increases with the length of the line. Capaci-tors and inductive reactors are installed, as needed, onlines to, in part, control the amount of voltage drop.This is important because voltage levels and currentlevels determine the power that can be delivered to thecustomers.
System Operating Constraints
The operating constraints of bulk power systems stemprimarily from concerns with security and reliability.These concerns are related to maintaining the powerflows in the transmission and distribution lines of anetwork. Power flow patterns redistribute whendemands change, when generation patterns change, orwhen the transmission or distribution system is altereddue to a circuit being switched or put out of service.
Power Flows in Networks
When one utility, or control area, transmits power toanother, the resulting power flows along all paths
4The ratio of real power (kilowatt) to apparent power (kilovoltampere) for any given load and time.5CSA Energy Consultants, “Existing Electric Transmission and Distribution Upgrade Possibilities,” unpublished report prepared for
the Energy Information Administration (Arlington, VA, July 18, 1995), pp. 12-13.6Reactive power is a phenomenon associated with AC power characterized by the existence of a time difference between voltage
and current variations and depends on the power dispatch and the power requirements of the system. Reactance is a characteristicof the design and length of the line.
Energy Information Administration/ Electric Power Monthly June 1996xiv
joining the two areas, regardless of ownership of thelines. The amount of power flowing on each path of thetransmission system depends on the impedance7 of thevarious paths. The impedance of a transmission linedepends on the line’s length and design details for theline. A low impedance path attracts a greater part ofthe total transfer than a path with a high impedance.
When utilities enter into a wholesale power transactionwith other utilities, nonutilities, or customers theydesignate a pro forma “contract path” of transmissionlines or systems through which the power is expectedto flow. The actual power flows from the transactions,however, do not necessarily follow the contract pathbut may flow through parallel paths in other trans-mission systems depending on the loading conditionsat the time when the transfer occurs. These are referredto as “parallel path flows.” When transmission systemsare directly or indirectly interconnected with each otherat more than one point, power flows can travel into theother systems’ networks and return, thus forming “loopflows.” Both loop flows and parallel path flows maylimit the amount of power these other systems cantransfer for their own purpose.
Preventive Operation for System Security
Constraints on the transmission capabilities also occurdue to preventive operating procedures for systemsecurity. The bulk power system is designed and oper-ated to provide continuity of service in the case ofpossible contingencies such as: loss of a generation unit,loss of a transmission line, or a failure of any othersingle component of the system. “Preventive” operatingprocedures means operating the system in such a wayas to avoid service interruptions as a result of certaincomponent outages. It is recognized as good utilitypractice and regarded by the North American ElectricReliability Council (NERC) as the primary means ofpreventing disturbances in one area from causing ser-vice failures in another.8 NERC provides standards andoperating guidelines for overall coordination of utilityprocedures in the United States, Canada, and parts ofMexico.
The NERC guidelines recommend making it an oper-ational requirement that systems be able to handle anysingle contingency. The ability to handle multiple
contingencies should be an operational requirementwhen practical, according to NERC. The adoption of theNERC guidelines has increased the operating securityof the interconnected systems and reduced the fre-quency with which major disturbances occur.
The NERC preventive operating requirements includerunning sufficient generation capability to provideoperating reserves in excess of demand and limitingpower transfers on the transmission system. The systemthen operates so that each element remains belownormal thermal limits under normal conditions andunder emergency limits during contingencies. Thereserve capacity can then be used to handle con-tingencies.9
System Stability
Power systems stability problems represent othersystem operating constraints. Generally they aregrouped into two types:
• Maintaining synchronization among the gener-ators of the system
• Preventing the collapse of voltages.
In a synchronous, interconnected operating system, allgenerators rotate in unison at a speed that produces aconsistent frequency. In the United States, this fre-quency is 60 cycles per second. When a disturbance(fault) occurs in the transmission system, the powerrequirements from the generators change. The faultmay reduce the power requirements from the gen-erator; however, the mechanical power driving theturbine stays constant, causing the generator toaccelerate. Removing the fault alters the power flowand the turbine slows down. This results in oscillationsin the speed at which the generator rotates and in thefrequency of the power flows in the system. Unlessnatural conditions or control systems damp out theoscillations, the system is unstable. This is referred to astransient instability and may lead to a completecollapse of the system. To avoid transient instability,power transfers between areas are limited to levelsdetermined by system contingency studies.10 Steady-state instability can occur if too much power istransferred over a transmission line or part of a system
7Impedance is the opposition to the power flow on an AC circuit.8CSA Energy Consultants, “Existing Electric Transmission and Distribution Upgrade Possibilities,” unpublished report prepared for
the Energy Information Administration (Arlington, VA, July 18, 1995), p. 17.9Power Technologies, Inc., “Technical Background and Considerations in Proposed Increased Wheeling, Transmission Access and
Non-Utility Generation,” (Schenectady, New York, March 30, 1988), pp. 4-25 to 4-26.10Power Technologies, Inc., “Technical Background and Considerations in Proposed Increased Wheeling, Transmission Access and
Non-Utility Generation,” (Schenectady, New York, March 30, 1988), pp. 4-23-24.
Energy Information Administration/ Electric Power Monthly June 1996 xv
to the point that the synchronizing forces are no longereffective. Steady-state instability is an unusual occur-rence because it is easily preventable; however, it actsas a constraint on transmission power transfers.11
Small-signal instability, also called dynamic instability,usually occurs when normal variations in generation orconsumption are too small to be considered disturb-ances, but initiate oscillations at low frequencies. Theseconditions can lead to large voltage and frequencyfluctuations, resulting in loss of overall system sta-bility.12
Voltage instability occurs when the transmission systemis not adequately designed to handle reactive powerflows. Large amounts of reactive power flows on longtransmission lines result in severe drops in voltage atthe consumption end, causing the consuming entities todraw increasing currents. The increased currents causeadditional reactive power flows and voltage losses inthe system, leading to still lower voltages at the con-sumption end. As the process continues, the voltagescollapse further, requiring users to be disconnected toprevent serious damage. Finally, the system partially orfully collapses.13
Upgrade Remedies for Constraintson the Transmission System
The constraints, that have been described, limit asystem’s ability to transfer power and, therefore, lowerthe utilization rates of the existing transmission net-work. This section of the report will discuss upgradepossibilities to increase the transfer capability ofexisting transmission lines so that additional power canbe transmitted reliably from one area of a system toanother, or from one entire system to another.Remedies for constraints related to thermal limits,voltage-related limits, other options to increase powertransfer, and system operating procedures will beexplained and the typical costs of these remediesprovided. The typical cost of building a new trans-mission line (Table FE2) is also included for com-parison. Note that actual costs for a specific projectcould be somewhat higher or lower than those shown
in the table. Right-of-way costs, that is the cost of landand the legal right to use and service the land on whichthe transmission line would be located, are notincluded in the table because they vary significantlydepending on the location and the territory beingtraversed. New line costs are substantial, however, evenwithout the inclusion of the costs of rights-of-way.
Remedies for Thermal Constraints onComponents
Many options are available for reducing the limitationson power transfers due to the thermal rating of over-head transmission lines. Available measures are muchmore limited for underground cables and transformers.A review of the process used to set the present thermalrating for a transmission line may reveal ways to in-crease the rating at little or no cost. In the past, it wascommon practice to use approximations and simplifica-tions to determine thermal ratings for lines, with theresult that the lowest possible rating and greatestreliability were selected. Modern methods for com-puting thermal ratings for different conditions mayallow higher ratings without any physical changes tothe line.14
In addition, power flow limits for lines based onreaching a maximum temperature can be calculated inreal-time using data on the ambient weather conditionson the line and power flow information available to thecontrol center. Some utilities measure the temperatureof the line using detectors located on the transmissionlines and transmit it to the control center. One estimatefor such a system, including sensors and groundinstallation, was $70,000 per location.15
Since the thermal limit of a transmission line is basedon the component that would be the first to overheat,a substantial increase in the overall thermal rating ofthe line can sometimes result from replacing aninexpensive element. The replacement of a disconnectswitch or circuit breaker is much less costly than majorwork to replace a line or to build a new line. The partsbeing replaced can often be used somewhere else onthe system.
11CSA Energy Consultants, “Existing Electric Transmission and Distribution Upgrade Possibilities,” unpublished report prepared forthe Energy Information Administration (Arlington, VA, July 18, 1995), pp. 20-21.
12CSA Energy Consultants, “Existing Electric Transmission and Distribution Upgrade Possibilities,” unpublished report prepared forthe Energy Information Administration (Arlington, VA, July 18, 1995), p. 21.
13CSA Energy Consultants, “Existing Electric Transmission and Distribution Upgrade Possibilities,” unpublished report prepared forthe Energy Information Administration (Arlington, VA, July 18, 1995), p. 21.
14CSA Energy Consultants, “Existing Electric Transmission and Distribution Upgrade Possibilities,” unpublished report prepared forthe Energy Information Administration (Arlington, VA, July 18, 1995), p. 26.
15CSA Energy Consultants, “Existing Electric Transmission and Distribution Upgrade Possibilities,” unpublished report prepared forthe Energy Information Administration (Arlington, VA, July 18, 1995), p. 30.
Energy Information Administration/ Electric Power Monthly June 1996xvi
Table FE2. Typical Costs and Capacity of New Transmission Lines(1995 Dollars)
aThese costs do not include right-of-way costs.AWG = American wire gauge.kcmil = One kcmil is 1,000 circular mils, a measure of wire cross-area.kV = Kilovolts.MVA = Megavolt amperes.MW = Megawatts.Source: CSA Energy Consultants, “Existing Electric Transmission and Distribution Upgrade Possibilities,“ (Arlington, VA, July
18, 1995), p. 9.
It may be acceptable to increase allowable temperaturesand plan for a decrease in the life of the lines. Thisapproach may produce sags in the line such that theallowable clearance to the ground is not maintained. Ifinadequate clearances occur at a limited number ofspans on the line, it may be economically justifiable torebuild the towers, increasing their height to restore sagclearances, or to fence the affected parts of the right-of-way to make them inaccessible. If the excessive sagoccurs throughout the line, however, increasing theheight of towers would be very expensive. Sometimesit is possible to re-tension the line or span to increasethe clearance to the ground.
It may also be possible to increase the transfercapability of the line by monitoring the line sag toallow higher temperatures/currents. There are twopossible approaches—one direct and another indirect.The direct approach involves calculating the actual sagof the line at its mid-span using actual informationprovided by special sensors on the towers about thehorizontal tension and ambient temperature. Using thismethod, the control center calculates the actual limit onthe current that the line can handle under actualconditions. The indirect method entails transmittingtemperatures and wind velocity and locations of thecritical sag sites to the control center by radio or
Energy Information Administration/ Electric Power Monthly June 1996 xvii
telephone. With this information, the control centercalculates what the sag is and determines anydangerous trend.
The most obvious, but also most expensive method foralleviating the thermal constraints on a line is to replacethe lines with larger ones (conductors) through“restringing” or to add one or more lines, forming“bundled” lines. This approach requires considerationof the tower structures that support power lines. Thetowers are designed to hold the weight of the existinglines and the weight of any possible ice formations.They require lateral strength to withstand thesometimes very substantial forces of winds blowingperpendicular to the direction of the line. Replacinglines with larger ones, or bundling them, usuallyrequires substantial reinforcement of the tower struc-tures and, possibly, the concrete footings of the towers.Restringing or bundling lines to increase the transfercapability also requires enhancing substation equipmentso that it does not become a limiting factor. Substationenhancements cost approximately $600,000 per sub-station.16
Other typical cost estimates for restringing transmissionlines with larger conductors are:
• 60 kV line, to 397.5 kcmil:17 $40,000 per mile
• 115 kV line, to 715.5 kcmil: $80,000 per mile
• 230 kV line, to 1,113 kcmil: $120,000 per mile.
The normal thermal ratings of the restringed lineswould be approximately 55 MW, 150 MW, and 400MW, respectively.
Some typical costs of bundling lines are:
• 115 kV line, 715.5 kcmil: $130,000 per mile
• 230 kV line, 1,113 kcmil: $200,000 per mile
• 230 kV line, 2,300 kcmil: $260,000 per mile.
Bundling these lines would approximately double theirnormal thermal ratings, for an increase of approxi-mately 150 MW, 400 MW, and 500 MW, respectively.18
Remedies for Voltage Constraints forIndividual Lines
The standard voltages for electric utility lines in theUnited States are currently 34.5 kV, 46 kV, 69 kV, 115kV, 138 kV, 161 kV, 230 kV, 345 kV, 500 kV, 765 kV,and 1,100 kV (not yet commercially installed). Each ofthese line types can carry 5 percent more or less voltagefor normal operation. Upgrades to change line voltagescan be divided into two categories: increases within avoltage class and changes to a different voltage class.
Increasing the operating voltage within a voltage classis a technique that has been used for decades. If thesystem does not reach the upper voltage limit duringlight loads under normal operation, normal operatingvoltage can be increased without major configurationchanges to the lines. It is necessary, however, toincrease the voltages of the generators, and to makesome adjustments to the settings of the transformer, orpossibly some transformer replacements, in order toproduce the new operating voltage. Coordination withneighboring systems is required to prevent additionalreactive power flows because of the increased voltageinto the neighboring system.
Other remedies for voltage problems that limit transfercapabilities involve controlling reactive power flows.There are two types of reactive power sources, capaci-tors, and reactors, which generate and absorb reactivepower flows, respectively. The installation of capacitorsor reactors at strategic locations of the transmission ordistribution system, is a remedy often used to controlreactive power flows and therefore increase powertransfers. Shunt capacitor installation costs are shownbelow:
• 230 kV, 63 MVAR: New installation, $2,000,000;additional step, $700,000
• 500 kV, 100 MVAR: New installation, $3,000,000
• 500 kV, 200 MVAR: New installation, $5,000,000.
16CSA Energy Consultants, “Existing Electric Transmission and Distribution Upgrade Possibilities,” unpublished report prepared forthe Energy Information Administration (Arlington, VA, July 18, 1995), p. 28.
17One kcmil is 1,000 circular mils, a measure of wire cross-area.18CSA Energy Consultants, “Existing Electric Transmission and Distribution Upgrade Possibilities,” unpublished report prepared for
the Energy Information Administration (Arlington, VA, July 18, 1995), p. 28.
Energy Information Administration/ Electric Power Monthly June 1996xviii
Typical costs of shunt reactors on the transmission lineare:
• 230 kV, 87.9 MVAR: New installation, $2,000,000
• 500 kV, 100 MVAR: New installation,$3,000,000.19
Voltage changes to a higher voltage class usuallyrequire substantial reconstruction of the transmissionlines. Higher voltages require greater clearancesbetween the lines, and between grounded objectsincluding the towers. Increasing the string of insulatorsand making other changes drive up the weight andtransverse loadings of the towers. These changesrequire additional strength in the construction of thetowers and their footings. Typical estimates forconverting steel tower transmission lines from onevoltage class to another are:
• 60 kV to 115 kV: $50,000 per mile
• 115 kV to 230 kV: $500,000 per mile
• 230 kV to 500 kV: $800,000 per mile.
Voltage class conversions increase normal thermalratings which depend on the conductor size. Thefollowing are typical values of increases that can beachieved:
• 60 kV to 115 kV, 397.5 kcmil conductors: from 56MW to 108 MW;
• 115 kV to 230 kV, 715.5 kcmil conductors: from151 MW to 302 MW; and
• 230 kV to 500 kV, 1,113 kcmil conductors: from400 MW to 865 MW.20
Rebuilding a line to higher voltage requires furtherexpense for substation equipment. If the connectednetworks remain at the older voltage, rebuilding a lineto higher voltage would require a transformer at eitherend to provide connection to the rest of the system.Rebuilding a line for higher voltage class is not cost-effective unless a number of circuits are converted atthe same time.
Other Options to Increase PowerTransfer
Other methods of mitigating power transfer constraintsdue to individual components include: convertingsingle circuit towers to multiple-circuit towers andconverting alternating current (AC) lines to high-voltage direct current (HVDC) lines. Most transmissioncircuits for 230 kV and below are built on two-circuittower lines. Circuits for higher voltages are generallybuilt on single-circuit towers. Substantial increases ineither right-of-way width or in tower height arerequired for conversion of a single-circuit line to adouble-circuit line. Estimates of the costs of conversionare given on Table FE3.
The conversion of an AC line to HVDC, or the replace-ment of an AC line, is a consideration when large
Table FE3. Estimates for Converting Single-Circuit Tower Lines to Double Circuit
kcmil = One kcmil is 1,000 circular mils, a measure of wire cross-area.kV = Kilovolts.NA = Not applicable.Source: CSA Energy Consultants, Existing Electric Transmission and Distribution Upgrade Possibilities, July 18, 1995, p. 35.
19CSA Energy Consultants, “Existing Electric Transmission and Distribution Upgrade Possibilities,” unpublished report prepared forthe Energy Information Administration (Arlington, VA, July 18, 1995), p. 32.
20CSA Energy Consultants, “Existing Electric Transmission and Distribution Upgrade Possibilities,” unpublished report prepared forthe Energy Information Administration (Arlington, VA, July 18, 1995), p. 34.
Energy Information Administration/ Electric Power Monthly June 1996 xix
amounts of power are transmitted over long distances.HVDC lines are connected to AC systems through con-verter systems at each end. The power is convertedfrom AC to DC at the sending end and back to AC atthe receiving end. HVDC circuits have some advan-tages over AC circuits for transferring large amounts ofpower. HVDC circuits can be controlled to carry aspecific amount of power without regard to the opera-tion of the AC circuits to which they are connected. IfHVDC lines are operating in parallel with AC lines, theoutage of a parallel AC line does not overload the DCline. However, the outage of the HVDC line does in-crease the loading on the parallel AC lines. HVDCcircuits have resistance but do not have reactanceassociated with AC, so they have less voltage drop thanAC circuits. HVDC circuits have a major disadvantageas they require converter stations at each end of thecircuit that are very expensive, making HVDC uneco-nomical except when power is transmitted for longdistances. HVDC circuits also do not have the systeminstability problems that AC circuits have.
Remedies for System OperatingConstraints
Changing Power Flows
As previously mentioned, the distribution of powerflows through a transmission network depends on theimpedance of the different lines. If the power flowsover the system can be changed so that the loading ona critical line is reduced, larger power transfers can bepermitted. Sometimes the power flows through atransmission system can be improved by changing theconnections of lines at various substations to increasepower flow through some lines and reduce it in others.Some reconfigurations, such as closing some circuitbreakers and opening others, require no investment.Other reconfigurations require small investments suchas the addition of some circuit breakers or thereconnection of a line from one bus in a substation toanother.
There frequently are multiple paths between sections ofthe transmission system. A single line often becomesoverloaded before the others. Some devices can also beused to address this problem and change the powerflows; the phase-angle regulator (PAR) is the devicemost often used. PAR is also referred to as a power-angle regulator, or phase shifter. A PAR looks like a
transformer and induces a circulating power flowthrough the regulated line and back through all linesthat are more or less in parallel with it. The distributionof the current flows over the lines is changed, but thetotal power transfer is not. The use of PARs hasincreased in recent years; however, their installationsare relatively costly. A 230-kV, 300-MVA PAR with aphase angle capability of plus or minus 60 degrees isestimated at $30,000,000.21
The power flow can also be altered by reducing theimpedance of the line by inserting a series capacitor orincreasing the impedance by inserting a series reactor(actually a coil). Series capacitors are often used on longtransmission lines to reduce impedance, thus reducingthe voltage drop along the line and decreasing theamount of losses due to reactive power. Capacitorsincrease the flow of power on the line on which theyare inserted and reduce the power flow on other paral-lel lines. A 500 kV, 570 million volt amperes reactive(MVAR) capacitor installation was recently estimated at$10,000,000.22 Series reactors reduce the power flowingthrough a line which otherwise would be overloaded,but are used less often than capacitors. Series reactorsare often used to limit short circuit currents. They haveone disadvantage in that they increase the voltage dropon the line reducing power transfer capability.
Change in Operating Philosophies
The “preventive” operating procedure, discussed undersystem operating constraints, ensures that no action isrequired in the event of a system contingency otherthan clearing the fault. When contingencies arise, thesystem is capable of responding without lines over-heating, voltage problems, and instability. This ap-proach is different from “corrective” operation, whichrequires immediate action, such as switching circuits orother actions, after a contingency occurs, so the systemperformance will be adequate. Corrective operation isless reliable than preventive operation, but allowsgreater power transfers during normal operations.Corrective measures between systems sometimesbecome so complex that when a certain contingencyoccurs, the system fails.
Changing the power flows over the system to reducethe loading on the critical line after a contingencyoccurs increases the power transfers that can be madeunder normal conditions. The improvement in the
21CSA Energy Consultants, “Existing Electric Transmission and Distribution Upgrade Possibilities,” unpublished report prepared forthe Energy Information Administration (Arlington, VA, July 18, 1995), p. 42.
22CSA Energy Consultants, “Existing Electric Transmission and Distribution Upgrade Possibilities,” unpublished report prepared forthe Energy Information Administration (Arlington, VA, July 18, 1995), p. 43.
