News Digest
September 15, 2000
Chaos
Takes Hold in San Diego. San Diego Gas & Electric's 1.1 million
customers saw their bills double during the course of a few months this
summer, sparking frenzied activity by regulators, legislators, and market
players to quell public outrage and fix the state's troubled wholesale
electric market. Among their efforts were the following:
- The California Independent
Operator lowered the price cap for wholesale electricity, but SDG&E
urged federal regulators to go further with caps;
- California Gov. Gray Davis
asked the Federal Energy Regulatory Commission to investigate the state
power market;
- SDG&E and the California
Power Exchange asked the PUC to approve market-based bidding;
- A report to Gov. Davis
concluded that market control was out of state regulators' hands; n
Power producers asked FERC to force the ISO to pay lost profits if power
scheduled for export is recalled at the capped price;
- FERC approved the PX's
proposal to loosen credit requirements imposed on traders;
- The PUC OK'd incentives
for qualifying facilities to produce more power;
- The PUC authorized Pacific
Gas & Electric and Southern California Edison to purchase energy on
the bilateral market;
- SDG&E's plan to decrease
rates in the California Alternative Rates for Energy program was approved;
and
- SDG&E mailed customers
deregulation-related refund checks.
Amid the confusion, a voice
of perspective reverberated through the California energy industry. The
unlikely channel for this message was the July 3 resignation memo of ISO
board member Camden Collins, a non-market participant. (See p. 17,
"An ISO Board Member Resigns.")
Wholesale Price Caps.
The day after the board of governors of the California ISO voted to lower
the price cap to $250-the highest price the ISO said it would pay for
power (per megawatt-hour) used for grid system balancing and other ancillary
functions-San Diego Gas & Electric Co. asked the FERC to impose the same
maximum price limit on sellers offering power to the ISO, and for transactions
in markets run by the California Power Exchange for trading wholesale
energy delivered as a product to consumers.
SDG&E said it supported the
board in voting to cap ISO buy offers on Aug. 1 (see News Digest, Sept.
1, p. 10), but thought it didn't go far enough, since the board could
reverse its stance.
"That measure does not obviate
the urgent need for Commission action," said the utility. It noted that
the ISO's price caps did not extend to the day-ahead, hour-ahead, and
block-forward markets in the PX, "which together account for the great
bulk of the sales at wholesale to meet retail demand in California."
But SDG&E stressed that the
price cap would not solve long-term "design and structure problems inherent
in the ISO's decentralized approach," since, in its view, "market coordination
is breaking down whenever the market is even moderately stressed."
Yet the utility still saw value
in stop-gap action from the Feds: "The only way that the FERC can rein
in prices in bid-based markets such as those of the PX and ISO is to limit
what sellers bid," it said. "Quite simply," the petition concludes, "California
wholesale markets are, particularly at high demand levels, dysfunctional,
allowing sellers to exact prices considerably above levels that would
prevail in open competition, where the demand side of the equation could
participate in the market." FERC Docket No. EL00-95-000, filed Aug.
2, 2000.
Earlier, on July 27, California
Gov. Gray Davis had written to FERC Chairman James J. Hoecker, asking
for immediate customer refunds should the FERC determine in its investigation
into wholesale power rates that the rates are not "just and reasonable,"
as required under the Federal Power Act. Yet Davis already had drawn his
own conclusion on the matter: "Californians are willing to pay their fair
share of the cost for a reliable supply of electricity, but I believe
the current situation is unjust and totally unacceptable."
On July 20, SDG&E and the PX
had asked the California PUC to approve a new market-based bidding solution
aimed at allowing the utility to procure power with less price volatility
over the next five to nine months. The proposal emerged from an emergency
summit held the second week in July that brought together more than 100
market participants. The new bidding program would allow SDG&E to bid
for power within the PX as far in advance as the spring of 2001. Without
it, bids could cover only the upcoming three months.
Reporting to the Governor.
On Aug. 2, California PUC President Loretta Lynch and state Electricity
Oversight Board Chairman Michael Kahn wrote to Gov. Gray Davis in an attempt
to explain the turmoil in summer electricity prices in the state. But
they warned that by creating the Power Exchange and Independent System
Operator-both regulated by the FERC-the state had "handed the reins" of
its electric system to the federal government.
As Lynch and Kahn explained,
"the State of California no longer possesses the ability to protect California
businesses and consumers." They added that "changes in power system governance
resulted in PG&E being ordered to black out over 100,000 of its customers
without an ability for the State to weigh in on that decision."
They urged state interests
to present a united front to the FERC to ask for extended price caps to
moderate wholesale prices.
Lost Profits. A group
of power producers-Reliant Energy, Dynegy Power Marketing, and Southern
Energy California-filed a complaint asking the FERC to issue a declaratory
ruling that the California ISO must compensate generators and scheduling
coordinators for actual damages and potential lost revenues in the event
that the ISO curtails any transaction already scheduled for exporting
power out of the ISO's control area, and instead recalls the energy for
use within the ISO during a system emergency, forcing the generator to
sell within the ISO at a capped price.
