Smart grid
Summary:
On the customer side of the electric meter, in the homes and businesses of utility customers, lie countless opportunities to reduce and improve energy use through higher efficiency and the installation of onsite generating systems. California is a breeding ground of energy technology innovation that someday will turn old-school electricity distribution networks into smarter and stronger interactive grids that will propel the new energy economy of the future. Fuel cells, solar photovoltaics (pv), advanced solar thermal and solar hot water, net metering, time of use meters, and more effective conservation are some of the innovations on the demand side of the energy equation that we call "Greening the Grid."
Recent Developments:
CEERT is pursuing multiple ways to develop a low-carbon transmission and distribution grid. "Greening the grid" encompasses energy efficiency, distributed generation, demand management, and combined heat and power (also known as cogeneration). We are working to identify the technical uncertainties and market barriers that currently accompany each of these technologies.
Low-Carbon Grid Advocacy
CAISO and ARRA Projects
Nearly 17,000 MW of proposed renewable generation projects are currently either in the existing serial group or in the transition cluster—enough to get the CAISO to 33% renewables integration.
Despite their preference for performing a comprehensive, integrated analysis of all proposed transmission projects before approving any new transmission, the CAISO is expediting the interconnection study process this year to accommodate the deadlines facing generation projects that seek ARRA funding. Specifically, the CAISO and participating transmission owners are planning to complete the interconnection studies for ARRA projects and all other generation projects in the CAISO's current study queue by early July to allow sufficient lead time for the interconnection agreements to be completed by the end of September. This is a good indicator of CAISO staff’s willingness to work creatively with renewable projects.
Interconnection Standards
CAISO staff recently released their interconnection standards straw proposal. Recognizing the need for proactively managing their growing portfolio of intermittent assets, they have taken an aggressive ap¬proach to defining interconnection standards ahead of the upcoming NERC and FERC standards. Several of their initiatives pose large challenges to the renewable community. Some of the issues are:
Discriminatory Practices: Is it fair to ask renewable generators to adhere to a different set of standards than conventional generators? The real issue may be reframed as the difference between synchronous versus asynchronous generation. Synchronous generation has attributes that support stable grid operation, while asynchronous generation, or generation delivered through an electronic inverter, does not naturally possess such characteristics. Renewables can be synchronous (e.g., solar thermal) or asynchronous (e.g., wind, solar PV). Because of their inherent stability, synchronous generators have to this point not re¬quired strict regulation guidelines. With the introduction of renewables on the grid, the CAISO is now requesting new guidelines. Should those guidelines be allowed to discriminate against renewables, or should separate rules be developed for synchronous and asynchronous generation?
Equipment Standards: Current equipment standards differ for various types of generation, and in some cases manufacturing standards are not consistent with those the CAISO is seeking. CAISO staff has indicated they are willing to work with manufacturers to develop standards, and in the meantime they will not penalize renewable generators who rely on equipment that is not consistent with CAISO standards.
Curtailment: The CAISO is requesting that all renewable generation facilities have the ability to limit ramp rates, and provide a mechanism that would allow the CAISO to automatically curtail production when there is excess generation on the grid. Involuntary curtailment presents a particular challenge to renewable generators as it introduces an additional element of financial risk. The CAISO is currently only requesting that the functionality be present to limit ramp rates and curtail production, without defining rules for when these mechanisms would be implemented. The CAISO is aware of the increased financial risk and is deferring discussion of that until a later date.
Dynamic Scheduling
Dynamic Scheduling, or intra-hour scheduling, enables the CAISO to source or sink power flow across interties to or from the CAISO in sub-hourly intervals. Pseudo ties, which the CAISO is currently studying through pilot projects, is a type of dynamic scheduling whereby the CAISO also maintains complete control and balancing responsibility for the generation facility, regardless of where it is located.
Dynamic scheduling is extremely beneficial to renewable energy integration. Under the hourly scheduling procedures many systems now use, grid operators rely on expensive reserves to accommodate the intra-hour variability of load, variable energy resources (VERs) and other resources, when shorter scheduling intervals would allow existing generators to provide much of the needed flexibility less expensively.
