March 21-22, 2023
Rate analysis comparison
Provider of Choice Concept Summary as of March 9, 2023 (one-page version)
Provider of Choice Concept Summary as of March 9, 2023 (extended version)
- Policy discussions continued
- Customer Presentations
- Transmission Updates
- Updates on LDD/IRD Billing Credits
- Peak Net Requirements Proposal
- EWEB Peak Net Requirements Proposal
- Northwest Requirements Utilities Proposal
March 9, 2023
Meeting slide deck (updated at close of meeting)
- CHWM and system size updates
- Non-federal transfer service updates
- REC updates and FJD
Feb. 21-22, 2023
Meeting slide deck Meeting slide deck content
- Peak Net Requirements
- Above High Water Mark Load Service
Feb. 9, 2023
Meeting slide deck content
- Organized Day Ahead Markets
- Transfer Updates
Jan. 24-25, 2023
Meeting slide deck content
- Rate Construct
- Contract High Water Mark Calculation
- System Size
Jan. 19, 2023
Meeting slide deck (slide 13 updated on Jan. 19, 2023)
Meeting slide deck content
- Nonfederal resources minimum threshold update
- Carbon update
- Reflections on Dec. 14, 2022 customer presentations
- Jan. 24-25, 2023 workshop plan
Nonfederal Resources Minimum Threshold reference materials (2021 analysis):
Dec. 14, 2022
Meeting slide deck content:
- Puget Sound Utilities
- Eugene Water & Electric Board
- Pacific Northwest Generating Cooperative, Northern Wasco County PUD and Umatilla Electric Coop.
Dec. 8, 2022
Meeting slide deck (updated Dec. 7, 2022)
Dec. 1, 2022
Meeting slide deck content:
- System augmentation cost analysis
Nov. 9, 2022
Meeting slide deck content:
- Non-federal resources
Oct. 26, 2022
Meeting slide deck content:
- Billing credits
- Regional Dialogue Augmentation
- CHWM Policy Considerations
Oct. 12, 2022
Oct. 5, 2022
Sept. 8, 2022
CWHM Scenarios (updated Sept. 7, 2022)
- This spreadsheet includes new scenarios for conservation. Conservation data can be found on the last tab of the workbook.
Aug. 31, 2022
Meeting slide deck content:
- System size
Aug. 16, 2022
CHWM Scenarios (updated Sept. 1, 2022)
July 21, 2022
Meeting slide deck content:
- BPA Provider of Choice Concept Paper Overview
May 19, 2022
Meeting slide deck content:
- Workshop Roles and Expectations
- Provider of Choice Goals and Principles
- Policy Workshop Framework
April 21, 2022
Meeting slide deck content:
- Regional Dialogue Contracts
- 2022-05-05 - Northwest Requirements Utilities
- 2022-05-05 - Pacific Northwest Generating Cooperative
- 2022-05-23 - Snohomish PUD
- 2022-06-01 - Public Power Council
- 2022-06-02 - Avista Corporation, NorthWestern Corporation, PacifiCorp, Portland General Electric Company, and Puget Sound Energy, Inc.
- 2022-06-02 - Mason 3
- 2022-06-02 - Northwest Energy Coalition
- 2022-06-08 - Northwest Requirements Utilities
- 2022-06-13 - Pacific Northwest Generating Cooperative
- 2022-06-23 - Seattle City Light
- 2022-08-08 - Seattle City Light
- 2022-08-09 - Raft River Rural Electric Cooperative Inc.
- 2022-08-09 - Idaho Consumer-Owned Utilities Association
- 2022-08-10 - Snohomish PUD
- 2022-08-10 - Tacoma Power
- 2022-08-10 - Wells Rural Electric Company
- 2022-08-10 - Ravalli Electric Co-op
- 2022-08-10 - United Electric Co-op Inc.
- 2022-08-10 - Orcas Power &Light Cooperative
- 2022-08-10 - Pacific Northwest Generating Cooperative
- 2022-08-10 - Northern Lights Inc.
- 2022-08-10 - Western Public Agencies Group
- 2022-08-10 - Slice Customer Group
- 2022-08-10 - Public Power Council
- 2022-08-10 - Consumers Power Inc.
- 2022-08-10 - Eugene Water & Electric Board
- 2022-08-10 - Lost River Electric Cooperative Inc.
- 2022-08-10 - Northwest Requirements Utilities
- 2022-08-11 - Lower Valley Electric
- 2022-08-23 - Clatskanie PUD
- 2022-08-23 - Grant County PUD
- 2022-08-25 - Northwest Requirements Utilities
- 2022-08-26 - City of Richland
- 2022-08-26 - Pacific Northwest Generating Cooperative
- 2022-08-26 - Western Public Agencies Group
- 2022-09-21 - Tacoma Power
- 2022-09-22 - Northwest Requirements Utilities
- 2022-09-22 - Pacific Northwest Generating Cooperative
- 2022-09-29 - Snohomish PUD
- 2022-10-19 - Tacoma Power
- 2022-10-21 - Northwest Requirements Utilities
- 2022-10-26 - Alliance of Western Energy Consumers
- 2022-10-31 - Peninsula Light Co.
- 2022-11-07 - Northwest Requirements Utilities
- 2022-11-07 - Tacoma Power
- 2022-11-17 - Tacoma Power
- 2022-11-17 - Northwest Requirements Utilities
- 2022-11-22 - Seattle City Light
- 2022-11-23 - Alliance of Western Energy Consumers
- 2022-12-05 - Above High-Water Mark Requirements Customer Group
- 2022-12-14 - Pacific Northwest Generating Cooperative
- 2022-12-14 - Oregon Trail Electric Co-op.
- 2022-12-15 - Northwest Requirements Utilities
- 2022-12-21 - Renewable Northwest
- 2022-12-22 - Cowlitz Public Utility District
- 2022-12-22 - Mason Public Utility District 3
- 2022-12-22 - Northwet Energy Coalition
- 2022-12-22 - Tacoma Power
- 2022-12-23 - Northwest Requirements Utilities
- 2022-12-29 - Wells Rural Electric Company
- 2022-12-29 - Western Public Agencies Group
- 2023-01-03 - New Large Single Loads Group
- 2023-01-06 - Seattle City Light
- 2023-01-09 - Snohomish PUD
- 2023-01-10 - Eugene Water & Electric Board
- 2023-01-27 - Snohomish PUD
- 2023-02-03 - Cowlitz PUD
- 2023-02-03 - Eugene Water and Electric Board
- 2023-02-03 - Northwest Energy Coalition
- 2023-02-03 - Pacific Northwest Generating Cooperative
- 2023-02-06 - Tacoma Power
- 2023-02-07 - Alliance of Western Energy Consumers
- 2023-02-07 - Grant County PUD
- 2023-02-08 - Northwest Requirements Utilities comments, proposal document, Contract High Water Mark scenario tool
- 2023-02-08 - Snohomish PUD
- 2023-02-09 - Big Bend Electric Cooperative
- 2023-02-09 - Columbia REA
- 2023-02-09 - Hermiston Energy Services
- 2023-02-09 - Hood River Electric and Internet Co-op
- 2023-02-09 - Mason PUD 3, Central Lincoln PUD, Columbia River PUD
- 2023-02-09 - Midstate Electric
- 2023-02-09 - Public Power Council
- 2023-02-09 - Salmon River Electric Cooperative
- 2023-02-10 - Harney Electric Cooperative
- 2023-02-10 - Klickitat PUD
- 2023-02-10 - Kootenai Electric Cooperative
- 2023-02-10 - Seattle City Light
- 2023-02-10 - Vera Water and Power
- 2023-02-10 - Western Public Agencies Group
- 2023-02-13 - Idaho Falls Power
- 2023-02-13 - Lower Valley Energy
- 2023-02-13 - Lower Valley Energy
- 2023-02-13 - Northern Wasco County PUD
- 2023-02-13 - Salmon River Electric Cooperative
- 2023-02-16 - Columbia Basin Electric Cooperative
- 2023-02-16 - Inland Power
- 2023-02-16 - Peninsula Light Co
- 2023-02-17 - City of Forest Grove
- 2023-02-17 - Northwest Requirements Utilities, Pacific Northwest Generating Cooperative
- 2023-02-17 - Pacific Northwest Generating Cooperative
- 2023-02-17 - Renewable Northwest
- 2023-02-17 - Seattle City Light
- 2023-02-17 - Tacoma Power
- 2023-02-17 - United Electric Co-op.
