Gregory K. Lawrence, Partner
McDermott Will & Emery LLP
(Contributing Editor)

Although pointedly excluding transmis­sion planning and cost allocation, the NOI covered such issues as VER power forecasting, scheduling flexibility and incentives for VER output, reliabil­ity and day-ahead market participation concerns, capacity market and real-time barriers to VER use, and coordination among balancing authorities. During a comment period that ended April 12, 2010, FERC received input from more than 250 industry participants. Critical to the future direction of VER integration were the concerns and recommendations from several key sectors, which are briefly sampled below. Comments like these in­dicate the complexity that lies ahead for any FERC efforts, including rule changes to facilitate VER integration.

VER Associations

The organizations that represent the two largest VER segments, wind (American Wind Energy Association, AWEA) and solar (Solar Energy Industries Associa­tion, SEIA) were above all concerned that VERs be treated in what the SEIA called a “just, reasonable and not unduly dis­criminatory manner.” AWEA pointed out that much of FERC’s current regulatory structure was developed at a time when power generation was dominated by dis­patchable power resources.
To promote a level playing field, these VER organizations urged a combination of fast­er (sub-hourly) power system dispatch and scheduling, larger and more geographically diverse balancing areas, and promotion of region-wide load following markets and ancillary services markets, particularly in regions where no ISO or RTO exists.

VER Producers

Two of the largest individual VERs – BP En­ergy and NextEra – generally supported the industry association positions. Each, how­ever, emphasized that “one size fits all” access and market solutions are not possi­ble. BP Energy noted that a “combination of technologies [can] drive market trans­formation on a far greater scale than the individual technologies would do,” while NextEra noted that all energy generation sources vary by their technology, fuel type, emissions, location, and use (baseload, mid-merit, peaking, and variable).

NextEra reminded FERC that “numer­ous existing market rules are tailored to the needs of non-VERs,” particularly RTOs that typically do not encompass VERs. The Commission’s goal, Nex­tEra asserted, should be to “ensure that market rules are just and reasonable, and to remedy rules that are unjust and unreasonable.”

ISOs and RTOs

Many of the comments from the VER perspective implied that regulations favoring ISOs and RTOs need to be redressed to encompass the unique needs of VERs. The ISO-RTO Council, comprised of the ten current North American ISOs and RTOs that work collaboratively together, acknowledged that VERs will be increasingly impor­tant in helping states meet their man­datory Renewable Portfolio Standard (RPS) goals and asserted that its mem­ber organizations are doing much to facilitate VER growth.

However, the Council gave reminders that uncertainty, variability and lack of dispatch control over VER output remain major impediments to integra­tion. Efforts to smooth out the average VER production profile “may also re­sult in ever more complex operational requirements,” the Council reminded. The Council did not view this as an impediment, but emphasized that “because of different regional scope of each market and different generation mixes (especially the availability of faster ramping resources), there will be different operational and market needs and impacts” for VER integration into the grid.

Electric Utility Industry and Other Power Suppliers

This regional variation was emphasized by the electric utility industry. The Edi­son Electric Institute (EEI), represent­ing shareholder-owned electric compa­nies, held that VER integration should be determined primarily on a regional basis, with robust coordination across regions. EEI reasoned that because the grid regions are organized differently in terms of market structure and have varying amounts of VER potential, the regional level is the best perspective to determine how to most effectively inte­grate VERs into the transmission grid and wholesale electric markets. EEI pointed out that FERC excluded region­al transmission planning from the NOI, and implied this was a mistake given the fact that much current grid system maintenance is done in off-peak hours. If VERs are allowed to use the transmis­sion system more intensively off-peak, EEI warned that “planning assumptions for the transmission system may need to change.”

The Electric Power Supply Associa­tion (EPSA), representing competitive power suppliers, including generators and marketers, generally agreed. It as­serted that transmission planning and cost allocation, smart grid development, demand response and maintaining grid reliability are all issues that need to be addressed along with, and not apart from, a new VER regulatory structure.

One of the largest investor-owned utilities, Exelon, identified operational concerns about VER integration. The company asserted that, “… it is economically harmful to shut down baseload plants at night to ac­commodate wind generation and then run fossil-fired peakers during the day because the baseload is not there.” Exelon was as concerned about the issue of regulatory fairness as VERs, but from a 180-degree direction, warned that FERC “…must not put its finger on the scale in order to subsidize VERs,” because this “…will distort markets and make them much less efficient and will ultimately harm electricity consumers.”.

Other Industry Voices

Not surprisingly, other industry voices matched the VERs, system operators, utility industry and other power sup­pliers in identifying their own turf. For example, the California Public Utilities Commission (CPUC) reminded FERC that, given state and local jurisdiction over long-term power development and transmission, the most effective solutions for VER integration must be “developed and supported within, and are likely to vary across, different regions and sub-regions across the country” and urged FERC to “move forward cautiously and collaboratively” in setting new policies.

Moreover, although virtually all com­mentators offered at least some support for the notion that direct VER transmis­sion integration is the wave of the future for technology, one group – the Coalition to Advance Renewable Energy Through Bulk Energy Storage (CAREBS) – held itself out as an alternative. CAREBS reminded FERC that, because lack of adequate transmission capacity is a key hindrance to VER integration, bulk energy storage using compressed air and hydroelectric technologies can also be effective integration tools. The organization also identified as an important incentive the idea that, “…an energy storage device performing transmis­sion functions should be eligible for transmission rate treatment, including applicable incentives.”

Conclusion

There is clearly much more work that needs to be done in order to develop a consistent regulatory framework for VER integration. That need for (and speed of) that integration is unquestion­ably accelerating due to state and pos­sibly federal RPS requirements and the possibility of carbon emissions pricing. The comments highlighted here and many of the remaining 250 comments filed will likely help shape FERC’s ex­pected issuance of rulemaking efforts to formalize its policies for the integration of VERs into the wholesale energy mar­kets. What shape that notice will take to balance political, economic and tech­nological issues remains to be seen.

About the Author

Gregory K. Lawrence is a partner in the Energy and Commodities advisory group, and leads the Renewable Power practice area of global law firm McDermott Will & Emery. Mr. Lawrence focuses his practice on regulatory proceed­ings, market structure and trading, project development and contract negotiations relating to the wholesale and retail electricity and natural gas industries.