Because of the variable nature of intermittent generation, it is usually much more difficult to forecast avail¬able energy for an hour interval than for, say, a five-minute interval. So for markets that do not provide sub-hourly trading, firming and shaping services are usually required to supplement the delivered renewable energy into a block of energy that can be bid in the financial markets. With dynamic scheduling, the interval is shorter and the actual amount of delivered energy is easier to forecast, so the firming and shaping required to create a tradable block of energy is significantly reduced.
While the current CAISO tariff for dynamic scheduling functions well for conventional resources, it discriminates against intermittent resources. Intermittent generators ideally want to bid in the day-ahead or hour-ahead markets, since prices are usually higher than in the spot market. However, if they do so, and don’t have the ability to adjust schedules closer to real-time (when, for example, weather forecasts are more accurate), uninstructed-deviation penalties will be assessed against them if they don’t fully deliver the contracted energy. Firming and shaping services can be used, but such expensive resources are not only inefficient, but also reduce the ROI of VER projects and hence limit their access to capital markets.
So a big question is: How can VERs be allowed to bid in the day-ahead and hour-ahead markets without being unduly penalized? And how can a tariff be created that works for all generators (VERs and conventional) in a nondiscriminatory way? The answer may ultimately rely on allowing VERs to adjust their contracts closer to real time.
Another significant issue is that dynamic scheduling and pseudo ties both currently require firm transmission reservations for the project’s entire capacity, even though its capacity factor may be significantly less than 100%—with the result that much of the available transmission capacity is unused. The current dynamic scheduling tariff is therefore extremely inefficient in its use of available transmission capacity.
FERC VER NOI
FERC recently released a Notice of Inquiry on integration of VERs on the grid. CEERT has joined comments with the Project for Sustainable FERC Energy Policy that advocate for reforms to enhance the flexibility and efficiency of the grid and make it easier to accommodate all sources of variability.
CEERT urged FERC to encourage sub-hourly scheduling both to reduce VER integration costs and to address intra-hour load variability on sys¬tems without VERs. Studies suggest that intra-hour scheduling and dis¬patch can dramatically reduce the costs of integrating VERs. We also urged FERC to review current market rules under which VERs face significant risks in day-ahead or hour-ahead markets because such schedules are financially binding.
If VERs could adjust their schedules closer to real-time, their participation in the day-ahead and hour-ahead markets would likely increase, which could make balancing loads and resources more efficient. But if regulatory policies make integrating variable resources unduly costly, or if VERs are subjected to inappropriate penalties and integration charges, the growth of renewable resources will be inhibited. Most important among the changes needed are greater reliance on centralized forecasting and better use of the forecast information by system operators to balance the variability of load and system resources.
Storage
Storage is an extremely useful technology for providing additional grid regulation. However, arguing that storage is needed solely for integration of intermittent resources discriminates against renewables: existing grid operational flexibility can more than adequately handle added variability from VERs at penetrations of up to 35% renewables, as shown by the NREL Western Wind and Solar Integration Study (wind.nrel.gov/public/WWIS/). And while storage is certainly a desirable resource, its cost far exceeds other comparably reliable sources of operational flexi¬bility, such as demand response / load shifting; balancing area consolidation; and sub-hourly scheduling.
TRECs
Tradable renewable energy credits (TRECs) have become quite a complex and convoluted affair, as reflected by the recently released third CPUC decision calling for a hearing in part to establish whether firm transmission paths represent bundled transactions. This is somewhat surprising, as a workable definition of bundled transactions relies precisely on the presence of firm transmission.
Bundled transactions can be defined as follows: If there is a firm transmission path (defined by NERC eTags) from the renewable generator to the load (in real time) or from close proximity of the renewable generation to the load (not in real time), then the entity paying for the energy plus REC is paying for and receiving full benefit of the renewable energy. As long as there is an appropriate NERC eTag, then this qualifies as a bundled transaction, regardless of whether the mechanism for scheduling the transaction is day-ahead, hour-ahead or dynamic scheduling. The key to defining whether or not a transaction is bundled is the existence of the NERC eTag. For renewable generation both located and delivered in CA, it may be assumed that a firm transmission path exists, and so it may not be necessary to explicitly rely on the NERC eTag to demonstrate that the transaction is bundled.
