Excerpts from the 242 page Eastern Wind Integration & Transmission study, 2011, EnerNex corporation for National Renewable Energy Laboratory.

Key Findings

1. Building transmission capacity takes much longer than installing wind plants. It is already starting to limit wind growth in certain areas. This report concludes that a 20% scenario is unlikely to happen with a business-as-usual approach.
2. Supplying 20% of the electric energy requirements of the U.S. portion of the Eastern Interconnection would call for approximately 225,000 megawatts (MW) of wind generation capacity, which is about a tenfold increase above today’s levels.
3. To reach 30% energy from wind, the installed capacity would have to rise to 330,000 MW.
4. Without transmission enhancements, substantial curtailment (shutting down) of wind generation would be required for all the 20% scenarios.
5. The higher quality winds in the Great Plains have capacity factors that are about 7%–9% higher than onshore wind resources near the high-load urban centers in the East. Offshore equals the Great Plains  but the cost of energy is higher because capital costs are higher.
6. Wind generation cannot be dispatched to meet peak loads. Unlike conventional generating units, only a small fraction of the nameplate capacity rating of a wind plant can be counted on to be available for serving peak loads.
7. The existing transmission infrastructure in the Eastern Interconnection has a limited capacity for accommodating additional wind generation; transmission congestion is already an issue in some areas, including those with the potential for tenfold or greater development in wind capacity.
8. The capital cost of offshore is twice as high as onshore, fixed O&M ($/kW/yr) is 30% higher, and variable O&M ($/MWh) is 3 times higher.
9. Because it is primarily a source of energy, not capacity, wind generation does not fit well into conventional resource adequacy-based transmission planning processes.
10. High amounts of wind generation are likely in off-peak hours or seasons that might not be of special interest for reliability issues.
11. Very large balancing areas with adequate transmission take maximum advantage of diversity in both load and wind generation. By contrast, the Western Interconnection, with the exception of California, comprises smaller, less tightly interconnected balancing areas. Even modest penetrations of wind generation, much smaller than those considered here, can have very significant operational and cost impacts because of the additional requirements they bring for regulation and balancing.
12. Wind generation generally does not appear on peak and contributes less to serving load on peak than off peak. Wind generation on the peak hour in the Midwest ISO for the last 5 years has been 1.2%, 11.4%, 1.2%, 11.8%, and 56%, respectively.

It is important to note that the scenario definitions result in some areas being self-sufficient in wind capacity (wind energy requirements being met with local wind energy production) but others require support from wind located in external regions. Areas that meet the target energy on a regional basis, by scenario, are as follows:

1. Scenario 1: Midwest ISO, MAPP, SPP
2. Scenario 2: Midwest ISO, MAPP, SPP, New England ISO (ISO-NE), New York ISO (NYISO)
3. Scenario 3: MAPP, SPP, PJM, ISO-NE, NYISO
4. Scenario 4: Midwest ISO, MAPP, SPP, PJM, ISO-NE, NYISO

ISO-NE = New England Independent System Operator, MISO = Midwest ISO, NYISO = New York ISO, PJM = PJM Interconnection, SERC = Southeastern Electric Reliability Council, SPP = Southwest Power Pool, TVA – Tennessee Valley Authority

Areas with less than the target amounts by scenario include the following:

Scenario 1: ISO-NE, NYISO, PJM, Southeastern Electric Reliability Council (SERC), TVA, Entergy (operated as part of SERC)

Scenario 2: SERC, TVA, PJM, Entergy

Scenario 3: Midwest ISO, SERC, TVA, Entergy

Scenario 4: SERC, TVA, Entergy

Scenario 4 is 30% wind penetration and requires expensive offshore wind power to meet that goal.

Note that New England, New York, the South East, and Tennessee region have particularly low wind resources. 

Just a few years ago, 5% wind energy penetration was a lofty goal, and to some the idea of integrating 20% wind by 2024 might seem a bit optimistic. And yet, we know from the European experience—where some countries have already reached wind energy penetrations of 10% or higher in a short period of time—that change can occur rapidly and that planning for that change is critically important.

