Alignment of the business and the information technology (IT) functions within a company is critical to the effectiveness of any strategic initiative. Three years ago, our research identified a...
Don't Rush the Seamstress: Second Thoughts on the Marriage of the Northeast Grids
those demanding the electricity (the loads) or those owning the transmission lines. It uses a rigid unit commitment method, which originated in the regulated industry. Moreover, a closer look into the actual software shows that this computationally complex software is not useful for near real time decision making that turns units on or off. It does not optimize use of the transmission system during the commitment of generating units. Because it bundles together the ancillary services and reserve markets with the energy market and is too computationally complex to use in real time, the current platform (called MAPS) cannot differentiate value-offered-day-ahead from value-offered-in-near-real-time.
Furthermore, MAPS works with rigid reserve requirements, a relic of the old utility days. MAPS, moreover, does not capture the value of peaking technologies or of faster ramping rates. Nor does it offer quantifiable ways to value the willingness of customers to allow interruption of service or to shave peak demand. Any makeshift moves in this direction must end with the recognition that the amount of total reserve capacity is not related to what end users are willing to do when supply is short. This lack of sensitivity to the needs and desires of the ultimate customer could put an end to the development of a viable energy service provider industry.
Now let's move on to transmission constraints. The supposed model platform deals with them by a process of sub optimal unit commitment based on knowing the specifics of each given transmission system. In addition, the platform offers firm transmission rights (FTRs) as the means of hedging against volatile market conditions. The near-real-time Congestion Management System (CMS) has no protocols in place by which long-term FTRs would not be implemented in order to make way for more valuable spot market requests for transmission; this failure has a large impact on the revenue of the transmission provided, and also on the optimal use of overall transmission capacity available. The FTRs are rarely denied access except in case of emergencies. The transmission owner, of course, sees no income from the FTR.
Sweating the Deadline:
What Consolidation Means for Traders and Vendors
Interviews with software middlemen.
Partner, Utility Practice Group
Q: What sort of work have you been doing with RTOs [regional transmission organizations]?
Oliva: We've been working in four basic areas:  Business strategy,  market design and monitoring,  budgeting and program management, and  outsourcing of various financial back-office and settlement functions.
Q: What do you think about a forced marriage of RTOs in the Northeast and Southeast? Can they still meet the December deadline imposed by the FERC [Federal Energy Regulatory Commission] for RTO start-up?
Oliva: I seriously doubt that it [agreement on RTO structure] can be done now in 45 or 60 or even 90 days. I don't see why the FERC cannot extend the deadline. In fact, I think we may have lost ground in the short run, by forcing New England to halt its work on its proposed standard market design [SMD] and agree to mediation on the PJM version. There is