News Digest
July 1, 2000
Regionwide Pricing. The
Federal Energy Regulatory Commission suspended the California ISO's proposed
Tariff Amendment No. 27 and set it for an evidentiary hearing, finding
some aspects "encouraging" (helping to expand ISO membership among municipal
utilities), but on the whole deciding that the ISO had not demonstrated
its proposal to be just and reasonable, and that in fact the new tariff
"may be Š unduly discriminatory or preferential."
Amendment 27 would completely
revamp the ISO's grid access charge over a 10-year transition period in
an effort to attract new ISO members from municipal utilities and other
government-owned utilities (GOUs) such as the Los Angeles Department of
Water & Power and the Sacramento Public Utility District.
In particular, Amendment 27
would change pricing from a "license-plate" model (which recovers utility
costs specific to their individual service territories) to a two-tiered
model, with access prices for higher-voltage long-distance lines reflecting
an average of costs across the entire ISO system (postage-stamp rate).
During the transition, the ISO essentially would charge three distinct
postage-stamp transmission access charges (TACs)-one for each of three
TAC zones corresponding to each of the three control areas that were combined
initially to form the ISO control area.
Nevertheless, the municipal
and government-owned utilities oppose the proposal nearly unanimously,
arguing that various "hold harmless" provisions (including cost caps for
current participants) applicable during the 10-year transition will increase
their costs. Sempra Energy opposes the move entirely, and Enron objects
to certain aspects as well. (See News Digest, June 1, 2000, p. 22,
and "L.A. vs. The ISO," May 15, 2000, p. 4.)
In its order, the FERC said
it could not yet determine whether the transition cost caps were fair,
and said the ISO's proposed plan for setting GOU grid revenue requirements
without final FERC review likely would run afoul of federal statutes.
It encouraged a settlement and asked a settlement judge to report back
to the FERC in 120 days. Docket No. ER00-2019-000, draft order issued
May 31, 2000 (F.E.R.C.).
Resource Dispatch. The
California ISO announced that effective June 1, it was putting into effect
its new computerized Automated Dispatching System, designed to improve
the market for ancillary services by automating the communication of dispatch
instructions to scheduling coordinators acting on behalf of suppliers
of imbalance energy. FERC Docket ER99-1971-007, filed May 19, 2000.
Michigan Transco. In a move
that opens many options, such as joining the proposed Alliance regional
transmission organization (RTO) or just complying with FERC Order 2000,
DTE Energy filed plans with the FERC to divest its 6,000-plus miles of
transmission lines (120-345 kilovolts) to a new stand-alone subsidiary
to be named the International Transmission Co.
ITC then would supply transmission
and ancillary services to DTE subsidiary Detroit Edison and other grid
customers under the same rates, terms, and conditions as described in
Edison's filed tariffs for open-access, network, and point-to-point transmission,
regardless of whether ITC eventually joins the Alliance group or any other
RTO.
The application notes that
Detroit Edison would make a "complete exit from the transmission business,"
becoming a hybrid that would function "solely as a generation and distribution
company." It says the full plan could include (1) a spin-off of ITC shares
to DTE stockholders, (2) an initial public or private offering of new
ITC stock, or (3) a business combination with other unaffiliated third
parties. DTE added that it would capitalize ITC at the current depreciated
net book value of the transferred grid assets, estimated at about $400
million as of year-end 1999. FERC Docket EC00-86-000, filed May 4, 2000.
Capacity Hoarding. In
granting authority to a DTE subsidiary to sell power at market-based rates
from the soon-to-be refurbished River Rouge power plant, the FERC rejected
claims that Detroit Edison had blocked power imports from Ontario Hydro
and monopolized access to Michigan's transmission grid by hoarding firm
import capacity for the peak summer months. It said that Edison would
need all the capacity it had reserved. Docket No. ER00-1816-000, 91
FERC ¶61,139, May 17, 2000 (F.E.R.C.).
Midwest ISO Membership.
