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Frequently asked questions

Power Marketing


Capacity and energy

What is the difference between capacity and energy?  Capacity is the instantaneous amount of power available to meet consumer demand as they turn on lights, appliance and motors. It is measured in kilowatts or megawatts. Energy is the amount of electricity delivered over time and is measured in kilowatthours or megawatthours. One kilowatthour of energy delivered over one hour requires one kilowatt of capacity. Capacity and energy can be marketed and billed separately.



How does Western contract with firm power customers?  When existing contracts expire or when additions to generating capacity occurs, we develop a new marketing plan on a project-specific basis. Marketing plans specify when and how Western will sell power. Although marketing plans vary from project to project, they commonly address issues such as contract terms and conditions, the geographic area where electricity will be sold, classes of service and the amount of electricity offered, who is eligible to receive the electricity, how power is allocated among applicants and the deadline for successful applicants to sign their contracts.

Final marketing plans are the basis for allocating firm power to individual customers. An allocation does not grant a customer the right to receive power; this happens only when a contract is signed. The contract typically contains a capacity commitment (also referred to as the contract rate of delivery) and an energy commitment (except for the Central Valley Project, which markets power based on a percentage of the project’s hourly output).

Western normally requires the potential customer to enter into a contract within a defined time period after the allocation is made. The entire contracting process could take anywhere from several months to several years. The customer may also need to make delivery arrangements beyond Western’s point of delivery; customers take delivery according to the contract terms.

When do Western's contracts expire?  Most Western power contracts have a 20-year term. The Provo River Project contract expires Sept. 30, 2024 while Parker-Davis Project expires on Sept. 30, 2028. Boulder Canyon contracts expire Sept. 30, 2017 and Pick-Sloan Missouri Basin Program—Eastern Division contracts expire Dec. 31, 2020. Contracts for existing customers of the Salt Lake City Area Integrated Projects and Loveland Area Projects end on Sept. 30, 2024. Central Valley Project and Washoe Project contracts expire Dec. 31, 2024.



What type of customers does Western serve?  Western sells power to 751 firm and nonfirm wholesale power customers, including cities and towns, rural electric cooperatives, public utility and irrigation districts, Federal and state agencies, investor-owned utilities, power marketers and Native American tribes. They, in turn, provide retail electric service to millions of consumers in Arizona, California, Colorado, Iowa, Kansas, Minnesota, Montana, Nebraska, Nevada, New Mexico, North Dakota, South Dakota, Texas, Utah and Wyoming.

Does Western serve any retail loads?  Western is a wholesale power provider. Our customers provide retail electric service to millions of consumers in 15 western and central states. However, we do have a number of end-use customers, including Federal and state agencies, tribes and irrigation districts that do not resell power from Western to residential or commercial consumers but use it for their own facilities.

Do Western's customers serve retail loads?  Yes, the vast majority of Western’s customers/customer members serve consumers over their electrical distribution systems.

What are the requirements to get long-term firm power from Western?  Long-term firm customers must have preference status, be within the project marketing area, have utility status (except for Native American tribes), be ready and able to deliver power to their loads and must execute an electric service contract with Western.

Does Western give preference to a particular type of customer?  Various laws, including the Reclamation Project Act of 1939, require Western to give preference to certain types of nonprofit organizations seeking to purchase Federal power. Those entitled to preference include cities and towns, state and Federal agencies, irrigation districts, public utility districts and rural electric cooperatives. Western also developed a policy to give preference to Native American tribes regardless of whether they have utility status.

Does Western have customers who just purchase transmission and not power?  Yes. When Western has excess transmission available to market, it is listed on an Open Access Same-time Information System, or OASIS Redirect link to a non-Western sitesite. Available transmission capacity on Western’s lines can be purchased by those who are seeking to deliver energy across Western's system. Western also may use existing transmission contracts or OASIS sites to purchase transmission to deliver energy to our customers.


Firm power and non-firm energy

What is long-term firm power?  Firm power is capacity and energy that Western guarantees to be available 24 hours a day. We usually offer different amounts of long-term capacity and energy for sale during two seasons—winter and summer. The length of the seasons may vary depending on which powerplants supply the generation. Differences result from the seasonal fluctuations in how much water flows through the powerplants and project use loads.

