**NATURAL GAS PRICE VOLATILITY:**

**REGULATORY POLICIES TO ASSURE AFFORDABLE AND STABLE GAS SUPPLY
PRICES**

## FOR RESIDENTIAL CUSTOMERS

**Barbara R. Alexander**

**Consumer Affairs Consultant**

January 2004

Barbara R. Alexander opened her own consulting practice in March 1996.
From 1986-1996 she was the Director, Consumer Assistance Division, at
the Maine Public Utilities Commission. Her special area of expertise has
been the exploration of and recommendations for consumer protection,
universal service programs, service quality, and consumer education
policies to accompany the move to electric, natural gas, and telephone
competition. She has authored AA Blueprint for Consumer Protection
Issues in Retail Electric Competition@ (Office of Energy and Renewable
Energy, U.S. Department of Energy, October, 1998), available at
<http://www.eere.energy.gov/electricity_restructuring/toc.html>. In
addition, she has published papers that address price volatility and
consumer benefits associated with the provision of Default Electric
Service: <http://neaap.ncat.org/experts/defservintro.htm> Her clients
include national consumer organizations, state public utility
commissions, and state public advocates.

This report was prepared under contract with

Oak Ridge National Laboratory Energy Division

UT-Battelle, LLC

Subcontract No. 4000014875

The opinions and conclusions expressed in this report are

those of the author alone and do not represent

the views of Oak Ridge National Laboratory or the

U.S. Department of Energy

**INTRODUCTION**

Natural gas supply prices are headed up to potentially record setting
levels again this winter, according to experts and observers. Natural
gas distribution companies (NGDC) have filed for significant price
increases for the natural gas supply portion of customer bills in most
states. Politicians and regulators at both the state and federal level
of government have warned consumers about high prices this winter, held
public educational meetings to urge consumers to conserve natural gas
and enter into budget or levelized payment plans, issued press
advisories, and contemplated long term and significant natural gas
supply options, such as increasing reliance on imported liquefied
natural gas and creating federal subsidies for a natural gas pipeline
from Alaska to the mainland U.S. The upswing in natural gas supply
prices is typically blamed on the lack of sufficient exploration and
drilling of U.S. natural gas fields, i.e., a shortage of supply, as well
as the increased usage of natural gas to generate electricity and power
industrial operations, i.e., an increase in demand.[^1]

As usual with natural gas pricing, the weather plays a major role. An
unusual late cold spell in the Northeast in 2003 resulted in the draw
down of stored gas to very low levels, resulting in very high prices to
replenish this storage capacity during the summer, a period when
traditionally gas prices drop. These factors led to record setting spot
market prices at various times in 2003. In December, prices for natural
gas futures on the New York Mercantile Exchange (NYMEX) were hovering at
\$7 per thousand cubic feet, sparking calls from some Capitol Hill
veterans for an investigation.[^2] Natural gas prices have moved to a
new potentially sustainable level above \$4/MMBtu.[^3] Observers
question whether this is a spike similar to that which occurred in late
2000-early 2001 or whether these higher prices are here to stay,
creating a new higher level plateau within which the traditional
seasonal volatility of natural gas prices will swing.

These events are occurring in an industry that is widely regarded as
having achieved a workable competitive wholesale market as a result of
policies adopted by Congress (prices at the wellhead, i.e., the locus of
production, were deregulated by the Wellhead Decontrol Act of 1989) and
the Federal Energy Regulatory Commission, which regulates the prices
charged for the transmission of natural gas through interstate
pipelines. FERC has consistently followed a policy to "deregulate" the
interstate market for natural gas supply. The pipeline owners were
pressured to renegotiate long term supply contracts and local natural
gas distribution companies, whose rates are regulated by state
regulatory commissions, were forced to obtain natural gas supplies on
the open market where the price is set by the law of supply and demand.

Recent developments in both natural gas and electricity markets have
called into question the transparency and competitive nature of
wholesale energy markets. The following events and developments have
contributed to an aura of suspicion that natural gas price spikes are
not entirely "natural": (1) allegations of price manipulation in natural
gas pipeline prices in the West; (2) the California electric market
implosion (caused in part by extremely high natural gas prices) in
2000-2001; (3) the financial meltdown of many energy companies,
particularly the competitive electric generation companies; and (4) the
significant decrease in wholesale "trading" for both natural gas and
electricity. When suspicions concerning the operation of the wholesale
market are coupled with the impact of higher prices on residential and
low-income customers in a time of record job losses and economic
stagnation, a recipe for controversy is easily brewed.

Also key to the concern about higher prices for residential customers
are several factors that reflect their usage profile and dependence on
natural gas for home heating. First, residential customers typically
rely on natural gas for home heating and so their need for this product
at particularly vulnerable circumstances results in significant risk of
health and safety when natural gas is priced too high to provide
affordable home heating. Unlike industrial customers who use natural gas
year-round and can make investments and long term plans based on this
known need, residential customer usage for natural gas spikes every
winter and is typically a direct function of weather. Second,
residential customers are not particularly responsive to price spikes
because they do not have what economists call "elasticity of demand."
Residential customers cannot typically change out the fuel necessary to
generate winter heating without great expense and significant lead time.
Nor can they access more efficient appliances or weatherize their homes
without significant investment. Of course, low-income and working class
consumers have even fewer options in this regard because they rarely
have access to the additional cash or means to invest in these
improvements. Third, the residential natural gas customer's bill is
greatly influenced by the price of natural gas supply. Over 50% of the
average bill is driven by the price of natural gas supply and the
pipeline transportation costs incurred to deliver that product to the
"city gate", where the local gas utility takes control. The balance is a
reflection of local distribution costs incurred by the NGDC to deliver
and operate the local distribution system, and bill and collect from its
customers. This percentage is even higher in some states particularly in
the winter where residential customer usage dramatically increases.

According to a recent General Accounting Office report[^4] on state
natural gas price changes, many gas utilities and state commissions have
endorsed at least a partial reliance on various forms of "hedging" or
gas supply portfolio management by the incumbent natural gas utilities.
In a survey of state decisions and policies adopted after the price
spike of the 2000-2001 winter, the GAO reported that:

-   Most states (82%) price natural gas supply by means of a Purchased
    Gas Adjustment mechanism with a reconciliation of actual and
    estimated costs. Only 3% rely on a fixed price for natural gas
    supply and 9% use of an incentive or Performance Based Rate
    approach.

-   Frequent price changes are the norm, with 59% using monthly price
    changes, 36% quarterly price changes, 1% semi-annually, and 9% using
    annual price changes.

-   After the 2000-2001 price spike, the GAO report documented the
    growing use of hedging and approval of financial hedging
    instruments. While only 20% of the larger gas utilities responding
    to the GAO survey reporting that before the price spike of
    2000-2001, they had planned to hedge any of their gas supply, 90% of
    all utility companies reported that they had decided to hedge some
    portion of their gas supply before the winter of 2001-2002.[^5]

-   The report also documented the key role of storage facilities in the
    ability of the gas utility to manage its gas supply for price
    stability.

-   Those utilities with access to local production were also favored,
    because they could avoid the costs associated with transportation of
    natural gas through interstate pipelines

This report will use the term "hedging" to refer to the management of a
gas portfolio to mitigate price volatility, i.e., the use of both
physical and financial instruments to avoid a total reliance on spot
market acquisitions. Physical hedging occurs when a utility buys a
contract for future delivery of gas at a set or indexed price. This may
or may not be coupled with the used of stored gas. This might result in
a staggered series of contracts for natural gas supply that are bought
early in the year for delivery at a fixed price later in the year during
the winter heating season or the use of even longer term fixed price
contracts from a supplier or pipeline owner. Financial hedging occurs
when a utility purchases natural gas derivatives, which are contracts
whose market value is derived from the price of the gas itself.
Derivatives can be bought and sold through numerous sources, such as
NYMEX and other over-the-counter marketers. Two basic types of
derivatives include natural gas futures and options. A futures contract
is a promise to deliver gas in the future on price set or a price
formula set in the contract. This type of instrument can either result
in the delivery of the product or the payment of cash. An option
contract gives the buyer the right, but not the obligation, to buy or
sell gas at a specific price on or before a specific date.

In addition to tariff adjustments that pass through the actual cost of
gas (whether based on hedged products or spot market acquisitions) with
frequent price changes, most states also conduct a reconciliation
proceeding at least annually. This proceeding compares the amount
charged to customers for natural gas supply with the actual costs
incurred by the utility, which may reflect increased or decreased sales
depending on the weather or rapid changes in natural gas costs that
occur during the period of time the approved price is in effect. This
approach typically means that commissions allow the utility to build up
a balance that is owed to customers (refund) or a deferral that is owed
by the ratepayers to the utility. This approach has been used as a means
of spreading out significant price spikes so that the utility is allowed
to charge somewhat less than the actual costs incurred and then bill
customers for the deferred balance at the end of the winter period.

Another key variable in how states approach the pricing of natural gas
supply is the presence of retail natural gas competition. While many
states have initiated pilot programs or voluntary customer choice
programs on a utility-by-utility basis, only a few states have mandated
retail natural gas competition for residential customers as the "law of
the land": Ohio, New Jersey, Pennsylvania, Georgia, and the District of
Columbia,. Several other states have "virtually"[^6] restructured with
programs in place that make all residential customers eligible:
Massachusetts, New York, Michigan, Maryland, and Virginia.

According to statistics maintained by the Energy Information
Administration (EIA)[^7] at the Department of Energy, there are far more
residential customers who have entered the competitive natural gas
market and selected an alternative to their incumbent utility than have
entered the retail electric market. According to EIA, as of December
2002, 4.1 million residential customers have enrolled with a competitive
natural gas supplier, approximately 13.5% of the total eligible to do
so. This contrasts with the retail electric shopping statistics that
show that in most states, 95% of the residential customers who are
eligible have not left their incumbent electric utility. The only
exceptions are in Texas (7-8%), the District of Columbia (12%),
Consolidated Edison in New York, and in some utility service territories
(Duquesne Light and PECO Energy) in Pennsylvania.

States have typically required the NGDC to obtain supply from the
wholesale market and pass through that price to retail consumers. State
commissions are often at great pains to explain to the public that the
local gas utility does not make a profit on the sale of natural gas and
that states do not directly regulate the price of natural gas
supply.[^8] However, state regulators do have authority over the gas
procurement practices of local gas utilities that are the focus of this
paper and are responsible for answering the following key questions that
affect the prices that are charged to consumers:

-   Should the NGDC base its procurement strategy on short-term
    wholesale market prices, i.e., on contracts and supply options that
    are typically less than one year and may rely in large part on
    monthly acquisitions or should state regulators require NGDCs to
    emphasize long-term price stability and enter into longer term
    contracts for at least a portion of the known customer load?

-   How often should retail prices change to reflect changes in the
    wholesale price of natural gas supply---monthly, quarterly,
    annually?

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-   How should the impact of weather be reflected in natural gas pricing
    policies?

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-   Should gas supply prices for retail customers be fixed or estimated
    and then reconciled based on actual costs incurred by the NGDC?

-   What should be the relationship between the procurement and pricing
    policies imposed on the NGDC and the existence of a competitive
    market at the retail level for customers? And should the answer to
    this question differ for larger customers versus smaller commercial
    and residential customers?

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-   Should state regulators pre-approve NGDC procurement plans or even
    specific contracts?

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-   Should utilities be rewarded or provided incentives for achieving
    price stability or meeting certain hedging targets?

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-   Should NGDC be allowed or encouraged to use financial instruments as
    part of their gas procurement tools, as well as the more traditional
    contracts for the physical storage and delivery of natural gas?

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-   Should regulators approve fixed price "options" or "price protection
    plans" for residential customers as a means of responding to natural
    gas market volatility?

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-   Should state regulators require NGDCs to invest in energy efficiency
    and demand reduction programs as a means of addressing gas price
    volatility? If so, how should rates be set to reflect the impact of
    such programs in reducing sales, thus reducing profits, for the
    NGDC?

The purpose of this paper is to examine how some representative states
in each of the regional natural gas markets have answered these
questions and to offer preliminary observations and recommendations on
state regulatory policies for the procurement and pricing of natural gas
supply for residential customers. This paper does **not** address how
state commissions or gas utilities should create or implement programs
for individual residential customers that respond to gas price
volatility or high gas supply prices, such as budget billing mechanisms,
low income bill payment assistance programs, and implementing voluntary
bill or usage reduction measures. Rather, this paper focuses on state
regulatory policies that impact the prices charged to residential
customers and not how residential customers can respond to high natural
gas prices once they appear on the bill.

> **CASE STUDIES OF STATE POLICIES CONCERNING THE PROCUREMENT**

**AND PRICING OF NATURAL GAS SUPPLY:**

**OBSERVATIONS AND RECOMMENDATIONS**

The following summaries of state natural gas procurement and pricing
policies demonstrate a wide range of approaches in states that have
significant differences in natural gas supply costs, in their
implementation of retail competition for residential and small
commercial customers, and in the state's philosophy concerning price
stability and the use of financial hedging instruments. The case studies
are grouped by the following geographic regions:

New England: Massachusetts, Rhode Island, and Connecticut

Mid-Atlantic: New York, New Jersey

South: West Virginia, Arkansas

Midwest: Michigan, Indiana, and Ohio

West: Oregon

Southwest: Arizona

**Key Observations**

-   The research and data gathered for this report from the various
    state regulatory commission orders, websites, and other documents
    suggests that it is very difficult to gather comparable data on
    retail natural gas supply prices or to compare this data with that
    gathered and reported at the federal level by the Energy Information
    Administration (EIA). The EIA retail natural gas supply pricing data
    is gathered from utilities who return an EIA survey and presents
    average retail price data by means of a simple division of sales and
    revenues for residential customer classes. As a result, the EIA data
    does not reflect individual utility residential customer class rates
    approved by state regulatory commissions and a comparison among the
    various natural gas utilities within a single state is not possible.
    Most states do not publicly maintain pricing data that breaks down
    the components of the natural gas distribution company monthly bill
    and those states that do track and publicly report such data often
    do so in a manner that does not allow easy comparisons with other
    states. This report reflects retail pricing data gathered from state
    public utility commission websites and attempts to convert the state
    price data into a cents per CCF (hundred cubic feet) format, even
    though states and NGDCs often use a cents-per-therm pricing format
    in tariffs and customer bills. All per therm prices were converted
    to CCF prices by multiplying the cents per therm by 1.029.

