Wind Energy in the West: Transmission, Operations, and Market Reforms

Vol. 26 No. 3

Ms. Gardner is an attorney/policy analyst with the Western Interstate Energy Board, Denver, Colorado. Mr. Lehr is the western representative, American Wind Energy Association, Denver, Colorado.

The benefits of renewable energy have been touted for decades. Wind energy development, in particular, has increased dramatically over the past ten years. In 2009, nearly 10,000 megawatts (MW) of wind was installed, bringing the total wind capacity in the United States to over 35,000 MW—a nearly twelve-fold increase since the year 2000. K. Porter & J. Rogers, Status of Centralized Wind Power Forecasting in North America, Subcontractor Report for NREL, Apr. 2010 (hereinafter Wind Power Forecasting Report). Last year, despite a stagnant economy, cumulative wind power capacity grew by 15 percent, bringing the U.S. total to more than 40,000 MW. U.S. Dep’t of Energy, 2010 Wind Technologies Market Report, Executive Summary (2011). Wind and other renewable energy sources have enormous potential to not only reduce dependence on fossil fuels, but to reduce overall carbon emissions. Yet, despite the inherent benefits of wind power, it is a variable and uncertain generation resource—in other words, the wind is not always blowing. As a result, some have raised concerns regarding the reliability of electric grids that derive a large fraction of their energy from wind. Others have taken issue with the costs of reliably integrating large amounts of variable generation into electric grid operations.

The U.S. transmission system today exists as an interconnected network with more than 150,000 miles of high-voltage transmission lines that transport electricity from generators to consumers. The Honorable Spencer Abraham, Secretary of Energy, National Transmission Grid Study 2 (2002) (hereinafter Transmission Grid Study). This system is comprised of three major electric power systems that are only weakly connected: the Eastern Interconnection, the Western Interconnection, and the Electric Reliability Council of Texas (ERCOT). While this network performs well most of the time, weaknesses do emerge. On rare occasions, the stresses on these networks become so intense that they break down, causing blackouts such as the one that shut down the power system in the Northeast and Midwest on August 14, 2003, or the blackout that affected nearly five million people in San Diego County, Baja California, and parts of Arizona in early September. Given these weaknesses, today’s transmission debate focuses on how best to strengthen these weak network sections and incorporate renewable sources of energy onto the grid, the backbone of U.S. electricity system.

Lack of cost-effective transmission has been, and remains, the single greatest impediment to rapid development of utility-scale renewable energy in the United States. The North American Electricity Reliability Corporation (NERC) projects that over 145,000 MW of renewable energy will be added to the North American electric grid over the next ten years—if only half comes into service, it will account for a 350 percent increase in renewable energy since 2008. NERC, Accommodating High Levels of Variable Generation, Executive Summary (2009).

However, for a variety of systemic reasons, expanding the transmission grid to support renewables is challenging. Renewable energy developers do not always have the financial capability to support large-scale transmission investment, yet transmission is often not built because of uncertainty about whether renewable energy projects will actually be developed. On the other hand, although renewable energy developers can build wind and other renewable energy projects in as little as two or three years, transmission is not always available to transport energy produced from those projects to high demand areas. Even if these critical financial and timing problems can be solved, other obstacles remain. Five primary obstacles inhibiting the development of a robust U.S. transmission system that can best utilize renewable energy include: (1) the location-constrained nature of renewables; (2) the need for improved electric grid flexibility; (3) the need for transmission expansion; (4) solving cost allocation issues related to transmission expansion; and (5) determining fair transmission access rates.

Location-constrained nature of renewables. In the West, where renewable resources are abundant, the best sources of renewables are often located far from loads. Because wind’s value as an energy source is directly proportional to wind speed, the best wind economics result where the most powerful wind resources are “tapped”––typically in remote areas far from major population centers. So, for wind developers, the cost of transmission facilities for wind developments are often higher than for conventional energy plants that can be located nearer transmission facilities and system loads. Darrel Blakeway & Carol Brotman White, Tapping the Power of Wind: FERC Initiatives to Facilitate Transmission of Wind Power, 26 Energy L.J. 393, 401 (2005).

