Form EIA 861 Instructions

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ANNUAL ELECTRIC POWER
INDUSTRY REPORT
INSTRUCTIONS
FORM EIA-861 OMB No. 1905-0129
Approval Expires: 12/31/2015
Burden: 9.0 hrs
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 power industry entities including: electric
utilities, all DSM Program Managers
(entities responsible for conducting or administering a
DSM program),
wholesale power marketers (registered with the Federal Energy Regulatory
Commission), energy service providers (registere
d with the States), and electric power
producers. Entities that report using the Form EIA-861S do not complete the EIA-861 form.
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 (e-file). 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 email requesting
assistance to: EIA-861@eia.gov.
• If you have registered with Single Sign-On, log on at
https://signon.eia.gov/ssoserver/login
• If you are having a technical problem with logging into e-file or using e-file contact the
Help Desk for further information. Contact the Help Desk at:
Email: EIASurveyHelpCenter@eia.gov
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 e-file, see the help contact information
immediately above.
Data Questions: For questions about the data requested on Form EIA-861, contact the Survey
Manager, preferably via email at EIA-861@eia.gov.
Jorge Luna-Camara Stephen Scott
(202) 586-3945 (202) 586-5140
FAX Number: (202) 287-1938
ANNUAL ELECTRIC POWER
INDUSTRY REPORT
INSTRUCTIONS
FORM EIA-861 OMB No. 1905-0129
Approval Expires: 12/31/2015
Burden: 9.0 hrs
GENERAL
INSTRUCTIONS
Submit the completed Form EIA-861 to the EIA by April 30, following the end of the
calendar year.
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 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. For example: revenue of $8,459,688.42 should be reported as 8,460
(thousand dollars). There is one decimal place for revenue on Schedule 3 and Schedule4
(A-D); and lines 4, 6 and 7 on Schedule 6A.
5. A state code can only be removed by highlighting the state and clicking on the Remove
Record button. The Remove Record button is located along the top row of the form (same
row as the save and print button).
6. 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 4, 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.
7. Use a minus sign for reporting negative numbers. Line 9 on schedule 2B must be a
negative number. On schedule 2B, line 1 and schedule 3, line 4 and 5, the number may
either positive or negative.
8. Where exact data are unavailable, report estimated data.
9. 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).
ANNUAL ELECTRIC POWER
INDUSTRY REPORT
INSTRUCTIONS
FORM EIA-861 OMB No. 1905-0129
Approval Expires: 12/31/2015
Burden: 9.0 hrs
ITEM-BY-ITEM
INSTRUCTIONS
SCHEDULE 1: IDENTIFICATION
1. Survey Contact: Verify contact name, title, address, telephone number, fax number, and
address.
2. Supervisor of Contact Person for Survey: Verify the contact’s supervisor’s name, title,
address, telephone number, fax number and address. Supervisor contact must be
different than the survey contact.
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.
Entity and Preparer Information
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.
SCHEDULE 2 - PART A: GENERAL INFORMATION
1. For line 1, please check all of the Regional Entities within the North American Electric
Reliability Corporation (NERC), in which your organization conducts operations.
The Regional Entities are:
TRE .................... Texas Regional Entity
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
For line 1a, select the RTO or ISO from the list:
California ISO
Electric Reliability Council of Texas
Southwest Power Pool
Midwest ISO
PJM Interconnection
New York ISO
ISO New England
None
ANNUAL ELECTRIC POWER
INDUSTRY REPORT
INSTRUCTIONS
FORM EIA-861 OMB No. 1905-0129
Approval Expires: 12/31/2015
Burden: 9.0 hrs
2. For line 3, Balancing Authority(s), enter the name of the balancing authority(s)
responsible for your oversight. If your balancing authority is not on the list, use “Other” and
list the authority on Schedule 9 (Footnotes).
3. For line 4, Operate Generating Plant(s), Check Yes to indicate that your 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. If your activity is not listed on line 5 please include a description
on Schedule 9 (Footnotes). You must check at least one.
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.
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.”
Combined 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, to
the nearest tenth.
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 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 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.
