[BETA] Fortnightly

State and federal incentives provide the carrot for utilities to invest in grid intelligence. But regulatory and technological incentives are not enough without customer participation. Smart-grid policies will succeed only by focusing on customer needs and benefits.

On Wednesday May 7, FERC will host a conference in Washington, D.C. that might prove extraordinary. The commission staff promises not only to review the forward capacity markets now operating in New England and PJM—each a story unto itself—but also to discuss a new rate-making theory that has come virtually out of nowhere and which proposes to help solve the notorious “missing money” problem.

Federal regulators have penalized wholesale energy market participants with fines ranging from $300 thousand to $300 million over the past two years. The magnitude of the penalties, along with uncertainty over how to effectively mitigate the risk of any civil action by regulators, has raised concern about how companies are approaching their regulatory obligations.

Late last year FERC learned that the Midwest regional grid likely would require at least 40 years — until 2050 — simply to clear its backlog of proposed gen projects awaiting a completed interconnection agreement to certify their compatibility with the interstate power grid. But grid engineers would meet that date only by shortening the process and studying multiple projects simultaneously in clusters. To apply the process literally, studying one project at a time, as envisioned by current rules, the Midwest reportedly would need 300-plus years to clear its project queue.

Electric utility executives generally view corporate restructuring as a potential source of economic value and a potential partial solution to financial problems that reflect changing business risks. On the other hand, regulatory commissioners attempt to insulate and regulate the utility component of the restructured energy business and to protect the public interest, including reliability of service at reasonable costs.

Liam Baker, vice president for regulatory affairs at US Power Generating, questions whether his company’s power plants and control systems in New York and Massachusetts must comply with the electric industry’s new mandatory standards for cyber security. Baker voiced his doubts in written comments he filed in October with FERC.

(November 2007) Fortnightly's annual rate-case analysis reveals a new trend at state PUCs involving return-on-equity rate allowances. Regulators increasingly are giving utilities an earnings incentive to pursue preferred investments.

About four months ago, at a conference at Stanford University’s Center for International Development, the economist and utility industry expert Frank Wolak turned heads with a not-so-new but very outrageous idea.

Federal Energy Regulatory Commission (FERC) has proposed to bring a modicum of federal oversight to the nation’s intrastate natural-gas pipelines. Given the historical structure and regulation of the nation’s natural-gas industry, it should come as no surprise that FERC’s proposal has polarized the industry in general and the state of Texas in particular.

Now at last, in a region other than California, we can see clearly that renewable mandates and fears of carbon taxes have influenced the power-plant development cycle. Moreover, this effect is helping to drive policy proposals for the pricing of transmission service and the recovery of costs for grid upgrades deemed necessary to bring the new plants on line.