Need for improved grid flexibility. Today’s electric grid operates in response to fluctuating loads and is therefore inherently flexible by incorporating a variety of energy sources. Electric system operators play a key role in this flexibility by ensuring that a balance between generation and demand always exists in their respective control areas. Because demand fluctuates mostly in response to weather, as system operators continue to integrate wind, they will confront additional uncertainty on the generation side due to wind’s inherent variability. This will significantly increase the demands placed on operators to manage the generation and load balancing process and, thus, will require additional flexibility from the grid.

Need for transmission line expansion. New transmission line construction presents additional hurdles to renewable energy development. The process to plan and build new transmission lines is often long and, at times, controversial. Controversy can range from environmental concerns (particularly when building on the federal lands common in the West) to “NIMBY” (Not In My Backyard) concerns from local communities where added transmission lines may be viewed as unsightly or undesirable. In addition to potential controversy over transmission expansion, obtaining the necessary approvals from local, state, and tribal siting authorities can prove difficult. Assuming the necessary approvals have been obtained, who pays for transmission costs must still be determined. New transmission tends to be expensive, but when viewed in terms of its potential to reduce generation costs, it is a relative bargain when a utility’s ability to access lower-cost generation more than makes up for investments in new transmission lines. Yet, determining who pays for transmission upgrades never fails to present a challenge.

Cost allocation issues. Examples of typical cost allocation methods for new transmission include “participant funding” and “socialization” of costs. Under the participant funding method, a wind developer pays for all upgrades in exchange for transmission rights or credits for future transmission service. Bruce Edelston, Participant Funding: The Se Trans Proposal, Presentation to HEPG (Dec. 11, 2003). By contrast, the socialization method requires the utility transmission owner to pay for all new lines and upgrades to its transmission system. Matthew H. Brown & Richard P. Sedano, Electricity Transmission: A Primer 22 (2004) (hereinafter Electricity Transmission: A Primer). Much of Texas’ grid—ERCOT—broadly recovers costs using this method, resulting in utility companies providing the upfront financing and passing those costs on to their customers, which means that utility customers ultimately pay for all transmission upgrades. Id. at 22–23.

In practice, most of the United States has adopted or is considering some form of cost recovery that combines participant funding and socialization by spreading only some costs to utility customers. For example, Southwest Power Pool (SPP) and Midwest Independent Transmission System Operator (MISO) both have filed requests at FERC for regional cost allocation mechanisms that broadly allocate costs of regionally beneficial transmission projects.

FERC Order 1000, issued July 21, 2011, has the potential to address the still unresolved issue of cost allocation. Order 1000, which focuses on regional transmission planning, follows the “beneficiary pays” principle, allocating costs for new transmission facilities to the beneficiaries of those facilities rather than socializing those costs on a regional or national basis. FERC Transmission Planning, Cost Allocation Reforms to Benefit Consumers. While the order allows the participant funding method to be used for new transmission facilities, it cannot be used as the regional or interregional cost allocation method. FERC Staff, Final Rule on Transmission Planning and Cost Allocation by Transmission Owning and Operating Public Utilities: Briefing on Order No. 1000 (July 27, 2011). However, because Order 1000 did not take effect until October, it is too soon know whether it truly resolves the debate surrounding cost allocation of new transmission. Id.

Transmission access rates. Transmission access pricing is yet another transmission-related consideration. Experts typically describe four methods for setting transmission rates: (1) pancaked rates; (2) postage stamp pricing; (3) license plate pricing; and (4) distance-sensitive pricing. Electricity Transmission: A Primer at 24–25. Each method attempts to establish a means for users of a power system to pay transmission system owners for using their transmission lines.

“Pancaked” rates are paid when power traverses more than one power system and where each system charges its full rate to provide transmission service. Scott Hempling, Postage Stamp Pricing: The Seventh Circuit Reverses FERC 2 (2009). This method of pricing for a regional transmission system, common in the West, is expensive and tends to discourage companies from sending power over long distances and through several transmission systems, regardless of the value to consumers.

