When I first started at APPA in February 2001, I had a lot to learn. While I had a crash course in electricity policy as a legislative assistant for then-Senator Chuck Hagel (R-Neb.), I still had a steep learning curve to grasp the complexity of the industry as well as the variety of players involved. Given the timing of my arrival, I was forced to quickly wrap my head around the often-competing policy objectives inherent to the regulatory bifurcation of the industry between retail and wholesale sales and how that split impacted public power utilities.
There were proposals in Congress to mandate regional transmission organizations across the country. Some people in our part of the industry were so fed up with the market power exerted by many investor-owned utilities that they were supportive of RTOs as so-called “cops on the beat,” but they did not support a mandate. Others in public power were more skeptical of RTOs in general — not because of their potential value, but because of the potential downside of what inviting more federal control might mean for local control – a fundamental tenet of public power.
As I began to better understand the various policy drivers related to RTOs/ISOs, it became clear that I did not fully grasp their relationship to transmission access, planning, cost allocation, siting, and ownership. The history and reality of public power’s transmission ownership, transmission dependence, and power supply options all influenced how individual public power utilities and joint action agencies viewed wholesale markets. To put it bluntly, if a public power utility was transmission-dependent, an RTO might have felt like the only recourse to access affordable power supply, making the potential for additional federal regulation seem worth the risk. If, on the other hand, a public power utility either outright owned transmission, was a joint owner of transmission, or had access to significant amounts of federal hydropower, then it might not have been so interested in the gamble.
From the early 2000s to when I left APPA in 2016, RTOs/ISOs evolved significantly. The gamble wasn’t paying off for public power in the eastern RTOs, where many transmission-dependent utilities were seeking relief from high transmission costs and generation market power (enabled by transmission ownership) in the late 1990s and early 2000s. In the Midwest, it had gone markedly better. In the West and the South, only California had embarked on the experiment, and many public power utilities had been able to opt out of that market.
In the four years I was away, things shifted a bit. Sadly, the eastern RTOs are still unhelpful — if not downright antagonistic — to public power. The midwestern RTOs are still holding their own in terms of both benefits to public power and to the industry, and the West has evolved quite significantly. The most notable development has been the Western Energy Imbalance Market, a voluntary real-time market through which participants can buy and sell imbalances in load and generation. The EIM has provided the efficiencies and costs savings of centrally dispatched markets without the risks of a full RTO.
The unevenness of the RTO experiment reflects the deference the Federal Energy Regulatory Commission has shown to the RTOs/ISOs, whose policies are, in turn, molded by their largest stakeholders. But FERC blesses and codifies poor policy, such as the minimum offer price rule, while taking a hands-off approach to the processes enabling the bad policy. In the case of the East, this has been the worst of both worlds. In the Midwest, the hands-off approach has worked better because public power and rural electric cooperatives wield more influence, and many of the IOUs in those regions have retained an obligation to serve their customers and align more often with their public power and rural electric cooperative colleagues.
There is more to the RTO/ISO story than I can get to here — stakeholders like independent power producers, jurisdictional creep into retail markets, and new technologies, just to name a few. This issue of Public Power magazine touches on some of these other perspectives and issues.
As the RTOs/ISOs continue to evolve, and as public power utilities continue to navigate the pluses and minuses to these constructs, I come back to the “t” in RTO: transmission. The key policy matters surrounding transmission — planning, cost allocation, siting, incentives, and ownership — have not been resolved. While Congress attempted to address siting in the Energy Policy Act of 2005, the courts disagreed with the back-stop authority granted by that law. Granting incentives for certain priority transmission lines hasn’t really worked to get the “right” transmission built (i.e., transmission with the greatest benefit to the most entities at the least cost), and FERC has ping-ponged about what is the right approach (APPA thinks the granting of such incentives must be weighed closely). Public power utilities must actively engage in the planning processes within RTOs to ensure their views are heard, but these processes often require significant resources and time. The issue of who pays is almost as thorny as siting, and a cost allocation methodology that strikes the right balance between transmission owners and other transmission users might be close to impossible to achieve. However, the policy of joint ownership of transmission is proven. Where it has happened, it has helped with siting and with cost allocation. But it has usually happened only when events have forced policymakers at the state level to bring the transmission-owning IOUs to the table with public power and co-ops.
The push for more joint ownership of transmission was a priority when I first came to APPA in 2001, and it is an issue whose time has come. As an industry, we can come together around this concept and make it a priority again. In so doing, we could hedge against our exposure to rising transmission costs while helping to ensure that beneficial transmission infrastructure gets built.
