Preparing for Automated Metering

Over the past year, technology advances and high energy prices have stimulated
interest in advanced metering infrastructure (AMI). Discussions are wide-ranging.
Some focus globally: Australian and Canadian “smart metering”; new European
Union requirements; the results of time-ofuse pilots that arose in the wake
of California’s deregulation debacle. Some discussions emphasize AMI benefits
– new products, “instant” outage detection, better load management. Others plunge
immediately into interval billing’s fine points: contracting, hedging and settlements.
Focusing utilities’ attention is the federal mandate that each state examine
the possible expansion of advanced metering within its borders.

Cost Focus

Midsize and smaller industrial and commercial firms are generally eager to
explore AMI benefits. Still, what this discussion lacks is a clear focus on
their primary concern: total energy cost. And despite relatively low U.S. energy
prices, when compared with prices worldwide, there is good reason for businesses’
cost concerns.

U.S. industrial firms spend an annual $53.6 billion on electricity[1] and another
$47 billion on natural gas.[2] Energy costs vary widely among specific industries
but typically comprise between 2 and 20 percent of the value of goods shipped.[3] In some industries, attempts to reduce energy intensity have been successful.
But not in all. The Industrial Energy Consumers of America, for instance, cite
energy as a major contributing factor to the loss of 2.8 million U.S. manufacturing
jobs since 2000.[4]

While costs per commercial company are generally lower, energy costs loom large
for the sector as a whole. U.S. companies, for instance, spend in excess of
$100 billion on electricity[5] and almost $30 billion on natural gas.[6]

Possibly even more significant is price creep. Over the five years from 1999
to 2004, industrial electricity prices per megawatt hour rose 19 percent, while
commercial prices rose 12 percent.[7] And that’s before exceptional price escalations
of 2005-2006 – especially for natural gas – initiated today’s energy-cost outcry.

Competition and AMI

In the 1990s, continuing concern about energy costs and competitiveness led
many commercial and industrial (C&I) energy users to support competitive energy
retail markets they believed could reduce prices. And even though competition
remains limited in most states, there have been positive effects:

• A recent report[8] credits competition for reducing the inflation-adjusted
  energy bills of most New York businesses, where competitive energy suppliers
  now service more than half of the commercial electricity load and more than
  75 percent of the industrial load;
• A 2005 report from the Associated Industries of Massachusetts (AIM)
  Foundation, for instance, credited competition, in combination with restructuring-related
  rate caps, for a seven-year total savings of $2 billion and projected ongoing
  annual savings of $350 million[9]; and
• While national averages can be no more than suggestive, given the
  difference in populations served, the U.S. Department of Energy shows energy-only
  suppliers as pricing commercial electricity at 6.58 cents per kilowatt hour,
  as opposed to full-service providers’ 7.91 cents.[10]

Few C&Is are as yet voicing such high hopes for advanced metering. In fact,
to some, AMI may look like a solution in search of a problem. Metering does
not address the high price of heating with natural gas, oil or propane. Time-shifting
of electricity use might work for businesses running multiple but changeable
shifts but it means nothing in the context of a retail store whose customers
are unlikely to shift their shopping to the pre-dawn hours. And when oligarchic
supply markets result in only the smallest of price spreads among suppliers,
even large businesses with dedicated energy managers cannot use hourly price
changes to significantly reduce costs.

In other words, AMI is not an automatic positive for the C&I customers often
seen as its primary supporters.

To improve the atmosphere for the discussion of possible metering changes,
utilities should examine the extent to which existing programs meet C&I customer
needs. Do existing utility programs maximize the customer benefits available
from whatever deregulation currently exists? Do customers understand their choices
among existing utility programs? Have utilities extended business programs to
all who might benefit, or are “special deals” available only to the largest
and most sophisticated industrials? Might existing or new services address the
unmet needs of a broader C&I audience? Answering those questions requires some
careful analysis and communication.

Step One: Analyze C&I Program Costs and Profits

AMI can, of course, be a win/win
proposition for utility and customer alike. But it is more likely to be accepted
as such if C&I customers already work with the utility in an atmosphere in which
their individual concerns are addressed.

Utilities have a long history, of course, in addressing the concerns of the
largest commercial and industrial customers. They frequently play a role in
regional economic development strategies that attempt to keep large local employers
in place and attract new ones. Discounts or special rates for large energy users
are common.

But the number of customers addressed with these special programs has, per
utility, typically been small. And utilities generally handle them as exceptions
to routine IT processes. To facilitate this “exception handling,” more than
half of all utilities – and more than 60 percent of electric utilities – use
key account programs that manage highly individualized billing approaches.

The key account approach is staff-intensive. That means high costs. Salary
and support for an account representative servicing a utility’s 30 largest customers
may be cost-effective when spread across revenues generated by those customers.
It becomes less and less so, however, when smaller C&Is are handled in the same
way.

