Rob Gramlich is the Policy Director of the American Wind Energy Association in Washington, DC.Wind Integration in the USA

Rob Gramlich is the Policy Director of the American Wind Energy Association in Washington, DC.
By Rob Gramlich, AWEA

The optimal conditions for integrating large amounts of wind energy at low cost include a large electric balancing area with access to neighboring markets, a robust electric grid, short-term electricity generation markets, flexible generation and load, the effective integration of wind forecasts into utility operations, and flexible transmission services.

The current state of affairs in the U.S. electric industry falls short of each of these ideals.

Wind generation has become a mainstream utility scale energy source. In 2007, wind generation accounted for 30 percent of new installed capacity in the U.S. In parts of Europe wind is providing 10 to 20 percent of annual electricity needs.

There is a rapidly expanding body of research and experience with integrating wind into electric power systems around the world.

This research and experience is sufficiently developed to indicate both the importance of electric industry structure, rules, and infrastructure, and the particular types of structure, rules, and infrastructure that integrate the most wind energy while maintaining reliability.

Wind energy has four characteristics that affect how it is integrated into power systems: 1) its variability, 2), its near-zero variable cost, 3) the difficulty of forecasting its output precisely, and 4) its remoteness. These characteristics can be better accommodated in some market structures than others.

Larger Balancing Areas
A number of studies have documented that wind integration costs are significantly lower in large balancing areas. Larger balancing areas provide more opportunity for excess generation in one region to be offset by shortfalls in generation in another region. This effect is true even for systems without wind energy. However, this effect is often even more pronounced for wind energy, as variations in wind output tend to be less correlated over larger geographic regions.

A wind integration study conducted in Minnesota in 2005 found that consolidating the state’s four balancing areas into a single balancing area would reduce the requirement for regulation services by 50%.
In addition, a larger balancing area provides a larger pool of flexible resources that can be used to accommodate variations in electricity supply or demand. The ability to export power to neighboring regions is particularly useful during minimum load situations in regions with many must-run generators, as it allows excess power to be exported to nearby regions that can use this power.

A Robust Electric Grid
An important asset for allowing power flows to neighboring regions is an electric grid with robust regional interconnections. Regional transmission planning processes with effective processes to allocate the costs of new transmission tend to result in more transmission capacity being built between neighboring regions.
The Western Governors Association Clean and Diversified Energy Advisory Committee evaluated a “high renewables” case and found that it required 3,578 line miles of transmission above the 3,956 line miles required in the reference case, at a total cost of $15.2 billion for transmission to serve all the generation in the high renewables case. Transmission is currently constraining wind development as interconnection queues continue to be filled up and a lack of available transmission capacity continues to limit deliveries.

Shorter-term Markets
Grid integration studies have also found that electricity market design can have a significant impact on the cost of integrating wind. A March 2007 study of wind integration costs in the Northwest U.S. calculated that ten-minute markets would reduce wind integration costs by 40-60% compared to hourly markets.

Similarly, the presence of five-minute markets in California plays a large role in keeping incremental load following costs for higher wind penetrations at approximately zero. This is because wind output tends to be relatively constant over ten-minute periods of time, although it can vary significantly over the course of an hour. In regions with hourly markets, significant deviations in wind output over the course of an hour often must be accommodated through the use of regulation services, which are typically the most expensive type of ancillary services.

More Flexibility
Wind integration studies have also found that electric grid systems with more flexible generators tend to have lower integration costs.

For example, systems with large amounts of flexible hydroelectric and natural gas generation will tend to have lower integration costs than systems with inflexible generators such as nuclear and coal power plants. In fact, the study of California’s grid calculated that the load following cost for integrating wind energy is essentially zero, in part because of the large available stack of flexible generators in the state.

In the future, smart grid technology offers significant potential for electric load to be dispatched just as generators are dispatched today. Plug-in hybrid electric vehicles that are attached to the grid using smart grid technology also have significant potential to provide demand-side flexibility in the future.

Wind Forecasting Integrated
Integrating wind forecasts into system operations can also significantly reduce the cost of accommodating wind energy on the electric grid. Without a reliable forecast, in regions with large amounts of wind energy grid operators would have to maintain significant reserves to accommodate potential variations in wind output.

