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 (registered 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
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FORM EIA-861 OMB No. 1905-0129

Approval Expires: 12/31/2015

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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 
ANNUAL ELECTRIC POWER 

INDUSTRY REPORT

INSTRUCTIONS

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 efile 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 
ANNUAL ELECTRIC POWER 

INDUSTRY REPORT

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FORM EIA-861 OMB No. 1905-0129

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.
ANNUAL ELECTRIC POWER 

INDUSTRY REPORT

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FORM EIA-861 OMB No. 1905-0129

Approval Expires: 12/31/2015

Burden: 9.0 hrs 

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 
ANNUAL ELECTRIC POWER 

INDUSTRY REPORT

INSTRUCTIONS

FORM EIA-861 OMB No. 1905-0129

Approval Expires: 12/31/2015

Burden: 9.0 hrs 

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 twoletter 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 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
ANNUAL ELECTRIC POWER 

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FORM EIA-861 OMB No. 1905-0129

Approval Expires: 12/31/2015

Burden: 9.0 hrs 

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 companyadministered 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 programrecommended 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

Burden: 9.0 hrs 

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 twoway 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 

INDUSTRY REPORT

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.