News Digest
December
1, 2000
Grid
Management Charges. Faced with mounting complaints from customers
who are angry about having to pay for services they don't need, the California
ISO proposed a new grid management charge to recover its administrative
and operating costs. It would unbundle the new GMC into three "buckets,"
or service categories—(1) control area services and scheduling, (2)
interzonal scheduling (congestion management), and (3) market operations,
billing, and settlements—with each category using a different billing
determinant.
Charges for the
three service buckets would be determined, respectively, by (1) exports
and gross load within the ISO, (2) net scheduled interzonal flow per path
for a given scheduling coordinator, and (3) the ratio of any SC's total
purchases and sales of energy (auxiliary, imbalance, and supplemental)
to total purchases and sales by all SCs. FERC Docket No. ER01-313-000,
filed Nov. 1, 2000.
Software
Costs. The Federal Energy Regulatory Commission allowed the
PJM ISO to use its formula rates under its Open Access Transmission Tariff
to bill customers to collect $136 million in costs incurred to acquire
information technology and other assets from its transmission owners in
order to conduct ISO operations. Docket Nos. EL00-85-000, Oct. 25,
2000, 93 FERC ¶61,056.
Return
on Equity. Complaining of cost shifting and a "rapid-fire series
of seemingly never-ending pancaked rate increases," many players protested
Pacific Gas & Electric Co.'s fifth transmission rate increase filed within
a period of three-and-one-half years—a request that proposes a return
on equity of 12.8 percent and a revenue requirement of $396.2 million,
representing an increase of $57.1 million (or 16.8 percent) above the
level of the prior (fourth in a series) application.
As Sacramento
Municipal Utility District put it, "The transmission function seems to
be getting the brunt of cost impacts. ... Even though the ISO is now operating
PG&E's transmission system ... expenses are increasing dramatically. ...
The effects of inflation and necessary upgrades and replacements ... can
neither justify nor explain the large increases. ... As PG&E sells off
its generation, PG&E is proposing to shift many of the costs of generation
tie lines and generation step-up transformers to the transmission network
function."
SMUD questioned
PG&E's reliance on natural gas companies as a proxy group for a transmission
sector ROE, adding that "PG&E is also using its [grid] facilities for
purposes other than electric service, such as telecommunications services."
SMUD joined other parties complaining of allegedly unsupported costs,
including the Modesto Irrigation District, the Transmission Agency of
Northern California, and the California PUC, which complained that the
proposed 12.8 percent ROE was "much higher" than the 11.22 percent rate
the PUC OK'd on June 8 in PG&E's rate case for retail wires services.
Also protesting
the application was Southern California Edison, which said its own wheeling
revenues would be affected by the rate methods chosen by PG&E. Edison
complained that PG&E's regional/local allocation method was inconsistent
with the high/low voltage allocation method proposed by the ISO in its
tariff amendment 27. It alleged that PG&E's method would allow it to "continue
to collect an inequitable share of wheeling revenues, to the detriment
of other transmission owners" participating in the ISO. FERC Docket
No. ER01-66-000, protests filed Oct. 27, 2000.
Innovative
Ratemaking. Led by Michigan Attorney General Jennifer Granholm,
a host of electric industry players urged the FERC to rehear and overturn
its Sept. 28 order allowing International Transmission Co., formed by
DTE, parent company of Detroit Edison, to charge transmission rates derived
from the transmission component of bundled retail rates set for Detroit
Edison by the Michigan Public Service Commission.
Dynegy, ELCON,
and the advocacy group ABATE (Association of Businesses Advocating Tariff
Equity) all complained that the FERC should not use its Order 2000 to
justify innovative rate treatment for a "transco" like ITC that would
not qualify as an RTO.
Attorney Sara
Schotland, representing ELCON, complained that, "once again, FERC's 'beg-and-plead'
approach to RTO formation leads it to award excessive and inappropriate
incentives." According to Granholm, "the incentives ... are unnecessary
and ... will discourage the entrance of new competitors in Midwest power
markets." FERC Docket No. ER00-3295-000, protests filed Oct. 30, 2000.
