Across the United States, there is a growing interest in distributed generation, which produces electricity in small quantities near the point of use, rather than in large amounts in a few places. Yet, distributed generation presents certain challenges for investor-owned utilities, independent power producers, and state and federal regulators. The integration of distributed generation resources onto the electric grid on a wide scale may dramatically impact utility investment and operations.
During this one-hour webinar, our presenters discussed distributed generation resources, their impact on utilities, and relevant policy considerations.
On August 15, the U.S. Court of Appeals for the District of Columbia Circuit rejected the challenges filed by various utilities, industry groups, and state commissions that claimed that the Federal Energy Regulatory Commission (FERC or the Commission) overstepped its authority when promulgating Order No. 1000. The court’s decision in South Carolina Public Service Authority v. FERC, which FERC Chairman Cheryl LaFleur hailed as “critical to the Commission’s efforts to support efficient, competitive, and cost-effective transmission,” substantially strengthens FERC’s ability to establish the structures necessary to encourage and facilitate competitive transmission planning and development.
On July 17, the Federal Energy Regulatory Commission (FERC) proposed to approve a new mandatory reliability standard that would require electric utilities to protect their transmission facilities and control centers against physical threats. Although FERC did not take issue with most of the language in the CIP-014-1 standard proposed by the North American Electric Reliability Corporation (NERC), FERC did express concern over the ability of utilities to identify their own critical facilities, even when that determination is subject to third-party review. To address that concern, FERC proposed to direct NERC to modify the standard so that FERC, or other appropriate federal agencies, could direct electric utilities to add additional facilities to their list of facilities that need physical security protections.
The Federal Energy Regulatory Commission (FERC or the Commission) introduced a set of reforms on June 19 to its current market-based rate (MBR) program for wholesale sales of electric energy, capacity, and ancillary services. Much of the wholesale electricity delivered on the U.S. interstate power grid—especially in the Commission’s organized market regions in the Northeast and California—is sold under MBR regulation, in which the terms and conditions of sale are typically FERC-regulated, but the selling parties are not themselves subject to traditional utility cost-of-service ratemaking or regulatory (non-GAAP) accounting.
The Commission’s main goal in issuing its notice of proposed rulemaking (NOPR) is to streamline the application process and increase the transparency of information submitted to the Commission as part of the MBR program. If adopted, the changes could reduce some administrative burdens on industry participants while still preserving FERC’s regulatory jurisdiction and capability to supervise the market conduct and eligibility of MBR sellers. Overall, the changes exempt some participants from certain filing requirements while imposing additional requirements on other participants with MBR authority.
On June 19, the Federal Energy Regulatory Commission (the Commission) issued Opinion No. 531, which affirmed in part and denied in part an initial decision on the return on equity (ROE) for the public utility transmission-owning members of ISO New England (ISO-NE). In addition, the Commission announced a modification to its policies regarding ROE calculation for electric utilities.
Opinion No. 531 tentatively determined that the “just and reasonable base ROE” for the ISO-NE transmission owners would be 10.57%, which is halfway between the midpoint and the maximum point of a “zone of reasonableness” based on a range of cost-of-equity estimates. The Commission determined that the base ROE should be set above the midpoint because of the unusual capital market conditions and other indicators, including a review of state-approved ROEs, which demonstrate that simply setting the base ROE at the midpoint of the zone of reasonableness would be insufficient to attract capital for new investment in transmission.
In a Notice of Proposed Rulemaking issued on June 19, FERC proposed to approve a new Reliability Standard—MOD-001-2 (Modeling, Data, and Analysis)—to govern the calculation of the various components of Available Transfer Capability (ATC), including Total Transfer Capability, Existing Transmission Commitments, Transmission Reliability Margin, and Capacity Benefit Margin. If approved, MOD-001-2 will replace multiple existing Reliability Standards that currently address these issues, including MOD-001-1a, MOD-004-1, MOD-008-1, MOD-028-2, MOD-029-1a, and MOD-030-2.
FERC has approved a new Reliability Standard to address Geomagnetic Disturbances (GMDs). EOP-010-1 (Geomagnetic Disturbance Operations) is the first in a set of Reliability Standards addressing the threat of GMDs to bulk-power system reliability. FERC’s concern with GMDs has been that they can create geomagnetically induced currents in transformers, which can, in turn, increase the absorption of reactive power, create harmonics, and cause transformer spot-heating. Ultimately, the loss of reactive power this causes could result in voltage instability, relay misoperations, and equipment damage.