Developers are watching two FERC proceedings
Two initiatives that have the potential to affect project developers are currently stalled at the Federal Energy Regulatory Commission, but should start to move once recent Trump nominees are confirmed to fill vacancies.
The commission is in the process of updating its policies on interconnecting independent power plants to the transmission grid. The existing policies date to 2003.
FERC is also grappling with a debate that has spilled over to the federal courts about the extent to which states can adopt policies that favor certain types of generation over other types. The debate has the potential to affect renewable portfolio standards that favor renewable energy.
The commission needs at least three members to have a quorum required to do business. It has had just two of five commissioners since February.
Cheryl LaFleur is the acting chairwoman, and Colette Honorable is the other commissioner, but Honorable has announced she will not seek reappointment at the end of her current term, which ends in June.
President Trump nominated a Republican Senate staffer, Neil Chatterjee, who is an advisor to Senator Mitch McConnell (R-Kentucky), and Rob Powelson, a commissioner of the Pennsylvania Public Utilities Commission (and current chairman of the National Association of Regulatory Utility Commissioners) to join FERC. The Senate energy committee is expected to approve their nominations the first week in June. The process may still take several weeks before the nominations are put before the full Senate for a vote.
They might be joined by a third rumored Republican pick, Kevin McIntyre, an energy attorney currently in private practice.
Based on campaign promises, transition team statements and industry appeals, the re-constituted FERC is likely to prioritize energy infrastructure development, grid reliability, cyber security and wholesale market design.
Some groundwork on two initiatives of particular interest to project developers has already been laid.
FERC issued a notice of proposed rulemaking, or “NOPR,” in December 2016 indicating that it plans to update its regulations governing interconnection of large generators, meaning greater than 20 megawatts, to the utility grid. The proceeding is in Docket No. RM17-8-000.
Large generators use a form agreement called a Large Generator Interconnection Agreement, or “LGIA,” that FERC prescribed in 2003 based on negotiations between the Edison Electric Institute and representatives from the independent generators.
FERC proposed 14 separate reforms in its notice of proposed rulemaking. The reforms are designed to address “concerns with systemic inefficiencies and discriminatory practices” expressed by independent generators, changes in technology and the generation resource mix and the frustration expressed by utilities dealing with late-stage queue withdrawals.
FERC wants to give generators greater control over the timely construction of interconnection facilities by making it easier for generators to build interconnection facilities themselves: the so-called self-build option. FERC also wants utilities to coordinate with neighboring transmission systems (known as “affected systems”) earlier in the interconnection process to avoid unanticipated delays and expenses for generators. Although not part of the proposed rule, FERC also requested comments on whether it should impose a cap on the amount of network upgrade costs that may be assigned to a generator. This should facilitate planning and mitigate serial re-studies.
FERC wants to improve transparency by increasing communication and information access. For example, it proposes to require owners of transmission lines to post congestion and curtailment information all in one place on their Open Access Same-Time Information System (OASIS) sites and to publish specific study processes and inputs to network models that are used for interconnection studies. Better up-front communication of information should hasten queue speeds and allow affected parties to predict the timeline for interconnection more accurately.
Another proposed reform is a requirement for utilities to offer provisional interconnection agreements to allow generators to operate on a limited basis before completion of the full interconnection study process. This could make a significant difference in project viability by allowing new power plants to start earning some revenue before the full interconnection process has played out. A few utilities already offer provisional interconnection and, when available, it is generally viewed as a way to mitigate certain development risks.
FERC also wants to tackle interconnection issues specific to emerging technologies and, in particular, energy storage. It proposes to include energy storage as part of the “generating facility” that can interconnect through use of the form LGIA and to require utilities to reevaluate their modeling methods for interconnection studies as related to energy storage. Such reforms would align the LGIA with the interconnection agreements and procedures for small generators and may mitigate key risks in the financing of energy storage projects, as discussed in a separate article in this issue called “Financing Energy Storage Projects: Assessing Risks” starting on page 12. This proposal is somewhat more controversial than some of the others in the NOPR as many still question whether it is too restrictive to put energy storage in the “generation” box when storage is able to function in other capacities, such as transmission and load.
Many companies filed comments in response to the NOPR, but FERC is currently unable to act due to lack of a quorum. The newly-constituted commission will have no obligation to advance the proposal, but it will be difficult to ignore. The NOPR includes a preliminary finding “that certain interconnection practices may not be just and reasonable and may be unduly discriminatory or preferential,” in violation of the Federal Power Act. At a minimum, the new commissioners may be pressured to explain any contrary conclusions.