Energy Information Administration/ Electric Power Monthly June 1996xx
power flows must be compared against the cost ofsystem failures when the corrective measures do notwork. Technologies are being developed to movetoward corrective, rather than preventive methods.Technologies, developed as a part of a Flexible ACTransmission System, (FACTS), can be used to helpmitigate current preventive system operating con-straints. The FACTS concept uses new power-electronics switches and other devices to provide fasterand finer controls of equipment to change the way thesystem power flows divide over the system undernormal conditions or during contingencies. A FACTSdevice can be used to reduce the flow on the over-loaded line and increase the utilization of thealternative paths excess capacity. This allows forincreased transfer capability in existing transmissionand distribution systems under normal conditions.Some FACTS applications are presently feasible and inservice while others are in various stages of develop-ment.
Increasing Stability Limits
Various schemes are available to increase the ability towithstand power system transient instability. Thesemeasures reduce the power mismatch between genera-tion and consumption levels in different regions of thepower system. The following describes some tech-nologies for generators and their controls that influencethe transient stability performance of the power system.
The new relatively small simple cycle and combined-cycle turbines, which are dispersed throughout thepower system, can improve the stability of the systembecause of their fast response. These generators havelittle inertia and fast-acting mechanical drives, allowingthem to change their generation level rapidly comparedwith older fossil-fuel steam plants. Dispersed genera-tion usually reduces both power transfers betweenregions of the power system and power imbalance ineach region. Dispersed generation also allows for amore uniform distribution of overall system inertia.Finally, the faster response of the generators can betterfollow demand variations in their region.
Transient stability can also be maintained by two gen-erator control systems. The automatic voltage regulator(AVR) control system is responsible for maintaining afixed voltage from the generator regardless of demandlevels. AVR’s contribute to keeping the power systemwithin stability limits in the face of faults. The governorcontrol system regulates the mechanical power output
of the generator’s mechanical drive or turbine. If thegenerator rotor speed drops in a steam power plant, thegovernor increases the steam flow to the turbine, whichincreases the mechanical power delivered to the gen-erator. Conversely, an increase in rotor speed iscountered with a reduction in steam flow and turbinemechanical power. The control systems help to main-tain the synchronous speed of generators in a regionand improve the stability performance of the overallsystem.
Transient stability in systems with more than one longtransmission line can be increased by inserting one ormore switching stations. For example, if one of a pairof long lines is lost due to a fault, the path of these twolines now has an impedance twice (200 percent) whatit was before one line failed. This can have a seriouseffect on the stability of the system. If a switchingstation is installed on both lines and a fault occurs onone line, the two lines will now have 150 percent of theoriginal impedance when the fault is cleared. This is asubstantial contribution to the stability of the systemand allows a substantial increase in the transfer ofpower.
Transient instability is a major concern of system opera-tors because it is the most common source of instabilityand because changes in operating conditions producethe greatest variation in stability constraints. If systemlimitations can be calculated for actual conditions ratherthan off line, the system can be operated closer toactually needed limitations. These calculations requireon-line data that provide immediate measurements ofactual loading, generation, and transmission systemstatus. Some utilities perform their off-line dynamicsecurity studies every day based on the operating con-ditions forecast for the next day. The results of thesestudies, which are usually performed overnight, areprovided to the control center for operating the powersystem the next day. On-line dynamic security assess-ment eliminates all conservative assumptions aboutfuture operating conditions because actual data onsystem operating conditions are used. This on-lineassessment can increase the actual transfer capability ofa power system.23
Conclusion
Utilities are expecting increased competition in thefuture and are looking for ways to lower their costs.The option to increase transmission capacity by up-grading the existing lines is of interest because it can
23CSA Energy Consultants, “Existing Electric Transmission and Distribution Upgrade Possibilities,” unpublished report prepared forthe Energy Information Administration (Arlington, VA, July 18, 1995), pp. 49-50.
Energy Information Administration/ Electric Power Monthly June 1996 xxi
be done at considerably less cost than constructing anew transmission line and with a shorter lead time.Also, constructing new transmission lines is becomingmore difficult with environmental concerns, potentialhealth effects of EMF, and possibly declining propertyvalues over transmission line routes. The transfercapability of a system may be increased if the thermal,voltage, or system operating constraints of the existingtransmission lines can be removed with some of the
upgrade remedies described herein. As restructuring ofthe electric power industry for increased competitioncontinues, along with increases of wholesale trade, it isexpected that the future operators of the transmissionsystem, whether they are independent system operators(ISOs), regional transmission groups (RTGs), powerpools, or utilities, will be interested in increasing theutilization rates of the existing transmission lines usingsome of the options described in this article.
Energy Information Administration/ Electric Power Monthly June 1996xxii
U.S. Electric Power At A Glance
Energy Information Administration/Electric Power Monthly June 1996 1
Monthly Update
Nonutility Sales for Resale -- February1996
Total estimated sales of electricity for resale by nonu-tility power producers in the United States wereapproximately 18 billion kilowatthours for March1996, an increase of 1 billion kilowatthours (5percent), compared with the previous month.
Utility Generation and Retail Sales --March 1996
Generation. Total U.S. net generation of electricitywas 247 billion kilowatthours, 14 billionkilowatthours (6 percent) above the amount reportedin March 1995. Generation from all major energysources (except gas) were at higher levels during themonth, compared with the corresponding period in1995. Temperatures, that were colder than those of1995 by 29 percent, and colder than normal by 14percent, across the Nation contributed to the highergeneration levels in March 1996.
Sales. Total U.S. retail sales of electricity duringMarch 1996 were 248 billion kilowatthours, 12 billionkilowatthours (5 percent) higher than the levelreported last year at this time. Retail sales of elec-tricity in all end-use sectors were higher, comparedwith the levels reported during March 1995. Residen-tial sales increased by 7 billion kilowatthours (9percent) followed by the commercial sector, whichincreased by 3 billion kilowatthours (5 percent). Inthe industrial sector, sales of electricity were 1 billionkilowatthours (1 percent) higher, compared with ayear ago at this time.
At the Census division level, residential kilowatthoursales increased the most in the South Atlantic CensusDivision, 3 billion kilowatthours or 14 percent, fol-lowed by the East North Central, Pacific Contiguous,Middle Atlantic, and East South Central Census Divi-sions, which increased by 1 billion kilowatthours,each. Except for the Pacific Contiguous Census Divi-sion, these increases in sales to residential consumerswere due in large part to temperatures that werecolder (based on number of heating-degree days) thanlast year at this time. Temperatures during March1996, in the South Atlantic, East North Central,Middle Atlantic, and East South Central Census Divi-sions were colder by 55, 34, 29 and 61 percent,respectively, compared with a year ago.
First quarter generation and sales. Total U.S.net generation of electricity during the first quarter of1996, was 761 billion kilowatthours, an increase of 47billion kilowatthours (7 percent) compared to thesame quarter last year. Total sales of electricity to
ultimate consumers in the United States during thefirst quarter of 1996, were 773 billion kilowatthours,an increase of 43 billion kilowatthours (6 percent),compared with a year ago during the same timeperiod. March 1996 year-to-date sales of electricity toultimate consumers increased in all end-use sectors.Year-to-date residential sales increased by 28 billionkilowatthours, followed by commercial sector saleswhich increased by 11 billion kilowatthours, andindustrial sales which increased by 4 billionkilowatthours (10, 5, and 1 percent, respectively).
Total U.S. retail sales of electricity exceeded net-generation of electricity, during the first 3 months of1996, by 11 million kilowatthours (1 percent). Themajor factor contributing to this difference was elec-tric utility purchases of electricity from nonutilitypower producers, which were 56 millionkilowatthours, during this time period. Also contrib-uting to this difference, but to a lesser extent, werenet imports of electricity to the United States, whichwere estimated to be 7 million kilowatthours, during1st quarter 1996.
Fuel Receipts, Costs, and Quality --February 1996
February 1996 receipts of coal at electric utilitiestotaled 67 million short tons, up 1 million short tonsfrom February 1995 levels. This higher level of coalreceipts was due to record coal consumption of 77million short tons in January. Nationally, receipts ofcoal in February were below consumption levels,resulting in end-of-February stocks of bituminous coalfalling to 106 million short tons, their lowest levelsince October 1994.
Receipts of petroleum totaled 7 million barrels, downmore than 50 percent from the January 1996 level of15 million barrels, but in-line with the level ofmonthly purchases reported in 1995. Heavy oilreceipts for February were well below consumptionlevels for the month, causing end-of-February stocksto fall to 31 million barrels, the lowest level of inven-tory since data collection began in January 1980. Thisdrop in oil receipts is significant because it shows theextent to which electric utilities have shifted awayfrom petroleum as a baseload fuel. Today, most of thefuel oil delivered to electric utilities is received foruse at power plants in New York, Massachusetts,Florida, and Hawaii.
Receipts of gas in February were 132 billion cubicfeet (Bcf), down from the 164 Bcf reported in Feb-ruary 1995. This decrease in gas receipts was due inpart, to an increase in hydroelectric generation in thePacific Contiguous Census Division which reducedthe need for gas-fired electric generation in thisCensus division. A substantial increase in the cost ofgas as compared with the prior year period was also alimiting factor for receipts. It should also be notedthat during the winter months, especially duringperiods of extremely cold weather, gas shipments to
Energy Information Administration/Electric Power Monthly June 1996 3
Energy Information Administration/ Electric Power Monthly June 19964
Over the past decade, electric power produced by nonutility power producers re-emerged as anincreasing part of U.S. electricity generation. In the 1970's, the energy crisis, inflation, and the high costof nuclear power resulted in increased electricity rates and reduced investment in new capacity. Thesefactors led to a re-examination of alternative sources of power, such as nonutility electric power,stimulating the passage of the Public Utility Regulatory Policies Act (PURPA) of 1978 and otherlegislation encouraging growth in the nonutility industry.
For nonutilities (with a nameplate rating of 1 megawatt and greater), the final 1994 and estimated 1995for year-end nameplate capacity, gross generation, and sales to electric utilities are:
Nonutility Power Producers Final 1994 Estimated 1995
Nameplate Capacity (gigawatts) 68 71
Gross Generation (gigawatthours) 354,925 376,475
Sales to Electric Utilities (gigawatthours) 204,688 219,653
Source: Form EIA-867, “Annual Nonutility Power Producer Report.” Estimates were derived using the following procedure.For facilities that have filed for 1995 and 1994, a growth factor for each data element was calculated [Growth Factor equals(current year’s data divided by last year’s data)]. For facilities that have not filed to date, their last year’s data were multipliedby the growth factor of the corresponding data element to derive estimates for the current year. More information concerningnonutility power producers will be provided in the Electric Power Annual Volume II (DOE/EIA-348), scheduled for release inNovember 1996. For more information, contact Ms. Betty Williams at (202) 426-1269 or E-mail [email protected].
electric utilities under interruptible contracts are often customers which are given priority (for heatingeither reduced or curtailed. This is primarily due to an purposes) over electric utilities in distribution.increase in demand by residential and commercial
Electricity Supply and Demand Forecast for 1996 1
The EIA prepares a short-term forecast for electricitythat is published in the Short-Term Energy Outlook.This page provides that forecast for the current yearalong with explanations behind the forecast.2
• In 1996 total electricity demand is expected tocontinue to grow, but at slower rates than the 2.7percent seen in 1995. This is due partly to theexpectation of somewhat slower economicgrowth, as well as the assumption of normalweather, which means fewer cooling degree daysthan in 1995.
• Residential demand growth for electricity in 1996is projected at 2.1 percent compared with 1995.Normal weather this year implies higher demandin the first quarter and sharply lower demand inthe summer compared to the 1995 situation.
• Commercial sector demand is projected to rise by1.7 percent in 1996 due primarily to expandingemployment. Industrial demand is projected togrow by 0.7 percent in 1996 reflecting thecontinuing growth in industrial output.
• U.S. utilities are expected to generate about 1.1percent more electricity in 1996. Nonutility gener-ation is expected to increase at even faster rates of6.0 percent in 1996, as a result of capacityadditions.
• Hydropower generation by electric utilities is ex-pected to decrease in 1996 from the high 1995levels, even though there was significantly above-normal snowfall and rainfall in January andFebruary. This is because the improvements instreamflow in the Pacific Northwest during 1995from prior drought conditions is not expected tobe repeated.
• Nuclear power generation is expected to rise in1996, as Watts Bar 1 goes on-line and BrownsFerry 3 returns to service.
• Net imports of electricity from Canada are fore-cast to be somewhat lower than in 1995 becauseof expected growth in Canadian electricity de-mand and strong U.S. exports to Canada in thePacific Northwest area.
1Energy Information Administration, Short-Term EnergyOutlook: 2nd Quarter 1996, DOE/EIA-0202 (96/2Q) (Washington,DC, April 1996).
2Further questions on this section may be directed to RebeccaMcNerney at 202-426-1251 or via Internet [email protected].
Electricity Supply and Demand(Billion Kilowatthours)
aOther includes generation from wind, wood, waste, and solar sources.bElectricity from nonutility sources, including cogenerators and small power
producers. Quarterly numbers for nonutility net sales, own use, and generationby fuel source supplied by the Office of Coal, Nuclear, Electric and AlternateFuels, Energy Information Administration (EIA), based on annual data reportedto EIA on Form EIA-867, “Annual Nonutility Power Producer Report.”
cIncludes refinery still gas and other process or waste gases, and liquefiedpetroleum gases.
eBalancing item, mainly transmission and distribution losses.Notes: •Minor discrepancies with other EIA published historical data are due
to rounding. •Historical data are printed in bold, forecasts are in italic. •Theforecasts were generated by simulation of the Short-Term IntegratedForecasting System. •Mid World Oil Price Case.
Sources: Energy Information Administration, Short-Term IntegratedForecasting System database, and Office of Coal, Nuclear, Electric andAlternate Fuels.
Energy Information Administration/ Electric Power Monthly June 1996 5
Table 1. New Electric Generating Units by Operating Company, Plant, and State,�and Retirements and Total Capability at U.S. Electric Utilities, 1996
Net Generating Unit Month/ Summer Energy Plant State Unit Type Company Capability1 Source Number Code (megawatts)
RJanuaryIndependence City of .................................. Independence IA 8.9 3.7 Petroleum ICThorne Bay City of ..................................... Thorne Bay AK 4 0.5 Petroleum IC
Total Capability of Newly AddedUnits ......................................................... −- −- −- 4.2 −- −-
Total Capability of Retired Units............... −- −- −- .6 −- −-U.S. Total Capability ................................... −- −- −- 705,331.7 −- −-
1 Net summer capability is estimated.R Revised.Notes: •Totals may not equal sum of components because of independent rounding. •Data are preliminary. Final data for the year are to be released
in the Inventory of Power Plants in the United States 1997 (DOE/EIA - 0095(97)). •Unit Type Codes are: IC=Internal Combustion.Source: Energy Information Administration, Form EIA-860, ‘‘Annual Electric Generator Report.’’
Energy Information Administration/Electric Power Monthly June 19966
Table 2. U.S. Electric Power Summary Statistics
Year to Date March February March Items 19961 19961 19951 Difference 19961 19951 (percent)
NonutilitySales for Resale (Million kWh)............. 18,028 17,111 — 55,720 — —Coefficient of Variation (percent).......... 1.0 1.9 — — — —
Energy Information Administration/Electric Power Monthly June 1996 7
1 Values for generation, consumption, stocks, sales, revenue, and average revenue per kWh are final for 1995 and are preliminary for 1996. As ofJanuary 1996, values shown represent preliminary estimates based on a cutoff model sample for the Forms EIA-759 and EIA-900. See technicalnotes for a discussion on these sample designs.
2 Includes petroleum coke.3 Represents total pumped storage facility production minus energy used for pumping. Pumping energy used at pumped storage plants for March
1996 was 1,919 million kilowatthours.4 The March 1996 petroleum coke consumption was 38,718 short tons.5 The March 1996 petroleum coke stocks were 52,512 short tons.6 Estimates for retail sales and net generation may not correspond exactly for a particular month. Net generation data are for the calendar month.
Retail sales and associated retail revenue data accumulated from bills collected for periods of time (28 to 35 days) that vary dependent upon cus-tomer class, represent consumption occurring in and outside of the calendar month. This among other reasons (i.e., sales data may include pur-chases of electricity from nonutilities or imported electricity), is why the monthly retail sales and generation data are not directly comparable.
7 Includes public street and highway lighting, other sales to public authorities, sales to railroads and railways, and interdepartmental sales.8 Based on unrounded values. Retail revenue and retail average revenue per kilowatthour do not include taxes, such as sales and excise taxes
that are assessed on the consumer and collected through the utility. See technical notes for a discussion on 1) the sample design as of January1993 estimates and 2) data precision.
9 The February 1996 petroleum coke receipts were 95,584 short tons.10 Includes small amounts of coke-oven, refinery, and blast-furnace gas.11 Average cost of fuel delivered to electric generating plants; cost values are weighted values.12 February 1996 petroleum coke cost was 72.6 cents per million Btu.* = For detailed data, the absolute value is less than 0.5; for percentage calculations, the absolute value is less than 0.05 percent.
NM = This value may not be applicable or the percent difference calculation is not meaningful.Notes: • * means the absolute value of the number is less than 0.5. •Totals may not equal sum of components because of independent
rounding. •Percent difference is calculated before rounding. •kWh=kilowatthours, and Mcf=thousand cubic feet. •Monetary values are expressedin nominal terms.
Sources: •Energy Information Administration, Form EIA-759, ‘‘Monthly Power Plant Report’’; Form EIA-826, ‘‘Monthly Electric Utility Sales andRevenue Report with State Distributions’’; Form EIA-900, ‘‘Nonutility Sales for Resale Report.’’ •Federal Energy Regulatory Commission, FERC Form423, ‘‘Monthly Report of Cost and Quality of Fuels for Electric Plants.’’
Energy Information Administration/Electric Power Monthly June 19968
U.S. Electric Utility Net Generation
Energy Information Administration/Electric Power Monthly June 1996 9
Table 3. U.S. Electric Utility Net Generation by Month and Energy Source, January 1994�Through March 1996
All Energy Share of Total U.S. Net Generation (percent) Sources Period (Million) Coal1 Petroleum2 Gas Hydroelectric Nuclear Other3 (Kilowatthours)
1 Includes lignite, bituminous coal, subbituminous coal, and anthracite.2 Includes fuel oil Nos. 2, 4, 5, and 6, crude oil, kerosene, and petroleum coke.3 Includes geothermal, wood, wind, waste, and solar.4 Data for 1995 and prior years are final.5 As of 1996, values shown represent preliminary estimates based on a cutoff model sample of generating plants with a nameplate capacity of 25
megawatts or more (this includes all nonhydroelectric plants that use renewable fuel sources and all nuclear plants). See the Technical Notes for a detaileddescription of the estimation procedure.
Notes: •Totals may not equal sum of components because of independent rounding.Source: Energy Information Administration, Form EIA-759, ‘‘Monthly Power Plant Report.’’
Energy Information Administration/Electric Power Monthly June 1996 11
Table 4. U.S. Electric Utility Net Generation by Nonrenewable Energy Source, 1990 ThroughMarch 1996(Million Kilowatthours)
All Nonrenewable Hydroelectric3 Period Coal1 Petroleum2 Gas Nuclear Energy Sources (Pumped Storage)
1 Includes lignite, bituminous coal, subbituminous coal, and anthracite.2 Includes fuel oil Nos. 2, 4, 5, and 6, crude oil, kerosene, and petroleum coke.3 Pumping energy used for pumped storage plants for March 1996 was 1,919 million kilowatthours.4 Data for 1995 and prior years are final.5 As of 1996, values shown represent preliminary estimates based on a cutoff model sample of generating plants with a nameplate capacity of 25
megawatts or more (this includes all nonhydroelectric plants that use renewable fuel sources and all nuclear plants). See the Technical Notes for a detaileddescription of the estimation procedure.
Notes: •Totals may not equal sum of components because of independent rounding.Source: Energy Information Administration, Form EIA-759, ‘‘Monthly Power Plant Report.’’
Energy Information Administration/Electric Power Monthly June 199612
Table 5. U.S. Electric Utility Net Generation by Renewable Energy Source, 1990 ThroughMarch 1996(Thousand Kilowatthours)
All Renewable Hydroelectric Period Geothermal Biomass Wind Photovoltaic Energy Sources Conventional
1 Data for 1995 and prior years are final.2 As of 1996, values shown represent preliminary estimates based on a cutoff model sample of generating plants with a nameplate capacity of 25
megawatts or more (this includes all nonhydroelectric plants that use renewable fuel sources and all nuclear plants). See the Technical Notes for a detaileddescription of the estimation procedure.
Notes: •Totals may not equal sum of components because of independent rounding.Source: Energy Information Administration, Form EIA-759, ‘‘Monthly Power Plant Report.’’
Energy Information Administration/Electric Power Monthly June 1996 13
Table 6. Electric Utility Net Generation by NERC Region and Hawaii�(Million Kilowatthours)
Year to DateNERC Region March February March
and Hawaii 19961 19962 19952 Difference 19961 19952 (percent)
1 As of 1996, values shown represent preliminary estimates based on a cutoff model sample of generating plants with a nameplate capacity of 25megawatts or more (this includes all nonhydroelectric plants that use renewable fuel sources and all nuclear plants). See the Technical Notes for a detaileddescription of the estimation procedure.