Congestion
Contracts. Morgan Stanley Capital Group lost its bid to postpone
the New York ISO's planned auction of two- and five-year transmission
congestion contracts until the ISO irons out market irregularities to
give traders a better inkling of the real value of grid congestion. The
FERC countered that TCCs were still valuable in hedging against congestion
costs despite uncertainties caused by market disruptions. Docket No.
EL00-103-000, Oct. 25, 2000, 93 FERC 61,058.
Midwest
ISO Convulsions. The Midwest ISO announced on Nov. 3 that it
had assumed management responsibility for operations of the Mid-America
Interconnected Network, but prior weeks were marked with uncertainty,
as Midwest ISO CEO Matthew Cordaro acknowledged on Oct. 31 that Commonwealth
Edison intended to withdraw from the group and instead join the Alliance
RTO, while Dynegy had announced a similar intention on Oct. 13 on behalf
of subsidiary Illinois Power.
Com Ed senior
vice president Elizabeth Moler said Alliance made more sense for her company,
since more of Com Ed's business would lie in the Eastern U.S. after the
merger with PECO Energy (to form Exelon Corp.)
Dynegy explained
its strategy in a letter sent to the FERC:
"One advantage
is that the Alliance RTO will put all similarly situated transmission
users on the same tariff at the same rate at RTO inception ... all users
that deliver energy to the Alliance RTO facilities at a common input point
and [that] receive energy back at a second, common removal point will
pay one uniform rate for that service. ... In contrast, the Midwest ISO
will take at least six years for the transition to a single rate for a
single transaction for all users." FERC Docket No. ER01-123-000, filed
Oct. 13, 2000.
OASIS
Standards. The FERC revised its business practice standards
for transactions conducted over its Open-Access Same-Time Information
System for reserving transmission service. Docket No. RM95-9-013, Oct.
26, 2000, 93 FERC 61,078.
Interregional
Coordination. Electric utilities, state regulators, ISOs, consumer
advocates, and even a smattering of power producers and marketers overwhelmingly
oppose a complaint filed in early October by Morgan Stanley Capital Group
that asked the FERC to equalize certain rules in the PJM ISO with those
expected to apply in the New York ISO and ISO New England—all in
the name of interregional coordination.
In particular,
MSCG asked the FERC to terminate PJM's installed capacity market (ICAP)
and associated deficiency charge to match the same step taken in ISO New
England, and also to ensure that PJM's permanent bid cap of $1,000 per
megawatt-hour (which has applied in the PJM ISO since its formation) will
sunset simultaneously with the expected termination of price caps of the
same amount in the New York and New England ISOs.
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Abolishing
ICAP Markets. Morgan Stanley had urged the FERC to follow the
lead of New England in abolishing ICAP markets and deficiency charges
throughout the Northeast, citing studies submitted by economists (such
as William Hogan of Harvard Univ.) that ICAP markets are "valueless"
and that capacity deficiency charges ought to be set at zero. (Pending
the adoption of a new structure to replace its ICAP market, ISO-NE
has proposed a deficiency charge of 17 cents per kilowatt-month as
a transition measure, but PJM still retains a stiffer deficiency charge
of $54.40 per kilowatt-year.)
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Coordinating
Price Caps. MSCG also urged the FERC to coordinate bid-cap policies
among regions so that power producers, marketers, buyers, and sellers
are not tempted to game markets by selling in one region to avoid
a price cap in another. Nevertheless, by early November, Morgan Stanley
appeared to have won support for its request only from Williams Energy
and the Mid-Atlantic Power Supply Association. Nearly all other responding
parties have opposed the request, including state PUCs from Pennsylvania
and Maryland, the staff of the Virginia commission, plus consumer
advocates from Pennsylvania, Delaware, Maryland, and New Jersey.
- Stressing Reliability.
Denise Goulet, the senior assistant consumer advocate from Pennsylvania,
acknowledged that the PJM ICAP market was in need of review and reform,
but warned against eliminating the requirement without another structure
to ensure reliability and generation adequacy. She added that PJM already
was considering alternative plans through its Future Adequacy Working
Group, or FAWG.
- Defending ISO Independence.