What is nonfirm energy?  Nonfirm energy comes without a guarantee of continuous availability. Nonfirm means energy delivery can be interrupted at the seller's discretion upon telephone notice. Nonfirm energy is sold to utilities that prefer not to use an expensive fuel or to make expensive purchases from another seller. In this type of sale, the customer has the capacity to meet its consumers' demand for electricity, but would rather purchase nonfirm energy that is less expensive than the cost of its own generation or alternative sources of supply. 



Is the drought over?
Western’s service territory covers many multipurpose water projects in 15-states. As may be expected the precipitation conditions across this vast territory can vary widely. While recent increased hydrology has helped some water systems in California and the Upper Great Plains Region, there are still some areas in the West where the drought continues to deplete the ability to generate hydropower (see the U.S. Drought Monitor site Redirect link to a non-Western sitefor more detail). For example, the 11 years between 2000 and 2010 has been the driest period in the last 100 years of historical records for the Colorado River Basin. In general, Western is optimistic with the recent hydrology reports from Bureau of Reclamation and the Army Corps of Engineers.

When less hydropower is available due to drought, how does that affect current Western contracts?
Commitments for firm power in current contracts remain firm for the life of the contract. However, due to changes in hydrology or river operations during the contract term, contracts containing resource commitments that are extended under the Energy Planning and Management Program can be modified to change the amount of power delivered after Western completes a public process and provides five years’ notice.

How does drought affect Western power sales?
Continued drought for more than a decade across the West caused lower water inflows, which, in turn, create decreased reservoir storage levels and decreased available capacity and energy. Because of the drought, generation decreased to the point where it was insufficient to meet firm power contract commitments, causing Western or its customers to purchase power from other suppliers. The drought has lessened its hold on marketed hydropower West and we are seeing recovery in some areas.

Does a decrease in power sales affect future repayment to Treasury?
Although Western must repay all the investment and operating costs of the power facilities, short-term decreases in power sales would not necessarily negatively impact future repayment obligations to the U.S. Treasury. Each year, Western prepares a power repayment study for each rate-setting system. We analyze current power rates to determine if they will provide enough revenue to cover all costs, including future repayment obligations. Western’s power repayment studies forecast cycles of above and below average water as that information becomes available to derive the power rate. Surplus sales accelerate repayment, while deficits are capitalized at a current interest rate. If the study projects that rates will under collect the required revenue, Western begins a public process to adjust its rates accordingly.

How are power rates impacted by drought?
For more than 10 years, Western saw higher expenses to cover increased power purchases due to drought. As the drought lowered generation, Western purchased more power to meet its firm power commitments to customers. As the water systems recover and refill the reservoirs, Western anticipates having more hydropower to market. Even through the drought, Western customers continued to cover all of its operating costs, including purchase power, through firm power rates, except where Western has contract arrangements in place to make purchases on a pass-through cost basis. Using flexible provisions in our power sales contracts, Western can adjust power rates through a public process to deal with changes in the environment.

The status of some of Western’s most drought-impacted rate-setting systems in FY 2010 include:

  • Central Valley Project saw the end of the drought period in FY 2011. Several different services are marketed under the current Power Marketing Plan. So depending upon the product or service received, the percentage of rate increase will vary with the increases associated with any actions taken to lessen the impacts of the drought. Base Resource power is marketed as a “take or pay resource.” Under this arrangement, since the power customers are not guaranteed a defined quantity of power, they, and not Western, assume the entire hydrological variability and risk. Their derived rate is dependant primarily on the available CVP hydropower subject to water conditions and operating constraints due to environmental and biological opinions. So as the hydrology has improved, CVP has been able to increase the amount of hydropower marketed to customers, thus improving the value of power.
  • Boulder Canyon Project is expected to see a 13.4 percent rate increase Oct. 1, 2012.
  • Loveland Area Projects saw an 11.2 percent increase Jan. 1, 2010. The increase is due mostly to the extended impact of the drought. The drought-adder rate component (16.34 mills/kWh of the 41.42 mills/kWh composite rate) clearly identifies how much of the rate is due to drought-related expenses. In the last two years, the LAP river basins have experienced above normal inflows and reservoir levels are currently above normal.
  • Pick-Sloan Missouri River Basin Program—Eastern Division is still in financial recovery mode from the effect of years of drought and the need to increase purchase power. In January 2010 the new rate for firm electric service resulted in an overall composite rate increase of about 13.3 percent above the 2009 composite rate. In the last two years, the Missouri river system has experienced above normal runoff and reservoir levels have returned to normal. Recent generation forecasts from the Army Corps of Engineers for the regionRedirect link to a non-Western site and the Bureau of Reclamation for Yellowtail DamRedirect link to a non-Western site put generation for 2011 above average.