“Postage stamp” pricing is similar to that of actual postage stamp pricing. The per-unit fee to use the transmission system within a single zone is the same, whether the power is contracted to move 100 feet or 100 miles. Companies located in less densely populated areas and in higher cost areas tend to favor postage stamp pricing.

“License plate” pricing occurs when companies that use the transmission grid pay different prices based on costs at points at which power is delivered into their area. The license plate metaphor applies because each company pays a fee to obtain access to the transmission system and can use any part of the system after paying that fee. Companies based in low-cost areas—generally, dense metropolitan areas—tend to favor this approach.

“Distance-sensitive” pricing is dependent upon the cost of moving power over varying distances. Sheila S. Hollis, The Electric Industry Opportunities and Impacts for Resource Producers, Power Generators, Marketers, and Consumers, Rocky Mountain Mineral Law Special Institute, 42B Special Institute, Chap. 13 (1996). For example, users who contract to use the transmission system for 10 miles would pay less than those who use it for 100 miles. Distance-sensitive rates tend to discourage investments in long distance transmission.


In addition to transmission-focused obstacles, there are numerous operations-based obstacles that also impact renewable energy integration, including power plant operations and forecasting. These issues relate to the multifaceted nature of electricity generation. To meet the ever-changing demand for energy, utilities build and operate a variety of power plant types, typically categorized as: (1) baseload; (2) load following; (3) intermediate load; and (4) peaking. Baseload plants are used to meet the large basic daily demand for electricity, usually nuclear, coal-fired, or hydroelectric plants, which run at full output as much as possible. In contrast, predictable variation in load is typically met with load following or “cycling” plants. These units are typically hydroelectric generators or plants fueled with natural gas or oil. Load following units are further categorized as “intermediate load” plants used to meet most of the day-to-day variable demand and “peaking” units designed to meet peak demand. Renewables are typically used to meet intermediate load. Although old, smaller coal plants and natural gas generators can also be used for intermediate load, they are more expensive to run.

Power plant operations. The variable nature of wind energy affects the operation of existing power plants in three primary operating time frames: (1) regulation; (2) load following; and (3) unit commitment. “Regulation” refers to changes in generation requirements occurring in short time frames (i.e., seconds to minutes). Regulation is provided by automated systems that provide generation ramping in response to short-term mismatches between generation and load. Brendan Kirby & Eric Hirst, Generator Response to Intrahour Load Fluctuations 3 (2002). These mismatches are generally increased when variable sources of renewable energy are incorporated into the electric grid.

“Load following” refers to generation changes resulting from more long-term (i.e., hourly) ramping requirements related to changes in loads. Paul Denholm et al., The Role of Energy Storage with Renewable Electricity Generation, Technical Report for NREL (Jan. 2010) (hereinafter NREL Technical Report). Load following differs from regulation in that load following occurs over longer time intervals and changes in load following are often predictable and have similar day-to-day patterns, whereas regulation patterns do not. Eric Hirst & Brendan Kirby, Measuring Generator Performance in Providing Regulation and Load-Following Ancillary Services 1 (2001). As with regulation, the integration of a variable resource such as wind to the grid will, in most cases, increase load following costs.

“Unit commitment” refers to longer-term decisions to commit generation units to service from days to weeks ahead. M. Milligan & B. Kirby, Impact of Balancing Areas Size, Obligation Sharing, and Ramping Capability on Wind Integration 35 (2007). The purpose of unit commitment is to determine the least-cost mix of generation available at each interval for the next several days. Increased costs can result from having a suboptimal mix of units online because of errors in unit commitments. These errors can follow from weather forecasts, wind-specific forecasts, and an inability to access planned generation due to unscheduled outages. NREL Technical Report. Adding a variable energy resource like wind complicates the unit commitment process in that energy requirements, ramping requirements, and forecast errors all change.

