D.T.E. 01-09
Bay State Gas Company's Request for Authorization to Adjust its Gas Adjustment Factors.
D.T.E. 01-10
Berkshire Gas Company's Request for Authorization to Adjust its Gas Adjustment Factor
D.T.E. 01-11
Blackstone Gas Company's Request for Authorization to Adjust its Gas Adjustment Factor
D.T.E. 01-12
Boston Gas Company's Request for Authorization to Adjust its Gas Adjustment Factor
D.T.E. 01-13
Colonial Gas Company's Request for Authorization to Adjust its Gas Adjustment Factor
D.T.E. 01-14
Commonwealth Gas Company's Request for Authorization to Adjust its Gas Adjustment Factor
D.T.E. 01-15
Essex Gas Company's Request for Authorization to Adjust its Gas Adjustment Factors
D.T.E. 01-16
Fall River Gas Company's Request for Authorization to Adjust its Gas Adjustment Factor
D.T.E. 01-17
North Attleboro Gas Company's Request for Authorization to Adjust its Gas Adjustment Factor
D.T.E. 01-18
Fitchburg Gas and Electric Light Company's Request for Authorization to Adjust its Gas Adjustment Factors

APPEARANCES:

Donna K. Sharkey, Esq.
Rubin and Rudman LLP
50 Rowes Wharf
Boston, Massachusetts 02110
FOR: Bay State Gas Company

Robert J. Keegan, Esq.
Cheryl M. Kimball, Esq.
Keegan, Werlin & Pabian, LLP
21 Custom House Street
Boston, Massachusetts 02110
FOR: Boston Gas Company
Colonial Gas Company
Commonwealth Gas Company
Essex Gas Company
Fall River Gas Company
North Attleboro Gas Company

James M. Avery, Esq.
Rich, May, Bilodeau & Flaherty, PC
176 Federal Street
Boston, Massachusetts 02110
FOR: Berkshire Gas Company

Andrew J. Newman, Esq.
Rubin and Rudman LLP
50 Rowes Wharf
Boston, Massachusetts 02110
FOR: Blackstone Gas Company

Patricia M. French, Esq.
LeBoeuf Lamb Green & MacRae LLP
260 Franklin Street
Boston, Massachusetts 02110
FOR: Fitchburg Gas and Electric Light Company

The situation in today's gas markets, whether national or local, has no precedent. In December and January, all ten gas local distribution companies (LDCs) filed to increase their customer billing charges to recover increased costs to buy and supply natural gas. The requested increases for a typical residential heating customer ranged from 8.33 percent to 65.9 percent and came on top of increases of about 24.3 percent allowed in November. Recovery is sought through increases in the Cost of Gas Adjustment Clause (CGAC) or Gas Adjustment Factor (GAF) on the customer bill.

Stable at about $2.00 - $2.50 per therm (100,000 Btu) from 1985 to 1999, unregulated gas costs nearly quintupled in 2000-01. The increase is unprecedented. Gas costs, in fact, declined by 30 percent in real terms over the fifteen years ending with 1999. Lower prices discouraged exploration, but spurred demand. Environment regulation and siting considerations made gas the fuel of choice for new power plants. The winters of 1998-99 and 1999-2000 were two of the warmest in the history of the U.S. Weather Bureau; the winter of 2000-01 has been the coldest across the entire U.S. in the 105 years of Bureau record-keeping. Latent demand accumulated in the previous warm winters became actual demand this winter. Price has risen steeply as a result.

A customer's gas bill has two parts: (1) the CGAC which recovers dollar-for-dollar, without any profit, an LDC's costs of gas itself, purchased on the unregulated interstate market, and of interstate pipeline charges set by the Federal Energy Regulatory Commission; and (2) distribution rates set under G.L. c. 164, Sec. 94, to recover an LDC's operating costs for bringing gas from the interstate pipeline, the distribution system, and to a customer's meter (e.g., labor, mains and service lines, office supplies, insurance, etc.). Only the CGAC is at issue in this proceeding. Base rates can be changed only after a nearly year-long proceeding under G.L. c. 164, §§ 93 or 94.

