Integrating Wind Resources Into the Transmission Grid

Transcription

1 Integrating Wind Resources Into the Transmission Grid Gary D. Bachman Wisconsin Public Utility Institute May 26, 2010

2 Introduction Statement of FERC Chairman Jon Wellinghoff on Efficient Integration of Renewables into the Grid, January 21, 2010: Approximately 9,000 MW of variable energy resources went into commercial operation in the U.S. during 2009 and a similar number in Currently, there are thousands of MW of VERs, particularly wind, in the process of interconnection to the electric grid. These new resources offer low operating costs and low greenhouse gas emissions, which can benefit consumers VERs also have some operational characteristics which present challenges to system operators. Therefore, it is important that the Commission examine the most efficient ways to effectively integrate these resources into the electric grid, while maintaining reliability and operational stability. 2

3 Introduction Wind and Natural Gas are the leading sources of new generation capacity in the United States, collectively totaling roughly 80% of new installed capacity in New growth driven in large part by state renewable portfolio standards, production tax credits, and in some cases, favorable economics. Here in the Midwest, the Midwest Governors Association has established a goal of 30 percent renewable energy consumption by

4 Introduction The rapid development of wind generation presents challenges for transmission system operators 4

5 What s the Problem? Balancing Area operators ( BAs ) are responsible for continuously balancing generating resources with load and must maintain adequate generating reserves that are quickly available to accomplish this task. NERC measures a BA s compliance with this requirement through its Control Performance Standard 2 ( CPS-2 ), which measures the balance over 10-minute periods of each month. 5

6 What s the Problem? CPS-2 sets a limit on the maximum permitted Area Control Error ( ACE ). ACE is the instantaneous difference between actual and scheduled flow on tie lines between a balancing area and surrounding balancing areas. In order to be in compliance with CPS-2, a BA must pass this measurement in at least 90 percent of the 10-minute periods in each one month period. 6

7 What s the Problem? The output from dispatchable (fossil-based, nuclear, hydro) generation is typically set at a certain level, and can be maintained so long as the unit is performing properly. Dispatchable generation typically does not vary much from its scheduled output, barring an unforeseen outage. A BA s intrahour role has therefore traditionally focused on managing the moment-to-moment deviations in loads using online generating capacity that can respond instantaneously in a process known as regulation. 7

8 What s the Problem? Wind generation introduces a new source of variability that the BA must manage to meet its CPS-2 requirements. The output from a wind generator can increase or decrease in response to changes in wind speed and direction, and is also susceptible to a phenomenon known as high speed cutout which can occur during high wind conditions when governors on the generators shut them down as a protective mechanism. 8

9 What s the Problem? Insert Hopkins Telemetry Ridge: 0 MW Example to 134 MW from in 7 minutes PSE Wind Generation (MW) Wild Horse: 0 MW to 129 MW in 11 minutes 0 20:00 20:30 21:00 21:30 22:00 22:30 23:00 23:30 0:00 0:30 1:00 1:30 2:00 2:30 3:00 June 4-5, 2009 Wild Horse Hopkins Ridge HR Schedule: HE 2100 = 15, HE 2200 = 130, HE 2300 = 140, HE 2400 = 100, HE 01 = 5 9

10 What s the Problem? Wind generators underperform relative to their schedules when the wind blows less than expected. During times of low load levels, wind projects may produce energy that is not needed, which requires other generation to back down to preserve balance on the system. Example of Extreme Wind Variability: On November 27, 2009, one wind facility in the Pacific Northwest recorded an output of 0 MW halfway through the 0:300 scheduling hour, 175 MW halfway through the 0:400 hour, and 26 MW halfway through the 0:500 hour. A 175 positive ramping event, followed by a 149 MW negative ramping event, in two hours. 10

11 What s the Problem? Offsetting Load Variability? When wind generators in a balancing area experience a ramping event in the same direction of load movement, the variability of wind and load offset to reduce the BA s within hour fluctuations. Of course, when wind and load vary in the opposite direction, there is an additive effect on net variability. Analysis of some western systems has shown that the beneficial effects of offsetting load variability dissipate as more wind is added because the first few large wind projects absorb the available offsetting load variability. 11

12 What s the Problem? Wind Diversity? Different wind sheds may experience ramping events at different times, such that a wind resource in one geographical corner of a balancing area may ramp up while another resource ramps downward. This offsetting wind variability reduces the within-hour burden on the BA. However, a concentration of wind farms around a single geographic resource (i.e., single windshed) can have an additive effect and increase the burden on the BA. 12

13 What s the Problem? BAs must have sufficient flexible capacity available that can be ramped up or down to balance wind ramping events in order to meet CPS-2 standard and keep the system balanced. Current tariff provisions and market protocols were largely developed prior to the recent increase in wind development and were designed with dispatchable not variable generation in mind. 13

