Smart grid

Not every answer to our future energy supply solution can come from the grid to the customer. On the other side of the electric meter, in the homes and businesses of utility customers, lie countless opportunities for us to reduce and improve energy consumption through smarter usage, as well as tap power to meet some or all of our own needs with distributed generation sources. California is a breeding ground of technological innovation aimed at turning traditional one-way electricity distribution networks into smarter interactive grids of the future. Fuel cells, residential and commercial solar photovoltaic systems, advanced solar heating and hot water, net metering, time-of-use meters, and more effective passive and active "green building" design and investments are some of the innovations on the demand side of the energy equation that we promote in our "Greening the Grid" project.

Low-Carbon Grid and Renewables Integration

Summary:

The CAISO board approved its 2010 – 2011 transmission plan and a new Dynamic Scheduling tariff.

The CAISO’s PIRP provisions and monthly netting of deviations for most wind and solar resources will end in 2015, and these resources will then have the flexibility to bid into CAISO markets.

CEERT filed comments on the CAISO’s Renewable Integration Market & Product Review 2 proposals.

A CAISO model used four CPUC scenarios that all showed there is no need for additional resources to manage 33% renewables by 2020.

A recent CEC workshop addressed distribution infrastructure challenges and Smart Grid solutions to advance 12,000 MW of distributed generation.

Recent Developments:

CEERT continues to participate actively in a number of key renewables-integration proceedings at the CAISO, CPUC, CEC, and FERC.

CAISO May 2011 Board Meeting

The CAISO board approved its 2010-2011 transmission plan and the new Dynamic Scheduling tariff. A number of stakeholder groups opposed the 2010-2011 transmission plan on the grounds that the CAISO did not fully use the new Revised Transmission Planning Process (RTPP) tariff, which FERC recently approved.  Under the new RTPP, the CAISO should have opened up policy on economically driven transmission lines to merchant developers.  However, the plan the board approved was based on Large Generator Interconnection Agreements previously created between the CAISO and incumbent IOUs, with no participation whatsoever by merchant developers.  A strong argument for adoption was that any delays would put ARRA money at risk, so it was generally agreed not to let the perfect be the enemy of good enough, and to improve upon the process in future planning cycles.

The Dynamic Scheduling tariff has been years in the making, and provides a mechanism for dynamically importing or exporting energy and ancillary services to the CAISO balancing authority area (BAA).  One significant remaining concern is that under the terms of the tariff, firm transmission must exist for dynamic scheduling to occur.  Given the lack of a spot market for transmission outside of the CAISO BAA, it is unclear how effective the introduction of the dynamic scheduling tariff will actually be.

CAISO Renewable Integration Market and Product Review, Phase 1 (RIMPR1)

The CAISO has now reversed course again on its proposal to update the Participating Intermittent Renew­able Program (PIRP), which was originally developed to provide a level of financial protection to variable energy resources (VERs).  

Under the new proposal, PIRP provisions and the monthly netting of deviations for most wind and solar resources will end in 2015, and these VERs will then have the flexibility to bid into CAISO markets like other resources.  Limited grandfathering will be available for older resources that are not able to reduce output in response to dispatch instructions.  RIMPR Phase 2 (see below) might provide additional mechanisms that will enable VERs to have just and reasonable market participation.  

Convergence bidding is a financial mechanism that can be used to hedge a physical market position, and may provide an alternative to PIRP.  However, the CAISO is currently having significant issues with con­vergence bidding at the interties, since an arbitrage opportunity exists there due to lack of convergence of real-time and forward markets, and market players are exploiting this opportunity, with load paying the cost.  The CAISO is considering eliminating convergence bidding at the interties, but this would not affect convergence bidding within the CAISO BAA.

CAISO Renewable Integration Market and Product Review, Phase 2 (RIMPR2)

The CAISO just launched a massive new initiative to potentially redesign their entire market structure, including the potential introduction of renewable integration charges.  Options being considered include: Hourly Contingency-Only Election for Operating Reserves, Enhancements to Residual Unit Commitment, Pay for Performance Regulation, Load Following Reserve, Flexible Ramping Constraint, Allocation of Integration Costs, 15-minute Real-Time Market, Capacity Markets, and Forward Reserve Markets.  A detailed summary of all RIMPR2 proposals and CEERT’s reply comments is available upon request.

CAISO Generation Interconnection Process (GIP), Phase 2

The CAISO continues its overhaul of the GIP.  Based on stakeholder input from the GIP2 work group 1, “Cost Assessment Provisions” has been taken out of the GIP2 scope and is now being managed as its own high-priority initiative: “Integration of GIP and Transmission Planning Process.”  This move might allow the CAISO to take a more holistic view of interconnection and transmission planning.  

Other issues being examined are: (a) how generators interconnect to non-PTO (participating transmission owner) facilities in the CAISO BAA, (b) how projects are studied for full deliverability status, (c) Triggers for Financial Security Posting Deadlines, (d) PTO per-unit cost information and methodology for es­ti­mating costs, (e) how financing of generator projects proceed when COD is significantly out of alignment with required trans­mission up­grades, and (f) handling of interconnection deposit refunds.  

Per this last item:  if a project in the queue complies with the RPS, then its security deposit will be re­funded once the unit is operational.  But if the project provides renewable generation in excess of RPS compliance, then security deposits may go toward network upgrades.  This may create a significant barrier to financing renewable projects that arbitrarily do not get counted toward the current 33% RPS.