Upper Peninsula Power Co. and Wisconsin Public Service Corp. applied
to the FERC to cede operational control of their transmission assets to
the Midwest Independent Transmission System Operator Inc., as part of
their proposal to join the Midwest ISO by the end of June. FERC Docket
EC00-84, filed April 28, 2000.
Pancaking and Refunds. In
April, the FERC OK'd a new regional open access transmission tariff for
the Mid-Continent Area Power Pool (MAPP), but only after modifying the
proposal to reform a two-part rate scheme deemed unacceptable because
it would create unwanted rate pancaking.
And in May, in a separate case,
the FERC denied MAPP's request for an extension of time to pay refunds
from overcharges under a similar but different two-part transmission pricing
scheme that the FERC had struck down in 1999 in granting a complaint by
Enron Power Marketing. It ruled that MAPP members collectively must refund
all excess charges from the illegal tariff, even though some members that
owed a share of refunds (e.g., the Nebraska Public Power District) might
lie outside of FERC jurisdiction.
The latest two-part MAPP tariff
(at issue in the April case) had featured (1) a regional megawatt-mile
charge for firm and non-firm point-to-point transmission service, based
on point of receipt and point of delivery, plus (2) a special "home zone"
charge, applicable only when the resource and load for a particular point-to-point
transaction were located within the service territory of a single transmission-owning
MAPP-member utility, and billed under the open-access tariff of that utility.
MAPP had claimed that the two-part
tariff was needed to avoid cost shifting and reach consensus among members,
but the FERC said the tariff contributed to rate pancaking for transactions
spanning multiple zones, in effect granting a preference for transactions
completed within a single "home zone" by vertically integrated utilities,
such as utility native load. Docket No. ER99-3318-000, 91 FERC ¶61,065,
April 14, 2000 (accepting tariff as modified), and Nos. OA97-163-000,
OA97-658-000, 91 FERC ¶61,163 May 19, 2000 (mandating refunds and denying
request for stay).
Pacific Northwest RTO. Six
Western utilities on May 2 announced plans to study formation of a for-profit
independent transmission company that subsequently would join RTO West,
a new nonprofit ISO. The six utilities are Avista Corp., Montana Power,
Puget Sound Energy, Portland General Electric, Nevada Power, and Sierra
Pacific Power. The group has published an extensive library of documents
with ideas on services, tariffs, congestion management, and other issues.
See http://redlandlab.com.
Electric Reliability
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Ancillary Services.
In an effort to attract more demand-side bids to its markets for
ancillary services and imbalance energy to aid reliability criteria,
the California ISO initiated a trial "Demand Relief Program" for
the summer, soliciting voluntary curtailment bids to trim 1000 MW
in net cumulative demand between June 15 and Oct. 15. It also proposed
new Tariff Amendment No. 28, governing recovery of costs incurred
by the ISO for the program. FERC Docket No. ER00-2208-000, filed
April 14, 2000.
At the same time, to
encourage supply-side bids for ancillary services, the ISO has asked
the FERC to approve new Participating Load Agreements issued to
NewEnergy California LLC, New West Energy, and the Ancillary Service
Coalition. FERC Docket Nos. ER00-2581-000, ER00-2582-000, ER00-2583-000,
filed May 24, 2000.
Nevertheless, the demand-side
program drew protests from municipal utilities, including Los Angeles
and the Sacramento Municipal Utility District (SMUD), which argued
that they had already ensured the reliability of their own systems
and should not have to pay to aid others that had not.
In particular, SMUD described
the ISO's bid to spread costs throughout the system as a "peanut
butter approach." But it said it would not oppose Amendment 28,
due to the critical need for resources in California this summer.
Docket No. ER00-2208, protests filed May 5, 2000.
Contractual Provisions.
Choosing not to wait for federal legislation or a formal reorganization
of the North American Reliability Council (NERC), Montana Power
Co. (as transmission operator) and PPL Montana LLC (a local power
producer) signed and submitted to the FERC their own private contract
governing electric system reliability.
The contract sets out
terms and conditions by which each will agree to comply with directives
of the Western Systems Coordinating Council (a NERC regional reliability
council) and to be subject to sanctions enforced by WSCC. FERC Docket
ER00-2591-000, filed May 23, 2000.