The group claims the ISO has
opposed such payments and has suggested that higher prices for export
transactions already reflect the risk of curtailment. FERC Docket EL00-97-000,
filed Aug. 3, 2000.
Credit and Collateral.
The FERC granted conditional approval of Tariff Amendment No. 18, proposed
by the California Power Exchange, to loosen the credit requirements it
imposes on those who trade through the exchange.
The amendment contains rules
governing collateral and banking, a surety pool performance bond, and
a scoring system for setting limits on unsecured credit. Previously, the
PX had forced traders to post security equivalent to the dollar value
of 46 days of trading activity. Docket No. ER00-2736-000, 92 FERC ¦61,096,
July 28, 2000.
Commission and Utility Actions.
In the wake of the price spikes in the state wholesale market, the California
PUC issued a flurry of short-term bandages and at the same time opened
a longer-term investigation into the functioning of the market (Investigation
00-08-002). Meanwhile, utility San Diego Gas & Electric scrambled
to appease ratepayers through a series of refunds, credits, and promises.
- QF Incentives. To
increase energy production during high-demand periods, the PUC approved
voluntary qualifying facility (QF) contract amendments for Southern
California Edison and San Diego Gas & Electric that gives the QFs temporary
financial incentives for producing more power. QFs would be paid 70
percent of the zonal California Power Exchange day-ahead market-clearing
price for energy delivered during high demand hours that exceeds a pre-established
"baseline level,"or the level of a QF's normal output during peak periods.
The incentive is available only during peak hours and from Aug. 1 through
Oct. 31. Decision 00-08-022, Aug. 3, 2000 (Calif.P.U.C.).
- Bilateral Market Purchases.
In another move, the PUC authorized Pacific Gas & Electric and SCE to
purchase energy and ancillary services and capacity products in the
bilateral market, but limited its authorization to contracts that expire
on or before Dec. 31, 2005. "Entering into appropriate bilateral transactions
and providing delivery through the PX may be valuable in hedging against
price spikes in the PX Day-ahead Market," the PUC said. Decision
00-08-023, Aug. 3, 2000 (Calif.P.U.C.).
- CARE Rate Cut. Linking
rates to PX prices, the PUC next approved SDG&E's proposal to decrease
rates in the California Alternative Rates for Energy program by an amount
equal to 35 percent of the difference between the applicable weekly
PX price and the 4.6 cents per kilowatt-hour price embedded in rates
for the four-week period beginning Aug. 7. The PUC also adopted an interim
methodology to adjust CARE rates by an amount equal to 15 percent of
the difference between the applicable weekly PX price and the 4.6 cents
per kilowatt-hour price embedded in rates, for each week thereafter.
CARE rates will be adjusted downward when PX prices go above 4.6 cents
per kilowatt-hour and upward when they fall below that amount, providing
CARE customers a discount of 15 percent of their electric bill. The
adjustments would remain in effect until the PUC issues a final decision
in SDG&E's "Rate Design Window" application (91-11-024), which is expected
Nov. 1.
- Customer Cash. Meanwhile,
as customers protested their energy bills, San Diego Gas & Electric
moved to implement a June 8 PUC order by mailing deregulation-related
checks totaling $390 million to its 1.1 million customers throughout
San Diego and southern Orange Counties. According to SDG&E, the checks,
which were to be mailed within two weeks after delivery of the customers'
August energy bills, would be for $260 for the typical residential customer
and $870 for the typical small-business customer.
Acknowledging the favorable
timing of the check mailing, Edwin A Guiles, president of SDG&E, said,
"We are hopeful that these checks will help ease the cash-flow crunch
caused by the highest power prices we are all paying to the California
Power Exchange."
SDG&E's recovery of its transition
costs two-and-one-half years earlier than expected allowed it to distribute
the $390 million, which includes the balance of proceeds from rate-reduction
bonds issued in December 1997 to refinance their debt related to their
stranded assets.
- Credits and Promises.
Earlier, on Aug. 3, the PUC approved SDG&E's petition granting the utility
authority to accelerate the return of $100 million in a regulatory balancing
account controlled by the PUC, allowing the typical residential customer
to receive a total credit of $34 on the August and September electric
bills and the typical small-business customer to receive a credit of
$128 over that period.
In that order, the
PUC said it would "hold SDG&E to [its] promises" that no customer will
have service disconnected pending receipt of the lump-sum bond refund
check, and further ordered "that no customer have service disconnected
as a result of summer price spikes." Decision 00-08-021, Aug. 3,
2000 (Calif.P.U.C.).
An ISO Board Member
Resigns-
And Speaks Her Mind
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July 3, 2000
Members of the Governing Board of the California ISO
Dear Colleagues:
Let me first say what
a great pleasure it was to serve with you. It was truly an honor
to work with so many dedicated, diverse, and well-informed individuals.
