Why not start off big? My inaugural blog is the first in a 2-part series on FERC’s Planning and Cost Allocation Final Rule.
While Congress continues to be mired in partisanship and politics pushing hopes of comprehensive energy reform to the far-back burner, the sometimes under-recognized but critically important Federal Energy Regulatory Commission (FERC) has demonstrated that it is willing to forge ahead in the transition towards a clean energy future. Last Thursday, FERC issued Order 1000, one of its most significant rules in years. In all of its 620-page glory, the rule contains transmission planning and cost allocation reforms that in addition to lots of other good things, will equate to real progress towards the integration of renewable energy resources and state and federal renewable energy, energy efficiency, demand response and distributed generation policies. Today’s blog will focus on the planning reforms; we’ll talk about who should pay for what later this week.
How do utilities plan for new transmission now?
Let me quickly oversimplify existing planning processes. Utilities that participate in regional transmission organizations, known as “RTOs” or “ISOs” (in New England, NY, the Mid-Atlantic, much of the Midwest, TX and CA), already engage in annual regional transmission planning. The planning involves a prediction of expected electricity demand and supply in the near and longer-term, and an assessment of the reliability needs and congestion issues related to this prediction. The utilities in each region have agreed to allow their respective RTO to serve as the chief planner, analyzer and master of ceremonies of the planning process. When an RTO predicts a reliability or congestion deficiency, it works with its member utilities and other stakeholders to devise a transmission solution, or, less often, it solicits the market for proposed solutions. In much of the West and Southeast where utilities don’t participate in RTOs, each utility takes care of its own transmission planning with varying degrees of transparency. Some non-RTO utilities also join in regional efforts to coordinate transmission planning.
So what’s the problem?
Transmission planners are underappreciated – they’re the ones that make sure your lights turn on every day – but from a renewable energy and demand-side resources perspective, the current transmission planning process has a few problems (aside from ever-present transmission siting concerns) that stops it from keeping pace with an evolving electric grid.
Consider the RTOs and ISOs, with which I’m most familiar. First, regions generally view the process as “transmission” planning and not “comprehensive system” planning. Many RTOs suggest that either they do not have the jurisdiction (“smells like integrated resource planning!”) to consider and select non-wires alternatives to reliability or congestion issues, or that their members would never agree to such a change. In fact, RTOs have an obligation to engage in comprehensive system planning, which includes the obligation to analyze the most cost-effective solutions to a given need and to provide that information to stakeholders and the market. Regardless, most RTOs only direct new transmission lines or upgrades (NYISO is a notable exception – read page 38), even though energy efficiency, demand response, distributed generation or an emerging smart grid technology may be able to solve a reliability issue in less time with less money.
Of course sometimes, transmission is necessary. For example, new utility-scale renewable energy projects must be built where it’s really windy or sunny, often away from cities and towns where the demand for power exists. This leads to the second problem with planning processes, which is that most planning processes focus on reliability and congestion issues to the exclusion of considering public policies like the need to integrate far-away renewable resources. A third, really big issue with current systems planning is that it’s hard to figure out who should pay for a new transmission project identified through a regional planning process (more about cost allocation in my next blog).
Outside of the RTOs, planning is sometimes more balkanized and often less transparent, compounding the problems I’ve mentioned.
Why is Order 1000 such a big deal?
The new rule provides a platform for environmental advocates and other stakeholders to address the problems I mention and more. On the planning front, Order 1000:
- Makes sure that all transmission owners, including utilities both in and outside of RTOs, engage in a transparent and inclusive planning process that results in a real regional plan, and also participate in interregional planning with neighbors;
- Requires regional planning processes to consider and plan for/facilitate the impacts of existing public policies like, for example, state renewable energy portfolio standards, state and federal efficiency mandates and EPA clean air rules; and
- Compels regions to provide comparable treatment for non-wires solutions as compared to new transmission when it comes to figuring out how to solve reliability, economic and public policy needs. [UPDATE 7/26 - A wise colleague rightfully pointed out that I'm stretching it a bit on this point - although the rule requires comparable treatment, it may be better interpreted as meaning that planners need to consider non-wires alternatives in the planning process but not provide comparable consideration in determining solutions to suggest or direct.]
Opponents of the rule, specifically incumbent utilities with a monopolistic reign on the transmission in their territories, will make a lot of noise about FERC’s heavy handedness in issuing regulations that risk grid reliability and implicate regional transmission planning processes that already work well. In reality, the rule’s implications are just the opposite. Order 1000 will allow for important tweaking of regional planning processes in RTOs and provide a look under the hood at sometimes mysterious non-RTO utility transmission planning processes. By clarifying planning procedures, fostering competition with nonincumbent transmission developers, facilitating public policy needs and opening the door, even if just a crack, to comparable treatment for non-wires solutions, the rule actually increases transparency and fosters competition.
Is there any downside?
Of course, when any action eases the road to new transmission development, we must remember the enduring need to protect sensitive lands and habitats from harm. Transmission developers are starting to understand the advantages of engaging in “smart siting” and leaving protected wildlife and habitat out of a line’s path (just take a look at some of my NRDC colleague the great Johanna Wald’s blog posts). And yes, the rule could have been stronger – it could clarify a broad list of policy types that planners must consider and more clearly require RTOs to consider non-wires alternatives on equal footing with transmission projects as solutions to reliability, economic or public policy needs. It could make certain that load forecasting methodologies account for the emergence of demand-side resources on the grid, and that RTOs and other TPs are quipped to provide for the fast and reliable retirement of dirty old coal plants. There is more work to be done.
For now, though, the Commission should be commended for this transformative rule, which puts forth a framework that can move this country’s electric grid towards a clean energy future.