    Jointly with the Loveland Area Projects, Pick-Sloan—Eastern Division implemented a drought-adder rate component in January 2008 to specifically identify drought-related expenses. Making up almost half of the composite rate (16.67 mills/KWh of the 33.54 mills/kWh overall rate) explains how costly the drought has been. The drought adder can be annually adjusted to account for changes in hydropower availability because of drought.
  • Salt Lake City Area Integrated Projects saw a 22-percent increase Oct. 1, 2005 and another 6-percent increase Oct. 1, 2008 with the first step of a two-step rate. The second step increased the rate in 2009 by 11 percent and since then has remained the same with then next potential rate change projected for FY 2014.

What is a drought-adder rate component?
A drought-adder rate component recovers costs due to drought-related expenses. Identifying the component as a separate rate clearly identifies those costs specifically due to drought and allows for more timely adjustments of the drought adder rate. Currently both Loveland Area Projects and Pick Sloan Missouri River Basin Program use this component to recover those costs directly related to drought, seasonal flooding and low system storage.

How is drought affecting power production at Hoover Dam?
While many other systems in Western territory have seen increased hydrology, Lake Powell and Lake Mead (Hoover Dam) continue to see depleted hydropower generation capability due to low reservoir levels. Marketed as the Boulder-Canyon Project, Western does not need to purchase power to compensate for any reduced generation at Hoover because that power is sold on an as-available basis for both capacity and energy. These contracts allow Boulder Canyon customers to ask Western to purchase energy on their behalf and pass-through the cost, but such requests have been infrequent.

If an emergency water shortage is declared for the Lower Colorado River Basin, how would that affect Western?
Western sells power from four dams on the Lower Colorado River, including Davis, Glen Canyon, Hoover and Parker dams. In response to the persistent drought and declining Hoover Dam elevations, the Department of Interior issued its December 2007 Record of Decision on the Colorado River Interim Guidelines for Lower Basin Shortages and the Coordinated Operations of Lake Powell and Lake Mead, otherwise known as the Interim Guidelines. For the first time, shortage criteria was put in place to govern the operation of Hoover and Glen Canyon dams. The shortage criteria basically states that at certain Hoover Dam elevations, downstream water demands will be reduced accordingly, and subsequently power production. In November 2010, the Hoover Dam elevation came within 7 feet of triggering the shortage criteria. Not since May 1937, when Hoover Dam was initially filling, has Hoover Dam elevation been this low. If generation is further reduced for the Boulder-Canyon project, customers could request Western to purchase energy on their behalf and pass-through the costs to supplement their power supply.

Purchase Power Costs chart shows:How much did Western spend on purchased power in FY 2010 and how does that compare to purchases in previous years?
Western spent almost $377.1 million in FY 2010 Western wide for 9.3 million MWh of purchased power, compared to almost $612 million in FY 2008 for 11.1 million MWh—the highest amount Western has paid for purchased power in more than 10 years. 





What is the largest amount of electric power that Western has delivered to meet customer power use?  Western served a peak load of 7,237 MW on July 18, 1995.


Power marketing service areas

How are Western’s marketing areas determined? Power sold by the power marketing administrations is generally distributed within the watershed of the river in which power is generated or in states that are partially within the watershed. This keeps the benefit of low-cost hydroelectric power within the region for such entities as military bases, Native American tribes or cities and towns that serve the area’s population.