2 Data for 1995 are final.NM = This estimated value is not available due to insufficient data, or inadequate anticipated data/model performance; information may not be appli-
cable; or the percent difference calculation is not meaningful.Notes: •Totals may not equal sum of components because of independent rounding. •See Glossary for explanation of acronyms. •Percent difference
is calculated before rounding.Source: Energy Information Administration, Form EIA-759, ‘‘Monthly Power Plant Report.’’
Energy Information Administration/Electric Power Monthly June 199614
Table 7. Electric Utility Net Generation by Census Division and State(Million Kilowatthours)
Year to Date Census Division March February March and State 19961 19962 19952 Difference 19961 19952 (percent)
U.S. Total....................................... 247,471 245,311 233,675 761,438 714,878 6.5
1 As of 1996, values shown represent preliminary estimates based on a cutoff model sample of generating plants with a nameplate capacity of 25megawatts or more (this includes all nonhydroelectric plants that use renewable fuel sources and all nuclear plants). See the Technical Notes for a detaileddescription of the estimation procedure.
2 Data for 1995 are final.* = For detailed data, the absolute value is less than 0.5; for percentage calculations, the absolute value is less than 0.05 percent.
NM = The percent difference calculation is not meaningful.Notes: •Totals may not equal sum of components because of independent rounding. •Percent difference is calculated before rounding.Source: Energy Information Administration, Form EIA-759, ‘‘Monthly Power Plant Report.’’
Energy Information Administration/Electric Power Monthly June 1996 15
Table 8. Electric Utility Net Generation from Coal by Census Division and State(Million Kilowatthours)
Year to Date
Census Division March February March Coal Generation Share of Total (percent) and State 19961 19962 19952 Difference 19961 19952 19961 19952 (percent)
U.S. Total.................................................... 137,805 137,321 126,970 427,495 397,829 7.5 56.1 55.6
1 As of 1996, values shown represent preliminary estimates based on a cutoff model sample of generating plants with a nameplate capacity of 25megawatts or more (this includes all nonhydroelectric plants that use renewable fuel sources and all nuclear plants). See the Technical Notes for a detaileddescription of the estimation procedure.
2 Data for 1995 are final.NM = This value is not available due to insufficient data, inadequate anticipated data/model performance, the percent difference calculation is not
meaningful.Notes: •Negative generation denotes that electric power consumed for plant use exceeds gross generation. •Totals may not equal sum of components
because of independent rounding. •Percent difference is calculated before rounding. •Coal includes lignite, bituminous coal, subbituminous coal, and anthra-cite.
Source: Energy Information Administration, Form EIA-759, ‘‘Monthly Power Plant Report.’’
Energy Information Administration/Electric Power Monthly June 199616
Table 9. Electric Utility Net Generation from Petroleum by Census Division and State(Million Kilowatthours)
Year to Date
Census Division March February March Petroleum Generation Share of Total (percent) and State 19961 19962 19952 Difference 19961 19952 19961 19952 (percent)
U.S. Total.................................................... 6,181 8,255 3,080 22,390 14,282 56.8 2.9 2.0
1 As of 1996, values shown represent preliminary estimates based on a cutoff model sample of generating plants with a nameplate capacity of 25megawatts or more (this includes all nonhydroelectric plants that use renewable fuel sources and all nuclear plants). See the Technical Notes for a detaileddescription of the estimation procedure.
2 Data for 1995 are final.* = For detailed data, the absolute value is less than 0.5; for percentage calculations, the absolute value is less than 0.05 percent.
NM = This value is not available due to insufficient data, inadequate anticipated data/model performance, the percent difference calculation is notmeaningful.
Notes: •Negative generation denotes that electric power consumed for plant use exceeds gross generation. •Totals may not equal sum of componentsbecause of independent rounding. •Percent difference is calculated before rounding. •Includes fuel oil Nos. 2, 4, 5, and 6, crude oil, kerosene, andpetro-leum coke.
Source: Energy Information Administration, Form EIA-759, ‘‘Monthly Power Plant Report.’’
Energy Information Administration/Electric Power Monthly June 1996 17
Table 10. Electric Utility Net Generation from Gas by Census Division and State(Million Kilowatthours)
Year to Date
Census Division March February March Gas Generation Share of Total (percent) and State 19961 19962 19952 Difference 19961 19952 19961 19952 (percent)
U.S. Total.................................................... 15,225 13,330 23,844 44,551 59,605 −25.3 5.9 8.3
1 As of 1996, values shown represent preliminary estimates based on a cutoff model sample of generating plants with a nameplate capacity of 25megawatts or more (this includes all nonhydroelectric plants that use renewable fuel sources and all nuclear plants). See the Technical Notes for a detaileddescription of the estimation procedure.
2 Data for 1995 are final.* = For detailed data, the absolute value is less than 0.5; for percentage calculations, the absolute value is less than 0.05 percent.
NM = This value is not available due to insufficient data, inadequate anticipated data/model performance, the percent difference calculation is notmeaningful.
Notes: •Negative generation denotes that electric power consumed for plant use exceeds gross generation. •Totals may not equal sum of componentsbecause of independent rounding. •Percent difference is calculated before rounding.
Source: Energy Information Administration, Form EIA-759, ‘‘Monthly Power Plant Report.’’
Energy Information Administration/Electric Power Monthly June 199618
Table 11. Electric Utility Hydroelectric Net Generation by Census Division and State(Million Kilowatthours)
Year to Date
Census Division March February March Hydroelectric Generation Share of Total (percent) and State 19961 19962 19952 Difference 19961 19952 19961 19952 (percent)
U.S. Total.................................................... 32,287 29,929 27,458 91,109 74,704 22.0 12.0 10.4
1 As of 1996, values shown represent preliminary estimates based on a cutoff model sample of generating plants with a nameplate capacity of 25megawatts or more (this includes all nonhydroelectric plants that use renewable fuel sources and all nuclear plants). See the Technical Notes for a detaileddescription of the estimation procedure.
2 Data for 1995 are final.* = For detailed data, the absolute value is less than 0.5; for percentage calculations, the absolute value is less than 0.05 percent.
NM = This value is not available due to insufficient data, inadequate anticipated data/model performance, the percent difference calculation is notmeaningful.
Notes: •Negative generation denotes that electric power consumed for plant use exceeds gross generation. •Pumping energy used at pumped storageplants for March 1996 was 1,919 million kilowatthours. •Totals may not equal sum of components because of independent rounding. •Percent difference iscalculated before rounding.
Source: Energy Information Administration, Form EIA-759, ‘‘Monthly Power Plant Report.’’
Energy Information Administration/Electric Power Monthly June 1996 19
Table 12. Electric Utility Nuclear-Powered Net Generation by Census Division and State(Million Kilowatthours)
Year to Date
Census Division March February March Nuclear Generation Share of Total (percent) and State 19961 19962 19952 Difference 19961 19952 19961 19952 (percent)
U.S. Total.................................................... 55,474 55,978 51,880 174,393 167,080 4.4 22.9 23.4
1 As of 1996, values shown represent preliminary estimates based on a cutoff model sample of generating plants with a nameplate capacity of 25megawatts or more (this includes all nonhydroelectric plants that use renewable fuel sources and all nuclear plants). See the Technical Notes for a detaileddescription of the estimation procedure.
2 Data for 1995 are final.NM = This value is not available due to insufficient data, inadequate anticipated data/model performance, the percent difference calculation is not
meaningful.Notes: •Negative generation denotes that electric power consumed for plant use exceeds gross generation. •Totals may not equal sum of components
because of independent rounding. •Percent difference is calculated before rounding.Source: Energy Information Administration, Form EIA-759, ‘‘Monthly Power Plant Report.’’
Energy Information Administration/Electric Power Monthly June 199620
Table 13. Electric Utility Net Generation from Other Energy Sources by Census Division and State(Million Kilowatthours)
Year to Date
Census Division March February March Other Generation Share of Total (percent) and State 19961 19962 19952 Difference 19961 19952 19961 19952 (percent)
U.S. Total.................................................... 499 498 442 1,499 1,379 8.7 .2 .2
1 As of 1996, values shown represent preliminary estimates based on a cutoff model sample of generating plants with a nameplate capacity of 25megawatts or more (this includes all nonhydroelectric plants that use renewable fuel sources and all nuclear plants). See the Technical Notes for a detaileddescription of the estimation procedure.
2 Data for 1995 are final.* = For detailed data, the absolute value is less than 0.5; for percentage calculations, the absolute value is less than 0.05 percent.
NM = This value is not available due to insufficient data, inadequate anticipated data/model performance, the percent difference calculation is notmeaningful.
Notes: •Negative generation denotes that electric power consumed for plant use exceeds gross generation. •Totals may not equal sum of componentsbecause of independent rounding. •Percent difference is calculated before rounding. •Other energy sources include geothermal, wood, wind, waste, and so-lar.
Source: Energy Information Administration, Form EIA-759, ‘‘Monthly Power Plant Report.’’
Energy Information Administration/Electric Power Monthly June 1996 21
U.S. Electric Utility Consumption of Fossil Fuels
Energy Information Administration/Electric Power Monthly June 1996 23
Table 14. U.S. Electric Utility Consumption of Fossil Fuels, 1986 Through March 1996
Coal Petroleum Petroleum(thousand short tons) (thousand barrels) Coke Gas
Period (thousand (thousand short Mcf) Anthracite1 Bituminous2 Lignite Total Light Heavy Total tons)
1 Includes anthracite silt stored off-site.2 Includes subbituminous coal.3 Data for 1995 and prior years are final.4 As of 1996, values shown represent preliminary estimates based on a cutoff model sample of generating plants with a nameplate capacity of 25
megawatts or more (this includes all nonhydroelectric plants that use renewable fuel sources and all nuclear plants). See the Technical Notes for a detaileddescription of the estimation procedure.
Notes: •Totals may not equal sum of components because of independent rounding. •Mcf=thousand cubic feet.Source: Energy Information Administration, Form EIA-759, ‘‘Monthly Power Plant Report,’’ and predecessor forms.
Energy Information Administration/Electric Power Monthly June 1996 25
Table 15. Electric Utility Consumption of Coal by NERC Region and Hawaii(Thousand Short Tons)
Year to DateNERC Region March February March
and Hawaii 19961 19962 19952 Difference 19961 19952 (percent)
1 As of 1996, values shown represent preliminary estimates based on a cutoff model sample of generating plants with a nameplate capacity of 25megawatts or more (this includes all nonhydroelectric plants that use renewable fuel sources and all nuclear plants). See the Technical Notes for a detaileddescription of the estimation procedure.
2 Data for 1995 are final.NM = This estimated value is not available due to insufficient data, or inadequate anticipated data/model performance; information may not be appli-
cable; or the percent difference calculation is not meaningful.Notes: •Totals may not equal sum of components because of independent rounding. •Percent difference is calculated before rounding. •Coal includes
lignite, bituminous coal, subbituminous coal, and anthracite.Source: Energy Information Administration, Form EIA-759, ‘‘Monthly Power Plant Report.’’
Table 16. Electric Utility Consumption of Petroleum by NERC Region and Hawaii(Thousand Barrels)
Year to DateNERC Region March February March
and Hawaii 19961 19962 19952 Difference 19961 19952 (percent)
1 As of 1996, values shown represent preliminary estimates based on a cutoff model sample of generating plants with a nameplate capacity of 25megawatts or more (this includes all nonhydroelectric plants that use renewable fuel sources and all nuclear plants). See the Technical Notes for a detaileddescription of the estimation procedure.
2 Data for 1995 are final.NM = This estimated value is not available due to insufficient data, or inadequate anticipated data/model performance; information may not be appli-
cable; or the percent difference calculation is not meaningful.Note: Totals may not equal sum of components because of independent rounding.Source: Energy Information Administration, Form EIA-759, ‘‘Monthly Power Plant Report.’’
Energy Information Administration/Electric Power Monthly June 199626
Table 17. Electric Utility Consumption of Gas by NERC Region and Hawaii(Million Cubic Feet)
Year to DateNERC Region March February March
and Hawaii 19961 19962 19952 Difference 19961 19952 (percent)
1 As of 1996, values shown represent preliminary estimates based on a cutoff model sample of generating plants with a nameplate capacity of 25megawatts or more (this includes all nonhydroelectric plants that use renewable fuel sources and all nuclear plants). See the Technical Notes for a detaileddescription of the estimation procedure.
2 Data for 1995 are final.NM = This estimated value is not available due to insufficient data, or inadequate anticipated data/model performance; information may not be appli-
cable; or the percent difference calculation is not meaningful.Note: Totals may not equal sum of components because of independent rounding.Source: Energy Information Administration, Form EIA-759, ‘‘Monthly Power Plant Report.’’
Energy Information Administration/Electric Power Monthly June 1996 27
Table 18. Electric Utility Consumption of Coal by Census Division and State(Thousand Short Tons)
Year to Date Census Division March February March and State 19961 19962 19952 Difference 19961 19952 (percent)
U.S. Total....................................... 68,838 69,129 63,569 214,769 198,782 8.0
1 As of 1996, values shown represent preliminary estimates based on a cutoff model sample of generating plants with a nameplate capacity of 25megawatts or more (this includes all nonhydroelectric plants that use renewable fuel sources and all nuclear plants). See the Technical Notes for a detaileddescription of the estimation procedure.
2 Data for 1995 are final.NM = This value is not available due to insufficient data, inadequate anticipated data/model performance, the percent difference calculation is not
meaningful.Notes: •Totals may not equal sum of components because of independent rounding. •Percent difference is calculated before rounding. •Coal includes
lignite, bituminous coal, subbituminous coal, and anthracite.Source: Energy Information Administration, Form EIA-759, ‘‘Monthly Power Plant Report.’’
Energy Information Administration/Electric Power Monthly June 199628
Table 19. Electric Utility Consumption of Petroleum by Census Division and State(Thousand Barrels)
Year to Date Census Division March February March and State 19961 19962 19952 Difference 19961 19952 (percent)
U.S. Total....................................... 10,532 14,417 5,183 38,454 23,968 60.4
1 As of 1996, values shown represent preliminary estimates based on a cutoff model sample of generating plants with a nameplate capacity of 25megawatts or more (this includes all nonhydroelectric plants that use renewable fuel sources and all nuclear plants). See the Technical Notes for a detaileddescription of the estimation procedure.
2 Data for 1995 are final.* = For detailed data, the absolute value is less than 0.5; for percentage calculations, the absolute value is less than 0.05 percent.
NM = This value is not available due to insufficient data, inadequate anticipated data/model performance, the percent difference calculation is notmeaningful.
Notes: •Totals may not equal sum of components because of independent rounding. •Percent difference is calculated before rounding. •Data do notinclude petroleum coke. •The March 1996 petroleum coke consumption was 38,718 short tons.
Source: Energy Information Administration, Form EIA-759, ‘‘Monthly Power Plant Report.’’
Energy Information Administration/Electric Power Monthly June 1996 29
Table 20. Electric Utility Consumption of Gas by Census Division and State(Million Cubic Feet)
Year to Date Census Division March February March and State 19961 19962 19952 Difference 19961 19952 (percent)
U.S. Total....................................... 156,110 136,572 245,111 460,317 612,053 −24.8
1 As of 1996, values shown represent preliminary estimates based on a cutoff model sample of generating plants with a nameplate capacity of 25megawatts or more (this includes all nonhydroelectric plants that use renewable fuel sources and all nuclear plants). See the Technical Notes for a detaileddescription of the estimation procedure.
2 Data for 1995 are final.* = For detailed data, the absolute value is less than 0.5; for percentage calculations, the absolute value is less than 0.05 percent.
NM = This value is not available due to insufficient data, inadequate anticipated data/model performance, the percent difference calculation is notmeaningful.
Notes: •Totals may not equal sum of components because of independent rounding.Source: Energy Information Administration, Form EIA-759, ‘‘Monthly Power Plant Report.’’
Energy Information Administration/Electric Power Monthly June 199630
Fossil-Fuel Stocks at U.S. Electric Utilities
Energy Information Administration/Electric Power Monthly June 1996 31
Table 21. U.S. Electric Utility Stocks of Coal and Petroleum, 1986 Through March 1996
Coal Petroleum Petroleum(thousand short tons) (thousand barrels) Coke
Period (thousand short Anthracite1 Bituminous2 Lignite Total Light Heavy Total tons)
1 Anthracite includes anthracite silt stored off-site.2 Bituminous coal includes subbituminous coal.3 Data for 1995 and prior years are final.4 As of 1996, values shown represent preliminary estimates based on a cutoff model sample of generating plants with a nameplate capacity of 25
megawatts or more (this includes all nonhydroelectric plants that use renewable fuel sources and all nuclear plants). See the Technical Notes for a detaileddescription of the estimation procedure.
Notes: •Totals may not equal sum of components because of independent rounding. •Prior to 1993, values represent December end-of-month stocks.For 1993 forward, values represent end-of-month stocks.
Source: Energy Information Administration, Form EIA-759, ‘‘Monthly Power Plant Report,’’ and predecessor forms.
Energy Information Administration/Electric Power Monthly June 1996 33
Table 22. Electric Utility Stocks of Coal by NERC Region and Hawaii(Thousand Short Tons)
NERC Region March February March Monthly Difference Yearly Difference and Hawaii 19961 19962 19952 (percent) (percent)
1 As of 1996, values shown represent preliminary estimates based on a cutoff model sample of generating plants with a nameplate capacity of 25megawatts or more (this includes all nonhydroelectric plants that use renewable fuel sources and all nuclear plants). See the Technical Notes for a detaileddescription of the estimation procedure.
2 Data for 1995 are final.NM = This estimated value is not available due to insufficient data, or inadequate anticipated data/model performance; information may not be appli-
cable; or the percent difference calculation is not meaningful.Notes: •Totals may not equal sum of components because of independent rounding. •Percent difference is calculated before rounding. •Coal includes
lignite, bituminous coal, subbituminous coal, and anthracite. •Stocks are end-of-month stocks at electric utilities.Source: Energy Information Administration, Form EIA-759, ‘‘Monthly Power Plant Report.’’
Table 23. Electric Utility Stocks of Petroleum by NERC Region and Hawaii(Thousand Barrels)
NERC Region March February March Monthly Difference Yearly Difference and Hawaii 19961 19962 19952 (percent) (percent)
1 As of 1996, values shown represent preliminary estimates based on a cutoff model sample of generating plants with a nameplate capacity of 25megawatts or more (this includes all nonhydroelectric plants that use renewable fuel sources and all nuclear plants). See the Technical Notes for a detaileddescription of the estimation procedure.
2 Data for 1995 are final.NM = This estimated value is not available due to insufficient data, or inadequate anticipated data/model performance; information may not be appli-
cable; or the percent difference calculation is not meaningful.Notes: •Totals may not equal sum of components because of independent rounding. •Percent difference is calculated before rounding. •Data do not
include petroleum coke. •Stocks are end-of-month stocks at electric utilities.Source: Energy Information Administration, Form EIA-759, ‘‘Monthly Power Plant Report.’’
Energy Information Administration/Electric Power Monthly June 199634
Table 24. Electric Utility Stocks of Coal by Census Division and State(Thousand Short Tons)
Census Division March February March Monthly Difference Yearly Difference and State 19961 19962 19952 (percent) (percent)
U.S. Total ............................................. 117,477 115,553 135,778 1.7 −13.5
1 As of 1996, values shown represent preliminary estimates based on a cutoff model sample of generating plants with a nameplate capacity of 25megawatts or more (this includes all nonhydroelectric plants that use renewable fuel sources and all nuclear plants). See the Technical Notes for a detaileddescription of the estimation procedure.
2 Data for 1995 are final.* = For detailed data, the absolute value is less than 0.5; for percentage calculations, the absolute value is less than 0.05 percent.
NM = This value is not available due to insufficient data, inadequate anticipated data/model performance, the percent difference calculation is notmeaningful.
Notes: •Totals may not equal sum of components because of independent rounding. •Percent difference is calculated before rounding. •Coal includeslignite, bituminous coal, subbituminous coal, and anthracite. •Stocks are end-of-month stocks at electric utilities.
Source: Energy Information Administration, Form EIA-759, ‘‘Monthly Power Plant Report.’’
Energy Information Administration/Electric Power Monthly June 1996 35
Table 25. Electric Utility Stocks of Petroleum by Census Division and State(Thousand Barrels)
Census Division March February March Monthly Difference Yearly Difference and State 19961 19962 19952 (percent) (percent)
U.S. Total ............................................. 42,440 45,036 56,641 −5.8 −25.1
1 As of 1996, values shown represent preliminary estimates based on a cutoff model sample of generating plants with a nameplate capacity of 25megawatts or more (this includes all nonhydroelectric plants that use renewable fuel sources and all nuclear plants). See the Technical Notes for a detaileddescription of the estimation procedure.
2 Data for 1995 are final.* = For detailed data, the absolute value is less than 0.5; for percentage calculations, the absolute value is less than 0.05 percent.
NM = This value is not available due to insufficient data, inadequate anticipated data/model performance, the percent difference calculation is notmeaningful.
Notes: •Totals may not equal sum of components because of independent rounding. •Percent difference is calculated before rounding. •Data do notinclude petroleum coke. •The March 1996 petroleum coke stocks were 52,512 short tons. •Stocks are end-of-month stocks at electric utilities.
Source: Energy Information Administration, Form EIA-759, ‘‘Monthly Power Plant Report.’’