14 What s the Problem? For example, it is generally not efficient or appropriate to balance wind generation using the same regulation products used to balance load variation because of the magnitude and duration of wind ramping events. The most appropriate products are similar to the Spinning Reserve Service and Supplemental Reserve Service, which reserve products are defined as ancillary services under the pro forma OATT. However, they are only available during contingencies. Most wind ramping events do not qualify as contingencies as defined in the pro forma OATT and thus the ancillary service products are not available for use by BAs for that purpose. 14

15 What s the Problem? Moreover, FERC s restrictions on the sale of ancillary services at market-based rates have limited the development of a market for products that are like spinning and supplemental reserves but are not contingency products. Absent a market for reserve products, BAs are often forced to balance wind resources using facilities or resources on their system that are not well suited to the task and/or would otherwise be dedicated to optimizing cost of service to native load. The pro forma OATT does not recover the costs of providing the integration service or such resources. 15

16 What s the Problem? Wind developers are concerned that BAs may try to shift the costs of wind integration to wind developers in a way that is inconsistent among BAs, unduly discriminatory, or punitive. Wind developers fear that if the cost of integrating wind generation becomes unduly high, the growth of the industry will be stunted. Wind developers also fear discriminatory curtailment practices by BAs that could limit the amount of wind energy that reaches the market and limit RECs. 16

17 What s the solution? FERC-approved tariff amendments allow BAs to recover costs of following wind generation: Entergy Services, Inc., 120 FERC 61,042 (2007): Commission approved amendment to Entergy OATT that allowed for separate recovery of the costs of holding additional reserves for meeting generation imbalances. 17

18 What s the solution? FERC-approved tariff amendments allow BAs to recover costs of following wind generation: Westar Energy, Inc., 130 FERC 61,215 (2010) Westar sought and obtained FERC approval to implement new OATT Schedule 3A, Generator Regulation and Frequency Response Service Westar observed wind generators in Kansas from Dec to Nov to determine the deviation from schedule over 10-minute intervals. Westar allowed load variations and other wind variations in the BA to offset a generator s deviations where applicable the portfolio-wide approach to measuring wind variability. The data collected demonstrated that wind generators deviations from deployment signal are more than three times greater than those of dispatchable generators. Westar claimed that as a result, wind generators placed a heavier burden on its system than dispatchable generation. 18

19 What s the solution? FERC-approved tariff amendments allow BAs to recover costs of following wind generation: Westar Energy, Inc., 130 FERC 61,215 (2010) (cont d) Westar therefore proposed to charge under Schedule 3A intermittent generators a higher generator regulation charge than dispatchable units a regulation requirement of 7.8 percent of nameplate capacity (Westar s Schedule 3 charges dispatchable units a regulation requirement of 1.35 percent of nameplate capacity). The Commission s approved Westar s proposal, finding that it reasonably assesses intermittent generation a higher regulation requirement consistent with cost causation principles. Id. at P

20 What s the solution? FERC Rejects Tariff Amendments That Shift Burden of Providing Following Services to Generators: NorthWestern Corporation, 129 FERC 61,116 (2009) Northwestern proposed an amendment that would have required intermittent renewable generators to supply or otherwise provider their own generation following capability for both capacity and energy. The Commission held that Northwestern could not shift its responsibility to provide generator imbalance service under Schedule 9 of the pro forma OATT to intermittent generators. Opinion advised Northwestern to file tariff revisions that would allow it to recover costs of providing regulation services to intermittent generators if those costs were not already being recovered under the utility s OATT. 20

21 What s the solution? Curtailment? Generally, transmission providers are allowed to curtail generation on a pro rate basis to reduce transmission congestion. But: some wind generation cannot reduce output without shutting down completely, presenting an all or nothing decision for BAs. Some transmission providers have developed different curtailment practices for wind generation to accommodate ramping events: BPA agreed in a settlement with its customers to sell flexible capacity to wind generators under its OATT at a discounted rate of $1.29 to $1.58 per kw-month. In exchange, BPA obtained the right to curtail wind generators when 90% of its balancing reserves are deployed. 21

22 What s the solution? Voluntary Regional Efforts: Various regions have formed working groups to develop solutions to wind integration. Example: Northwest Wind Integration Action Plan ( NWIAP ). Identifies 16 action plan items that would help facilitate the reliable and efficient interconnection of large amounts of wind in the region. Example: Joint Initiative Voluntary effort by ColumbiaGrid, Northern Tier Transmission group, and WestConnect to develop products and services to aid wind integration. Have developed a standard intrahour scheduling product and business practice. 22

23 What s the solution? Different regions have taken different approaches depending on the quantity and characteristics of wind resources interconnected to the grid in those regions. Wind generators are concerned that this ad hoc approach may lead to a lack of consistency across regions, a lack of transparency, and potentially discriminatory treatment of wind resources. 23

24 FERC s Notice of Inquiry On January 21, 2010, FERC issued a Notice of Inquiry ( NOI ) seeking comments on whether reforms of existing policies are needed to better integrate wind generation into the transmission grid. The NOI welcomed general comments, and also sought comments on seven particular subject areas. 24