Reliable wind forecasts allow system operators to significantly reduce their uncertainty about future wind output, and wind forecasting techniques available today have a very high degree of accuracy. The California grid study found that the use of existing wind forecasting techniques reduced grid integration costs by $4.37/MWh.

Flexible Transmission
Although the U.S. electric grid is highly congested during a small number of hours per year, for the majority of the year only a fraction of available transmission capacity is used. In addition, wind plants tend to produce the most electricity during these off-peak times. As a result, there are significant opportunities for wind energy facilities to use spare transmission capacity outside of peak times.  It is also possible to dynamically rate transmission such that more is made available when wind blows and cools the transmission lines, allowing more transfers.  In the ideal electric system, such options would be made available to transmission customers including wind generators.

Energy Market Diversity
Approximately two-thirds of the country’s transmission system is operated by Regional Transmission Organizations (RTOs) or Independent System Operators (ISOs, which are similar in function but usually smaller). Other parts of the country have large vertically integrated utilities that operate most of the system. Other regions, including much of the middle of the country where the best wind resources are located, have small, balkanized systems with weak links to each other and to urban load centers.
There are some very large Balancing Authorities and some very small. There are some with peak loads over 100 Gigawatts and some under 100 Megawatts. Generally the ISO and RTO areas have the larger balancing areas. The middle of the country where a lot of wind resource is located tends to have smaller areas.

Some regions coordinate transmission plans in a centralized fashion. The ISOs and RTOs tend to do this. Other regions have less coordinated transmission planning. Many utilities tend to focus their planning efforts on local generation to serve local load, without much consideration for opportunities to access more distant resources or to coordinate with neighbors on joint resource plans.

Transmission services vary considerably between RTO/ISO-operated areas and non-RTO/ISO areas. In RTOs, transmission service spans the region of the RTO/ISO footprint so it is a one-stop shop for transmission. Transmission rights are financial in most cases, not physical, which provides more flexibility for variable resource generators to pay for the transmission they use as opposed to paying to reserve capacity all day every day. Outside of RTO/ISO areas, transmission services follow FERC pro forma tariffs, require physical reservations, and are provided in a way so that customers who want service across the assets of multiple owners must pay multiple “pancaked” transmission rates.

Regulatory Oversight Diversity
Electric utilities have many masters. Investor owned utilities typically have 80% of their assets regulated by state public utilities commissions, and 20% by FERC which regulates wholesale transmission and power sales. Municipal utilities are overseen by the governments of which they are a part, and do not file rate cases with regulators.

Cooperatives are overseen by boards made up of their consumers. The Department of Energy has almost no jurisdiction or authority over the electric industry. DOE’s role changed only recently with the Energy Policy Act of 2005 granting DOE a role in designating transmission corridors, but this policy is unproven and has had no effect to date.

While DOE houses the Power Marketing Administrations including Bonneville Power Administration in the moderately windy Pacific Northwest and the Western Area Power Administration in much of the very windy Great Plains, political control of these agencies lies more with the Congressional offices that represent their customers. With U.S. electric utilities reporting to so many different entities, it is very difficult to move the industry towards the greater regional coordination and planning that is needed for many purposes.

Competition vs. Regulation
Public policy has also affected U.S. electric utilities in very different ways. The push in the 1990s for open competitive wholesale markets led to many changes towards the ideal structure from a wind industry perspective, namely larger regional open competitive wholesale markets. There was also a push for retail competition in a number of states. As a result, there are investor-owned utilities in restructured states and regions that own assets in these sectors but face competition in generation and in serving load.
There remain, however, many fully integrated utilities that have no competition at the retail level and almost no competition in generation.

Political support for competitive reforms has substantially waned due to the California energy crisis and rate shock in some states that have retail competition and retail rate caps expired at a time when costs were high.

Policy makers generally do not distinguish wholesale competition from retail competition, so even though large regional competitive wholesale markets would benefit reliability and efficiency, they have lost support due to political opposition to markets in general.

Michael Goggin is an Electric Industry Analyst with AWEA in Washngton, DC and contributed to this article.