Electric Power Surveys

U.S. Department of Energy
Energy Information Administration
Form EIA-861 (2007)

ANNUAL ELECTRIC POWER
INDUSTRY REPORT

Form Approved
OMB No. 1905-0129
Approval Expires: 11/30/2010

PURPOSE

Form EIA-861 collects information on the status of electric power industry participants involved
in the generation, transmission, and distribution of electric energy in the United States, its
territories, and Puerto Rico. The data from this form are used to accurately maintain the EIA list
of electric utilities, to draw samples for other electric power surveys, and to provide input for the
following EIA reports: Electric Power Monthly, Monthly Energy Review, Electric Power Annual,
Annual Energy Outlook, and Annual Energy Review. The data collected on this form are used
to monitor the current status and trends of the electric power industry and to evaluate the future
of the industry.

REQUIRED
RESPONDENTS

The Form EIA-861 is to be completed by electric industry distributors including: electric utilities,
wholesale power marketers (registered with the Federal Energy Regulatory Commission),
energy service providers (registered with the States), and electric power producers. Responses
are collected at the business level (not at the holding company level).

RESPONSE DUE
DATE

Submit the completed Form EIA-861 to the EIA by April 30, following the end of the calendar
year.

METHODS OF
FILING RESPONSE

Submit your data electronically using EIA’s secure Internet Data Collection system (IDC). This
system uses security protocols to protect information against unauthorized access during
transmission.
•

If you have not registered with EIA’s Single Sign-On system, send an e-mail requesting
assistance to: [email protected].

•

If you have registered with Single Sign-On, log on at
https://signon.eia.doe.gov/ssoserver/login

•

If you are having a technical problem with logging into the IDC or using the IDC contact
the IDC Help Desk for further information. Contact the Help Desk at:
E-Mail: [email protected]
Phone: 202-586-9595

•

If you need an alternate means of filing your response, contact the Help Desk.

Please retain a completed copy of this form for your files.
CONTACTS

Internet System Questions: For questions related to the Internet Data Collection system, see
the help contact information immediately above.
Data Questions: For questions about the data requested on Form EIA-861, contact the Survey
Manager:
Karen McDaniel
Telephone Number: 202 586-4280
FAX Number: (202) 287-1938
E-mail: [email protected]

1

U.S. Department of Energy
Form Approved
ANNUAL ELECTRIC POWER
Energy Information Administration
OMB No. 1905-0129
INDUSTRY REPORT
Form EIA-861 (2007)
Approval Expires: 11/30/2010
Submit the completed Form EIA-861 to the EIA by April 30, following the end of the
GENERAL
calendar year.
INSTRUCTIONS
1. Respondents, who also submit the Form EIA-826, “Monthly Electric Sales and Revenue
Report with State Distributions," should coordinate the information submitted on the Form
EIA-861, and Form EIA-826 to ensure consistency.
2. Complete the information at the top portion of the form with the name, telephone and FAX
number, and e-mail address, of the current contact person, and the contact person’s
supervisor.
3. Report peak demand in megawatts and energy values (e.g., generation and sales) in
megawatthours, except where noted. One megawatthour equals 1,000 kilowatthours. To
convert kilowatthours to megawatthours, divide by 1,000 and round to the nearest whole
number. For example, sales of 5,245,790 kilowatthours should be reported as 5,246
megawatthours.
4. Report in whole numbers (i.e., no decimal points), except where explicitly instructed to
report otherwise. All revenue data on Schedules 3, 4, and 6 should be rounded and
reported in thousand dollars. For example, revenue of $8,459,688.42 should be reported
as $8,460.
5. For number of customers, enter the average of the 12 close-of-month customer accounts.
•

All respondents having end-use customers, including retail power marketers selling
power in deregulated, competitive State programs must use the average of the 12
close-of-month customer counts when reporting on Schedule IV, even if your
company began business after the beginning of the reporting year, or ended
business before the close of the year.

•

Count each meter as a separate customer in cases where commercial franchise, or
residential customer-buying groups have been aggregated under one buyer
representative. The customer counts for public-street and highway lighting should
be one customer per community.

•

Please do not count each pole as a separate customer even if billing is by a flat
rate per pole per month.