Forecasting. In addition to general plant operations, system operators’ reliance on variable energy resources like wind makes balancing energy and demand increasingly difficult—particularly in the spring and in the evening, when wind tends to “ramp up.” Further, increased costs are associated with having excess generating units online in case wind unexpectedly “ramps down.” Improved wind forecasting can help reduce these costs.

While all agree that improved wind forecasting is needed, differences in opinion abound over how. Discussions about wind forecasting methods often center upon whether forecasts should be centralized or decentralized. Centralized forecasting refers to one forecast supplier providing forecasts for all wind power facilities in a specified geographic area, whereas decentralized forecasting refers to one or more forecast suppliers providing individual and independent forecasts on a wind farm-by-wind farm basis. Wind Power Forecasting Report. Additionally, ensemble forecasting should be considered. Ensemble forecasting describes forecasting methods (used on a centralized or decentralized basis) that test the simultaneous use of multiple forecasting methodologies within the same meteorological zone in order to determine the best forecasting tools to apply to different weather scenarios. Id. By employing an ensemble of wind forecasts, forecast errors can be reduced as the forecast errors from individual wind forecasting models tend to cancel out.


In addition to plant operations, forecasting, and transmission rates, another potential barrier to wind integration is market structure. Most of the electricity generated in the United States today is managed in competitive wholesale markets through Regional Transmission Operators (RTOs) or Independent System Operators (ISOs). Transmission Grid Study at 24. An RTO or ISO operates the transmission assets of numerous utilities in a region. One notable trait of an RTO is its size—RTOs cover large regions rather than the smaller in-state areas typically covered by utility control areas in the West. Ideally, an RTO or ISO is independent of any market participant, provides fair and open access to its grid for any market participant desiring to engage in transactions, and impartially allocates transmission capacity in the event of a transmission constraint. Lisa G. Dowden, The RTO In Your Future: What Should You Know?, 16 Nat. Res. & Env’t 247 (Spring 2002).

In contrast to the RTOs and ISOs commonplace to the East, Midwest, and California, the West is organized by utility control areas—also referred to as “balancing areas” or “balancing authority areas.” ScottMadden, Inc., Emerging Regional Electricity Market Issues 2 (2009). In the West, balancing authority areas (BAAs) are operated by balancing authorities (BAs)—entities that manage generation supply and demand within their own jurisdictional boundaries and interchange power with adjacent utilities and other BAAs as needed. Currently, there are 38 balancing authorities in the Western Interconnection. Western Governors’ Association, Map of Current Western Interconnection Balancing Authorities.

Operators in a BAA must balance load and resources and keep track of imports and exports, all while load is continuously changing. BAs do this by operating hourly (i.e., scheduling loads at each hour of the day). The basic test of success in this balancing is known as Area Control Error (ACE). Sixth Northwest Conservation and Electric Power Plan – Chapter 12: Capacity and Flexibility Resources 12-6 (2010). ACE is a measurement, calculated every four seconds, of imbalance between load and generation within a BA, taking into account previously planned imports and exports of electricity and interconnection frequency. Id. ACE is designed to minimize what are called “frequency excursions” (i.e., spikes and dips in frequency measurement). The effect of wind and other variable generation on the BA’s ability to balance generation and load has raised operator concerns regarding the costs of maintaining ACE within NERC’s required reliability limits.

Various “balancing tools” have been proposed to combat these reliability concerns, as well as concerns pertaining to what many view as inefficiencies inherent in the West’s balkanized BA structure. These tools are designed to enhance both the reliability and efficiency of balancing load and generation as variable generation increases between and within BAs.

The Western Electricity Coordinating Council’s (WECC’s) Efficient Dispatch Toolkit (EDT) is one such proposal. It is designed to enable increased use of transmission facilities in the West, which will lower costs for both renewable energy integration and energy supply for balancing market participants. The EDT is comprised of two tools: (1) the Enhanced Curtailment Calculator (ECC) and (2) the Energy Imbalance Market (EIM). Western Interstate Energy Board, New Tools for Integrating Variable Energy Generation Within the Western Interconnection (2011).