-   In general, the traditional method of pricing natural gas supply
    transfers most of the risk of price volatility and short-term price
    changes in the wholesale natural gas market to retail customers.
    This is true in most states whether or not retail natural gas
    competition has been adopted as the regulatory philosophy or state
    law. Unlike electricity supply, however, natural gas supply costs
    are typically over 50% (60-80% in the winter) of the residential
    customer bill so that this emphasis on price volatility and frequent
    price changes has a significant impact on residential customers
    whose usage pattern (dominated by winter heating) creates a
    dependency on natural gas at the exact time it is most costly. The
    impact of the weather, over which no customer has the ability to
    control, only exacerbates this impact.

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-   There is a remarkable lack of stated regulatory policies with
    respect to the procurement of natural gas supply. State regulatory
    commissions appear to treat the purchase of natural gas supply as
    not subject to their regulatory control even though the retail
    provision of natural gas service is fully "regulated" by state
    authorities in every state that was studied. State regulators have
    typically deferred to short term procurement policies in general and
    have only recently and only in a few jurisdictions explored the
    actual policies and programs that should be in place to govern the
    acquisition of this commodity for sale to end-use customers. While
    natural gas utilities do not own the gas producing wells or the long
    distance pipelines that transport the gas to the NGDCs, they have
    the ability to buy long term contracts, build or contract for
    storage, manage a portfolio of both physical and financial gas
    supply products, and, in some cases, sell natural gas for a profit
    to other wholesale customers. The implications and responsibilities
    of state regulatory officials for the procurement policies that
    should govern this activity, particularly with respect to
    residential customers, is not widely discussed in either
    rulemakings, policy papers, or specific NGDC decisions.

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-   Unlike residential customers, utilities have the ability to
    [manage]{.underline} gas supply costs. In part, this is due to the
    fact that natural gas can be stored for use at a later time, a
    factor that distinguishes natural gas supply from electricity. This
    means that utilities can physically purchase natural gas in advance
    of its use by retail customers and store this gas until it is pumped
    through its distribution system to retail customers. In addition,
    utilities can acquire a mixed or balanced portfolio of physical and
    financial contracts, storage options, fixed and variable priced
    contracts, short and long term contracts. This approach is more
    likely to be followed when the regulatory commission has adopted an
    explicit policy that favors price stability over time and engages in
    rigorous review and analysis of natural gas procurement decisions
    that document imprudent behavior and disallow excess costs when the
    utility has failed to follow established policy to hedge gas prices
    to mitigate price volatility. The states that have initiated a
    significant effort to regulate the NGDC's procurement of natural gas
    supply and emphasized the need to manage this procurement function
    to achieve specific policy objectives include Indiana, Michigan,
    Rhode Island, Arkansas, and Arizona. These states have demonstrated
    that they can provide natural gas supply at more stable or even
    lower prices either in comparison with neighboring states or by
    comparing individual NGDC prices with those in effect at an NGDC in
    the same state. For example, in Indiana NIPSCO's failure to engage
    in gas procurement management and hedging resulted in higher prices
    than other Indiana NGDCs. In Rhode Island, the regulatory commission
    has documented that it's more proactive approach to gas supply
    procurement practices by its largest natural gas utility has
    resulted in lower and more stable prices than those passed through
    to residential customers in Massachusetts.

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-   In some states, the use of multi-year performance plans, rate
    freezes, or price caps for the total natural gas bill, including the
    natural gas supply portion of the bill, has resulted in at least
    temporary price stability for residential customers. Of course, any
    price cap or rate freeze that was in effect during the 2000-2001
    winter generally operated as a "win" for ratepayers. The propensity
    of NGDCs to enter into such rate caps or rate freezes since that
    period has lessened. Also evident is that when the NGDC emerges from
    the price cap or rate freeze period, customers are typically in for
    a significant jump in natural gas supply prices. States in which the
    operation of rate caps or price freezes can be evaluated include
    Michigan, West Virginia, New York, Rhode Island, and Oregon.

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-   States that have adopted retail natural gas competition as an
    overriding policy objective typically have more volatile natural gas
    prices and higher prices generally compared to the other states
    reflected in this study. The implementation of retail natural gas
    competition for residential customers leads to the logical
    conclusion that (1) customers should see the "real" market
    price; (2) marketers should be responsible for offering fixed prices
    or more stable prices if that is what customers prefer; and (3) the
    price of natural gas supply should change frequently so that
    customers can make decisions in their usage and their selection of
    alternative services in the face of market conditions. Under this
    philosophy, it is not the responsibility of the incumbent gas
    utility to protect its customers from volatile prices or engage in
    substantial hedging activities that might prevent the "real" market
    price from appearing on customer bills. This approach is readily
    apparent in Massachusetts and Ohio. However, some states that have
    adopted vigorous natural gas competition programs have also
    initiated such programs with multi-year rate plans or rate freezes
    for incumbent gas utilities that have resulted in low and stable
    prices for residential customers who remain with the incumbent
    during this transition period. This has occurred for some gas
    utilities in New York (particularly the upstate region) and in
    Michigan. Unfortunately, when the New York utilities transitioned
    out of these price freezes or rate stability plans, the state
    commission allowed a significant increase in natural gas supply
    prices to reflect the then-current wholesale market prices, thus
    contributing to a significant change in retail prices.

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-   States that have adopted portfolio management and hedging have
    uniformly acknowledged that such an approach will not necessarily
    result in the lowest possible price at any one point in time. In
    other words, there is a cost to portfolio management and price
    stability in the form of a slightly higher price than may be
    achievable over any particular short period of time using the spot
    market. The opposite may also occur. Furthermore, utilities incur
    administrative or management costs associated with hedging and
    portfolio management that are typically included in the gas cost
    recovery mechanism. These costs are obviously theoretically lower if
    the utility can take advantage of a multi-state management by a
    parent company or affiliate because those costs can be spread among
    a larger number of ratepayers, although most state commissions do
    not identify these costs or potential savings in their decisions. On
    the other hand, regulatory commissions may not be particularly
    skilled in the ability to audit and oversee the more sophisticated
    financial hedging programs without the investment in either
    consulting assistance or additional staff training. For examples of
    state policies that recognize the importance of price stability in
    the NGDC procurement function, as well as the costs associated with
    the portfolio management programs, see Arizona, Indiana.

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-   States that have not emphasized portfolio management and price
    stability per se are more likely to allow the NGDC to offer
    voluntary options to residential customers, such as a fixed price
    option (typically over a 12 month period that begins in the fall) or
    a "weatherwise" product that offers bill stability. Under these
    programs, the gas utility offers residential customers an option to
    enter the program at a specific price, which is often higher than
    the price in effect during the fall and the beginning of the new gas
    price "season." Such programs are often accompanied by limits on
    participation or viewed as "pilot" programs. However, marketers in
    states that have adopted retail natural gas competition (such as in
    Ohio and Massachusetts) vigorously oppose these options.
    Furthermore, it is not clear why such products cannot be purchased
    for all residential customers rather than a small subset of those
    who voluntarily elect this option.

-   There is a remarkable lack of analysis and discussion of the effect
    of energy efficiency programs and efforts as a means of ameliorating
    price volatility or as a substitute for buying natural gas supply
    "on the margin" in times of high prices and tight supplies. While
    "interruptible" rates and services are routinely offered to larger
    customers, they are not offered to residential or small commercial
    customers. Nor have regulatory commissions analyzed purchasing
    decisions based on energy efficiency or interruptible load
    alternatives. The only program that even discusses these connections
    is the Oregon partial decoupling program adopted for Northwest
    Natural Gas Co. for a three-year period in 2002. The more typical
    state approach is to require a certain amount of spending on energy
    efficiency by gas utilities as a form of public benefit funding that
    is never discussed or analyzed in the context of the acquisition and
    pricing of natural gas supply. No regulatory commission has asked
    the question, "What would residential customers pay for a voluntary
    reduction in usage at certain times in return for a lower price?"
    Or, "What would be the impact on the price of natural gas if the gas
    utility engaged in a dramatic effort to install energy efficient
    appliances at a subsidized cost at a time of rising prices and
    increased gas price volatility?" Rather, it is universally assumed
    that residential (and small commercial) load is "firm" and must be
    served at the demand level of those customer classes and the
    exhortations for energy efficiency and conservation are typically
    limited to energy reduction rather than energy efficiency. Most
    every regulatory commission has a press release, conference, or
    publication available on its website to prepare customers for higher
    gas prices. Most of the suggestions concerning energy efficiency are
    focused on reducing natural gas use, e.g., "use your appliances
    wisely"; "turn down the thermostat"; "reduce the use of hot water."
    Few states have integrated their delivery or educational efforts on
    responding to higher winter natural gas prices with the
    comprehensive energy management or energy efficiency programs.

**Recommendations**

(1) Regulatory commissions should proactively "regulate" the natural gas
    procurement policies and prices of NGDCs. Even though the price of
    wholesale natural gas market is "deregulated", the retail
    acquisition of a natural gas portfolio should be monitored and
    evaluated based on consumer benefits, particularly for residential
    and small commercial customers. There are a wide variety of
    regulatory policies that, if adopted, enunciated, and enforced, will
    impact the rates charged for the natural gas supply portion of
    customers' bill. In short, state regulatory commissions should not,
    as many do, seek to shift the responsibility for natural gas supply
    rates and charges to "the market" or contribute to the public aura
    that state commissions cannot regulate natural gas prices or gas
    procurement decisions. This overall policy directive concerning the
    establishment and enforcement of natural gas procurement practices
    may need to be established by statute in those states in which the
    regulatory commission fails to adopt this approach, but in most
    states the regulatory commission already possesses sufficient
    statutory authority to adopt a more proactive approach. State
    regulatory commissions can establish natural gas procurement
    practices and policies. These practices and policies should be
    adopted either as a rule or a policy statement and then implemented
    by conducting regular reviews of individual utility natural gas
    procurement and pricing proposals.

(2) State commissions should require NGDCs to proactively manage their
    natural gas supply portfolio and acquire a balanced and diverse
    portfolio of physical and financial contracts that is designed to
    provide stable and reasonable prices for residential and small
    commercial customers over a long term planning horizon. As indicated
    by the Rhode Island PUC, simply making use of "dollar cost
    averaging" (the use of regular purchases of part of the overall load
    over a period of time) may not be sufficient. Rather, it may be
    necessary to adopt performance benchmark goals and objectives, as
    discussed further below.

(3) State regulatory commissions should require NGDCs to develop and
    submit for review and approval an annual procurement plan that
    describes the implementation of its overall approach to the
    management of its natural gas supply portfolio. In addition, the
    utility should prepare and annually update a five-year plan that
    reflects an analysis of its service territory, customer load
    profile, the state of the natural gas market, long and short term
    market trends, an analysis of long term contracts, and a review of
    the previous year's procurement plan and suggested amendments. This
    procurement plan should also include an analysis of the impact of
    energy efficiency and demand response programs that, in times of
    rapidly increasing wholesale gas prices, could be deployed to avoid
    the impacts of higher bills for residential and small commercial
    customers.

(4) The Legislature and/or the regulatory commission should adopt an
    explicit policy that requires natural gas utilities to follow
    portfolio management principles that value price stability. That may
    include reliance on long-term contracts with either fixed prices or
    limitations on price upper and lower boundaries for some portion of
    the gas supply portfolio, financial hedging instruments, and an
    expansion of storage options. These pricing principles should be
    explicitly adopted to apply to "default" customers in states that
    have moved to retail natural gas competition, for the same reasons
    that advocates have urged more stable and long term pricing
    principles for electric service in restructuring states. Residential
    customers should not bear all of the risks associated with volatile
    or short-term movements of the wholesale commodity market. Rather,
    the incumbent utilities should be required to perform the public
    service function of managing this price volatility as a steward on
    behalf of their customers. Relying on unregulated gas marketers to
    perform this function is dangerous for several reasons. First, the
    gas marketers have a habit of exiting the market (either voluntarily
    or by entering bankruptcy) whenever the going gets tough. This
    phenomenon was well documented in New York, Massachusetts, New
    Jersey, Illinois, and Ohio during the 2000-2001 price spike. Second,
    it is unlikely that the price paid to the gas marketer for providing
    a more stable price product is cheaper than if the incumbent utility
    incurred such costs on behalf of a much larger customer group and
    load factor. Third, there is absolutely no basis to conclude that
    gas marketers will offer an option for stable or fixed prices and in
    many jurisdictions they have not done so. Finally, and most
    importantly, it should be the obligation of the public utility that
    has received the privilege and obligation to provide service to all
    without discrimination to provide the "public interest" service of
    stable and reasonably priced natural gas service.

(5) Utilities should bear more of the risk associated with the failure
    to achieve one or more pre-established performance benchmarks.
    Advocates and commissions should explore whether it is more likely
    that a utility will have the proper incentives to engage in
    portfolio management if it bears some of the rewards and risks
    associated with the implementation of a gas supply program that
    values price stability and achieving a price benchmark. These
    incentives and penalties might include benchmarking the resulting
    price of natural gas with a bandwidth, making the rewards explicit,
    requiring the utility to bear the risk of failure (imposing a fixed
    price), reducing the frequency of price changes, and exploring
    decoupling mechanisms that lessen the link between retail sales and
    profits. Even though utilities do not make a "profit" on the pass
    through of the sale of natural gas supply, utilities rely on the
    distribution revenues, which do reflect sales and are priced in the
    same manner as natural gas supply, i.e., on a per therm or per ccf
    basis. As a result, the theoretical indifference by NGDC management
    to the price of natural gas supply is not apparent when price spikes
    cause large industrial load shedding or fuel shifting and increased
    incidence of default and disconnection from residential customers
    that result in higher customer service costs and public relations
    headaches, if not nightmares.[^9]

(6) The use of annual or semi-annual price changes is more likely to
    focus the utility's attention to price stability, particularly when
    compared to monthly price changes. Furthermore, a lengthier period
    between price changes can be more easily linked to decoupling
    initiatives as demonstrated by the program adopted in Oregon. The
    experience in Indiana shows how difficult it is to construct a
    policy that favors proactive gas procurement and hedging when
    monthly price changes are available to reflect short term changes in
    wholesale gas markets.

(7) While commissions have traditionally and frequently relied on the
    use of the deferral mechanism to smooth out significant price
    increases for residential customers, this is a blunt instrument that
    should not be the primary basis for mitigating price volatility.
    First, such an approach has a significant cost in the form of
    interest paid on the deferred balance. Second, this approach masks
    the utility's failure to properly manage its natural gas supply
    portfolio and does not provide any incentive to rely on hedging
    techniques and a balanced portfolio approach to natural gas pricing.

