How to develop balanced revenue-backed financing to manage the impacts of governmental mandates.
Severe upward pressure on electric rates after a decade of stability has regulators, legislators, utility executives, consumer advocates, and myriad other stakeholders searching for solutions. Revenue-backed financing can mitigate many of these mandate-driven rate increases significantly. These programs must, however, be designed to eliminate the inefficiencies and inequities that can be associated with revenue set-aside programs.
Intermittent and interruptible resources increasingly are being considered in regional resource adequacy calculations—but the approaches differ.
Lawrence Risman and Joan Ward
While both NERC and the NERC regional councils (known today as the Electric Reliability Organization) have standards and guidelines for resource adequacy and system reliability, much of the specificity as to how interruptible (e.g., demand-side) and intermittent resources (e.g., wind) are included is left up to the individual ISO/RTOs, states, provinces, etc. In fact, the various regions across North America each seem to have their own methodology for incorporating these resources into their resource adequacy and reserve-margin calculations. As the North American energy industry escalates its desire to reduce greenhouse-gas emissions through the expanded use of demand-side resources and intermittent renewables, the importance of this topic also will escalate.
Consultant Ed Krapels makes waves with undersea transmission.
“Make no small plans,” the saying goes, and consultant Ed Krapels has taken that to heart. Krapels' vision: Bring significant quantities of renewable energy south from Maine and the Canadian Maritimes, and inject that capacity directly into the congested downtown local grids of America’s large East Coast cities. Who could find fault with that?
A new set of skills and expertise will be necessary to deal with the risks created by new government mandates, new market developments, and new energy technologies.
Experts say a new set of skills and expertise will be necessary to manage the risk created by new government mandates, new market developments, and new energy technologies.
Using the past, present, and future to optimize our understanding of today’s energy markets.
By Andy Dunn
Price forecasting is a significant business process within any energy merchant that trades electricity and natural gas. Business planning, trading, mergers and acquisitions (M&A), even rate-case activities rely upon some type of a price forecast as the foundation to analysis.
The problem with a single forecast is that it never is correct. As soon as the forecast is complete, the world changes and the information becomes dated and often even irrelevant.
Electric shortages and the generation overbuild continue to co-exist.
While maintaining its stance as the most sophisticated competitive electricity market in the country, PJM still faces several challenges, all of which are augmented by its expanded footprint. Most prominent is the RTO’s plan to implement a new reliability pricing model. Further, parts of PJM are ailing from transmission congestion issues that limit access to abundant, cheap power sources in the region.
Sam Newell, Frank Felder, and Johannes Pfeifenberger
When summer heat waves cause electric demand to peak, they also often cause wholesale electricity prices to rise substantially above their average levels. However, since most electricity customers face retail rates that do not reflect this movement in wholesale market prices, they do not modify their consumption patterns, causing a significant drop in economic efficiency. The Energy Policy Act of 2005 calls upon states and utilities to evaluate and implement DR programs to mitigate this problem.
Everyone is in favor of more demand response, but little gets delivered when system operators need it the most.
Scott Neumann, Fereidoon Sioshansi, Ali Vojdani, and Gaymond Yee
Despite overwhelming theoretical and empirical evidence, we aren’t seeing more DR when it is needed most—during emergency periods. The reasons boil down to two obstacles, both of which must be addressed before widespread DR implementation can move forward.
Dominion and AEP want to put the toothpaste back in the tube, but re-regulation could get messy.
Richard Stavros, Executive Editor
Is it possible to go back to the way things were? Nostalgia for the old regulated model seems to be waxing of late, particularly in Virginia. The 70-percent rate increases in Maryland last year at the expiration of price caps—part of the transition to electric competition—has become the calamity that some state regulators fear most. Several utilities are pushing for re-regulation.
Does anyone care about rising redispatch costs?
Richard Lauckhart and Gary L. Hunt
Regional transmission organizations (RTOs) or independent system operators (ISOs) dominate the major power grids of North America, with the notable exceptions of the Southeast and Pacific Northwest. The purpose of this article is not to criticize system reliability but to highlight the more pervasive challenge today and for the future: Controlling the cost impact of decisions by grid operators on energy market participants.