Outage Response.
The New Jersey board ordered Conectiv, Public Service Electric &
Gas Co., Rockland Electric Co., and Jersey Central Power & Light
(doing business as GPU Energy) to implement recommendations set
out in a staff report on outages during July 1999.
The board told the utilities
to implement a fully integrated system to assess outages, comprised
of a software-driven management system, a geographic information
system, and a supervisory control and data acquisition (SCADA) system.
According to the report,
the utilities had trouble pinpointing the location of outages: "While
the utilities weren't dealing with a storm that needed damage assessment
in the July event, it still became apparent that the utilities,
to varying degrees, were unable to accurately identify where the
outages were occurring and who would be affected by the rolling
blackouts," the staff report said.
The board ordered Conectiv,
Rockland, and PSE&G to "substantially implement" their enhanced
systems by Dec. 31. Each utility must report to staff every 90 days
on the status of the new systems. Docket No. EX99100763, April
28, 2000 (N.J.B.P.U.).
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State PUCs
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California's
PX: Monopoly No
More
Yet the PUC would
require a "market-clearing algorithm"-a feature opposed earlier
by rival APX.
By
Bruce W. Radford and Richard Stavros
On June 8, California
regulators released the state's investor-owned electric utilities
(IOUs) from the duty to purchase power only from the California
Power Exchange.
Commissioners Josiah
Neeper and Richard A. Bilas had proposed the new policy in their
alternate proposed decision filed in May. Then, with a third "swing"
vote from commissioner Henry M. Duque, the proposal became law.
Together the three regulators believed that California's competitive
electricity commodity market was far enough along to lift the mandatory
"buy requirement." Application 99-01-016 (Cal.P.U.C.).
As a result of the PUC
decision, IOUs will be able to buy power from what regulators have
deemed a "qualified exchange." But just what is a "qualified exchange"
and will independent exchanges wanting to do business in California
measure up?
According to the draft
PUC decision, a "qualified" exchange must offer: 1) non-discriminatory
access 2) anonymous price transparency 3) audit and record verification,
4) a compliance unit, and 5) a "market-clearing price algorithm."
These criteria were loosely based on a proposal filed earlier by
the California Energy Commission.
Edward Cazalet, chairman
and chief executive officer at Automated Power Exchange, a rival
of the Cal PX, says he has no problem with the new criteria and
is looking forward to competing for the sum 80 percent volume that
the three IOUs make up.
But it should be noted
that earlier, when it filed comments on the Energy Commission's
criteria for a "qualified" exchange, APX had opposed the idea of
a mandatory mathematical "market clearing" mechanism, which is now
chapter and verse set by the PUC.
"The APX does not agree
that an exchange needs a mathematical 'market clearing' mechanism.
This is not an appropriate criterion for a valid exchange," Cazalet
wrote, responding to the CEC proposal in late May.
Cazalet explained in
those earlier comments that in many other markets, for example,
buyer bids are matched directly to equivalent seller bids: no uniform
market price is applied to all buyers and sellers. "The commission
should not limit the kinds of markets that could be developed,"
he wrote at the time.
But Cazalet, who had
lobbied hard for this day, said on June 9 that his exchange would
have no problem with offering either the mathematical "market clearing"
mechanism or more bilateral markets. "We can even offer the California
Power Exchange type [of] trading markets if customers wish it."
And Cazalet added, "We
can get utilities into an APX-type exchange this summer," explaining
that utilities will have to submit a utility advice letter before
it is allowed to trade on other exchanges.
"The CPUC has said that
they would expedite the advice letter process by which we could
qualify," says Cazalet. But George Sladoje, president and chief
executive officer at the PX, believes there will be no action this
summer.
"I don't think anything
will be in place this summer," he says. Sladoje believes there may
be conflict of interest with utilities submitting advice letters.
"Can you imagine a utility
sponsoring an exchange and then conducting arms length business
with that. I think we should also have a problem with that," he
says.
However, if competition
should start sooner, Sladoje is confident that the PX will prevail.
He believes that once an exchange is established and has established
liquidity and trust, it is hard to get them to change.
