Environmental, Natural Resources, & Energy Law Blog
Revisiting FERC Order No. 1000 Should Maximize Investment in Regional Transmission Infrastructure - Helen Kemp
Electricity transmission planning is a key component of traditional utility operations that increasingly faces criticism as a hinderance to decarbonization efforts. Recent developments in national energy policy are calling for a renewed commitment to innovation and investment in this area. Drastic, rapid increases to transmission capacity are necessary to meet the Biden Administration’s goal of carbon-free electricity by 2035 and as much as a 60% increase in high-voltage capacity is required by 2030 just to catch and keep up with current solar, wind, and additional clean energy production goals. To support transmission planning reform, the Federal Energy Regulatory Commission (“FERC”) recently issued Advanced Notice of Proposed Rulemaking Docket No. RM21-17-000 (“RM 21-17”), which seeks to revisit the potential reinstatement of a federal right of first refusal (“ROFR”) for incumbent utilities to undertake new transmission projects. RM 21-17 would amend the previously adopted Order No. 1000 (the “Order”), issued just over ten years ago. The Order established reforms in transmission planning and cost allocation and eliminated the ROFR in favor of incumbent utilities involved in regional or inter-regional infrastructure construction, with limited exceptions. RM 21-17 presents an opportunity to find a balanced solution that benefits consumers, incumbent utilities, and new entrants to the electricity market. To capitalize on the institutional experience of the utility industry as well as the entrepreneurial potential of the non-utility private sector, FERC should use this rulemaking to incentivize increased utility investment in regional transmission infrastructure that meets stringent reliability, capacity, and transparency standards, without obstructing third parties’ ability to compete for such projects.
At the heart of every effort to replace fossil fuels with clean power sources lies the critical need to mitigate global climate change. Despite advancements in renewable energy technology, the aggregate process of power generation is still one of the most significant causes of greenhouse gas emissions. One study estimates that inefficiencies in transmission and distribution alone account for as much as 1 billion metric tons of carbon emissions through loss annually. Compared to their non-renewable counterparts, modern energy sources tend to require more extensive transmission connections that cross the service areas of multiple utility providers due to their significant land area siting requirements. This structural challenge has created a gap between the capability to produce clean energy and an inability to deliver that energy to consumers across the country. Those involved in the RM 21-17 proceedings must keep in mind that the goal of optimizing the nation’s transmission infrastructure is underscored by the urgency of the climate crisis. With little room for error or delay, whether the ROFR is reinstated or not should ultimately be determined by its potential as a mechanism for expediting design and construction to meet these needs.
The changing energy resource landscape poses technological and cost problems that utilities feel they are best suited to solve, though other stakeholders advocate for further expanding access to the bidding process for regional transmission projects. Utilities that traditionally had a monopolistic hold on all aspects of the system are under pressure to evolve, or risk losing their revenue-generating business lines to competitors enabled by deregulation and restructuring. Before Order No. 1000, the ROFR granted a public utility transmission developer an automatic first option to build, own, and operate any transmission project within their service area. The project would only be set out for third-party bidding if the incumbent chose not to construct it themselves. The revocation of the ROFR has been one of the most controversial of the Order’s reforms and challenged on all sides by utility representatives and consumer groups, as either excessively or insufficiently protective of competition. A few states, under pressure from lobbyist groups, even subsequently enacted their own ROFR laws to apply within their borders.
Utilities argue that both local and regional transmission are most effectively administered by a minimum number of entities, and propose reinstating the federal ROFR. Because of the coordination and unity of technology required to interconnect a high quantity of generation facilities and transport power across long distances, the owners and operators of transmission infrastructure must possess a certain level of expertise as well as a willingness and ability to communicate with each other at all stages of the construction and operation processes. On behalf of investor-owned utilities (“IOUs”), the Edison Electric Institute (“EEI”) challenged the ROFR removal in their response to RM 21-17 as having “resulted in a near standstill in transmission development for regional projects and a substantial increase in process-related costs” and “stifled the cooperation and collaboration that has historically existed among transmission owners.” Without these features, there is a risk of unnecessary redundancy, inefficiency, or technological incompatibility.
The California Public Utilities Commission (“CPUC”) also criticized FERC’s Order No. 1000 approach to the ROFR, expressing that, “despite [FERC’s] laudable intent…[this] action inadvertently created a perverse incentive that encouraged incumbent IOUs to concentrate transmission investment in local transmission facilities to avoid competition.” However, CPUC’s proposed solution is geared towards further invoking a ban on the ROFR as it relates to local projects (currently exempted by the Order), to promulgate additional competition at all levels of the transmission system. In an open letter to Congress, the Electricity Transmission Competition Coalition (“ETCC”) captured the ratepayer perspective, opposing “transmission monopoly market power that leads to transmission capacity additions that are not holistically planned and costs that are not checked against alternative transmission and non-wires solutions.” The ETCC echoed CPUC’s contention that utilities are simply over-investing in capital projects deemed “local” (and therefore outside of the scope of the Order) to their service areas to ensure profit through their rate base rather than compete in the market for regional projects.