I regret I am compelled
by the events of last week to resign, effective tomorrow.
When I was appointed
to the Board for a term of one year, I did not anticipate that
three years later I would still be working on and thinking about
the same issues. I hope you find my last thoughts and suggestions
on the price cap (memo dated 7/3/00) useful as you continue your
deliberations.
May each of you find
the determination to stand for the principle that the ISO must
be independent of manipulation by any market participant.
Respectfully
submitted,
Camden Collins
Non-market participant
To: Members of the ISO
Board
From: Camden Collins
Date: July 3, 2000
Re: Fixing The Real Problem(s)
Cc: ISO Management Team
I hope the ISO Board
will take action to reverse the incentive to under-schedule, and
become legislatively active on stranded cost issues that are likely
to continue to disrupt interstate commerce.
How did we get here?
In my opinion, efforts to manipulate the Board have been on the
rise ever since new state law, in an effort to resolve preemption
disputes, provided that ISO matters "affecting" retail customers
effectively separates state from federal subject matter jurisdiction.
Despite our hopes for an amicable resolution, in practice this term
"affecting" is fatally vague and ambiguous, lending itself to ever-bolder
over-reaching by individuals. Apparently the prevailing view of
Oversight Board review scope in proposed legislation is an unqualified
"all activities" of the ISO.
Unlike the rest of you,
I have no employer interested in my attendance. Thus I cannot be
threatened with employment termination, removal from the Board,
or legislative revenge on my employer. That's true independence.
I am saddened that you do not share it.
In my opinion, no political
representative of a small fraction of the state's consumers-no matter
how well intentioned-has the right to dictate to this Board a matter
exclusively within FERC's jurisdiction, or question your integrity
in voting what you believe to be the ISO and state's best interests.
I can only guess that an appeal of the ISO's decision on price caps
in the appropriate federal forum is viewed by some as unlikely to
prevail on the merits. I concur.
How can we incent
over-scheduling? As someone who has never accepted money from
Southern California Edison, I am shocked by the idea that my conversations
prior to the Board vote last week deserve investigation. All that
will be found is that I spoke with an Edison representative (and
no other stakeholder) about an instantaneously available
method of shifting the incentive to enormously under-schedule to
an incentive to modestly over-schedule, thus protecting Edison financially,
the ISO operationally, and the citizens who will suffer in a blackout.1
All it requires is the PX cap to be lower than the ISO's. The PX
is no less able to meet and act on four day's notice than the ISO.
The imbalance energy volatility under those circumstances should
trend towards decreasing ("dec'ing") generation, should be lower
in amplitude, and should reflect true opportunity costs in the region
much better than the game of chicken our operators are dealing with
today.
Failing to address the
incentive to under-schedule is in my view very unfair to our operators.
For reasons known only
to them, Edison chose not to support this reform.
Is this about reliability?
I have only heard one objection to this proposal: if the incentive
were for Utility Distribution Companies to err slightly towards
over-scheduling load in the PX, the generators would (it is argued)
still not bid in the PX forward markets. How would such withheld
generation thus obtain any revenue, since imbalance energy volumes
and prices would drastically decrease? If California is "a buyer's
market," then this concern is unfounded; if not, then we truly have
a reliability problem. The withheld generation could not make
more money exporting. Generators will have no choice but to meet
the load in a forward period because the concentration of load has
been proved by our experience to be an effective exercise of market
power. (So states our annual Market Surveillance Report.) Even if
reluctantly, generation would follow the lead of load into forward
periods. The process would be hastened by shrinking imbalance energy
volumes, as too many withheld MWs chases too few clearing imbalance
MWs.
If, on the other hand,
California cannot dictate to the rest of the western energy markets
the value of scarce capacity on a hot day, then we do indeed have
a reliability problem that will be worsened by a lower cap. All
other things being equal, a lower cap causes a more unfavorable
ratio of imports to exports, and higher out-of-market volumes and
prices. In my view, the lower the cap, the greater the burden on
and distortion to interstate commerce, the more amplified the painful
price impact behind the misguided Balkan wall.
If it is not about
reliability, what is it about? This Board has been repeatedly
subjected to pressure on behalf of the principle of stranded cost
collection, hiding as it does behind a host of bogus cover issues.
But there seems to be very little disagreement with that principle.
The CPUC's initial stranded cost collection proposal was that Utility
Distribution Companies be given the discretion to balance flexibly
and continuously over a longer period of time the competing interests
of stranded cost collection and rate reduction as the market and
competition matured and evolved. This was unacceptable to one utility;
they obtained instead from the legislature provisions that are far
less flexible, and are treated as if they were written in stone.
If someone is in possession of stranded cost estimates done in 1997
that are to be honored, I wish they would share them with us so
we could address the problem. More and more, addressing shareholder
equity seems the palatable route.