In defending their bid
to end the monopoly, Neeper and Bilas had said: "We are convinced
that other viable exchanges now exist or are forming that can be
equally as reliable as the Cal PX .... We are not criticizing the
PX but are instead recognizing fundamental economic theory."
THE BATTLE OVER THE
PX IS JUST ONE OF THE MANY ISSUES PENDING in the "PTR" case
on post-transition ratemaking-the most important and contentious
matter now before the PUC. Other questions include how to evaluate
the prudence of energy procurement by the IOUs, as well as the very
purpose, structure, and role of electric utility distribution companies
in California. In fact, on May 25, PUC President Loretta Lynch had
offered her own set of draft amendments to the alternate proposed
decision in which she recommended authorizing San Diego Gas & Electric
Co. (which has recovered its stranded costs) to return excess revenues
to ratepayers from its state-sponsored rate reduction bonds as an
immediate bill credit or refund check, rather than to amortize and
pay back such revenues over the life of the bonds.
On the issue of energy
procurement, for example, Neeper and Bilas suggested in May that
it was still premature to adopt any sort of sort of PBR scheme (performance-based
regulation), since the future role of electric utilities (default
service, etc.) was still not decided. And they drew no extra confidence
from the fact that the PUC had adopted a PBR experiment adopted
in 1993 for SDG&E to evaluate natural gas procurement. As Neeper
and Bilas explained, that program was put in place when gas markets
were much more mature than power markets. They added that they were
still "not sure that this experiment [gas PBR] will enable the PUC
to determine its success when completed or that the experiment itself
does not present unreasonable risks."
FOR ITS PART, THE
CALIFORNIA PX WANTED MORE DETAIL. As the PX explained, "some
of the criteria" for determining whether an alternative energy market
meets the test for a "qualified exchange," were "constructive and
necessary features," but it sought more detail when it filed comments
earlier on the Neeper/Bilas plan. In particular, the PX asked:
- "What record-keeping
practices ought to be required to ensure that audits can be effective?"
- "Who would be performing
any such audits?"
- "How many exchange
may eventually qualify?"
- "Is an `exchange'
any Internet trading platform or electronic marketplace owned
by a market participant?"
- "Can such trading
platforms meet the criteria and policy objectives set forth in
the [PUC's 1996] preferred Policy Decision?"
Furthermore, with exception
of the APX and NYMEX, he doesn't believe many of the other Internet-based
exchanges will qualify under the new PUC policy. Sladoje adds that
broker-type Internet platforms that provide bilateral trading markets
don't have the ingredients of going to make a successful exchange.
"A lot of these are just
trading platforms where they have devised some pretty slick software.
They really don't provide full services and really don't provide
a neutral trusted forum for trading," Sladoje says.
Bruce W. Radford is
editor-in-chief and Richard Stavros is senior editor of Public Utilities
Fortnightly.
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The New Power Co., an
energy services company launched May 16 by Enron Corp. and other
strategic investors, has selected IBM Global Services to build,
staff, and run core components of its back-office functions. IBM will
Web-enable The New Power Co.'s back-office infrastructure, and host its
website from IBM's e-business center in Southbury, Conn. The company's
billing and revenue management functions also will be managed at the Southbury
facility.
Schlumberger Ltd.'s Resource
Management Services business segment on May 16 acquired substantially
all of the assets of troubled CellNet Data Systems Inc. for $235
million (including assumption of liabilities), after a U.S. Bankruptcy
Court gave final approval to the deal on May 5.
Logica and American Electric
Power have signed a five-year contract for Market Data ClearingHouse,
Logica's approach to managing transformations associated with customer
choice. The AEP contract is Logica's largest ever in North America. The
service will be online to support AEP's customer choice activities beginning
with a pilot project in Virginia later this year, and full choice in Ohio
on Jan. 1.
The Cooperative Research
Network, the research and development arm of the National Rural
Electric Cooperative Association, recently signed a memorandum of
understanding with the Tennessee Valley Authority's Public Power Institute,
signaling the electric cooperative's commitment to providing a low-cost,
environmentally acceptable energy supply, and the critical role of private
and public consumer-owned electric utilities in the increasingly competitive
electric industry.