The Department's evaluation balanced effects of present CGAC increase against problems with deferring cost recovery to later, i.e., to the 2001-02 heating season. Some cost deferral is acceptable. Excessive deferral would compound the present problem: (1) customers would pay interest as unrecovered amounts; (2) some gas companies are already or near borrowing limits, and mounting deferrals may jeopardize their finances, and thereby their ability to serve customers; and (3) large commercial and industrial customers may, if today's costs to serve them are deferred to next year, elect to purchase their gas commodity in 2001-02 from independent marketers (rather than have their LDC procure it for them) and thereby escape the operation of next year's GAF altogether. This escape would leave their portion of this year's GAF to be paid by smaller, captive customers, unattractive to marketers (e.g., residential and small business users). Avoiding excessive deferrals averts these risks.

Having balanced concerns for bill continuity against problems caused by excessive deferrals of gas costs to next year and having examined the softening trend in natural market indices for gas (e.g., NYMEX), the Department has reduced the increase requests in the proposed GAF as follows: Bay State Gas by 41.18 percent; Berkshire Gas by 10.0 percent; Boston Gas by 46.82 percent; Colonial Gas by 44.5 percent; Commonwealth Gas by 17.78 percent; Essex Gas by 37.02 percent; Fall River Gas by 16.28 percent; Fitchburg Gas and Electric Light by 9.76 percent; and, North Attleboro Gas by 7.44 percent. Blackstone Gas's request was not reduced: that LDC is too small to absorb deferrals above what it already has accumulated. The companies are directed to file plans for reducing deferrals further over the off-peak season (May - October).

The Department also directed the companies to (1) extend the moratorium on shut-offs for non-payment from March 15 to May 1, (2) re-open their levelized billing plans immediately to all customers, and (3) promote their energy conservation programs aggressively.

The Department announced a rulemaking investigation for May 2001 to examine ways to make the GAF more price-responsive to reflect the fact that natural gas costs nationwide have become more volatile. New York, Connecticut, and New Hampshire have monthly adjustments; Massachusetts' adjustment is semi-annual. All four states have similar costs. The other three have achieved cost recovery with less abrupt shifts.

I. Introduction
In December 2000 and January 2001, the Department of Telecommunications and Energy ("Department") received requests from the ten local distribution companies ("LDCs" or "Companies") for authorization to increase their peak Gas Adjustment Factor ("GAF") (1) as a result of substantial increases in natural gas commodity prices. (2) 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 LDC noted that the increases in gas commodity costs are driven by national and international forces beyond either the Department's or the Companies' control. In their filings, and in presentations at the public hearings, the Companies noted that one reason for the increase in commodity costs is the historical cold winter that we have experienced nationwide. The winter of 2000/2001 is markedly different from the recent past. Historically, cold weather has affected only limited regions of the nation during any given week of a winter season. What is unprecedented this winter is that virtually every state in the nation has experienced weather that is colder than normal, with many states seeing weather significantly colder than normal. Winter 2000-01 is the coldest nationwide in the 105 years of U.S. Weather Bureau records. It follows two of the warmest winters on record during which latent demand increased. Today, there is anincreased demand for natural gas resulting from a strong economy and the increasing use of gas to generate electricity. (3) Also, on the supply side, relatively low gas and oil prices in recent years resulted in less exploration for, and production of, gas at the well-head. In combination, these factors are driving up the priceof natural gas, heating oil and electricity, to unusually high levels.

The Department conducted a detailed review and investigation of each filing to determine whether the LDC met its burden to appropriately document the calculations pursuant to 220 C.M.R. § 6.00 et seq. Moreover, the Department held a dozen hearings throughout the Commonwealth to listen to the views and concerns of the public and elected officials and to provide them with the opportunity to understand the reasons for the requested increases by the LDCs. (4)

II. Description of a Gas Bill
Before discussing the GAF filings themselves, we describe the components of a consumer's gas bill. The total price paid for natural gas by Massachusetts consumers depends on (1) the price of the gas commodity itself; (2) the cost of storing and transporting the gas from production areas to the LDCs' service areas (interstate transportation); and (3) the cost of distributing that gas (via the local distribution system) to the customers.