How small do customers have to be before it becomes cost-ineffective to handle
them as key accounts? To answer that question, utilities need extensive analysis
of the profitability of individual C&I customers, profitability by type of service
and profitability by group. They need to identify usage patterns and chart consumption.

Step Two: View Customers’ Business Drivers

The data analysis in step one is far more useful in the context of customers’
business drivers and trends in their markets. Also important is to understand
changes in customer needs through time. As C&Is’ energy sophistication increases,
the utility/customer conversation is likely to become deeper and more complex.
Among the parameters likely to change are:

• Cost determinations. C&Is may initially be driven by cost per kilowatt
  hour. As they become more sophisticated, however, they will likely want to
  evaluate energy and related services as a single unit. They will also want
  to evaluate costs in terms of their own output – energy cost per car or per
  billable hour.
• Risk assessments. Many C&Is are risk-averse. They are willing to
  accept the costs of risk reduction. That is particularly evident in the interest
  in switching – where possible – to competitive suppliers.
  • Switching initially appeared risky to many C&Is. Many new suppliers
    offered contracts that might or might not prove less costly than their
    utilities’ supply. And the penalties some utilities placed on switching
    back, plus the uncertainties of dealing with the new competitive entities,
    added to that perception of risk.
  • Over time, acceptance of retail, energy-only suppliers is growing,
    albeit slowly. Of the 16.6 million commercial customers in 2004, only
    about 445,500 (2.7 percent, representing 11 percent of total commercial
    load) were being served by competitive suppliers. Similarly, only 13,800
    industrials (1.8 percent of the 747,600 U.S. industrials in 2004, for
    about 9 percent of total industrial load) used competitive suppliers.
  • Increasingly, C&Is will want to explore competitive supply. But that
    does not have to mean the loss of a customer. In fact, it can be a spur
    to the utility’s ability to sell new services. Utilities may offer market-rate
    contracts, for instance, in conjunction with hedging strategies tailored
    to the individual customer’s needs.
• Interest in demand reduction. C&Is avoid participation in demandside
  management programs when alternatives are too complex for facilities managers
  to readily evaluate. Utilities that need to expand demand response or load-shifting
  strategies with C&I customers may want to ease the burden by, for instance,
  providing basic demand-andload analysis without charge or by offering free
  consultations aimed at demand reduction.
• Investment in tools to manage the energy profile. Companies attuned
  to the energy marketplace are more likely to seek facilitymanager training,
  decision-support software, on-site or backup generation and outsourcing strategies.
  Ultimately, large users may find they need to analyze their own consumption
  data and develop “what if” scenarios that help them manage their businesses.

Step Three: Lessons From Europe

Predicting C&I enthusiasm for various program options is never easy. To improve
success, it is helpful to look at a market where utilities have already been
forced to respond more fully to C&I demands: the European Union (EU).

Currently, all EU industrial customers and some commercial customers may choose
among suppliers. It’s part of the overall market liberalization taking place
as the EU matures. Many C&Is have already exercised their right to switch. Many
more have renegotiated their utility contracts.

Typically, C&Is have represented the greater share of European utilities’ revenues
– 70 percent is not uncommon. In addition, service to C&Is has generally been
a higher-margin business for them than has mass-market retail. As a consequence,
European utilities have approached renegotiation carefully. Their aim has been
to:

• Optimize portfolios by balancing customers with sourcing. To do so,
  they have been forced to evaluate not only the profitability of individual
  customers to the utility but also the market drivers affecting that profitability.
• Structure contracts that best suit their purchasing capability. European
  utilities commonly offer incentives for long-term contracts, which offer their
  traders greater leverage in wholesale markets. And they have increased their
  monitoring of trends in their customers’ businesses so as to more accurately
  predict their demand.
• Segment customers. This helps differentiate the needs of groups and
  suggests the parameters of tailored contracts. Not every group wants quoting
  or risk management services. But some do.
• Identify commonalities among customers. It is important, for instance,
  to identify factors that result in losses. While European utilities generally
  retain an obligation to serve, they are not forced to do so at a loss. And
  they have every right to develop strategies that turn problem customers into
  assets.
• Understand customers’ views toward costs and services. Research by Datamonitor
  in the German market,[11] for instance, shows C&I customers have responded
  more favorably to complete solutions than to a price-focused, commodity-only
  view of the utility-client relationship.

Step Four: Address Billing

A number of utilities have as yet failed to provide C&I customers with relatively
simple billing options that can help them analyze their own consumption and
reduce their own costs. Among these options are:

• Consolidated billing. Companies with multiple sites may want one energy
  bill sent to a central financial office. They may also want copies sent to
  the sites. Or they may want sites to receive only their own consumption statistics.
  And that’s just the start. Some companies want each site to compare its consumption
  against company averages. Or a benchmark of similar businesses in a state.
  Some companies want tables. Some want graphs. The list goes on.
• Convergent billing, or billing for multiple services on a single bill.
  Here again, requests for different formats abound.
• Electronic bill presentment and payment. This lets businesses review and
  pay bills online. Large businesses may want raw data on CD so they can run
  their own comparisons.