Peabody Group has reached
a definitive agreement to sell its Citizens Power subsidiary to
Edison Mission Energy, a global power producer. The sale of Citizens
is expected to be completed during the summer, upon regulatory approval.
Accudocs LLC, a provider
of electronic document solutions, has agreed to produce statements for
271,000 Central Hudson Gas & Electric Corp. customers in traditional
paper and PDF formats. AccuDocs will provide comprehensive document processing
that includes Internet presentment and proofing, printing, and mailing
services.
Allegheny + Mountaineer.
The West Virginia PSC OK'd the takeover of Mountaineer Gas Co. (a wholly
owned subsidiary of Energy Corp. of America) by Monongahela Power Co.
(doing business as Allegheny Power), subject to certain conditions that
address union concerns. It would require Allegheny to (1) offer continued
employment to all Mountaineer employees in the same job held prior to
closing of the deal, (2) assume all terms of all collective bargaining
agreements between Mountaineer and union workers, and (3) refrain from
altering any union benefit packages without first negotiating with the
unions. Case No. 00-0067-G-PC, May 11, 2000 (W.Va.P.S.C.).
KeySpan + EnergyNorth.
In a 2-1 vote split over recovery of the acquisition premium, the New
Hampshire PUC OK'd a settlement allowing KeySpan to acquire EnergyNorth
Natural Gas, the state's largest gas utility, as a second-tier subsidiary,
operating under the new first-tier subsidiary Eastern Enterprises, which
KeySpan would also acquire. The PUC said it may allow amortization and
rate recovery of transaction and integration costs, including the acquisition
premium, but may first require the companies to prove that merger benefits
to customers will equal or exceed the premium and related costs. Still,
Commissioner Nancy Brockway dissented, saying that "there are no possible
grounds for flow-through to consumers of an acquisition premium created
on the books of KeySpan or its affiliate as a result of this merger."
DG 99-193, Order No. 23,470. May 8, 2000 (N.H.P.U.C).
New Century + Northern States.
Regulators in New Mexico and Texas approved the merger of New Century
Energies Inc. into Northern States Power Co. to form Xcel Energy, marking
the final two state approvals required to consummate the deal. In New
Mexico, Southwestern Public Service Co. will guarantee $65,000 per month
in rate credits to customers over at least a 54-month transition period.
SPS estimates that the credit will flow back some $4 million in merger
benefits back to New Mexico consumers, or roughly two-thirds of the predicted
$6.1 million in savings. Case No. 3116, May 9, 2000 (N.M.P.R.C.).
Electric Retail Choice.
The New Mexico Public Regulation Commission delayed the dates set earlier
for the start of electric retail supply choice-to Jan. 1, 2002, for schools,
small business, and residential customers (a one year delay), and to July
1, 2002, for large commercial and industrial customers (a six-month delay).
The new timetable matches the schedule adopted in Texas.
The holdup in New Mexico would
give more time to prepare for the transition, said Commissioner Herb Hughes,
but large power users objected to the plan. "We didn't think it needed
to be pushed back at all," said Steve Michel, general counsel for New
Mexico Industrial Energy Consumers.
Renewable Energy. The
New Mexico PRC also OK'd rules requiring electric utilities to acquire
at least 5 percent of the energy supply dedicated to standard offer service
from renewable resources inside the state, plus a greater percentage to
customers that want it, but only "based on availability," since it acknowledged
that supplies of in-state renewable energy "may initially be quite low."
It added, "We do not discourage
continued reliance on renewable and other power sources from other states,
but rather encourage the development of renewable energy resources in
New Mexico."
The PRC also limited to four
the number of times that a customer can switch during one year between
standard offer service and a competitive supplier. Case No. 3109, May
2, 2000 (N.M.P.R.C.).
Universal Service. Maryland
regulators told electric companies in the state to collect $0.40 per customer
per month, beginning in July, to fund the first year of the state's universal
service program. Case No. 8738, Order No. 76139, May 8, 2000 (Md.P.S.C.).