6. Use a minus sign for reporting negative numbers.
7. Where exact data are unavailable, report estimated data.
8. See the Glossary for terms used in this survey. The financial and accounting terms are
consistent as outlined in the Uniform System of Accounts for Public Utilities and
Licensees (U.S. of A.) (18 CFR Part 101).
ITEM-BY-ITEM
INSTRUCTIONS

SCHEDULE 1. IDENTIFICATION
1. Survey Contact: Verify contact name, title, address, telephone number, fax number, and
e-mail address.
2. Supervisor of Contact Person for Survey: Verify the contact’s supervisor’s name, title,
address, telephone number, Fax number and e-mail address.
3. Report For: Verify all information, including entity name, entity identification number, and
reporting year for which data are being reported. These fields cannot be revised online.
Contact EIA if corrections are needed.
If any of the above information is incorrect, revise the incorrect entry and provide the correct
information. Provide any missing information.
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U.S. Department of Energy
ANNUAL ELECTRIC POWER
Energy Information Administration
INDUSTRY REPORT
Form EIA-861 (2007)
Entity and Preparer Information

Form Approved
OMB No. 1905-0129
Approval Expires: 11/30/2010

4. Legal Name of Entity: Enter the legal name of the entity for which this form is being
prepared.
5. Current Address of Entity’s Principal Business Office: Enter the complete address,
excluding the legal name, of the entity’s principal business office (i.e., headquarters, main
office, etc.).
6. Preparer’s Legal Name: Enter the legal name of the company, which prepares this form, if
different from the Legal Name of Entity.
7. Current Address of Preparer’s Office: Enter the address to which this form should be
mailed, if different from the Current Address of Entity’s Principal Business Office.
Include an attention line, room number, building designation, etc. to facilitate the future
handling and processing of the Form EIA-861.
8. Respondent Type: Enter an "X" for ownership type that describes the electric entity.
SCHEDULE 2, PART A. GENERAL INFORMATION
1. For line 1, please check all of the Regional Councils within the North American Electric
Reliability Corporation (NERC), in which your organization conducts operations.
The Regional Councils are:
ERCOT .............. Electric Reliability Council of Texas
FRCC ................. Florida Reliability Coordinating Council
MRO ................... Midwest Reliability Organization
NPCC................. Northeast Power Coordinating Council
RFC…………..… ReliabilityFirst Corporation
SERC ................. Southeastern Electric Reliability Council
SPP.................... Southwest Power Pool
WECC ................ Western Electric Coordinating Council
2. For line 3, Control Area Operator(s), enter the name of the control area operator(s)
responsible for your oversight.
3. For line 4, Operate Generating Plant(s), Check Yes to indicate that organization operated
a generating plant(s) during the reporting period. Otherwise, Check No.
4. For line 5, Activities, Check the appropriate activities the electric entity was engaged in
during the reporting year.
Generation from company owned plant. Owned power generation only.
Transmission. Owned or leased transmission lines.
Buying transmission services on other electrical systems. Types of services include
borderline customers, transmission line rental, transmission capacity, transmission
wheeling, and system operational services.
Distribution using owned/leased electrical wires. Power delivery to your own end-use
customers over distribution facilities.
Buying distribution on other electrical systems. Types of support include customer
billing, distribution system support charges for energy delivered, line maintenance, and/or
equipment charges.
Wholesale power marketing. Wholesale transactions with other electric utilities,
purchases from power producers, and transactions to export and/or import electricity to, or
from, Canada or Mexico. Also includes electrical sales and purchases among Federal
Energy Regulatory Commission registered power marketers and similar participation in
transactions with electric utilities.
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U.S. Department of Energy
Form Approved
ANNUAL ELECTRIC POWER
Energy Information Administration
OMB No. 1905-0129
INDUSTRY REPORT
Form EIA-861 (2007)
Approval Expires: 11/30/2010
Retail power marketing. Provision of electrical energy to end-use customers in areas
where the customer has been given the legal right to select a power supplier other than
the “traditional electric utility.”
Bundled services. Provision of electricity in combination with gas, water, cable, Internet,
and/or telephone for a single price.
5. For line 6, Highest Hourly Electrical Peak System Demand, electric utility companies
should enter the maximum hourly summer load (for months of June through September)
based on net energy for the system during the reporting year. Net energy for the system is
the sum of energy an electric utility needs to satisfy their service area and includes full and
partial wholesale requirements customers, and the losses experienced in delivery. The
maximum hourly load is determined by the interval in which the 60-minute integrated
demand is the greatest. If such data are unavailable, adjust available data to approximate
a 60-minute demand interval and explain the adjustment on Schedule 9, Footnotes. If
adjustments cannot be made, furnish data as available and explain on Schedule 9,
Footnotes. For winter enter the maximum hourly winter load (for months of January
through March, and the previous December) based on the net energy for the system during
the reporting year. Please note: These data elements should be provided in megawatts.
6. For line 7, Alternative Fueled Vehicles, Check Yes to indicate that your company
owns/operates, or plans to own and operate, alternative fueled vehicles; otherwise Check
No. If “Yes,” provide the name, title, FAX number, telephone number and e-mail address of
a contact person. Note: For the purpose of this question, an “alternative-fueled vehicle” is