On one hand, utility-managed transmission projects benefit from the extra financial protection that the regulatory system provides. Their longevity and financial integrity are almost ensured. From the perspective of the Electricity Consumers Resource Council, “one will search in vain for a real-world investment document that characterizes rate base, cost-plus transmission as anything other than an exceptionally safe investment.” While characteristically safe, utilities’ maximize their profits by making capital-intensive investments and supplanting those costs in the rate base, but the resulting dividend is limited by their regulatory authorities. New transmission bidders may push the envelope in terms of innovation. However, they are subject to the full extent of market risks. They may not have knowledge of - or an invested interest in - the region to the same extent that a local utility would; some ROFR proponents argue that “the transmission system isn’t suitable for Silicon Valley type investment”  and these new entrants may not be able to stay the course of such an expensive long-term construction venture. The unique structuring of the utility sector that arose from the nature of its business requirements has developed specifically to protect the original service providers of this essential business, and the urgency with which transmission development is needed leaves less room for failure and thus a lower appetite for risk. The potential pitfalls of unfettered competition to the exclusion of IOUs warrants consideration as RM 21-17 proceeds.
On the other hand, a right of first refusal is redundant if electricity transmission truly fits the mold of a natural monopoly industry. If natural monopoly theory applies to the field of transmission infrastructure as contended by the incumbents, then as the entities with the most established resource procurement for their locality, they should be able to provide the most competitive pricing and planning. As such, it seems clear that amendments to Order No. 1000 do not need to restore an unlimited ROFR for utility developers. Any solution to the ROFR controversy should acknowledge the advantages that an open market provides while still encouraging incumbent utility participation, allowing the system to draw on their current market position and experience. Some form of a monetary incentive for public utility participation in the regional planning process is likely the answer.
In that vein, RM 21-17 requests comment specifically on “how to expand or improve any incentives to incent the development of regional transmission facilities that demonstrably may offer a more efficient or cost-effective solution to an identified need than local alternatives.” The notice questions whether a return on equity (“ROE”) incentive, a payment beyond the standard rate of return for a capital investment, should apply to projects that are regional, local, or both provided they are constructed pursuant to Regional Transmission Organization/Independent System Operator (“RTO/ISO”) participation. Instead of or perhaps in addition to using this feature to compel blanket RTO/ISO engagement (potentially invoking pushback from the still non-RTO participant West and Southeast regions), such an ROE could target any project completed by an incumbent developer that meets certain criteria. This should include, at a minimum, that the project (1) demonstrably improves regional reliability and capacity, (2) utilizes the best available technology as determined through a set minimum investment in research and development, and (3) specifically supports the incorporation of renewable generation sources to the grid. Utilities should apply for these incentives and their applications subject to public review and comment to ensure that such criteria are met.
From the ratepayer perspective, embedded transmission incentive costs could be fully or partially offset by the reduction in fuel costs as expensive fossil fuels are replaced by renewable energy. For example, a recent study by PJM Interconnection found that “the new transmission and renewable energy additions would generally lower consumer electricity costs, but more studies are needed to flesh out the extent of those savings.” Ultimately, because utilities do not benefit from the potential for unlimited profit margins that private businesses do, this is where revenue motivations can balance out. Ideally, utilities will feel able to compete and win regional infrastructure bids while retaining the ability to plan locally. IOUs can capture efficiencies if they have a renewed ability, in cases of successful bidding, to integrate their local and regional planning with an amplified enthusiasm to modernize in order to meet incentive requirements.
It is important that any modifications to Order No. 1000 that may result from the new rulemaking proceeding do not sacrifice the positive advances made towards opening the electricity transmission industry to market-based competition. FERC should seize the opportunity within RM 21-17 to take advantage of the stability and resource accessibility that existing utilities possess without precluding the benefits of innovation that market competition provides. Incentivizing incumbent utilities’ participation would need to be done thoughtfully and with plenty of accountability safeguards in place, but if carried through appropriately this approach could maximize efficiency and minimize risk in transmission development. Meeting the nation’s renewable energy goals will require employing the electricity industry’s collective resources as well as investing in new technologies that are still under development. While the rulemaking and implementation process for RM-21-17 may take years, it is imperative that stakeholders continue to engage with the proceeding so that the final rule represents a holistic and effective approach to transmission planning for the future.
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 Building for the Future Through Electric Regional Transmission Planning and Cost Allocation and Generator Interconnection, 176 FERC ¶ 61,024, Docket No. RM21-17-000, (Issued July 15, 2021).
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 “A market that can support only one firm because conditions of supply and demand leave room for no more—what is called a “natural monopoly”—has no need for a right of first refusal. Such a right implies a possibility of entry (why otherwise create such a right?)—in other words room for an additional firm or firms, yet the right enables the incumbent firm to ward off entry.” MISO Transmission Owners v. FERC, 819 F.3d 329 (7th Cir. 2016)
 Building for the Future Through Electric Regional Transmission Planning and Cost Allocation and Generator Interconnection, 176 FERC ¶ 61,024, Docket No. RM21-17-000, (Issued July 15, 2021). 61.
 Patterson, Delia. “Who Really Benefits from Transmission Incentives?” Who Really Benefits from Transmission Incentives? | American Public Power Association, 5 Sept. 2019, https://www.publicpower.org/blog/who-really-benefits-transmission-incentives.
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