- 2023-02-17 - Wells Rural Electric Company
- 2023-02-17 - Western Public Agencies Group
- 2023-02-20 - Flathead Electric Cooperative
- 2023-02-24 - Northwest Requirements Utilities, Pacific Northwest Generating Cooperative, Idaho Falls Power
- 2023-02-25 - Missoula Electric Cooperative
- 2023-03-01 - Mason Public Utility District 3
- 2023-03-03 - Above High Water Mark Group
- 2023-03-03 - Northwest Requirements Utilities
- 2023-03-03 - Northwest Requirements Utilities (Low Density Discount proposal)
- 2023-03-03 - Seattle City Light
- 2023-03-03 - Snohomish County PUD
- 2023-03-03 - Tacoma Power
- 2023-03-03 - Western Public Agencies Group
- 2023-03-07 - Clatskanie PUD
- 2023-03-09 - Public Power Council
- 2023-03-10 - Slice Customers Group
- 2023-03-13 - Consumers Power, Inc.
- 2023-03-13 - Kootenai Electric Cooperative
- 2023-03-14 - Columbia REA
- 2023-03-15 - McMinnville Water & Light
- 2023-03-16 - Big Bend Electric Cooperative, Inc.
- 2023-03-16 - Northern Lights, Inc.
- 2023-03-17 - Cowlitz PUD
- 2023-03-17 - Flathead Electric Cooperative
- 2023-03-17 - Alliance of Western Energy Consumers
- 2023-03-17 - Big Bend Electric Cooperative, Inc.
- 2023-03-17 - Northern Wasco County PUD
- 2023-03-17 - Northwest Requirements Utilities
- 2023-03-17 - Seattle City Light
- 2023-03-17 - Snohomish PUD
- 2023-03-17 - Wells Rural Electric Company
- 2023-03-21 - Northwest & Intermountain Power Producers Coalition
- 2023-03-28 - Northwest Requirements Utilities
- 2023-03-30 - Energy Northwest
- 2023-03-31 - Northwest Requirements Utilities
- 2023-03-31 - Seattle City Light
- 2023-03-31 - Wells Rural Electric Company
- 2023-03-31 - Western Public Agencies Group
- 2023-04-04 - Mason Public Utility District
- 2023-04-13 - Eugene Water & Electric Board
- 2023-04-14 - Riverside Electric Company
- 2023-04-18 - Alliance of Western Energy Consumers
- 2023-04-20 - Mission Valley Power
- 2023-04-24 - Mission Valley Power Consumer Council
- 2023-04-26 - Google
- 2023-04-26 - Grant Public Utility District
- 2023-04-26 - Northwest Requirements Utilities
- 2023-04-28 - Alliance of Western Energy Consumers (AWEC)
- 2023-04-28 - Eugene Water and Electric Board
- 2023-04-28 - Northwest Requirement Utilities (Peak Net Requirements)
- 2023-04-28 - Northwest Requirement Utilities (Transfer Service)
- 2023-04-28 - Seattle City Light
- 2023-04-28 - Snohomish PUD
- 2023-04-29 - Wells Rural Electric Company
- 2023-05-02 - Tacoma Power
- 2023-05-04 - Idaho Falls Power
- 2023-05-05 - Public Power Council
- 2023-05-08 - Eugene Water & Electric Board
- 2023-05-09 - Northwest Requirements Utilities, Pacific Northwest Generating Cooperative
- 2023-05-10 - Lower Valley Energy
- 2023-05-10 - Northwest Irrigation Utilities
- 2023-05-10 - Pacific Northwest Generating Cooperative
- 2023-05-11 - Clatskanie PUD
- 2023-05-11 - Tacoma Power
- 2023-05-12 - Renewable Northwest
- 2023-05-13 - Salmon River Electric Cooperative
- 2023-05-18 - Snohomish PUD
- 2023-05-19 - Above High Water Mark Group
- 2023-05-22 - Big Bend Electric Cooperative, Inc.
- 2023-05-22 - Peninsula Light Co.
- 2023-05-22 - Seattle City Light
- 2023-05-26 - Lost River Electric Cooperative, Inc.
- Residential Exchange Program Background (Nov. 18, 2021)
- Background and mechanics for IOU workshop (Dec. 1, 2021)
- Summary of Residential Exchange comments and BPA responses (Feb. 16, 2022)
- Foundational Interests and Carbon Continued (Nov. 9, 2021)
- Summary of Interests comments and BPA responses (Feb. 16. 2022)
Cost Management and Overarching Goals (Oct. 26, 2021)
Transfer Service and Transmission Discussion (Oct. 12, 2021)
Carbon Discussion (Sept. 28, 2021)
- Energy Efficiency and Transfer Services/Transmission Background (Sept. 14, 2021)
- Energy Efficiency (Dec. 7, 2021)
- Summary of Energy Efficiency comments and BPA responses (Feb. 16, 2022)
Capacity Discussion (Aug. 24, 2021)
Contract Term/Cost Control, Carbon Background (Aug, 10, 2021)
Non-federal Resource Discussion (July 27, 2021)
High Water Marks and Tier 1 System Discussion (July 13, 2021)
BPA Statutes and Capacity (June 22, 2021)
Non-Federal Resources Background (June 8, 2021)
High Water Marks and Tier 1 System Background (May 28, 2021)
Feedback on March 18th Leanings and the 2021 calendar (April 28, 2021)
March 2021 Provider of Choice Introductory Materials
To download a PDF version, click here.
While numerous laws may affect or apply to the BPA’s operations, four key statutes define the agency’s mission and guide its day-to-day operations.
1. The Bonneville Project Act of 1937, 16 U.S.C. § 832
This act created the Bonneville Project, which included Bonneville Dam and the transmission system necessary to deliver the power generated by it. It also tasked the BPA to provide preference and priority in sales of federally generated power to Pacific Northwest public bodies and cooperatives. These public bodies and cooperatives became known as BPA’s preference customers. The statute authorized the administrator to sell power generated by the Bonneville Dam and to construct, own and operate a transmission system to deliver such power to its customers. The Bonneville Project Act requires the administrator to set rates to recover the costs related to producing and transmitting energy from the Federal Columbia River Power System. BPA was originally established under the Department of Interior but was later designated as a distinct entity within the Department of Energy, under the 1977 Department of Energy Organization Act, 42 U.S.C. §7152.