Planning for the expansion of the electrical grid is a process that requires an immense amount of study, dialogue among regional organizations, development of technical methodologies, and communication and coordination among a multitude of important stakeholders. Keeping abreast of the changes is challenging because there are so many different developments, ideas, and viewpoints.

The 20% Report states that although significant costs, challenges, and impacts are associated with a 20% wind scenario, substantial benefits can be shown to overcome the costs.

The growth of domestic wind generation over the past decade has sharpened the focus on two questions: Can the electrical grid accommodate very high amounts of wind energy without jeopardizing security or degrading reliability? And, given that the nation’s current transmission infrastructure is already constraining further development of wind generation in some regions, how could significantly larger amounts of wind energy be developed?

The Eastern Interconnection is one of the 3 synchronous grids covering the lower 48 U.S. states. It extends roughly from the western borders of the Plains states through to the Atlantic coast, excluding most of the state of Texas.

PAGE 23 Figure 1. NERC synchronous interconnections

Page 26: the 4 scenarios by iso authority

The Eastern Wind Data Study. A precursor to EWITS known as the Eastern Wind Data Study (AWS Truewind 2009) identified more than 700 GW of potential future wind plant sites for the eastern United States. All the major analytical elements of EWITS relied on the time series wind generation production data synthesized in this earlier effort. The data cover three historical years—2004, 2005, and 2006—at high spatial (2- km) and temporal (10-minute) resolution. On- and offshore resources are included, along with wind resources for all states.

1. Scenario 1, 20% penetration – High Capacity Factor, Onshore: Utilizes high-quality wind resources in the Great Plains, with other development in the eastern United States where good wind resources exist.
2. Scenario 2, 20% penetration – Hybrid with Offshore: Some wind generation in the Great Plains is moved east. Some East Coast offshore development is included.
3. Scenario 3, 20% penetration – Local with Aggressive Offshore: More wind generation is moved east toward load centers, necessitating broader use of offshore resources. The offshore wind assumptions represent an uppermost limit of what could be developed by 2024 under an aggressive technology-push scenario.
4. Scenario 4, 30% penetration – Aggressive On- and Offshore: Meeting the 30% energy penetration level uses a substantial amount of the higher quality wind resource in the NREL database. A large amount of offshore generation is needed to reach the target energy level.

By the mid-1990s, independent system operators (ISOs) and regional transmission operators (RTOs) began forming to support the introduction of competition in wholesale power markets. Today, two-thirds of the population of the United States and more than one-half of the population of Canada obtain their electricity from transmission systems and organized wholesale electricity markets run by ISOs or RTOs.

The study shows the following:

High penetrations of wind generation—20% to 30% of the electrical energy requirements of the Eastern Interconnection—are technically feasible with significant expansion of the transmission infrastructure.

New transmission will be required for all the future wind scenarios in the Eastern Interconnection, including the Reference Case. Planning for this transmission, then, is imperative because it takes longer to build new transmission capacity than it does to build new wind plants.

Interconnection-wide costs for integrating large amounts of wind generation are manageable with large regional operating pools and significant market, tariff, and operational changes.

Transmission helps reduce the impacts of the variability of the wind, which reduces wind integration costs, increases reliability of the electrical grid, and helps make more efficient use of the available generation resources. Although costs for aggressive expansions of the existing grid are significant, they make up a relatively small portion of the total annualized costs in any of the scenarios studied.

With significant wind generation, forecasting will play a key role in keeping energy markets efficient and reducing the amount of reserves carried while maintaining system security. Large operating areas—in terms of load, generating units, and geography—combined with adequate transmission, are the most effective measures for managing wind generation.