No reason exists for
this stubborn refusal to re-examine fair stranded cost collection
periods. Manipulating the wholesale market, in my opinion, threatens
the reliability of the entire western region, the ISO's future in
that region (as we are mistrusted and viewed as easily manipulated),
and the near term health and safety of every Californian.
I am appalled by the
thinly voiced threats of re-regulation and consumer revolt. My parents
are retired on a fixed income and live in SDG&E's territory. I understand
what a 52 percent bill increase does to them. History has ruthlessly
proved that those who erect the highest protective barriers to interstate
and foreign commerce end up paying much more for resisting the pressures
of incremental change. This pressure allows a broad array of private
decisions and investments to be made on a gradual and punctual basis.
How much longer can California stave off change when it is not electrically
self-sufficient? Operationally, not much longer. Why mislead and
deceive the public on the paternalistic assumption that they are
not capable of understanding pent up change? What else does the
public buy that has not had price increases for three to five years?
I also understand how
little the impact of changing ISO price caps will be on that
average bill. Our ancillary service price "spike" was a 12 percent
increase (from 2 percent to 14 percent of energy costs), while natural
gas prices have doubled. It is extremely hypocritical for a state
that honors (with a vengeance) 12 cent per kilowatt-hour deals (both
QF and nuclear) to be so extremely upset about my $11 bill, in which
my average energy price for the month ended 6/21/00 was 8.402 cents
per kilowatt-hour.
If those that crafted
the stranded cost law find it too inflexible, there is no reason
the law cannot be changed to calculate at the end of the rate freeze
the extension necessitated by all hours and volumes clearing over
$250 per megawatt-hour. It is not as if we have burgeoning and vibrant
competitive retail sector that will be harmed: politics at its worst
has seen to that.
Who are you going
to choose to believe? We were informed by Sen. Peace at last
week's Board meeting that he does not believe the ISO will be unable
to procure or attract to its markets the reserves it needs if the
cap is lowered to $250 per megawatt-hour. This is a matter of speculation,
not fact, in which the citizens of this state are placed at risk.
Edison similarly believes that the western regional market should
be counted on to perform in these next two summers as it always
has in the past under vastly different circumstances. We are asked
to make an educated guess who will turn out to be right all of the
time. Because it does not matter if $250 per megawatt-hour works
most of the time-so does $750.
With combined operating
experience of over 40 years, the current operational perspective
of the ISO management team suggests that it will only make a difficult
situation worse. In the two years that Edison's buy-sell agreement
has been in place, Edison has not been in a position to accumulate
experience trading in the region for large blocks of load.
(Unless, of course, they
are violating affiliate restrictions and sharing information with
their unregulated traders.)
How much time can
we buy? I wish to leave you with the following potential scenario:
In a handful of weeks generators will meet the condition we voted
on last week by bidding $2,500 in the PX and not clearing; the ISO
will pay more than $750 to avert an ever-increasing number of emergencies
in "out of market" calls for reserves during ever-lower temperature
"events"; the price signal will be sent, both long and short, to
build outside California and export outside of California; the under-scheduling
(the root cause) will continue by those who have the most market
power (concentrations of load); and another assault on the ISO's
independence will begin.
When would the Board
prefer to take a stand and support our operators doing something
humanly feasible?
Wouldn't it be great
if command and control worked? As discussed last week, in my
view (as well as others'), forcing merchant generators to sell to
the ISO is illegal. Even if it were not, exercising an emergency-based
option to cut export schedules in real time will, on a hot day,
only result in an equal or greater cut in imports, dangerously destabilizing
all western states. This is lunacy: We can not get through a heat
wave without normal import volumes. Cutting exports is a counter-productive
fix under temperature conditions where internal generation can not
meet peak load by about 11,000 MW, absent planned outages. We can't
cut enough exports to replace that, and cutting huge export/import
blocks in real time is a prescription for a blackout.
Who keeps the lights
on, politicians or operators? To me, the suggestion that the
ISO management does not have as its first interest and priority
keeping the lights on, or does not have the best operational perspective
on the regional market dynamics, and should be removed along with
this Board for having a different opinion of the likely outcome
is an accusation that is incredibly unfair, particularly if it comes
from those who will not be blamed or held accountable for an outage.
The very idea that one
person could "take down" the whole Board and the CEO with it over
a difference of opinion on the appropriate wholesale price cap is
truly stunning.
Why should a few persons
have such precise accuracy of prediction? I have known many of you
for three years, and I do not believe that we deserve to have our
good faith questioned, however we vote. Particularly the designated
consumer representatives, who make a living by interacting with
consumers on a continuous basis, and have not been accepting money
to support what are obviously issues of utility shareholder equity.
