Risk
Management: Where Utilities Still Fear to Tread
October 15, 2000
By Richard Stavros
Experts debate the
value of hedging for an industry built on passing costs down the
line
Better
risk management by utilities could have prevented the financial
losses, political turmoil, and ratepayer anger that ensued in California
when power prices soared this past summer, say analysts.
But critics argue that regulators
failed to give enough incentives to utilities to hedge against the risk
of hot weather or high prices. They say that is why companies like San
Diego Gas & Electric (SDG&E) did not do more to take advantage of forward
contracts to lock in lower prices in the spring.
As a result, complaints from
ratepayers have touched off a firestorm. Some politicians have called
for a halt to utility competition and a return to monopoly regulation.
A recent report from Fitch
IBCA, Duff & Phelps sums up the opinion of the U.S. financial players
about risk management by regulated electric distribution utilities.
"By limiting the distributors'
ability to manage price risk, policy makers have forced distributors to
bear the brunt of high prices." (See "Procuring Power in California:
A Potential Stranded Cost," by Lori R. Woodland, Sept. 7, 2000, www.fitchratings.com.)
Nevertheless, California utility
regulator Richard Bilas suggests that hedging options were available.
He insists that the state public utilities commission (PUC) did offer
utilities the option of using risk management products two years ago,
but only Pacific Gas & Electric (PG&E) and Southern California Edison
(SCE) submitted a proposal at the time.
In fact, PG&E, SCE, and SDG&E
received initial authorization as far back as July 1999 to participate
in the California Power Exchange (CalPX) market for so-called "block forward"
contracts. (See Calif. PUC Resolutions E-3618, E-3620.) PG&E and SCE then
requested additional authority for expanded participation in the CalPX's
block forward market in January, months before the hot summer. That authority
was granted in March 2000. (See Calif. PUC Resolution E-3658, E-3666,
E-3672 & E-3683.)
But it was not until July 10,
2000 that SDG&E requested authority for expanded participation in block
forwards at the CalPX. That authority was granted on Aug. 3 (See Calif.
PUC Decision 00-08-021).
One can see the potential value
of such forward contracts by examining power prices posted on the CalPX.
(A "block forward" contract is a continuously traded, standardized commodity
contract for a calendar month of on-peak energy.)
Monthly average prices at the
CalPX for June show the difference between near-term and forward prices:
$197.58 per megawatt-hour (day-of market); $170.60 per megawatt-hour (day-ahead
market); $40.65 per megawatt-hour (block forward market).
July's average prices at the
CalPX show the same basic pattern: $134.53 per megawatt-hour (day-of market);
$139.78 per megawatt-hour (day-ahead market); $64.14 per megawatt-hour
(block forward market).
"I am not going to say rightly
or wrongly, but [SDG&E] has been accused of not hedging against price
spikes," Bilas adds.
Nevertheless, utility executives
complain that risk management is too expensive. They say that risk products
don't hedge against all the risks and often leave the hedger open to criticism
if the price was locked in too high and the price drops, or no risk management
was performed and the price increases.
Meanwhile, on Sept. 12, utility
executives and federal and state regulators met in San Diego to sort it
all out. Chairman James Hoecker and the rest of the commissioners from
the Federal Energy Regulatory Commission (William Massey, Curt Hébert,
and Linda Breathitt) appeared, along with U.S. Sen. Barbara Boxer and
San Diego mayor Susan Golding. So did George Sladoje and Terry Winters
from the CalPX and the state's Independent System Operator (ISO). Also
appearing were Robert Levin from the New York Mercantile Exchange, Michael
Kahn from the state's Electricity Oversight Board, plus key executives
from Enron, Reliant, Duke Energy, and the three big California electric
utilities. The meeting may well have decided the future of utility competition-at
least in California.
Ratepayers
vs. Shareholders: Which Group at Risk?
Utility commissioner Bilas
explains that when the PUC designed its electric restructuring plan, it
assumed that the price for power purchased from the CalPX would always
be deemed "just and reasonable," under regulatory law. That means that
ratepayers of utility distribution companies eventually will have to pay
for the high prices seen this summer in California's market.