ANNUAL ELECTRIC POWER
INDUSTRY REPORT
INSTRUCTIONS
FORM EIA-861 OMB No. 1905-0129
Approval Expires: 12/31/2015
Burden: 9.0 hrs
SCHEDULE 2 - PART B: ENERGY SOURCES AND DISPOSITION
1. Enter the annual megawatthours (MWh) for all sources of electricity and disposition of
electricity 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
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 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, B and
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FORM EIA-861 OMB No. 1905-0129
Approval Expires: 12/31/2015
Burden: 9.0 hrs
D, when summed for all reported States.
12. 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.
13. 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 street and highway lighting. This entry does not include data entered in line 14.
14. 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.
15. 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.
SCHEDULE 2 - PART C: GREEN PRICING
• Revenue should no longer include the base cost of electricity. It should now
include only the premium paid by the retail customer.
Green Pricing programs are voluntary retail programs only. Do not include mandatory
wholesale purchases of RECs to meet state Renewable Portfolio Standards
Green Pricing programs allow electricity customers the opportunity to purchase electricity
generated from renewable resources and to pay for renewable energy development.
Renewable resources include solar, wind, geothermal, hydroelectric power, and wood.
Revenue should only
include premium revenue from the green pricing program.
Line1: Report the Total Green Pricing Revenue for customers in each customer class.
Revenue should be reported in thousands of dollars to the nearest tenth (for example,
$1,299 would be reported as 1.299 thousand dollars). Revenue should only include
money derived from premium green pricing rate of your program. Below are two of the
most common ways to calculate Total Green Pricing Revenue:
Assumption: 1,000 kWh (or 1 MWh) of Green electricity sales
a) An entity sells Green Energy in blocks of $2.50 per 100 kWh-block:
Total cost = ($2.50/100kWh-block) x (1000 kWh)
= ($0.025) X (1000 kWh)
= $25.00 OR
b) A Utility which sells Green Energy for a premium of $0.05 per kWh:
Total cost = ($0.05/kWh) X (1,000kWh)
= $50.00
Line 2: Report the Total Green Pricing Sales, the total amount of megawatthours
purchased by customers for each green pricing customer class (for example, 1,299 kWh
would be reported as 1.299 MWh).
Line 3: Report the Total Green Pricing Customers, the number of customers who
ANNUAL ELECTRIC POWER
INDUSTRY REPORT
INSTRUCTIONS
FORM EIA-861 OMB No. 1905-0129
Approval Expires: 12/31/2015
Burden: 9.0 hrs
purchased green power for each customer class. The sales volumes and the number of
customers should not exceed the values reported in Schedule 4, Parts A, B, or D.
The Total for each customer class will automatically sum for the electronic online e-
file system.
SCHEDULE 2 - PART D: NET METERING
Net Metering tariff arrangements permit a facility, typically generating electricity from a
renewable resource, (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,
typically at a rate equivalent to the retail price of electricity.
For net metering applications of 2 MW nameplate capacity or less, report the installed net
metering capacity by State, customer class and technology. Report net metering data by
sector and technology type for each state. Capacity should be reported in MW as AC load
capable. Example: 8 kW should be 0.008 MW. Capacities should not exceed limits set up
by each state. Please provide this capacity in MW, to the nearest 0.001 MW by
technology. Do not report for net metering applications larger than 2 MW.
Report the number of net metering customers by customer class. They should not exceed
the values in Schedule 4 Parts A and C. If you are unable to utilize the e-file system which
creates the totals automatically
; then provide the Totals for net metering megawatt hours,
installed net metering capacity and customers by State, customer class and technology.
Complete all lines for Schedule 2, Part D; if the data is available, enter the amount of
electric energy sold back to the utility (MWh)
SCHEDULE 3: ELECTRIC OPERATING REVENUE
1. All electric operating revenue data should be rounded to the nearest tenth and reported in
thousand dollars (for example, revenue of $8,461,688.42 should be reported as 8,461.7
(thousand dollars).
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
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Approval Expires: 12/31/2015
Burden: 9.0 hrs
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, Revenue from Transmission, enter the amount of revenue derived from the
transmission of electricity for others (wheeling).
7. For line 6, Other Electric Operating Revenue, enter the amount of revenue received
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 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.