either designed or manufactured by an original equipment manufacturer or is a converted
vehicle designed to operate in either dual-fuel, flexible-fuel, or dedicated modes on fuels
other than gasoline or diesel. This does not include a conventional vehicle that is limited to
operation on blended or reformulated gasoline fuels.
SCHEDULE 2, PART B. ENERGY SOURCES AND DISPOSITION
1. Enter the annual megawatthours (MWh) for all sources of energy and disposition of energy
listed.
2. For line 1, Net Generation, enter the net generation (gross generation minus station use)
from all respondent-owned plants. If a plant is jointly owned, enter only the reporting
party’s share of generation. Include generation used to replace system losses arising from
wheeling transactions. Include net generation supplied as part of a tolling arrangement.
3. For line 2, Purchases from Electricity Suppliers, enter the total amount of energy
purchased from electricity suppliers including: nonutility power producers and power
marketers (reported separately in previous years), municipal departments and power
agencies, cooperatives, investor-owned utilities, political subdivisions, State agencies and
power pools, and marketing agencies of the United States Government and Canada; these
agencies include Bonneville Power Administration (BPA), Southeastern Power
Administration (SEPA), Southwestern Power Administration (SWPA), Western Area Power
Administration (WAPA), Tennessee Valley Authority (TVA), United States Army Corps of
Engineers, the United States Bureau of Reclamation, United States Bureau of Indian
Affairs, International Boundary and Water Commission, Hydro-Quebec, etc. This entry
includes requirements power, firm power and all other nonfirm service. Note: Please
identify on Schedule 9, Footnotes, the portion of purchased power obtained through tolling
arrangements, and any international purchases.
4. For line 3, Exchanges Received (In), enter the amount of exchange energy received. Do
not include power received through tolling arrangements.
5. For line 4, Exchanges Delivered (Out), enter the amount of exchange energy delivered.
Do not include power delivered as part of a tolling arrangement.
6. For line 5, Exchanges (Net), enter the net amount of energy exchanged. Net exchange is
the difference between the amount of exchange received and the amount of exchange
delivered (lines 3-4). This entry should not include wholesale energy purchased from or
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U.S. Department of Energy
Form Approved
ANNUAL ELECTRIC POWER
Energy Information Administration
OMB No. 1905-0129
INDUSTRY REPORT
Form EIA-861 (2007)
Approval Expires: 11/30/2010
sold to regulated companies or unregulated companies for other systems.
7. For line 6, Wheeled Received (In), enter the total amount of energy entering your system
from other systems for transmission through your system (wheeling) for delivery to other
systems. Do not report as Wheeled Received, energy purchased or exchanged for
consumption within your system, which was wheeled to you by others.
8. For line 7, Wheeled Delivered (Out), enter the total amount of energy leaving your system
that was transmitted through your system for delivery to other systems. If Wheeling
Delivered is not precisely known, please estimate based on your system's known
percentage of losses for wheeling transactions.
9. For line 8, Wheeled (Net), enter the difference between the amount of energy entering
your system for transmission through your system and the amount of energy leaving your
system (line 6 minus line 7). Wheeled net represents the energy losses on your system
associated with the wheeling of energy for other systems.
10. For line 9, Transmission by Others, Losses, enter the amount of energy losses
associated with the wheeling of electricity provided to your system by other utilities.
Transmission by Others Losses should always be expressed as a negative value.
11. For line 10, Total Sources, enter the sum of the energy sources (lines 1, 2, 5, 8, and 9).
This entry should be equal to line 16, Total Disposition.
12. For line 11, Sales to Ultimate Customers, enter the amount of electricity sold to
customers purchasing electricity for their own use and not for resale. This entry should
correspond to the revenue from sales to ultimate customers reported on Schedule 3, line
1, and should be equal to the total megawatthours reported on Schedule 4, Parts A, and
B, column e, when summed for all reported States. This entry should include all unbilled
megawatthours sold during the reporting period.
13. For line 12, Sales for Resale, enter the amount of electricity sold for resale purposes.
This entry should include sales for resale to power marketers (reported separately in
previous years), full and partial requirements customers, firm power customers and
nonfirm customers. This entry should also correspond to the revenue from sales for
resale reported in Schedule 3, line 3. Note: Please identify on Schedule 9, Footnotes,
the portion of sales for resale power sold through tolling arrangements, and any
international sales.
14. For line 13, Energy Furnished Without Charge, enter the amount of electricity furnished
by the electric utility without charge, such as to a municipality under a franchise agreement
or for public street and highway lighting. This entry does not include data entered in line
14.
15. For line 14, Energy Consumed by Respondent Without Charge, enter the amount of
electricity used by the electric utility in its electric and other departments without charge.
This entry does not include data entered in line 13.
16. For line 15, Total Energy Losses, enter the total amount of electricity lost from
transmission, distribution, and/or unaccounted for. This is the difference between line 10,
"Total Sources," and the sum of lines 11, 12, 13, and 14. Total Energy Losses should
always be expressed as a positive value.
17. For line 16, Total Disposition, enter disposition of energy (the sum of lines 11, 12, 13, 14,
and 15). This entry should equal line 10, Total Sources.