2. The Pacific Northwest Consumer Power Preference Act of 1964, 16 U.S.C § 837
In the early 1960s, the United States was negotiating the Columbia River Treaty with Canada, as well as considering a proposed high-voltage interconnection that would connect the Northwest federal transmission system with some southwest states, including parts of California, Nevada and Utah. These actions raised concerns about how BPA would allocate power among the regions, particularly to publicly owned utilities in California. In response, Congress passed the Pacific Northwest Consumer Power Preference Act of 1964, also known as the Regional Preference Act. This act defined what states and regions make up BPA’s Pacific Northwest service territory and obligated the agency to ensure the energy needs of its customers in the Pacific Northwest region are met before offering surplus power and capacity for sale outside of the region.
3. The Federal Columbia River Transmission System Act of 1974, 16 U.S.C §838
This act designates BPA’s administrator as the marketing agent for all federal power generation in the Pacific Northwest, and vests the administrator with broad authority to construct transmission systems to integrate and transmit both federal and nonfederal power. Before the act, the administrator’s authority to market federal power beyond the Bonneville Project was based on delegated authority through orders of the Secretary of the Interior. The Transmission System Act also established the BPA Fund to enable financial flexibility by allowing BPA to manage funding and repayment obligations based on rates, rather than through annual appropriations from Congress.
4. The Pacific Northwest Electric Power Planning and Conservation Act of 1980, 16 U.S.C § 839
Known as the Northwest Power Act, this statute is the most recent significant legislation pertaining to BPA. The act:
- Reaffirmed the agency’s preference and priority for power sales to its public body and cooperative customers.
- Further defined BPA’s first obligation to supply power to the Pacific Northwest.
- Granted the administrator authority to acquire resources on a long-term basis.
- Obligated the administrator to offer a contract to sell power to public bodies and investor-owned utilities whenever requested.
The act also created the Northwest Power and Conservation Council and directed BPA to protect, mitigate and enhance conditions for fish and wildlife. The act provides the legal framework for BPA's energy efficiency program, fish and wildlife program and the Residential Exchange Program. These four statutes are the legal framework for BPA’s power and transmission operations. Other laws, such as the National Environmental Policy Act, Endangered Species Act and National Historic Preservation Act, also direct some of the agency’s actions and day-to-day work. Information about these statutes and many others are available here.
The Columbia River produces more hydropower than any other river in North America. BPA plays a unique role in the sale and distribution of this renewable resource, giving its customers access to 22,000 MW of flexible, reliable, carbon-free hydropower across 15,000 miles of transmission lines.
As a nonprofit wholesale power marketer and transmission provider, BPA sells its products and services to Northwest utilities at the cost of production. The power BPA sells is produced by 31 federally-owned hydroelectric dams that are operated by the U.S. Army Corps of Engineers and Bureau of Reclamation. BPA also markets the output of the 1,200 MW Columbia Generating Station, a nuclear plant in Washington that is owned and operated by Energy Northwest.
While the federal dams and Columbia Generating Station produce carbon-free power, a small amount of carbon emissions is associated with the federal system. This is because BPA sometimes purchases power on the open market, and that power has a certain amount of carbon emissions attributed to it. BPA uses these purchases to balance resources and meet its customers’ demands beyond what the federal system can provide. But even with these market purchases, the emissions associated with BPA’s system are significantly lower than the regional average.
Where does the carbon in BPA’s resource mix come from?
The power BPA purchases on the wholesale market cannot be attributed to a specific resource. These unspecified market purchases, which are assigned a default emissions factor, make up about 3 to 12 percent of BPA’s total annual power supply. The difference from year to year is largely due to the significant streamflow variability in the Columbia River Basin.
BPA typically purchases more power in the market during years when there is less water. Other factors that contribute to BPA’s market purchases include the availability of the Columbia Generating Station and whether it experiences an extended outage, and fish operations that are designed to help endangered fish migrate to the ocean. These operations call for spilling water past dams instead of sending it through turbines, which reduces generation.
The power BPA sells is not attributed to individual resources. The entire federal system, including market purchases, is treated as a single source. Therefore, the federal system is collectively assigned an annual emissions factor, which is measured as pounds or metric tons of carbon dioxide per megawatt-hour.
Maximizing the value of the region’s carbon-free assets
BPA is taking steps to ensure its long-term commercial success by addressing industry challenges that could affect its ability to remain a cost-effective power supplier. BPA’s strategy includes improving its competitive position by reducing costs, while also maximizing revenues from sales of surplus federal power. To do this, BPA is focused on new market opportunities for clean capacity resources.
The West Coast states are setting ambitious carbon reduction goals and aggressively pursuing energy policies that put a price on carbon. The Northwest’s existing hydropower resources can play an essential role in meeting these goals most cost-effectively while maintaining safe, reliable service. Policies that put a price on carbon could increase the value of BPA’s surplus sales because of an increased premium for low-carbon power.
For example, California’s existing cap-and-trade program has created value for low-carbon generation. Demand for BPA’s low-carbon power has resulted in surplus sales to California at a premium over other wholesale market prices. The premium BPA earns from these surplus sales is used to offset its costs, thereby lowering power rates for the agency’s principal customer base, which is made up primarily of Northwest public utilities.
Carbon pricing programs
Carbon pricing programs, such as California’s cap-and-trade program, require participants to purchase carbon allowances for power that they either generate in California or import into California. If BPA were to import power into California, the requirement to purchase allowances would apply due to the emissions factor that is assigned to the federal system as a whole (arising from the small amount of market purchases BPA makes).
However, carbon allowances are considered a state tax by the U.S. Department of Energy, BPA and other federal agencies. Federal agencies cannot pay state taxes unless Congress specifically authorizes it. Therefore, BPA currently cannot purchase these carbon allowances.
As an alternative, BPA uses third-party arrangements to sell to entities who take BPA’s power into the California market and who pay for the carbon allowances. But these arrangements are costly, inefficient and raise complications. BPA is exploring options for future participation in markets that put a price on carbon.
What about other greenhouse gases associated with the federal system?
Sulfur hexafluoride: SF6 is a greenhouse gas commonly used as an insulator in high-voltage electrical equipment, including in BPA’s transmission system. Since 1999, BPA has led the nation as a charter partner in the Environmental Protection Agency’s SF6 Emission Reduction Partnership for Electric Power Systems. BPA’s 2017 emissions rate — the ratio of SF6 emissions relative to total amount of SF6 contained in electrical equipment — was 0.53 percent. That is well below even the EPA partnership’s latest reported average of 1.9 percent.
Methane: The conversion of water into power does not produce methane, but some research has shown that reservoirs can emit methane under certain conditions, particularly in tropical climates where there is a lot of plant growth and algae — conditions not found in the Federal Columbia River Power System. Both the U.S Army Corps of Engineers and the Northwest Power and Conservation Council concluded that the reservoirs in the Columbia and Snake rivers do not emit a measurable level of methane.
BPA delivers federal power to customers across several states. The agency has sometimes chosen to serve customers over transmission systems owned and operated by entities other than BPA, rather than build to directly connect those customers to its transmission system. BPA refers to this kind of delivery as “transfer service.”