"The ratepayer will be likely
to pay unless we at the PUC find that the procurement procedures on the
part of SDG&E were not good and they were liable for those dollars," he
explains.
Notwithstanding, as the magazine
went to press, the PUC had ordered an investigation into the "prudence
and reasonableness" of SDG&E's wholesale energy purchases. In fact, Bilas
says that utilities would be "foolish" not to implement risk management
procedures after what happened during the last two summers.
Bilas believes the biggest
mistake the PUC made was to call for a power exchange like the one in
Great Britain. He now thinks alternative exchanges should have been allowed
to develop according to the market's design rather than through central
planning.
"Had we had alternative exchanges,
the market would have worked this summer. But that is like closing the
barn door after the horses left," he says.
David Shimko, senior lecturer
at Harvard Business School and partner at Risk Capital Management, a boutique
risk management consulting firm, says liquidity remains the biggest problem
for CalPX.
"There are four major utilities
using the PX. If they trade large blocks, what happens on the margin price
of a megawatt-hour may be plus or minus 25 cents on a single trade for
a one-hour block. But when you get these massive 1,000-hour blocks trading,
we have noticed that there is a 17 percent difference between the bid
price and the offer price," he says.
Shimko believes the answer
ultimately lies in consumers knowing the different kinds of contracts
they can use.
"Where I see the future of
Southern California is in utilities offering their retail clients fixed-price
contracts. That would be a more efficient way of hedging their risks than
using the Power Exchange," he predicts.
The
Distribution Utility: Wrong Place for Hedging?
"I still believe that if you
want to replace the obligation to serve with contractual obligations,
you are getting into an area that is inviting lawsuits, litigation, and
cross claims." That comes from Mike Shore, executive director of gas management
services for Consumers Energy, the electric and gas utility business owned
by holding company CMS Energy.
Shore believes that market
participants will increasingly walk away from a contractual obligation
if there is money in doing so. But that is an option unavailable to a
distribution utility like Consumers Energy, because of its legally mandated
duty to serve.
"We go out and do our job and
we make sure customers get their gas service and we don't say that it
cost us too much, and we are not going to do that anymore," he says.
Shore points out that in Michigan,
the state utility commission has recognized the value in risk management
products such as options, puts, calls, and futures contracts, which Consumers
Energy has used. However, he notes that his company's risks have increased
fivefold as a result of being the supplier of last resort.
"What has happened now is that,
in addition to managing the supply, we are responsible for buying and
coordinating with all these other people that are bringing in gas, and
having to make sure they are performing," he says.
Shore says that trying to track
the multitude of various suppliers, their obligations, and their customers
has made things more complex and fundamentally changes the company's approach
to the business.
Although having used risk management,
Shore says that ultimately there is nothing that can be done to prevent
the market from dictating the price of the commodity to everyone.
"To the extent that you try
to use fixed prices to protect yourself, if prices go down you are exposed.
If you use price protection and prices go up, you look good. If you tie
yourself to an index price, you are subject to the volatility of the market,"
he observes.
Not
Worth the Trouble?
A report from Fitch says hedging held "limited value" for Edison, and
wouldn't have helped much for SDG&E.
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In a report issued Sept.
7 on the fallout from California's summer of high power prices,
Fitch IBCA, Duff & Phelps states that the best way to offset price
risk is to "procure power through owned or contractual access to
generation." In other words, own or rent the hard asset.
By contrast, says Fitch,
"liquid financial hedges are limited. The NYMEX [futures] contracts
have limited reliability, as they remain largely illiquid." With
that said, Fitch praises the hedging strategy at Southern California
Edison (SCE), but says it offset only a fraction of Edison's exposure.
Fitch adds that even if SDG&E had turned earlier to block forwards
at the CalPX, it wouldn't have helped much either.