(8) Advocates should seek regular prudence reviews of natural gas
    procurement decisions, ideally in the context of an annual review of
    the implementation of the utility's procurement plan. While it may
    not be reasonable to question a particular contract or particular
    contract price with the hindsight of "perfect vision", it is
    reasonable to expect that a documentation of the failure to explore
    portfolio management or various portfolio management tools and the
    comparison of the resulting prices with similarly situated utilities
    in the state or region can result in a substantial disallowance and
    the adoption of improved policies.

(9) While advocates typically want to rely on prudence reviews that look
    backwards and evaluate decisions already taken by utility
    executives, utilities themselves prefer pre-approval and have called
    for such an approach as a means of responding to calls for increased
    risk management by policymakers. This paper did not find many
    instances of pre-approval of actual gas procurement decisions, but
    the Arkansas approach in which a gas procurement plan is approved or
    individual utility programs, such as those in Indiana, in which a
    certain specified portion of a portfolio is required to be hedged,
    are examples of a more modest approach. Under the Arkansas model,
    the NGDC's procurement plan is reviewed and approved, but its actual
    implementation of that procurement plan is subject to prudence
    reviews at a later time. This is also the approach being explored in
    several states that are attempting to develop Default Service
    policies that impose a procurement obligation under certain
    specified policies on the incumbent electric distribution utility.
    [^10]

(10) There is little discussion by commissions in their gas pricing
     decisions about the expansion or use of natural gas storage by
     local distribution companies. Whether or not the availability or
     use of storage is a function of historical ownership of such
     facilities by the NGDC or the natural geography of the region that,
     similar to Michigan, supports large storage capacity is not clear.
     Nonetheless, advocates should press for a more proactive analysis
     of storage options as a means of reducing reliance on gas price
     volatility. However, the most controversial issues associated with
     gas storage, as revealed by the disallowance ordered by the
     Michigan PSC, is the pricing of gas when it is injected versus its
     price when it is removed and sold to end-use customers. The pricing
     of the various "layers" within the stored gas deserves careful
     attention by advocates.

(11) If the gas utility is allowed to offer "fixed bill" or
     "Weatherproof" billing options to residential customers, the same
     problems exist as those pointed out above when the competitive
     market is relied upon to offer these services. If the utility can
     offer a fixed bill or "weather proof" bill to some customers, why
     not to all? Customers who select these options often pay entry or
     administrative fees and the small pool of entrants are likely to
     increase the overall costs of such an option. Furthermore,
     utilities who offer such options often rely on third parties to
     deliver the program and these entities come and go similar to gas
     marketers themselves. For example, Kansas Gas Service recently
     announced that it was discontinuing its WeatherProof billing
     program because the outside company that administered it could no
     longer offer it.[^11] Over 40,000 residential customers were
     enrolled in the program. Another example is NIPSCO's "premium
     service" offered to Indiana residential customers that may have
     contributed to the internal incentives that resulted in the
     company's lack of affirmative hedging as described later in this
     report. The objectives of these services should be provided to all
     residential customers and not just those willing to pay an
     additional fee for this service.

**Massachusetts**

Massachusetts passes through gas supply costs through the Gas Adjustment
Clause, which is changed at least twice per year[^12] and reconciled
annually in the fall. The annual reconciliation may result in
supplemental recovery or credit to customers for over-recovery.
Massachusetts has also ordered the statewide implementation of retail
natural gas competition. As a result, customer bills are unbundled,
competitive suppliers are licensed, and customer education programs
encourage comparative shopping. However, the rate of residential
customer participation in the natural gas supply market is miniscule.
According to the EIA, as of December 2002, only 300 residential
customers were participating. As a result, almost all residential
customers receive natural gas supply service from their Local
Distribution Company (NGDC).

Similar to most states, the Massachusetts Department of Energy and
Telecommunications (DTE) confronted substantial increases in the price
of natural gas supply in the winter of 2000-2001. Faced with proposed
increases of in the Cost of Gas Adjustment Clause (natural gas supply
portion of the bill) ranging from 8.33% to 65.9% for December-January
(which followed double digit increases approved in November), the DTE
discussed its overall approach to the recovery of the very high
wholesale market prices that occurred that winter[^13]:

> The companies requested these increases to collect from ratepayers the
> costs that they incurred and will incur to purchase natural gas
> supplies for their customers. In their filings each NGDC noted that
> the increases in gas commodity costs are driven by natural and
> international forces beyond either the Department's or the Companies'
> control.
>
> It is important to differentiate the components of the bill that are
> regulated by the Department. The Department does not regulate the
> interstate price of the gas commodity. Rather, the gas commodity price
> is determined by market forces, based on supply and demand.
>
> In terms of pricing, natural gas is merely goods in trade, just like
> grain, oil, coffee, or any other fungible commodity. Natural gas
> commodity prices are determined by the marketplace. Factors affecting
> gas prices include the weather, overall gas demand, supply of gas, and
> the prices of competing fuels, such as oil and coal.
>
> Costs incurred by the NGDCs for the purchase, storage, and interstate
> transportation of gas (referred to as gas supply costs) are recovered
> via the Cost of Gas Adjustment Clause on a dollar-for dollar basis.
> See 220 C.M.R. §6.00. That is, NGDCs do not profit on the gas
> commodity component of a gas bill, and the cost of gas is a straight
> pass-though. NGDCs earn a rate of return solely and entirely on their
> investment in local distribution facilities, i.e., the second
> component of the gas bill.
>
> Because this winter's dramatic and unprecedented increases in gas
> commodity costs are historic, the Department needs to review the CGAC
> mechanism and perhaps make it more responsive to extraordinary price
> fluctuations, analogous to the gas costs mechanisms used in New York,
> Connecticut, and New Hampshire, where comparable gas costs are being
> recovered in customer bills today.

The Department recognized the need to balance the urge to defer some of
these unprecedented price increases until after the winter period with
the "policy of mitigating severe billing swings." As a result of this
decision, the largest natural gas companies were allowed to charge a gas
supply price of \$.95 per therm (Bay State Gas) to \$1.06 per therm
(Boston Gas) in February 2001. In both cases, this was projected to
eliminate any projected under-recovery as of April 30, 2001.

In 2002 the Department considered its overall approach to gas
procurement and pricing for the NGDCs and rejected a proposal to
emphasize the mitigation of price volatility in gas procurement
practices and emphasized the importance of sending the proper "price
signals" to all customers.[^14] With respect to the use of financial
"hedging" instruments, the Department stated that it would consider such
programs on a company-specific basis:

> The Department will review the effect that a company's use of
> financial hedging instruments will have on the reliability and
> transparency of commodity prices on a case-specific basis, taking into
> account the wide-ranging options, instruments, and strategies that are
> available to both the NGDCs and the Competitive Suppliers.

The Department noted that with respect to "reliability and transparency
of commodity prices", it meant "NGDC prices that reflect accurately what
the prevailing market prices are likely to be in a CGAC period." The
NGDC's prices must not "provide customers with distorted or misleading
price signals."

With respect to the impact of its pricing policies on the development of
a retail competitive market, the Department quoted one participant in
the proceeding:

> Planalytics observes that, overall, NGDC risk-management programs will
> result in stable, consistent pricing; thus the customer will benefit
> from both reduced price volatility and low prices (Planalytics at 2).
> However, Planalytics argues that an environment of low price
> volatility and stable prices could hamper the development of
> competition and customer choice because gas unbundling and customer
> choice program become less attractive to consumers.
> ([id.]{.underline}).

The Department rejected proposals to require NGDCs to engage in risk
management activities that might require all customers to pay costs
incurred for risk management. Rather, the DTE concluded that customer
participation in NGDC financial risk management programs must be
voluntary rather than mandatory and the costs associated with such a
program must be recovered from only the customers who choose to
participate in such programs. The Department also rejected the creation
of any incentives to encourage or reward risk management activities or
programs.

Finally, with respect to how it intended to evaluate an NGDC's risk
management activities, the DTE stated:

> The Department agrees with the majority of commenters who state that
> the implementation of risk management programs would be designed to
> stabilize prices but would not necessarily result in "least cost" gas
> supply or minimize costs. As noted, due to the volatile and
> unpredictable nature of commodity derivatives markets, financial
> risk-management program unlikely to consistently produce prices below
> index levels.

The following Table[^15] shows the price charged for natural gas supply
for the two largest NGDCs for the period November 2000 through the
summer of 2003.

  ------------------- --------------------------- -----------------------
  **Date**            **Bay State Gas**           **Boston Gas**

  11/1/2000           0.7853                      0.6935

  2/1/2001            0.95                        1.0626

  5/1/2001            0.6994                      0.9097

  11/1/2001           0.6138                      0.6546

  1/1/2002            0.6138                      0.5282

  2/1/2002            0.6138                      0.5282

  3/1/2002            0.6138                      0.4412

  6/1/2002            0.3395                      0.4734

  11/1/2002           0.6354                      0.635

  1/1/2003            0.7483                      0.778

  3/1/2003            1.0066                      0.8749

  5/1/2003            0.6992                      0.797
  ------------------- --------------------------- -----------------------

The following chart presents the same data as the table, but in a CCF
pricing format to allow for comparisons with other states in this
report:

![](media/image1.wmf)

**Rhode Island**

Rhode Island, a small state, has devoted substantial regulatory
resources to address gas price stability and affordability, primarily
through reviews and decisions concerning the cost of gas supply of the
largest natural gas utility, New England Gas Co., the successor to two
smaller NGDCs and a "sibling" of Southern Union Co. While natural gas
retail choice is available to commercial and industrial customers, there
are no retail choice programs in place for residential customers.

New England Gas Co. (NEGas) serves 290,000 residential and commercial
customers in Rhode Island and Massachusetts. NEGas operates pursuant to
both an incentive rate plan for the distribution portion of its business
and has litigated and resolved gas procurement policies and practices,
stimulated in part by the extremely high prices that were flowed through
to the ratepayers in 2000-2001. The RI Public Utilities Commission
ordered an explicit gas procurement incentive program in early 2003,
which has been widely acknowledged as responsible for lower gas prices
for the 2003-2004 winter.[^16] The Commission ordered an incentive plan
with both rewards and penalties for the purchase of natural gas
supplies:

In this proceeding, the Commission has attempted to take gas procurement
to the next stage. The Commission's modifications to the parties'
Proposed Incentive Plan takes a middle path to this next stage. Rhode
Island's gas utilities have treated the recovery of purchased gas costs
as a mere "pass-through" to ratepayers. Consequently, prior to the
winter of 2000-2001, Rhode Island's former gas utilities, ProvGas and
Valley, tended to rely nearly exclusively on spot market purchases and
claimed that this served the objective of affordability. A litigious and
contentious prudence review by the Commission ensued, which resulted in
savings to ratepayers. NEGas, the successor of ProvGas and Valley,
learned the lessons of the winter of 2000-2001. NEGas hedged extensively
and followed a dollar cost averaging approach to achieve price
stability. Unfortunately, the winter of 2002-2003 demonstrates that
dollar cost averaging is not enough to keep ratepayers' bills reasonable
and affordable. As a result, NEGas must utilize its discretionary
purchases to depart from a simple dollar cost averaging strategy and
take advantage of low priced gas in order to achieve affordability.

The Proposed Incentive Plan as modified by the Commission achieves a
marriage of price stability and affordability. Price stability is
achieved by requiring 50 percent of NEGas' gas supply be purchased
through a dollar cost averaging approach. Affordability is achieved if
NEGas utilizes its discretionary purchases, covering up to 45 percent of
the gas supply, to purchase gas below the price produced by its dollar
cost averaging strategy for non-discretionary purchases. To incent
Southern Union to utilize its discretionary purchases as envisioned, the
Commission had to modify the reward and penalty structure proposed by
NEGas. Under NEGas' proposal, Southern Union would be nearly assured of
never incurring a penalty and always receiving a reward, even if NEGas'
discretionary gas purchases did not lower gas costs by being lower than
the price of its nondiscretionary purchases. A true incentive system
provides a realistic opportunity for Southern Union to receive a reward
for lowering gas costs and an equally real threat of incurring a penalty
for failing to be proactive.

Therefore, utilizing its own expertise and choosing among the
contradictory positions of the experts presented, the Commission under
the broad authority conferred by Title 39 modified the reward/penalty
structure of the Proposed Incentive Plan by eliminating the NYMEX
benchmark and increasing the limits on rewards and penalties. If NEGas
chooses to continue utilizing the dollar cost averaging approach for its
discretionary gas purchases, Southern Union will face the possibility of
absorbing a penalty. If NEGas utilizes its discretionary purchases to
achieve lower gas costs for ratepayers than produced by its dollar cost
averaging strategy, Southern Union's shareholders will have an
opportunity to share in the cost savings. \*\*\* The Commission hopes
this approach will be sufficient to incent NEGas' to be proactive in gas
procurement so as to lower gas costs for its ratepayers. Wholesale gas
costs account for more than 50 percent of the typical residential
heating customer's annual bill. Also, NEGas' annual bill for a typical
residential heating customer is clearly the most expensive utility bill
for the average Rhode Islander. The Commission will not merely rubber
stamp the pass-through to ratepayers of NEGas' gas cost increases. The
Commission has taken the proactive step of ordering the implementation
of an Incentive Plan that is designed to incent NEGas to be more
proactive in procuring lower cost gas. If NEGas is not interested in
pursuing rewards for Southern Union, then it will face penalties. The
penalties could grow with time if NEGas refuses to be proactive. At this
time, however, the Commission has chosen a middle path that gives ample
opportunity for Southern Union to receive rewards. Southern Union can
either embrace the Incentive Plan and pursue rewards or stubbornly
refuse to change its ways and face penalties. The choice is for Southern
Union to make.

\[At 45-46\]

In September 2003, New England Gas Co. issued a press release[^17]
congratulating itself on keeping gas supplies at a reasonable price:

While many areas of the country are predicting substantial increases in
the cost of natural gas for this year's heating season, Rhode Islanders
will largely be spared. Thanks to an innovative program initiated by the
Rhode Island Public Utilities Commission, the New England Gas Co. has
already purchased much of the fuel supply that it expects to need to
meet this year's heating demand.