Figure 3. Comparison of scenario costs Although production-related costs constitute a large fraction of the total costs for all scenarios, these decline as the amount of wind generation increases. In scenarios 3 and 4, capital costs for wind generation increase because of slightly lower capacity factors and the much higher capital cost of offshore construction. page 30. It appears scenario 4 is about 175 billion dollars

Transmission costs are a relatively small fraction for all scenarios, with only a small absolute difference seen across the 20% cases. Wind integration costs are measurable but very small relative to the other factors.

The project team also assumed that operations in each area would conform to the same structure. For example, on the day before the operating day, all generating units bid competitively to serve load, and after market clearing, operators perform a security-constrained unit commitment to ensure that adequate capacity will be available to meet forecast load. During the operating day, generators are dispatched frequently to follow short-term demand trends under a fast, subhourly market structure. A competitive ancillary services market supplies regulation, balancing, and unused generation capacity to cover large events such as the loss of major generating facilities.

Wind generation was assigned a firm capacity value of 20%.

The conceptual transmission overlays, shown in Figure 8, consist of multiple 800-kilovolt (kV) high-voltage direct current (HVDC) and extra-high voltage (EHV) AC lines with similar levels of new transmission and common elements for all four scenarios. Tapping the most high-quality wind resources for all three 20% scenarios, the project team arrived at a transmission overlay for Scenario 1 that consists of nine 800-kV HVDC lines and one 400-kV HVDC line. As more wind generation is moved toward the east and more offshore resources are used in Scenario 3, the resulting transmission overlay has the fewest number of HVDC lines, with a total number of five 800-kV HVDC lines and one 400-kV HVDC line. To accommodate the aggressive 30% wind target and deliver a significant amount of offshore wind along the East Coast in Scenario 4, the overlay must be expanded to include ten 800-kV HVDC lines and one 400-kV HVDC line.

The total AC line costs include a 25% margin to approximate the costs of substations and transformers. In addition, the total HVDC line costs include those for terminals, communications, and DC lines. Costs associated with an offshore wind collector system and those for some necessary regional transmission upgrades are not included in the total estimated cost and would increase total transmission costs. With approximately 22,697 miles of new EHV transmission lines, the transmission overlay for Scenario 1 has the highest estimated total cost at $93 billion (US$2009).

The 800-kV HVDC and EHV AC lines are preferred, if not required, because of the volumes of energy that must be transported across and around the interconnection, as well as the distances involved. Similar levels of new transmission are needed across the four scenarios, and certain major facilities appear in all the scenarios.

Modeling indicates that significant wind generation can be accommodated as long as adequate transmission capacity is available and market/operational rules facilitate close cooperation among the operating regions.

Sufficient amounts of wind generation increase the variability and uncertainty in demand that power system operators face from day to day or even from minute to minute. Quantifying how the amounts of wind generation in each of the study scenarios would affect daily operations of the bulk system and estimating the costs of those effects were major components of EWITS.

RESERVE REQUIREMENTS. With large amounts of wind generation, additional operating reserves are needed to support interconnection frequency and maintain balance between generation and load. Because the amounts of wind generation in any of the operating areas, for any of the scenarios, dramatically exceed the levels for which appreciable operating experience exists, the study team conducted statistical and mathematical analyses of the wind generation and load profile. Types of reserves:

1. Contingency Reserves. Reserves to mitigate a “contingency,” which is defined as the unexpected failure or outage of a system component, such as a generator, a transmission line, a circuit breaker, a switch, or another electrical element.
2. Operating Reserves. That capability above firm system demand required to provide for regulation, load forecasting error, forced and scheduled equipment outages, and local area protection. This type of reserve consists of both generation synchronized to the grid and generation that can be synchronized and made capable of serving load within a specified period of time. In the production simulations
3. Regulating Reserves. An amount of reserve that is responsive to automatic generation control (AGC) and is sufficient to provide normal regulating margin. Regulating reserves are the primary tool for maintaining the frequency of the bulk electric system at 60 Hz.
4. Spinning Reserves. The portion of operating reserve consisting of (1) generation synchronized to the system and fully available to serve load within the disturbance recovery period that follows a contingency event; or (2) load fully removable from the system within the disturbance recovery period after a contingency event. The levels of wind generation considered in EWITS increase the amount of operating reserves required to support interconnection frequency and balance the system in real time.