Unable to enter
into bilateral agreements earlier this year, SCE was prudent in
purchasing gas call options. There is some correlation between
gas and electricity prices. ...
This year, however,
the price of power rose far higher than the price of gas in California.
The fair value of SCE's gas call options rose from $21 million
at June 30, 1999 to $99 million at June 30, 2000. While an impressive
increase in their mark-to-market value, the options still hold
limited value relative to the $644 million transition revenue
account undercollection recorded at June 30, 2000. Purchase of
the gas call options has also required PUC approval, thereby limiting
a utility's ability to move quickly. ...
SDG&E was authorized
to purchase a small percentage of its summer supplies through
forward contracts this past spring, but did not. In hindsight,
these purchases would have helped but the net financial effect
would have been small.
Source: "Procuring
Power in California: A Potential Stranded Cost," Fitch IBCA, Duff
& Phelps (analyst: Lori R. Woodland), Sept. 7, 2000, www.fitchratings.com.
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Furthermore, he believes that
the increased number of commodities traders makes it difficult to secure
gas at a reasonable price.
He says that if the only people
playing in the market were the local distribution companies (LDCs), General
Motors for its gas needs, and Texaco and Amoco for their gas sales, the
gas market would be more stable.
"But the market is just plagued
with traders who have absolutely no use for natural gas, and all they
have use for is money. [They] make it absolutely miserable for those of
us that absolutely need the commodity," he says.
Nevertheless, Shore is hesitant
to draw conclusions as to whether competition has been a success or not.
"We don't know what the value
is because we are still in the learning stage. It is a transitional period,
and I don't know if we can draw conclusions yet."
Software
and Tools: Out of Reach for Utilities?
Some experts say that if regulated
utilities had more access to the sophisticated equipment that unregulated
subsidiaries have, managing and purchasing weather and price risk management
tools might be easier.
David Johnson, partner at Arthur
Andersen's Risk Consulting Practice, explains that the technology in place
at most regulated utilities is not focused on managing market risks inherent
in electric competition.
"In regulated utilities you
have logistic systems-which are involved in scheduling and moving product,
customer billing systems, and forecasting models so that you can forecast
load. What you do not often see is a process that looks at market prices
into the future," he explains.
Johnson says that regulated
utilities are not making decisions routinely about the forward markets
and their impact on fuel acquisition plans and fuel sale plans.
"In a deregulated marketplace,
you have to have the tools and capabilities to react to the forward marketplace
and respond to what it is telling you," he says.
That is why bringing risk management
systems into a regulated utility is so crucial to understanding the ramifications
of the forward market on your portfolio, Johnson adds.
Richard McMahon Jr., group
director at the Alliance for Energy Suppliers, a division of the Edison
Electric Institute, says that the technology could make it more cost effective
for both sides of the transaction. Furthermore, he believes that the emergence
of new online markets should make hedging easier for utilities, even if
they lack the expertise of their unregulated marketing and trading subsidiaries.
"I don't think you need to
have the same level of sophistication in terms of technology and investment
on the distribution side to be able to hedge and take advantage of the
market," he points out.
Furthermore, most experts say
that many companies now offer risk management and weather derivative evaluation
software that can be installed on almost any personal computer.
For example, Cameron Rookley,
financial economist at Caminus, is part of a team that has developed a
risk management software system known as WeatherDelta, which includes
a set of tools to perform a "bottom up" micro level analysis of the impact
of weather on load, generation, retail contracts, and traded positions.
"By empirically capturing as
many statistical properties in the data as possible, you really start
to get an idea of what types of risks you are facing," says Rookley.
He adds that the program can
help utilities by exploiting market forward curves, and discern between
buying different mixes of forward fixed-price contracts and weather hedges.
WeatherDelta allows for the valuation of a variety of assets and obligations,
such as full-requirements deals, interruptible service contracts, physical
assets, and hourly options. Baskets of such contracts are valued simultaneously
such that overall profit and loss distributions can be obtained, analyzed,
and subjected to a variety of what-if scenarios. Rookley adds that WeatherDelta
takes the level of analysis down to the hour, where a lot of real-time
risk transpires.