Shopping Credits. American
Electric Power, FirstEnergy, and Cincinnati Gas & Electric Co. filed agreements
with the Ohio PUC staff (and others in the state) regarding shopping credits,
rate freezes, and recovery of stranded costs, in connection with the startup
of electric retail choice.
- AEP. Consumers would pay
transition costs over seven years. Residential customers of AEP affiliates
Columbus Southern Power and Ohio Power Co. would receive shopping credits-but
only the first groups at each company (25 percent and 20 percent, respectively)
who switch suppliers.
- FirstEnergy. To quell objections
from power marketers, FirstEnergy agreed to boost incentives for customers
to deal with competitive energy retailers. It said it would (1) give
preference to nonaffiliated marketers (over its own subsidiaries) to
some 1,120 MW of generation that will be made available for sale to
retail customers, (2) boost the shopping credit from 25 percent to 30
percent for commercial customers and to 15 percent for industrial customers,
and (3) provide a list of contract customers to any certified supplier.
- CG&E. Commercial and industrial
customers would get rate freezes through 2005 or through the end of
the "market development period," whichever comes sooner. The first 20
percent of residential customers who switch would receive shopping credits
and would not pay transition costs between 2001 and 2005.
Executive Compensation.
The Washington commission staff recommended a $16.5 million cut in electric
rates for Avista Corp. (the company had sought a $26.2 million hike),
stating that regulated rates should cover less of the company's management
salaries since it had been diversifying into unregulated businesses. A
final order is expected in September. Docket Nos. UE-991606 and UG-991607
(Wash.U.T.C.).
Gas Rate Discounts.
The Kansas commission ruled that all special contracts awarded by natural
gas local distribution companies (LDCs) that do not fall within the terms
of an established tariff must be filed for prior approval.
But it rejected a proposal
by its staff to automatically impute a set percentage of revenues while
setting rates for the LDC to make up for the discounts to large customers,
saying that an automatic "standard percentage imputation" would ignore
the issue of the prudence of a particular contract or discount practice.
The commission also set new
standards for gas tariffs with flexible pricing tariffs. First, any rate
reduction must be necessary (and the minimum amount so required) to retain
a customer who has a credible competitive alternative. Second, the discounted
rate must cover all incremental costs, plus make a contribution to common
fixed costs. Third, flexible tariff discounts are not available to utility
affiliates. Fourth, any deal will be reviewed in the utility's next retail
rate case. Docket No. OO-KGSG-420-RTS, April 20, 2000 (Kan.S.C.C.).
Water Utility Ratemaking.
For only the third time, the Florida PSC decided to use an "operating
ratio" to set rates for a small water utility.
It said the OR method is appropriate
where a utility has a small or nonexistent rate base, so that risk lies
primarily in recovery of operating costs, rather than capital investment.
But it admitted it lacked "economic guidance" on the issue and had settled
on 10 percent as a convenient figure. Docket No. 991290-WU, Order No.
PSC-00-0807-PAA-WU, April 25, 2000 (Fla.P.S.C.).
Water Service Territories.
The Oregon PUC OK'd new rules governing the assignment of exclusive
service territories for water utilities following passage of state enabling
legislation.
It said it would recognize
existing franchise agreements between water utilities and municipalities
and designate additional areas as exclusive if a water utility was providing
adequate service. AR 370, Order No. 00-194, April 11, 2000 (Ore.P.U.C.).
Plant Transfers. The
Nuclear Regulatory Commission on May 16 OK'd the transfer by Wisconsin
Electric of its Point Beach Nuclear Plant to the Nuclear Management Co.,
which was set up last year after Wisconsin Electric and other companies
with nuclear generating units studied ways to improve safety and performance
through consolidation of resources.
The NMC fleet now includes
seven units at five sites with 3,700 MW of capacity, owned by Alliant
Energy, Northern States Power Co., Wisconsin Public Service, Central Iowa
Power Co-op, Corn Belt Power Co-op, and Wisconsin Electric.
