Texas’ winter cold snaps and hot summer temperatures in 2011 triggered several years of debate on how best to guarantee long-term grid reliability, and decide whether to supplement Texas’ energy-only market with a forward capacity market. In 2014 Texas regulators decided against a standard forward capacity market for an energy-only market design with an operational reserve demand curve and a higher wholesale energy price cap of $9,000 per megawatt-hour (MWh). This decision has likely saved Texas consumers billions even as reliability improved, evidencing an energy transition driven by load reductions, significant increases in renewable generation, and cheap natural gas.
Utility regulation is getting harder. Before information technology’s rise combined with plummeting costs of energy efficiency and customer-sited generation, utilities had relatively few options for minimizing costs while achieving a balance of reliable, safe, and environmentally clean service. But distributed energy resources (DER) and better system awareness made possible by information technology have created massive new opportunities to optimize the system around these outcomes. If utilities are to serve as system optimizers, regulators must address the information asymmetry that strains cost-of-service prudency review to maximize the public interest.
Independent System Operators (ISO) like CAISO and PJM have empowered aggregators of distributed energy resources (DERs) to sell services into the transmission grid through market mechanisms recognizing their potential to create a more reliable, efficient, and clean grid. But since the flow of electrons between DERs and the transmission grid is mediated by distribution utilities, simply opening the door for DERs to join the party only goes so far – we still must identify and overcome challenges impeding progress at the interface between meters and transmission towers.
Change is constant for the electric utility industry and government regulators. New York State has been facing this change by “reforming the energy vision” (REV) – a far-reaching statewide energy policy initiative. As an administrative law judge for the New York Public Service Commission (PSC) from 1994-2014, and the project manager for REV in 2014-2015, I witnessed firsthand four elements contributing to its development and share them here to help others manage change.
Electricity from competitive wholesale power markets keeps the lights on for two-thirds of all Americans, but pressure is mounting to reform markets to match today’s energy system, and things may be about to change – for the better. Four factors will make 2016 a turning point for policymakers, clean energy providers, and wholesale market operators to work together and modernize America’s regulated wholesale power markets.
With the Paris talks just ending and policymakers thinking about how to meet national commitments, it is a useful time to review the current status of U.S. power sector emissions and energy trends shaping the next decade. The basic facts: according the U.S. Energy Information Agency (EIA), power sector emissions peaked in 2007 at 2,425 million metric tons (MMT) and dropped to 2,046 MMT in 2014 (see chart). This article describes the dynamics at play since 2007, and what the trends suggest about the future.
Market forces are precipitously changing the role of utilities. Private companies are offering customers more choices and control over their electricity through energy efficient products and services, demand management, self-generation like rooftop solar, smart electric vehicle chargers, and on-site storage. At the same time, the role of utility-scale wind and solar is growing, as costs have plummeted since 2010.
One year ago, the D.C. Circuit Court of Appeals decided to vacate FERC Order 745, holding that demand response could not be traded in wholesale energy markets. Since then, the ground has shifted, as demand response (DR) companies and large customers adjust to an uncertain future in which DR may be restricted to retail energy markets. Now that the Supreme Court has held oral arguments in the appeal of the case and a final resolution is imminent, we contemplate how DR will fare and how the market might evolve.
If Charles Dickens were an energy analyst, he’d probably say the past ten years have been the best of times and the worst of times for wind power in America. Most observers would guess we’re referring to the on-and-off nature of the federal Production Tax Credit (PTC) which has created a chaotic investment environment for wind project developers and financiers. Yet comparing the two regions with similar total installed wind capacity adds another twist to the story: the importance of good transmission planning.
This month the experts of America’s Power Plan released a new resource for policymakers and electric utility stakeholders as a part of our work under the Solar Electric Power Association’s (SEPA) 51st State Challenge. The new report begins to answer the question – “Who should own and operate distributed energy resources?” The report examines a series of case studies on different ownership models for distributed energy resources (DERs) with system optimization as the metric for success. It turns out that there are many options for who can own and operate DERs—and any of them can work, as long as the revenue streams (and revenue delivery mechanisms) are designed or adjusted appropriately.