Energy Information Administration/Electric Power Monthly June 199636
Receipts and Cost of Fossil Fuels at U.S. ElectricUtilities
Energy Information Administration/Electric Power Monthly June 1996 37
Table 26. U.S. Electric Utility Receipts of and Average Cost for Fossil Fuels,�1985 Through February 1996
All Fossil Coal 1 Petroleum Gas Fuels 2
Heavy Oil 3 Total Period Receipts Cost Receipts Cost Cost (thousand (cents/ Receipts Cost Receipts Cost (thousand (cents/ (cents/ short tons) 106 Btu) (thousand (cents/ (thousand (cents/ Mcf) 106 Btu) 106 Btu) barrels) 106 Btu) barrels) 106 Btu)
1 Includes lignite, bituminous coal, subbituminous coal, and anthracite.2 The weighted average for all fossil fuels includes both heavy oil and light oil (Fuel Oil No. 2, kerosene, and jet fuel) prices. Data do not include petro-
leum coke.3 Heavy oil includes Fuel Oil Nos. 4, 5, and 6, and topped crude fuel oil.4 Data for 1996 are preliminary. Data for 1995 are final.Notes: •Totals may not equal sum of components because of independent rounding. •As of 1991, data are for electric generating plants with a total
steam-electric and combined-cycle nameplate capacity of 50 or more megawatts. •Data for 1986-1990 are for steam-electric plants with a generator name-plate capacity of 50 or more megawatts. •Mcf=thousand cubic feet. •Monetary values are expressed in nominal terms.
Source: Federal Energy Regulatory Commission, FERC Form 423, ‘‘Monthly Report of Cost and Quality of Fuels for Electric Plants,’’ and predecessorforms.
Energy Information Administration/Electric Power Monthly June 1996 39
Table 27. Electric Utility Receipts of Coal by NERC Region and Hawaii(Thousand Short Tons)
Year to Date NERC Region February January February and Hawaii 19961 19961 19951 Difference 19961 19951 (percent)
1 Data for 1996 are preliminary. Data for 1995 are final.Notes: •Totals may not equal sum of components because of independent rounding. •Data are for electric generating plants with a total steam-elec-
tric and combined-cycle nameplate capacity of 50 or more megawatts. •Includes lignite, bituminous coal, subbituminous coal, and anthracite.Source: Federal Energy Regulatory Commission, FERC Form 423, ‘‘Monthly Report of Cost and Quality of Fuels for Electric Plants.’’
Table 28. Average Cost of Coal Delivered to Electric Utilities by NERC Region and Hawaii(Cents/Million Btu)
Year to Date NERC Region February January February and Hawaii 19961 19961 19951 Difference 19961 19951 (percent)
1 Data for 1996 are preliminary. Data for 1995 are final.Notes: •Totals may not equal sum of components because of independent rounding. •Data are for electric generating plants with a total steam-elec-
tric and combined-cycle nameplate capacity of 50 or more megawatts. •Includes lignite, bituminous coal, subbituminous coal, and anthracite. •Monetary val-ues are expressed in monetary terms.
Source: Federal Energy Regulatory Commission, FERC Form 423, ‘‘Monthly Report of Cost and Quality of Fuels for Electric Plants.’’
Energy Information Administration/Electric Power Monthly June 199640
Table 29. Electric Utility Receipts of Petroleum by NERC Region and Hawaii(Thousand Barrels)
Year to Date NERC Region February January February and Hawaii 19961 19961 19951 Difference 19961 19951 (percent)
1 Data for 1996 are preliminary. Data for 1995 are final.Notes: •Totals may not equal sum of components because of independent rounding. •Data are for electric generating plants with a total steam-elec-
tric and combined-cycle nameplate capacity of 50 or more megawatts.Source: Federal Energy Regulatory Commission, FERC Form 423, ‘‘Monthly Report of Cost and Quality of Fuels for Electric Plants.’’
Table 30. Average Cost of Petroleum Delivered to Electric Utilities by NERC Region and Hawaii(Cents/Million Btu)
Year to Date NERC Region February January February and Hawaii 19961 19961 19951 Difference 19961 19951 (percent)
1 Data for 1996 are preliminary. Data for 1995 are final.Notes: •Totals may not equal sum of components because of independent rounding. •Data are for electric generating plants with a total steam-elec-
tric and combined-cycle nameplate capacity of 50 or more megawatts. •Monetary values are expressed in monetary terms.Source: Federal Energy Regulatory Commission, FERC Form 423, ‘‘Monthly Report of Cost and Quality of Fuels for Electric Plants.’’
Energy Information Administration/Electric Power Monthly June 1996 41
Table 31. Electric Utility Receipts of Gas by NERC Region and Hawaii(Million Cubic Feet)
Year to Date NERC Region February January February and Hawaii 19961 19961 19951 Difference 19961 19951 (percent)
1 Data for 1996 are preliminary. Data for 1995 are final.Notes: •Totals may not equal sum of components because of independent rounding. •Data are for electric generating plants with a total steam-elec-
tric and combined-cycle nameplate capacity of 50 or more megawatts.Source: Federal Energy Regulatory Commission, FERC Form 423, ‘‘Monthly Report of Cost and Quality of Fuels for Electric Plants.’’
Table 32. Average Cost of Gas Delivered to Electric Utilities by NERC Region and Hawaii(Cents/Million Btu)
Year to Date NERC Region February January February and Hawaii 19961 19961 19951 Difference 19961 19951 (percent)
1 Data for 1996 are preliminary. Data for 1995 are final.Notes: •Totals may not equal sum of components because of independent rounding. •Data are for electric generating plants with a total steam-elec-
tric and combined-cycle nameplate capacity of 50 or more megawatts. •Monetary values are expressed in monetary terms.Source: Federal Energy Regulatory Commission, FERC Form 423, ‘‘Monthly Report of Cost and Quality of Fuels for Electric Plants.’’
Energy Information Administration/Electric Power Monthly June 199642
Table 33. Electric Utility Receipts of Coal by Type, Census Division, and State,�February 1996
Anthracite Bituminous Subbituminous Lignite Total
Census Division(thousand (thousand (thousand (thousand (thousand
and State (billion (billion (billion (billion (billionshort short short short short
Notes: •Totals may not equal sum of components because of independent rounding. •Data are for electric generating plants with total steam-electricand combined-cycle nameplate capacity of 50 or more megawatts. •Data for 1996 are preliminary.
Source: Federal Energy Regulatory Commission, FERC Form 423, ‘‘Monthly Report of Cost and Quality of Fuels for Electric Plants.’’
Energy Information Administration/Electric Power Monthly June 1996 43
Table 34. Receipts and Average Cost of Coal Delivered to Electric Utilities by CensusDivision and State
February 1996 February 1995 Year to Date Receipts Receipts
Census Division Receipts Average Cost and State (thousand (billion (thousand (billion (billion Btu) (cents/million Btu) 1 short tons) Btu) short tons) Btu)
U.S. Total..................................................................... 66,567 1,370,489 65,789 1,350,737 2,739,026 2,782,591 129.2 133.3
1 Monetary values are expressed in nominal terms.Notes: •Data for 1996 are preliminary. Data for 1995 are final. •Totals may not equal sum of components because of independent rounding. •Data
are for electric generating plants with a total steam-electric and combined-cycle nameplate capacity of 50 or more megawatts. •Coal includes lignite, bitumi-nous coal, subbituminous coal, and anthracite.
Source: Federal Energy Regulatory Commission, FERC Form 423, ‘‘Monthly Report of Cost and Quality of Fuels for Electric Plants.’’
Energy Information Administration/Electric Power Monthly June 199644
Table 35. Receipts and Average Cost of Coal Delivered to Electric Utilities by Type of Purchase,�Mining Method, Census Division, and State, February 1996
Type of Purchase Type of Mining
Contract Spot Strip and Auger Underground
Census Division Receipts Average Cost1 Receipts Average Cost1 Receipts Average Cost1 Receipts Average Cost1 and State
(1,000 ($/ (1,000 ($/ (1,000 ($/ (1,000 ($/ (Cents/ (Cents/ (Cents/ (Cents/ short short short short short short short short 106 Btu) 106 Btu) 106 Btu) 106 Btu) tons) ton) tons) ton) tons) ton) tons) ton)
U. S. Total.......................................... 53,933 132.6 26.71 12,634 117.0 26.27 45,966 123.2 23.24 20,601 139.8 34.19
1 Monetary values are expressed in nominal terms.Notes: •Totals may not equal sum of components because of independent rounding. •Data are for electric generating plants with a total steam-
electric and combined-cycle nameplate capacity of 50 or more megawatts. •Data for 1996 are preliminary.Source: Federal Energy Regulatory Commission, FERC Form 423, ‘‘Monthly Report of Cost and Quality of Fuels for Electric Plants.’’
Energy Information Administration/Electric Power Monthly June 1996 45
Table 36. Receipts and Average Cost of Coal Delivered to Electric Utilities by Sulfur Content,Census Division, and State, February 1996
0.5% or Less More than 0.5% up to 1.0% More than 1.0% up to 1.5%
Average Average Average Receipts Receipts Receipts Census Division Cost1 Cost1 Cost1
and State (1,000 ($/ (1,000 ($/ (1,000 ($/ (Cents/ (Cents/ (Cents/ short short short short short short 106 Btu) 106 Btu) 106 Btu) tons) ton) tons) ton) tons) ton)
U. S. Total.................................................. 23,231 121.0 21.31 19,748 140.8 30.21 7,026 132.2 29.06
1 Monetary values are expressed in nominal terms.Notes: •Totals may not equal sum of components because of independent rounding. •Data are for electric generating plants with a total steam-
electric and combined-cycle nameplate capacity of 50 or more megawatts. •Data for 1996 are preliminary.Source: Federal Energy Regulatory Commission, FERC Form 423, ‘‘Monthly Report of Cost and Quality of Fuels for Electric Plants.’’
Energy Information Administration/Electric Power Monthly June 199646
Table 36. Receipts and Average Cost of Coal Delivered to Electric Utilities by Sulfur Content,Census Division, and State, February 1996 (Continued)
More than 1.5% up to 2.0% More than 2.0% up to 3.0% More than 3.0% All Purchases
Average Average Average Receipts Receipts Receipts Census Division Cost1 Cost1 Cost1
and State (1,000 ($/ (1,000 ($/ (1,000 (Cents/ ($/ (Cents/ ($/ (Cents/ (Cents/ short short short short short 106 short 106 short 106 Btu) 106 Btu)tons) ton) tons) ton) tons) Btu) ton) Btu) ton)
U. S. Total.................................................... 5,319 129.4 29.22 5,666 121.3 28.86 5,578 122.7 28.28 129.3 26.63
1 Monetary values are expressed in nominal terms.Notes: •Totals may not equal sum of components because of independent rounding. •Data are for electric generating plants with a total steam-
electric and combined-cycle nameplate capacity of 50 or more megawatts. •Data for 1996 are preliminary.Source: Federal Energy Regulatory Commission, FERC Form 423, ‘‘Monthly Report of Cost and Quality of Fuels for Electric Plants.’’
Energy Information Administration/Electric Power Monthly June 1996 47
Table 37. Electric Utility Receipts of Petroleum by Type, Census Division, and State,February 1996
No. 2 Fuel Oil No. 4 Fuel Oil1 No. 5 Fuel Oil1 No. 6 Fuel Oil Total Census Division
1 Blend of No. 2 Fuel Oil and No. 6 Fuel Oil.Notes: •Totals may not equal sum of components because of independent rounding. •Data are for electric generating plants with total steam-electric
and combined-cycle nameplate capacity of 50 or more megawatts. •Data for 1996 are preliminary.Source: Federal Energy Regulatory Commission, FERC Form 423, ‘‘Monthly Report of Cost and Quality of Fuels for Electric Plants.’’
Energy Information Administration/Electric Power Monthly June 199648
Table 38. Receipts and Average Cost of Petroleum Delivered to Electric Utilities by CensusDivision and State
February 1996 February 1995 Year to Date Receipts Receipts
Census Division Receipts Average Cost and State (thousand (billion (thousand (billion (billion Btu) (cents/million Btu) 1 barrels) Btu) barrels) Btu)
U.S. Total..................................................................... 7,021 44,214 6,535 41,374 135,849 79,836 325.3 272.5
1 Monetary values are expressed in nominal terms.* Less than 0.5.Notes: •Data for 1996 are preliminary. Data for 1995 are final. •Totals may not equal sum of components because of independent rounding. •Data
are for electric generating plants with a total steam-electric and combined-cycle nameplate capacity of 50 or more megawatts. •The February 1996 petro-leum coke receipts were 95,584 short tons and the cost was 72.6 cents per million Btu.
Source: Federal Energy Regulatory Commission, FERC Form 423, ‘‘Monthly Report of Cost and Quality of Fuels for Electric Plants.’’
Energy Information Administration/Electric Power Monthly June 1996 49
Table 39. Receipts and Average Cost of Petroleum Delivered to Electric Utilities by Type ofPurchase, Census Division, and State, February 1996
Fuel Oil No. 6 by Type of Purchase Averaged Cost of Fuel Oils1
Contract Spot No. 2 No. 4-No. 5 No. 6 Census Division and State Receipts Average Cost1 Receipts Average Cost1
U. S. Total....................................... 3,224 285.7 18.21 2,794 276.9 17.64 431.2 25.17 352.6 21.28 281.6 17.94
1 Monetary values are expressed in nominal terms.Notes: •Totals may not equal sum of components because of independent rounding. •Data are for electric generating plants with a total steam-
electric and combined-cycle nameplate capacity of 50 or more megawatts. •Data for 1996 are preliminary.Source: Federal Energy Regulatory Commission, FERC Form 423, ‘‘Monthly Report of Cost and Quality of Fuels for Electric Plants.’’
Energy Information Administration/Electric Power Monthly June 199650
Table 40. Receipts and Average Cost of Heavy Oil Delivered to Electric Utilities by SulfurContent, Census Division, and State, February 1996
0.3% or Less More than 0.3% up to 0.5% More than 0.5% up to 1.0%
Average Average Average Census Division Receipts Receipts Receipts Cost1 Cost1 Cost1 and State
U. S. Total.................................................. 719 236.8 15.16 965 342.1 21.56 2,323 292.7 18.60
1 Monetary values are expressed in nominal terms.Notes: •Totals may not equal sum of components because of independent rounding. •Data are for electric generating plants with a total steam-
electric and combined-cycle nameplate capacity of 50 or more megawatts. •Fuel Oil No. 2 has been omitted from this table. •Oil and petroleum are usedinterchangeably in this report.•Data for 1996 are preliminary.
Source: Federal Energy Regulatory Commission, FERC Form 423, ‘‘Monthly Report of Cost and Quality of Fuels for Electric Plants.’’
Energy Information Administration/Electric Power Monthly June 1996 51
Table 40. Receipts and Average Cost of Heavy Oil Delivered to Electric Utilities by SulfurContent, Census Division, and State, February 1996 (Continued)
More than 1.0% up to 2.0% More than 2.0% up to 3.0% More than 3.0% All Purchases
Average Average Average Receipts Receipts Receipts Census Division Cost1 Cost1 Cost1
U. S. Total.................................................... 1,675 265.4 16.97 417 238.0 15.26 — — — 282.5 17.99
1 Monetary values are expressed in nominal terms.Notes: •Totals may not equal sum of components because of independent rounding. •Data are for electric generating plants with a total steam-
electric and combined-cycle nameplate capacity of 50 or more megawatts. •Fuel Oil No. 2 has been omitted from this table. •Oil and petroleum are usedinterchangeably in this report.•Data for 1996 are preliminary.
Source: Federal Energy Regulatory Commission, FERC Form 423, ‘‘Monthly Report of Cost and Quality of Fuels for Electric Plants.’’
Energy Information Administration/Electric Power Monthly June 199652
Table 41. Electric Utility Receipts of Gas by Type, Census Division, and State,February 1996
Natural Blast-Furnance1 Refinery Total Census Division
and State (thousand (billion (thousand (billion (thousand (billion (thousand (billion Mcf) Btu) Mcf) Btu) Mcf) Btu) Mcf) Btu)
U.S. Total...................................... 130,341 134,136 1,231 135 67 75 131,639 134,346
1 Includes coke oven gas.* The absolute value of the number is less than 0.5.Notes: •Totals may not equal sum of components because of independent rounding. •Data are for electric generating plants with total steam-electric
and combined-cycle nameplate capacity of 50 or more megawatts. •Data for 1996 are preliminary. •Mcf=thousand cubic feet.Source: Federal Energy Regulatory Commission, FERC Form 423, ‘‘Monthly Report of Cost and Quality of Fuels for Electric Plants.’’
Energy Information Administration/Electric Power Monthly June 1996 53
Table 42. Receipts and Average Cost of Gas Delivered to Electric Utilities by CensusDivision and State
February 1996 February 1995 Year to Date Receipts Receipts
Census Division Receipts Average Cost and State (thousand (billion (thousand (billion (billion Btu) (cents/million Btu) 1 Mcf) Btu) Mcf) Btu)
U.S. Total..................................................................... 131,639 134,346 163,665 166,679 291,155 358,903 286.7 203.6
1 Monetary values are expressed in nominal terms.* Less than 0.5.Notes: •Data for 1996 are preliminary. Data for 1995 are final. •Totals may not equal sum of components because of independent rounding. •Data
are for electric generating plants with a total steam-electric and combined-cycle nameplate capacity of 50 or more megawatts. •Includes small quantities ofcoke-oven, refinery, and blast-furnace gas. •Mcf=thousand cubic feet.
Source: Federal Energy Regulatory Commission, FERC Form 423, ‘‘Monthly Report of Cost and Quality of Fuels for Electric Plants.’’
Energy Information Administration/Electric Power Monthly June 199654
Table 43. Receipts and Average Cost of Gas Delivered to Electric Utilities by Type of Purchase,Census Division, and State, February 1996
Firm Gas Interruptible Gas Spot Gas Total Gas
Average Average Average AverageCensus Division Receipts Receipts Receipts Receipts Cost1 Cost1 Cost1 Cost1 and State
U. S. Total.......................................... 80,860 262.4 2.69 25,949 348.8 3.43 24,829 336.8 3.50 131,639 293.1 2.99
1 Monetary values are expressed in nominal terms.* = Less than 0.05.Notes: •Totals may not equal sum of components because of independent rounding. •Data are for electric generating plants with a total steam-
electric and combined-cycle nameplate capacity of 50 or more megawatts. •Data for 1996 are preliminary. •Mcf=thousand cubic feet.Source: Federal Energy Regulatory Commission, FERC Form 423, ‘‘Monthly Report of Cost and Quality of Fuels for Electric Plants.’’
Energy Information Administration/Electric Power Monthly June 1996 55
U.S. Electric Utility Sales, Revenue, and AverageRevenue per Kilowatthour
Energy Information Administration/Electric Power Monthly June 1996 57
Table 44. U.S. Electric Utility Retail Sales of Electricity by Sector, 1986 Through�March 1996(Million Kilowatthours)
Residential Commercial Industrial Other1 All Sectors
1 Includes public street and highway lighting, other sales to public authorities, sales to railroads and railways, and interdepartmental sales.2 Data are estimates. See technical notes for an explanation of the modification to the sample design as of January 1993 estimates.3 As of 1984, national retail sales values are based on data reported on the Form EIA-861, ‘‘Annual Electric Utility Report.’’4 Estimates for 1995 and prior years are final and for 1996 are preliminary.
Notes: •Totals may not equal sum of components because of independent rounding. •Estimates for retail sales and net generation may not corre-spond exactly for a particular month. Net generation data are for the calendar month. Retail sales and associated retail revenue data accumulated frombills collected for periods of time (28 to 35 days) that vary dependent upon customer class, represent consumption occurring in and outside of the calendarmonth. This, among other reasons (i.e., sales data may include purchases of electricity from nonutilities or imported electricity), is why the monthly retailsales and generation data are not directly comparable.
Sources: •Monthly Estimates: Energy Information Administration, Form EIA-826, ‘‘Monthly Electric Utility Sales and Revenue Report with State Distri-butions,’’ formerly the ‘‘Electric Utility Company Monthly Statement,’’ and predecessor forms. •Annual Series: Energy Information Administration, Form EIA-861, ‘‘Annual Electric Utility Report.’’
Energy Information Administration/Electric Power Monthly June 1996 59
Table 45. Estimated Electric Utility Retail Sales of Electricity to Ultimate Consumersby Sector, Census Division, and State, March 1996 and 1995(Million Kilowatthours)
Residential Commercial Industrial Other1 All Sectors Census Division and State 1996 1995 1996 1995 1996 1995 1996 1995 1996 1995
1 Includes public street and highway lighting, other sales to public authorities, sales to railroads and railways, and interdepartmental sales.Notes: •Estimates for 1995 are final and for 1996 are preliminary. •Totals may not equal sum of components because of independent rounding. •Esti-
mated retail sales are based on the retail sales by utilities in the sample. •See technical notes for an explanation of the modification to the sample designas of January 1993 estimates.•Estimates for sales and net generation may not correspond exactly for a particular month. Net generation data are for thecalendar month. Retail sales and associated retail revenue data accumulated from bills collected for periods of time (28 to 35 days) that vary dependentupon customer class, represent consumption occurring in and outside of the calendar month. This, among other reasons (i.e., sales data may include pur-chases of electricity from nonutilities or imported electricity), is why the monthly retail sales and generation data are not directly comparable.