Contingency reserves are not directly affected, but the amount of spinning reserves assigned to regulation duty must increase because of the additional variability and short-term uncertainty of the balancing area demand.

The assumption of large balancing areas does reduce the requirement, however. Under the current operational structure in the Eastern Interconnection, the total amount of regulation that would need to be carried would be dramatically higher.

Figure 9. Regulating reserve requirements by region and scenario. The incremental amount resulting from wind generation is the difference between the scenario number and the load-only value. page 42   quite a bit of extra spinning reserve required.

The fastest changes in balancing area demand—on time scales from a few to tens of seconds—are dominated by load, even with very large amounts of wind generation.

Incremental regulating reserve requirements are driven by errors in short-term (e.g., 10 to 20 minutes ahead) wind generation forecasts.

Because wind is variable and results in ramping, it is important to understand these ramp rates and maintain reserves to cover them as needed.

Wind generation cannot be dispatched to meet peak loads. Unlike conventional generating units, only a small fraction of the nameplate capacity rating of a wind plant can be counted on to be available for serving peak loads. With the amounts of wind generation considered in EWITS, though—more than 200,000 MW—understanding the small fraction in quantitative detail is important because it equates to billions of dollars of capital investment.

Transmission overlay enhancement: As described earlier, the analytical methodology was based on a single pass through what is considered to be an iterative process. Further analysis of the existing results could be used to refine the transmission

Because new transmission will most likely be necessary for much of the future wind power that will be installed in the United States, it is imperative to plan for this transmission. The lead times for building transmission are significantly longer than those for building wind plants.

The Eastern Wind Data Study (AWS Truewind 2009), a precursor to this study, identified more than 700 gigawatts (GW) of potential future wind plant sites for the eastern United States. Wind generation is approaching 30 GW in the United States

The existing transmission infrastructure in the Eastern Interconnection has a limited capacity for accommodating additional wind generation; transmission congestion is already an issue in some areas, including those with the potential for tenfold or greater development in wind capacity. Consequently, evaluating transmission needs was also a major aspect of this study.

1,325 separate wind production plants, most hypothetical and others corresponding to the locations of existing operating wind plants. These plants are aggregations of the 2-kilometer (km) wind simulation grid data from meteorological simulations done by AWS Truewind (2009). The nameplate capacity of these plants varies from 100 megawatts (MW) to greater than 1,400 MW. The total installed nameplate capacity is approximately 700 gigawatts (GW).

The wind data calculated for this study are roughly distributed according to the geographic quality of the wind resources across the eastern United States. Some heavier weighting was given to eastern states because high-capacity wind resources are concentrated in the western states. States like Nebraska and Minnesota have large amounts of high-quality wind; states like New Jersey, Maryland, and Ohio have relatively small amounts.

The plants with the lowest costs typically have the highest capacity factor.

Offshore wind plants tend to have the highest LCOE because of their high capital and maintenance costs—even though their capacity factors are generally quite high. The data in Figure 2-1 reflect approximately 580 GW of onshore wind nameplate capacity and about 100 GW of offshore wind nameplate capacity in the Great Lakes and off the eastern seaboard. Offshore wind is located in waters up to 30 meters (m) deep.

TABLE 2-1. LCOE ECONOMIC ASSUMPTIONS (US $2009) ASSUMPTION ONSHORE OFFSHORE

Another useful way to look at the overall data is in terms of capacity factor versus cumulative nameplate capacity. Capacity factor can be seen as a reasonable proxy for return on construction, carrying, and operations costs.

[The US consumes 4,000 TWh, eastern conn is 70% of popu so 2,800 needed]

SCENARIO 1 In general, this scenario exploits the onshore wind resources with high capacity factors across the interconnection. Consequently, it has the largest Great Plains wind capacity of the three 20% scenarios and takes advantage of the best onshore resources in the East. Table 2-4 shows capacity by operating region. Locations and sizes of individual plants are shown in Figure 2-8.