How can we condone a process that is so corrupted and manipulated
with fears of removal and reprisal,2 exercised upon us
by people who are experts at initiating letter campaigns with incomplete
information, who flagrantly disrespect the differing opinion of
consumer representatives on the Board, and the operational talent
and experience the ISO has accumulated? It saddens me that I continue
to hear reports of "verbal abuse," "brow-beating," being "whipped"
and "excoriated" stemming from the same source.
Surely we can get on
with fixing the real problems: the incentive to under-schedule and
the need for equitable stranded cost collection. Although one might
not think the latter is an ISO issue, no positive regional developments
for the ISO can occur until there is resolve at the Board to force
retail rate making issues where they belong-away from interference
with interstate commerce.
1 I
also spoke to David Jermain, who heads up market surveillance at
the California PX, and Richard O'Neill, who is employed at the Federal
Energy Regulatory Commission. But in my opinion, neither of these
persons should be considered industry stakeholders.
2 The fear
of reprisal in the form of a refusal to re-seat a member prospectively
for their vote on this issue has, as you know, already been voiced
at our meeting last week. The fear of employment termination is
equally palpable to the astute observer.
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Customer Rebates. The
Nevada PUC on Aug. 3 approved a $9.3 million rebate for Sierra Pacific
Power Co.'s electric and natural gas customers, effective for October
bills, in the third and final installment of a "shared savings agreement"
that shares last year's efficiency gains with customers. The rebate amounts
to $11.26 for the typical electric customer and $3.72 for the typical
natural gas customer, the company said. Docket Nos. 00-5005 (electric)
and 00-5003 (natural gas), Aug. 3, 2000 (Nev.P.U.C.).
Retail Supply Choice.
The Nevada PUC also OK'd agreements allowing retail electric competition
to be phased in from Nov. 1, 2000 to Dec. 31, 2001. The deal calls for
various parties to withdraw lawsuits filed in state and federal courts
that had challenged state legislation on electric competition.
The deal also would impose
a general rate freeze, but would allow both utilities to institute mandatory
monthly fuel and purchased power cost adjustments starting Sept. 1, 2000.
Case Nos. 97-00742A et al., July 20, 2000 (Nev.P.U.C.).
Natural Gas Competition.
The New York PSC OK'd a restructuring of natural gas operations of Niagara
Mohawk Power Corp., requiring NiMo to make certain pipeline and storage
capacity available to competitors. NiMo also must offer balancing services
to competitors and allow gas suppliers and marketers to choose between
separate or combined billing, plus the option of providing their own billing
services such as calculation, printing, processing, and mailing.
NMP also must develop aggregation
programs for low-income customers, and must unbundle rates and publish
the "backout credit" reflecting costs it will avoid when a customer chooses
an alternate gas supplier. The order imposes financial penalties (credits
to customers) if NiMo fails to meet targets for service quality and reliability.
Case No. 99-G-0336, Opinion No. 00-9, July 27, 2000 (N.Y.P.S.C.).
Electric Delivery Rates.
The New York PSC opened a case to study the differential in electric delivery
rates charged by Consolidated Edison Co. between New York City (lower)
and suburban Westchester County (higher), and to consider whether to equalize
rates.
The PSC itself had imposed
the rate difference to equalize overall bills, believing that energy costs
would generally run higher within the city's urban load pocket, as NYC
and Westchester fall within different zones under the locational pricing
regime maintained by the New York Independent System Operator. Case
00-E-1208 and 96-E-0897, July 20, 2000 (N.Y.P.S.C.).
Standard Offer Prices.
The Maine PUC increased Bangor Hydro-Electric Co.'s standard offer price
by 1.7 percent, citing price spikes and general uncertainty in New England
power markets.
Commissioner Welch dissented,
claiming the adjustment was no greater than the margin of error in cost
projections. He said he would rather "spare customers the confusion, and
inconvenience" of a mid-course correction. Docket No. 99-111, July
20, 2000 (Maine P.U.C.).
Low-Income Programs.
The California PUC found too little cost savings to justify mandatory
competitive bidding to solicit providers for low-income assistance programs
for electric and gas utility customers. Decision 00-07-020, July 6,
2000 (Cal.P.U.C.).
Water Utility Diversification.
The California PUC adopted rules on ratemaking for revenues earned by
water utilities from unregulated services. Ratepayers get compensation
for any contribution to fixed costs by sharing in the revenues received
by the utility, plus 10 percent of gross revenues from larger "active"
non-tariffed ventures (shareholder investment of at least $125,000) and
30 percent of revenues from smaller, passive ventures. R.97-10-049, D.
00-07-018, July 6, 2000 (Cal.P.U.C.).
Power Plants
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Grid Interconnection.
The FERC OK'd tariff amendments filed by the Southwest Power Pool
setting out new coordinated interconnection rules for those seeking
to link new generating plants to the grid, and for upgrades to existing
plants.
The rules will require
interconnection customers to reimburse SPP for costs it incurs for
feasibility studies, and give SPP 90 days to complete a system interconnection
study. (The FERC rejected calls for a 60-day time limit.) Third-party
studies are allowed, but only if the transmission provider agrees.