Source: Energy Information Administration, Form EIA-826, ‘‘Monthly Electric Utility Sales and Revenue Report with State Distributions.’’
Energy Information Administration/Electric Power Monthly June 199660
Table 46. Estimated Coefficients of Variation for Electric Utility Retail Sales of Electricity�by Sector, Census Division and State, March 1996(Percent)
Census Division Residential Commercial Industrial Other1 All Sectors and State
U.S. Average....................................... .4 .3 .5 .7 .3
1 Includes public street and highway lighting, other sales to public authorities, sales to railroads and railways, and interdepartmental sales.Notes: •For an explanation of coefficients of variation, see the technical notes. •It should be noted such things as large changes in retail sales, re-
classification of retail sales, or changes in billing procedures can contribute to unusually high coefficient of variations. •Estimates for 1996 are preliminary.Sources: Energy Information Administration, Form EIA-826, ‘‘Monthly Electric Utility Sales and Revenue Report with State Distributions.’’
Energy Information Administration/Electric Power Monthly June 1996 61
Table 47. Estimated Electric Utility Retail Sales of Electricity to Ultimate Consumersby Sector, Census Division, and State, January Through March 1996 and 1995(Million Kilowatthours)
Residential Commercial Industrial Other1 All Sectors Census Division and State 1996 1995 1996 1995 1996 1995 1996 1995 1996 1995
1 Includes public street and highway lighting, other sales to public authorities, sales to railroads and railways, and interdepartmental sales.Notes: •Estimates for 1995 are final and for 1996 are preliminary. •Totals may not equal sum of components because of independent rounding. •Esti-
mated retail sales and associated retail revenue are based on retail sales by the utilities in the sample. •See technical notes for an explanation of themodification to the sample design as of January 1993 estimates.
Source: Energy Information Administration, Form EIA-826, ‘‘Monthly Electric Utility Sales and Revenue Report with State Distributions.’’
Energy Information Administration/Electric Power Monthly June 199662
Table 48. Revenue from U.S. Electric Utility Retail Sales of Electricity to UltimateConsumers by Sector, 1986 Through March 1996(Million Dollars)
Residential Commercial Industrial Other1 All Sectors
Series2 Series Series2 Series Series2 Series Series2 Series Series2 Series
1986 .................................. NA 60,773 NA 45,386 NA 40,982 NA 5,412 NA 152,5531987 .................................. NA 63,318 NA 46,787 NA 40,949 NA 5,479 NA 156,5321988 .................................. NA 66,790 NA 49,224 NA 42,145 NA 5,551 NA 163,7101989 .................................. NA 69,240 NA 52,228 NA 43,719 NA 5,609 NA 170,7971990 .................................. NA 72,378 NA 55,117 NA 44,857 NA 5,891 NA 178,2431991.................................. 77,142 76,828 57,471 57,655 45,803 45,737 6,207 6,138 186,624 186,3591992.................................. 76,907 76,848 58,273 58,343 46,770 46,993 6,260 6,296 188,209 188,4801993.................................. 82,900 82,814 61,030 61,521 47,828 47,357 6,587 6,528 198,345 198,2201994 3
1 Includes public street and highway lighting, other sales to public authorities, sales to railroads and railways, and interdepartmental sales.2 Data are estimates. See technical notes for an explanation of the modification to the sample design as of January 1993 estimates.3 Estimates for 1995 and prior years are final and for 1996 estimates are preliminary. For further information, see the technical notes.
NA=Data not available.Notes: •Totals may not equal sum of components because of independent rounding. •Monetary values are expressed in nominal terms. Retail reve-
nue does not include taxes, such as sales and excise taxes, that are assessed on the consumer and collected through the utility. •Estimated retail salesand associated retail revenue are based on retail sales by the utilities in the sample.
Sources: •Monthly Estimates: Energy Information Administration, Form EIA-826, ‘‘Monthly Electric Utility Sales and Revenue Report with State Distri-butions,’’ formerly the ‘‘Electric Utility Company Monthly Statement,’’ and predecessor forms. •Annual Series: Energy Information Administration, Form EIA-861, ‘‘Annual Electric Utility Report.’’
Energy Information Administration/Electric Power Monthly June 1996 63
Table 49. Estimated Revenue from Electric Utility Retail Sales of Electricity to UltimateConsumers by Sector, Census Division, and State, March 1996 and 1995(Million Dollars)
Residential Commercial Industrial Other1 All Sectors Census Division and State 1996 1995 1996 1995 1996 1995 1996 1995 1996 1995
1 Includes public street and highway lighting, other sales to public authorities, sales to railroads and railways, and interdepartmental sales.* Less than 0.5.
Notes: •Estimates for 1995 are final and for 1996 are preliminary. •Totals may not equal sum of components because of independent rounding.•Monetary values are expressed in nominal terms. Retail revenue does not include taxes, such as sales and excise taxes, that are assessed on the con-sumer and collected through the utility. •Estimated retail sales and associated retail revenue are based on retail sales by the utilities in the sample. •Seetechnical notes for an explanation of the modification to the sample design as of January 1993 estimates.
Source: Energy Information Administration, Form EIA-826, ‘‘Monthly Electric Utility Sales and Revenue Report with State Distributions.’’
Energy Information Administration/Electric Power Monthly June 199664
Table 50. Estimated Coefficients of Variation for Revenue from Electric Utility Retail Salesof Electricity by Sector, Census Division, and State, March 1996(Percent)
Census Division Residential Commercial Industrial Other1 All Sectors and State
U.S. Average....................................... .4 .4 .5 .7 .3
1 Includes public street and highway lighting, other sales to public authorities, sales to railroads and railways, and interdepartmental sales.Notes: •Estimates for 1996 are preliminary. •It should be noted such things as large changes in retail sales, reclassification of retail sales, or
changes in billing procedures can contribute to unusually high coefficient of variations. •For an explanation of coefficient of variation, see the technicalnotes.
Source: Energy Information Administration, Form EIA-826, ‘‘Monthly Electric Utility Sales and Revenue Report with State Distributions.’’
Energy Information Administration/Electric Power Monthly June 1996 65
Table 51. Estimated Revenue from Electric Utility Retail Sales to Ultimate Consumersby Sector, Census Division, and State, January Through March 1996 and 1995(Million Dollars)
Residential Commercial Industrial Other1 All Sectors Census Division and State 1996 1995 1996 1995 1996 1995 1996 1995 1996 1995
1 Includes public street and highway lighting, other sales to public authorities, sales to railroads and railways, and interdepartmental sales.Notes: •Estimates for 1995 are final and for 1996 are preliminary. •Totals may not equal sum of components because of independent rounding.
•Monetary values are expressed in nominal terms. Retail revenue does not include taxes, such as sales and excise taxes, that are assessed on the con-sumer and collected through the utility. •Estimated retail sales and associated retail revenue are based on retail sales by the utilities in the sample. •Seetechnical notes for an explanation of the modification to the sample design as of January 1993 estimates.
Source: Energy Information Administration, Form EIA-826, ‘‘Monthly Electric Utility Sales and Revenue Report with State Distributions.’’
Energy Information Administration/Electric Power Monthly June 199666
Table 52. U.S. Electric Utility Average Revenue per Kilowatthour by Sector, 1986�Through March 1996(Cents)
Residential Commercial Industrial Other1 All Sectors
1 Includes public street and highway lighting, other sales to public authorities, sales to railroads and railways, and interdepartmental sales.2 Data are estimates. See the technical notes for an explanation of the modification to the sample design as of January 1993 estimates.3 Estimates for 1995 and prior years are final, and 1996 are preliminary.Notes: •Monetary values are expressed in nominal terms. Retail revenue and average revenue per kilowatthour do not include taxes, such as sales
and excise taxes, that are assessed on the consumer and collected through the utility. •These estimates are calculated by dividing retail revenue by retailsales. Revenue may not correspond to retail sales for a particular month because of utility billing and accounting procedures. This could result in unchar-acteristic increases or decreases in the monthly average revenue per kilowatthour. •For an explanation of the modifications reflecting data precision, seethe technical notes.
Sources: •Monthly Estimates: Energy Information Administration, Form EIA-826, ‘‘Monthly Electric Utility Sales and Revenue Report with State Distri-butions,’’ formerly the ‘‘Electric Utility Company Monthly Statement,’’ and predecessor forms. •Annual Series: Energy Information Administration, Form EIA-861, ‘‘Annual Electric Utility Report.’’
Energy Information Administration/Electric Power Monthly June 1996 67
Table 53. Estimated Electric Utility Average Revenue per Kilowatthour by Sector,Census Division, and State, March 1996 and 1995(Cents)
Residential Commercial Industrial Other1 All Sectors Census Division and State 1996 1995 1996 1995 1996 1995 1996 1995 1996 1995
1 Includes public street and highway lighting, other sales to public authorities, sales to railroads and railways, and interdepartmental sales.Notes: •Estimates for 1995 are final and for 1996 are preliminary. •Monetary values are expressed in nominal terms. Retail revenue and retail aver-
age revenue per kilowatthour do not include taxes, such as sales and excise taxes, that are assessed on the consumer and collected through the utility.•These estimates are calculated by dividing retail revenue by retail sales. Revenue may not correspond to retail sales for a particular month because of util-ity billing and accounting procedures. This could result in uncharacteristic increases or decreases in the monthly average revenue per kilowatthour. •Seetechnical notes for an explanation of modifications to 1) the sample design as of January 1993 estimates and 2) reflecting data precision.
Source: Energy Information Administration, Form EIA-826, ‘‘Monthly Electric Utility Sales and Revenue Report with State Distributions.’’
Energy Information Administration/Electric Power Monthly June 199668
Table 54. Estimated Coefficients of Variation for Electric Utility Average Revenueper Kilowatthour by Sector, Census Division and State, March 1996(Percent)
Census Division Residential Commercial Industrial Other1 All Sectors and State
U.S. Average....................................... .3 .4 .4 .5 .3
1 Includes public street and highway lighting, other sales to public authorities, sales to railroads and railways, and interdepartmental sales.Notes: •Estimates for 1996 are preliminary. •It should be noted such things as large changes in retail sales, reclassification of retail sales, or
changes in billing procedures can contribute to unusually high coefficient of variations. •For an explanation of coefficient of variation, see the technicalnotes.
Source: Energy Information Administration, Form EIA-826, ‘‘Monthly Electric Utility Sales and Revenue Report with State Distributions.’’
Energy Information Administration/Electric Power Monthly June 1996 69
Table 55. Estimated Electric Utility Average Revenue per Kilowatthour by Sector,Census Division, and State, January Through March 1996 and 1995(Cents)
Residential Commercial Industrial Other1 All Sectors Census Division and State 1996 1995 1996 1995 1996 1995 1996 1995 1996 1995
1 Includes public street and highway lighting, other sales to public authorities, sales to railroads and railways, and interdepartmental sales.Notes: •For an explanation of coefficients of variation, see the technical notes. •It should be noted such things as large changes in retail sales, re-
classification of retail sales, or changes in billing procedures can contribute to unusually high coefficient of variations. •Estimates for 1995 are final and for1996 are preliminary.
Sources: Energy Information Administration, Form EIA-826, ‘‘Monthly Electric Utility Sales and Revenue Report with State Distributions.’’
Energy Information Administration/Electric Power Monthly June 199670
Monthly Plant Aggregates: U.S. Electric Utility NetGeneration, Fuel Consumption, and Fuel Stocks
Energy Information Administration/Electric Power Monthly June 1996 71
Table 56. U.S. Electric Utility Net Generation, Fuel Consumption, and Fuel Stocks by Company�and Plant, February 1996
1 Other energy sources include geothermal, solar, wood, wind, and waste.* Less than 0.05.Notes: •Totals may not equal sum of components because of independent rounding. •Net generation for jointly owned units is reported by
the operator. •Negative generation denotes that electric power consumed for plant use exceeds gross generation. •Station losses include energyused for pumped storage. •Generation is included for plants in test status. •Nuclear generation is included for those plants with an operatinglicense issued authorizing fuel loading/low power testing prior to receipt of full power amendment. •Central storage is a common area for fuel stocksnot assigned to specific plants. •Mcf=thousand cubic feet and bbls=barrels. •Data for 1995 are final. •Holding Companies are: AEP is AmericanElectric Power, APS is Allegheny Power System, ACE is Atlantic City Electric, CSW is Central & South West Corporation, CES is CommonwealthEnergy System, DMV is Delmarva, EU is Eastern Utilities Associates Company, GPS is General Public Utilities, MSU is Middle South Utilities, NEESis New England Electric System, NU is Northeast Utilities, SC is Southern Company, TU is Texas Utilities.
Source: Energy Information Administration, Form EIA-759, ‘‘Monthly Power Plant Report.’’
Energy Information Administration/Electric Power Monthly June 1996 117
Monthly Plant Aggregates: U.S. Electric UtilityReceipts, Cost, and Quality of Fossil Fuels
Energy Information Administration/Electric Power Monthly June 1996 119
Table 57. Receipts, Average Cost, and Quality of Fossil Fuels Delivered to U.S. Electric�Utilities by Company and Plant, February 1996
Coal Petroleum1 Gas % of Total Btu
Average Average Average Receipts Receipts Receipts Cost3 Cost3 Cost3Utility (Holding Company) Avg. Avg. Pe- Plant (State) Sul- Sul- (Cents (Cents (Cents Coal tro- Gas ($ per fur fur (1,000 per (1,000 per $ per (1,000 per $ per leum short % % tons) 106 bbls) 106 bbl Mcf) 106 Mcf ton) Btu) Btu) Btu)
Energy Information Administration/Electric Power Monthly June 1996 121
Table 57. Receipts, Average Cost, and Quality of Fossil Fuels Delivered to U.S. ElectricUtilities by Company and Plant, February 1996 (Continued)
Coal Petroleum1 Gas % of Total Btu
Average Average Average Receipts Receipts Receipts Cost3 Cost3 Cost3Utility (Holding Company) Avg. Avg. Pe- Plant (State) Sul- Sul- (Cents (Cents (Cents Coal tro- Gas ($ per fur fur (1,000 per (1,000 per $ per (1,000 per $ per leum short % % tons) 106 bbls) 106 bbl Mcf) 106 Mcf ton) Btu) Btu) Btu)
Energy Information Administration/Electric Power Monthly June 1996122
Table 57. Receipts, Average Cost, and Quality of Fossil Fuels Delivered to U.S. ElectricUtilities by Company and Plant, February 1996 (Continued)
Coal Petroleum1 Gas % of Total Btu
Average Average Average Receipts Receipts Receipts Cost3 Cost3 Cost3Utility (Holding Company) Avg. Avg. Pe- Plant (State) Sul- Sul- (Cents (Cents (Cents Coal tro- Gas ($ per fur fur (1,000 per (1,000 per $ per (1,000 per $ per leum short % % tons) 106 bbls) 106 bbl Mcf) 106 Mcf ton) Btu) Btu) Btu)
Energy Information Administration/Electric Power Monthly June 1996 123
Table 57. Receipts, Average Cost, and Quality of Fossil Fuels Delivered to U.S. ElectricUtilities by Company and Plant, February 1996 (Continued)
Coal Petroleum1 Gas % of Total Btu
Average Average Average Receipts Receipts Receipts Cost3 Cost3 Cost3Utility (Holding Company) Avg. Avg. Pe- Plant (State) Sul- Sul- (Cents (Cents (Cents Coal tro- Gas ($ per fur fur (1,000 per (1,000 per $ per (1,000 per $ per leum short % % tons) 106 bbls) 106 bbl Mcf) 106 Mcf ton) Btu) Btu) Btu)
Energy Information Administration/Electric Power Monthly June 1996124
Table 57. Receipts, Average Cost, and Quality of Fossil Fuels Delivered to U.S. ElectricUtilities by Company and Plant, February 1996 (Continued)
Coal Petroleum1 Gas % of Total Btu
Average Average Average Receipts Receipts Receipts Cost3 Cost3 Cost3Utility (Holding Company) Avg. Avg. Pe- Plant (State) Sul- Sul- (Cents (Cents (Cents Coal tro- Gas ($ per fur fur (1,000 per (1,000 per $ per (1,000 per $ per leum short % % tons) 106 bbls) 106 bbl Mcf) 106 Mcf ton) Btu) Btu) Btu)
Energy Information Administration/Electric Power Monthly June 1996 125
Table 57. Receipts, Average Cost, and Quality of Fossil Fuels Delivered to U.S. ElectricUtilities by Company and Plant, February 1996 (Continued)
Coal Petroleum1 Gas % of Total Btu
Average Average Average Receipts Receipts Receipts Cost3 Cost3 Cost3Utility (Holding Company) Avg. Avg. Pe- Plant (State) Sul- Sul- (Cents (Cents (Cents Coal tro- Gas ($ per fur fur (1,000 per (1,000 per $ per (1,000 per $ per leum short % % tons) 106 bbls) 106 bbl Mcf) 106 Mcf ton) Btu) Btu) Btu)
Energy Information Administration/Electric Power Monthly June 1996126
Table 57. Receipts, Average Cost, and Quality of Fossil Fuels Delivered to U.S. ElectricUtilities by Company and Plant, February 1996 (Continued)
Coal Petroleum1 Gas % of Total Btu
Average Average Average Receipts Receipts Receipts Cost3 Cost3 Cost3Utility (Holding Company) Avg. Avg. Pe- Plant (State) Sul- Sul- (Cents (Cents (Cents Coal tro- Gas ($ per fur fur (1,000 per (1,000 per $ per (1,000 per $ per leum short % % tons) 106 bbls) 106 bbl Mcf) 106 Mcf ton) Btu) Btu) Btu)
Energy Information Administration/Electric Power Monthly June 1996 127
Table 57. Receipts, Average Cost, and Quality of Fossil Fuels Delivered to U.S. ElectricUtilities by Company and Plant, February 1996 (Continued)
Coal Petroleum1 Gas % of Total Btu
Average Average Average Receipts Receipts Receipts Cost3 Cost3 Cost3Utility (Holding Company) Avg. Avg. Pe- Plant (State) Sul- Sul- (Cents (Cents (Cents Coal tro- Gas ($ per fur fur (1,000 per (1,000 per $ per (1,000 per $ per leum short % % tons) 106 bbls) 106 bbl Mcf) 106 Mcf ton) Btu) Btu) Btu)
Energy Information Administration/Electric Power Monthly June 1996128
Table 57. Receipts, Average Cost, and Quality of Fossil Fuels Delivered to U.S. ElectricUtilities by Company and Plant, February 1996 (Continued)
Coal Petroleum1 Gas % of Total Btu
Average Average Average Receipts Receipts Receipts Cost3 Cost3 Cost3Utility (Holding Company) Avg. Avg. Pe- Plant (State) Sul- Sul- (Cents (Cents (Cents Coal tro- Gas ($ per fur fur (1,000 per (1,000 per $ per (1,000 per $ per leum short % % tons) 106 bbls) 106 bbl Mcf) 106 Mcf ton) Btu) Btu) Btu)
Energy Information Administration/Electric Power Monthly June 1996 129
Table 57. Receipts, Average Cost, and Quality of Fossil Fuels Delivered to U.S. ElectricUtilities by Company and Plant, February 1996 (Continued)
Coal Petroleum1 Gas % of Total Btu
Average Average Average Receipts Receipts Receipts Cost3 Cost3 Cost3Utility (Holding Company) Avg. Avg. Pe- Plant (State) Sul- Sul- (Cents (Cents (Cents Coal tro- Gas ($ per fur fur (1,000 per (1,000 per $ per (1,000 per $ per leum short % % tons) 106 bbls) 106 bbl Mcf) 106 Mcf ton) Btu) Btu) Btu)
Energy Information Administration/Electric Power Monthly June 1996130
Table 57. Receipts, Average Cost, and Quality of Fossil Fuels Delivered to U.S. ElectricUtilities by Company and Plant, February 1996 (Continued)
Coal Petroleum1 Gas % of Total Btu
Average Average Average Receipts Receipts Receipts Cost3 Cost3 Cost3Utility (Holding Company) Avg. Avg. Pe- Plant (State) Sul- Sul- (Cents (Cents (Cents Coal tro- Gas ($ per fur fur (1,000 per (1,000 per $ per (1,000 per $ per leum short % % tons) 106 bbls) 106 bbl Mcf) 106 Mcf ton) Btu) Btu) Btu)
Energy Information Administration/Electric Power Monthly June 1996 131
Table 57. Receipts, Average Cost, and Quality of Fossil Fuels Delivered to U.S. ElectricUtilities by Company and Plant, February 1996 (Continued)
Coal Petroleum1 Gas % of Total Btu
Average Average Average Receipts Receipts Receipts Cost3 Cost3 Cost3Utility (Holding Company) Avg. Avg. Pe- Plant (State) Sul- Sul- (Cents (Cents (Cents Coal tro- Gas ($ per fur fur (1,000 per (1,000 per $ per (1,000 per $ per leum short % % tons) 106 bbls) 106 bbl Mcf) 106 Mcf ton) Btu) Btu) Btu)
Energy Information Administration/Electric Power Monthly June 1996132
Table 57. Receipts, Average Cost, and Quality of Fossil Fuels Delivered to U.S. ElectricUtilities by Company and Plant, February 1996 (Continued)
Coal Petroleum1 Gas % of Total Btu
Average Average Average Receipts Receipts Receipts Cost3 Cost3 Cost3Utility (Holding Company) Avg. Avg. Pe- Plant (State) Sul- Sul- (Cents (Cents (Cents Coal tro- Gas ($ per fur fur (1,000 per (1,000 per $ per (1,000 per $ per leum short % % tons) 106 bbls) 106 bbl Mcf) 106 Mcf ton) Btu) Btu) Btu)
Energy Information Administration/Electric Power Monthly June 1996 133
Table 57. Receipts, Average Cost, and Quality of Fossil Fuels Delivered to U.S. ElectricUtilities by Company and Plant, February 1996 (Continued)
Coal Petroleum1 Gas % of Total Btu
Average Average Average Receipts Receipts Receipts Cost3 Cost3 Cost3Utility (Holding Company) Avg. Avg. Pe- Plant (State) Sul- Sul- (Cents (Cents (Cents Coal tro- Gas ($ per fur fur (1,000 per (1,000 per $ per (1,000 per $ per leum short % % tons) 106 bbls) 106 bbl Mcf) 106 Mcf ton) Btu) Btu) Btu)
Energy Information Administration/Electric Power Monthly June 1996134
Table 57. Receipts, Average Cost, and Quality of Fossil Fuels Delivered to U.S. ElectricUtilities by Company and Plant, February 1996 (Continued)
Coal Petroleum1 Gas % of Total Btu
Average Average Average Receipts Receipts Receipts Cost3 Cost3 Cost3Utility (Holding Company) Avg. Avg. Pe- Plant (State) Sul- Sul- (Cents (Cents (Cents Coal tro- Gas ($ per fur fur (1,000 per (1,000 per $ per (1,000 per $ per leum short % % tons) 106 bbls) 106 bbl Mcf) 106 Mcf ton) Btu) Btu) Btu)
Energy Information Administration/Electric Power Monthly June 1996 135
Table 57. Receipts, Average Cost, and Quality of Fossil Fuels Delivered to U.S. ElectricUtilities by Company and Plant, February 1996 (Continued)
Coal Petroleum1 Gas % of Total Btu
Average Average Average Receipts Receipts Receipts Cost3 Cost3 Cost3Utility (Holding Company) Avg. Avg. Pe- Plant (State) Sul- Sul- (Cents (Cents (Cents Coal tro- Gas ($ per fur fur (1,000 per (1,000 per $ per (1,000 per $ per leum short % % tons) 106 bbls) 106 bbl Mcf) 106 Mcf ton) Btu) Btu) Btu)
1 The February 1996 petroleum coke receipts were 95,584 short tons and the cost was 72.6 cents per million Btu.2 Monetary values are expressed in nominal terms.3 The entry includes at least one delivery at a price of 1,000 cents per million Btu or greater. High price is frequently caused when fixed costs are
averaged into a small quantity.* Less than 0.05.Notes: •Totals may not equal sum of components because of independent rounding. •Data are for electric generating plants with a total steam-
electric and combined-cycle nameplate capacity of 50 or more megawatts. •Data for 1996 are preliminary. •Mcf=thousand cubic feet andbbl=barrel.•Holding Companies are: AEP is American Electric Power, APS is Allegheny Power System, ACE is Atlantic City Electric, CSW is Central &South West Corporation, CES is Commonwealth Energy System, DMV is Delmarva, EU is Eastern Utilities Associates Company, GPS is General PublicUtilities, MSU is Middle South Utilities, NEES is New England Electric System, NU is Northeast Utilities, SC is Southern Company, TU is Texas Utilities.
