Slate of FERC Orders and Court Decisions Will Impact Grid

In Washington’s summer months, when it rains, it pours. There has been a slate of recent activity on the U.S. electric grid, some coming down as official FERC Orders, others coming down as court decisions. Some of these decisions have been positive developments for a U.S. shift towards a cleaner electricity grid, some of have been negative, and the implications of others still are unclear. In this post, we summarize each order and decision, and discuss briefly their impact.

FERC Accepts CAISO Energy Imbalance Market
At the June 19 Commission meeting, FERC accepted a California Independent System Operator (CAISO) proposal to implement an Energy Imbalance Market (EIM) in the West. By creating a mechanism which allows excess energy in one balancing area to reduce a shortfall in another, an EIM can reduce costs while bolstering reliability. EIMs are central markets which aggregate and balance generation and load across a wide geographic region, reducing system operation challenges that increasing penetrations of variable generation are expected to bring [1]. In the Western interconnection, the EIM opens the door to a more market-driven, rational, and efficient process for balancing generation and load than is possible at present with 38 separate and largely isolated balancing areas. PacifiCorp of California will be the first company to participate in the EIM, and NV Energy of Nevada has filed with FERC to join the market by October 2015. Participation in the market will be voluntary.

FERC Adopts New ROE Methodology for Electric Utilities
Also at the June 19 Commission meeting, FERC came to an important decision regarding the appropriate base rate of return on equity (ROE) for electric utilities building new transmission lines. Pursuant to the Federal Power Act, FERC must ensure that rates charged by transmission providers remain “just and reasonable.” In 2013, a group led by New England public utility commissions, attorney generals , and consumer advocates filed a complaint against utilities owning transmission lines (New England Transmission Owners or NETOs), arguing that the 11.14% return on equity they were receiving was “unjust and unreasonable” in light of the decline in interest rates and other criteria traditionally used to gauge appropriate rates of return for electric utility transmission investments. The hearings involved strong financial and technical arguments on both sides, but the focus of the debate was the methodology used to calculate ROE. In a very significant step, FERC adopted a two-step ROE calculation methodology that accounts for both short and long term growth projections – the same model used for oil and gas pipelines. The new method tempers the impact on ROE of fluctuations in short term growth benchmarks like interest rates by adding in a factor for long term growth linked to GDP. Using this methodology, FERC set the new base ROE at 10.57%. This result is lower than the prior industry-supported ROE, higher than the ROE requested by the complainants, and we believe a good compromise – both methodologically and quantitatively – which should be adequate to attract capital for needed for robust investment in transmission. It’s important to note that finalization of the 10.57% ROE is subject to the outcome of a paper hearing established by FERC to give participants in the case an opportunity to present evidence on the long term growth rate estimates used to calculate it.

Supreme Court Declines to Hear Missouri Cost-Recovery Case
In 2011, the Missouri Public Service Commission (MPSC) denied Kansas City Power and Light’s (KCPL) application to recover transmission costs incurred when transmitting power from a gas plant owned by its affiliated generation company in Mississippi to its customers in Missouri. The MPSC concluded that the utility could get the same power at lower cost without incurring the transmission cost. KCPL sought rehearing by the Supreme Court, arguing a violation of the supremacy clause of the U.S. Constitution, which holds that federal law preempts state law on transmission rates, so that a state could not reject a FERC-approved transmission rate. Missouri argued that KCPL was not challenging the transmission rate approved by FERC, but its own utility’s decision to purchase its remotely-generated power that required paying such a transmission rate, rather than cheaper power to which it had easier access. Since the Supreme Court declined to accept the case, the ripple effects of this decision remain unclear. The Edison Electric Institute has expressed concern that the decision could set a precedent for public utility commissions across the country to potentially deny recovery of FERC-approved transmission costs if utilities have a lower-cost supply option. As remote, low cost, utility-scale wind and solar resources displace retiring traditional generator closer to load, interstate transmission may become a proportionately larger cost factor in utility procurement decisions. Nonetheless, this ruling should not disadvantage remote clean energy as long as its net delivered cost – including FERC-approved transmission rates – remains competitive.