As of July 1, 2003, Rhode Island residential heating customers of New
England Gas Co. were paying \$.7120 per therm for gas charges. In
November 2003, the Commission addressed New England Gas' proposed
increase in the Gas Cost Recovery Charge for the 2003-2004 winter in
which the utility proposed to increase the GCR factor on a per therm
basis to \$.8195 for residential customers. In ruling on this
request[^18], the Commission summarized its recent approach to the rates
charged for natural gas supply and contrasted the Rhode Island PUC's
approach from that adopted in Massachusetts:

> Justice Brandeis once stated that "in no other field of public service
> regulation is the controlling body confronted with factors so baffling
> as in the natural gas industry." \[[Pennsylvania v. West
> Virginia]{.underline}, 262 U.S. 553,621 (Brandeis dissenting) (1923)\]
> Thus, it is not surprising that certain members of the public may be
> baffled as to how NEGas' rates continue to climb despite this
> Commission's best efforts to keep these rates low or stable. As an
> initial matter, it must be understood that this Commission cannot set
> the wholesale price of interstate natural gas. The GCR portion of
> ratepayers' bills was deregulated by the federal government in the
> Natural Gas Policy Act of 1978. This state Commission has been
> pre-empted in this arena and must treat these purchased gas costs as a
> utility operating expense. Therefore, in regards to the wholesale gas
> cost increases, this Commission has a few options such as: disallowing
> imprudent wholesale gas purchases, reduce interest charges on any
> undercollection for deferred gas costs, establishing a gas procurement
> policy to attempt to shelter residential heating ratepayers from price
> spikes during the winter, creating a gas procurement plan that imposes
> penalties on NEGas if it does not take advantage of price dips, or
> finding savings in NEGas' distribution rates to offset GCR increases.
> This Commission has done and will continue to do all of the above. It
> has not been a passive observer who simply blamed the wholesale gas
> market as prices rose.
>
> In past proceedings relating to wholesale gas costs, the Commission
> has reduced gas costs by approximately \$1.26 million after it
> conducted a review of the prudence of ProvGas and Valley Gas' gas
> procurement for the winter of 2000-2001. Also, the Commission approved
> the development of a gas procurement plan that requires NEGas to
> purchase gas months in advance in order to ameliorate the price spikes
> of a colder than normal winter.21 In addition, this gas procurement
> plan contains a potential penalty of \$500,000 for NEGas if its gas
> purchases do not take advantage of drops in gas prices. This is quite
> a contrast from neighboring Massachusetts. In Massachusetts, gas
> utilities rely heavily on the spot market so if a winter is very cold
> and demand is high, the ratepayers are paying for a large amount of
> gas at a very high price. Furthermore, these gas utilities are not
> subject to a penalty plan for poor gas purchases. The difference in
> these two approaches has been made clear over the last four years.
> Since November 1999, in three of the last four years, NEGas/ProvGas'
> GCR rates have been below the GCR rates of at least two of three major
> Massachusetts gas utilities: Bay State, Boston Gas and
> NStar/Commonwealth. Specifically, NEGas/ProvGas rates were
> significantly lower in the winter of 2000-2001, and 2002-2003, when
> dramatic price spikes occurred due to colder than normal weather. This
> Commission's gas procurement policy has sheltered residential heating
> customers from extreme price spikes at the time their consumption is
> highest---extreme cold weather during the winter. Unfortunately,
> because of the legal limitations on this Commission regarding
> regulation of wholesale gas costs, ProvGas/NEGas' GCR rates for
> residential heating customers have increased from \$0.4531 per therm
> as of September 30, 2000 to \$0.7984 per therm as of November 1, 2003,
> or approximately a 76 percent increase in three years.

**Connecticut**

Connecticut prices its natural gas supply in the more traditional
manner, at least with respect to residential customers. Gas costs are
evaluated at the time of base rate cases and the Purchased Gas
Adjustment factor is changed monthly to reconcile the commodity costs
approved in the tariffs with actual revenues and costs. Connecticut has
not approved retail natural gas competition for residential customers,
but has approved such programs for multi-unit residential customers
(more than 6 units), as well as commercial and industrial customers. The
utility bills for residential customers were unbundled in 2002, showing
the separate rates for natural gas supply and distribution service.

Energy East owns the two largest natural gas utilities. Both operate
under multi-year performance based rate plans. Southern Connecticut Gas
Company's rates and charges were last subject to a revenue requirements
investigation in 1999, with new rates effective 2/1/2000. Since that
time, the Company's rate design has been subjected to review and changes
in various "phases" associated with the prior base rate decision. In
mid-2002[^19], the Department of Public Utility Control (DPUC) revised
the class revenue requirements by imposing a 20% increase on residential
classes, most of which was imposed on residential non-heating customers.
In addition, the DPUC altered the means by which the commodity charges
are recovered in various customer classes. Instead of a system-wide
average cost of gas, the DPUC adopted a class-specific gas cost
approach. An attempt to increase the monthly customer charge for
residential classes was rejected. As a result of these various changes,
residential heating customers saw a previously unbundled rate of \$.9848
change to a delivery charge of \$.4636 and a commodity charge of
\$.5243, plus itemized adjustments: Purchased Gas Adjustment, Weather
Normalization Adjustment. The Weather Normalization Adjustment affects
base delivery charges and affects bills during the months of September
through June. It insulates the company's revenue requirement from the
impact of abnormal weather.

Connecticut Natural Gas Corporation's revenue requirement was last
approved in 2000, followed by a cost of service study and rate design
proceeding in 2001.[^20] The DPUC created two residential classes:
heating and non-heating and significantly increased rates for
non-heating residential customers. While the total bill for residential
heating customers was estimated to remain the same as under prior rates,
the unbundled rates for delivery service were decreased and the rate for
commodity charges increased, as well as the monthly customer charge. As
a result of this proceeding, residential heating customers saw their
customer charge move from \$8.10 to \$10.25, delivery charge decrease
from \$.4391 to \$.3762 and commodity charge increase from \$.4776 to
\$.5225.

The DPUC rejected a proposal by the Office of Consumer Counsel to
establish an average fixed commodity cost for residential customers for
a twelve-month period on the grounds that such customers were not
eligible for competitive alternatives and could not exploit the average
prices for commodity service. The OCC's proposal was linked to its
suggestion that the cost of gas supply could be fixed by the purchase of
futures contracts. The Department determined that the issue of hedging
should be generically explored for all NGDCs. In a previous order, the
Department had approved the use of the futures market (i.e., financial
hedging) for up to 10% of the NGDC's gas supply portfolio, with any
resulting profits split 80% to firm ratepayers and 20% to stockholders.
The Department has not yet opened a specific docket to address hedging
or gas purchasing policies, but continues to conduct semi-annual reviews
and analysis of individual utility gas purchasing decisions. The most
recent decisions do not address hedging policies.

Subsequent to the two revenue requirement decisions, the Department
approved a comprehensive settlement for both Southern Connecticut and
Connecticut Natural to resolve the pending impacts of the merger with
Energy East on existing incentive rate plans, as well as pending
affiliate transactions.[^21] In this decision the Incentive Rate Plans
for both companies was extended until 9/30/2005, with substantial
changes to the Earnings Sharing Mechanism to reduce rates by a total of
\$5 million over four years. This decision address the gas purchase
prudence standard and addressed deferred gas costs of \$26 million, due
to the under-recovery of gas costs in the PGA during the winter of
2000-2001. Rate reductions in delivery base rates were also agreed upon
(\$8 M over four years). As a result of these decisions, the DPUC
authorized the recovery of previously unrecovered gas costs over a
period of 4 years (instead of the normal 11 months) and the resulting
delivery service rate reductions were ordered to be returned to
customers in the form of credits on customer bills during the winter
months of 2002 (March-April) and 2003 (November-March) so as to
alleviate the higher gas bills. Both companies were warned that the DPUC
would review any storage or supply agreements for prudence in light of
its long standing policy to ensure that the companies' decisions
"balance cost minimization with cost stability." \[At 25\] However, the
Department did not elaborate on any further policy guidance in this
regard and did not discuss financial hedging at all. A Dissenting
Opinion issued with this Decision alleges that affiliate contracts for
acquisition of gas supply resulted in higher costs for ratepayers.

The following Table of Purchased Gas Adjustment factors are derived from
the DPUC website:[^22] These prices are added (or subtracted) from the
tariffed commodity charge that is set at the time of a base rate case.
With respect to these three NGDCs, the following table shows the
tariffed commodity price for residential heating customers in effect for
the last three years:

+-----------------+-----------------+-----------------+-----------------+
|                 | Connecticut     | Southern        | Yankee Gas      |
|                 | Natural Gas     | Connecticut Gas | Service Co.     |
|                 |                 |                 |                 |
|                 | (\$ per ccf)    | (\$ per ccf)    | (\$ per ccf)    |
+-----------------+-----------------+-----------------+-----------------+
| October 2000    | .1741           | .3566           | .3742           |
+-----------------+-----------------+-----------------+-----------------+
| January 2001    | .3152           | .5332           | .4926           |
+-----------------+-----------------+-----------------+-----------------+
| July 2001       | .2095           | .3185           | .3285           |
+-----------------+-----------------+-----------------+-----------------+
| January 2002    | .0870           | .1324           | .1668           |
+-----------------+-----------------+-----------------+-----------------+
| July 2002       | .0003           | .0980           | .0630           |
+-----------------+-----------------+-----------------+-----------------+
| January 2003    | .0996           | .2057           | .2882           |
+-----------------+-----------------+-----------------+-----------------+
| July 2003       | .1800           | .2910           | .4945           |
+-----------------+-----------------+-----------------+-----------------+

As demonstrated by the Chart, below, Connecticut Natural's natural gas
supply prices are consistently lower than Southern Connecticut Natural
Gas rates (and those of Yankee Gas) even though Energy East owns both
companies. Furthermore, this Chart also reveals the significant
variation in natural gas supply rates after the price spike in the
winter of 2000-2001, falling significantly in the summer and fall of
2002, but then rising rapidly since then:

![](media/image2.wmf)

**New York**

New York's Gas Supply Charge (GSC) changes monthly, with an annual
reconciliation. The New York Public Service Commission (PSC) has
strongly supported the move to retail natural gas competition and
instituted competition programs at each NGDC. Pursuant to the
Commission's Gas Policy Statement issued in 1998 (and amended in
1999)[^23], gas utilities are required to unbundle their rates and limit
their acquisition of new capacity contracts, shifting to short-term and
citygate arrangements for capacity necessary for system operation and
reliability. While the PSC initially anticipated that the gas utilities
would exit the merchant function within a relatively short time, this
has in fact not occurred. While customer migration to competitive gas
supplies has exceeded participation rates for electric generation
service, the statewide migration rate for residential customers remains
at 7% as of August 2003, a 10% reduction in the last 12 months[^24]. The
degree of residential customer shopping varies significantly among the
various NGDCs, with largest numbers in Keyspan Energy Delivery of New
York and Niagara Mohawk Power Co. Most NGDCs are governed my multi-year
performance plans that address the distribution and, in some case, the
GSC portion of the customer bill. Each of these plans contains a Service
Quality or Customer Service performance mechanism with established
baseline performance standards and automatic penalties (in the form of
reduced earnings) for the annual failure to achieve the minimum
standards during the term of the plan and a company-specific low income
bill payment assistance program funded through distribution rates.

New York State Electric & Gas Corp. (NYSEG), an upstate utility owned by
Energy East, has operated under a multi-year performance rate plan since
1995 in which most customers enjoyed a rate freeze until October 2002.
In late 2002, the PSC approved a rate plan that for the first time has
resulted in unbundled customer bills and the use of market based rates
for the gas supply portion of the bill beginning in October 2002.[^25]
Distribution rates will remain frozen through 2008. As a result of
merger-related savings and a phase-in approach to market-based rates for
gas supply service, bills for residential customers were expected to
increase gradually until full market based rates will be in effect by
the fall of 2003. The settlement also includes a Gas Cost Incentive
Mechanism to share savings in gas supply costs as a result of NYSEG and
Energy East efficiencies and procurement policies between customers and
shareholders. The Gas Supply Guidelines attached to the settlement
(Appendix C of the Agreement, attached to the PSC's order) do not
discuss procurement policies, but merely describe how the GSC will be
calculated. The commodity cost of case will include a Merchant Function
Charge of 16.4 cents per dekatherm, identified as a "proxy" for gas
supply uncollectibles and administrative and general expenses typically
incurred by marketers in interactions with their customers. The GSC will
be calculated monthly and GSC recoveries will be reconciled with actual
gas supply expenses on an annual basis. Any adjustment will be included
in future GSC statements.

National Fuel Gas Distribution Corp. (NFGC), an upstate utility, also
operates under a multi-year rate plan that the Commission recently
extended until December 2004.[^26] This decision recites that
Commission's actions in October 2000 to reduce the equity earnings
sharing formula in the 1998 rate plan, resulting in a \$19.1 million
credit to customers "to ameliorate gas costs that were expected to be
much higher than in the prior winter." As a result, customer bills were
lower than what might otherwise have occurred. Even so, however, NFGD
residential customer bills were the highest in the state in January
2001, averaging about \$480 for 300 therms. These high customer bills
were not matched by any other New York gas utility for that period.

Consolidated Edison's most recent three-year rate plan was adopted in
April 2002.[^27] Again, the Commission recites its actions in the winter
of 2000-2001 to accelerate the return of some credits to customers to
ameliorate high gas supply costs. Distribution rates will be decreased
under the plan, but the monthly customer charge was increased. Several
changes were made to the Gas Cost Adjustment Mechanism, all of which
were designed to enable customers to more clearly compare the gas supply
charge on their unbundled bill with marketer offers. The monthly GSC is
allowed to differ among customer classes, based on customer load factor
(heating versus non-heating, in particular). In this proceeding, the
Public Utility Law Project (PULP) raised objections to the lack of any
policy to prevent volatile commodity costs from being passed through to
residential customers during the term of the plan and asked the
Commission to require Consolidated Edison to "set a stable commodity
prices as it says NYSEG has done, so that customers can be protected
against an unwarranted risk of market price changes." \[at 17\] Both the
PSC Staff and the utility objected to this proposal. The Commission
rejected PULP's proposal, stating:

> Action in this case with respect to either the company's gas
> procurement practices or the proposed institution of a stable market
> price option for Consolidated Edison's full service customers is also
> not warranted now. Not a single specific gas procurement problem or
> issue has been raised and no party has outlined a specific stable rate
> proposal or explained its impacts for our consideration.

At. 27.

The Commission adopted several proposals designed to foster competitive
retail choice, including a retail choice credit and ratepayer funding or
promotional or educational program funding.[^28]

The following Table presents the NY PSC Gas Supply Cost data[^29] for
four large gas utilities on a per therm basis. This data portrays
significant differences in the price of natural gas supply service among
the various New York utilities. It is likely that the significant
increases in natural gas supply prices for Consolidated Edison in 2002
and NFDC in 2002 were the result of the end of their prior multi-year
rate plans or rate freezes. However, the Commission has not discussed in
its orders or in public documents any of these wide disparities in
prices.