In 1937, Congress passed the Bonneville Project Act. This act created the Bonneville Project, which included Bonneville Dam and the transmission system necessary to deliver the power generated by it. The act also tasked BPA to provide preference and priority in sales of power produced by the Federal Columbia River Power System to Pacific Northwest public bodies and cooperatives, also known as preference customers.
To fulfill its obligation to deliver federal power to its preference customers, the agency had to either build transmission to connect to customers, or contract with third-party transmission owners to use their systems to deliver federal power to the customers’ loads. As more and more public utilities requested power from BPA, the need for additional transmission continued to grow, and the agency had to decide how it would serve the new customer loads.
Reorganization of some federal agencies also contributed to the expansion of BPA’s preference customer base. For example, in 1963, the U.S. Bureau of Reclamation’s power marketing and transmission functions in southern Idaho were transferred to BPA. Reclamation’s former customers became additional BPA preference customers, and the agency again had to decide the best plan of service for each of these locationally distant preference customers: build more transmission, or acquire third-party transmission.
BPA determines the best plan of service by evaluating the cost of building transmission as compared to acquiring transfer service. BPA also considers the timing of a customer’s request for service as compared to the time it would take to build the necessary facilities versus using existing facilities. In many instances, BPA’s evaluation revealed that existing third-party transmission facilities could accommodate preference customers’ loads in a more timely and cost-effective manner than building duplicate facilities connecting customers directly to BPA’s system. In these instances, BPA decided to use transfer service to meet its obligation to deliver federal power to preference customers. As customer loads have grown over time, new arrangements and improvements have had to be considered and implemented on BPA’s transmission system and on third-party provider systems.
As of 2020, 83 of BPA’s 134 customers with long-term power sales agreements had at least one transfer point of delivery, and 55 customers were served solely by transfer service. In 2019, BPA’s transfer service annual budget was approximately $90 million.
It is important to note that BPA is not statutorily obligated to provide transfer service; rather, it is an option available to the administrator. Under the current long-term Regional Dialogue contracts that expire in 2028, BPA has contractually committed to acquire and pay for transfer service for customers’ existing points of delivery. Any new requests for transfer service are evaluated on a case-by-case basis to determine if it is the best plan of service.
BPA will continue advocating on behalf of its preference customers through the term of the Regional Dialogue contracts when working with third-party transmission providers.
BPA strives to keep transfer service costs down through:
- Proper contract management and implementation.
- Active involvement in third-party transmission providers’ rate cases.
- Engagement with Federal Energy Regulatory Commission on the third-party providers’ open access transmission tariff terms and conditions.
Learn more about transfer service here.
To download a PDF version, click here.
Hydropower planning and power supply
BPA was created in 1937 to sell hydroelectric power generated by Bonneville Dam to publicly owned utilities in the Northwest. As more federal dams were built in the region, the agency began selling power from those facilities as well. Today, there are 31 federal dams in the Federal Columbia River Power System (FCRPS). The power produced by these dams, as well as that produced by the nonfederal Columbia Generating Station nuclear plant along with other acquired resources, is made available to BPA’s preference customers with Regional Dialogue contracts.
While the amount of water moving through the FCRPS is highly variable and, at times, difficult to predict, the volume of flow and when it occurs greatly affects how much hydropower BPA has available to sell to its customers. Therefore, forecasting the amount of hydropower that can be produced is critical to meeting the energy needs of BPA’s customers. BPA has developed methodologies and tools to forecast the firm power supply content that can be produced given the variable water conditions that affect hydropower production.
BPA’s standard practice is to forecast the amount of firm power the FCRPS can be expected to produce based on the driest or worst water years on record. This is known as critical water planning. Currently, BPA uses conditions that occurred from October 1936 through September 1937 as a baseline and refers to it as 1937 historical critical water conditions. With 1937 critical water as the baseline for FCRPS hydro planning, BPA then overlays river operation demands, including irrigation, fish passage, flood risk management and recreation. Planners refer to the resulting amount, or inventory, as critical firm power. This is the amount the FCRPS can be expected to produce on a continuous basis to supply the firm power used to satisfy the administrator’s firm power supply obligations. It is also used to develop power rates and to determine the amount of firm requirements power BPA sells under Regional Dialogue contracts at the Priority Firm (PF) Tier 1 rate.
Since the baseline critical firm power is based on conservative assumptions of what the FCRPS will produce, BPA may have additional firm power available to sell as surplus. BPA offers and sells surplus power through its bulk marketing trading floor. Revenues earned from such sales are credited to BPA’s firm power rates, which helps lower or minimize such rates. Using a less conservative assumption around water supply would result in greater amounts of power available as critical firm power but would inherently result in a reduction in the amount of surplus power credited back in rates.
How Regional Dialogue contracts incorporate hydro planning concepts
Contract High Water Marks: Contract High Water Marks (CHWM) are used to determine how much firm power a Regional Dialogue customer is entitled to purchase at BPA’s Tier 1 PF rate. CHWMs were established based on a utility’s historical load in 2010, and then scaled proportionally to use the full amount of critical firm power expected of the FCRPS. The use of CHWMs and the tiering of PF rates under the Tiered Rate Methodology is intended to make the cost of the firm power sold under the Regional Dialogue contracts transparent.
Rate Period High Water Mark: Forecasting the expected production of hydropower – especially the FCRPS – is complicated considering the many flexibilities and constraints, including seasonal and annual water variability, statutory, treaty, and other legal obligations, that can affect operations over time. The Regional Dialogue construct recognized these factors and established an approach, through the biennial Rate Period High Water Mark (RHWM) process, to measure system output over time and accommodate changes in system operations. RHWMs reflect updates to the projected capability of the Tier 1 FCRPS resources and costs for each two-year rate period and in turn determine the amount of firm power a customer can purchase during that rate period at the Tier 1 PF rate.
Unused critical firm power: The Tiered Rate Methodology establishes a special treatment for amounts of critical firm power that customers with Regional Dialogue contracts are unable to purchase at Tier 1 PF rate because they don’t have enough load to purchase the full amount available to them under their RHWMs. The value of this unused critical firm power, or unused RHWM, is shared proportionally with all Regional Dialogue customers and built into BPA’s rates, including adjustments for times when unused critical firm loads differ from rate case forecasts. This ensures that the full value of the federal system is shared equitably across all customers with Regional Dialogue contracts.
To download a PDF version, click here.
When Congress passed the 1980 Pacific Northwest Electric Power Planning and Conservation Act, also known as the Northwest Power Act, it directed that customers requesting power from the federal system to serve large loads be served at BPA's marginal resource cost-based rate. This rate is known as the New Resources Firm Power (NR) rate. This rate treatment is intended to limit the relocation of large loads from other parts of the country to the Pacific Northwest that otherwise would be attracted by low-cost federal power. Alternatively, a customer with an NLSL can choose to serve such load with nonfederal resources.
Under the Northwest Power Act, a new large single load (NLSL) is defined as any new load, or expansion of an existing load, at a single facility that grows by 10 average megawatts (aMW) or more in any consecutive 12-month monitoring period. The Act requires BPA's administrator to monitor large loads in the region and determine if the load at a facility is an NLSL, or if it becomes an NLSL during the monitoring period. Once a load is designated an NLSL it remains an NLSL, regardless of changes in the size of the load.