25 FERC s Notice of Inquiry 1. Data and Reporting Requirements: Development of state-of-the art forecasting techniques could take some of the uncertainty out of a BA s job when it comes to integrating wind resources. BAs will have a better idea of the quantity of reserves they need to have available if they can better predict large scale ramping events. Wind generators will be able to schedule more accurately and hence avoid scheduling penalties for over/under generation if they can better predict output. 25

26 FERC s Notice of Inquiry 1. Data and Reporting Requirements: Questions Raised: Sharing of data collected by a generator at the site of wind turbines with BAs Centralized forecasting by BA? Cost recovery? Even with a perfect forecast the variability must still be smoothed. 26

27 FERC s Notice of Inquiry 2. Scheduling Practices and Incentives/Penalties: FERC primarily sought comments on two areas of inquiry: Whether there should be a move to intrahour scheduling Whether the current exemption from third tier scheduling penalties for wind generation should be continued and/or creating proper incentives to schedule accurately. Intrahour Scheduling: A move to intrahour scheduling would wind generators to schedule more accurately in response to changing weather conditions, and allow BAs to more frequently and efficiently adjust the amount of reserves they need to have available to balance wind. Tariff provisions and operational protocols would need to be revised to accommodate intrahour scheduling. 27

28 FERC s Notice of Inquiry 2. Scheduling Practices and Incentives/Penalties: Scheduling Penalties: Currently, intermittent generators are exempt from 25% scheduling penalty for third tier scheduling errors (>7.5%), which requires wind generators to purchase imbalance energy at 125% of the energy s incremental cost. Instead, wind generators must only pay 110% of the incremental cost of replacement energy for even the largest of generation imbalances. FERC solicited comments on whether this 10% penalty is an adequate incentive for wind generators to schedule accurately, or whether it is not harsh enough (or too harsh). 28

29 FERC s Notice of Inquiry 3. Day-Ahead Market Participation Currently, participating in day-ahead markets (in regions where they are available) is generally considered too risky for wind generation because of the uncertain output and risk of underperformance. Wind generators without a full contract offtaker generally participate only in the real time energy market. The Commission is considering ways of encouraging participation by wind resources in day-ahead markets. 29

30 FERC s Notice of Inquiry 4. Balancing Area coordination and/or consolidation: In some cases, wind integration costs can be reduced by increasing the size of a balancing area to encompass more (hopefully) offsetting load and wind variations. If there is little wind or load diversity in the region, consolidating balancing areas may not have significant benefits. Some western utilities have discussed the formation of a wind only balancing area across the interconnection, though significant transmission issues would need to be resolved. 30

31 FERC s Notice of Inquiry 4. Balancing Area coordination and/or consolidation: BA coordination activities that can facilitate integration by shifting BA responsibilities and burdens: Dynamic transfers Dynamic schedules Pseudo-ties ACE Diversity Interchange ( ADI ) developed in Pacific Northwest; voluntary frequency sharing program that has allowed some BAs to better meet their CPS-2 requirements. 31

32 FERC s Notice of Inquiry 5. Reserve Products and Ancillary Services: As discussed previously, spinning reserves and supplemental reserves contingency products that could otherwise be used to balance wind ramping events. The lack of a market for suitable wind following reserve products means that transmission providers often rely on more expensive regulation reserves or, outside of RTO/ISO areas, are required to balance wind ramping events using resources that were acquired to serve to native load. The Commission thus sought comments on whether the definitions of these ancillary services should be revised to make them applicable to wind ramping events; and otherwise how a market for such products and services should be fostered. 32

33 FERC s Notice of Inquiry 5. Reserve Products and Ancillary Services: Key Questions: Type of product flexible, can be ramped up or down (spinning?) on short notice Technology Natural gas, peaking unit? Who should be responsible under the tariff for providing wind following service? BA? Wind generator? Cost allocation if BA provides service Based on historical scheduling imbalances of wind generators? Portfolio-wide approach, taking into account offsetting load and wind variations 33

34 FERC s Notice of Inquiry 6. Wind participation in capacity markets In areas with organized capacity markets, Commission has inquired, among other topics, whether: Uniform capacity rating for wind resources should be developed Wind resources are prohibited from participating in forward capacity markets 34

35 FERC s Notice of Inquiry 7. Real-time Adjustments Redispatch there is some uncertainty concerning redispatch practices when a wind ramping event results in a reserve shortage, and who is to bear the costs associated with the event. Inability of to reduce output when a wind generator cannot reduce output through blade feathering or a governor in response to BA dispatch instructions, should they be ordered to shut down completely? 35

36 FERC s Notice of Inquiry The Commission received over 100 sets of comments on these topics. Trends: BAs and transmission providers generally favor: Flexibility to develop regional/ba-specific solutions. Shifting of responsibility to balance wind generation to wind generators curtailment in extreme ramping events. Full cost recovery Wind developers generally favor: Consistent application of policies through a FERC rulemaking. BAs retain responsibility for balancing system with reserves, even during ramping events. Policies which place wind generators on equal footing with dispatchable generation. 36

37 QUESTIONS? 37

38 For more information Gary D. Bachman Wisconsin Public Utility Institute May 26, 2010