Step Five: Outreach

As energy prices rise, an increasing number of companies find value in investing
in energy savings and energy “insurance” tools like price stabilization. Utilities
are likely to find increasing interest in such services as:

• Web-based energy audits tailored to types of installations – offices,
  factories, distribution centers. The Web and email are also valuable tools
  for ongoing help – from the “tip of the week” to fairly technical comparisons
  of office-cooling strategies.
• Special telephone numbers that connect to business-savvy service representatives.
  Staff in these specialized call centers generally require ready access to
  online help, including scripts and business process assistants that help with
  tough questions.
• Service and price guarantees tailored to the type of business. A
  retailer may need a guarantee during the holiday shopping season; a farmer
  may need one for the summer irrigation season.
• On-site energy audits. Possibly for a fee or for some percent of
  the savings generated.

• Cost management programs. A utility may, for instance, offer to share
  the savings from changes it would undertake to lighting or cooling.
• Energy-quality guarantees. These can be vital to computer-based businesses.
  And paying for power quality guarantees from the utility can be a welcome
  alternative when it reduces the need for backup power sources.
• Incentives for backup power supplies. Many utilities have demandresponse
  programs that offer incentives to businesses that agree to reduce or cut power
  use during times of tight supply or a distribution emergency. But not all.
  And not all businesses believe the incentives are adequate. Exploring ways
  to expand existing programs may generate new ideas. They may also convince
  skeptical businesses that current programs are justified and deserve support.
• Net metering. Do all businesses with backup power supplies have the
  opportunity to generate energy for the grid when utility supply runs short?
  Net metering is now a mandatory option in some states, and interest is growing.Special
  telephone numbers that connect to business-savvy service representatives.
  Staff in these specialized call centers generally require ready access to
  online help, including scripts and business process assistants that help with
  tough questions.

Preparing the Foundation for Tomorrow’s Discussions

Over the next decade, many utilities will want to implement at least some elements
of AMI. Support from C&I customers is likely to be essential in winning regulatory
consent.

Utilities will be best able to win that support by linking AMI to C&I concerns
about rising energy costs. But while those links exist, they may not carry the
day if C&Is are skeptical of utilities’ general commitments to meeting their
needs. C&Is are far more likely to support the AMI proposals of utilities that
have previously demonstrated that commitment by putting in place a variety of
cost-cutting services.

For utilities, then, one of the best ways to ensure support for AMI in the
future is to maximize the number and effectiveness of programs to help C&Is
cut costs today.

Endnotes

1. Electric Power Annual 2004, Energy Information Administration, U.S. Department
   of Energy, http://www.eia.doe.gov/cneaf/electricity/epa/ epa_sum.html.
2. http://tonto.eia.doe.gov/dnav/ng/hist/n3020us2A.htm and http://tonto.eia.doe.gov/dnav/ng/hist/n3035us3A.htm.
3. Bernard A. Gelb, Industrial Energy Intensiveness and Energy Costs in the
   Context of Climate Change Policy,” a CRS Report for Congress, November 21,
   1997, http://www.ncseonline.org/nle/crsreports/climate/clim-
   11.cfm?&CFID=9567575&CFTOKEN=6848150. See also figures from the Energy Information
   Administration, U.S. Department of Energy, at http://www.eia.doe.gov/emeu/mecs/mecs98/datatables/d98e7_2.htm.
4. http://www.ieca-us.com/downloads/natgas/$111bilion.doc.
5. Electric Power Annual 2004, Energy Information Administration, U.S. Department
   of Energy, http://www.eia.doe.gov/cneaf/electricity/epa/ epa_sum.html.
6. http://tonto.eia.doe.gov/dnav/ng/hist/n3020us2A.htm and http://tonto.eia.doe.gov/dnav/ng/hist/n3035us3A.htm.
7. Electric Power Annual 2004, Energy Information Administration, U.S. Department
   of Energy, http://www.eia.doe.gov/cneaf/electricity/epa/ epa_sum.html.
8. New York Public Service Commission Staff Report on the State of Competitive
   Energy Markets: Progress to Date and Future Opportunities. http://www.dps.state.ny.us/StaffReportCompetition.pdf.
9. Electric Industry Restructuring in Massachusetts: Progress in Achieving
   the Goals of the Restructuring Act, Associated Industries of Massachusetts
   Foundation, Inc., http://www.aimnet.org/AM/Template.cfm?Section= Home&TEMPLATE=/CM/ContentDisplay.cfm&CONTENTID=7783
10. The difference between energy-only and full-service providers for industrial
    electricity is less dramatic – 5.06 cents per kilowatt-hour for energyonly,
    against the full-service providers’ 5.10 cents.
11. “Competitor Tracking, Customer Acquisition in the German Major Power Users
    Sector,” Datamonitor, Issue 1.