However, loads that a customer contracted or committed to serve before Sept. 1, 1979, are protected from being an NLSL until there is load growth in excess of 10 aMW during a subsequent 12-month period.
How a large load officially becomes an NLSL
BPA's NLSL policy is implemented through its firm power sales contracts. Under BPA's current Regional Dialogue contracts, a utility must provide reasonable notice to BPA of any expected increase in a single load that may qualify as an NLSL. Once notified, BPA will complete a facility determination and determine whether the prospective large consumer load has the potential to increase by 10 aMW or more in a 12-month period. The facility determination serves as the official designation of a single facility that will be monitored to track whether or not it becomes an NLSL. After BPA issues a facility determination, it will then begin monitoring the facility’s load.
A Load Following customer may elect to either be treated as a potential NLSL or a planned NLSL. Slice customers should work with their account executive regarding service to facilities that may become NLSLs.
A load treated as a potential NLSL will be served with power at the PF rate. If the load increases by 10 aMW or more in a 12-month monitoring period, BPA will deem the load an NLSL and any federal power consumed since the beginning of the monitoring period will be backbilled at the NR rate. Once the load becomes an NLSL the customer must serve that load, and any increases to it, with either power from BPA at the NR rate or a dedicated nonfederal resource. If the potential load does not grow by 10 aMW in a monitoring period, any load growth from the prior year is considered grandfathered load that is eligible to be served at the PF rate and a new monitoring period will commence.
If a Load Following customer elects to treat the load as a planned NLSL, the load can be treated as such and the customer can serve it with power purchased from BPA at the NR rate, or with a dedicated nonfederal resource. This eliminates the possibility of backbilling at the NR rate if the load becomes an NLSL during the monitoring period. If the load does not grow by 10 aMW in a monitoring period, the load will not be considered an NLSL and the customer will receive a credit for paying the NR rate, if elected, for power eligible for the PF rate. Further, any load growth under 10 aMW from the prior year is considered grandfathered load and is eligible to be served at the PF rate. If the possibility remains that the facility load may grow an additional 10 aMW, a new NLSL monitoring period will commence.
Data centers are an example of a NLSL.
BPA considers the following criteria when making a facility determination:
- If the load is for a single consumer’s operations.
- If the load is at a single location or in a single building.
- If the load results from producing a single product or using a single process.
- If portions of the load are interdependent or can be separated.
- If the load is contracted for, billed, or served as a single load under the utility’s customary billing and service policy.
- If there are any applicable precedents or similar determinations.
Regional Dialogue Contracts
The BPA’s current long-term power sales contracts, commonly referred to as Regional Dialogue (RD) contracts, are 20-year agreements to provide electrical power service to the agency’s Pacific Northwest customers. These utilities serve millions of homes, businesses and facilities across the Pacific Northwest. Following extensive negotiations between BPA and its customers, the Regional Dialogue contracts were signed in 2008. Power deliveries under the RD contracts began on Oct. 1, 2011, and will continue until the contracts expire on Sept. 30, 2028. All products and services described are subject to applicable wholesale power rates and charges established through the BPA rate proceeding, conducted under Section 7(i) of the Northwest Power Act.
The applicable priority firm (PF) rates for power sold under the contracts are determined by the tiered rates methodology (TRM). The TRM is a rate design that is used by BPA in setting its PF rates every 2-years In its simplest form, this means that customers are able to buy amounts of power up to an established contract amount, known as the contract high water mark, at the PF Tier 1 rate, which is based on the cost of the existing federal system. If the customer’s load needs exceed their contract high water mark amount, they may buy more power from BPA at PF Tier 2 rates that reflect the cost of such additional power.
The RD contracts are take-or-pay contracts, meaning the customer must pay for the firm net requirements power – total retail load minus dedicated nonfederal resources – it commits to purchase from BPA, whether or not the customer actually takes delivery of such power.
There are three RD contract power products: Load Following, Block and Slice/Block. They are all subject to the PF rates as described above.
The Load Following product provides firm power service to meet a customer’s actual total retail load minus its dedicated resources. Customers can apply their dedicated resources in pre-established amounts, called shapes, or simply as the resource generates. Depending on the size and type of resource, the customer may be required to purchase additional Resource Support Services from BPA to account for resource unpredictability.
The Block product provides a planned amount of firm power to meet a customer’s planned annual net requirement load. The customer must dedicate nonfederal resources to serve its load and is responsible for using those resources to meet any load in excess of its planned monthly BPA Block purchase. The Block product provides a predefined amount of power each hour and can be purchased in two different shapes:
- The flat annual block shape, which provides the same amount of power every hour in a defined year.
- A shaped block of power is shaped to the customer’s forecast net requirement, where amounts of power can vary by month and between heavy and light load hours based on the customer’s actual fiscal year 2012 net requirement shape. Although the annual average amount of Block power may vary based on a customer’s updated annual net requirement, the shape stays the same for the life of the contract.
Slice/Block provides for the combined sale of two distinct power products to meet a customer’s planned annual net requirement: the Slice product and the Block product. The Slice/Block products in most cases are provided together. As with the Block product described above, the customer is responsible for meeting its Total Retail Load each hour and is obligated to supply any amount of power needed to meet such load that is not met by the Slice and Block products.
The Slice product is a federal system sale of power that includes firm requirements power, hourly scheduling rights and surplus power. The Slice product is a power sale subject to limitations and is not a sale of operational rights, Tier 1 system resources, resource capability, or transfer of control of any federal resources. Federal operating agencies retain all operational control of all resources that comprise the Federal Columbia River Power System at all times.
The customer’s Slice output is calculated based on a percentage of the annual firm portion of the federal resources known as the Tier 1 system. Customers access Slice output using a computer simulation representing the actual variable federal system output and conditions. From time to time, the Slice product may deliver more or less power due to water availability and system operations. BPA neither guarantees any amount of Slice output, nor does it guarantee that the amount of Slice output combined with Block power will be sufficient to meet the customer’s total load. The Slice product offers operational flexibility but has inherent risk due to the variability in the amount of system power available during a given year.
The Block portion of Slice/Block is the same as described above for the Block product except all hourly amounts are equal throughout a month, with no variation between heavy and light load hour amounts. The annual amount of PF Tier 1-priced Block is calculated as the difference between the customer’s planned annual net requirement load and the firm Slice amount from the Slice product.
BPA's Regional Dialogue Guidebook includes a more detailed summary of these products. Visit Regional Dialogue products to learn more.
To download a PDF version, click here.
BPA is a federal power marketing administration. Although it is part of the U.S. Department of Energy, BPA uses its revenues from electric power and transmission rates to pay all its costs and does not receive annual appropriations. The agency must recover all operations and maintenance costs and repay the federal investment in hydropower generation, fish and wildlife mitigation, conservation and transmission from revenues it receives from the sale of power and transmission services to eligible customers.
BPA establishes the rates it charges for power and transmission services through formal rate proceedings, or rate cases, as described in Section 7(i) of the Pacific Northwest Electric Power Planning and Conservation Act of 1980, also called the Northwest Power Act.
What costs are included in BPA's rates?