  -------------- -------------- -------------- -------------- --------------
                 Keyspan East   Consolidated   NYSEG          NFDC
                 d/b/a Brooklyn Edison                        
                 Union of Long                                
                 Island                                       

  July 1, 2001   .522534        .244297        Not unbundled  .303920 per
                                                              ccf

  January 1,     .545361        .132962        Not unbundled  .155770 per
  2002                                                        ccf

  July 1, 2002   .563374        .484181        Not unbundled  .469380 per
                                                              ccf

  January 1,     .597356        .575690        .566400        .629800 per
  2003                                                        therm (change
                                                              in price
                                                              presentation
                                                              as reflected
                                                              in PSC price
                                                              charts)
  -------------- -------------- -------------- -------------- --------------

The following chart presents the data in the above table in a uniform
Per CCF pricing format. Immediately evident is that Keyspan (Brooklyn
Union of Long Island) has consistently had a more stable, but much
higher rate for natural gas supply than either Consolidated Edison or
NFDC. This is most likely a result of the multi-year performance rate
plans in effect for the latter two NGDCs.

![](media/image3.wmf)

**New Jersey**

New Jersey adopted statewide natural gas (and electric) retail
competition for all customer classes in 1999. This resulted in changes
in the way the gas supply service is priced and how it appears on
customer bills. Basic Gas Supply Service (BGSS) is the label used for
the "default" service for non-shopping customers. Since most residential
customers have not shopped (as of May 2003, 5.3% residential customers
had selected a competitive gas marketer[^30]), the vast majority of such
customers receive BGSS. Gas utilities are required to file an annual
BGSS filing on June 1^st^, proposing a BGSS rate to be effective the
following October 1- September 30, subject to an annual review and
reconciliation. A utility may file for two self-implementing BGSS rate
increases, effective December and February. Each self-implementing rate
increase is limited to no more than a 5% increase (based on 100 therms).
Rates are also subject to a Temperature Adjustment Clause to insulate
the utility from the impacts of abnormal weather (based on whether
degree days are more or less than a 20-year average). This calculation
is based on the October-May time period.

The Board's Order Approving BGSS Price Structure[^31] rejected proposals
to provided BGSS through a competitive process (but the Board has in
fact adopted a competitive wholesale bidding approach for the equivalent
electric service). Commercial/industrial customers receive monthly BGSS
price changes based on the NYMEX spot market prices. Residential and
small commercial customers receive periodic BGSS pricing, effective
October 1, with the two discretionary rate increases described above. In
approving this approach the Board noted favorably the customer benefits
associated with "a price structure that is more consistent with market
conditions" and the potential for such an approach to enhance retail
competition. \[at 3\] However, the Board also noted that smaller users
should be introduced to market-based rates at a more gradual pace, thus
approving the approach that will result in a potential for up to three
price changes during the year. While this approach contemplates an
average price for BGSS based on both supplies bought on the spot market,
as well as supplies whose price was previously set by hedges or other
financial instruments, the Board's order does not discuss procurement
policies or the role that hedging should play in assuring stable gas
supply prices for residential and small commercial customers.

However, the Board's 2003 decision, Order Adopting Annual BGSS Minimum
Filing Requirements Settlements, contains some additional discussion of
procurement policies.[^32] The NGDC annual BGSS filing must include a
"hedging" report and a "schedule covering both the reconciliation and
projected period which shows monthly gas purchase volume requirements
and price hedged volumes broken down into discretionary and
non-discretionary hedging objectives.[^33] A plain English explanation
in narrative form regarding these hedging activities should be
provided." \[At 4\]

PSE&G has been under a Board requirement since late 2000 to adopt a
mixed portfolio approach to its gas supply purchases. The Board's Order
approving gas supply price increases in October 2000[^34] required PS&G
to initiate a mitigation measure as follows:

On or before January 1 of each year, Petitioner shall provide the Board,
Staff and the Advocate with its gas purchasing strategy based on a mixed
portfolio approach consisting of fixed gas price contracts (both
short-term and long-term), storage inventories, financial instruments
and spot market purchases. With regard to financial hedging, Petitioner
shall include parameters, triggers, and associated costs.

However, the Board's subsequent orders have not discussed or evaluated
the gas procurement policies. Instead, for example, PSE&G's proposals to
make changes in its BGSS charges have been routinely approved, often
accompanied by stipulations that require further filings by the company
concerning gas procurement and hedging practices. As a result, there is
no publicly available analysis of PSE&G's gas supply procurement
practices or the impact of its hedging program.

The Board required the same type of comprehensive hedging program and
filing of New Jersey Natural Gas Co. in August 2001 at a time when it
approved the recovery of a large under collection balance due from
ratepayers in a surcharge that was authorized for three years beginning
in December 2001.[^35] New Jersey Natural Gas Co. claims to be the
"lowest cost gas company in New Jersey" as a result of its long term
purchasing practices and what pricing data is available for BGSS in New
Jersey (see below) suggests that this allegation is correct.[^36]
Recently, the Board resolved several pending proceedings involving the
BGSS rate for New Jersey Natural and approved an "omnibus" stipulation
that covered the final BGSS rates and recovery methodology for 2000,
2001, and 2002, as well as numerous incentive designed to reward the
company and share profits with ratepayers in certain procurement
practices.[^37] Specifically, the Stipulation[^38] proposed and the
Board approved the following factors and clauses concerning the price of
natural gas:

(1) The Gas Cost Recovery factors reflected in the BGSS rate (previously
    "provisional" 2000, 2001, and 2002 rates approved as final and the
    after-tax GCR factor within the BGSS rate of \$0.2745 per therm is
    deemed final for the February-August 2003 period);

(2) The Gas Cost Under-recovery surcharge and its effect on the Gas Cost
    Recovery rate (reconciliation);

(3) A variety of incentive programs that "seek to align the objectives
    of customers and shareholders, while also supporting the State's
    public policy goals":

    a.  Off System Sales and Capacity Release incentive program (profits
        are shared 85/15 between customers and shareholders);

    b.  Financial Risk Management program (older "hedging" program);

    c.  On-System Interruptible Sales, Transportation and Other Sharing
        (various incentive sharing programs relating to targeted sales);

    d.  Market Development Fund (targeted to assist third party
        suppliers);

    e.  Capacity Reduction and Portfolio Enhancement (older program with
        profit sharing designed to get rid of older capacity contracts);

    f.  Capacity Reliability Incentive (newer program to recognize the
        need for long term capacity due to lack of development of the
        retail market);

    g.  Storage Incentive (storage-related gains and losses will be
        shared on a 80/20 percentage basis, as measured by the
        difference between the actual cost of storage and an agreed upon
        storage inventory cost benchmark established through NYMEX
        forward prices for the injection season); and

(4) Weather Normalization Clause (levelizes the impact of colder or
    warmer weather on customers; operates as a reconciliation with a 3%
    rate impact cap).

The Board also approved a proposal to establish one or more Fixed Price
Commodity Pools to respond to customer desire to locking in a fixed
price for gas commodity. Specifically, the utility has committed to
develop a "Low-Income Commodity Pool" on a pilot basis that will fix the
BGSS price for a one-year period, but only when New Jersey Natural gas
offers the available fixed price at a lower rate than the current BGSS
rate, thus ensuring that participants will realize savings. This program
will be offered on an "opt in" basis to the 17,000 NJNG customers
currently receiving Lifeline or LIHEAP benefits. A comparable
Non-Low-Income Commodity Pool will also be developed in the future, but
without the price restrictions associated with the Low-Income Pool.

The existence of such a wide range of factors and incentive programs
suggests that it would be difficult to determine the actual cost of
natural gas supply charges at any one point in time.

The following table contains prices for BGSS service for residential
customers as derived from the various Board orders. The NJ BPU does not
maintain pricing data on its website.

+-------------+-------------+-------------+-------------+-------------+
|             | PSE&G       | New Jersey  | South       |             |
|             |             | Natural Gas | Jersey Gas  |             |
|             | Residential | Co.         | Co.         |             |
|             | Heating     |             |             |             |
|             |             | Residential | Residential |             |
|             | \$ per      | Heating     | Heating     |             |
|             | therm       |             |             |             |
|             |             | \$ per      | \$ per      |             |
|             |             | therm       | therm       |             |
+-------------+-------------+-------------+-------------+-------------+
| December    | \$.451973   |             |             |             |
| 1999        |             |             |             |             |
+-------------+-------------+-------------+-------------+-------------+
| January     | \$.568173   | 11/2000:    |             |             |
| 2000        |             | \$2343      |             |             |
+-------------+-------------+-------------+-------------+-------------+
| December    | \$.703373   | \$.5748     |             |             |
| 2001        |             |             |             |             |
+-------------+-------------+-------------+-------------+-------------+
| January     | \$.55247    |             |             |             |
| 2002        |             |             |             |             |
+-------------+-------------+-------------+-------------+-------------+
| April 2002  | \$.597827   |             |             |             |
+-------------+-------------+-------------+-------------+-------------+
| December    | \$597827    | \$.5238     |             |             |
| 2002        |             |             |             |             |
+-------------+-------------+-------------+-------------+-------------+
| January     | \$.662757   |             | \$.6715     |             |
| 2003        |             |             |             |             |
+-------------+-------------+-------------+-------------+-------------+
| March 2003  | +5%         |             | 5/2003:     |             |
|             | increase    |             | \$.7867     |             |
+-------------+-------------+-------------+-------------+-------------+
| August 2003 | \$.71854    | \$3617      | \$.7867     |             |
+-------------+-------------+-------------+-------------+-------------+
| October     | \$.796357   | \$.6981     | \$.9017     |             |
| 2003        |             |             |             |             |
+-------------+-------------+-------------+-------------+-------------+

**West Virginia**

West Virginia has not adopted retail customer choice for residential
customers. The two largest natural gas utilities---Mountaineer Gas Co.
(Allegheny Power) and Hope Gas Co. (Dominion) have operated under a
variety of performance based rate plans with rate freezes applicable to
the entire bill, including the gas supply portion of the rates. During
the November 1998-October 2001 incentive rate plan, the customers of
Mountaineer Gas saw no rate increase during that period even though the
wholesale prices for natural gas increased dramatically in the fall of
2000[^39]. At the time of the frozen rates, residential customers were
charged \$6.11 per Mcf, which included at gas supply charge of \$4.361
per Mcf. As part of this agreement, the NGDC assumed the risk of any
changes in interstate pipeline rates and charges, but also retained all
supplier refunds received during this period. However, that rate freeze
is no longer in effect and residential customers currently pay a total
gas charge of \$9.680 per Mcf, of which \$7.850 per Mcf is purchased gas
cost.

In December 2001, Hope Gas Co. entered into a two-year incentive rate
plan (January 2002 through December 2003) with an initial rate increase
of 8.3% for residential customer bills, but followed by a two-year rate
freeze. This rate case was preceded by a three-year rate freeze that
avoided the 2000-2001 price changes. The current rate~~s~~ in effect for
residential customers is a total gas cost charge of \$7.687 per Mcf,
that includes a commodity price of \$5.07 per Mcf.

The Consumer Advocate Division has entered into these agreements and the
Commission has approved them because of the important advantage for
residential customers in achieving rate stability. This approach was
supported by the PSC Staff, which issued a report in July 2001[^40] that
supported the judicious use of hedging. While gas companies routinely
relied on spot market purchases through most of the 1990s, flat or
stable prices in the wholesale market did not result in any warning
signals about the use of this pricing strategy until the winter of
2000/2001. The Staff Report compared various hedging approaches for the
November 2000 through March 2001 period using actual data and compared
two hedging approaches to spot market prices for each winter beginning
in 1992/1993 through 2000/2001. The two hedging scenarios always
produced a more stable price structure than reliance on spot markets. In
one approach, the utility locked in its winter's gas supply in the five
months preceding the winter (i.e, during the April 2000 through
September 2000) period. In the other scenario, the utility acquired its
winter gas portfolio over a 17-month period preceding the winter (i.e.,
between April 1999 through September 2000). Even though the author
acknowledged that the most significant impact resulted from the
comparison between the spot market of 2000/2001 and either hedging
strategy, he concluded that "...the cumulative costs of most
unsuccessful strategies would have been relatively small when compared
to the benefits of price stability and the protection against a
catastrophic price escalation." \[At 8\]

It is also noteworthy that the author describes Mountaineer Gas'
behavior after its entry into the "total rate moratorium." The utility
immediately locked in gas costs for the rate moratorium period. In other
words, the "Commission had hedged the customers' rates by locking-in a
tariff rate." This transferred the risk of high gas prices to the
utility who responded with the management decisions to reduce that risk.
Even though the gas utility was not required to hedge its purchases as a
result of the rate agreement, it did so because it no longer had the
ability to pass through gas price changes to its customers.

**Arkansas**

Arkansas has adopted the traditional Purchased Gas Adjustment Clause to
govern its natural gas supply costs and has not adopted retail
competition for residential and small business customers, although
larger customers have access to a transportation service. Since rates
have not been formally unbundled, there is a widely acknowledged
blending of gas and non-gas related costs in delivery or base
rates[^41]. In any case, customer bills separately show delivery charges
and commodity or Purchased Cost of Gas charges. Unlike other states,
however, Arkansas natural gas utilities do not publish the actual
Purchase Cost of Gas factor in their tariffs, relying on a tariff that
describes the process of filing such charges with the Public Service
Commission[^42]. Unfortunately, the Commission does not publish these
rates and charges in an accessible format either. However, the
Commission does publish residential customer bill information for
natural gas service (total bill) at various usage levels every
month[^43].

While many states reacted to the price spikes and volatility in natural
gas supply prices in the winter of 2000-2001 with orders and directives
concerning the need for hedging and gas procurement planning designed to
achieve more stable natural gas prices for consumers, very few states
issued comprehensive rules and specific requirements such as Arkansas.
After a public proceeding, several hearings and rounds of testimony or
comments, the Arkansas Public Service Commission issued Principles for
Gas Procurements Plans of Utilities.[^44] The rules state the policies
that should guide the gas utility in developing its gas procurement
strategy, require an annual submission of a Gas Supply Portfolio Plan,
allows recovery of costs associated with financial risk management
instruments, establishes recordkeeping requirements, requires outreach
and customer education programs about upcoming winter gas prices, and
requires all gas utilities to offer levelized billing or average payment
plans for residential and small business customers, as well as assess
the demand for and feasibility of a fixed price gas commodity supply
option for customers at least once every two years.