SCHEDULE 4: Sector Groupings
The table below should be used as a guide for the classification of your end-use customers;
pay close attention to how your consumers should be organized based on our four Sectors:
Residential, Commercial, Industrial, and Transportation. Please note that data for the
Transportation Sector (see definitions) has replaced the “Other” Sector on all parts of
Schedule 4. 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.
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The residential sector includes private
households and apartment buildings where
energy is consumed primarily for:
• space heating,
• water heating,
• air conditioning,
• lighting,
• refrigeration,
• cooking, and
• clothes drying.
The commercial sector includes
nonmanufacturing business establishments
such as:
• hotels,
• motels,
• restaurants,
• wholesale businesses,
• retail stores, and
• health, social, and educational
institutions.
• public street and highway lighting,
• municipalities,
• divisions or agencies of State and
Federal Governments under special
contracts or agreements, and other
utility departments, as defined by the
pertinent regulatory agency and/or
electric utility.
The industrial sector includes:
• manufacturing,
• construction,
• mining,
• agriculture (irrigation),
• fishing, and
• forestry establishments.
The transportation sector includes:
• railroads and railways (the fuel
source of propulsion must be like a
metro system which only exists in
large cities costing millions of
dollars)
SCHEDULE 4 - PART A: SALES TO ULTIMATE CUSTOMERS -
FULL SERVICE ENERGY AND DELIVERY SERVICE (BUNDLED)
Enter the reporting year revenue (thousand dollars, to the nearest tenth), 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, to the nearest tenth), megawatthours,
and number of customers for sales of electricity to ultimate customers by State and customer
class category for which your company provides only the energy consumed, where another
electric utility provides delivery services, including, for example, billing, administrative
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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, to the nearest tenth), megawatthours
delivered, and number of customers for sales of electricity to ultimate customers in your
service territory by State and customer class category for which 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”
Note: typically, the only entities that report on Schedule D are Texas Retail Energy
Providers. Any other entity that believes it should report on Schedule D should first contact
EIA.
Enter the reporting period revenue (thousand dollars, to the nearest tenth), 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.)
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.
SCHEDULE 5: MERGERS AND/OR ACQUISITIONS
If a merger or acquisition has occurred during the reporting period, report those newly-
acquired 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
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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 DSM program
managers (entities responsible for conducting or administering a DSM program). In previous
years, companies with sales to ultimate customers or sales for resale which were less than
150,000 megawatthours were required to complete only the INCREMENTAL EFFECTS
portion of Part A and annual cost to achieve in Part B, line 13, Total Cost. For this
reporting year and forward, all companies including those non-utility DSM Program
Managers are required to complete the entire schedule.
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) non-participants (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 should 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 Schedule 6 of another company should name that
company in the space provided on line 2 of the schedule and proceed to Schedule 6, Part D.
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
within a State. It is divided into two subparts, Incremental Effects and Annual Effects.
Incremental Effects: are those changes in energy use (measured in megawatthours) and
peak load (measured in megawatts) caused in the current reporting year by new
participants in DSM programs that already existed in the previous reporting year, and all
participants in your new DSM programs that existed for the first time in the current reporting
year. Reported Incremental Effects should be annualized.
Please leave blanks, not zeros, if the questions do not apply. For example, if your
company operates industrial programs but does not expect any incremental effects in the
current reporting year, the field would have a value of zero. However, if your company
does not operate any industrial programs, then the field should be left blank.
ANNUAL ELECTRIC POWER
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INSTRUCTIONS
FORM EIA-861 OMB No. 1905-0129
Approval Expires: 12/31/2015
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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.
For both sections of Part A – “Annualized Incremental Effects” and “Actual Annual Effects” -
enter the aggregate Energy Effects (megawatthours, to one decimal point, if possible) and
Actual Peak Reduction (megawatts to one decimal point, if possible) attributable to Energy
Efficiency and Load Management programs under the appropriate customer sector
(Residential, Commercial, Industrial, and Transportation). For Load Management on Line 5
enter the Energy Effects: on Line 6 (Potential Peak Reduction) and Line 7 (Actual Peak
Reduction, enter the amount attributable to each customer sector (megawatts to one
decimal point, if possible).
Please leave blanks, not zeros, if the questions do not apply. For example, your company
operates industrial programs but does not expect any incremental effects in the current
reporting year, the field would have a value of zero. However, if your company does not
operate any industrial programs, then the field should be left blank.