The ECC is a seams coordination tool used to manage power flow impacts across all seams (transmission borders) between BAs within the Western Interconnection. The ECC would be used to coordinate curtailments for reliability purposes in order to manage congestion on WECC transmission paths. Michelle Mizumori, Remarks at the WestConnect EIS Work Group (Oct. 28, 2010). Although ideally the ECC and EIM would operate together, the ECC can be developed and implemented independently of the EIM.

The EIM would supply both energy imbalance and congestion management services for those portions of the WECC not within the footprint of the Alberta and California ISOs. WECC Staff, White Paper: WECC Efficient Dispatch Toolkit Cost-Benefit Analysis (2011). More specifically, the EIM would function as a type of “virtual” BA consolidation by allowing BAs to supply energy imbalance and to manage transmission constraints across their borders, rather than only within their borders (as is the current practice). Id.

Another balancing tool is the ACE Diversity Interchange (ADI). ADI is a form of dynamic scheduling that pools the ACE measurements among multiple BAs in order to take advantage of control error diversity (i.e., momentary imbalances of generation and load). ACE Diversity Interchange. Ideally, when multiple BAs pool their ACE responsibilities, they are able to: (1) reduce control burden on individual control areas; (2) reduce generator movement; (3) reduce sensitivity to variable resource output; and (4) improve compliance with NERC reliability standards. Id.

Recommendations: Transmission

There are a number of possible transmission-specific solutions to overcome the challenges and obstacles of incorporating wind and other renewable energy sources into the electric grid. Alternatives include: (1) increased coordination among relevant parties; (2) creation of single state entities for siting authority; (3) construction of new transmission; (4) improved cost allocation for new transmission; and (5) establishment of fair transmission access rates.

Increased coordination among relevant parties. Increasing the coordination among relevant parties will not only assist in the efficient completion of renewable energy projects, but it will help to identify any political or regulatory obstacles to permitting and construction of new transmission lines, particularly those that will cross over multiple jurisdictions. Relevant parties in terms of renewable energy projects and transmission integration include: (1) resource planners; (2) subregional and interconnection-wide transmission planners; (3) transmission developers; (4) federal land use agencies; (5) renewable energy developers; (6) state, provincial and federal regulators; (7) tribal authorities; (8) balancing authorities; and (9) environmental organizations.

Creation of single state entities for siting. In addition to increasing coordination among relevant parties, in terms of siting transmission, consolidated decision making is needed. In some Western states, several governmental entities have responsibility approving transmission siting proposals. As a result, no single entity balances all facets of the project and applicants often are required to submit separate applications to acquire permits from multiple agencies. By assigning siting authority to one agency—such as the state public utility commission or state environmental agency—the inefficiencies inherent in current siting processes can be greatly reduced.

Construction of new transmission. The reality of present transmission systems in the United States is that they are often near their maximum capacity in critical areas—particularly in the West. Furthermore, the West is the fastest growing region in the United States, placing additional pressures on utilities and state authorities to provide more energy to meet the needs of a rapidly expanding population. Although recent studies indicate it is possible to make more effective and efficient use of existing transmission lines, ultimately, without construction of new lines, it will become increasingly difficult to get significant new wind resources to market.

Improved cost allocation for new transmission. By combining participant funding, cost socialization methods, and spreading regional costs to regional beneficiaries (as MISO and SPP have done), construction costs for new transmission can be fairly divided and shared. However, FERC Order 1000 appears to limit cost allocation through its “beneficiary pays” mandate, whereby widespread socialization of costs for new transmission is not permitted, but rather, the specifically identified beneficiaries of new transmission lines are directed to bear the costs. Only time will tell whether Order 1000’s requirements truly resolve the transmission cost allocation debate.

Setting fair transmission access rates. Once new transmission is built, generators seeking access to the grid will want access through the most cost-effective means possible. With this consideration in mind, the existing use of “pancaked rates” in the West should be discouraged, as it makes traversing power over long distances (often necessary in the geographically dispersed West) incredibly expensive. Instead, a switch to “postage stamp” style pricing would make such long-distance transmission access more cost-effective to wind and other renewable energy generators.