The PJM and New York ISOs both suggested that each region should map
its own course. New York said that it "strongly disagreed" with New
England's position that ICAP markets and deficiency charges are "inherently
unworkable and anachronistic." It said its own ICAP market rules "should
be preserved and ISO-NE and PJM should be free to make their own decisions."
- Warning of Disruptions.
PJM asked the FERC to dismiss the complaint absent any evidence specific
to the PJM that its ICAP market wasn't working: "PJM should not be forced
to eliminate its ICAP rules simply because ISO New England has chosen
to do so, just as ISO-NE should not be forced to retain its ICAP market
because the New York ISO intends to keep its own." PJM argued that if
it terminated its ICAP market, it actually would make regional differences
greater, since New York had not shown a similar intent. "Adoption of
Morgan Stanley's complaint," said PJM, "would create a PJM/NY seams
issue where none now exists." FERC Docket No. EL01-3, protests filed
Oct. 26, 2000.
New
York Locational Reserves. The New York ISO announced "significant"
reductions in locational reserve requirements for the eastern and Long
Island sectors for 30-minute reserves and 10-minute spinning and nonspinning
reserves, so as to allow western energy suppliers to participate more
fully in wholesale power markets in the state, and to allow it to lift
interim bid caps imposed on suppliers in reserve markets. FERC Docket
No. ER00-3591-002, filed Nov. 1, 2000.
PJM
Transmission Rights. The PJM Interconnection filed amendments
to its Open Access Transmission Tariff to provide for a reallocation of
fixed transmission rights (on the basis of load) among network transmission
customers on an annual basis, to replace the prior procedure whereby network
customers received a one-time allocation and could then retain FTRs in
perpetuity, so long as they retained enough load. PJM's Energy Market
Committee had recommended an annual reallocation because of "significant
fluctuations in load" occurring among load-serving entities, due to retail
choice in the PJM region. FERC Docket No. ER01-210-000, filed Oct.
24, 2000.
Revenue
Assessments. The FERC announced a new method to assess annual
charges against electric utilities to fund its activities, based only
on the volume of electricity transmitted, rather than both transmission
and volume of wholesales, as before. Docket No. RM00-7-000, Order No.
641, Oct. 26, 2000, 93 FERC 61,083.
Mountain
West Funding. The Nevada PUC denied a request by the Mountain
West Independent System Administrator to set up a method for electric
utilities to fund startup and operating costs and for the ISA through
a surcharge on distribution rates, explaining that state law requires
utilities to submit such a request. It also questioned whether state regulators
should guarantee recovery of costs for transmission functions subject
to federal jurisdiction. Docket No. 00-2017, Sept. 28, 2000 (Nev.P.U.C.).
Interconnection Standards. Virginia Power filed amendments
to its Open Access Transmission Tariff to include procedures for dealing with
requests to interconnect new generating plants with the utility's transmission
system, and to allow for recovery of costs from interconnection applicants
in a manner that the FERC rejected in a similar case involving Carolina Power
& Light Co.
Virginia Power's
standards require the interconnection customer to pay the entire cost
of any required evaluation study and facilities study, including costs
related to a change in configuration or operation of adjacent transmission
systems--a cost allowance that the FERC had rejected for CP&L.
Virginia Power
argued that changes on adjacent systems (including interconnection queues)
would affect power flows and congestion on its own system. It reasoned
that the FERC had denied such costs in the prior case only because CP&L
had failed to offer supporting evidence. FERC Docket No. ER01-247-000,
filed Oct. 27, 2000.
Station
Power Requirements. Citing doubts about whether the proposal
was just and reasonable, the FERC accepted and suspended tariffs filed
by the PJM ISO that would allow power producers the option of purchasing
station power requirements (energy consumed on-site by generating plants)
either at retail from utilities or at wholesale from the PJM Interchange
Energy Market. Docket No. ER00-3513-000, Oct. 25, 2000, 93 FERC ¶61,061.
Power Markets
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California
Price Caps. Though it declined to order retroactive refunds
of excessive wholesale power costs, the FERC proposed a new "soft"
price cap of $150 per megawatt-hour for the next two years in wholesale
power markets operated by the California Independent System Operator
and Power Exchange, whereby any suppliers bidding $150 per megawatt-hour
or less may receive the market-clearing price, but those bidding
more must take a price equal to their bids and file detailed information
with the FERC to explain and justify their higher requests.