Source: Federal Energy Regulatory Commission, FERC Form 423, ‘‘Monthly Report of Cost and Quality of Fuels for Electric Plants.’’
Energy Information Administration/Electric Power Monthly June 1996 137
Appendix A
Bibliography
ArticlesFeature articles on electric power energy-related subjects are frequently included in this publication. The fol-lowing articles and special focus items have appeared in previous issues.
June 1990. . . . . . . . . . . . . . Petroleum Fuel-Switching Capability in the Electric Utility Industry
April 1991 . . . . . . . . . . . . . U.S. Wholesale Electricity Transactions
April 1992 . . . . . . . . . . . . . Electric Utility Demand-Side Management
April 1992 . . . . . . . . . . . . . Nonutility Power Producers
August 1992. . . . . . . . . . . . Performance Optimization and Repowering of Generating Units
February 1993. . . . . . . . . . .Improvement in Nuclear Power Plant Capacity Factors
October 1993 . . . . . . . . . . . Municipal Solid Waste in the U.S. Energy Supply
November 1993. . . . . . . . . .Electric Utility Demand-Side Management and Regulatory Effects
November 1994. . . . . . . . . The Impact of Flow Control and Tax Reform on Ownership and Growth in the U.S.Waste-to-Energy Industry
July 1995. . . . . . . . . . . . . . Nonutility Electric Generation: Industrial Power Production
August 1995. . . . . . . . . . . . Steam Generator Degradation and Its Impact on Continued Operation of PressurizedWater Reactors in the United States
September 1995 . . . . . . . . . New Sources of Nuclear Fuel
November 1995. . . . . . . . . . Relicensing and Environmental Issues Affecting Hydropower
For additional information or questions regarding availability of article reprints, please contact the NationalEnergy Information Center, at (202)586-8800 or by FAX at (202)586-0727.
Energy Information Administration/Electric Power Monthly June 1996140
Bibliography
1. Energy Information Administration, Office of Coal, Nuclear, Electric and Alternate Fuels,Inventory of PowerPlants in the United States,DOE/EIA-0095(93) (Washington DC, 1994), pp. 247-248.
2. Energy Information Administration, Office of Statistical Standards,An Assessment of the Quality of Selected EIAData Series: Electric Power Data,DOE/EIA-0292(89) (Washington DC, 1989).
3. Kott, P.S., "Nonresponse in a Periodic Sample Survey,"Journal of Business and Economic Statistics,April 1987,Volume 5, Number 2, pp. 287-293.
4. Knaub, J.R., Jr., "Ratio Estimation and Approximate Optimum Stratification in Electric Power Surveys,"Pro-ceedings of the Section on Survey Research Methods,American Statistical Association, 1989, pp. 848-853.
5. Knaub, J.R., Jr., "More Model Sampling and Analyses Applied to Electric Power Data,"Proceedings of theSection on Survey Research Methods,American Statistical Association, 1992, pp. 876-881.
6. Royall, R.M. (1970), "On Finite Population Sampling Theory Under Certain Linear Regression Models,"Biometrika,57, 377-387.
7. Royall, R.M., and W.G. Cumberland (1978), "Variance Estimation in Finite Population Sampling,"Journal ofthe American Statistical Association,73, 351-358.
8. Royall, R.M., and W.G. Cumberland (1981), "An Empirical Study of the Ratio Estimator and Estimators of ItsVariance,"Journal of the American Statistical Association, 76, 66-68.
9. Knaub, J.R., Jr., "Alternative to the Iterated Reweighted Least Squares Method: Apparent Heteroscedasticity andLinear Regression Model Sampling,"Proceedings of the International Conference on Establishment Surveys,American Statistical Association, 1993, pp. 520-525.
10. Rao, P.S.R.S. (1992), Unpublished notes on model covariance.
11. Hansen, M.H., Hurwitz, W.N. and Madow, W.G. (1953), "Sample Survey Methods and Theory," Volume II,Theory,pp. 56-58.
12. Knaub, J.R., Jr., "Relative Standard Error for a Ratio of Variables at an Aggregate Level Under Model Sam-pling," in Proceedings of the Section on Survey Research Methods,American Statistical Association, 1994, pp.310-312.
13. Knaub, J.R., Jr., "Weighted Multiple Regression Estimation for Survey Model Sampling," InterStat(http://interstat.stat.vt.edu), May 1996.
Energy Information Administration/Electric Power Monthly June 1996 141
Appendix B
TechnicalNotes
Appendix B
Technical Notes
Sources of Data
The Electric Power Monthly (EPM)is prepared by theCoal and Electric Data and Renewables Division,Office of Coal, Nuclear, Electric and Alternate Fuels(CNEAF), Energy Information Administration (EIA),U.S. Department of Energy. Data published in theEPM are compiled from six data sources. Four statis-tical forms are filed monthly and two forms are filedannually by electric utilities. Those forms are: theForm EIA-759, “Monthly Power Plant Report, ” theForm EIA-900, “Monthly Nonutility Sales for ResaleReport, ” the FERC Form 423, “Monthly Report ofCost and Quality of Fuels for Electric Plants, ” theForm EIA-826, “Monthly Electric Utility Sales andRevenue Report with State Distributions, ” the FormEIA-861, “Annual Electric Utility Report, ” and theForm EIA-860, “Annual Electric Generator Report. ”
Form EIA-759
The Form EIA-759 is a cutoff model sample ofapproximately 360 electric utilities drawn from theframe of all operators of electric utility plants(approximately 700 electric utilities) that generateelectric power for public use. Data will be collectedon an annual basis from the remaining operators ofelectric utility plants. The new monthly data col-lection is from all utilities with at least one plant witha nameplate capacity of 25 megawatts or more. (Note:includes all nuclear units). However, the few utilitiesthat generate electricity using renewable fuel sourcesother than hydroelectric are all included in thesample. The Form EIA-759 is used to collect monthlydata on net generation; consumption of coal, petro-leum, and natural gas; and end-of-the-month stocks ofcoal and petroleum for each plant by fuel-type combi-nation. Summary data from the Form EIA-759 are alsocontained in the Electric Power Annual (EPA),Monthly Energy Review (MER),and the AnnualEnergy Review (AER).These reports present aggregatedata estimates for electric utilities at the U.S., Censusdivision, and North American Electric ReliabilityCouncil Region (NERC) levels.
Instrument and Design History. Prior to 1936,the Bureau of the Census and the U.S. GeologicalSurvey collected, compiled, and published data on theelectric power industry. In 1936, the Federal PowerCommission (FPC) assumed all data collection andpublication responsibilities for the electric power
industry and implemented the FPC Form 4. TheFederal Power Act, Sections 311 and 312, and FPCOrder 141 define the legislative authority to collectpower production data. The Form EIA-759 replacedthe FPC Form 4 in January 1982. As of the January1996 reporting period, the Form EIA-759 waschanged to collect data from a cutoff model sample ofplants with a nameplate capacity of 25 megawatts ormore.
Data Processing. The Form EIA-759, along with areturn envelope, is mailed to respondents approxi-mately 4 working days before the end of the month.The completed forms are to be returned to the EIA bythe 10th day after the end of the reporting month.After receipt, data from the completed forms are man-ually logged in and edited before being keypunchedfor automatic data processing. An edit program checksthe data for errors not found during manual editing.The electric utilities are telephoned to obtain data incases of missing reports and to verify data whenquestions arise during editing. After all forms arereceived from the respondents, the final automatededit is submitted. Following verification of the data,text and tables of aggregated data are produced forinclusion in theEPM. Following EIA approval of theEPM, the data are made available for public use, on acost-recovery basis, through custom computer runs,data tapes, or in publications.
FERC Form 423
The Federal Energy Regulatory Commission (FERC)Form 423 is a monthly record of delivered-fuel pur-chases, submitted by approximately 230 electric utili-ties for each electric generating plant with a totalsteam-electric and combined-cycle nameplate capacityof 50 or more megawatts. Summary data from theFERC Form 423 are also contained in theEPA, MER,and theCost and Quality of Fuels for Electric UtilityPlants - Annual.These reports present aggregated dataon electric utilities at the U.S., Census division, andState levels.
Instrument and Design History. On July 7,1972, the FPC issued Order Number 453 enacting theNew Code of Federal Regulations, Section 141.61,legally creating the FPC Form 423. Originally, theform was used to collect data only on fossil-steamplants, but was amended in 1974 to include data oninternal combustion and combustion turbines. The
Energy Information Administration/Electric Power Monthly June 1996 145
FERC Form 423 replaced the FPC Form 423 inJanuary 1983. The FERC Form 423 eliminatedpeaking units, which were previously collected on theFPC Form 423. In addition, the generator nameplatecapacity threshold was changed from 25 megawatts to50 megawatts. This reduction in coverage eliminatedapproximately 50 utilities and 250 plants. All histor-ical FPC Form 423 data in this publication wererevised to reflect the new generator nameplatecapacity threshold of 50 or more megawatts reportedon the FERC Form 423. In January 1991, the col-lection of data on the FERC Form 423 was extendedto include combined-cycle units. Historical data havenot been revised to include these units. Starting withthe January 1993 data, the FERC began to collect thedata directly from the respondents.
Data Processing. The FERC processes the datathrough edits and each month provides the EIA with adiskette containing the data. The EIA reviews the datafor accuracy. Beginning with May 1994 data, an addi-tional quality check began in which coal data arecompared with data prepared by Resource Data Inter-national, Inc., of Boulder, Colorado. Following verifi-cation of the data, text and tables of aggregated dataare produced for inclusion in theEPM. After the EPMis cleared by the EIA, the data become available forpublic use, on a cost-recovery basis, through customcomputer runs or in publications.
Form EIA-826
The Form EIA-826 is a monthly collection of datafrom approximately 260 of the largest primarilyinvestor-owned and publicly owned electric utilities.A model is then applied to estimate for the entire uni-verse of U.S. electric utilities. The electric powersales data are used by the Federal Reserve Board intheir economic analyses.
Instrument and Design History. The collectionof electric power sales, revenue, and income databegan in the early 1940's and was established as FPCForm 5 by FPC Order 141 in 1947. In 1980, the reportwas revised with only selected income itemsremaining and became the FERC Form 5. The FormEIA-826 replaced the FERC Form 5 in January 1983.In January 1987, the Form EIA-826 was changed tothe "Monthly Electric Utility Sales and RevenueReport with State Distributions." It was formerlytitled, "Electric Utility Company Monthly Statement."The Form EIA-826 was revised in January 1990, andsome data elements were eliminated. In 1993, EIA forthe first time used a model sample for the FormEIA-826. A stratified-random sample, employing aux-iliary data, was used for each of the 4 previous years.(See previous issues of this publication, and (Knaub,12) for details.) The current sample for the FormEIA-826, which was designed to obtain estimates of
electricity sales and revenue per kilowatthour at theState level by end-use sector, was chosen to be ineffect for the January 1993 data.
Frame. The frame for the Form EIA-826 was ori-ginally based on the 1989 submission of the FormEIA-861 (Section 1.4), which consisted of approxi-mately 3,250 electric utilities selling retail and/orsales for resale. Note that for the Form EIA-826, theEIA is only interested in retail sales. Updates havebeen made to the frame to reflect mergers that affectdata processing. Some electric utilities serve in morethan one State. Thus, the State-service area is actuallythe sampling unit. For each State served by eachutility, there is a utility State-part, or "State-servicearea." This approach allows for an explicit calculationof estimates for sales, revenue, and revenue perkilowatthour by end-use sector (residential, commer-cial, industrial and other) at State, Census division,and the U.S. level. Regressor data came from theForm EIA-861. (Note that estimates at the "Statelevel" are for sales for the entire State, and similarlyfor "Census division" and "U.S." levels.)
The preponderance of electric power sales to ultimateconsumers in each State are made by a few large utili-ties. Ranking of electric utilities by retail sales on aState-by-State basis revealed a consistent pattern ofdominance by a few electric utilities in nearly all 50States and the District of Columbia. These dominantelectric utilities were selected as a model sample.These electric utilities constitute about 8 percent ofthe population of U.S. electric utilities, but providethree-quarters of the total U.S. retail electricity sales.The procedures used to derive electricity sales,revenue, revenue per kilowatthour, and associatedcoefficient of variation (CV) estimates are provided inthe Form EIA-826 subsection of the Formulas DataSection. See (Knaub, 12) for a study of CV estimatesfor this survey.
Data Processing. The forms are mailed each yearto the electric utilities with State-parts selected in thesample. The completed form is to be returned to theEIA by the last calendar day of the month followingthe reporting month. Nonrespondents are telephonedto obtain the data. Imputation, in model sampling, isan implicit part of the estimation. That is, data thatare not available, either because it was not part of thesample or because the data are missing, are estimatedusing a model. The data are edited and entered intothe computer where additional checks are completed.After all forms have been received from the respond-ents, the final automated edit is submitted. Followingverification, tables and text of the aggregated data areproduced for inclusion in theEPM. After the EPMreceives clearance from the EIA, the data are madeavailable for public use through custom computerruns, data tapes, or in publications (EPA, AER) on acost-recovery basis.
Energy Information Administration/Electric Power Monthly June 1996146
Form EIA-900
The Form EIA-900, "Monthly Nonutility Sales forResale Report," is a cutoff model sample drawn fromthe frame for the Form EIA-867, "Annual NonutilityPower Producer Report." Members of the FormEIA-867 frame with nameplate capacity greater thanor equal to 50 megawatts constitute the sample for theForm EIA-900. Unlike the Form EIA-867 whichgathers data on a number of topics, however, the FormEIA-900 currently is used to collect data on only oneelement, sales by nonutilities for resale through thepower grid.
Instrument and Design History. The FormEIA-900 was implemented to collect monthly data,starting with January 1996. The reason for its incep-tion was to fill, in part, a "data gap" that existed on amonthly basis when comparing utility sales to endusers (from the Form EIA-826) with utility generation(from the Form EIA-759). This data gap occurredbecause utility sales data include electricity purchasedfrom nonutilities and because of other factors such astransmission losses and imports/exports. In light ofsampling and nonsampling error, a more completedescription of events may be gleaned by includingresults based on the Form EIA-900.
Data Processing. The Form EIA-900 is mailed toall operating Form EIA-867 respondent facilities withmore than 50 megawatts of total operating capacity.In 1996, there were approximately 380 respondentsfor the Form EIA-900. Data submission is allowed byInternet e-mail, postal mail, telephone or facsimile(FAX) transmission. In the near future, the EIA plansto allow touchtone data entry. At first submission, thenumber for the one datum element collected is com-pared to a previously submitted number, through theuse of an interactive edit. Later, batch edits areapplied. One edit is used to compare total sales, gen-eration, line losses and imports/exports to determine ifthe results are reasonable. Another edit is applied onan individual, annual basis, to compare 12 monthtotals for the Form EIA-900 submissions to the corre-sponding Form EIA-867 submissions.
Form EIA-861
The Form EIA-861 is a mandatory census of electricutilities in the United States. The survey is used tocollect information on power production and salesdata from approximately 3,250 electric utilities. Thedata collected are used to maintain and update theEIA's electric utility frame data base. This data basesupports queries from the Executive Branch, Con-gress, other public agencies, and the general public.Summary data from the Form EIA-861 are also con-tained in theElectric Sales and Revenue;the ElectricPower Annual; the Financial Statistics of SelectedPublicly Owned Electric Utilities;the Financial Sta-tistics of Selected Investor-Owned Electric Utilities;the AER; and, theAnnual Outlook for U.S. ElectricPower. These reports present aggregate totals for
electric utilities on a national level, by State, and byownership type.
Instrument and Design History. The FormEIA-861 was implemented in January 1985 to collectdata as of year-end 1984. The Federal AdministrationAct of 1974 (Public Law 93-275) defines the legisla-tive authority to collect these data.
Data Processing. The Form EIA-861 is mailed tothe respondents in February of each year to collectdata as of the end of the preceding calendar year. Thedata are manually edited before being entered into theinteractive on-line system. Internal edit checks areperformed to verify that current data total across andbetween schedules, and are comparable to datareported the previous year. Edit checks are also per-formed to compare data reported on the FormEIA-861 and similar data reported on the FormsEIA-826; EIA-412, "Annual Report of Public ElectricUtilities;" and FERC Form 1, "Annual Report ofMajor Electric Utilities, Licensees, and Others."Respondents are telephoned to obtain clarification ofreported data and to obtain missing data.
Form EIA-860
The Form EIA-860 is a mandatory census of electricutilities in the United States and Puerto Rico thatoperate power plants or plan to operate a power plantwithin 10 years of the reporting year. The survey isused to collect data on electric utilities' existingpower plants and their 10-year plans for constructingnew plants, generating unit additions, modifications,and retirements in existing plants. Data on the surveyare collected at the generating unit level. These dataare then aggregated to provide totals by energy source(coal, petroleum, gas, water, nuclear, other) andgeographic area (State, NERC region, Federal region,Census division). Additionally, at the national level,data are aggregated to provide totals by prime mover.Data from the Form EIA-860 are also summarized inthe Inventory of Power Plants in the United Statesandthe EPA, and as input to publications (AER) andstudies by other offices in the Department of Energy.
Instrument and Design History. The FormEIA-860 was implemented in January 1985 to collectdata as of year-end 1984. The Federal Energy Admin-istration Act of 1974 (Public Law 93-275) defines thelegislative authority to collect these data.
Data Processing. The Form EIA-860 is mailed toapproximately 900 respondents in December to collectdata as of the end of the preceding calendar year. Datafor each respondent are preprinted from the applicabledata base. Respondents are instructed to verify all pre-printed data and to supply missing data. The data aremanually edited before being keypunched for auto-matic data processing. Computer programs containingadditional edit checks are run. Respondents are tele-phoned to obtain correction or clarification ofreported data and to obtain missing data, as a result ofthe manual and automatic editing process.