A gas bill has two components: (1) a gas supply component, containing gas commodity and interstate transportation costs ( i.e. the cost of gas itself and the cost of transporting it from Texas, Louisiana, or Canada to the LDC); and (2) a base rate component, designed to recover all distribution-related costs, including plant and equipment, labor, taxes, interest on borrowed money, return on investment, billing, metering, and customer service ( i.e., the cost to operate the LDC).

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. From 1954 into the late 1970s, the federal government controlled the wellhead price of natural gas charged by producers. Federal price controls kept wellhead prices low, which also artificially depressed production to such an extent that a national system of customer service curtailments had to be implemented to manage chronic shortages. During the Carter Administration, Congress responded to the natural gas shortages by enacting legislation that led to an increase in the flow of gas into the interstate market. Passage of the Natural Gas Policy Act ("NGPA") of 1978 effectively terminated federal control over the wellhead price of "new" gas as of January 1, 1985, but maintained (for a time) wellhead price controls for older, "vintage" gas. The purpose of the NGPA was to encourage and permit a competitive wellhead market where market forces would determine the supply, demand and ultimately the price of natural gas.

In 1989 Congress lifted all remaining wellhead price controls on natural gas with the passage of the Natural Gas Wellhead Decontrol Act. The result was an increasing abundance of supply and consequent drop in the price of natural gas throughout the 1980s and well into the 1990s. From 1985 to 1999, gas prices fell by 30 percent in real terms. Today, there are no remaining federally-mandated wellhead prices. 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 in 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.

The Department does not regulate interstate transportation. The cost of interstate transportation is regulated by the Federal Energy Regulatory Commission ("FERC"). (5) The cost of local distribution is determined by the Department. The Companies do not propose any increases to the interstate transportation component, nor to the base rate component. In fact, for certain gas companies, base rates have been and will be frozen for several years.

Costs incurred by the LDCs for the purchase, storage, and interstate transportation of gas (referred to as gas supply costs) are recovered via the Cost of Gas Adjustment Clause ("CGAC") on a dollar-for-dollar basis. See 220 C.M.R. § 6.00. That is, LDCs do not profit on the gas commodity component of a gas bill, and the cost of gas is a straight pass-through. LDCs earn a rate of return solely and entirely on their investment in local distribution facilities, i.e., the second component of the gas bill.

Gas supply costs are fully reconciled. Each September 15 th, every LDC files a reconciliation accounting of its prior year's costs, stating actual costs incurred to procure gas and comparing costs to what was charged to customers under the previous gas year's GAF. Each LDC proposes, for Department review and approval, either supplemental recovery from customers for the LDC's under-recovery of gas costs or a credit to customers for the LDC's over-recovery of gas costs (both with interest). The Department investigates the Companies' accounting to ensure that the reconciliation leads to the recovery of only the gas supply costs actually incurred. Stability in gas commodity prices throughout the 1980s and 1990s meant that both over- and under-recoveries tended to be small and manageable each year -- until 2000-2001.

III. Deferrals vs. Bill Impacts
After 25 years of wellhead price controls, followed by nearly 20 years of gas supply abundance and stable or declining prices, this winter's situation is utterly without precedent. Yet, the Department must apply the law and cannot take refuge in rhetoric. In assessing the LDCs' current GAF filings, the Department is faced with the difficult task of balancing (a) cost recovery at rates that may challenge our goal of rate continuity, (6) against (b) the potentially greater harm of increasing deferrals to be recovered in the future ( i.e., 2001-02) with interest. As we discuss below, recent softening of New York Mercantile Exchange ("NYMEX") prices ( i.e., since the filings in early January 2000) indicates that gas costs in February and March, though higher than last year, may not be as dramatic as they were predicted to be (however reasonably) in early January or late December. Nonetheless, deferral of recovery of excessive amounts to the next heating season could create serious additional problems and is ill advised. Deferral will impose otherwise avoidable interest charges on customers and may jeopardize a company's ability to serve customers by impairing the LDC's credit rating and access to borrowing. (7) In addition -- and this is worrisome to anyone knowledgeable in gas regulation -- deferral of significant amounts runs the risk that large users of gas ( e.g., commercial and industrial users) may obtain their gas commodity next heating season directly from marketers, rather than from their LDC, solely on the basis of avoiding deferred costs. By going to marketers, large commercial and industrial customers could avoid next year's CGAC and leave behind costs that they actually incurred this year to be paid next year by captive, smaller customers, typically residential or small commercial users. Given that such a scenario is inequitable, the Department rejects deferring CGAC recovery, any more than is necessary to mitigate rate shock.