WeatherDelta contains an hourly
weather simulation engine that has been statistically built from 37-40
years worth of hourly data for over 200 locations in the continental United
States, he says.
Learning
How to Hedge
How one utility lost its bet on the spot market but
won over the PUC.
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Before San Diego Gas
& Electric made headlines in electricity, there was Public Service
Company of New Mexico, on the gas side. In the mid-1990s PNM turned
to spot markets in search of bargains for natural gas procurement,
but got burned by high gas prices during the winter of 1996-97.
Now, says Tim O'Brien, general manager-gas acquisitions at PNM,
his company has emerged with a stronger risk management culture.
O'Brien remembers how
customers complained, asking the utility to explain the price spikes.
"Were they national prices?
Were they regional prices? Was [PNM] marking up the price? It was
a difficult time for us."
The former New Mexico
PUC (since renamed the Public Regulation Commission) then launched
an investigation of gas procurement. But as O'Brien explains, the
old PUC actually favored hedging and supported PNM's reliance on
spot markets as the best long-term bargain.
"The old commission mandated
by order that we use [price hedging]. What turned out," says O'Brien,
"was an in-depth study looking at the market for natural gas-what
led up to the higher prices, what could impact prices, what kinds
of hedging tools were out there."
O'Brien remembers that
workshops with the attorney general and the PUC gave PNM an opportunity
to engage the PUC staff and the AG on the essence and merits of
hedging. That led PNM to take additional steps to mitigate high
winter heating bills.
"We had long billing
periods for December and January, the two coldest months, which
have 31 days each. With all the holidays, some of our bills were
extended over too long a time." PNM decided to smooth out winter
bills. If gas price (per million Btu) went from $4 to $6, rather
than charging $6 in December,
PNM might decide to smooth
that price over five or six months, O'Brien explains.
Crystal McClernon, director
of public affairs at PNM, says that the company also has stepped
up the amount and timing of information it provides the public when
high gas prices are expected.
"Basically we start talking
about high [winter] gas prices in June. We work with local news
media and get coverage as early as June." -R.S.
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Volatile
Earnings: A Better Reason to Hedge?
Financial analysts say that
shareholders no longer will stand for unpredictable earnings due to weather
or unexpected commodity costs, forcing utilities to hedge their risks
in a competitive world.
Mark Williams, vice president
of risk management for Boston-based Edison Mission Marketing and Trading,
says with 40 percent annualized volatility in fuel inputs such as oil
and natural gas and over 100 percent volatility in electricity prices,
shareholders are becoming more aware of the earnings uncertainty associated
with utilities.
"When you go to Wall Street,
you have institutional investors that are very concerned about unexpected
price and earnings volatility and consequently focused on utilities' ability
to meet or beat profit and loss targets," he explains.
In fact, Williams says, in
the new environment shareholders will penalize utilities that do not effectively
manage their earnings volatility. Instead, to manage this risk, he believes
utilities are beginning to accept the earnings-at-risk (EaR) idea as a
more comprehensive measurement.
The Ear concept, unlike value
at risk (VaR), is used as a longer-term risk measurement to estimate and
manage earnings volatility. And unlike VaR, which measures a period no
more than days, Ear measures earnings volatility over monthly, quarterly,
semi-annual, and annual time periods.
The calculation of Ear usually
is overseen by a company chief financial officer or treasurer, and is
becoming a standard practice in the more sophisticated companies, according
to Williams. He adds that Ear is versatile, as it can be used to focus
closely on the cost side (price and volume of the input fuel) as well
as on the revenue side (price and volume of output).
Furthermore, he says, Ear is
the most appropriate measure to use since utilities owning generation
do not calculate the risks of their generation portfolio on a value-at-risk
basis because generation has accrual accounting treatment and is not marked-to-market
for balance sheet or income statement purposes. (To "mark to market" is
to calculate the value of a financial instrument or a portfolio of such
instruments at current market rates or prices of the underlying.)