SCHEDULE 2, PART C. CUSTOMER SERVICE PROGRAMS
Schedule 2C. Green Pricing programs allow electricity customers the opportunity to
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U.S. Department of Energy
Form Approved
ANNUAL ELECTRIC POWER
Energy Information Administration
OMB No. 1905-0129
INDUSTRY REPORT
Form EIA-861 (2007)
Approval Expires: 11/30/2010
purchase electricity generated from renewable resources and to pay for renewable energy
development. Renewable resources include solar, wind, geothermal, hydroelectric power,
and wood. For Green pricing revenue, report the total amount of revenue collected from
customers in each green pricing customer class, e.g., residential. For Green pricing sales
(MWh), report the total amount of megawatthours purchased by customers in each green
pricing customer class. Number of sales volumes and customers should not exceed the
values in Schedule 4, Parts A, B, or D. If your programs are active in more than one
State, provide additional information on Schedule 9, Footnotes.
Schedule 2D. Net Metering arrangements permit a facility (using a meter that reads
inflows and outflows of electricity) to sell any excess power it generates over its load
requirement back to the electrical grid to offset consumption. For Net Metering
megawatthours, enter the amount of energy not served to the customer class as a result of
customers’ power generation. This energy may be metered at the customer’s meter, or
estimated by the utility. Number of net metering customers should not exceed the values
in Schedule 4, Parts A, B, or D. If your programs are active in more than one State,
provide additional information on Schedule 9, Footnotes.
SCHEDULE 3. ELECTRIC OPERATING REVENUE
1. All electric operating revenue data should be rounded and reported in thousand dollars
(for example, revenue of $8,461,688.42 should be reported as $8,462).
2. For line 1, Electric Operating Revenue from Sales to Ultimate Customers, enter the
amount of revenue from sales of electricity to those customers purchasing electricity for
their own use and not for resale. Revenue reported on Schedule 4, Part C, for delivery
service (and all other charges) should not be reported on Schedule 3, line 1, but should
be reported in Schedule 3, line 2, Revenue from Unbundled (Delivery) Customers. This
entry is gross revenue and includes the revenue from State and local income taxes,
energy or demand charges, customer service charges, environmental surcharges,
franchise fees, fuel adjustments and other miscellaneous charges applied to end-use
customers during normal billing operations. This entry should not include deferred
charges, credits, or other adjustments, such as fuel or revenue from purchased power,
from previous reporting periods which are included in Schedule 3, line 4, Electric Credits/
Other Adjustments. This entry should correspond to electricity sales reported in
Schedule 2, Part B, line 11. (This entry should also be the same total revenue reported on
Schedule 4, column e, Parts A and B, when summed for all reported States). This entry
should include all unbilled revenue resulting from power sold during the reporting period.
3. For line 2, Revenue from Unbundled (Delivery) Customers, enter the amount of
revenue from unbundled customers who purchase their electricity from a supplier other
than the electric utility that distributes power to their premises. This electric operating
revenue does not include the charges for electric energy but does include the revenue
required to cover power delivery.
4. For line 3, Electric Operating Revenue from Sales for Resale, enter the amount of
revenue from sales of electricity sold for resale purposes. This entry should include
revenue from sales for resale to wholesale or retail power marketers, full and partial
requirements customers (firm) and to nonrequirements (nonfirm) customers. This entry
should also correspond to the sales for resale reported in Schedule 2, Part B, line 12.
5. For line 4, Electric Credits/Other Adjustments, enter the amount of deferred revenue,
which corresponds to Account 449.1 of the Uniform System of Accounts including revenue
not applied to end-use or resale customers during the normal billing cycle. Funds included
in this entry consist of refunds to customers resulting from rate commission rulings
delayed beyond the reporting year in which the funds were originally collected. Also,
include revenue distributions to customers from rate stabilization funds where the
distribution occurred during the current reporting year but the funds were collected during
previous reporting years.
6. For line 5, Other Electric Operating Revenue, enter the amount of revenue received
6

