[Matt Lecar][September 27, 2006]In previous columns, I’ve talked about the challenges of utility innovation and the difficulty of guiding a new technology from pilot to implementation.  No technology better demonstrates that tortuous path than advanced metering infrastructure (AMI). 

The good news: recent changes in regulation, combined with declining costs and enhanced features have dramatically improved the AMI business case.  With the recent approval of PG&E’s $2.2B, 9M meter (gas and electric) rollout, the stage is set for the largest AMI deployment in U.S. history.  GlobalSmartEnergy believes the tipping point has arrived.  It is a good time to look back and see how we got here (and why it’s taken so long).

The pain free (and progress free) past
I worked at PG&E in the mid- 90’s through 2000 and participated in the review of what was then called Automated Meter Reading (AMR).  A large, cross-functional committee of “stakeholder” departments (meter reading, meter operations, gas field services, billing, call centers, account services, rates, and new products) would convene every six months to update the business case.  Because meter data are core to almost all customer-facing activities, a change in technology impacts hundreds of internal processes and thousands of employees.

Although the “hard" benefits– primarily avoided manual meter reading costs– were easy to quantify, they only paid back about half the cost.  Meanwhile, the “soft" benefits (remote disconnects, better outage detection, fewer estimated bills, new rates and customer services) generally got little weight. Internal departments would not risk budget cuts to put a dollar value on unproven process improvements; there was no obvious “pain” from business-as-usual. 

As a result, AMR went nowhere.

California's energy ailment
What's changed?
  During the 90’s, many utilities deployed advanced metering selectively, with large commercial and industrial customers, load research samples, remote or hard-to-read meters, and, in a few cases, mass market customers.  The “soft” benefits firmed up, as folks learned from real world experience. 

Then, the California energy crisis hit.  By 2003, the dust had settled and a new policy consensus emerged in favor of Time of Use (TOU) pricing and demand response, for which AMI is a necessary platform.  The California PUC ordered the state’s three big utilities to develop detailed plans to implement AMI.  PG&E’s is the first to be reviewed and approved; revised plans are due from SCE and San Diego later this year.

How pain made AMI healthier
I recently presented at Spintelligent’s Smart Metering West Coast conference, where I caught up with Jana Corey, Project Manager for PG&E’s AMI deployment.

In PG&E’s new business case, approximately 90% of the cost of AMI is offset by utility operational savings of $160M  a year (the remaining 10% is expected to come from the reliability benefits of demand response).  And of those “hard” savings, a little over half ($86M) is in meter reading.

So, what’s the rest?  Remote disconnect, quicker outage restoration, reduced estimated billing, lower call center costs related to billing complaints, more efficient system capacity planning and dispatching.  We've finally put hard dollar values on the same soft benefits from the business cases of the 90’s.  As Jana explained, department heads were forced to “sign in blood” that their organizations would achieve the benefits in the plan. 

The lesson for innovators is this: nothing breaks down institutional barriers like real business pain.  When that pain includes a $20B market meltdown, months of rolling blackouts, and a major utility bankruptcy, you may be surprised how quickly an organization can change!