The Department's review of the Companies' filings confirms that the Companies are under-collecting gas supply costs and the Companies are accruing deferrals at a significant and highly problematic rate. (8) If rates do not presently recover costs incurred for gas provided, then serious adverse financial consequences are risked. (9) The total amount of costs deferred for future recovery could well grow to a level that would threaten the financial viability of the LDCs and with it, their ability to serve their customers. A gas company has a statutory obligation to serve its customers in an efficient and cost-effective manner. See G.L. c. 164, § 69I. Where it does so, a gas company is entitled to an opportunity to recover its legitimately-incurred gas costs. 220 C.M.R. § 6.00 et seq. Imposing an obligation to serve but denying the opportunity to recover legitimate costs incident to meeting that obligation is confiscatory and unconstitutional. It would invite - perhaps even court- appellate reversal. While the final reconciliation of the 2000-01 GAF must await the September 15 filing, the Department notes that its actions today conform with the Senate Resolution of January 25, 2001. We expressly find that constitutional safeguards require that where the law imposes an obligation to serve, with implied attendant costs to serve, a regulator cannot deny recovery of costs fairly and efficiently incurred to meet that legal obligation. Chapter 164 imposes just such an obligation.

Nonetheless, the Department is mindful of the effect these increases will have on ratepayers, especially low-income customers. The question is whether customers should pay now for costs legitimately incurred to serve them or whether deferral of recovery of gas costs to a later date and at interest is the better course. If today's increased costs are postponed and recovered through next October's reconciliation adjustment in the 2001-02 peak period, LDC customers will be paying some of this year's increased gas costs next winter on top of what already promises to be higher prices than witnessed in the 1985-99 period.

Equity requires us to ensure that customers on whose behalf costs are incurred are the same customers who bear these costs. No one ( e.g., large commercial or industrial customers) should be allowed to run up a large bill and leave it for others to pay. Our goal is to reduce deferrals as much as possible, tempered by rate continuity concerns, so as to eliminate any artificial incentives that would cause customers to migrate to marketers and thereby avoid payment of costs incurred on their behalf, leaving behind their bills to be paid by others. While the reduction of deferrals is crucial, the Department has also balanced the impacts of GAF increases on consumers' bills.

Concerning the actual gas commodity costs realized by LDCs, the Department notes that over the past four months, there have been steep and significant increases in the prices of natural gas. For example, the October 2000 NYMEX price settled at $5.31 per One Million British Thermal Units ("MMBtu"), while, at the time that the LDCs submitted their current filings, the January 2001 NYMEX was as high as $10.01 per MMBtu. Natural Gas Intelligence Weekly Gas Prime Index, Volume 13, Number 34 (1/1/01).Furthermore, these prices are about $7.50 per MMBtu higher than they were a year ago at this time, representing more than a four-fold increase. Energy Information Administration Office of Oil and Gas, January 3, 2001.

The January 2001 filings represented the actual and NYMEX prices at the time of filing; thus it was reasonable to forecast continuance of high prices, given historically cold weather and other market conditions. Gas commodity prices, however, have recently decreased from these record high levels. This moderation will ameliorate the under-recovery position for the LDCs in that the total amount under-collected will likely be lower than threatened. This allows the Department to adjust the GAFs of the LDCs to levels below those proposed. Conversely, given the potential financial impact on both the consumers and the companies, the Department was limited on how much, if at all, it could reduce the GAFs for those companies that had proposed deferring recovery of some commodity costs to the end of the current peak season.