SCENARIO 2 In Scenario 2, some of the wind generation from the Great Plains is moved eastward. In addition, a modest amount of offshore development is assumed off the East Coast.

SCENARIO 3 To create a contrast with Scenario 1, a large amount of wind generation is moved from the Great Plains nearer to the East Coast load centers. To bring about this shift, a large amount of offshore wind generation is required.

SCENARIO 4 Reaching 30% energy penetration requires more than 300 GW of wind generation, and therefore uses a significant portion of the higher quality wind resources in the NREL database. A large amount of offshore wind is required, and the amounts in the Great Plains are comparable to Scenario 1.

EGEAS has five primary alternatives for region expansion: coal-fired steam turbines, natural-gas-fired combined cycles, natural-gas-fired combustion turbines, nuclear facilities, and wind facilities. Before using the capacity expansion model, the project team eliminated other alternatives such as integrated gasification and combined cycle (IGCC) units with sequestration, biomass, and hydro facilities as options because they were not economically competitive with the conventional resources under the assumptions applied to the analysis.

Wind is given a 20% capacity credit against the required planning margin; all other units produce 100% of available capacity at peak system hours

The amounts of wind generation defined for study in this project exceed the current installed capacity by nearly an order of magnitude. Transmission issues are already limiting wind energy development in some regions, so it is a near certainty that significant new transmission would be necessary to accommodate the much higher amounts of wind generation represented in the Eastern Wind Integration and Transmission Study (EWITS) scenarios.

BACKGROUND The transmission facilities that make up today’s Eastern Interconnection were developed through a planning process that had two basic objectives: (1) to connect specific new generating units to load, and (2) to maintain or enhance the reliability of the bulk power system in the face of growing demand. By building transmission facilities to interconnect with neighbors, capacity resources could be shared in emergencies, reducing the amount of excess capacity an individual utility must maintain to serve load reliably. Opportunities for economic exchanges of energy under nonemergency conditions were a side benefit— though not usually the driver—of the process.

Because it is primarily a source of energy, not capacity, wind generation does not fit well into conventional resource adequacy-based transmission planning processes. In conventional planning, the focus will typically be concentrated on certain system conditions—peak or minimum load hours, or operation of the system with a major facility out of service. The status of conventional generating units during these periods is usually a given. With large amounts of wind generation, the disposition of other conventional generating units may not be so easily ascertained; in addition, high amounts of wind generation are likely in off-peak hours or seasons that might not be of special interest for reliability issues.

Wind generation is accounted for by assigning an estimated capacity value, which is the fractional amount of nameplate rating that can be considered firm capacity for planning purposes.

All of the overlays are structured to allow a general west-to-east energy transfer. There are several reasons for such a bias. First, in all the scenarios, the western part of the interconnection has large amounts of wind generation and minimal load. Second, issues with loop flows in portions of the existing transmission system in roughly the geographical center of the interconnection favor west-to-east lines over more north-south orientations of long-distance facilities.

Canada has significant wind energy potential in addition to hydroelectric resources, and its proximity to the northeastern U.S. load centers in particular offers the northeastern portion of the United States access to wind generation that is relatively local compared to wind generation in the Great Plains. The TRC recommended that such a scenario be considered in the future, if and when compatible wind data are available for those provinces.

Tables 4-3 through 4-5 summarize the EWITS transmission construction cost-per-mile assumptions by voltage level and region, the estimated total line miles by voltage level, and the estimated cost in millions of US$2024 for the four wind scenario conceptual overlays. In Table 4-5, the total AC line costs include a 25% adder to approximate the costs of substations and transformers; the total HVDC line costs include terminals, communications, and DC line costs. The costs associated with an offshore wind collector system or some subregional transmission upgrades that would be required, which could be substantial, are not included in the total estimated cost. With approximately 21,666 miles of new EHV transmission, the transmission overlay for Scenario 4 has the highest estimated total cost at $158 billion.