SPP has indicated that it will develop separate, streamlined rules
for plants (or expansions) smaller than 10 megawatts. Docket
No. ER00-2713-000, 92 FERC ¶61,109, July 28, 2000.
Return on Equity.
The FERC reviewed its overall policy on setting rate of return on
common equity (ROE) in the electric industry in affirming a 10.8
percent ROE set by an administrative law judge for System Energy
Resources Inc., for the sale of electric capacity and energy from
SERI's Grand Gulf nuclear unit 1 to four electric utility subsidiaries
of SERI's parent company Entergy Inc.
As it had done three
days earlier in setting ROE for transmission service for Southern
California Edison Co. (See News Digest, Sept. 1, 2000, p. 16),
the FERC said it would use a "constant growth" variation of the
traditional discounted cash flow (DCF) method to estimate dividend
growth, rather than use the two-stage model of dividend growth applicable
for gas pipelines that assumes that long-term growth will mirror
the Gross Domestic Product.
As the FERC explained,
the electric industry is not the sort of mature industry where long-term
growth reflects the overall domestic economy. "Important facts which
we have relied on in recent gas pipeline cases are not present,"
said the FERC. "There is no evidence that Entergy's growth rate
will approach that of the economy as a whole." Docket No. ER95-1042-000,
Opinion No. 446, 92 FERC ¶61,119, July 31, 2000.
Plant Sales. Central
Hudson Gas & Electric Corp. announced Aug. 8 that it, along with
Consolidated Edison Co. of New York Inc. and Niagara Mohawk Power
Corp., had agreed to sell their interests in the Sanskammer and
Roseton (1,700 MW combined capacity) to Dynegy Inc. for $903 million-a
premium of over four times book value.
The plants, which burn
natural gas and No. 6 fuel oil, are the last two fossil units to
be sold by investor-owned utilities under utility restructuring
plans ordered in New York.
Certification Procedure.
The Wisconsin PSC streamlined its process for certifying new
power plants, explaining that the old two-stage process had raised
"inappropriate regulatory barriers" to much-needed new construction.
Utilities may still choose to use the old rules, however. Nos.
05-BE-103 et al., July 11, 2000 (Wis.P.S.C.).
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Cross-Contract Ranking.
Natural interstate pipelines and local distribution companies (LDCs) continued
to disagree markedly over the need to share contract-level information
in the confirmation process for gas pipeline capacity gas in comments
filed on the three different business standards proposed by the Gas Industry
Standards Board (GISB) to implement "cross-contract ranking" (CXKR), which
would allow shippers to rank gas transportation contracts by preference
and allocate gas volumes freely among contracts according to rank to increase
efficiency. FERC Docket No. RM96-1-015, comments filed Aug. 7, 2000.
- Pipeline View. While
most of the gas industry appeared to support CXKR, implying confirmations
on an "entity-to-entity" level, the pipelines appeared unanimously to
favor GISB proposal 3. The alternative, proposal 2, would have required
pipelines to provide supplemental contract information to LDCs and producers
holding working interests, with such information as upstream and downstream
package ID, receipt location, and type of contract (e.g., firm vs. interruptible).
The pipelines, including Williams, Enron, and El Paso Energy, saw no
need to provide such data to LDCs. In fact, the FERC had taken the pipeline
view and given LDCs the burden of proving need for data when it its
notice of proposed rulemaking (NOPR) issued June 30, which accepted
CXKR in principle. (GISB itself had voted 18-5 for proposal 2, but it
failed to pass under GISB rules because it failed to win at least two
"yes" votes from pipelines.)
- LDC View. By contrast,
the LDCs favored proposal 2, claiming a need for contract-specific data
to preserve reliability. Comments from National Fuel Gas Distribution
Corp. were typical. As NFG claimed, "entity-level confirmation can pose
a threat to reliability at an LDC's city gate because the transportation
contract identity ceases to be a part of the confirmation and allocation
process. This step makes it impossible for the LDC to determine whether
primary firm transportation is being used on the pipeline to transport
gas supply to its city gate." Cincinnati Gas & Electric echoed that
concern, claiming that "the safety, reliability, and integrity of an
LDC's delivery system depend upon knowledge of upstream transportation
priorities for the parcels of gas delivered to its city gates." In fact,
NFG saw the pipelines as the true roadblock to progress: "This failure
of GISB consensus results solely from the unjustified intransigence
of a single segment-pipelines-at the expense of the legitimate and operationally
critical, requirements of other segments."
- Shipper View. Ironically,
a shipper coalition representing Salt River Project, Boeing, the Midland
Cogeneration Venture and the Tennessee Valley Authority, among others,
opposed implementation of the proposed CXKR rules without correcting
what it saw as two major flaws in the FERC NOPR: "First, it does not
require pipelines to follow the rankings provided by the shippers; second,
the NOPR does not provide shippers with the information necessary to
determine which packages of gas actually flowed." The shippers added:
"Absent this information, [we] request that the FERC deny the proposed
standards and address the issue of CXKR in collaboration with Title
Transfer Tracking [another GISB initiative] in a subsequent rulemaking."