In addition, it is more difficult to deliver electricity across long distances because of transmission line constraints, multiple charges for transmission over multiple systems and the physical loss of energy due to resistance in the transmission line conductors. All of these factors can make delivery outside the region impractical or higher in cost.

Where does Western fit into the Department of Energy?  Western is one of four power marketing administrations within the Department of Energy. Western's Administrator reports to the Deputy Energy Secretary.

What is a power marketing administration?  There are four PMAs in the United States: Western, Bonneville, Southeastern and Southwestern power administrations. All administrations primarily market power generated at Federal dams at cost-based rates to consumer-owned utilities. They serve 60 million Americans in 34 states. Marketing of power by these PMAs s is one of many purposes of multi-purpose water projects, such as the Boulder Canyon Project, which includes the Hoover Dam. These water projects were built primarily for irrigation and flood control, but they also have many other purposes, including power marketing, which is handled by the power marketing administrations.

What types of power/services does Western provide?  The main types of service include power marketing, transmission and ancillary services. Under power marketing services, we offer: long-term firm power and long-term peaking power sales; nonfirm energy/short-term sales and purchases; and seasonal power sales. For the Central Valley Project system, we offer a percentage of the output of the system and firming purchases. Transmission services include point-to-point service—transmission between points of receipt and delivery; Network Integration Transmission Service—delivering capacity and energy over a transmission network. Ancillary Services are services that support the transmission of capacity and energy from resources to loads while maintaining reliable system operation. These include scheduling, system control and dispatch; reactive supply and voltage control from generation sources service; regulation and frequency response services; operating reserve—spinning reserve service; and operating reserve-supplemental reserve service.


Power sales

Where does Western get the power available to sell?  Western sells and transmits power generated at 14 different multipurpose water resource projects throughout the West, which are managed by the U.S Bureau of Reclamation, U.S. Army Corps of Engineers and the State Department’s International Boundary and Water Commission. We also sell the United States’ 547-MW entitlement from the coal-fired Navajo Generating Station near Page, Ariz., and transmit power through our entitlements on the Pacific NW-SW Intertie Project. In FY 2005, Western sold 35.5 billion kWh of power.


Purchase power

Why does Western sometimes purchase power?  By contract, Western guarantees to provide a certain amount of power to firm power customers. This means that when enough h ydrogeneration is not available due to drought or operational constraints, such as curtailed water releases for environmental reasons, then Western must purchase power from the open market from other utilities or independent power producers. Western may elect to purchase power in advance or buy on the open spot market.

  • Western also regularly purchases energy to meet our responsibilities as operators of four control areas (dispatch centers). Because we are required to match generation to load, we sometimes must buy energy to follow the hourly variations in customer loads. The costs of these purchases are passed on to the customer that has caused the imbalance.
  • Western also sells surplus energy when generation is greater than our contractual commitments.

In the CVP system , the customer has a percentage of the hourly output of the system. Western purchases firming energy to meet project use load or at the request of customers to guarantee a firm supply.  



Do our customers pay the same rates?  Western bundles power from the Federal resources into 10 different projects for marketing purposes. Customers pay the same rate for long-term firm power if they receive power from the same project . Rates vary from project to project.

Federal law requires Western to set its rates to cover all costs associated with power generation and transmission, including part of the cost of constructing the multi-purpose water project. This includes all operating and investment costs—including interest—plus the requirement to repay irrigation investment costs that are above what the irrigators can afford to repay.

Rates are set in a formal public process after Western conducts annual power repayment studies to ensure power rates for each project are adequate. Data in the study include historic expenses and investments already repaid from power revenues, as well as projections for future years. Also listed are estimated annual repayment of generation and transmission investment costs throughout the project's repayment period. More specifically, the studies detail year-by-year revenues and expenses, estimated amounts of investment and interest to be paid each year and the total amount of investment remaining to be repaid. Historical data is gathered primarily from accounting records through the last fiscal year. In addition to Western's marketing and billing records, generation, hydrology and project data, historical and projected figures are provided by the Bureau of Reclamation, the Army Corps of Engineers and the International Boundary and Water Commission. The Bureau and Corps also contribute hydrological forecasting data used to project resource sales and any required purchases.