The renewable energy production tax credit (PTC) is the primary federal incentive to encourage wind power development.

To accommodate increasingly high wind penetration levels, regional transmission infrastructure is needed to deliver substantial amounts of high quality wind energy to remote load centers. Without new transmission corridors to access the wind resources, large amounts of wind curtailment would occur.

SECTION 5: POWER SYSTEM REGULATION AND BALANCING WITH SIGNIFICANT WIND GENERATION Matching the supply of electrical energy to the demand for electricity, over time frames ranging from seconds to decades, is a fundamental building block for maintaining resource adequacy in the bulk power system. Wind generation adds additional variability and uncertainty that make the general task more challenging.

operating reserve to be specifically evaluated are as follows: • Regulating reserve: Generation responsive to automatic generation control (AGC) that is adjusted to support the frequency of the interconnection and compensate for errors in short-term forecasts of balancing area demand. • Contingency reserve: The unloaded capacity carried to guard against major system disruptions such as the sudden loss of a large generating unit or major transmission facility. • Contingency reserve—spinning: That portion of the contingency reserves that is synchronized to the system and fully available to serve load within the time specified by the NERC Disturbance Control Standard (DCS). • Contingency reserve—supplemental: That portion of the contingency reserve consisting of generation that is either synchronized to the system or capable of being synchronized to the system within a specified window of time that is fully available to serve load within the time specified by the NERC DCS.

OPERATING RESERVE— SPINNING DEFINITION Those services necessary to support the transmission of capacity and energy from resources to loads while maintaining reliable operation of the transmission service provider’s transmission system in accordance with good utility practice. The provision of capacity deployed by the balancing authority to meet the DCS and other NERC and regional reliability organization contingency requirements. That capability above firm system demand required to provide for regulation, load forecasting error, forced and scheduled equipment outages, and local area protection. Consists of spinning and nonspinning reserve. The portion of operating reserve that consists of • Generation synchronized to the system and fully available to serve load within the disturbance recovery period that follows the contingency event • Load that can be fully removed from the system within the disturbance recovery period after the contingency event. OPERATING RESERVE— SUPPLEMENTAL The portion of operating reserve that consists of • Generation (synchronized or capable of being synchronized to the system) that is fully available to serve load within the disturbance recovery period that follows the contingency event • Load that can be fully removed from the system within the disturbance recovery period after the contingency event. REGULATING RESERVE SPINNING RESERVE An amount of reserve that is responsive to AGC, which is sufficient to provide normal regulating margin. Synchronized unloaded generation that is ready to serve additional demand. a Adapted from

MANAGING VARIABILITY Each BAA must assist the larger interconnection with maintaining frequency at the target level (usually 60 hertz [Hz]) and must maintain scheduled energy flows to the BAAs with which it is interconnected. Balancing real power supply with real power demand is the means by which frequency is maintained. Regulation and load following are mechanisms for achieving this control under normal operating conditions.

Variations in the aggregate electric demand are continuous, and can be roughly separated into two components: • Fast variations, nearly random in nature, that result from a great number (millions) of individual decisions or actions like flipping light switches • Slower trends that are relatively predictable, such as the rising load in the morning and the falling load through the evening into nighttime.

Generation units on regulation duty are adjusted to compensate for random or sudden changes in demand. These adjustments take place automatically through AGC and occur, depending on the characteristics of the balancing area, over tens of seconds to a minute. Regulation movements both up and down are required, and the amount of net energy over a period is small because the movements tend to cancel each other. To offer regulation, therefore, a generating unit must reserve capacity and operate below its maximum (to reserve room for upward movement) and above its minimum (for downward movement). In addition, only generating units that meet the balancing authority’s requirements for providing regulation and frequency service can participate in the regulation market.