U.S. Department of Energy
Form Approved
ANNUAL ELECTRIC POWER
Energy Information Administration
OMB No. 1905-0129
INDUSTRY REPORT
Form EIA-861 (2007)
Approval Expires: 11/30/2010
from electric activities other than selling electricity. This may include revenue from selling
or servicing electric appliances, revenue from the sale of water and water power for
irrigation, domestic, industrial or hydroelectric operations, revenue from electric plants
leased to others, revenue from the transmission of electricity for others (wheeling),
revenue from the sale of steam, but not including sales made by a steam heating
department or transfers of steam under joint facility operations, revenue from
interdepartmental rents or sale of electric property, revenue from late fees, penalties or
reconnections, and revenue from interest.
7. For line 6, Total Electric Operating Revenue, enter the total revenue received by your
company for the reporting year (sum of lines 1, 2, 3, 4, and 5).
SCHEDULE 4. PART A. SALES TO ULTIMATE CUSTOMERS.
FULL SERVICE – ENERGY AND DELIVERY SERVICE (BUNDLED)
Please note that data for the Transportation Sector (see definitions) has replaced the
“Other” Sector on all parts of Schedule IV. Non-Transportation customers previously
reported under “Other,” including street and highway lighting, should now be
included in the Commercial Sector. Irrigation customers should be reported in the
Industrial Sector.
Enter the reporting year revenue (thousand dollars), megawatthours, and number of
customers for sales of electricity to ultimate customers by State and customer class category
for whom your company provides both energy and delivery service. Power marketers
providing both energy and delivery service should report on Part D. Note: For sales to
customer groups using brokers or aggregators, continue to count each customer separately.
For instance, count a group of franchised commercial establishments aggregated through a
single broker as separate customers (as reported in prior years). Enter the 2-letter U.S.
Postal Service abbreviation for the State in which the electric sales occurred.
SCHEDULE 4. PART B. SALES TO ULTIMATE CUSTOMERS.
ENERGY – ONLY SERVICE (WITHOUT DELIVERY SERVICE)
Enter the reporting year revenue (thousand dollars), megawatthours, and number of
customers for sales of electricity to ultimate customers by State and customer class category
for whom your company provides only the energy consumed, where another electric utility
provides delivery services, including, for example, billing, administrative support, and line
maintenance.
SCHEDULE 4. PART C. SALES TO ULTIMATE CUSTOMERS.
DELIVERY – ONLY SERVICE (AND ALL OTHER CHARGES)
Enter the reporting year revenue (thousand dollars), megawatthours delivered, and number
of customers for sales of electricity to ultimate customers in your service territory by State
and customer class category for whom your company provides only billing and related
energy delivery services, where another company supplies the energy.
SCHEDULE 4. PART D. SALES TO ULTIMATE CUSTOMERS. BUNDLED SERVICE BY
RETAIL ENERGY PROVIDERS, OR ANY POWER MARKETER THAT PROVIDES
“BUNDLED SERVICE”
Enter the reporting period revenue (thousand dollars), megawatthours, and number of
customers for sales of electricity to ultimate customers by State and customer class category
for whom your company provided both energy and delivery service. For public street and
highway lighting, count all poles in a community as one customer. Note: For sales to
customer groups using brokers or aggregators, continue to count each customer separately.
For instance, count a group of franchised commercial establishments aggregated through a
single broker as separate customers (as reported in prior years). Enter the two-letter U.S.
Postal Service abbreviation (if not preprinted) for the State in which the electric sales occur.
(Note: Texas Retail Energy Providers (REPs) should include delivery revenues.)
7

U.S. Department of Energy
Energy Information Administration
Form EIA-861 (2007)