The excessive confusion and uncertainty about delivery issues is having a chilling effect on development projects in and around California. Without clear, consistent signals on how RECs will be accepted for RPS compliance, uncertainty in future earnings will erode developer access to financial markets.
Defining bundled transactions may not be nearly as complex as the current CPUC decision indicates. Some of the confusion may be due to linking bundled transactions to whether a project is in-state or out-of-state. There is no link between whether a transaction is bundled and where the project is physically located, other than the existence of a firm transmission path. Attempting to manipulate the definition of a bundled transaction in order to incentivize where generation is built is misinformed and confusing for developers and financial markets.
A confounding TRECs issue is the now infamous example 3 of footnote 2 from the Delivery Requirements section of the CEC's RPS Eligibility Handbook Third Edition (p. 24, Jan. 2008) suggesting ‘matching’ as an acceptable form of delivery, or bundling. This example should be expunged from the record as it does not represent true bundling and causes unnecessary confusion and uncertainty in the markets.
CPUC Smart Grid Rulemaking
On February 8, the CPUC issued an Amended Scoping Memo (ASM) on smart-grid issues, announcing it was revising its May 2009 scoping memo in response to SB 17 requirements, and as a follow-up to its December decision (D.09-12-046) to consider rules for providing customers and third parties with access to usage and price data. The ASM also scheduled workshops on a framework for utility smart-grid deployment plans consistent with SB 17 (March 17 and 18), and customer access to data (March 19). CEERT submitted opening and reply comments on March 9 and April 7 respectively.
SB 17 requires that the CPUC establish by July 1 a framework for the design of utility smart-grid deployment plans, while the utilities have until July 1, 2011 to deliver their individual deployment plans for the Commission’s consideration. Utilities need to demonstrate how their deployment plans would improve overall grid efficiency, reliability, and cost-effectiveness; contribute to achieving the state’s energy efficiency, RPS, and AB32 goals; and improve worker safety.
CPUC staff included a fairly comprehensive set of draft metrics in its ASM, largely focused on how the utilities’ efforts would improve the grid’s operational performance. In their opening comments the IOUs countered by offering a short, simplistic list of metrics that would have been appropriate for the grid of the 20th century. CEERT noted that the IOUs’ proposed metrics were inadequate, that the PUC staff’s metrics were a good start, and that additional metrics more explicitly tied to the Energy Action Plan were necessary. CEERT further recommended that for maximum transparency, utility initial deployment plans, annual progress reports, and updates should be reviewed together as part of a single proceeding, and that the Commission should undertake programmatic reviews at appropriate intervals. (Specific smart-grid investments will likely be reviewed as part of either a GRC or special application.)
In our opening and reply comments, CEERT maintained our long-standing position in this proceeding on customer access and use of data: customers, and authorized agents, should be able to access real-time recorded information at the meter; a customer should expressly grant third-party access through an electronic signature if information is provided from the utility; and grid operation, privacy, and security should follow forthcoming NIST standards, including Fair Information Principles and NIST cyber-security standards. In cases where a NIST standard has not been issued, CEERT recommended that the CPUC adopt an interim standard developed in consultation with NIST.
The Commission has indicated that it will focus its next decision on establishing the framework for deployment plans, and will continue to explore customer and third-party data access and usage after it releases that decision.
Energy Efficiency
CEERT has continued to work on integrating energy efficiency into the major utilities’ long-term procurement planning, and on expanding efforts to link the efficiency targets in CARB’s AB 32 Scoping Plan with the plans and actions of the CPUC, CEC, and municipal utilities.
To push beyond traditional utility efficiency programs, we have convened meetings and discussions with a variety of stakeholders and expert analysts on integrating energy efficiency with smart grid, distributed generation, and large-scale renewables investment. We have also worked with the California State Treasurer’s office to develop low-interest financing mechanisms, such as private activity bonds, to accelerate efficiency investments in state government buildings.