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.
Annual Costs: For each State enter for each sector your actual Direct Costs, Incentive
Payments, and Indirect Costs, incurred in the current reporting year.
Direct Costs are those costs that are directly attributable to a particular DSM program (e.g.,
Energy Efficiency or Load Management).
Incentives are the total financial value provided to a customer for program participation,
whether cash payment, in-kind services (e.g. design work), or other benefits directly provided
customer for their program participation.
Indirect Costs may include other costs that have not been included in any program category,
but could be meaningfully identified with operating the company’s DSM programs (e.g.,
Administrative, Marketing, Monitoring & Evaluation, Company-Earned Incentives, Other).
Report Energy Efficiency and Load Management Costs separately. The Total Cost row,
line 13 and the Total column (e) will be summed automatically for respondents that file
electronically through the e-file system. Provide the actual costs breakdown in thousand
ANNUAL ELECTRIC POWER
INDUSTRY REPORT
INSTRUCTIONS
FORM EIA-861 OMB No. 1905-0129
Approval Expires: 12/31/2015
Burden: 9.0 hrs
dollars.
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 state and 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 administered through a tariff. If the answer is “Yes,”
enter the number of participating customers, by state and class, on line 18.
SCHEDULE 6 - PART D: ADVANCED METERING
This schedule should only include customers from Schedule 4 Part A or Part C.
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.
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.
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.
For AMI meters that are only being used as AMR, report meters as AMR.
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. Also provide the data on all industrial and
commercial dispersed generators in the Total column. Provide actual data if available,
otherwise provide best estimates, and indicate the nature of the data by checking the
ANNUAL ELECTRIC POWER
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INSTRUCTIONS
FORM EIA-861 OMB No. 1905-0129
Approval Expires: 12/31/2015
Burden: 9.0 hrs
appropriate box on the form.
Schedule 7 is intended to collect information about generators on the systems that are
NOT 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 (less than 1 megawatt). In column (b),
provide the number of dispersed generators. (less than 1 megawatt). If you are unable to
provide the breakout, please explain in Schedule 9 (Footnotes).
2. For line 2 "Total combined capacity" columns (a) and (b), provide the nameplate capacity (to
the nearest tenth) for all generators with less than 1 megawatt that were reported on line 1.
3. For line 3, “Capacity that consists of backup-only units”, provide the total nameplate capacity
of generators in columns (a) and (b) that are used only for emergency backup service.
4. For Line 4 “Capacity Owned by Respondent” provide the total nameplate capacity in columns
(a) and (b) for the units listed in line 2 that the respondent owns.
5. For Line 5 “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.
SCHEDULE 7 - PART B: CAPACITY BY GENERATING TYPE AND TECHNOLOGY
For each of the technologies listed in columns (a) and (b), lines 1 through 8, provide the
capacity. The total of lines 1 through 8 (line 9) should equal the total combined capacity in Line
2 of each column.
SCHEDULE 8: DISTRIBUTION SYSTEM INFORMATION
Please verify the EIA provided names of the counties, parishes, etc. (dropdown menu), 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. If the information is incorrect, please
provide the correct information in Schedule 9 (Footnotes).
SCHEDULE 9: Footnotes
This schedule provides additional space for comments. For clarification purposes, identify
schedule, part, line number and column (if applicable) for each comment.
ANNUAL ELECTRIC POWER
INDUSTRY REPORT
INSTRUCTIONS
FORM EIA-861 OMB No. 1905-0129
Approval Expires: 12/31/2015
Burden: 9.0 hrs
GLOSSARY
The glossary for this form is available online at the following URL:
http://www.eia.gov/glossary/index.html
SANCTIONS
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
States any false, fictitious, or fraudulent statements as to any matter within its
jurisdiction.
REPORTING
BURDEN
Public reporting burden for this collection of information is estimated to average 9.0 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 U.S. Energy
Information Administration, Office of Survey Development and Statistical Integration, MS EI-21
Forrestal Building, 1000 Independence Avenue, SW, 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.
PROVISIONS
REGARDING
CONFIDENTIALITY
OF INFORMATION
Information reported on Form EIA-861 will be treated as public information and may be publicly
released in identifiable form.

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