The Department's review of the CGAC filings indicated that approval of the proposed GAFs would result in either no deferrals ( e.g., in the cases of Boston Gas, Colonial, Essex, Bay State) or still leave significant deferrals as of the end of this peak season (April 30, 2001). In balancing our goals of rate continuity and the desire to minimize the level of deferrals, the Department adjusted the proposed GAFs, based on company-specific circumstances. Thus, to ensure that prices are set at levels that recover all or a significant portion of the costs incurred, and in order to avoid the buildup of significant under-recoveries that would impair the Companies' ability to serve their customers, the Department approves the modified versions of the LDCs' GAFs, as shown in Table 1 attached to this Order.

To lessen the impact of the deferral on the prices for next winter, the Department directs the LDCs to attempt to recover a portion of their present under-recovery in the off-peak period (May through October) and to account for this direction in their March 15, 2001 CGAC filings.

IV. Service Shut-offs/Budget Billing
There are several programs currently available to consumers that could lessen the effect of commodity GAF increases on consumers this winter. These programs include, but are not limited to, level billing plans, payment plans, and energy conservation. (10) To ensure that each consumer is able to take advantage of company billing programs, the Department directs the Companies to: (1) immediately make available to all customers, the Companies' level billing plans, whether or not customers have enrolled in such a program prior to the deadline for doing so; (2) extend the suspension for service shut-offs from March 15, 2001 to May 1, 2001; (11) (3) encourage all customers to utilize energy conservation programs offered by the LDCs. The Companies are directed to inform the Department by February 15, 2001, of all measures taken to affirmatively inform their customers of these requirements and to accommodate customer requests to avail themselves of these programs.

V. Future Actions
Because this winter's dramatic and unprecedented increases in gas commodity costs are historic, the Department needs to review the CGAC mechanism and perhaps to 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. Therefore, the Department will open a rulemaking, in May 2001, designed to review and amend the Department's CGAC regulations, 220 C.M.R. § 6.

VI. Specific LDC filings
Here, the Department balances the need to avoid deferrals to 2001-2002 against the policy of mitigating severe billing swings. Each Company's circumstances varies from another's. Accordingly, consistent with balancing the two goals, we treat the companies somewhat differently in detail. As shown in Table 2, Bay State, Boston Gas, Colonial and Essex have proposed GAFs designed to eliminate their under-recovered costs as of the end of April 2001. In other words, these LDCs proposed to recover all of their actual costs incurred yet not recovered in the months of November and December 2000 as well as the higher projected costs for January through April 2001. As a result, the bill impact comparisons for these four companies were relatively higher than those of the remaining six companies who designed their proposed GAF so as to still lead to a significant under-recovery as of the end of this peak season (April 30th). Accordingly, in arriving at the final GAF for Bay State, Boston Gas, Colonial, and Essex, the Department's reduction of the proposed GAFs for those companies is larger than the adjustment to the proposed GAFs of the companies that did not seek to recover all of their costs over the next three months.

A. Bay State Gas Company
On December 15, 2000, Bay State Gas Company ("Bay State Gas") filed a revision to its peak period Gas Adjustment Factor ("GAF"). Bay State Gas proposed the following GAFs: (12)

Res. Heat. $0.9002
Res. Non-Heat. $0.8090
G-50 $0.8531G-40 $0.9109G-51 $0.8428
G-41 $0.9189G-52 & 53 $0.8530G-42 & 43 $0.9227 (13)

On January 5, 2001, Bay State Gas submitted yet another revision to its GAF and proposed the following GAFs to be applied to firm gas sales during the billing months of February through April, 2001:

Res. Heat. $1.0728
Res. Non-Heat. $0.9816
G-50 $1.0257G-40 $1.0835G-51 $1.0154
G-41 $1.0915G-52 & 53 $1.0256G-42 & 43 $1.0953

Bay State Gas stated that without the proposed adjustment, Bay State Gas would under-collect $38,301,832 or $0.14 per therm which would result in an artificially-increased 2001/2002 peak period GAF.

