Greenhouse Gas Reporting Protocols for Investor Owned Utilities and Electricity Service Suppliers

Oregon rules require each investor owned utility and electricity service supplier to report greenhouse gas emissions from electricity they imported, sold, allocated or distributed to end users in Oregon where that electricity was generated from facilities they own or operate. Companies must report these emissions using the form provided above. This form includes space for the company to input the generating fuel type, quantity of electricity distributed for use in Oregon, and corresponding anthropogenic and biogenic emission factors. The form automatically calculates total emissions from this information.

Each company needs to determine emission factors for electricity generated at facilities owned or operated by the company. The company will need to determine the emissions factors in metric tons of carbon dioxide equivalent per megawatt-hour. Companies must use a 2% transmission loss correction factor when determining emission factors for electricity not measured at the busbar of the generating facility. Companies reporting emissions from geothermal energy may use the default greenhouse gas emission factor published by the U.S. Energy Information Administration or derive an emission factor using engineering estimates based on monitoring data or other information specific to the facility.

Each company must also provide supplemental documentation that explains how the emission factors were calculated, including the necessary information for DEQ to verify these calculations. The supplemental documentation can be emailed with the completed form, or mailed with the signed summary page from the form.

Oregon rules require investor owned utilities and electricity service suppliers to report greenhouse gas emissions from the generation of electricity they purchase and distribute to end users in Oregon. These rules also require reporting of certain additional information about these purchases, including the number of megawatt-hours of electricity purchased, the original generating fuel type or types, and information, if known, on the seller.

Companies must report greenhouse gas emissions from purchased electricity generated by natural gas or coal using the information in the table below. These default emission factors are derived using average heat rate data published by the Energy Information Agency and the data in Table 1 of OAR 340-215-0040.

EIA only publishes national average heat rates for coal and natural gas. Companies do not need to report greenhouse gas emissions for purchases of electricity generated by other known fuel types. For purchases of electricity generated by a known fuel type that is not coal or natural gas, companies only need to report megawatt hours provided in Oregon, the generating fuel type, and known identifying information on the seller.

Companies must use a 2 percent transmission loss correction factor when calculating emissions for electricity not measured at the busbar of the generating facility.

Electricity purchased from an unknown seller or from a seller who is unable to identify the generating fuel type, must be reported using the "Unknown" fuel type available in the form provided above. Companies must also report the megawatt hours of these electricity purchases and estimate greenhouse gas emissions using a default emission factor of 1,100 pounds of carbon dioxide equivalent per megawatt-hour.

For each electricity purchase, the company must provide supplemental documentation with information about the seller, if known, including the name of the company, contact information at that company, and the location of the generating facility. If any of this information is not known, this must be indicated in the supplemental documentation or in the space provided on the form.

This supplemental documentation can be either emailed electronically with the completed form, or mailed with the signed summary page of the form.

Oregon rules require companies to report the number of megawatt-hours of electricity purchased for which a renewable energy certificate under ORS 469A.130 has been issued but subsequently transferred or sold to another entity. The form includes a worksheet to record this information separately from and in addition to emissions reported for electricity purchases.

Investor owned utilities and electricity service suppliers must determine SF6 emissions from transmission and distribution equipment they own or operate pursuant to methodologies included in 40 CFR Part 98, Subpart DD with a modification to delineate emissions for Oregon. While EPA’s protocols require reporting of the total emissions for all equipment owned or operated by the company, each company must estimate the emissions associated with their provision of electricity to Oregonians in their report to DEQ. Each company must do this by calculating the SF6 emissions based upon the portion of electricity they supply to Oregon end users. Companies must do this by first calculating the total SF6 emissions from all their transmission and distribution equipment pursuant to 40 CFR Part 98, Subpart DD, and  then multiplying these emissions by the ratio of the amount of electricity the utility supplied to Oregon end users compared to the total electricity the utility supplied within its jurisdiction.

An example would work as follows. A utility owns two substations and the associated switchgear and gas-insulated lines. This equipment emitted 90 metric tons CO₂ equivalent of SF6 during 2011. The utility transmitted 100 MWh of electricity to all its customers during this period, of which the utility transmitted 40 MWh to Oregon end users. In this example, the utility would report 40% of the emissions from its equipment, or 36 metric tons CO₂ equivalent.

For the 2011 emissions year, reporting of SF6 emissions is due September 28, 2012. Subsequent emissions years will include SF6 in the greenhouse gas reports that are typically due June 1 following the emissions year.

Oregon rules authorize an investor owned utility serving jurisdictions both inside and outside of Oregon to rely upon a cost allocation methodology approved by the Oregon Public Utility Commission for allocating emissions associated with the generation of electricity distributed in Oregon. The form includes a "Multi-jurisdictional allocation" fuel type. A multi-jurisdictional utility should report the amount of electricity the utility provided in Oregon (in megawatt hours) and the emission factor (using metric tons of carbon dioxide equivalent per megawatt-hour) the utility derived using the approved cost-allocation methodology.

The utility must also provide supplemental documentation with the form that explains how the emission factor was derived, including the necessary information for DEQ to verify the calculations used to derive this emission factor. This supplemental documentation can be either emailed electronically with the completed form, or mailed with the signed summary page from the form.