FERC held a technical conference in early May to discuss the contentious interplay of state incentives for particular types of generators and federally-regulated competitive wholesale markets. The discussion generated some heat, mirroring escalating tensions in the industry more broadly.
In one corner sit states with the power under the US constitution to protect the health and welfare of their citizens. This power has been deployed broadly to reduce environmental pollutants, support important industries and ensure reliable energy supply. State regulators, in turn, must execute state laws enacted pursuant to this power.
In the other corner is FERC, an independent agency charged by federal law to ensure all rates for the wholesale sale of electricity are “just and reasonable” and “not unduly discriminatory or preferential.” Independent generators typically align with FERC, viewing state subsidies as discriminatory and skewing market signals.
The Supreme Court stepped in to referee last year in Hughes v. Talen Energy. FERC won that round. The court threw out a Maryland program designed to secure in-state capacity by directing a utility to pay a generator the difference between an established “strike” price and the price it received through participation in the wholesale power market operated by PJM.
The narrow decision failed to provide the industry much guidance, and states continue to seek ways to work around the markets and advance their internal policies while avoiding this precedent. For example, New York established a program to encourage three nuclear power plants to remain operating by establishing “zero emission credits” that have led to nearly $1 billion in payments to the plants on top of the revenue they earn from electricity sales. This approach was also adopted by Illinois regulators, and both programs are being challenged in court. Other states are considering similar programs.
The notice of the technical conference said the “Commission staff seeks to understand the potential for sustainable wholesale market designs that both preserve the benefits of regional markets and respect state policies.” It laid out a “spectrum” of solutions, ranging from administering wholesale markets in a manner that incorporates and satisfies state policy goals to designing wholesale markets to avoid conflicting with state policies. Several options along this spectrum were discussed at the conference, with no clear consensus.
State regulators, not surprisingly, were vocal about preserving states’ rights to make policy decisions for the benefit of their citizens. For example, the chairperson of the Illinois Commerce Commission said, “FERC should adopt a policy that requires [regional transmission organization (RTO)] energy and capacity market designers and operators to account for state energy policies.”
One obstacle to requiring RTOs to accommodate state policies is RTOs operate across state lines and individual state policies differ in terms of targeted resources, types of incentives, implementation and ultimate goals. It would be particularly challenging for a multi-state RTO such as PJM to operate in a manner that promotes competition to ensure adequate resources across the system at least cost, yet avoids conflict with all state laws within its 14-state footprint.
The chairwoman of the Massachusetts Department of Public Utilities described an effort among the commissions from several New England states to align on policies. She said members of the Integrating Markets and Public Policy (IMAPP) initiative are trying to determine whether a consensus can be reached on state policies among the New England states that might be advanced broadly by ISO New England (ISO-NE), their RTO. Each of the states involved has state renewable standards or emission reduction laws or both.
Representatives from the RTOs were skeptical about the possibility of preserving the benefits of competitive wholesale markets while accommodating state policies. A pre-conference statement by ISO-NE expressed concern about the entry of subsidized market participants undermining cost-effective price formation in the ISO-NE’s forward capacity market: “[I]f current investors, after incurring the sunk costs of entry, face state-subsidized competition that depresses their capacity market revenue, then future investors (in unsubsidized resources) may logically hesitate to develop new capacity, require greater risk premiums, or only offer to develop new capacity at such a high price as to recover their total costs and return on equity within a short, initial capacity price lock period. This risk could raise the net cost of new entry substantially over time, and inefficiently undermine the cost-effectiveness of competitive markets to the detriment of society overall.”
ISO-NE has indicated on other occasions that the lack of financeable projects raises resource adequacy concerns within the region. The possibility of a carbon cap and trade system was raised as a compromise measure, but has its own attendant market risks to consider.
The independent market monitor for PJM was more direct: “The subsidy approach is inconsistent with the PJM market design and inconsistent with the market paradigm and constitutes a significant threat to both.”
FERC cannot act in response to the conference until it has a quorum. As such, FERC lacks the ability to challenge state programs that it believes impermissibly affect the wholesale power market, which only the federal government can regulate. In the meantime, all eyes are on the litigation over the zero emissions credit program in New York. (For earlier coverage, see “State Mandates and Incentives” in the December 2016 NewsWire.) The case could have far-reaching consequences.