ANNUAL ELECTRIC POWER
INDUSTRY REPORT

Form Approved
OMB No. 1905-0129
Approval Expires: 11/30/2010

Common Instructions: SCHEDULE 4. PARTS A, B, C, AND D
1. For column a, Residential, enter the revenue, megawatthours, and number of customers
for electric energy supplied for residential (household) purposes. For the residential class,
do not duplicate the customer accounts due to multiple metering for special services
(e.g., water heating, etc.).
2. For column b, Commercial, enter the revenue, megawatthours, and number of
customers for electric energy supplied for commercial purposes.
3. For column c, Industrial, enter the revenue, megawatthours, and number of customers
for electric energy supplied for industrial purposes.
4. For column d, Transportation, enter the revenue, megawatthours, and number of
customers for electric energy supplied for transportation purposes.
5. For column e, Total, enter for each State, the sum of the revenue, megawatthours, and
number of customers entered for residential, commercial, industrial, and transportation
sales. For IDC system users, this column will be automatically populated.
SCHEDULE 5. MERGERS AND/OR ACQUISITIONS
If a merger or acquisition has occurred during the reporting period, report those newlyacquired corporate entities whose operations are now included in this report.
SCHEDULE 6. DEMAND-SIDE MANAGEMENT INFORMATION
Demand-side management (DSM) programs are designed to modify patterns of electricity
usage, including the timing and level of electricity demand. Schedule 6 is divided into four
parts: Part A, Actual Effects, Part B, Annual Costs, Part C, Supplemental Information, and
Part D, Advanced Metering. Schedule 6 is to be completed by all respondents with a
company-administered demand-side management (DSM) program, company-administered
demand response programs, or companies which have implemented advanced metering
programs. On Parts A and B only, companies with both sales to ultimate customers and
sales for resale which are less than 150,000 megawatthours are required to complete only
the INCREMENTAL EFFECTS portion of Part A and annual cost to achieve in Part B, line
13, Total Cost, before continuing with Part C and Part D.
The DSM information provided should: 1) reflect only activities that are undertaken
specifically in response to company-administered programs, including activities implemented
by third parties under contract to the company; 2) account for the complete range of DSM
programs, including energy efficiency and load management; and 3) represent the energy
and load effects at the customer meter (i.e., transmission and distribution or reserve
requirement savings should be excluded). The DSM information should exclude, to the
extent possible, energy and load effects that are not attributable to DSM program activities.
Non-program related effects include changes in energy and load attributable to: 1) nonparticipants (e.g., customers known as free-riders, who would adopt program-recommended
actions even without the program); 2) government-mandated energy-efficiency standards
that legislate improvements in building and appliance energy usage; 3) natural operations of
the marketplace (e.g., reductions in customer energy usage due to higher prices); and 4)
weather and business-cycle fluctuations.
Power supply cooperatives, municipal joint action agencies, and Federal Power Marketing
Administrations are encouraged to coordinate the reporting of DSM information with their
power purchasing utilities to avoid double counting the effects and costs of DSM programs.
Utilities that have their DSM activities reported on the SCHEDULE 6 of another company
should name that company in the space provided on line 2 of the schedule and not complete
the SCHEDULE 6 themselves.
8

U.S. Department of Energy
Energy Information Administration
Form EIA-861 (2007)