The FERC also proposed
other remedies to correct California's power markets, which it described
as not workably competitive:
- Buy/Sell Rule.
Release the state's three major investor-owned utilities from
obligations imposed under state law to sell into and buy only
from the California PX, encouraging them to rely more on bilateral
trading and forward markets.
- Penalty Charges.
Impose a penalty charge for under- or overscheduling of load
in excess of 5 percent of hourly requirements.
- ISO Governance.
Remake the membership structure of the ISO board from the ground
up, along guidelines provided by the FERC.
- Plant Interconnections.
Require the ISO to draw up a tariff governing interconnections
of new power plants with the transmission grid.
Commissioner Massey concurred,
but he questioned the $150 figure for the soft price cap, saying
that changes in natural gas prices might justify a lower ceiling.
Commissioner Hébert also concurred, but said he would rather just
abolish the single-price auction altogether, and criticized the
commission for imposing any particular organization on the ISO Board,
warning of a needless constitutional showdown. Docket Nos. EL00-95-000,
Nov. 1, 2000, 93 FERC 61,121.
Pacific
Northwest Price Caps. Taking a page from California,
Puget Sound Energy asked the FERC to set a cap on prices for electric
energy or capacity sold at wholesale into the Pacific Northwest
at a level identical to any price cap it might approve in California
markets, arguing that the two regions each are part of the "substantially
integrated wholesale power market" consisting of the entire Western
Interconnection.
PSE added that any one-way
price cap in California markets would be "fundamentally unfair,"
as it would expose wholesale purchasers in the Pacific Northwest
(such as PSE) to uncapped prices when they need power to meet winter
demand, but yet "hobble" their ability to offset the costs of such
purchases with uncapped prices when they have surplus power to sell
to California, such as during periods favorable to hydroelectric
generation. FERC Docket No. EL01-10, filed Oct. 26, 2000.
New
York Price Caps. Citing delays in developing a new "market
protective mechanism," which would trigger "circuit breakers" in
the event of market disruptions, the New York ISO asked the FERC
to extend the life of its current bid cap of $1,000 per megawatt-hour
through the winter until April 30, otherwise set to expire on Nov.
1.
The ISO described the
price cap as "a blunt instrument" with "undesirable consequences,"
but stressed that caps were needed to counteract market imbalances
that it said were caused by delays in licensing and siting of much
needed new generating facilities.
"Our staff estimates
that there are 74 [generating] projects indicating a desire to build
in New York [but] only one of these (Athens) is likely to be complete
during the next three to four years. This situation is an invitation
both to severe reliability problems and to price disruptions. ...
It is unacceptable." FERC Docket Nos. ER01-180-000, ER01-181-000,
filed Oct. 20, 2000.
Functional
Separation. California Power Exchange president George
Sladoje wrote to FERC chairman James Hoecker to offer several reasons
why the PX should not combine with the state's Independent System
Operator, after Hoecker had asked for comment on the idea at the
public hearing on California power markets held in San Diego on
Sept. 12.
Claiming the PX-ISO schism
had nothing to do with market disruptions, Sladoje argued that the
PX actually had developed a greater variety of liquid trading products
than ISO-operated energy markets in Eastern states.
"The CalPX ... has created
numerous exchange services that are not available in PJM or in the
other eastern ISOs," said Sladoje. "ISO-operated energy markets
are largely self-contained within the 'four walls' of that ISO's
control area," he added, while "Cal PX, in contrast, has ventured
beyond the boundaries of the ISO-operated grid [to] the broader
market represented by the Western Systems Coordinating Council."
And Sladoje defended
the PX as gentle on power prices: "California's wholesale prices
were somewhat lower than those in the Pacific Northwest and the
Inland Southwest in May through August." FERC Docket Nos. EL00-95-000,
filed Oct. 20, 2000.