Western’s firm power rates are cost-based, not based on what the market will bear. Western and the other power marketing administrations are non-profit, so rate calculations do not have to include a return to shareholders. PMA resources are mostly hydropower, so there is no fuel cost. The PMAs sell power at wholesale, which means that there are no distribution costs included in our rates. Western is also not responsible for load growth, so the cost of obtaining additional power resources is not included in rates. Some of the water resource development projects from which Western sells power are largely repaid, so annual costs drive the rate; the impact of repayment of principal and interest is relatively small. Also, the rates that PMAs charge reflect the results of cost containment.

When and why do Western rates change?   Western runs a power repayment study for each project annually to determine if current rates are sufficient to cover annual operation and maintenance costs for Western and the generating agencies and repay the Federal investment, plus interest, in the power and transmission facilities, as well as other costs assigned to power, such as aid to irrigation.

Power repayment studies normally use long-term, average generation expected in all future years of the study. During low-water years, however, Western incurs additional expenses for purchase power to meet contractual obligations and cannot repay as much principal. Any deficits in repaying annual expenses or missing required payments are capitalized at the current interest rate. This can lead to a rate increase if the repayment study shows revenues are not sufficient to meet current operation and maintenance expenses.

Using flexible provisions in our power sales contracts, Western adjusts power rates through a public process. Customers can opt out of their contracts if they don't like the rate change.

What is Western’s composite rate?  Western’s composite firm power rate is an average of the rates charged by Western’s 10 rate-setting power systems. No customers pay this composite rate. Customers pay the specific rate charged by the project from which they buy power. The composite rate is useful for comparative purposes. Western’s composite rate in FY 2005 was 21.02 mills per kilowatthour. A mill is one tenth of one cent, so the composite rate is about 2.1 cents per kilowatthour. Western’s composite transmission rate is $1.79 kW/month.


Resource pools

What are resource pools?
Several projects include a small amount of power in a resource pool that’s set aside to be marketed to new customers. Projects with resource pools include Pick-Sloan Missouri Basin—Eastern Division, Loveland Area Projects, Salt Lake City Area/Integrated Projects, Central Valley Project and beginning in 2008, Parker-Davis. This power is withdrawn from current customers at the end of a specific contract term and then is offered to new customers. In some projects, we have also included withdrawals at five- and 10-year intervals to make additional power available for allocations to new customers.


Federal Energy Regulatory Commission

Does the Federal Energy Regulatory Commission oversee Western?  Although the Federal Energy Regulatory Commission does not have jurisdiction over Western for most purposes, Western is a transmitting utility and subject to FERC jurisdiction under section 211 of the Federal Power Act. However, because Western is a major transmission system owner and provides wholesale electricity across the West, we voluntarily choose to follow many FERC rules. FERC does have final authority over Western’s rates not as a matter of law, but by virtue of a delegation order signed by the Secretary of Energy. The Commission may confirm, approve and place the final rate in effect, reject it or send it back to Western for further study.  In addition, the Energy Policy Act of 2005 has expanded FERC's authority over Western. The Act gives FERC increased authority to issue rules governing how market price information is published, to obtain market price and availability information from any market participant, including Western, and to publish rules prohibiting market manipulation.  In addition, the Act allows FERC to order Western to provide comparable open access and transmisison service under terms that are not discriminatory or show preference. It also grants FERC refund authority over Western under section 206 of the Federal Power Act to achieve a just rate if Western makes a voluntary short-term sale of electric energy through an organized market.  The Act further expands FERC's jurisdiction over Western by requiring Western to comply with certain filing and notice provisions defined in the Federal Power Act.

What authority does FERC have in Western's rate-setting process?  FERC's review of Western's rates is much more limited than the manner in which it regulates Investor Owned Utilities. FERC reviews Westerns rates to ensure that they are adequate to cover Westerns costs and may reject Western’s decisions only if it finds they are arbitrary, capricious or in violation of law or regulation. Western's Administrator develops a final proposed rate, which is then sent to the Deputy Secretary of Energy to confirm, approve and either placed into effect on an interim basis or proceed directly to FERC for final approval. Next, the rate is sent to FERC. FERC may then confirm, approve and place the final rate in effect, reject it or send it back to Western for further study.