Energy Information Administration/Electric Power Monthly June 1996 147
Quality of Data
The CNEAF office is responsible for routine dataimprovement and quality assurance activities. Alloperations in this office are done in accordance withformal standards established by the EIA. These stand-ards are the measuring rod necessary for quality sta-tistics. Data improvement efforts include verificationof data-keyed input by automatic computerizedmethods, editing by subject matter specialists, andfollow-up on nonrespondents. The CNEAF office sup-ports the quality assurance efforts of the data collec-tors by providing advisory reviews of the structure ofinformation requirements, and of proposed designs fornew and revised data collection forms and systems.Once implemented, the actual performance of workingdata collection systems is also validated. Computer-ized respondent data files are checked to identifythose who fail to respond to the survey. By law, non-respondents may be fined or otherwise penalized fornot filing a mandatory EIA data form. Beforeinvoking the law, the EIA tries to obtain the requiredinformation by encouraging cooperation of nonre-spondents.
Completed forms received by the CNEAF office aresorted, screened for completeness of reported infor-mation, and keyed onto computer tapes for storageand transfer to random access data bases for computerprocessing. The information coded on the computertapes is manually spot-checked against the forms tocertify accuracy of the tapes. To ensure the qualitystandards established by the EIA, formulas that usethe past history of data values in the data base havebeen designed and implemented to check data inputfor errors automatically. Data values that fall outsidethe ranges prescribed in the formulas are verified bytelephoning respondents to resolve any discrepancies.
Conceptual problems affecting the quality of data arediscussed in the report,An Assessment of the Qualityof Selected EIA Data Series: Electric Power Data.This report is published by the Energy InformationAdministration (Office of Statistical Standards). Seeitem 2 in Appendix A.
Data Precision
Monthly sample survey data have both sampling andnonsampling errors. Sampling errors may be expectedsince all data are not collected and, therefore, must bemathematically estimated. (Note that the annual seriesfor a monthly sample is not subject to sampling errorbecause it is a census). Nonsampling errors are theresult of incorrect allocation of data (for example,transcriptions or misclassifications) and can be diffi-cult to control and estimate. A study of coefficients ofvariance and data revisions was conducted so that theappropriate levels of precision, based on the accuracyand completeness of the data from which the estimatesare derived, is provided in this report for averagerevenue per kilowatthour of electricity sold. It wasjudged that three significant digits are justified foraverage revenue per kilowatthour of electricity sold at
the U.S. level except for monthly data prior to 1990where two significant digits are more appropriate.
Data Editing System
Data from the form surveys are edited on a monthlybasis using automated systems. The edit includes bothdeterministic checks, in which records are checked forthe presence of required fields and their validity; andstatistical checks, in which estimation techniques areused to validate data according to their behavior in thepast and in comparison to other current fields. Whenall data have passed the edit process, the systembuilds monthly master files, which are used as inputto theEPM.
Confidentiality of the Data
In general, the data collected on the forms used forinput to this report are not confidential. However,data from the Form EIA-900, “Monthly Sales forResale,” are considered confidential and must adhereto EIA's “Policy on the Disclosure of IndividuallyIdentifiable Energy Information in the Possession ofthe EIA” (45Federal Register59812 (1980)).
Formulas/Methodologies
The following formula is used to calculate percentdifferences.
where x(t1) and x(t2) denote the quantity at year t1 andsubsequent year t2.
Form EIA-826. The Form EIA-826 data are col-lected at the utility level by sector and State. When autility has sales in more than one State, the State datathat may be required are dependent upon the sampleselection that was done for each State independently.Data from the Form EIA-826 are used to determineestimates by sector at the State, Census division, andnational level for the entire corresponding State,Census division, or national category. Form EIA-861data were used as the frame from which the samplewas selected, and also as regressor data.
The sample consists of approximately 260 electricutilities. This includes a somewhat larger number ofState-service areas for electric utilities. Estimationprocedures include imputation to account for nonre-sponse. Nonsampling error must also be considered.The nonsampling error is not estimated directly,although attempts are made to minimize it.
State-level sales and revenue estimates are calculated.Also, a ratio estimation procedure is used for esti-mation of revenue per kilowatthour at the State level.These estimates are accumulated separately toproduce the Census division and U.S. level estimates.
Energy Information Administration/Electric Power Monthly June 1996148
The coefficient of variation (CV) statistic, usuallygiven as a percent, describes the magnitude of sam-pling error that might reasonably be incurred. TheCV, sometimes referred to as the relative standarderror, is the square root of the estimated variance,divided by the variable of interest. The variable ofinterest may be the ratio of two variables (forexample, revenue per kilowatthour), or a single vari-able (for example, sales).
The sampling error may be less than the nonsamplingerror. Nonsampling errors may be attributed to manysources, including the response errors, definitionaldifficulties, differences in the interpretation ofquestions, mistakes in recording or coding dataobtained, and other errors of collection, response, orcoverage. These nonsampling errors also occur incomplete censuses. In a complete census, this problemmay become unmanageable. One indicator of the mag-nitude of possible nonsampling error may be gleanedby examining the history of revisions to data for asurvey (Table B2).
Coefficients of variation are indicators of error due tosampling. (CVs do not account for nonsamplingerrors, such as errors of misclassification or trans-posed digits. However, estimates of CVs, although notdesigned to measure nonsampling error, are affectedby them). In fact, large CV estimates found in prelim-inary work with these data have often indicated non-sampling errors, which were then identified andcorrected. Using the Central Limit Theorem, whichapplies to sums and means such as are applicablehere, there is approximately a 68-percent chance thatthe true sampling error is less than the correspondingCV. Note that reported CVs are always estimates,themselves, and are usually, as here, reported as per-cents. As an example, suppose that a revenue-per-kilowatthour value is estimated to be 5.13 cents perkilowatthour with an estimated CV of 1.6 percent.This means that, ignoring any nonsampling error,there is approximately a 68-percent chance that thetrue average revenue per kilowatthour is withinapproximately 1.6 percent of 5.13 cents perkilowatthour (that is, between 5.05 and 5.21 cents perkilowatthour). There is approximately a 95-percentchance of a true sampling error being 2 CVs or less.
The basic approach used is shown in (Royall, 6) withadditional discussion of variance estimation in(Royall and Cumberland, 7), (Royall and Cumberland,8), and (Knaub, 5). From (Royall, 6), for sales orrevenue for any sector at the State level, if we letxrepresent an observation from the Form EIA-861,yrepresents an observation from the Form EIA-826,and y
∧represents an estimated value for data not col-
lected, then
yi= bxi + xγi eoi
,
y∧
i= b∧xi ,
b∧(γ)= ∑
n
k = 1x1 − 2γ
k yk ∑n
k = 1x2 − 2γ
k
Here, n is the Form EIA-826 sample size for thatState, and b is the factor ('slope') relating x to y in the
linear regression. γ is taken to be 1/2 (see (Knaub, 5)),although more research (Knaub, 9) could refine this.For the Form EIA-826, γ = 1/2 has certainly beenshown to be adequate (see (Knaub, 5), page 878,Table 1). The variance formula for Vd found in (Royalland Cumberland, 7 and 8) performs well for sales andfor revenue. For revenue per kilowatthour, the modelcovariance comes from notes provided by ProfessorPoduri S.R.S. Rao (Rao, 10) of the University ofRochester and the Energy Information Administration.Aggregate level CV estimates for revenue perkilowatthour are calculated as supported by (Hansen,Hurwitz and Madow, 11). Details are published in(Knaub, 12).
Additional information or clarification can beaddressed to the Energy Information Administrationas indicated in the "Contacts" section of this publica-tion.
Form EIA-900. The Form EIA-900 data are col-lected at the facility level, which is roughly the nonu-tility equivalent of plant level. Like the FormEIA-826, cutoff model sampling and estimation areemployed, however, the estimation formula are modi-fied by use of a second regressor. It was found thatmore variability occurred under the single regressormodel than was generally found in the case of theForm EIA-826, but that through the use of nameplatecapacity as a second regressor, results were greatlyimproved. Increasing variance as regressor valuesincrease (heteroscedasticity), a phenomenon whichcaused us to use a value for gamma greater than zeroin the case of the Form EIA-826, is at least as impor-tant a consideration here, and further study to increaseefficiency may be performed. A paper, “WeightedMultiple Regression Estimation for Survey ModelSampling,” has been accepted for publication in theInternet statistics journal, InterStat athttp://interstat.stat.vt.edu/intersta.htm. This paperexplains a great deal of the background and method-ology involved in providing a satisfactory estimator inthis case. It appears at the Web site given above,under May 1996 (Knaub, 13).
Form EIA-759. Data for the Form EIA-759 are col-lected at the plant level. Estimates are then providedfor geographic levels. Consumption of fuel(s) is con-verted from quantities (in short tons, barrels, or thou-sand cubic feet) to Btu at the plant level.End-of-month fuel stocks for a single generating plantmay not equal beginning-of-the-month stocks plusreceipts less consumption, for many reasons,including the fact that several plants may share thesame fuel stock.
Like the Form EIA-900, cutoff model sampling andestimation are employed, using the same multipleregression model. Once again, as described under thecorresponding subsection on the Form EIA-900,details of the estimation of totals and variances oftotals are published on the Internet in a paper entitled"Weighted Multiple Regression Estimation for SurveyModel Sampling (Knaub, 13)."
At the fuel and State level (i.e., lowest aggregatelevel), there are a number of cases where the minimal
Energy Information Administration/Electric Power Monthly June 1996 149
sample size of three is not met, when using a 25 MWcutoff. Imputation of historic values for the smallestplants is used to supplement actual values for thelargest ones. However, at the NERC level, this is notnecessary. Data element totals for each NERC region,by fuel type, are estimated using model sampling.These samples are composed solely of data reportedfor the plants actually in the sample. The nationallevel estimate from this is then considered our bestestimate, and all other estimates are apportionedaccordingly.
FERC Form 423. Data for the FERC Form 423 arecollected at the plant level. These data are then usedin the following formulas to produce aggregates andaverages for each fuel type at the State, Census divi-sion, and U.S. level. For these formulas, receipts andaverage heat content are at the plant level. For eachgeographic region, the summation ∑ represents thesum of all plants in that geographic region. Addi-tionally,
• For coal, units for receipts ( R) are in tons, unitsfor average heat content ( A) are in Btu per pound,and the unit conversion ( U) is 2,000 pounds perton;
• For petroleum, units for receipts ( R) are inbarrels, units for average heat content ( A) are inBtu per gallon, and the unit conversion ( U) is 42gallons per barrel;
• For gas, units for receipts ( R) are in thousandcubic feet (Mcf), average heat content ( A) are inBtu per cubic foot, and the unit conversion ( U) is1,000 cubic feet per Mcf.
Total Btu = ∑i(Ri × Ai × U),
where i denotes a plant; Ri = receipts for plant i;Ai = average heat content for receipts at plant i;and, U = unit conversion;
Weighted Average Btu = ∑i(Ri × Ai)
∑iRi
,
where i denotes a plant; Ri = receipts for plant i;and, Ai = average heat content for receipts at plant i.
The weighted average cost in cents per million Btu iscalculated using the following formula:
Weighted Average Cost = ∑i(Ri × Ai × Ci)
∑i(Ri × Ai)
,
where i denotes a plant; Ri = receipts for plant i;Ai = average heat content for receipts at plant i;and, Ci = cost in cents per million Btu for plant i.
The weighted average cost in dollars per unit is calcu-lated using the following formula:
Weighted Average Cost = U∑
i(Ri × Ai × Ci)
108∑iRi
where i denotes a plant; Ri = receipts for plant i;Ai = average heat content for receipts at plant i;U = unit conversion; and,Ci = cost in cents permillion Btu for plant i.
Form EIA-861. Data for the Form EIA-861 are col-lected at the utility level from all electric utilities inthe United States, its territories, and Puerto Rico.These data are then aggregated to provide national-level electricity sales values by consumer class ofservice.
Form EIA-860. Data from the Form EIA-860 aresubmitted at the generating unit level and are thenaggregated to provide total capacity by energy sourceand geographic area. In addition, at the national level,data are aggregated by prime mover.
Estimated values for net summer and net winter capa-bility for electric generating units were developed byuse of a regression formula. The formula is used toestimate values for existing units where data aremissing and for projected units. It was found that azero-intercept linear regression works very well forestimating capability based on nameplate capacity.
The only parameter then is the slope (b∧) that is used to
relate capacity to capability as follows: y∧ = b
∧x, where
y∧
is the estimated capability, and x is the knownnameplate capacity. There will be a different value for
b∧
for different prime movers and for summer andwinter capabilities and it will also depend upon theage of the generator. For more details see the Inven-tory of Power Plants.
Average Heat Content
Heat content values (Table B1) collected on the FERCForm 423 were used to convert the consumption datafrom the Form EIA-759 into Btu. Respondents toFERC Form 423 represent a subset of all generatingplants (steam plants with a capacity of 50 megawattsor larger), while Form EIA-759 respondents generallyrepresent generating plants with a combined capacityof 25 or more megawatts. The results, therefore, maynot be completely representative.
Rounding Rules for Data
Given a number with r digits to the left of the decimaland d+t digits in the fraction part, with d being theplace to which the number is to be rounded and tbeing the remaining digits which will be truncated,this number is rounded to r+d digits by adding 5 tothe (r+d+1)th digit when the number is positive or bysubtracting 5 when the number is negative. The tdigits are then truncated at the (r+d+1)th digit. Thesymbol for a rounded number truncated to zero is (*).
Energy Information Administration/Electric Power Monthly June 1996150
Data Correction Procedure
The Office of Coal, Nuclear, Electric and AlternateFuels has adopted the following policy with respect tothe revision and correction of recurrent data in energypublications:
1. Annual survey data collected by this office arepublished either as preliminary or final when firstappearing in a data report. Data initially releasedas preliminary will be so noted in the report.These data will be revised, if necessary, anddeclared final in the next publication of the data.
2. All monthly and quarterly survey data collectedby this office are published as preliminary. Thesedata are revised only after the completion of the12-month cycle of the data. No revisions are madeto the published data before this.
3. The magnitudes of changes due to revisions expe-rienced in the past will be included in the datareports, so that the reader can assess the accuracyof the data.
4. After data are published as final, corrections willbe made only in the event of a greater than onepercent difference at the national level. Cor-rections for differences that are less than thebefore-mentioned threshold are left to the dis-cretion of the Office Director. Note that in thisdiscussion, changes or revisions are referred to as"errors."
In accordance with policy statement number 3, themean value (unweighted average) for the absolutevalues of the 12 monthly revisions of each item areprovided at the U.S. level for the past 4 years (TableB2). For example, the mean of the 12 monthly abso-lute errors (absolute differences between preliminaryand final monthly data) for coal-fired generation in1995 was 49. That is, on average, the absolute valueof the change made each month to coal-fired gener-ation was 49 million kilowatthours.
The U.S. total net summer capability, updatedmonthly in the EPM (Table 1), is based solely on newelectric generating units and retirements which cometo the attention of the EIA during the year throughtelephone calls with electric utilities and on the FormEIA-759, "Monthly Power Plant Report," and may notinclude all activity for the month. Data on net summercapability, including new electric generating units, arecollected annually on the Form EIA-860, "AnnualElectric Generator Report." Preliminary data for netsummer capability are published in theElectric PowerAnnual (EPA). Final data are published in theInven-tory of Power Plants.With respect to net summercapability published in the EPM, the EIA examinesthe accuracy of that data by comparing the annualtotal value with the final annual total value publishedin the IPP.
NERC Aggregation
Beginning in January 1986, NERC region totals forthe Form EIA-759 are aggregates based on member-ship of the individual electric utilities in NERC. Priorto January 1986, NERC region totals were aggregatesdefined by the physical location of the power plantsgenerating electricity.
Use of the Glossary
The terms in the glossary have been defined forgeneral use. Restrictions on the definitions as used inthese data collection systems are included in eachdefinition when necessary to define the terms as theyare used in this report.
Obtaining Copies of Data
Upon EIA approval of theEPM, the data becomeavailable for public use on a cost-recovery basis.
Computer listings are obtained by submitting awritten request to:
Energy Information Administration, EI-524Forrestal BuildingU.S. Department of EnergyWashington, DC 20585
These data are also available monthly on machine-readable tapes. Tapes may be purchased by usingVisa, Master Card, or American Express cards as wellas money orders or checks payable to the NationalTechnical Information Service (NTIS). Purchasersmay also use NTIS and Government Printing Officedepository accounts. To place an order, contact:
National Technical Information Service (NTIS)Office of Data Base ServicesU.S. Department of Commerce5285 Port Royal RoadSpringfield, Virginia 22161(703) 487-4650
Energy Information Administration/Electric Power Monthly June 1996 151
Data for Table B1 include all quality of fuels. For a detailed breakdown on types of coal, petroleum and gas, seeTables 33, 37, and 41, respectively.
Energy Information Administration/Electric Power Monthly June 1996152
Table B1. Average Heat Content of Fossil-Fuel Receipts, February 1996
Gas1 Census Division Coal1 Petroleum1
(Btu per thousandand State (Btu per ton) (Btu per barrel)
East North Central ........................................................ 21,522,295 5,931,809 493,287Illinois ............................................................................ 19,978,114 6,052,293 1,020,715Indiana ........................................................................... 20,889,306 5,783,434 1,025,607
U.S. Average................................................................... 20,588,127 6,297,815 1,020,570
1 Data represents weighted values.a Consists mostly of blast furnace gas which has a heat content of 82,000 Btu per thousand cubic feet.Note: Data for 1996 are preliminary.Source: Federal Energy Regulatory Commission, FERC Form 423, ‘‘Monthly Report of Cost and Quality of Fuels for Electric Plants.’’
Energy Information Administration/Electric Power Monthly June 1996 153
Table B2. Comparison of Preliminary Versus Final Published Data at the U.S.�Level, 1992 Through 1995
Mean Absolute Value of Change Item 1992 1993 1994 1995
Cost (cents per million Btu)4Coal......................................................................... .35 .14 .08 .10Petroleum ................................................................ .01 * .01 .01Gas .......................................................................... .34 .06 .04 .15
1 Includes geothermal, wood, waste, wind, and solar.2 Stocks are end of month values.3 Includes public street and highway lighting, other sales to public authorities, sales to railroads and railways, and interdepartmental sales.4 Data represents weighted values.* = For detailed data, the absolute value is less than 0.5; for percentage calculations, the absolute value is less than 0.05 percent.Notes: •Change refers to the difference between preliminary monthly data published in the Electric Power Monthly (EPM) and the final
monthly data published in the EPM. •Mean absolute value of change is the unweighted average of the absolute changes.Sources: •Energy Information Administration: Form EIA-759, ‘‘Monthly Power Plant Report’’ and Form EIA-826, ‘‘Monthly Electric Utility
Sales and Revenue Report with State Distributions.’’
Energy Information Administration/Electric Power Monthly June 1996154
Table B3. Unit-of-Measure Equivalents for Electricity
1 Includes geothermal, wood, wind, waste, and solar.Notes: •For an explanation of coefficients of variation, see the technical notes. •Estimates for 1996 are preliminary.
Source: Energy Information Administration, Form EIA-759, ‘‘Monthly Power Plant Report.’’
Energy Information Administration/Electric Power Monthly June 1996 157
Table B6. Estimated Coefficients of Variation for Electric Utility Fuel Consumption and Stocks byState, February and March 1996(Percent)
Consumption Stocks
State Coal Petroleum Gas Coal Petroleum
March February March February March February March February March February
Notes: •For an explanation of coefficients of variation, see the technical notes. •Estimates for 1996 are preliminary.Source: Energy Information Administration, Form EIA-759, ‘‘Monthly Power Plant Report.’’
Energy Information Administration/Electric Power Monthly June 1996158
Glossary
Ampere: The unit of measurement of electricalcurrent produced in a circuit by 1 volt acting througha resistance of 1 ohm.
Anthracite : A hard, black lustrous coal, oftenreferred to as hard coal, containing a high percentageof fixed carbon and a low percentage of volatilematter. Comprises three groups classified according tothe following ASTM Specification D388-84, on a drymineral-matter-free basis:
Average Revenue per Kilowatthour: The averagerevenue per kilowatthour of electricity sold by sector(residential, commercial, industrial, or other) andgeographic area (State, Census division, and national),is calculated by dividing the total monthly revenue bythe corresponding total monthly sales for each sectorand geographic area.
Barrel : A volumetric unit of measure for crude oiland petroleum products equivalent to 42 U.S. gallons.
Baseload: The minimum amount of electric powerdelivered or required over a given period of time at asteady rate.
Baseload Capacity: The generating equipmentnormally operated to serve loads on an around-the-clock basis.
Baseload Plant: A plant, usually housing high-efficiency steam-electric units, which is normallyoperated to take all or part of the minimum load of asystem, and which consequently produces electricityat an essentially constant rate and runs continuously.These units are operated to maximize system mechan-ical and thermal efficiency and minimize system oper-ating costs.
Bcf: The abbreviation for 1 billion cubic feet.
Bituminous Coal: The most common coal. It isdense and black (often with well-defined bands ofbright and dull material). Its moisture content usuallyis less than 20 percent. It is used for generating elec-tricity, making coke, and space heating. Comprisesfive groups classified according to the following
ASTM Specification D388-84, on a dry mineral-matter-free (mmf) basis for fixed-carbon and volatilematter and a moist mmf basis for calorific value.