Coal Outlook. Despite
the fact that U.S. coal production rose in 1998, recent events-including
falling exports, environmental initiatives, and a growing preference for
natural gas as a generating fuel-suggest a difficult period for the coal
industry, according to a study by GRI and Hill & Associates Inc.
The two-volume study, "Coal
Demand and Price Projection," examines those challenges and includes an
analysis of the competitiveness of coal in the industrial and electric
generation sectors, key markets for natural gas.
It concludes that total coal
demand by electric generation and industrial customers should rise slowly
from 980 million tons in 1998 to 1,123 million tons by 2015, but that
coal use will decline to 1,101 million tons by 2020. Contact Kelly Murray
at 703-526-7832.
Federal PMAs. A report
from the General Accounting Office says that the federal power marketing
administrations (PMAs) have inherent cost advantages over investor-owned
utilities-such as tax abatement, no dividend obligation, and low-cost
hydroelectric generation-and predicts that such advantages likely will
enhance the competitive positions of the PMAs as industry restructuring
continues.
Nevertheless, it did acknowledge
that financing costs for three PMAs-Bonneville Power, the Southeastern,
and Western Area Power Administrations-were high compared to those of
the IOUs and other government-owned utilities when measured against operating
revenues.
See "Power Marketing Administrations:
Their Ratesetting Practices Compared With Those of Nonfederal Utilities,"
GAO/AIMD-00-114. Call 202-512-6000.
Water Transport Rates. Reversing
a trial order, a California appeals court ruled that under a state law
that guaranteed open access to water pipelines and transport facilities
for wheeling service, a state water agency could fix a general transport
rate applicable to all its members, such as a local irrigation district,
based on the transporter's overall fully allocated systemwide costs, including
return on capital, without special allowance for distance traveled or
facilities used, and without having to set a different individual charge
for every specific transaction. Metro. Water Dist. of So. Calif. v.
Imperial Irrigation Dist., B119968, May 30, 2000 (Calif.App., 2d Dist.).
Pilot Programs. Finding
the case to be within the exclusive jurisdiction of the state PUC, the
Ohio Supreme Court dismissed a suit that complained that a utility violated
antitrust law by limiting its pilot program for retail competition to
an exclusive geographic area within the utility's larger service territory.
State ex rel. Cleveland Elec. Illum. Co. v. Cuyahoga County Ct. of
Common Pleas, No. 99-1979, May 17, 2000 (Ohio).
Nuclear Waste. Saying
it had no authority to act, a federal appeals court turned down a request
by an electric utility to force the U.S. Department of Energy to pay monetary
relief for its failure to begin disposing of spent nuclear fuel by Jan.
31, 1998, even though the court earlier in effect had rejected the DOE's
defense that such failure was unavoidable.
The court cited a "Catch-22"
standoff. On one hand, it agreed that the Nuclear Waste Policy Act imposed
an "unconditional obligation" on the DOE. On the other, however, it acknowledged
that the law itself did not require performance, and so the court had
no power to enforce the law. Wisc. Elec. Pwr. Co. v. DOE, No. 99-1342,
May 19, 2000 (D.C.Cir.).
Utility Bills. A Colorado
court affirmed a PUC order that a manufacturer that agreed to buy an automobile
tire recycling facility was liable to pay utility bills for service to
that facility, even though the manufacturer never followed through on
the actual purchase, where it had notified the utility of the agreement
and asked the utility to redirect the bills to the prospective new owner.
Jarco Inc. v. Colo. PUC, No. 98SA425, May 15, 2000 (Colo.).
Cross Marketing. A Michigan
appeals court upheld a PUC order that told a telephone utility to stop
its cable television affiliate from handing out vouchers to prospective
customers ("Americhecks") that could be traded in for free local telephone
service.
The PUC had ruled that the
free offers violated state law by reducing rates below cost for a tariffed
service. Mich. Cable Telecom. Asso. v. Mich. PSC, Docket No. 209011,
May 4, 2000 (Mich.App.).
Interconnection Standards.