ANNUAL ELECTRIC POWER
INDUSTRY REPORT

Form Approved
OMB No. 1905-0129
Approval Expires: 11/30/2010

SCHEDULE 6. PART A. ACTUAL EFFECTS
This part of the Schedule collects information on the energy and load effects of DSM programs
implemented, and measures installed, for each program category by major customer sector. It
is divided into two subparts, Incremental Effects and Annual Effects.
1. Incremental Effects: The changes in energy use (measured in megawatthours) and peak
load (measured in megawatts) caused in the current reporting year by new participants in
your existing DSM programs and all participants in your new DSM programs. Reported
Incremental Effects should be annualized to indicate the program effects that would have
occurred had these participants been initiated into the program on January 1 of the current
reporting year.
2. Annual Effects: The total changes in energy use (measured in megawatthours) and peak
load (measured in megawatts) caused in the current reporting year by all participants in all
of your DSM programs. This includes new and existing participants in existing programs
(those implemented prior to the current reporting year that were in place during prior
reporting year), all participants in new programs (those implemented during current
reporting year), and participants in programs terminated since 1992 (those effects continue
even though the programs have been discontinued). DSM programs have a useful life, and
the net effects of these programs will diminish over time. To the extent possible, the
Annual Effects should consider the useful life of efficiency and load control measures by
accounting for building demolition, equipment degradation, and program attrition. The
effects of new participants in existing programs and all participants in new programs should
be based on their start-up dates (i.e., if participants enter a program in July, only the effects
from July to December are to be reported). If start-up dates are unknown and cannot be
reasonably estimated, the effects can be annualized (i.e., assume the participants were
initiated into the program on January 1). Please note that Annual Effects are not a
summation of 12 monthly peaks, but are the total DSM program effects of all programs and
all participants for the current reporting year.
3. For Part A, under the appropriate customer sector: Residential, Commercial, Industrial, and
Transportation, enter the aggregate Energy Effects (megawatthours, to the third decimal
point, if possible) and Actual Peak Reduction (megawatts to the third decimal point, if
possible) attributable to Energy Efficiency and Load Management programs. For Load
Management also enter the Potential Peak Reduction (megawatts to the third decimal
point, if possible) attributable to each customer sector.
SCHEDULE 6. PART B. ANNUAL COSTS
This part of the schedule collects information on actual DSM program costs in the current
reporting year. Program costs consist of the cash expenditures, reported in thousands of
dollars, incurred by the company. Costs should reflect the total cash expenditures for the year,
reported in thousands of dollars that flow out to support DSM programs. They should be
reported in the year they are incurred, regardless of when the actual effects occurred. For
example, the cash expenditures to purchase 1,000 load control devices for installation in
customers' homes could be incurred a year in advance of the actual load savings that result
from operation of the devices.
Total Cost: In column (a), enter your actual Direct Costs, Incentive Payments, and Indirect
Costs, incurred in the current reporting year. Report Energy Efficiency and Load Management
Costs separately. Direct Costs are those costs that are directly attributable to a particular DSM
program (e.g., Energy Efficiency or Load Management). Indirect Costs are costs that may not
be meaningfully included in any program category, but could be identified with an accounting
cost category (e.g., Administrative, Marketing, Monitoring & Evaluation, Company-Earned
Incentives, Other).
Percentage of Cost: If you are reporting DSM program costs for more than one State, in
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U.S. Department of Energy
Form Approved
ANNUAL ELECTRIC POWER
Energy Information Administration
OMB No. 1905-0129
INDUSTRY REPORT
Form EIA-861 (2007)
Approval Expires: 11/30/2010
columns (b) through (e) provide the estimated percentage of those costs reported in column
(a). If you are reporting program costs in more than four States, duplicate the sheet and attach
the extra pages.
SCHEDULE 6. PART C. SUPPLEMENTAL INFORMATION
1. Please indicate, by checking “Yes” or “No” on line 14, whether DSM program changes,
tracking procedures, evaluations, or reporting methods have affected the data reported on
this schedule (since 1992).
2. Please indicate, by checking “Yes” or “No” on line 15, whether your company currently
operates any incentive-based demand response programs, i.e. direct load control,
interruptible programs, demand bidding/buyback, emergency demand response, capacity
market programs, and ancillary service market programs. If the answer is “Yes,” enter the
number of participating customers, by class, on line 16.
3. Please indicate, by checking “Yes” or “No” on line 17, whether your company currently
operates any time-based rate programs, e.g., real-time pricing, critical peak pricing, variable
peak pricing and time-of-use rates. If the answer is “Yes,” enter the number of participating
customers, by class, on line 18.
SCHEDULE 6. PART D. ADVANCED METERING
Standard (Electric) Meters are electromechanical or solid state meters measuring aggregated
kWh where data are manually retrieved over monthly billing cycles for billing purposes only.
Standard meters may also include functions to measure time-of-use and/or demand with data
manually retrieved over monthly billing cycles. The number of standard meters may be equal
to the number of customers on Schedule 4.
Automated Meter Reading (AMR): Meters that collect data for billing purposes only and
transmit this data one way, usually from the customer to the distribution utility. Aggregated
monthly kWh data captured on these meters may be retrieved by a variety of methods including
drive-by vans with short-distance remote reading capabilities and communication over a fixed
network such as a cellular network.
Enter the state and report the total number of AMR meters by sector. If your meters are in
more than one State, provide additional information on Schedule 9, Footnotes. The number of
AMR meters may be equal to the number of customers on Schedule 4.
Advanced Metering Infrastructure (AMI): Meters that measure and record usage data at a
minimum, in hourly intervals, and provide usage data to both consumers and energy
companies at least once daily. Data are used for billing and other purposes. Advanced meters
include basic hourly interval meters and extend to real-time meters with built-in two-way
communication capable of recording and transmitting instantaneous data.
Enter the state and report the total number of AMI meters by sector. If your AMI meters are in
more than one State, provide additional information on Schedule 9, Footnotes
Energy Served Through AMI (MWh) should be entered in megawatthours for customers
served.
SCHEDULE 7. DISTRIBUTED AND DISPERSED GENERATION
This schedule collects information from distribution companies on industrial and commercial
generators of less than 1 megawatt (1000 kilowatts) installed at or near a customer’s site, or
other sites within the system. Provide all of the requested information for grid
connected/synchronized distributed generators in column a, and for dispersed generators that
are not grid connected/synchronized in column b. Provide actual data if available, otherwise
provide best estimates, and indicate the nature of the data by checking the appropriate box on
the form.
Schedule 7 is intended to collect information about generators on the system that are NOT
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U.S. Department of Energy
Form Approved
ANNUAL ELECTRIC POWER
Energy Information Administration
OMB No. 1905-0129
INDUSTRY REPORT
Form EIA-861 (2007)
Approval Expires: 11/30/2010
reported on Form EIA-860, “Annual Electric Generator Report.” Plants with capacity of 1 MW
or greater which ARE grid-connected, meet the threshold criteria for reporting on the 860 and
as such, need not be reported on Schedule 7 of the EIA-861. Residential applications should
not be reported.
SCHEDULE 7. PART A. NUMBER AND CAPACITY
1. For line 1, Number of generators, provide in column (a), the number of distributed
generators in the area served by your distribution system of less than 1 megawatt. In column
(b), provide the number of dispersed generators of less than 1 megawatt. If you are unable
to provide the breakout, please explain in Schedule 9, Footnotes.
2. For line 2, columns (a) and (b), Total combined nameplate capacity (MW), provide the
total nameplate capacity of all generators reported on line 1.
3. For line 3, columns (a) and (b), Percent of nameplate capacity that consists of backuponly units, provide the percentage of the nameplate capacity listed in line 2 that is
comprised of generators that are used only for emergency backup service.
4. For Line 4, columns (a) and (b), Percent of capacity owned by respondent, provide the
percentage of the nameplate capacity listed in line 2 that the respondent owns.
5. For Line 5, columns (a) and (b), Nature of data reported, provide actual data if available,
otherwise provide best estimates, and indicate the nature of the data by checking the
appropriate box on the form.
6. For Line 6, columns (a) and (b), State, provide the 2-letter U.S. Postal Service abbreviation
for the State in which the generators are located. If you are reporting distributed or dispersed
generators for additional States, provide additional information on Schedule 9, Footnotes.
SCHEDULE 7. PART B, TYPES OF GENERATORS (%)
For each of the generator types listed in columns (a) and (b), lines 1 through 6, provide the
percentage of the total capacity (reported in Part A, line 2, columns (a) and (b), respectively)
that each generator type comprises. The total of lines 1 through 6 should equal 100 percent in
each column, (a) and (b).
SCHEDULE 8 - DISTRIBUTION SYSTEM INFORMATION
Please verify the EIA provided names of the counties, parishes, etc., by State, where your
utility-owned distribution system’s electrical equipment are located. The information may have
been reported by the respondent last year or the result of independent research by the EIA staff
processing the Form EIA-861. Correct or add information and systems as needed.
SCHEDULE 9 – COMMENTS