With regard to the overall policy that must govern gas procurement
activities, the Commission stated:

> Each gas utility is expected to take all reasonable and prudent steps
> necessary to develop a diversified gas supply portfolio. The portfolio
> should consist of an appropriate combination of different types of gas
> purchase contracts and/or financial hedging instruments designed to
> yield an appropriate balance of reliability, reduce volatility and
> reasonable price. In so doing, each utility should take into
> consideration various factors including, but not limited to, its
> particular circumstances, the demographics of its customers, the
> then-current market projections of both volatility and price,
> supply/demand estimates, and other relevant information that is
> available in the industry.

One of the first regulatory proceedings to consider past gas procurement
practices, as well as the annual gas procurement plan for the 2003-2004
season is pending in a review of Arkansas Oklahoma Gas Corp.
practices.[^45] This proceeding contains the results of a Staff
investigation of the utility's procurement practices for the 1997-2001
period, as well as the company's proposed gas procurement plan for the
coming gas year. The Arkansas Oklahoma gas procurement plan addresses
the following topics in the context of the specific system,
demographics, and procurement history of this utility:

1.  Natural Gas Environment

2.  Utility System Description

3.  Markets and Forecasting

    a.  Types of Markets

    b.  Forecasting Models

    c.  Weather Data Collection and Use

    d.  Design Day Forecast

    e.  Design Year Forecast

    f.  Load Factor Calculation

    g.  Forecast Misses in Requirements

    h.  Daily and Hourly Variations in Load

    i.  Summary of Supply Requirements

4.  Meeting Supply and Capacity Requirements

    a.  AOG's Preferred Contract Types

    b.  Current Supply Portfolio

    c.  Supply Mix Requirements

5.  On System vs Off-System Supplies

6.  Peaking Services

    a.  LNG/Propane Air

7.  Purchasing of Suppliers

8.  Price Stabilization

    a.  Need to Stabilize Prices

    b.  Summer Outlook

    c.  Price Stabilization Tools Available

    d.  Price Stabilization Actions

9.  Cost of Gas Forecast

10. WACOG (Cost of Gas) Volatility

11. Customer Options and Education

12. Discussion of Actual vs. Plan for 2002-2003

In its plan (written in May 2003), the utility had this to say about the
current natural gas environment:

> AOG believes that prices will be driven primarily by weather and
> emotion for at least the next two years. Deliverability is so closely
> balanced by demand that changes in weather or weather forecasts now
> cause extreme swings in prices. AOG believes that we are living on the
> inelastic part of the demand curse. Open interest in the NYMEX and
> speculative interest in natural gas increased dramatically in 2002.
> Trend following speculators coupled with high market requirements will
> probably exacerbate price swings. As is typical in volatile markets,
> prices will probably over-react in both directions.

At 3.

The following table shows selected results of the monthly natural gas
price comparisons prepared by the Arkansas PSC for the average
residential usage for each of the billing months. Because the PSC
reports "average bill" information, the actual usage for a particular
month changes to reflect the impact of the time of year (winter versus
non-winter) and the weather in effect during that particular year. The
actual average usage bill for the period in question is reflected in
parentheses for each month in question.

  ----------------- ----------------- ----------------- -----------------
                    Arkansas Ok. Gas  Arkansas Western  Arkla
                                      Gas Co.           (Centerpoint
                                                        Energy)

  August 2000       \$15.53           \$14.06           \$16.35
  (16-17 ccf)                                           

  January 2001      \$146.25          \$126.20          \$120.72
  (192-224 ccf)                                         

  March 2001        \$109.93          \$141.61          \$60.99
  (94-111 ccf)                                          

  July 2001 (16     \$23.20           \$19.53           \$18.16
  ccf)                                                  

  January 2002      \$160.72          \$83.42           \$
  (147-168 ccf)                                         

  March 2002        \$97.44           \$75.62           \$106.53
  (110-115 ccf)                                         

  July 2002 (16     \$18.08           \$16.10           \$18.51
  ccf)                                                  
  ----------------- ----------------- ----------------- -----------------

**Indiana**

Indiana's Utility Regulatory Commission (IURC) and the Indiana Office of
the Utility Consumer Counselor have been very active in oversight and
regulatory activities with respect to the management and pricing of
natural gas supply. While this activity pre-dates the winter of
2000-2001, litigation about natural gas utility portfolio management
decisions and hedging practices have escalated since that time. There
are three large investor-owned natural gas utilities: NIPSCO (Northern
Indiana Public Service Co., owned by NiSource); IGC (Indiana Gas Co.,
owned by Vectren) and SIGECO (Southern Indiana Gas and Electric Co.,
owned by Vectren). The state's largest municipally-owned gas utility
(Citizens Gas serving Indianapolis) is also regulated by the URC,
although other municipally-owned gas utilities have opted out of URC
regulation. Together, these four gas utilities represent 90% of the
natural gas sales in Indiana.

While Indiana has not adopted state-wide retail natural gas competition
for residential customers, the URC has approved one pilot program for
the NIPSCO service territory. The NIPSCO program was approved in 1997.
While the entire customer base is theoretically eligible to participate,
there are enrollment caps of 150,000 for residential customers and
20,000 commercial customers. Actual participation has never been high,
but it significantly decreased in 2001 and 2002. In late 2002, NIPSO
made a concerted effort to revitalize the program, but by April 2003
only 51,000 customers were enrolled. Of the five marketers participating
in this program, two were not accepting new residential customers.

The gas supply costs of a gas utility are reflected in the traditional
Gas Cost Adjustment that is separately stated on customer bills and must
be approved by the Commission. While the smaller NGDC's continue to file
quarterly GCA adjustments, with an annual true-up, the larger NGDC's
have been allowed to make monthly changes. NIPSCO has by far the
broadest authority to change the GCA every month pursuant to prevailing
market conditions. This authority to change the gas supply price monthly
was approved in a 1999 alternative rate plan that supplemented a retail
customer choice plan originally approved in 1997. Other large gas
utilities are subject to quarterly GCA filings, but have been granted a
much more limited authority to "flex" these charges on a monthly basis
within a small bandwidth, typically \$1.00 within the original quarterly
GCA price estimate.

According to the URC's 2003 Gas Report to the Indiana General Assembly,
"In its orders, the Commission has encouraged utilities to explore
innovative ways to control gas prices using strategies such as hedging,
fixed and ratable purchases and efficient use of storage." Rather than
relying on the spot market, the Indiana gas utilities have increased the
amount of gas purchased under fixed price or other hedged contracts. The
Commission has recognized that this approach does not guarantee that
customers will be charged the lowest price for gas at any particular
point in time: "More stable gas prices in a volatile market are
desirable and generally considered worth the payment of a slight
premium." [^46] This policy is supported in part by the statutory
obligation imposed on the gas utility to show that it has "made every
reasonable effort to acquire long term gas supplies so as to provide gas
to its retail customers at the lowest gas cost reasonably possible"
\[I.C. 8-1-2-42(g)(3)(A)\]

In 2001 the IURC reviewed the gas costs incurred by Citizens Gas in its
request for a Gas Cost Adjustment for March-May 2001. The Commission
accepted a settlement[^47] that resulted in a credit of \$3.38 million
to customers, noting that the majority of the commodity purchased by the
utility during the 2000-2001 heating season was priced using index
(i.e., non-hedged) prices, adjusted for delivery to the utility's city
gate. In addition, the utility had some fixed or other structured price
agreements, but these were not entered into until prices had already
reached extremely high levels. The litigated position of the consumer
advocate was that the utility should have purchased a greater portion of
the portfolio at fixed or structured price arrangements as it had been
previously authorized to do. The following year Citizens Gas filed for a
substantially lower GCA (compared to 2001) and sought a Monthly Flex
Mechanism whereby it could make monthly changes to its GCA within a
certain bandwidth. The resulting Stipulation (approved by the
Commission[^48]) contained a \$1.00 upwards and downwards limit on the
use of the monthly price change (relative to the approved quarterly GCA
benchmark estimate). This permission to "flex" the GCA is only
applicable to the portion of the gas supply portfolio that is not
otherwise hedged as emphasized by the Commission in its discussion of
Gas Procurement Principles in its decision approving the Stipulation:

> The Parties are committed to a diversified portfolio approach for gas
> procurement. The initiation of the monthly flex mechanism depends in
> large part on the Parties' agreement that development of a diversified
> gas supply portfolio is a reasonable effort---consistent with the goal
> of obtaining long-term gas supplies at the lowest cost reasonably
> possible. The Parties agree that reasonable price volatility
> mitigation efforts may not result in the absolute lowest priced gas
> being purchased for the period. The Parties further agree that review
> of Citizens' gas procurement efforts, include price volatility
> mitigation efforts, shall not be based on "20/20 hindsight" but shall
> be based on the information, facts and circumstances existing at the
> time its procurement decisions were made.

Stipulation, Part II(E).

The most controversial case in recent years was the IURC's review of
NIPSCO's gas cost adjustment prices passed through to customers in the
late winter 2003. This case was litigated and resolved by the
Commission[^49] with a \$3.8 million disallowance imposed on the utility
after the Commission found that NIPSO had failed to implement reasonable
price mitigation strategies during this time period. Specifically, the
Commission found that NIPSCO had purchased almost its entire gas
portfolio at spot market prices and did not use fixed priced or other
hedged gas contracts for volatility mitigation. Rather, the utility had
relied almost entirely on stored gas to limit price volatility and used
a storage pricing methodology that passed through the most expensive gas
to customers during the high use winter period. These gas portfolio
practices were documented as a change from the prior practices of NIPSCO
and occurred during a period in which the utility was attempting to
stimulate retail gas customer choice by incenting marketers to
participate in its service territory, as well as during the time NIPSCO
was marketing a fixed price bill option to residential customers at a
premium price. NIPSCO's policies and its ability to pass through gas
supply price changes on a monthly basis to its customers resulted in
March 2003 GCA rates of \$232.06 for a residential customers using 200
therms[^50]. The Commission's decision to disallow a portion of the
March 2003 gas cost adjustment documented the difference between NIPSO's
gas procurement practices and those followed by other Indiana utilities
and the regulatory history of approved fixed price gas supply contracts
for other utilities, particularly the decision in 2001 that disallowed
\$3.79 million in gas costs for Indiana Gas based on the failure of that
utility to enter into any fixed price or other hedged gas in the
2000-2001 period.

It should be noted that in a presentation before the URC on natural gas
prices and forecasts for the 2003-2004 winter in July 2003, the NIPSCO
representative stated that the company intended to purchase at least 20%
of its expected purchases at fixed prices.[^51]

Indiana annually tracks residential customer bill comparisons for all
its utilities as of January 1, but does not distinguish between the gas
supply and base rate or distribution portion of the bill.[^52] Over a
five-year average (1998-2002), NIPSCO had the highest average
residential bill compared to these other large Indiana gas utilities and
this trend continued in the January 2003 bill comparisons:

+-------------+-------------+-------------+-------------+-------------+
|             | NIPSCO      | Indiana Gas | Citizens    | SEIGCO      |
|             |             |             | Gas         |             |
|             | (Res. 200   | (Res. 200   |             |             |
|             | therms)     | therms)     | (Res. 200   |             |
|             |             |             | therms)     |             |
+-------------+-------------+-------------+-------------+-------------+
| 1999        | \$110.55    | \$107.62    | \$110.30    | \$101.12    |
+-------------+-------------+-------------+-------------+-------------+
| 2000        | \$114.53    | \$114.46    | \$108.58    | \$92.94     |
+-------------+-------------+-------------+-------------+-------------+
| 2001        | \$210.91    | \$175.40    | \$157.44    | \$134.82    |
+-------------+-------------+-------------+-------------+-------------+
| 2002        | \$127.81    | \$133.22    | \$125.92    | \$          |
|             |             |             |             | 172.41[^53] |
+-------------+-------------+-------------+-------------+-------------+
| 2003        | \$179.35    | \$\$161.32  | \$\$146.66  | \$146.42    |
+-------------+-------------+-------------+-------------+-------------+

The following chart presents the data in the table in a format that
allows for a better understanding of the differences in natural gas
supply prices among the Indiana NGDCs:

![](media/image4.wmf)

**Michigan**

Michigan is the 12^th^ largest natural gas producing state, but still
consumes far more than is locally produced. However, Michigan has the
largest working gas storage capacity in the nation, equal to more than
two-thirds of the state's total usage.[^54] These facts have had a
significant impact on the state's natural gas prices overall and its gas
portfolio management practices. In January 2003, the average cost of
delivered gas to residential customers in Michigan was \$6.13/Mcf, well
below the U.S. average of \$8.30/Mcf. While this was a 6% price increase
compared to January 2002, it was a modest increase compared to most
other jurisdictions. [^55]

Michigan has also adopted large-scale retail natural gas competition
programs for residential and small commercial customers, but the degree
of shopping activity and marketer interest in residential customers
varies among gas utilities. As of December 2002, 162,644 residential
customers had chosen an alternative gas marketer, but almost all of
those customers were served by either Consumers Energy or Michigan
Consolidated Gas Co. (MichCon). Approximately 11% of the eligible
residential customers have entered the competitive market.

Under the Michigan approach to pricing natural gas supply, each NGDC
must submit an annual plan that typically runs from April through the
following March. The Commission annually reviews the Gas Cost Recovery
Plan and sets a gas cost adjustment level designed to recovery the
approved gas supply costs for the forthcoming year, as well as reflect
any true up from the prior year's actual purchases and gas costs. As
part of this annual filing, the utility also submits a 5-year forecast
of the gas supply requirements, sources of supply and projections of gas
costs. The utility is obligated to "minimize the cost of gas purchased
by the utility." [^56]

The Commission's most recent decision concerning Consumers Energy
Company's gas cost recovery plan for April 2003-March 2004 approved a
stipulation that included a Gas Purchasing Strategy and Guidelines for
the Use of Hedging Instruments.[^57] This decision also allowed the
utility to make quarterly price adjustment to reflect market price
increases, based on a formula that reflects NYMEX 5-day average strip
prices (i.e., futures contract prices). The Gas Purchasing Strategy
Guidelines establishes fixed price contract target levels of commitment
that range from 15%-20% of the expected load during the early period of
the recovery period up to 75%-80% of the load by the end of the gas cost
recovery period. This is a tiered approach that links the obligation for
fixed price contracts to the gradual increase in load relating to
heating needs over the summer and fall period. The Guidelines also
contain Quartile Fixed Price Triggers, a method of fixing the price of
gas on a portion of the utility's annual supply requirements if the
current market price is within or below certain historical price ranges
or quartiles. The Guidelines for Use of Hedging Instruments addresses
the use of "put" and "call" options. Under a "put" option, a supplier
will pay a premium to Consumers Energy to sell or put gas to the utility
at a specified price at some future date. Under a "call" option, the
utility will pay a premium to a supplier to buy or call gas from the
supplier at a specific price at a future date in order to protect
against rising gas prices. The Guidelines limit the use of put and call
hedge instruments for a portion of the supply for a GCR period.