The FERC OK'd Entergy's proposed pro forma procedures and operating agreement
for interconnection of generation to the transmission grid with only minor
modifications. It looked past the many protests and denied requests by
Dynegy, PG&E, and the Electric Power Supply Association (EPSA) to open
a technical conference, generic hearing, or industry collaborative process
to develop a single nationwide interconnection standard. (See "Lost in
the Queue," Public Utilities Fortnightly, May 1, 2000, p. 4.)
The FERC's key modification
emphasized that interconnecting generators should be able to request unbundled
retail transmission service to facilitate retail service-not just wholesale
transmission, as envisioned in Entergy's proposed plan. Docket No.
ER00-1743-000, 91 FERC ¶61,149, May 18, 2000.
EPSA wasn't finished, however.
On May 25, it filed a protest against yet another set of pro forma interconnection
standards, this time filed by American Electric Power, and accused the
FERC of creating a balkanized regime, noting that "the commission is developing
standardized procedures, one case at a time."
EPSA observed that AEP's filing
marked the third recent interconnection proposal (Entergy and Commonwealth
Edison being the other two utility sponsors), but noted that each contained
significant differences, which could frustrate a nationwide generation
industry. In particular, EPSA noted that AEP, Entergy, and ComEd proposals
seemed to differ on whether generators could request interconnection standing
alone, or must request transmission service bundled with interconnection.
It argued that such differences ignored the FERC's March 15 ruling in
the Tennessee Power case (90 FERC ¶61,238) that interconnection and transmission
are separate services.
Another protest came from PSEG
Global, a subsidiary of Public Service Enterprise Group, which argued
that AEP's proposal was "unclear" concerning the queuing process-whether
it would govern priority for just a System Impact Study or would apply
both to the SIS and rights to grid capacity. Added PSEG, "this is not
merely an academic concern." FERC Docket ER00-2413- 000, filed May 4,
2000 (AEP proposal), and May 25, 2000 (protests by EPSA and PSEG).
Merchant Plant Approvals.
California and New England continued to certify new merchant power
plants.
- n California. The state's
Energy Commission OK'd the 700-MW High Desert Power Project for construction
and operation in San Bernardino County, the fifth project it has approved
since the state's competitive power market started up in March 1998.
Docket No. 97-AFC-1, May 3, 2000 (Calif. Energy Comm'n).
- n Massachusetts. The state's
siting board approved construction of Sithe West Development LLC's 540-MW
electric generating plant in Medway, Mass., provided that Sithe consult
with the board staff before it sells any entitlements for avoided CO2
emissions earned by the plant over its 20-year life to third parties
for use as offsets against other CO2 emissions limits, and that it in
no event sell more than 1 percent of emissions rights produced by the
plant. EFSB 98-10, April 13, 2000 (Mass. Energy Facilities Siting
Board).
Off-System Load. Believing
that its existing plant certification procedures were adequate for the
evolving electric industry, the North Carolina commission rejected a recommendation
by its staff to open a docket to consider new rules for utility plants
that serve off-system load.
It added that new rules might
be premature since a legislative commission was studying the future of
electric service in the state. Docket No. E-100, Sub 85, April 26,
2000 (N.C.U.C.).
Utility Divestitures.
Electric utilities continued to sell off generating plants, with unit
prices varying considerably.
- Pepco. Potomac Electric
Power Co. will sell its 9.72 percent interest (166 MW) in the Conemaugh
Generating Station to a joint bid by PPL Global Inc., a subsidiary of
PPL Corp., and Allegheny Energy Supply Co. LLC, a subsidiary of Allegheny
Energy Inc., for $52.5 million, or $920 per kilowatt-more than twice
net book value and near the top of the range for recent utility power
plant sales.
- SoCal Edison. AES
Corp. won a bid to purchase a 70 percent controlling interest in the
1,580-MW, coal-fired Mohave Generating Station in Laughlin, Nev., for
approximately $667 million, or about $603 per kilowatt. AES has executed
asset sale agreements with sellers Southern California Edison Co. (56
percent interest) and Nevada Power Co. (14 percent). The acquisition,
expected to close in the fourth quarter of 2000, is subject to review
by the FERC, California PUC, and Nevada PUC.
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.
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