Federal Appeals Court Rejects FERC’s Handling of Transmission Costs in PJM
In June of 2013, the U.S. Court of Appeals for the Seventh Circuit endorsed FERC’s proposed broad cost-allocation for the multi-value projects planned throughout the MISO area, accepting the premise that the entire area would benefit from the value of the incremental high-voltage transmission needed to bring clean energy to MISO’s millions of electricity customers. One year later, the same court issued a strongly contrasting decision. The court ruled 2-1 that FERC was unable to justify why utilities in the western portion of PJM Interconnection territory should have to pay the costs of transmission lines primarily benefiting the eastern side. At issue was not the “roughly commensurate” principle established in 2009’s landmark Illinois Commerce Commission v. FERC (by the very same court), but rather FERC’s ability to provide enough evidence that costs would indeed be roughly commensurate with benefits. In a strongly worded dissent, Judge Richard Cudahy assailed the court’s call for more exact numbers, saying that a “mathematical solution to this problem…is a complete illusion,” and that the court should defer to FERC’s technical analyses in such cases. Judge Cudahy’s concern that the court is looking for a level of precision that is unattainable by FERC or anyone else seems well-founded. However, if the Commission is able to meet the court’s “roughly commensurate” standard, this now multi-year saga could end as a major positive for investment in clean energy transmission.

Appeals Court Throws Out FERC’s Demand-Response Order
Order 745 – issued by FERC in March 2011 – required that demand response (DR) participating in energy markets be compensated on a basis comparable to generators, i.e. at full locational marginal price. FERC reasoned that DR, the power made available to the market by the willingness of a customer not to consume it, was of the same value as that amount of power made available by a generator, and therefore should be priced the same. The order was designed to increase penetration of DR in organized markets, and analyses show that it did, indeed, have the desired effect.. However, in late May, the U.S. Court of Appeals for the District of Columbia vacated Order 745, on the grounds that FERC has no jurisdiction over retail activities, and that DR is fundamentally a retail activity subject to State regulation. The court’s ruling applies only to economic payments for DR, not capacity payments, and importantly, implementation of the ruling has been stayed until all appeals are heard. In the short term, the effects of the decision on the DR industry are likely to be small, especially when one considers that economic DR payments accounted for just about 2% of industry revenue in 2013. Over the longer term, the decision raises more significant questions. Specifically, the court’s finding on jurisdiction will almost certainly be tested in DR capacity markets, the source of most of the industry’s revenue, which could turn regulation of DR into a predominantly or even exclusively state-run affair. States, many of which have trumpeted the benefits of DR programs, will play a pivotal role in determining what impact this decision has on the DR industry. The ruling seems unlikely to significantly affect the environment for high-voltage transmission investments for two reasons. First, DR typically produces a different set of benefits than transmission, and second, DR cannot, even at very high levels of penetration, substitute for certain critical clean energy transmission functions, like accessing remote renewable resources and linking balancing areas. That said, if the ruling results in a sharp curtailment of DR, normally viewed as a “non-transmission alternative,” transmission investments may receive greater attention as a result.

[1] For more information on how an EIM works, please see this article.

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Maine PUC Approves Transmission Upgrade With Regional Cost Allocation

The Maine Public Utilities Commission unanimously approved $1.4 billion in transmission upgrades requested by Central Maine Power, including a new 345 kV line to the New Hampshire border. The plan was a compromise settlement that also included non-transmission alternatives like demand response and energy efficiency in certain areas. You can read the official statement of MPUC here.

Though the upgrades are contained within the state of Maine, the impact will be felt throughout New England. Back in March, the Independent System Operator for New England (ISO-NE) approved regional cost allocation for the upgrades based on state energy use. Under this approach, Maine pays 8% of the cost.

You can read more about New England states’ attempts to regionalize transmission and renewable energy development here.