LV = Low-volatile bituminous coalMV = Medium-volatile bituminous coalHVA = High-volatile A bituminous coalHVB = High-volatile B bituminous coalHVC = High-volatile C bituminous coal
Boiler : A device for generating steam for power,processing, or heating purposes or for producing hotwater for heating purposes or hot water supply. Heatfrom an external combustion source is transmitted to afluid contained within the tubes in the boiler shell.This fluid is delivered to an end-use at a desired pres-sure, temperature, and quality.
Btu (British Thermal Unit) : A standard unit formeasuring the quantity of heat energy equal to thequantity of heat required to raise the temperature of 1pound of water by 1 degree Fahrenheit.
Capability : The maximum load that a generatingunit, generating station, or other electrical apparatuscan carry under specified conditions for a givenperiod of time without exceeding approved limits oftemperature and stress.
Capacity: The full-load continuous rating of a gen-erator, prime mover, or other electric equipment underspecified conditions as designated by the manufac-turer. It is usually indicated on a nameplate attachedto the equipment.
Capacity (Purchased): The amount of energy andcapacity available for purchase from outside thesystem.
Census Divisions: The nine geographic divisions ofthe United States established by the Bureau of theCensus, U.S. Department of Commerce, for thepurpose of statistical analysis. The boundaries ofCensus divisions coincide with State boundaries. ThePacific Division is subdivided into the Pacific Contig-uous and Pacific Noncontiguous areas.
Energy Information Administration/Electric Power Monthly June 1996 159
Circuit : A conductor or a system of conductorsthrough which electric current flows.
Coal: A black or brownish-black solid combustiblesubstance formed by the partial decomposition of veg-etable matter without access to air. The rank of coal,which includes anthracite, bituminous coal,subbituminous coal, and lignite, is based on fixedcarbon, volatile matter, and heating value. Coal rankindicates the progressive alteration from lignite toanthracite. Lignite contains approximately 9 to 17million Btu per ton. The contents of subbituminousand bituminous coal range from 16 to 24 million Btuper ton and from 19 to 30 million Btu per ton, respec-tively. Anthracite contains approximately 22 to 28million Btu per ton.
Coincidental Demand: The sum of two or moredemands that occur in the same time interval.
Coincidental Peak Load: The sum of two or morepeak loads that occur in the same time interval.
Coke (Petroleum): A residue high in carbon contentand low in hydrogen that is the final product ofthermal decomposition in the condensation process incracking. This product is reported as marketable cokeor catalyst coke. The conversion factor is 5 barrels(42 U.S. gallons each) per short ton.
Combined Pumped-Storage Plant: A pumped-storage hydroelectric power plant that uses bothpumped water and natural streamflow to produce elec-tricity.
Commercial Operation: Commercial operationbegins when control of the loading of the generator isturned over to the system dispatcher.
Compressor: A pump or other type of machine usinga turbine to compress a gas by reducing the volume.
Consumption (Fuel): The amount of fuel used forgross generation, providing standby service, start-upand/or flame stabilization.
Contract Receipts: Purchases based on a negotiatedagreement that generally covers a period of 1 or moreyears.
Cost: The amount paid to acquire resources, such asplant and equipment, fuel, or labor services.
Crude Oil (including Lease Condensate): Amixture of hydrocarbons that existed in liquid phasein underground reservoirs and that remains liquid atatmospheric pressure after passing through surfaceseparating facilities. Included are lease condensateand liquid hydrocarbons produced from tar sands,gilsonite, and shale oil. Drip gases are also included,but topped crude oil (residual oil) and other unfin-ished oils are excluded. Liquids produced at naturalgas processing plants and mixed with crude oil arelikewise excluded where identifiable.
Current (Electric) : A flow of electrons in an elec-trical conductor. The strength or rate of movement ofthe electricity is measured in amperes.
Demand (Electric): The rate at which electricenergy is delivered to or by a system, part of asystem, or piece of equipment, at a given instant oraveraged over any designated period of time.
Demand Interval: The time period during whichflow of electricity is measured (usually in 15-, 30-, or60-minute increments.)
Electric Plant (Physical): A facility containingprime movers, electric generators, and auxiliaryequipment for converting mechanical, chemical,and/or fission energy into electric energy.
Electric Utility : An enterprise that is engaged in thegeneration, transmission, or distribution of electricenergy primarily for use by the public and that is themajor power supplier within a designated service area.Electric utilities include investor-owned, publiclyowned, cooperatively owned, and government-owned(municipals, Federal agencies, State projects, andpublic power districts) systems.
Energy: The capacity for doing work as measured bythe capability of doing work (potential energy) or theconversion of this capability to motion (kineticenergy). Energy has several forms, some of which areeasily convertible and can be changed to another formuseful for work. Most of the world's convertibleenergy comes from fossil fuels that are burned toproduce heat that is then used as a transfer medium tomechanical or other means in order to accomplishtasks. Electrical energy is usually measured inkilowatthours, while heat energy is usually measuredin British thermal units.
Energy Deliveries: Energy generated by one electricutility system and delivered to another system throughone or more transmission lines.
Energy Receipts: Energy generated by one electricutility system and received by another system throughone or more transmission lines.
Energy Source: The primary source that providesthe power that is converted to electricity throughchemical, mechanical, or other means. Energy sourcesinclude coal, petroleum and petroleum products, gas,water, uranium, wind, sunlight, geothermal, and othersources.
Fahrenheit: A temperature scale on which theboiling point of water is at 212 degrees above zero onthe scale and the freezing point is at 32 degrees abovezero at standard atmospheric pressure.
Failure or Hazard : Any electric power supplyequipment or facility failure or other event that, in thejudgment of the reporting entity, constitutes a hazardto maintaining the continuity of the bulk electricpower supply system such that a load reduction actionmay become necessary and a reportable outage mayoccur. The imposition of a special operating proce-
Energy Information Administration/Electric Power Monthly June 1996160
dure, the extended purchase of emergency power,other bulk power system actions that may be causedby a natural disaster, a major equipment failure thatwould impact the bulk power supply, and an environ-mental and/or regulatory action requiring equipmentoutages are types of abnormal conditions that shouldbe reported.
Firm Gas: Gas sold on a continuous and generallylong-term contract.
Fossil Fuel: Any naturally occurring organic fuel,such as petroleum, coal, and natural gas.
Fossil-Fuel Plant: A plant using coal, petroleum, orgas as its source of energy.
Fuel: Any substance that can be burned to produceheat; also, materials that can be fissioned in a chainreaction to produce heat.
Fuel Emergencies: An emergency that exists whensupplies of fuels or hydroelectric storage for gener-ation are at a level or estimated to be at a level thatwould threaten the reliability or adequacy of bulkelectric power supply. The following factors shouldbe taken into account to determine that a fuel emer-gency exists: (1) Fuel stock or hydroelectric projectwater storage levels are 50 percent or less of normalfor that particular time of the year and a continueddownward trend in fuel stock or hydroelectric projectwater storage level are estimated; or (2) Unscheduleddispatch or emergency generation is causing anabnormal use of a particular fuel type, such that thefuture supply or stocks of that fuel could reach a levelwhich threatens the reliability or adequacy of bulkelectric power supply.
Gas: A fuel burned under boilers and by internalcombustion engines for electric generation. Theseinclude natural, manufactured and waste gas.
Generation (Electricity): The process of producingelectric energy by transforming other forms of energy;also, the amount of electric energy produced,expressed in watthours (Wh).
Gross Generation:The total amount of electric energyproduced by the generating units at a generatingstation or stations, measured at the generator termi-nals.
Net Generation: Gross generation less the electricenergy consumed at the generating station for stationuse.
Generator: A machine that converts mechanicalenergy into electrical energy.
Generator Nameplate Capacity: The full-load con-tinuous rating of a generator, prime mover, or otherelectric power production equipment under specificconditions as designated by the manufacturer.Installed generator nameplate rating is usually indi-cated on a nameplate physically attached to the gener-ator.
Geothermal Plant: A plant in which the primemover is a steam turbine. The turbine is driven eitherby steam produced from hot water or by natural steamthat derives its energy from heat found in rocks orfluids at various depths beneath the surface of theearth. The energy is extracted by drilling and/orpumping.
Gigawatt (GW): One billion watts.
Gigawatthour (GWh) : One billion watthours.
Gross Generation: The total amount of electricenergy produced by a generating facility, as measuredat the generator terminals.
Heavy Oil: The fuel oils remaining after the lighteroils have been distilled off during the refiningprocess. Except for start-up and flame stabilization,virtually all petroleum used in steam plants is heavyoil.
Horsepower: A unit for measuring the rate of work(or power) equivalent to 33,000 foot-pounds perminute or 746 watts.
Hydroelectric Plant: A plant in which the turbinegenerators are driven by falling water.
Instantaneous Peak Demand: The maximumdemand at the instant of greatest load.
Integrated Demand: The summation of the contin-uously varying instantaneous demand averaged over aspecified interval of time. The information is usuallydetermined by examining a demand meter.
Internal Combustion Plant : A plant in which theprime mover is an internal combustion engine. Aninternal combustion engine has one or more cylindersin which the process of combustion takes place, con-verting energy released from the rapid burning of afuel-air mixture into mechanical energy. Diesel orgas-fired engines are the principal types used in elec-tric plants. The plant is usually operated duringperiods of high demand for electricity.
Interruptible Gas : Gas sold to customers with aprovision that permits curtailment or cessation ofservice at the discretion of the distributing companyunder certain circumstances, as specified in theservice contract.
Kilowatt (kW) : One thousand watts.
Kilowatthour (kWh) : One thousand watthours.
Light Oil : Lighter fuel oils distilled off during therefining process. Virtually all petroleum used ininternal combustion and gas-turbine engines is lightoil.
Lignite : A brownish-black coal of low rank withhigh inherent moisture and volatile matter (usedalmost exclusively for electric power generation). It isalso referred to as brown coal. Comprises two groupsclassified according to the following ASTM Specifi-
Energy Information Administration/Electric Power Monthly June 1996 161
cation D388-84 for calorific values on a moistmaterial-matter-free basis:
Limits Btu/lb.
GE LTLignite A 6300 8300Lignite B - 6300
Maximum Demand: The greatest of all demands ofthe load that has occurred within a specified period oftime.
Mcf : One thousand cubic feet.
Megawatt (MW) : One million watts.
Megawatthour (MWh) : One million watthours.
MMcf : One million cubic feet.
Natural Gas: A naturally occurring mixture ofhydrocarbon and nonhydrocarbon gases found inporous geological formations beneath the earth'ssurface, often in association with petroleum. The prin-cipal constituent is methane.
Net Energy for Load: Net generation of main gener-ating units that are system-owned or system-operatedplus energy receipts minus energy deliveries.
Net Generation: Gross generation minus plant usefrom all electric utility owned plants. The energyrequired for pumping at a pumped-storage plant isregarded as plant use and must be deducted from thegross generation.
Net Summer Capability: The steady hourly output,which generating equipment is expected to supply tosystem load exclusive of auxiliary power, as demon-strated by tests at the time of summer peak demand.
Noncoincidental Peak Load: The sum of two ormore peak loads on individual systems that do notoccur in the same time interval. Meaningful onlywhen considering loads within a limited period oftime, such as a day, week, month, a heating or coolingseason, and usually for not more than 1 year.
North American Electric Reliability Council(NERC): A council formed in 1968 by the electricutility industry to promote the reliability and ade-quacy of bulk power supply in the electric utilitysystems of North America. NERC consists of nineregional reliability councils and encompasses essen-tially all the power regional of the contiguous UnitedStates, Canada, and Mexico. The NERC Regions are:
ASCC - Alaskan System Coordination Council
ECAR - East Central Area Reliability CoordinationAgreement
ERCOT - Electric Reliability Council of Texas
MAIN - Mid-America Interconnected Network
MAAC - Mid-Atlantic Area Council
MAPP - Mid-Continent Area Power Pool
NPCC - Northeast Power Coordinating Council
SERC - Southeastern Electric Reliability Council
SPP - Southwest Power Pool
WSCC - Western Systems Coordinating Council
Nuclear Fuel: Fissionable materials that have beenenriched to such a composition that, when placed in anuclear reactor, will support a self-sustaining fissionchain reaction, producing heat in a controlled mannerfor process use.
Nuclear Power Plant: A facility in which heatproduced in a reactor by the fissioning of nuclear fuelis used to drive a steam turbine.
Off-Peak Gas: Gas that is to be delivered and takenon demand when demand is not at its peak.
Ohm: The unit of measurement of electrical resist-ance. The resistance of a circuit in which a potentialdifference of 1 volt produces a current of 1 ampere.
Operable Nuclear Unit: A nuclear unit is "operable"after it completes low-power testing and is grantedauthorization to operate at full power. This occurswhen it receives its full power amendment to its oper-ating license from the Nuclear Regulatory Commis-sion.
Other Gas: Includes manufactured gas, coke-ovengas, blast-furnace gas, and refinery gas. Manufacturedgas is obtained by distillation of coal, by the thermaldecomposition of oil, or by the reaction of steampassing through a bed of heated coal or coke.
Other Generation: Electricity originating fromthese sources: biomass, fuel cells, geothermal heat,solar power, waste, wind, and wood.
Other Unavailable Capability: Net capability ofmain generating units that are unavailable for load forreasons other than full-forced outrage or scheduledmaintenance. Legal restrictions or other causes makethese units unavailable.
Peak Demand: The maximum load during a speci-fied period of time.
Peak Load Plant: A plant usually housing old, low-efficiency steam units; gas turbines; diesels; orpumped-storage hydroelectric equipment normallyused during the peak-load periods.
Peaking Capacity: Capacity of generating equip-ment normally reserved for operation during the hoursof highest daily, weekly, or seasonal loads. Some gen-erating equipment may be operated at certain times aspeaking capacity and at other times to serve loads onan around-the-clock basis.
Percent Difference: The relative change in a quan-tity over a specified time period. It is calculated asfollows: the current value has the previous value sub-tracted from it; this new number is divided by the
Energy Information Administration/Electric Power Monthly June 1996162
absolute value of the previous value; then this newnumber is multiplied by 100.
Petroleum: A mixture of hydrocarbons existing inthe liquid state found in natural underground reser-voirs, often associated with gas. Petroleum includesfuel oil No. 2, No. 4, No. 5, No. 6; topped crude;Kerosene; and jet fuel.
Petroleum Coke: See Coke (Petroleum).
Petroleum (Crude Oil): A naturally occurring, oily,flammable liquid composed principally ofhydrocarbons. Crude oil is occasionally found insprings or pools but usually is drilled from wellsbeneath the earth's surface.
Plant: A facility at which are located prime movers,electric generators, and auxiliary equipment for con-verting mechanical, chemical, and/or nuclear energyinto electric energy. A plant may contain more thanone type of prime mover. Electric utility plantsexclude facilities that satisfy the definition of a quali-fying facility under the Public Utility Regulatory Poli-cies Act of 1978.
Plant Use: The electric energy used in the operationof a plant. Included in this definition is the energyrequired for pumping at pumped-storage plants.
Plant-Use Electricity: The electric energy used inthe operation of a plant. This energy total is sub-tracted from the gross energy production of the plant;for reporting purposes the plant energy production isthen reported as a net figure. The energy required forpumping at pumped-storage plants is, by definition,subtracted, and the energy production for these plantsis then reported as a net figure.
Power: The rate at which energy is transferred. Elec-trical energy is usually measured in watts. Also usedfor a measurement of capacity.
Price: The amount of money or consideration-in-kind for which a service is bought, sold, or offered forsale.
Prime Mover: The motive force that drives an elec-tric generator (e.g., steam engine, turbine, or waterwheel).
Production (Electric): Act or process of producingelectric energy from other forms of energy; also, theamount of electric energy expressed in watthours(Wh).
Pumped-Storage Hydroelectric Plant: A plant thatusually generates electric energy during peak-loadperiods by using water previously pumped into an ele-vated storage reservoir during off-peak periods whenexcess generating capacity is available to do so. Whenadditional generating capacity is needed, the watercan be released from the reservoir through a conduitto turbine generators located in a power plant at alower level.
Pure Pumped-Storage Hydroelectric Plant: Aplant that produces power only from water that haspreviously been pumped to an upper reservoir.
Qualifying Facility (QF) : This is a cogenerator orsmall power producer that meets certain ownership,operating and efficiency criteria established by theFederal Energy Regulatory Commission (FERC) pur-suant to the PURPA, and has filed with the FERC forQF status or has self-certified. For additional informa-tion, see the Code of Federal Regulation, Title 18,Part 292.
Railroad and Railway Electric Service: Electricitysupplied to railroads and interurban and street rail-ways, for general railroad use, including the propul-sion of cars or locomotives, where such electricity issupplied under separate and distinct rate schedules.
Receipts: Purchases of fuel.
Reserve Margin (Operating): The amount ofunused available capability of an electric powersystem at peak load for a utility system as a per-centage of total capability.
Restoration Time: The time when the major portionof the interrupted load has been restored and theemergency is considered to be ended. However, someof the loads interrupted may not have been restoreddue to local problems.
Restricted-Universe Census: This is the completeenumeration of data from a specifically defined subsetof entities including, for example, those that exceed agiven level of sales or generator nameplate capacity.
Retail: Sales covering electrical energy supplied forresidential, commercial, and industrial end-use pur-poses. Other small classes, such as agriculture andstreet lighting, also are included in this category.
Running and Quick-Start Capability : The netcapability of generating units that carry load or havequick-start capability. In general, quick-start capa-bility refers to generating units that can be availablefor load within a 30-minute period.
Sales: The amount of kilowatthours sold in a givenperiod of time; usually grouped by classes of service,such as residential, commercial, industrial, and other.Other sales include public street and highwaylighting, other sales to public authorities and railways,and interdepartmental sales.
Scheduled Outage: The shutdown of a generatingunit, transmission line, or other facility, for inspectionor maintenance, in accordance with an advanceschedule.
Short Ton: A unit of weight equal to 2,000 pounds.
Spot Purchases: A single shipment of fuel orvolumes of fuel, purchased for delivery within 1 year.Spot purchases are often made by a user to fulfill acertain portion of energy requirements, to meet unan-
Energy Information Administration/Electric Power Monthly June 1996 163
ticipated energy needs, or to take advantage of low-fuel prices.
Standby Facility: A facility that supports a utilitysystem and is generally running under no-load. It isavailable to replace or supplement a facility normallyin service.
Standby Service: Support service that is available,as needed, to supplement a consumer, a utility system,or to another utility if a schedule or an agreementauthorizes the transaction. The service is not regularlyused.
Steam-Electric Plant (Conventional): A plant inwhich the prime mover is a steam turbine. The steamused to drive the turbine is produced in a boiler wherefossil fuels are burned.
Stocks: A supply of fuel accumulated for future use.This includes coal and fuel oil stocks at the plant site,in coal cars, tanks, or barges at the plant site, or atseparate storage sites.
Subbituminous Coal: Subbituminous coal, or blacklignite, is dull black and generally contains 20 to 30percent moisture. The heat content of subbituminouscoal ranges from 16 to 24 million Btu per ton asreceived and averages about 18 million Btu per ton.Subbituminous coal, mined in the western coal fields,is used for generating electricity and space heating.
Substation: Facility equipment that switches,changes, or regulates electric voltage.
Sulfur : One of the elements present in varying quan-tities in coal which contributes to environmentaldegradation when coal is burned. In terms of sulfurcontent by weight, coal is generally classified as low(less than or equal to 1 percent), medium (greater than1 percent and less than or equal to 3 percent), andhigh (greater than 3 percent). Sulfur content is meas-ured as a percent by weight of coal on an "asreceived" or a "dry" (moisture-free, usually part of alaboratory analysis) basis.
Switching Station: Facility equipment used to tietogether two or more electric circuits throughswitches. The switches are selectively arranged to
permit a circuit to be disconnected, or to change theelectric connection between the circuits.
System (Electric): Physically connected generation,transmission, and distribution facilities operated as anintegrated unit under one central management, oroperating supervision.
Transformer : An electrical device for changing thevoltage of alternating current.
Transmission: The movement or transfer of electricenergy over an interconnected group of lines andassociated equipment between points of supply andpoints at which it is transformed for delivery to con-sumers, or is delivered to other electric systems.Transmission is considered to end when the energy istransformed for distribution to the consumer.
Transmission System (Electric): An interconnectedgroup of electric transmission lines and associatedequipment for moving or transferring electric energyin bulk between points of supply and points at whichit is transformed for delivery over the distributionsystem lines to consumers, or is delivered to otherelectric systems.
Turbine : A machine for generating rotary mechan-ical power from the energy of a stream of fluid (suchas water, steam, or hot gas). Turbines convert thekinetic energy of fluids to mechanical energy throughthe principles of impulse and reaction, or a mixture ofthe two.
Watt : The electrical unit of power. The rate ofenergy transfer equivalent to 1 ampere flowing undera pressure of 1 volt at unity power factor.
Watthour (Wh) : An electrical energy unit ofmeasure equal to 1 watt of power supplied to, or takenfrom, an electric circuit steadily for 1 hour.
Wheeling Service: The movement of electricity fromone system to another over transmission facilities ofintervening systems. Wheeling service contracts canbe established between two or more systems.
Year to Date: The cumulative sum of each month'svalue starting with January and ending with thecurrent month of the data.
Energy Information Administration/Electric Power Monthly June 1996164