Contingency reserve is the conventional name for the spare generating capacity that can be called on in system emergencies. The spinning portion of the contingency reserve is synchronized with the grid and ready to respond immediately; off-line capacity that can be called on, started, and synchronized within a defined period of time (10 minutes or 30 minutes) makes up the non-spinning or supplemental contingency reserve. Unlike reserves for regulation, which are for supporting normal system operations within applicable reliability criteria, contingency reserves that are spinning are not dispatched continuously by AGC in response to ACE and are held in reserves for system emergencies. They are also unidirectional, in that the ability to move upward—serve more load—is counted as contingency reserve. Currently, the basis for the required contingency reserves varies across the interconnection. The need is usually defined by the magnitude of the top one or two largest loss-of-source events, which could result from a single contingency. For example, in an operating region where the largest plant is a 900-MW nuclear unit, enough additional generation must be available to cover the sudden loss of this large unit, assuming it normally operates at its rated output. In many reliability regions, a substantial portion of this additional generation must be synchronized with the grid (i.e., spinning). The required fraction of contingency reserves that must be spinning is often about 50% of total contingency reserves. As soon as a large 900 MW nuclear generator is lost, system frequency would begin to decline because the amount of load now exceeds the available supply. As frequency declines governors on all generating units, whether they are regulating units, units participating in the energy market, or operating reserve units, would detect the abnormal low frequency. If the deviation is large enough or exceeds a defined deadband, the governors would increase the mechanical power inputs to the generators. The system operator would use the operating reserves to replace the loss of generation. The NERC DCS requires balancing authorities to rebalance their systems within 15 minutes of a major disturbance and to restore the deployed contingency reserves within 105 minutes.

EFFECTS OF WIND GENERATION ON POWER SYSTEM CONTROL Actions to support frequency and maintain scheduled interchanges in a BAA are driven by the variety of errors in the generation and load balance. As a result, the effects of wind generation’s variability and uncertainty on the net variability and uncertainty of the BAA’s aggregate demand defines how a given amount of wind generation affects power system control. Measurable impacts would be manifested in increased requirements for regulation capacity and load-following capability. Wind plants typically do not affect contingency reserve requirements because the individual generators are relatively small.

Changes in wind generation over other time frames must also be factored into operational practices. Large drops in wind energy production could be as large as the contingency for which operating reserves are carried, but there would be a significant difference in the event duration. The nuclear unit described earlier could be lost in an instant, producing 900 MW 1 minute and going off line the next. Large reductions in aggregate wind generation do not occur suddenly— instead they can evolve over several hours. This is caused by the many individual turbines, the large geographic area over which they are installed, and the time it takes for major meteorological phenomena such as fronts to propagate.

Smaller, but more frequent, changes in wind generation over 1 to 4 hours are also operationally important. On these time scales, uncertainty about how much wind generation will be available becomes more important than variability. Because of the short lead time, replacement capacity for forecast wind generation that does not materialize in this time frame must be found. This replacement capacity can come from units already committed, regulating reserves (until economic replacement energy can be committed), units with quick-start capability if insufficient regulating reserves are available, or a neighboring balancing authority.

it was necessary to define requirements for contingency reserves on another basis. Where no information was available from current practice, the total contingency reserve requirement was defined as 1.5 times the single largest hazard (SLH) in the operating area. At least half of this requirement was required to be spinning.

REGULATION AND LOAD FOLLOWING The approach for calculating the incremental regulation and load-following capacity required to maintain control performance in each study BAA was based on observations from current market operations and experience from previous studies. The minute-to-minute variability of wind generation, relative to that of the aggregate load, is very small. Because the National Renewable Energy Laboratory’s (NREL) mesoscale data only goes down to a 10-minute resolution, actual wind data collected by NREL (Wan 2004) and others was used for the analysis in the quicker time frames. Those measurement data show that the standard deviation of the minute-to-minute variability—faster than that which can be dealt with by the subhourly energy market or subhourly scheduling— is about 1 MW for a 100-MW wind plant, based on separating the fastest variations from longer term trends using a 20-minute rolling average window.