Recommendations: Operations and Markets

In addition to increased coordination, siting reforms, and shared cost-recovery mechanisms, changes to existing operations and market structures are needed, including: (1) creation of a single regional BAA or BA consolidation; (2) improved forecasting; and (3) faster scheduling.

Creation of a single BAA or BA consolidation. Creation of a single regional BAA and cooperation within that BAA offers three key benefits: (1) aggregating diverse renewable resources over larger geographic areas reduces overall variability of the renewables; (2) aggregating loads reduces overall load variability; and (3) aggregating the nonrenewable balance of generation provides access to more balancing resources. Because creation of a single BAA creates a larger region in which to balance the variability characteristics of renewable resources of energy, it can also result in savings through the pooling of energy reserves. Alternatively, the virtual consolidation of certain BA functions (i.e., via the ECC, the EIM, ADI, or a combination of all three) can result in similar benefits. For instance, load and wind forecasts are more accurate over larger regions. Further, increasing the size of BAAs—either through consolidation or through sharing of balancing obligations—will reduce the costs of wind integration. Finally, from a purely operational perspective, such BA cooperation can lead to cost savings because generating resources are pooled.

Improved forecasting. While there are advantages and disadvantages to both centralized and decentralized wind forecasting, a centralized forecasting method that is used in combination with other forecasting techniques offers the best chance for accurate forecasting over a larger geographic area. In addition, certain other forecasting techniques should be implemented to increase accuracy of centralized wind forecasting, including: (1) establishment of a central clearinghouse; (2) use of ensemble forecasting; and (3) forecasting over larger geographic areas.

A central clearinghouse is needed for all wind forecasting within the same interconnection. State utility commissions should adopt a common regulatory requirement for utilities and wind plant operators to provide their forecast data to the clearinghouse. The central clearinghouse would be vital in recordkeeping and archiving forecast data, ultimately enabling the clearinghouse to evaluate improvements in forecasts and evaluate timing and impacts of forecast errors.

Ensemble forecasting should be used to take advantage of the best forecasting tools for differing weather situations. Being able to “pick and choose” the best forecasting tool based on the particular weather pattern will result in a reduction of forecasting errors and will improve the accuracy of wind forecasting. Wind Power Forecasting Report.

Additionally, forecasting should be conducted over larger geographic areas in order to reduce aggregate forecasting error. Because there can be a 30 to 50 percent reduction in forecasting error directly resulting from aggregation and geographic dispersion of wind power, wind forecasting over a larger region has a substantial impact on improving forecasting accuracy. Dr. Johannes Teyessen & Martin Fuchs, Wind Report 2005, E.ON Energie (2005). When forecasting is more accurate, power system operators can often more accurately predict and plan for future changes in wind generation.

Faster scheduling. The current practice of scheduling both generation and interstate exchange of electricity only once each hour has a significant impact on regulation duty. At high penetration levels, such hourly scheduling changes can use most, if not all, of the available regulation capability to compensate for ACE ramps. This results in no remaining regulation capability for any subhourly variability. By moving to a 30-minute or, ideally, a 10-minute scheduling window (rather than an hourly one), regulating responsibility can be reduced and used more efficiently.

To most effectively integrate renewable energy resources like wind to the electric grid in the West, changes to the transmission system, the market structure, and the operations systems, must all be made. To make this necessary integration as efficient and cost effective as possible, it will require the implementation of each of the following measures: (1) increased coordination among the relevant parties; (2) construction of new transmission lines; (3) improved cost allocation; (4) implementation of fair transmission access rates; (5) creation of single state entities for siting authority; (6) creation of a single BAA or BA consolidation; (7) improved forecasting; and (8) faster scheduling.

Combined, these measures should not only increase the future development of wind and other renewable energy sources in the West, but should aid in the effective and efficient incorporation of those resources to the electric grid. 


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