GLOSSARY
SANCTIONS

This schedule provides additional space for comments. For clarification purposes, identify
schedule, part, line number and column (if applicable) for each comment.
The glossary for this form is available online at the following URL:
http://www.eia.doe.gov/glossary/index.html
The timely submission of Form EIA-861 by those required to report is mandatory under Section
13(b) of the Federal Energy Administration Act of 1974 (FEAA) (Public Law 93-275), as
amended. Failure to respond may result in a penalty of not more than $2,750 per day for each
civil violation, or a fine of not more than $5,000 per day for each criminal violation. The
government may bring a civil action to prohibit reporting violations, which may result in a
temporary restraining order or a preliminary or permanent injunction without bond. In such civil
action, the court may also issue mandatory injunctions commanding any person to comply with
these reporting requirements. Title 18 U.S.C. 1001 makes it a criminal offense for any
person knowingly and willingly to make to any Agency or Department of the United
11

U.S. Department of Energy
Form Approved
ANNUAL ELECTRIC POWER
Energy Information Administration
OMB No. 1905-0129
INDUSTRY REPORT
Form EIA-861 (2007)
Approval Expires: 11/30/2010
States any false, fictitious, or fraudulent statements as to any matter within its
jurisdiction.
REPORTING
BURDEN

PROVISIONS
REGARDING
CONFIDENTIALITY
OF INFORMATION

Public reporting burden for this collection of information is estimated to average 8.0 hours per
response, including the time for reviewing instructions, searching existing data sources,
gathering and maintaining the data needed, and completing and reviewing the collection of
information. Send comments regarding this burden estimate or any other aspect of this
collection of information, including suggestions for reducing this burden, to the Energy
Information Administration, Statistics and Methods Group, EI-70, 1000 Independence Avenue
S.W., Forrestal Building, Washington, D.C. 20585-0670; and to the Office of Information and
Regulatory Affairs, Office of Management and Budget, Washington, D.C. 20503. A person is
not required to respond to the collection of information unless the form displays a valid OMB
number.
Information reported on Form EIA-861 will be treated as non-sensitive and may be publicly
released in identifiable form. In addition to the use of the information by EIA for statistical
purposes, the information may be used for any nonstatistical purposes such as administrative,
regulatory, law enforcement, or adjudicatory purposes.

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