BPA's rates are established to recover its costs consistent with statutory directives. These directives require rates to be set as follows:
- With a view to encouraging the widest possible diversified use of electric power at the lowest possible rates to consumers consistent with sound business principles.
- With regard to the recovery of the costs of producing and transmitting electric power, including amortization of the capital investment allocated to power over a reasonable period of years.
- At levels that produce such additional revenues as may be required to pay, when due, the principal, premiums, discounts, expenses and interest in connection with bonds issued under the Transmission System Act.
BPA's program spending levels for the agency are developed through a public process called the Integrated Program Review (IPR). The forecast spending levels developed in the IPR inform the assumptions about the costs BPA must recover in power and transmission rates established in a formal rate proceeding.
BPA's power rates must recover costs associated with generating electricity, including, but not limited to:
- Operation, maintenance and capital-related costs of the Northwest federal dams.
- The Columbia Generating Station.
- Other power purchases
- Fish and wildlife mitigation.
- Energy conservation.
- The Residential Exchange Program.
The agency’s transmission rates must recover all costs to build, operate and maintain BPA's transmission grid.
BPA is required to periodically review and revise its power and BPA rates no less frequently than once every five years. Under the Tiered Rate Methodology, BPA has committed to developing its power rates every two years, with certain limited exceptions, through the expiration of the Regional Dialogue contracts in 2028. As a result, BPA's current practice is to conduct a formal rate proceeding every other year to establish rates for the next two fiscal years.
Development of the rates that BPA proposes for in a formal rate proceeding begins long before the start of the formal proceeding itself. Using the IPR cost forecasts and other applicable information, such as customer load forecasts, BPA develops the rates for its initial proposal in the rate proceeding. In simple terms, BPA's rates can be calculated by adding up the expected costs for the rate period and dividing these costs by the expected sales. In practice, however, BPA's rate development process is complex, involves months of extensive analysis and studies by BPA staff, addressing a broad spectrum of issues from market risks to the legal rights of specific customer groups. The rates developed through this process form the basis of the initial proposal that staff presents in a formal rate proceeding under Section 7(i) of the Northwest Power Act.
A formal rate proceeding begins with publication of notice of staff’s rate proposal in the Federal Register and usually takes about nine months to complete. BPA sometimes will conduct an expedited rate proceeding to address a single issue or limited set of issues. Expedited proceedings typically last 90 to 120 days. At the conclusion of the rate proceeding, the administrator issues a final record of decision, or ROD, which includes BPA's final rates. The agency then files its rates with the Federal Energy Regulatory Commission (FERC) for confirmation and approval. The rates do not take effect until approved by FERC.
BPA's rate proceedings are conducted “on the record." That is, in making a decision on final rates, the administrator considers only information that is contained in the official record developed in the proceeding. Therefore, during a rate proceeding, BPA employees cannot engage in “ex parte communications,” meaning they cannot have discussions with or listen to input from people outside of BPA about substantive issues in the proceeding. The ex parte rule applies to all BPA employees and contractors during the rate proceeding and is intended to ensure that the proceedings are fair and transparent. Ex parte begins when BPA publishes the summary of its initial proposal in the Federal Register and concludes with the release of the administrator’s final record of decision.
Overview of the rate case process
The formal 7(i) proceeding is intended to allow BPA and parties to present evidence on the issues to develop the record for the administrator’s final decisions on those issues. The steps follow rules of procedures BPA has adopted for the proceeding and are identical for setting power rates or transmission rates.
- BPA publishes the Federal Register Notice, or FRN, summarizing its initial proposal. This publication begins the period prohibiting ex parte communications regarding rates issues, as well as the formal 7(i) proceeding. The FRN provides instructions for entities able to demonstrate a specific interest in BPA's rates to file petitions with the hearing officer to become an official party to the rate proceeding.
- Shortly after the FRN is published, a prehearing conference is held, at which time BPA's initial proposal is formally released. The initial proposal contains BPA's direct case and includes testimony, studies and documentation supporting the factors BPA's staff considered to ensure the proposed rates recover expected costs.
- Next, the parties file their direct cases with the hearing officer in the form of written testimony and supporting documentation. The parties' direct cases respond to BPA's initial proposal on areas of concern to them.
- BPA and the parties each review the parties' direct cases and then file rebuttal testimony.
- BPA staff involved in the development of the initial proposal and all participating parties are subject to cross-examination by the parties on all testimony and evidence that they have submitted.
- Parties then submit their initial briefs, which summarize the technical and legal basis for positions. Parties are also offered the opportunity to present oral argument to the administrator.
- The BPA administrator prepares a draft ROD and distributes it to the rate case parties. The draft ROD lays out all the rate case issues with an evaluation of the positions held by the various parties, and includes the administrator’s draft decision for each issue. The parties can respond to the draft ROD by filing briefs on exceptions.
- The hearing officer submits the entire official record of all the above materials to the administrator, who then prepares the final ROD. The final ROD contains a summary of the rate case process and the administrator's reasons supporting the final decision on each of the issues. The final ROD includes BPA's final rate schedules and General Rate Schedule Provisions (GRSPs). This document is incorporated into the official record of the rate proceeding.
- BPA submits the final official record to FERC at least 60 days before the date that the agency proposed for the new rates to take effect, which is usually Oct. 1, the start of the new federal fiscal year.
- FERC typically grants interim approval shortly before Oct. 1 to allow BPA to begin charging the new rates by the effective date. Final approval follows FERC's review of BPA's filing, which may take several months to more than a year, depending on whether the filing is contested.
To download a PDF version, click here.
The Residential Exchange Program (REP) was created by Congress when it passed the 1980 Pacific Northwest Electric Power Planning and Conservation Act, also known as the Northwest Power Act. The REP was designed to provide a measure of wholesale rate parity between the cost of resources paid by residential and small farm communities served by utilities with higher-cost resources, typically investor-owned utilities, or IOUs, and the lower cost of federal power sold by Bonneville to publicly owned utilities, also called consumer-owned utilities. Through the REP, all regional residential and small farm consumers, whether served by a publicly owned utility or IOU, may gain access to the benefits from the low-cost federal hydropower system that serves the Pacific Northwest without reducing the supply from the federal system that would otherwise be used to serve public customer loads.
How it works
Under the REP, any utility in the region can offer to sell power to Bonneville at that utility’s cost for resources, called the average system cost, or ASC. Bonneville must purchase that power and in return sell an equivalent amount of power back to the utility at Bonneville’s Priority Firm (PF) Exchange rate, or PFx. The amount of power sold is equal to the utility’s residential and small farm load.
In practice, no actual power is delivered; Bonneville pays the utility the difference between the utility’s ASC and Bonneville’s PFx rate. The larger the cost difference, the greater the benefit the utility receives. Utilities must pass on the benefits received under the REP to their residential and small farm consumers as credits on their retail power bills. The cost of the REP payments is recovered in Bonneville’s power rates.
Today, Bonneville pays more than $270 million a year in REP benefit payments to several utilities across the region. They include six IOUs (Avista, Idaho Power, Northwestern, PacifiCorp, Portland General Electric, and Puget Sound Energy) and two publicly owned utilities (Clark Public Utilities and Snohomish County Public Utility District).