CAISO Regulation Energy Management

Regulation Energy Management is a market feature for resources within the CAISO BAA that are able to operate as generation or load but have a MWh limit to generate, curtail, or consume energy.  Re­sources using Regulation Energy Management must be dispatchable on a continuous MW basis for at least 15 minutes after issuance of the dispatch instruction.  Resources using Regulation Energy Management may only provide regulation in the CAISO Market.  A resource using Regulation Energy Management may not provide any additional energy products or ancillary services other than regulation.

CEC /CPUC System Planning

The CEC held a meeting, featuring CAISO and E3 presentations, to examine system modeling efforts being used to inform the CPUC Long Term Procurement Planning process.  The CAISO model used four CPUC scenarios: trajectory, environmental, cost, and time-constrained.  E3 essentially duplicated the CAISO effort, with some additional backend analysis.  Methodology was the same as prior analyses, with minor adjustments for handling solar and wind variability issues.  (E.g., large solar farms were no longer represented as point sources, but actually reflected spatial extent and some level of insolation averaging.)  

In David Miller’s opinion, the results from all four models were nearly identical.  All show there is no need for additional resources to manage 33% VER penetration by 2020, and there is almost no difference between the various trajectories, which means there are no technology preferences.  

CEC Workshop on Estimating Costs of California Generation Resources

This workshop examined current best practices and lessons from other models for a comprehensive re­view of how the CEC estimates current and future generation costs.  The CEC's IEPR Committee is over­seeing this work.  

The Southern California Edison presentation attempted to include integration costs, sparking a vigorous debate in which most parties seemed to recognize that conflating integration and generation costs was not appropriate at this level of modeling.  If VERs integration costs are included, then the model should also include integration costs of thermal and nuclear resources, e.g., the cost of providing ancillary services such as contingency reserves.

CEC Integrated Energy Policy Report (IEPR) Committee Workshop on Distribution Infrastructure Challenges and Smart Grid Solutions to Advance 12,000 MW of Distributed Generation (DG)

Attendees included representatives from all the IOUs, the CAISO, several munis, EPRI, NREL, EDF, and Nevada Energy.  CEC Commissioners Robert Weisenmiller and Carla Peterman presided.  

The maximum amount of DG that can be reliably integrated onto a distribution system depends on the visibility of these resources to the system operator, as well as the ability of the operator to manage re­sources.  Several major issues were identified as requirements for increased DG penetration, including interconnection reform, transparency of the interconnection process, access to system data to enable innovation by third-party developers, dynamic pricing (which is a fundamental prerequisite of the smart grid), and safe and reliable two-way communication protocols between the DG and grid operators.  

Key considerations in planning for increased DG penetration include voltage regulation issues, bidirectional power flow, and safety issues that could result from islanding.  Islanding occurs when DG re­sources are generating power within an isolated distribution network that is disconnected from the greater distribution grid.  Under uncontrolled circumstances, islanding can inadvertently put power onto the grid where none is expected, creating potentially dangerous conditions for grid maintenance operators.

A new inverter protocol, IEEE 1547.8, will provide advanced DG functionality, including volt/VAR control, low voltage ride-through, and enhanced communication protocols.

The microgrid is a key concept for DG planning.  Microgrids are small, modern versions of the bulk grid that encompass a building, a building complex, a campus, or an entire community, with power managed by smart controllers.  The microgrid represents a self-contained, self-managed, and intelligent local net­work of generation, load, and storage that inter­acts with the greater distribution grid in an automated manner, as well as through two-way communication with the distribution and transmission grid operators.  This two-way communication gives grid operators a better picture of real-time and forecasted energy production, and also allows them to curtail components or dis­connect the en­tire microgrid if necessary.

Nevada Energy presented results from its studies of increasing DG penetration, and its conclusion that the distribution system is not the factor limiting how much DG can be installed.  Its other conclusions include: (1) NV Energy’s distribution feeders can accommodate greater amounts of DG when evenly distributed, but less when clustered; (2) for higher DG penetration, the impact on the transmission grid and generation operations must be considered; (3) the presence of utility‐scale renewable generation may cur­tail the amount of DG that can be installed; (4) the reduction in revenues from DG energy production is much higher than expected benefits to the utility.  Thus, new DG installations would result in a subsidy from NV Energy ratepayers to DG owners if current net metering rules were to apply.

The workshop included a “Transforming the Grid—Power to the Customer” presentation by Kurt Yeager of Galvin Electricity Initiative, which argued for transformation of the electricity infrastructure, policies, and business model to align market and utility incentives to accelerate smart grid investments.  Yeager pointed out that a smart grid requires looking beyond the regulated monopoly business model.  In order to be successful, barriers to retail competition must be removed, along with barriers to non-utility technology investments.  The result may significantly increase both consumer and producer benefits.

“Electricity is one of the few sectors where performance and earnings are not directly aligned with the interests of consumers or their satisfaction.  Instead, utilities answer primarily to state regulatory agencies, elected officials and federal authorities, operating under numerous rules that precede the New Deal.  But like many elements of the U.S. infrastructure, much of the equipment in the electricity grid is near the end of its functional lifespan.  We therefore face a choice of reinvesting in a system that served the past, or transforming it in ways that serve the consumers, businesses and society of tomorrow.”