B. Berkshire Gas Company
On December 18, 2001, Berkshire Gas Company ("Berkshire") filed a revision to its peak period Gas Adjustment Factor ("GAF"). Berkshire proposed a GAF of $0.8590 per Ccf to be applied to firm gas sales during the billing months of February through April, 2001. Berkshire stated that without the proposed adjustment, it would under-collect approximately $7.4 million or $0.20 per Ccf by April 30, 2001, which would result in an artificially-increased 2001/2002 peak and 2002 off-peak period GAFs. According to Berkshire, even if the Department were to approve its proposed GAF, it would still under-recover its peak commodity costs by about $5.2 million or $0.14 per Ccf.

C. Blackstone Gas Company
On December 21, 2001, Blackstone Gas Company ("Blackstone") filed a revision to its peak period Gas Adjustment Factor ("GAF"). (14) Blackstone proposed a GAF of $0.7723 per therm to be applied to firm gas sales during the billing months of January through April, 2001. Blackstone stated that without the proposed adjustment, it would under-collect approximately $246,692 or $0.26 per Ccf by April 30, 2001, which would result in an artificially-increased 2001/2002 peak period GAF. According to Blackstone, even if the Department were to approve its proposed GAF, it would still under-recover its peak commodity costs by about $123,305, or $0.13 per Ccf.

D. Boston Gas Company
On December 20, 2000, Boston Gas Company ("Boston Gas") filed a revision to its peak period Gas Adjustment Factor ("GAF") and proposed a GAF of $0.9643 per therm. On January 11, 2001, Boston Gas submitted yet another revision to its GAF and proposed a factor of $1.3948 to be applied to firm gas sales during the billing months of February through April, 2001. Boston Gas stated that without the proposed adjustment, Boston Gas would under-collect approximately $219 million or $0.41 per therm which would result in an artificially-increased 2001/2002 peak period GAF.

E. Colonial Gas Company
On December 20, 2000, Colonial Gas Company ("Colonial Gas") filed a revision to its peak period Gas Adjustment Factor ("GAF"). Colonial Gas proposed a GAF of $0.8264 per Ccf for its Lowell Division and $.8149 per Ccf for its Cape Cod Division. (15) On January 11, 2001, Colonial Gas submitted yet another revision to its GAF and proposed a factor of $1.1612 per Ccf for its Lowell Division and $1.1497 per Ccf for its Cape Cod Division to be applied to firm gas sales during the billing months of February through April, 2001. Colonial Gas stated that without the proposed adjustment, Colonial Gas would under-collect approximately $49 million or $0.31 per therm which would result in an artificially-increased 2001/2002 peak period GAF.

F. Commonwealth Gas Company
On December 20, 2000, Commonwealth Gas Company ("Commonwealth Gas") filed a revision to its peak period Gas Adjustment Factor ("GAF"). Commonwealth Gas proposed a GAF of $0.8758 per therm. On January 12, 2001, Commonwealth Gas submitted yet another revision to its GAF and proposed a factor of $1.1883 to be applied to firm gas sales during the billing months of February through April, 2001. Commonwealth Gas stated that without the proposed adjustment, Commonwealth Gas would under-collect approximately $50 million or $0.36 per therm which would result in an artificially-increased 2001/2002 peak period GAF.

G. Essex Gas Company
On December 20, 2000, Essex Gas Company ("Essex") filed a revision to its peak period Gas Adjustment Factor ("GAF"). Essex proposed the following GAFs:

R-1 $0.7172R-2 $0.7610
R-3 $0.7796R-4 $0.7931
R-5 $0.7581R-6 $0.7875
E-1 $0.6821G-41 $0.7806
G-42 $0.7886G-43 $0.7130
G-51 $0.7493G-52 $0.7434
G-53 $0.7416

On January 11, 2001, Essex revised the GAF to be applied to firm gas sales during the billing months of February through April, 2001:

R-1 $1.0723R-2 $1.1152
R-3 $1.1221R-4 $1.1380
R-5 $1.0993R-6 $1.1268
E-1 $1.0433G-41 $1.1211
G-42 $1.1319G-43 $1.0570
G-51 $1.1012G-52 $1.0995
G-53 $1.1047

Essex stated that without the proposed adjustment, Essex would under-collect approximately $17 million or $0.35 per therm which would result in an artificially-increased 2001/2002 peak period GAF.