History of the REP
The REP originates from a congressionally brokered compromise to address disparate resource costs between public and private utilities in the Pacific Northwest. Historically, the region’s IOUs have invested and relied upon thermal generating resources to meet their retail load demands. In comparison, the federal power sold by Bonneville that went mostly to the publicly owned utilities and the direct service industrial customers (DSIs) – such as aluminum and steel plants – reflected the lower costs of the federal dams. In the 1970s, the Pacific Northwest faced a projected power shortage that would have resulted in an allocation of federal power by Bonneville to its preference power customers.
IOUs, like publicly owned utilities, also wanted to purchase the inexpensive federal power from Bonneville, but were precluded from doing so because of the “preference” provisions of law which require that Bonneville sell power first to public entities. Soon, stark differences between the retail rates of publicly owned utilities and IOUs throughout the region emerged. Residential customers of IOUs were paying up to three times as much as those served by publicly owned utilities. These disparities led to calls for revisions to the “preference” clauses contained in federal statutes and efforts by state legislatures to place all rural and domestic customers under the preference clause, whether served by public or private utilities.
In 1980, Congress stepped in and passed the Northwest Power Act, a sweeping piece of legislation encompassing a wide array of topics, including the REP. Through the REP, regional publicly owned utilities and IOUs could access the low cost of the Federal Columbia River Power System resources for the benefit of their residential and farm consumers.
Statutory Limits of the REP and the 2012 Settlement Agreement
Congress included certain statutory protections that limit the amount of REP costs that can be recovered from publicly owned utilities that pay Bonneville’s priority firm (PF) rate. Specifically, the Northwest Power Act requires Bonneville to perform a rate test that compares the proposed PF rate with a hypothetical rate that excludes, among other items, the cost of the REP. If the level of the hypothetical rate is lower than the proposed PF rate, Bonneville reduces the PF rate by allocating the additional costs to other base rate cost pools that apply to power sold to other firm power customers, including IOUs. The effect of this reallocation of cost is to reduce REP benefits.
Because of the complexity of the REP, Bonneville and IOUs attempted to settle the REP in 2000. Publicly owned utilities filed lawsuits over the settlements, questioning whether they violated the statutory rate protections. In 2007, the Ninth Circuit Court of Appeals agreed that the settlements did not provide the publicly owned utilities with the protections that Congress intended and remanded Bonneville’s power rates and the REP settlement contracts. In 2011, IOUs and representatives of most of the publicly owned utilities reached a new settlement agreement for REP payments through 2028. Bonneville, through a public process, agreed with the utilities’ settlement and signed the 2012 Residential Exchange Program Settlement Agreement. Legal challenges against the 2012 REP Settlement were also filed, but the Court sustained the settlement.
Visit the Bonneville Power Administration website to learn more about the Residential Exchange Program.
Key features of the 2012 REP settlement
- Investor-owned utilities receive fixed REP payments from 2012 to 2028. The total of these payments in FY 2012
- 2013 was about $182 million annually. Payments increase each rate period until FY 2026-2028 when it will be about $286 million annually.
- Publicly owned utilities received annual refunds of $76 million through FY 2019 to repay past overcharges due to IOUs’ REP benefits.
- No single IOU is guaranteed any payments. If an IOU’s ASC is lower than Bonneville’s PFx rate, then that utility receives no REP benefits. However, IOUs with ASCs higher than the PFx each receive a portion of the total fixed annual amount of REP benefits.
Bonneville must revisit its implementation of the statutory rate protection in a public process before September 2028.
Energy efficiency: Part of BPA’s resource mix
A fundamental purpose of the Pacific Northwest Electric Power Planning and Conservation Act is to encourage the efficient use of electricity in meeting the Bonneville Power Administration’s obligation to supply federal power to its customers in the region. Bonneville is authorized to acquire “conservation” as a resource and the Act gives it priority when Bonneville acquires resources to meet its obligations. Conservation is defined as “any reduction in electric power consumption as a result of increases in the efficiency of energy use, production, or distribution.” Conservation—commonly referred to as energy efficiency (EE)--– acquired by Bonneville must be cost-effective and reduce the retail load demand served by the agency’s firm power customers.
Bonneville began acquiring conservation savings from its customers in 1981. Today, the agency acquires conservation in the form of energy savings from its firm power customers under Energy Conservation Agreements (ECA). Under the ECA, Bonneville sets a budgeted amount of money a customer is eligible to receive as reimbursement for implementing specified measures that produce verifiable energy savings. Customers choose which energy efficiency measures to install from a menu of measures and guidelines published in the agency’s implementation manual that accompanies the ECA. Using their own funding to install or implement measures, customers then invoice Bonneville for measures that produce verifiable energy savings. In return, the agency pays the customer, completing Bonneville’s acquisition.
Bonneville also supports customers’ energy efficiency efforts in other ways. BPA engineers assist customers with custom projects, and the agency offers programs that augment and support customers’ implementation efforts. BPA also offers funding to cover some of the administrative costs incurred by utility customers when running efficiency programs. In addition, Bonneville supports the Northwest Energy Efficiency Alliance in its energy efficiency market transformation initiatives.
Bonneville’s EE programs help keep the agency’s rates lower by cost-effectively meeting BPA’s resource needs. This helps BPA’s utility customers keep power bills low for people and businesses in their communities. Implementing EE measures can also help customers mitigate their risk of exceeding their BPA Tier 1 priority firm (PF) Contract High Water Mark.
A shared responsibility
The cost of acquiring energy efficiency is recovered in Bonneville’s Tier 1 PF power rates. At the beginning of each two-year rate period, Bonneville establishes a budget that reflects the cost of acquiring energy efficiency from customers. This is called the energy efficiency incentive (EEI) budget, and it is calculated using a utility’s Tier One Cost Allocator. Bonneville sets the amount of the incentive for each qualifying EE measure and reimburses utilities after approving their invoice for the energy efficiency savings. Utilities may pass all, some or none of that incentive on to their end-users.
In addition to the EE acquired by Bonneville under the ECA, utilities have pledged to achieve a significant amount of savings on their own. Bonneville budgets for 70% of the programmatic energy savings needed to meet its target, with utilities self-funding the remaining 30%. This has helped Bonneville keep power rate increases at or below the rate of inflation.
Relying on customers to self-fund 30% of the savings also recognizes that many utilities fund energy efficiency programs beyond what Bonneville reimburses with the EEI. The partnership with utility customers to deliver energy efficiency programs to Northwest communities helps reduce energy costs and benefits the region by reducing the need for new resources.
Learn more about Bonneville’s residential, commercial, industrial and agricultural energy efficiency resources here.
To download a PDF version, click here.
The Bonneville Power Administration’s customers provide power to urban and rural communities across the Northwest. Some utilities serving smaller populations or agricultural loads may be eligible for BPA power rate discounts.
Low Density Discount
Section 7(d)(1) of the Pacific Northwest Electric Power Planning and Conservation Act of 1980, also called the Northwest Power Act, directs BPA to provide a discount in its firm power rates to customers with low system densities and high distribution costs. The Low Density Discount, or LDD, is available to eligible BPA customers serving lower density population areas, often rural, to avoid adverse impacts on their retail rates. The cost of the LDD is recovered in BPA’s Priority Firm power rates. Today, BPA provides approximately $40 million in LDD benefits annually.