Very-short-term aggregate forecasts of large amounts of load can be quite accurate. For wind generation, the variations over these same time periods are less so. Errors in the short-term forecast of wind generation will therefore increase the requirement for regulation.

The persistence forecast for wind generation performs reasonably well, but the variations at 10-minute intervals for even this large amount of wind generation exhibit more volatility than is observed in the aggregate load. Consequently, the errors in wind generation forecasts dominate the net error, as Figure 5-8 shows.

In summary, for regulating reserves with no wind generation, the amount of regulation capacity carried is equal to 1% of the hourly load. The total spinning reserve carried forward to the production simulations is the regulation amount plus the spinning part of the contingency reserve defined earlier:

With wind generation, the regulation reserve is augmented to account for the short-term wind generation forecast errors

Reductions in next-hour wind generation output—which, given the persistence forecast assumption, is equivalent to the forecast being more than what actually is delivered—could possibly be covered by quick-start (non-spinning) generation. For EWITS, the study team assumed that some additional spinning reserve would be held to cover next-hour forecast errors, which are expected to be frequent (once or more per day). The amount of additional spinning reserve was set at one standard deviation of the expected error. Additional supplemental or non-spinning reserve was also allocated to cover the larger but less frequent forecast errors. An amount equivalent to twice the standard deviation of the expected next-hour wind generation forecast error was used here.

The penetrations of wind generation considered in EWITS are well beyond what experience can speak to definitively; further analysis is certainly warranted.

SCENARIO CHARACTERISTICS After considering various locations of wind resources and different wind penetration levels, four wind scenarios were developed: three 20% wind energy scenarios and one 30% wind energy scenario. Figure 6-1 summarizes the wind penetration levels by region and scenario. Among the three 20% wind scenarios, Scenario 1 has the highest penetration levels in the western regions because it uses the most high-quality wind resources in the Great Plains. Because wind is moved eastward and more offshore wind is used in Scenarios 2 and 3, the penetration levels increase in the PJM Interconnection, the New York ISO (NYISO), and the New England ISO (ISO-NE) as the levels drop in the western regions. To meet the 30% wind mandate, Scenario 4 uses a significant amount of good-quality wind across the footprint and offshore wind along the East Coast with the highest wind penetration levels in almost all the regions. Based on wind quality and availability, the Tennessee Valley Authority (TVA) and Southeastern Electric Reliability Council (SERC) have very little installed wind capacity and are the primary wind import regions. Conversely, the Southwest Power Pool (SPP) has very high wind penetration levels for all four scenarios. Because of the unique characteristics of the wind resource, additional reserve requirements are required to regulate the wind and maintain system reliability. The incremental reserve for each region is an hourly profile and varies hourly with the amount of wind generation at that particular hour. Figure 6-2 shows the annual, average, variable spinning reserves by region and scenario. As the figure shows, the level of required operating reserves increases with wind penetration levels, as expected. Figure 6-1.

Wind energy penetration levels by region using 2004 hourly profiles

Figure 6-2. Annual average variable spinning reserve using

SPP, MISO, and MAPP are the primary export regions and SERC is the predominant import region because of low wind availability in all the scenarios. | Added on Tuesday, February 10, 2015 7:46:18 AM

TOTAL COSTS Each EWITS scenario created for 2024 results in a picture of the Eastern Interconnection that is substantially different from what is in place today. The changes made include adding very large amounts of wind, regional and overlay transmission, and conventional generation. As described earlier, the top-down method leads to a snapshot of 2024; it does not consider the evolution of today’s power system through time to get to 2024. After refining each scenario through additional iterations of the study process, more conventional planning methods would be employed to fill in the details of the evolution over time, along with even further refinement.

Currently, wind generation in the Midwest ISO area is concentrated in a small geographic area in southwestern Minnesota and northern Iowa. Wind generation potential exists in much of the Midwest