That is why many companies
are coordinating their Ear calculation with their hedging, budgeting process,
and risk management strategies, Williams says. Without risk management,
he notes, margins get squeezed, making it more difficult for utilities
to manage those margins.
Glen Sweetnam, director of
weather derivatives for Reliant Energy, offers a slightly different perspective
but also appears to recommend hedging for utilities to avoid earnings
volatility and thus enhance stock price performance.
"I think you want to think
very carefully why the shareholders own the stock. If they own the stock
because the utility has predictable earnings and you have the operation
to grow, then earnings hedges make a lot of sense," he says.
Sweetnam believes that investors
who buy utility stock want to be insulated from weather risk. To underscore
that point, he contrasts utility equities with stock in oil and gas exploration
and production companies. Investors in those E&Ps understand that they
are taking on weather risk. That's the point, but it doesn't hold true
for gas utilities, says Sweetnam.
"I have never heard of anybody
saying that it is going to be a cold winter so let's buy [stock in] gas
utilities," he remarks.
Moreover, he believes that
utilities can benefit by hedging against weather-driven earnings fluctuations,
even though PUCs still impose weather normalization clauses in rate cases.
He recommends that utilities use weather hedges in concert with a price
hedge to obtain the best protection from price and volumetric risk.
"Most utilities are in a regulatory
regime where they pass along the price that they purchased the gas for
to the customers. But what they can't pass along is the weather risk.
If it is mild and they don't have as much volume, the variable component
of their revenues of their throughput tariff is less than it otherwise
would be," says Sweetnam.
Weather
and Prices: The Limits of Hedging
Mark Tawney, director of the
weather risk management group of Enron Global Markets, explains the difference
between hedging against high demand induced by extreme temperatures and
hedging against price spikes, which may or may not stem from the weather.
"SDG&E would have been able
to partially hedge their volatility with a weather derivative. You had
exceptionally high demand as a result of high temperatures. A weather
hedge would have helped them against the increased demand caused by high
temperatures but it would not have hedged them against the price spikes,"
he says.
To manage the price spikes,
a utility would have had to enter into price hedging, he adds.
Back at Consumers Energy, Mike
Shore is still not convinced of the full advantages of weather derivatives
and price risk management.
"The only way you can get a
perfect hedge is if you are willing to spend all the money you have got
to protect against that. A perfect hedge is taking all the money that
you made in profit to protect against a risk that maybe you bet wrong,"
he explains.
Shore also believes that weather
insurance products are still too expensive and end up benefitting the
insurance company and not the customer. He says that the weather derivatives
market is also expensive and too illiquid, but adds that he would consider
transacting weather derivatives when the weather market matures further.
"At this point we have not
taken advantage of these products. That does not mean we won't. We will
continue to look at them," he says. But Enron's Tawney says that a utility,
when evaluating whether to purchase a risk management tool, should not
solely consider price but how the hedge allows the company to do other
things from a strategic point of view. Tawney notes, for instance, that
risk management tools can make financing cheaper. He advises executives
to think of risk management in the same light as homeowner's insurance.
"If you are looking at the
purchase of homeowner's insurance as a trade, that is a terrible trade.
The insurance company will win every time on that trade. But you and I
have an aversion to a total loss of our home and our lender's aversion
to that same eventuality," he explains.
Moreover, Reliant's Sweetnam
is not surprised to hear that utilities are still somewhat skeptical about
risk management. In the area of weather, he estimates that the weather
risk for gas utility distribution businesses is $1.2 billion. Furthermore,
he says that only 25 percent of this risk has been hedged in the past
or for the coming winter.
Sweetnam offers four reasons
why gas utility executives have not used weather derivatives. First, they
haven't quantified the risks. Second, they're nervous about the market;
it's small but just complicated enough to make things difficult. Third,
they're still uncomfortable with derivatives, at least at the corporate
level. Fourth, they still see hedging as too expensive.
Richard Stavros is senior
editor at Public Utilities Fortnightly.
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