To reach the RPS goal of 33 percent renewables by 2020, California utilities must build extensive transmission upgrades to interconnect the renewable projects they are committing to buy power from. The current transmission upgrade process is badly misaligned, however, and navigating a comprehensive renewable buildout has become nearly impossible.
The California Independent System Operator’s (CAISO) ongoing initiative, the “Integration of Transmission Planning and Generator Interconnection Procedures” (TPP-GIP), illustrates how byzantine the transmission upgrade process has become. In the current TPP-GIP proposal, all proposed projects will be studied together and assigned cost responsibility for upgrades based on the results of the California Public Utilities Commission (CPUC) Transmission Planning Process (TPP).
The problem is, the TPP uses an RPS Calculator model -- a numbingly complex spreadsheet designed to predict the ‘ideal’ renewable capacities to given areas, in order to determine which upgrades should be pre-funded by the state. The final study results for projects will depend on how this model is run and on how the CAISO and other stakeholders decide to assign costs through TPP-GIP and other initiatives.
These are make-or-break results for projects, and it is very difficult for developers and utility off-takers to determine which projects will be ‘winners’ in this transmission study lottery. Projects that looked good at one time may look very bad at another, and vice versa.
Ask any developer or utility procurement staff and they will tell you how challenging and convoluted the transmission upgrade process has become. To get a better perspective on this problem, we should understand it in the context of the state’s overall approach to the power industry.
The California Way
When it comes to power, California has one of the most segmented approaches in the country. The paradigm over the past twenty years has been that market contracting and non-discriminatory processes, as opposed to the traditional holistic utility model, will produce the best outcome for the rate-payer. This framework has driven the various waves of ‘deregulation,’ as well as other reforms like CAISO’s 2008 Market Redesign and Technology Upgrade, which introduced transparent nodal pricing to the grid.
To see this approach with the RPS process, let’s walk through the development cycle of a renewable power plant:
- A project is ‘born’ when a private developer ties up a piece of land, does an initial design, and files an interconnection request with the CAISO.
- The developer then markets this plant to utilities, usually after receiving initial interconnection study results. After a competitive auction, the project is (hopefully) selected by the procurement arm of a utility and a power purchase agreement (PPA) is signed.
- At this point, the project is far from a done deal. The proposed plant will now continue to be processed in a neutral interconnection queue managed by the CAISO, receiving further sets of studies with different results. The transmission arm of the utility actually performs these studies, and they can give no consideration to any decisions made by the procurement arm.
- As mentioned, the CPUC and other statewide stakeholders also run parallel processes to determine the cost treatment of the upgrades needed by the project.
- When the interconnection study process is finally complete, the developer, the CAISO, and the transmission side of the utility sign an Interconnection Agreement. At this point, a different group in the utility -- the Major Projects Organization -- takes over and begins working out the schedule for actually constructing the transmission upgrades.
As you can imagine, this all amounts to a lengthy process. Filing an interconnection request requires little more than buying a low-cost option on a piece of land, producing initial designs, and placing a refundable deposit. As a result, the queue is bloated, currently with more than 52,000 megawatts of projects (many, many multiples of what is needed for the RPS). Projects can wait years for interconnection results, as utility transmission engineers are backed up trying to perform cascading sets of studies for all the projects in the queue.
This process is then continually being reformed mid-stream, through TPP-GIP and other initiatives that address problems with the process while attempting to maintain California’s ‘neutral’ approach to transmission planning -- where all projects are equal and utility groups completely separate. Developers sit on the edge of their seats following the ongoing reforms, trying to divine the likely consequences for their contracted project.
Projects with PPAs can fail (and have) because they receive new interconnection results that drastically change the amount of upgrades they are responsible for. In addition, projects can fail (and have) because of the sheer length of time it takes the utility to work through the interconnection study process and actually build the upgrades (the projects can’t come on-line before their PPA deadlines).
Southern California Edison’s (SCE) 2009 Renewables Standard Contract solicitation is but one example of a utility procurement program that has not been supported by the statewide transmission process. In 2009, SCE signed PPA’s with ten new wind andsolarprojects that were each 20 megawatts and under. At the time of this writing, not a single one of these projects has begun construction, all having spent the past three years being processed in the state’s interconnection queue.
If it takes California this long to figure out how to incorporate these smaller projects into the grid, how long will the 100-megawatt projects take? Everyone loses when we have to burn more fossil fuels while waiting for the achingly slow renewable development cycle.
California’s approach to power has delivered great value to rate-payers in the form of efficient markets and incentives for private-sector innovation, but it also can pose problems. In the case of renewables, when developers, utility procurement staff, transmission planners, and CPUC policy-makers have to engage in a complex dance to meet a simple requirement -- that 33 percent of power be renewable -- we may want to take a step back and rethink the fundamentals of our approach.
A Transaction Cost Framework
In The Nature of the Firm, Nobel Prize-winning economist Ronald Coase used transaction costs to rationalize the existence of large organizations. In his formulation, a firm will define its size and scope by the extent to which the transaction costs of contracting out for a given task outweigh efficiencies captured through the market. In other words, large companies exist because they complete tasks more efficiently than a collection of independent actors with contractual relationships, all things considered.
Coase’s framework, unfortunately, now seems to describe the California renewables build-out, where one wonders whether the state has paid more in transaction costs for its neutral, market-oriented approach than the benefits it has received.
Imagine if Southern Company, the Atlanta-based electric company that operates as a traditional vertically integrated (and empowered) utility, had been charged with meeting a 33 percent RPS. Simply put, they’d be done by now. The utility would have identified the best locations on the grid to install renewable facilities, and then would have constructed the plants and transmission upgrades (using contractors, just like a developer would), earning their approved rate of return on all capital expenditures.
The point isn’t that California, or any other power market, should copy Georgia. Opening parts of the utility business up to the free market has, among other things, made possible the existence of an innovative renewable development industry. However, attempting to complete various sub-tasks through neutral processes also comes with costs -- in the form of administrative expenses, lengthy delays, and the potential for outsized profits made by firms at the expense of rate-payers.
We should remember that the provision of electricity will always be, in part, a social good. Government-sponsored monopolies are the best vehicles to fulfill the societal mandate of reliable, reasonably priced, responsibly generated electricity. Utilities, after all, are the entities that are charged with meeting the RPS in the first place.
State policymakers should think critically about which aspects of the RPS build-out in California are best left to the ‘old’ utility framework and which warrant separate markets and processes.
A Proposed Solution
Coordinating a least-cost transmission solution to go along with 33 percent renewable procurement should fall squarely in the lap of a single set of utility decision-makers.
Why not give the utilities broader latitude to fit transmission upgrades to already-contracted projects, and to use the RPS procurement process to select projects that fit the least-cost solution? Once a developer has a contract, they can be sure that their project is a priority in the transmission development process and won’t get tripped up by some ‘non-discriminatory’ planning process.
We’re making the renewables build-out harder than it has to be. We need to let utilities do what utilities do: achieve mandated goals at a minimum cost to rate-payers. Let’s stop tying ourselves in knots with ‘neutral’ transmission processes and get serious about meeting our RPS.
Sam Maslin has spent four years in the power industry, first at Silicon Valley Power and then at Recurrent Energy, where he developed large-scale solar projects in California. Prior to that he worked for San Francisco Mayor Gavin Newsom.