Midwest ISO

They call the United States the “Saudi Arabia of Wind.” That’s due in large part to the huge potential of the Great Plains. But there’s a hole in the metaphor. Wind power development in some parts of the prairie is falling short of expectations.

Quantifying the impacts of renewable portfolio standards (RPS) on utility integrated resource plans (IRP) sounds straight forward—just add more wind, solar, hydro, biomass, etc., to the plan and everything should be good to go. The reality is not quite so simple.

A massive T&D system build-out is starting, but more needs to be done. Executives from Northeast Utilities, Pepco Holdings and ITC Holdings discuss improvements needed for reliability, capacity, security, smart-grid and demand-response measures, as well as accommodating wind and green-energy quotas.

Dodging capacity payments might become an art form among load-serving entities and large electric consumers, as evidenced by Duquesne’s plan to exit PJM, as well as alternative market-designs proposed by large users. But such behaviors might only serve to disrupt organized markets and cause a return to full regulation.

In light of your prescient Frontlines column, “PURPA Redirected” (February 2008), I am curious of your insight. Is there a nexus between §571 of EISA and the demand response (DR) text in the pending FERC NOPR, RM07-19-000, “Wholesale Competition in Regions with Organized Electric Markets,” issued Feb. 22, 2008?

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.

You might have thought the Feds closed the book on any broad, region-wide sharing of sunk transmission costs—especially after FERC ruled last spring in Opinion No. 494 that PJM could stick with license-plate pricing (LPP) for transmission lines already planned and built. If you thought that, you weren’t alone. Of 25 transmission owners (TOs) in the Midwest ISO (MISO), 24 voted recently to do the same for their market as well.

The Northeast energy markets are working hard to establish new levels of regional coordination and cooperation. The region’s concerted effort is essential to resolving some of the industry’s toughest issues since the individual markets evolved. These issues include the elimination, reduction, or bridging of seams issues that prevent the economic transfer of capacity and energy between neighboring wholesale electricity markets, or control areas, as a result of incompatible market rules or designs.

A motley assortment of naysayers and recalcitrants continue to oppose competitive electricity markets around the world. But the alternative to markets is centralized command economics—a discredited concept that deserves to be consigned to the dustbin of history.

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.