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Post-transition
Ratemaking. Claiming that "electric restructuring in California
is at a crossroads," Southern California Edison urged the state PUC, in
its investigation of post-transition ratemaking mechanisms for the state's
three investor-owned electric utilities, to adopt a four-point plan to
manage the crisis:
- Continued market reform
with greater freedom for utilities;
- Confirmation that utilities
eventually will be permitted to recover their "reasonable" energy procurement
costs incurred on behalf of customers;
- A new, post-freeze rate
stabilization plan to replace the current immediate passthrough of volatile
wholesale power costs to utility generation customers; and
- A prompt final decision
on whether the PUC will permit the utilities to sell off their remaining
generation assets.
Said Edison, "Allowing the
uncollected power costs to continue to grow without providing assurance
of their probably ultimate recovery--and without actually commencing the
process of that recovery--will almost inevitably lead to serious statewide
consequences, including the probability that financially weakened utilities
will not be able to build and modernize necessary infrastructure [or]
contract for power." Application Nos. 99-01-016 et al., filed Oct.
25, 2000 (Cal.P.U.C.).
Standard
Offer Re-enlistment. As an emergency measure, the Maine PUC
re-instated a rule requiring electric customers to pay an opt-out fee
or commit to receive 12 months of service on quitting a competitive energy
supplier and returning to standard offer retail service.
The PUC earlier had relaxed
the rule for service changes requested outside the summer months, but
reneged on discovering it had weakened the deterrent effect of the opt-out
fee, calling the prior decision an "inadvertent error." Docket No.
2000-890, Nov. 3, 2000 (Me.P.U.C.).
Retail
Gas Choice. Michigan allowed Consumers Energy Co. to double
and then triple the number of customers eligible for its voluntary program
for retail gas choice, from 300,000 accounts to 600,000 in April 2001,
and then 900,000 by April 2002. Case No. U-12680, Oct. 24, 2000 (Mich.P.S.C.).
Electric
Bill Formats. Ohio issued rules governing bill formats for
electric utilities, for both customers taking standard offer service and
for those who shop for alternative supply services, setting out rules
for unbundling separate prices for generation, delivery, and customer
account charges, plus any added discounts above a generation back-out
credit designed as an incentive to encourage customers to switch suppliers.
Case Nos. 00-1596-EL-UNC, 00-1998-EL-UNC, Oct. 26, 2000 (Ohio P.U.C.).
Winter
Gas Rate Relief. New York OK'd a natural gas rate settlement
for National Fuel Gas Corp. designed to offset anticipated higher-than-usual
gas commodity costs for the winter heating season.
The settlement extends a $10
million aggregate rate credit to ratepayers and modifies the current program
for sharing excess earnings with customers (on a 50-50 basis) by cutting
the benchmark rate return on equity from 12 percent to 11.5 percent. Case
00-G-1495, Oct. 23, 2000 (N.Y.P.S.C.).
Vertical
Disaggregation. Virginia regulators adopted rules governing
the functional separation of generation, transmission and distribution
services provided by electric utilities.
In so doing, it denied arguments
by Virginia Power that once a utility divests all generation, the commission
then loses authority to regulate purchased power costs passed through
to retail distribution customers, since such default service functions
merely as an assurance of available generating capacity, which is deregulated.
Case No. PUA000029, Oct. 19, 2000 (Va.S.C.C.).
Rate
Freeze Legislation. Michigan ruled that the rate freeze imposed
under the state's electric restructuring legislation does not bar the
state's electric utilities from boosting rates to recover costs incurred
to pay avoided cost rates to qualifying cogeneration facilities for purchased
power. Case No. U-12464, Oct. 6, 2000 (Mich.P.S.C.).
Return
on Equity. Marking a break from past practice, Kentucky set
rates reflecting return on equity measured against the utility's financial
statement capitalization, rather than an original cost rate base. It called
capitalization a "better measure of the real cost of providing service,"
especially where rate base exceeds capitalization, indicating that sources
other than debt are available to finance assets. Case No. 2000-080,
Sept. 29, 2000 (Ky.P.S.C.).
News Digest was compiled
by Carl J. Levesque, associate editor, Lori Burkhart and Phillip Cross,
contributing legal editors, and Bruce W. Radford, editor-in-chief. For
more frequent updates, see www.pur.com.
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