Capacity Price Manipulation.
Southern California Edison Co. told the FERC that it had settled its dispute
with Southern California Gas Co. over pricing of gas pipeline capacity
and asked the commission to dismiss the complaint. Three years earlier,
Edison had alleged that SoCalGas had sold off excess gas pipeline capacity
to its gas procurement division at below-market prices. (Excess capacity
not otherwise reserved for retail core gas customers.) FERC Docket
No. RP97-248-000, filed July 28, 2000.
Transco Spinoff. International
Transmission Co., formed to take over the wires assets of Detroit Edison
and operate as a stand-alone transmission company, now has asked the FERC
to OK a novel ratemaking scheme both to (1) boost revenues above what
likely would be earned as a transco or part of an ISO, and (2) minimize
the chilling effect of capital gains tax liability, which can deter divestiture
of grid assets.
Detroit Edison had proposed
to form ITC back in May, saying it would make a "complete exit from the
transmission business." (See News Digest, July 1, 2000, p. 14.)
- Rate Design. First,
in place of the rate structure contained in Detroit Edison's open-access
transmission tariff (OATT), ITC proposes to freeze its wholesale transmission
rates until 2006 at roughly the same level of revenue requirement inherent
in the electric transmission component of Detroit Edison's current,
state-regulated and bundled retail distribution rates. ITC says its
proposed rate plan would yield about $138 million in annual revenues-far
above the $93 million earned by its current OATT, and enough to preserve
capital and expand its system, according to financial witness Shimon
Awerbuch, who testified that OATT rates were too low to maintain an
investment grade bond rating.
- Capital Gains. Second,
to mitigate the effect of capital gains taxes on the newly formed company,
ITC proposed to require Detroit Edison ratepayers to pay higher bundled
retail rates to pay for increments of such taxes related to the difference
between the (lower) income tax basis and the (higher) net book value
of transmission assets, as created by accelerated depreciation and normalization
accounting. FERC Docket No. ER00-3295- 000, filed July 28, 2000.
MAPP Reorganization.
The Mid-Continent Area Power Pool (MAPP) filed amendments to its basic
operating agreement that will create separate membership classes (transmission
owners, power market participants, control area operators, etc.) to allow
members to join only selected MAPP committees and thus make it easier
for them to join the Midwest ISO or some other regional transmission organization.
FERC Docket No. ER00-3369-000, filed Aug. 7, 2000.
Virtual Trading. In
a case likely overlooked amid the furor involving price caps in regional
power markets, Morgan Stanley Capital Group Inc. asked the FERC to overturn
the policy whereby the New York ISO bars power marketers and other "non-physical
participants" from the buying or selling of wholesale power at nodes within
the ISO in the ISO's Day-Ahead or Real-Time markets, but instead allows
such sales or purchases only by generators and load-serving entities.
Morgan Stanley suggested that
the ban against marketers was the reason that prices in the DA and RT
markets had not converged in the short term, as expected, since such "virtual"
trading should increase liquidity and lessen differentials between markets.
It said the ban undermines New York's wholesale electric market and imposes
financial losses on marketers and consumers, in violation of the Federal
Power Act.
The ISO countered, however,
that the FERC already had OK'd ISO tariffs that contained the ban against
"virtual" markets, and charged that Morgan Stanley was seeking only to
circumvent the ISO's FERC-approved governance procedures.
The ISO added that a substantial
majority of its senior staff favored virtual bidding by non-physical traders,
and that its Market Structures Working Group had endorsed a "staged implementation"
in reports issued in May and June. But the ISO insisted that it would
have been a risk to its "overall" market design during the peak summer
demand season. FERC Docket No. EL00-90-000, complaint filed July 5,
2000, answer filed July 17, 2000.
Expansion Plans. The
board of managers of PJM Interconnection LLC approved the final group
of elements for the first coordinated regional transmission expansion
plan developed under the PJM Independent System Operator structure, thereby
giving the green light to transmission facilities required to interconnect
over 40 new generating resources (15,000-plus megawatts of capacity) to
the grid.
PJM has received interconnection
requests for over 150 projects to be evaluated through its regional planning
process, the only one to be approved by the Federal Energy Regulatory
Commission.
Asset Characterization.
To carry out state legislation requiring electric utilities either to
divest all transmission facilities or transfer control to an independent
system operator, the Wisconsin PSC ruled that any facility that can be
networked simply by closing a switch that is normally open should be considered
part of the interconnected transmission system.
Commissioner John H. Farrow
dissented, suggesting that such switches should qualify as distribution
equipment, since utilities might want to close them to minimize a local
outage caused by a break in a radial (non-networked) feed line.