The 2003 Gas Cost Recovery Plan of MichCon will rely on acquiring 65% of
its supply through fixed price contracts and 35% as purchases indexed to
the NYMEX futures market.[^58] This decision was preceded by the 2002
gas cost recovery plan decision[^59] that found imprudent gas
procurement practices by the utility and disallowed \$26.5 million.
MichCon entered into a multi-year alternative rate plan for the
1999-2001 period that froze its overall price at \$2.95/Mcf. This
alternative rate plan also reflected the initiation of the utility's
customer choice plan for residential and small commercial customers. The
Commission found that MichCon used storage gas to meet the needs of its
sales customers in 2001 rather than purchasing gas to replenish storage
volume. As a result, in 2002 the utility had to rely on an increased
firm flowing winter supply to meet its service obligation. This need was
exacerbated when participation in the customer choice program declined
in 2000 and 2001 and MichCon had to obtain additional supplies to meet
the returning customer needs. Rather than buy higher priced gas (which
would have cost more than the utility was recovering from customers
under its fixed rate plan), MichCon relied on relatively low cost gas in
storage. In 2002, the rate freeze ended and MichCon went into the market
to obtain gas. The Company entered into a fixed price contract in April
2001 for the first quarter 2002 supply requirement. Of course, this
action occurred at a time of rapid increases in natural gas supply
prices. The Commission's finding of imprudence was directed to the
decision to withdraw so much gas from storage in 2001 and not the fixed
price contract itself. As stated by the Commission, "Act 304 was enacted
to ensure that the utility, not its customers, is responsible for such
ill-advised gas supply decisions." \[Order at 24\]

The following table represents the Gas Cost Recovery rates approved by
the PSC for residential customers in a per CCF format that allows
comparison with the other prices and charts in this report:

  ----------------------- ----------------------- -----------------------
                          MichCon                 Consumers Energy

  July 2000               \$.295                  

  July 2001               \$.295                  

  July 2002               \$.438                  \$.366

  July 2003               \$.497                  \$.518
  ----------------------- ----------------------- -----------------------

**Ohio**

Ohio has adopted a statewide and aggressive customer choice or retail
competition program for natural gas service. Initiated in the late
1990's, these programs have expanded in two of the four investor-owned
gas utilities. The Columbia Gas of Ohio program has enrolled 42% of
residential customers and Dominion East Ohio Gas has enrolled 54% of its
residential customers with alternative suppliers. This trend is likely
to continue and increase since the Ohio Legislature has adopted a
municipal aggregation program for natural gas that is similar to that in
place for the Ohio retail electric competition program. It is likely
that this enrollment activity is related to the relatively high cost of
natural gas paid by customers of these two utilities. As reflected in
the Table showing natural gas supply prices for the period January
2001-October 2003, both Columbia Gas and Dominion East have consistently
charged higher prices compared to southern gas utilities in Ohio.

It appears that the Ohio PUC has in the past made gas cost recovery
decisions based on a formulaic approach and has not imposed or
promulgated procurement policies that mandate diversified portfolios,
price stability, or hedging. The Commission has initiated a review of
its Gas Cost Recovery rules to "make the GCR more reflective of recent
events in the natural gas industry relating to price volatility and
growth of customer choice."[^60] The issues accompanying the rulemaking
review issued by the Commission did not, however, raise concerns about
price stability or hedging. Rather, these issues focused on whether the
gas cost calculation should reflect weather normalized historical sales
as opposed to projected sales and if the gas cost adjustment rules
should allow flexibility to make adjustments other than quarterly.
Perhaps not surprisingly, the marketers used their opportunity to
comment to object to the Commission's approval of a modification of the
GCR price or formula in the last two heating seasons that had the impact
of smoothing out significant upward swings in prices over a longer
period of time (i.e, using the deferral mechanism to allow recovery
during the next quarter or over a longer period). The marketers stated,
"The better response to addressing unacceptably high levels of GCR
adjustments is to make the GCR track the authorized costs better so that
the adjustments will be small."[^61] This in turn would of course allow
marketers to respond to these gas prices with products that may offer
price stability or fixed price options to the more volatile utility
service. Pursuant to the marketers' view, the utility GCR tariff is a

> safety net for those who cannot or do not want to shop. Thus, the GCR
> tariff service today should be viewed and priced as the provider of
> last resort service. Customers will come and go to tariff gas as a)
> they change suppliers; b) their supplier defaults; or c) their retail
> supply contract terminates without renewal. Since the time horizon for
> a provider of last resort is one in which changes are not only
> possible but often will occur on a month to month basis, fixing prices
> on such a time line is more logical than for in essence for four
> months at a time---with the inevitable adjustments that will follow.

Joint Marketer Comments at 7.

In fact, all commenters, including most utilities, favored the use of
other than quarterly pricing, particularly in times of volatile natural
gas prices. Only the Office of Consumer's Counsel and Dominion Retail
favored the continuation of the quarterly GCR price changes. The OCC has
also proposed the implementation of a one year pilot with a fixed gas
price "...because it seems inappropriate for residential customers to
have to rely upon unregulated choice providers to obtain relatively
stable rates." \[OCC Comments at 9\] Naturally, the suppliers opposed
this approach, arguing that "one year fixed gas prices should be
available only from suppliers." \[Reply Comments of Energy America,
L.L.C. and Shell energy Co., L.L.C. at 4\]

The following table reflects the GCR rates in effect at the stated
months for residential customers. These prices (expressed as \$ per ccf)
include the applicable Gross Receipts Tax.[^62] Even a casual view of
this chart confirms that extreme price volatility of the GCR in Ohio and
the price differential between Columbia Gas and Dominion East (where
more customers are participating in choice) and the other two gas
utilities. Furthermore, these prices are significantly higher than those
in Michigan where the utilities have long been under an obligation to
rely on fixed price contracts and other hedging instruments to mitigate
price volatility.

  -------------- -------------- -------------- -------------- --------------
                 Columbia Gas   Dominion East  Cincinnati Gas Vectren Energy
                 of Ohio        Ohio           & Electric     Delivery
                                                              Service

  January 2001   \$.77387       \$.71760       \$.7666        

  July 2001      \$.92309       \$.86990       \$.6887        

  January 2002   \$.50534       \$.56476       \$.4800        

  July 2002      \$.47369       \$.36464       \$.3437        

  January 2003   \$.68640       \$.56696       \$.47834       \$.54185

  July 2003      \$1.00837      \$.66630       \$.85421       \$.80709

  October 2003   \$.75895       \$.89980       \$.7213        \$.72632
  -------------- -------------- -------------- -------------- --------------

The following chart shows the data in the table in a format that clearly
demonstrates the higher rates for natural gas supply in effect for
Columbia Gas compared to the other Ohio natural gas utilities. This is
likely a key explanation, as well, for the higher rates of customer
migration to alternative natural gas suppliers in that service
territory:

![](media/image5.wmf)

**Oregon**

Oregon (and other Pacific Northwest states) has historically enjoyed
stable and relatively low natural gas prices due to their ability to
access cheaper Canadian gas. However, this low cost advantage has been
changing as the nation's pipelines have become more integrated and the
Northeast and Midwest price and supply difficulties have reverberated in
the Northwest. Oregon's approach to the pricing of natural gas supply is
quite different from Northeast and Midwest policies. First, Oregon gas
utilities file an annual rate change to reflect purchase gas costs. This
rate change appears on customer bills as a single cents-per-therm price.
The Purchased Gas Adjustment filing sets rates based on projected gas
costs for the upcoming year and then also reconciles the prior year's
actual gas costs with the PGA in effect during the prior year. With
respect to any deferrals that are incurred, NGDCs can either accept at
20/80 percentage sharing (20% to the gas company) with an annual
earnings review or accept a 33/67 percentage sharing with no required
annual earnings review. While a gas utility can file for a more frequent
change in rates to reflect gas costs, this is not typical.

Second, the Oregon PUC has experimented with decoupling policies that
seek to break the link between a utility's sales and profits that has
the supposed effect of discouraging energy efficiency investments and
programs. This is important in a state that has a strong policy of
favoring energy efficiency programs as a means of addressing high
utility costs and prices. Finally, two of Oregon's NGDCs fund low-income
bill payment assistance by means of surcharges on customers' bills and
one NGDC has implemented a Public Purpose Funding surcharge to fund
energy efficiency programs, market transformation programs, and
low-income energy efficiency programs to benefit low-income residential
and small commercial customers in its service territory.

Oregon's largest natural gas utility is Northwest Natural Gas Co., which
serves over one-half million residential customers. In 2002, the PUC
approved a Stipulation that contained a Partial Decoupling Mechanism and
an Elasticity Adjustment. These adjustments do not reflect a full scale
decoupling mechanism, such as the PUC had approved for PGE and
PacifiCorp in the late 1990's. Under the elasticity adjustment, NW
Natural will recover, on a prospective basis, an additional charge
applied to rates for residential and commercial customers. The purpose
of this adjustment is to help account for the affect that rate changes
have on customer usage. Under the partial decoupling mechanism, NW
Natural will defer and amortize 90% of the margins associated with the
difference between each group's weather-normalized usage and usage
baseline. Again, this results in an adjustment (positive or negative)
included in rates for residential and commercial customers. As of
October 2003, the residential rate of \$.92213 per therm includes a
Price Elasticity Adjustment of \$.00304 per therm and a Partial
Decoupling Mechanism Adjustment of \$.00305 per therm. These decoupling
mechanisms were accompanied by stipulated provisions that implemented
Public Purpose Funding for low-income bill payment assistance (\$.25 per
residential customer per month), low-income weatherization assistance
(.25% (one quarter of one percent) of the customer's monthly bill for
residential and commercial customers) and enhanced energy efficiency
programs (.65%, but recently increased to 1.25%, of the customer's
monthly bill for residential and commercial customers). NW Natural also
agreed to transfer the responsibility for its energy efficiency,
demand-side management program, and energy audits to the Energy Trust of
Oregon[^63], an entity created to implement the public purpose and
renewable programs associated with the electric restructuring
legislation in Oregon.

The Commission has also recently approved a weather adjustment mechanism
for NW Natural called WARM. The purpose of this adjustment is to true up
the NGDC's fixed costs on a monthly basis for each customer during the
winter. After a cold month the customer will get a credit reflecting
that the per therm rate overcollects fixed costs due to increased usage
alone. After a warm month the customer will get a surcharge that
reflects the fact that the per therm rate undercollects fixed costs.
Customers can individually opt out of this program. The fact that this
adjustment operates on a monthly basis makes the connection between the
cold or warm weather immediately visible on customer bills, a connection
which would not occur if the weather normalization adjustment was
included in an annual decoupling mechanism.

Avista Utilities operates under a difference incentive plan called the
Natural Gas Benchmark Mechanism[^64]. Under this methodology, Avista
Utilities prices natural gas based on a consolidated of gas procurement
operations under the Company's affiliate, Avista Energy. The methodology
reflects short term acquisitions, fixed and hedged contracts, off system
sales, and actual transportation and storage costs. This methodology
also reflect administrative and general cost savings that are passed
through to Oregon customers. Avista is required to enter into a minimum
amount of hedged transactions on a schedule that acquires 35% of the
annual usage in a staggered schedule beginning in February of each year.
This is referred to as the "fixed" portion of the hedged portfolio. In
addition, there is a discretionary hedge volume that is triggered under
certain market conditions. While gas costs are established on October 1
of each year, deferrals or refunds due to customers as a result of the
actual cost of gas incurred monthly are calculated on a monthly basis
and reflected in customer rates as a PGA Adjustment at a later time.

While not reflected on customer bills, the Weighted Average Cost of Gas
adjustment is reviewed and approved separately by the Commission. The
following Table shows the changes ordered for the two largest natural
gas utilities as of October 1 of each year, expressed in a per ccf price
format to allow for comparisons among the various charts and tables in
this report:

+-----------------------+-----------------------+-----------------------+
|                       | NW Natural[^65]       | Avista Utilities[^66] |
+-----------------------+-----------------------+-----------------------+
| 1999                  | \$.22961              | \$.23667              |
+-----------------------+-----------------------+-----------------------+
| 2000                  | \$.35775              | \$.32438 (October)    |
|                       |                       |                       |
|                       |                       | \$.54666(December)    |
+-----------------------+-----------------------+-----------------------+
| 2001                  | \$.53910              | \$.41880              |
+-----------------------+-----------------------+-----------------------+
| 2002                  | \$.38758              | \$.38587 ((April)     |
|                       |                       |                       |
|                       |                       | \$.32825 (October)    |
+-----------------------+-----------------------+-----------------------+
| 2003                  | \$.42772              | \$.41324              |
+-----------------------+-----------------------+-----------------------+

**Arizona**

Arizona has adopted the traditional Purchased Gas Adjustor clause, which
adjusts monthly to reflect changes in the utility's average cost of
natural gas over the previous 12 months. The PGA reflects the difference
between the base cost of gas (reflected in the utility's base rates as
set in the last rate case) and the actual cost of the natural gas
commodity. As a result, the PGA itself does not reflect the total cost
of natural gas supply.

In 1998, the Arizona Corporation Commission (ACC) adopted the
recommendations on gas purchasing policies as reflected in a Staff
Report on Purchased Gas Adjustor Mechanisms.[^67] The Commission adopted
the following recommendations:

-   The NGDCs should pursue longer term, fixed price supply options as a
    viable option in procuring natural gas supplies. Such an approach
    will be deemed prudent and reasonable based on the situation at the
    time the utility entered into the contract. The Staff Report
    acknowledged that the purchase of longer term fixed price supply
    contracts for all or a portion of an NGDC's gas supplies would (all
    else being equal) result in somewhat higher prices compared to spot
    market prices due to the premium often charged for such longer term
    fixed price contracts. However, the Commission endorsed the notion
    of such an approach for at least a portion of the NGDC gas supply
    because of the consumer value of price stability.

```{=html}
<!-- -->
```
-   Price stability is one of the goals of the natural gas procurement
    process.

-   The PGA should be set on the basis of a rolling 12-month average and
    price changes should be banded so that the new rate for a month is
    no more than \$.07 per therm \[now \$.10 per therm\] different than
    the rate in effect during any of the preceding 12 months.

As a result of this policy, Southwest Gas charges residential customers
a total rate of \$.96051 for the first 20 therms and \$.87633 for over
20 therms. This rate is composed of a base rate for distribution
services of \$.48762, a base gas cost of \$.37034, a rate adjustment to
recover low-income program costs of \$.01194, and a monthly PGA
adjustment of \$.09061, effective October 2003.