BPA has developed criteria to determine which of its utility customers are eligible for the LDD. Determining which customers are eligible, establishing the level of the LDD for each rate period and applying the discount to those customers’ power bills satisfies BPA’s obligation. Current LDD eligibility criteria are:
- The customer must serve as an electric utility offering power for resale to retail consumers.
- The customer must agree to pass the benefits of the discount through to its eligible consumers within the region served by BPA.
- A customer’s average retail rate must exceed Bonneville’s average Priority Firm power rate by at least 25%.
- The customer’s kilowatt-hour/investment ratio must be less than 100.
- The customer’s consumers/pole miles ratio must be less than 12.
BPA collects information from customers each spring to determine eligibility for the LDD. The eligible LDD ranges from a 0.5% to 7% discount based upon the qualifying customer’s kilowatt-hour/investment ratio and consumers/pole miles ratio. The discount can be higher than 7% for utilities with net load requirements greater than their Rate Period High Water Marks.
Irrigation Rate Discount
Since 1942, BPA has provided a discount for eligible irrigation loads in various forms. Unlike the statutory obligation to provide the LDD, BPA is not required by statute to provide the Irrigation Rate Discount, or IRD. Historically BPA has offered power at a lower cost to customers that serve seasonal irrigation loads, typically during summer months and based on the availability of surplus power from the federal system. Providing this lower cost power directly assists the agriculture sector, an economic driver in many rural Northwest communities.
BPA’s current Irrigation Rate Discount, or IRD, applies to firm power sold May through September to customers that serve irrigation load. Today, BPA provides approximately $22 million in annual benefits.
Like the LDD, the cost of the IRD is recovered in BPA’s Priority Firm power rates. Current eligibility criteria for the IRD are:
- The customer participated in BPA’s FY 1997 to FY 2001 summer seasonal product or FY 2007 to FY 2011 Irrigation Rate Mitigation Program.BPA serves at least 75% of the customer’s Total Retail Load.
- BPA serves at least 75% of the customer’s Total Retail Load.
- 5% of the customer’s total retail load is irrigation load, or the customer’s three-year average irrigation load is more than 7,500 MWh.
Loads subject to the IRD are identified in Exhibit D of eligible customers’ Regional Dialogue contracts. Eligible customers are required to read irrigation meters each year at the beginning of May and after Sept. 30 and submit the total irrigation load to BPA. At the end of the irrigation season, a true-up is performed. If a customer uses less power than they contracted for, the discount may not apply and the utility will be charged for the difference at the applicable rate.
For more information, customers should contact their BPA Power Services account executive.
To download a PDF version, click here.
The Tiered Rate Methodology (TRM) establishes a two-tiered rate design for sales of firm power at the Priority Firm (PF) rate under the Regional Dialogue (RD) power sales contracts. The TRM is a 20-year rate design that is used in every biennial rate case to determine BPA's PF Tier 1 and Tier 2 rates. The TRM operates in conjunction with the RD contracts, also called Contract High Water Mark (CHWM) contracts. Pursuant to the RD contract and TRM, BPA calculates a customer’s Rate Period High Water Mark (RHWM), which establishes the amount of firm power a customer can purchase at the Tier 1 PF rate each rate period. Rates are set consistent with the TRM every two years through formal rate proceedings as required under Section 7(i) of the Pacific Northwest Electric Power Planning and Conservation Act of 1980.
Tiered rates preserve the cost benefits of the existing system for established customers. At the same time, customers experiencing load growth beyond their Tier 1 PF rate purchases from BPA can choose to serve that growth by using nonfederal power, by relying on BPAor by using a combination of the two.
In its simplest form, this means that utilities lock in a set amount of power from the existing federal system at a cost-based rate, the Tier 1 rate. Beyond that, Tier 2 rates are for any energy a utility obtains from BPA in addition to its contractual right to power at Tier 1 rates. Each rate period, the amount of power BPA offers at Tier 1 rates is based on what the existing federal system can produce. Tier 2 rates are based on the actual or forecast price paid to acquire the additional power requested by the customers.
High water marks
The central feature of the TRM is the CHWM. Each customer has a CHWM that determines its initial eligibility to purchase power at Tier 1 PF rates. The TRM directs how BPA will calculate a customer’s CHWM. The CHWMs were largely based on customer loads in FY 2010 with adjustments for weather-normalization and conservation, and adjustments to account for the economic downturn experienced throughout the region in FY 2010. Those CHWMs are fixed for the term of the Regional Dialogue contracts through 2028, with only minor exceptions such as annexations between customers, new utility formation and limited growth of tribal utilities.
CHWMs are administered through Rate Period High Water Marks (RHWM). A customer’s RHWM determines the average megawatt amount of energy customers can purchase at Tier 1 PF rates for a given rate period. Customers’ RHWMs are calculated every two years and largely depend on the amount of Tier 1 system capability forecast for the two-year rate period. If a customer’s net requirements load is greater than its RHWM, this is called Above-RHWM load and the customer must elect to serve it in one of three ways:
- Purchasing nonfederal resources.
- Purchasing an amount of firm power at Tier 2 rates from BPA.
- A combination of the two previous options.
Among all BPA's RD customers and among purchasers of each product – Load Following, Block or Slice/Block – the TRM introduced various features to its rates. Most notably, the Tier 1 PF rate design consists of three elements: Customer Charges, Load Shaping Charges and Demand Charges.
- Customer Charges: The majority of BPA's costs are recovered through Customer Charges. Costs are allocated to customers using the Tier One Cost Allocator (TOCA). A customer’s TOCA is calculated during the rate case and is based on the lesser of its RHWM or its forecast net requirement (a customer’s hourly electricity needs, minus any non-BPA resources the customer uses to serve its own loads), and then divided by the sum of all customers’ RHWMs. A customer’s TOCA may be updated within a rate period due to changes to its forecast net requirement. In addition to general charges administered through TOCAs, individual Customer Charges will be adjusted by costs and credits assigned to the specific BPA products they choose, such as Slice or non-Slice charges.
- Load Shaping Charges: Load Shaping Charges adjust for the difference between a customer’s actual use of power from the Tier 1 system and that customer’s base amount of power received for paying their TOCA share of the Tier 1 system costs. These base amounts are provided in the same shape as the projected Tier 1 system for a given rate period. Load Shaping rates are based on forecast market prices. Load Shaping Charges can be a charge or a credit on a customer’s monthly bill depending on whether their actual power use is greater or less than their base amounts of power.
- Demand Charge: The Demand charge is BPA to send a price signal to a limited portion of a customer’s overall demand on BPA and is applicable to customers purchasing Load Following and Block with shaping capacity products. This signal can encourage activities such as demand response initiatives to help the utility manage its Demand Charges.
Rate setting process
Although the rate design in the TRM is for the full term of the Regional Dialogue contracts, the actual applicable rates and charges, including those described above, are established every two years through formal rate proceedings as required under Section 7(i) of the Northwest Power Act of 1980. Statutorily, BPA's rates can be set for one to five years. The TRM and Regional Dialogue contracts provide for a two-year rate cycle, as parties determined that two-year rate periods strike a balance between the rapidly changing operating landscape and need for rate stability, while also accommodating for factors such as the two-year refueling cycle for the Columbia Generating Station.
The 2012 Wholesale Power and Transmission Rate Adjustment Proceeding through which TRM was established can be found on the Finance and Rates page of bpa.gov.