"The presence of such a switch
would not change the essential character of these lines," he noted. "Such
a shift could discourage utilities from using this method of improving
reliability."
Farrow also dissented from
the majority's finding that radial lines over 50 kilovolts must be classified
as transmission. He argued that the FERC's seven-factor test in Order
888 suggested otherwise, since, said Farrow, "there is no way" for power
to flow back out of a local distribution system through such a radial
line. No. 05-EI-119, July 14, 2000 (Wis.P.S.C.).
(In late June the Wisconsin
PSC temporarily had waived requirements for the state's five major investor-owned
utilities to meet the deadline for ceding control of the grid, noting
that the Midwest Independent System Operator was not scheduled to start
operating until Nov. 1, 2001.)
Business Wire
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EnerTech Capital Partners,
a private equity firm specializing in investment opportunities emerging
from the deregulation and resulting convergence of the energy, utility,
and telecommunications industries, has announced the final closing
of EnerTech Capital Partners II LP, bringing the new fund's
total committed capital to $234 million. Stakeholders in Capital
Partners II LP include founding investors Safeguard Scientifics
and Conectiv, plus 16 utility and energy companies worldwide
and nine financial institutions.
HoustonStreet Exchange
Inc. has entered into a memorandum of understanding with exchange
solutions provider OptiMark Inc. to give energy traders the
same tools that Wall Street traders enjoy by incorporating OptiMark's
enhanced trading platform technology into HoustonStreet.com. OptiMark
is used in some of the world's financial trading markets, including
the Nasdaq Stock Market and the Pacific Exchange.
HoustonStreet plans to incorporate OptiMark's patented matching
engine technology into its gas, power, crude oil, and refined projects
exchanges over time.
AEP-Central Power
& Light and Comision Federal de Electricidad have joined
with ABB Power Systems and EPRI to dedicate a first-of-its-kind
electrical tie using a new High-Voltage Direct-Current (HVDC) technology.
The electric tie links the transmission system of AEP with the Mexican
transmission system owned and operated by CFE. The new "asynchronous"
technology converts the formerly incompatible alternating currents
of both countries to direct current. As a result, operators of AEP's
Eagle Pass substation can allow the transfer of power between the
two countries without interrupting customers.
CMS Energy Corp.'s
independent power unit, CMS Generation Co., has brought into
commercial operation the first two gas-fueled electric generating
units totaling 370 megawatts at the Al Taweelah A2 power and desalination
facility currently under construction in the Emirate of Abu Dhabi,
United Arab Emirates. The first unit began supplying commercial
electricity on July 20, while the second unit achieved commercial
operation on July 24.
Powergen will
use Zai*Net, the energy trading and risk management package from
Caminus Corp., as a key component in its preparations for
the New Electricity Trading Arrangements in the United Kingdom.
NETA is due to begin Nov. 22 and will replace the current Electricity
Pool.
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Telco Spin-offs. The
Williams Cos. announced Aug. 8 that the Internal Revenue Service had issued
a favorable ruling on the company's proposed spin-off of its communications
business, allowing for a tax-free distribution of Williams Communications
stock to Williams shareholders. The transaction must occur within the
next 12 months under the ruling.
UtiliCorp + St. Joe + Empire.
The FERC directed the would-be merger partners to submit revised studies
so that the commission can determine if the merger of the utilities' integrated
systems will adversely affect competition in certain markets. Docket
Nos. EC00-27- 000 et al., July 26, 2000 (F.E.R.C.).
Sierra Pacific + PGE.
The FERC postponed approval of the merger of Sierra Pacific Resources
and subsidiaries Nevada Power and Sierra Pacific Power with Portland General
Electric, pending receipt of more data on how the merger would affect
competition, especially regarding the Alturas transmission line and other
facilities connecting the utilities. Docket No. EC00-63-000, July 26,
2000 (F.E.R.C.).
LG&E + Powergen. The
Virginia commission on July 21 approved the merger of LG&E Energy into
Powergen plc. The Kentucky PSC had approved the combination earlier this
year. Case No. PUA000020, July 21, 2000 (Va.S.C.C.).
Power Outages. A Texas
appeals court reversed a trial court order that had granted class action
status to multiple plaintiffs suing the local electric utility over power
outages. The appeals court ruled that common issues did not predominate
over individual interests. Entergy Gulf States, Inc. v. Butler, No.
06-99-0082-CV, Aug. 1, 2000 (Tex.App., Texarkana).
Securitization Bonds.
The New Jersey Supreme Court on July 14 said it would review a state appeals
court ruling that upheld state PUC restructuring and securitization orders
for Public Service Electric and Gas Co. The move will delay the utility's
sale of $2.5 billion of securitization bonds, along with its transfer
of generating assets to an unregulated affiliate. Opponents of the approved
restructuring plan believe that PSE&G inflated the amount of its debt
and say the PUC failed to follow certain required procedural steps.
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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