One advantage of the Arizona approach to pricing natural gas supply
costs is that the Commission can alter the imposition or amount of the
PGA to provide relief from particularly high gas prices during the
winter months when usage spikes. In October 2002, the Commission ordered
a "surcharge holiday" for the months of January and February for
Citizens Arizona customer gas bills. The Commission then extended the
period of time during which the utility could recoup its deferred
balance from ratepayers.[^68]

[^1]: See, e.g. presentations by the Energy Information Administration
    (EIA), as well as a policy paper issued by the U.S. Department of
    Energy on September 25, 2003, available at:
    <http://www.fossil.energy.gov./programs/oilgas/publications/npc/03gasstudy/index.html>
    . This paper does not offer an opinion on the reasons for the recent
    price increases for natural gas.

[^2]: "U.S. Lawmakers Mull Probe Into Surging Natural Gas Prices", [The
    Wall Street Journal Online]{.underline}, December 15, 2003,
    <http://online.wsj.com/article/0,,BT_CO_20031215_004929,00.html>
    This was matched by a similar call by the Chairman of the New York
    Public Service Commission several days later.

[^3]: Testimony of Alan Greenspan, Chairman of the Board of Governors,
    Federal Reserve System, before the U.S. Senate Committee on Energy
    and Natural Resources, July 10, 2003. According to Mr. Greenspan,
    the long term equilibrium price for natural gas has risen
    persistently during the past six years from about \$2 per million
    Btu to more than \$4.50.

[^4]: General Accounting Office (GAO), Natural Gas: Analysis of Changes
    in Market Price, GAO-03-46, December 2002. Available at
    <http://www.gao.gov/new.items/d0346.pdf>

[^5]: Ibid. at 7. The GAO Report did not describe the type and amount of
    hedging that formed the basis for this conclusion, but it should be
    noted that the term "hedging" does not necessarily imply the formal
    procurement planning process that is discussed later in this report.

[^6]: These states have typically not adopted legislative or statutory
    authority that mandates restructuring, but the regulatory commission
    has solicited customer choice programs and their expansion from
    local gas utilities.

[^7]: <http://www.eia.doe.gov/cneaf/electricity/chg_str/custpart.xls>
    (electricity) and
    <http://www.eia.doe.gov/oil_gas/natural_gas/restructure/state/us.html>
    (natural gas) shopping statistics.

[^8]: The statements by the Massachusetts DTE in its January 2001 Gas
    Cost Adjustment Order cited on in the Massachusetts case study in
    this report is the most explicit, but certainly typical, example of
    this approach.

[^9]: Both Pennsylvania and New York have documented the death of a
    residential customer due to lack of natural gas heating following
    disconnection for nonpayment or the inability of the customer to
    obtain reconnection in the face of payment difficulties in recent
    years.

[^10]: See, e.g., Alexander, Barbara, Managing Default Service to
    Provide Consumer Benefits in Restructured States: Avoiding
    Short-Term Price Volatility, National Center for Appropriate
    Technology, 2003 (available at
    <http://neaap.ncat.org/experts/defservintro.htm> ).

[^11]: [Kansas City Star]{.underline}, Page C3, October 23, 2003.

[^12]: In the last several years the Department has accepted and
    implemented more frequent price changes in the Gas Adjustment
    Clause.

[^13]: "Gas Cost Adjustment Order", January 31, 2001, available at
    <http://www.state.ma.us/dpu/gas/01-09/cgacorder.htm>

[^14]: D.T.E. 01-100-A, Investigation by the DTE on its own motion
    pursuant to G.L. c. 164, §§76, 94 and 94A, to investigate the
    appropriateness of the use of the Risk-Management Techniques to
    Mitigate Natural Gas Price Volatility, October 9, 2002, available at
    <http://www.state.ma.us/dpu/gas/01-100/109order.pdf>

[^15]: The MA DTE publishes changes in the CGAC on its website:
    <http://www.state.ma.us/dpu/gas>

[^16]: RI PUC, In Re: New England Gas Co. Gas Cost Recovery Filing,
    Docket No. 3436, Report and Order, May 1, 2003. Available at:
    <http://www.ripuc.ri.gov/order/pdfs/NEGas3436_Ord17444.pdf>

[^17]: New England Gas. Co, "Rhode Island Customer to Avoid Price Spike
    in Natural Gas", September 3, 2003, available at
    [http://www.negasco.com](http://www.negasco.com/).

[^18]: RI PUC, In Re New England Gas Company's Gas Cost Recovery Charge,
    Docket No. 3436, November 21, 2003. Available at:
    <http://www.ripuc.ri.gov/order/pdfs/3436_NEgasOrd17606(11.21.03).pdf>
    The extensive quotation from this order noted above appears at pages
    9-10 with extensive footnotes that are not included in this excerpt.

[^19]: CT DPUC, DPUC Review of the Southern Connecticut Gas Co. Rates
    and Charges Phase IV-Rate Design, Docket No. 99-04-18PH04, May 1,
    2002, available at
    <http://www.dpuc.state.ct.us/FINALDEC.NSF/2b40c6ef76b67c438525644800692943/c6f7602a462352d985256bac006d1a27/$FILE/990418PH04-050102.doc>

[^20]: CT DPUC, Application of Connecticut Natural Gas Corp. for a Rate
    Increase---Rate Design, Docket No. 99-09-03PH03, August 31, 2001,
    available at:
    <http://www.dpuc.state.ct.us/FINALDEC.NSF/2b40c6ef76b67c438525644800692943/3fd62f96b728941285256ab90067bced/$FILE/990903PH03-083101.doc>

[^21]: CT DPUC, Docket No. 01-10-17, et al., Decision, February 22,
    2002, available at:
    <http://www.dpuc.state.ct.us/dockcurr.nsf/17ff825cfc1e297385256b040067883c/7b9c722f86d030e085256c0800548c34/$FILE/011017-022202.doc>

[^22]: The DPUC publishes regular updates of historical natural gas
    supply prices:
    <http://www.dpuc.state.ct.us/DPUCINFO.nsf/9d977919e146d12685256c4e0052595e/a40ef432558602c5852564dc00578d0d?OpenDocument>

[^23]: New York PSC, Policy Statement Concerning the future of the
    Natural Gas Industry in New York State and Order Terminating
    Capacity Assignment, Case 97-G-1380, November 3, 1998. The
    Commission clarified some aspects of this order in April 1999. See
    <http://www.dps.state.ny.us/fileroom/doc4962.pdf> and
    <http://www.dps.state.ny.us/fileroom/doc5666.pdf> .

[^24]: The New York PSC publishes Gas Retail Access Migration statistics
    on its website: <http://www.dps.state.ny.us/Gas_Migration.htm>

[^25]: New York PSC, Proceeding on Motion of the Commission as to the
    Rates, Charges, Rules and Regulations of NYSEG for Gas Service, Case
    01-G-1668, November 20, 2002, available at
    <http://www.dps.state.ny.us/fileroom/doc12529.pdf>.

[^26]: New York PSC, Proceeding on Motion of the Commission as to the
    Rates, Charges, Rules and Regulations of National Fuel Gas
    Distribution Corp., Case No. 00-G-1858, September 18, 2003,
    available at: <http://www.dps.state.ny.us/fileroom/doc11550.pdf>

[^27]: New York PSC, Order Concerning Gas Rates, Restructuring,
    Competition, and other Issues, Case 00-G-1456, April 22, 2002,
    available at: <http://www.dps.state.ny.us/fileroom/doc11565.pdf>

[^28]: While the Commission favorably quoted staff opposition to PULP's
    stable commodity procurement policy on the grounds that costs would
    be incurred to implement hedging, thus resulting in higher commodity
    costs, the Commission does not explain why higher rates to pay for
    promotional efforts and other costs incurred to implement retail
    competition choice programs are acceptable.

[^29]: See <http://www.dps.state.ny.us/bills.htm> In addition, PULP has
    prepared a Table presenting average residential customer bills for
    all New York gas utilities for the period July 1997-January 2003.
    This chart confirms the extreme volatility in winter bills for
    residential customers of Brooklyn Union Gas, Keyspan East (Long
    Island), NFDC, and Orange and Rockland. See
    [http://www.pulp.tc](http://www.pulp.tc/)

[^30]: See New Jersey Gas Switching Statistics at
    <http://www.bpu.state.nj.us/energy/gasSwitchData.shtml>. Most of the
    residential switchers are South Jersey Gas Co. customers.

[^31]: NJ BPU, The Provision of Basic Gas Supply Service Pursuant to the
    Electric Discount and Energy Competition Act, N.J.S.A. 48:3-49
    et.seq., Order Approving BGSS Price Structure, Docket No.
    GX01050304, December 13, 2002.

[^32]: NJ BPU, Docket No. GR02090702, et seq., June 20, 2003.

[^33]: Most of the gas utilities are operating under an agreed-upon
    percent of their portfolio that is hedged (non-discretionary) and a
    percentage of their portfolio that is subject to, but not required
    to be hedged (discretionary).

[^34]: NJ BPU. Order Authorizing Provisional Rates, Docket No.
    GR00070491, November 1, 2000, at 9.

[^35]: NJ BPU, Decision and Order, Docket Nos. GR99100778, et seq.,
    March 30, 2001.

[^36]: See the 2000-2003 press releases at the New Jersey Natural Gas
    Co. website:
    <http://www2.njresources.com/news/trans/NewsRpt.asp#njng>

[^37]: NJ BPU, Decision and Order Approving Stipulation, Docket Nos.
    GR99100778, et seq., November 13, 2003, available at the BPU
    website:
    <http://www.bpu.state.nj.us/wwwroot/energy/GR99100778_20031113.pdf>

[^38]: Typically and here, the Stipulation was negotiated and signed by
    the Board Staff (represented by the Attorney General's office), the
    Division of the Ratepayer Advocate, and the gas utility.

[^39]: PSC of West Virginia, Mountaineer Gas Co., In the Matter of Rates
    and Charges on and after November 1, 1998, Case No. 98-0008-G-42T,
    Commission Order, July 17, 1998.

[^40]: Ellis, David, Director of Utilities Division, PSC of West
    Virginia, "A Report on Natural Gas Pricing and an Evaluation of
    Opportunities for Price Risk Management Through Various Hedging
    Options", July 11, 2001. Available at
    <http://www.psc.state.wv.us/Special_Reports/hedging.pdf>

[^41]: For example, it appears from a review of PSC orders that some gas
    utilities account for underground storage costs in base or delivery
    rates and not in the PGA.

[^42]: Nor do the utilities state the current PGA on their websites.

[^43]: Available at <http://www.accessarkansas.org/psc/compare-Gas.htm>

[^44]: AR PSC, In the Matter of a Notice of Inquiry into whether
    Arkansas Gas Utilities Should Integrate Gas Price Heding, Fixed
    Price Options, and Other Alternative Mechanisms into Gas Procurement
    Plans, Docket No. 01-023-NOI, June 20, 2001, available at
    <http://170.94.29.3/rules/rulesnatgasprocureplanrules.pdf> . These
    principles were then formally adopted as rules on April 19, 2002.

[^45]: AR PSC, Docket No. 02-179-U, where a Joint Stipulation and
    Settlement Agreement was filed on August 29, 2003 and is pending
    before the Commission. As part of this filing, the utility's
    2003-2004 gas procurement plan is available.

[^46]: At 7 and 10. This report is available at the IRC's website:
    <http://www.in.gov/iurc/issues/regflex/rf_natgas_03.pdf>

[^47]: IN URC, Causes No. 37399-GCA67 through 37399-GCA70, August 8,
    2001.

[^48]: IN URC, Cause No. 37399-GCA75, September 4, 2002.

[^49]: IN URC, Cause No. 41338-GCA4, September 10, 2003.

[^50]: The March 2003 GCA was \$.8194 per therm. See
    <http://www.nipsco.nisource.com/rates/tariffs/g_rates/ccgh.htm>

[^51]: All the presentations are available at
    <http://www.in.gov/iurc/utilities/energy/03natgas/03_natgas_index.html>

[^52]: Available at <http://www.in.gov/iurc/issues/billcomps/index.html>

[^53]: This very high price reflects the utility's previous year's gas
    supply costs that were approved to be carried over into the next
    year in an attempt to smooth out "sticker shock."

[^54]: MI PSC, Natural Gas Price and Supply Update, July 29, 2003.
    Available at
    <http://www.michigan.gov/documents/Natgasupd2003Jul11_69868_7.pdf>

[^55]: Ibid., at 2.

[^56]: M.C.L. Chapter 460.6h(3).

[^57]: MI PSC, Case No. U-13570, July 8, 2003, available at
    <http://www.cis.state.mi.us/mpsc/orders/gas/>

[^58]: MI PSC, Case No. U-13549, January 21, 2003.

[^59]: MI PSC, Case No.U-13060, March 12, 2003.

[^60]: Case No. 03-1384-GA-ORD, July 1, 2003, available at the PUCO
    website by selecting the Orders and Entries database and selecting
    the week that the order or entry was issued.

[^61]: Joint Initial Comments on Behalf of The Ohio Gas Marketers' Group
    and National Energy Marketers Association, Case No. 03-1384-GA-ORD,
    August 1, 2003.

[^62]: These prices are taken from the Ohio PUC's "Apples to Apples"
    Natural Gas Comparison Charts" available in the archive of the PUCO
    website: <http://www.puco.ohio.gov/emplibrary/files/NgA2A/Archive/>

[^63]: See <http://www.energytrust.org/>. Subsequent to this
    Stipulation, the PUC approved a request to allow NW Natural to
    operate the low income energy efficiency program instead of an
    external agency, such as Energy Trust. Case UG 143, September 23
    2003. The utility will form an advisory committee and implement
    these programs through local Community Action Program agencies.

[^64]: Avista Utilities Tariff, Schedule 464, PUC OR No. 4, available at
    <http://www.avistautilities.com/prices/rates/>.

[^65]: As provided in NW Natural 2003 PGA filing, Case UG 156, Order No.
    03-587, October 2, 2003, page 5.

[^66]: As provided in Avista Utilities, 2003 PGA filing, Case No. UG
    154, Order No. 03-588, October 1, 2003.

[^67]: Arizona CC, In the Matter of the Commission Examination of Local
    Distribution Company Purchased Gas Adjustor Mechanisms, Docket No.
    G-00000C-98-0568, October 30, 1998.

[^68]: See the ACC press release at
    <http://www.cc.state.az.us/news/pr10-25-02.htm>