H. Fall River Gas Company
On January 5, 2001, Fall River Gas Company ("Fall River") filed a revision to its peak period Gas Adjustment Factor ("GAF"). Fall River proposed a GAF of $0.9370 per Ccf to be applied to firm gas sales during the billing months of February through April, 2001. Fall River stated that without the proposed adjustment, it would under-collect approximately $17 million or $0.41 per therm by April 30, 2001, which would result in an artificially-increased 2001/2002 peak period GAF. According to Fall River, even if the Department were to approve its proposed GAF, it would still under-recover its peak commodity costs by about $13 million or $0.31 per Ccf.

I. Fitchburg Gas & Electric Company
On January 10, 2001, Fitchburg Gas & Electric Company ("FG&E") filed a revision to its peak period Gas Adjustment Factor ("GAF"). FG&E proposed a GAF of $1.0083 per therm for its Low Winter Use Class and $0.9814 for its High Winter Use Class to be applied to firm gas sales during the billing months of February through April, 2001. FG&E stated that without the proposed adjustment, it would under-collect approximately $4 million or $0.25 per therm by April 30, 2001, which would result in an artificially increased 2001/2002 peak period GAF. According to FG&E, even if the Department were to approve its proposed GAF, it would still under-recover its peak commodity costs by about $1.3 million or $0.08 per therm.

J. North Attleboro Gas Company
On January 5, 2001, North Attleboro Gas Company ("North Attleboro") filed a revision to its peak period Gas Adjustment Factor ("GAF"). North Attleboro proposed a GAF of $1.0235 per therm to be applied to firm gas sales during the billing months of February through April, 2001. North Attleboro stated that without the proposed adjustment, it would under-collect approximately $678,798 or $0.17 per therm by April 30, 2001, which would result in an artificially increased 2001/2002 peak period GAF. According to North Attleboro, even if the Department were to approve its proposed GAF, it would still under-recover its peak commodity costs by about $202,100 or $0.05 per therm.

VII. ORDER
Accordingly, after notice hearings and consideration, the Department

ORDERED: That the Gas Adjustment Factors as proposed by Bay State Gas Company, Berkshire Gas Company, Boston Gas Company, Colonial Gas Company, Commonwealth Gas Company, Essex Gas Company, Fall River Gas Company, Fitchburg Gas and Electric Light Company, and North Attleboro Gas Company are rejected; and it is

FURTHER ORDERED: That the Gas Adjustment Factors of Bay State Gas Company, Berkshire Gas Company, Blackstone Gas Company, Boston Gas Company, Colonial Gas Company, Commonwealth Gas Company, Essex Gas Company, Fall River Gas Company, Fitchburg Gas and Electric Light Company, and North Attleboro Gas Company, be approved as delineated in Table 1 attached to this Order and that such increases be applied to firm gas sales during the billing months of February through April, 2001; and it is

FURTHER ORDERED: That the LDCs comply with all other directives contained herein.

By Order of the Department,
_______________________________
James Connelly, Chairman
W. Robert Keating, Commissioner
Paul B. Vasington, Commissioner
Eugene J. Sullivan, Jr., Commissioner
Deirdre K. Manning, Commissioner


TABLE 1: 2001 PEAK ADJUSTMENT FACTORS

Effective February 1, 2001

CompanyApproved
GAF

CompanyApproved
GAF
BAY STATE GAS($/Therm)COMMONWEALTH GAS($/Therm)
Res Heat.9500All Classes1.1123
Res Non Heat.8588
G-40.9607ESSEX COUNTY GAS($/Therm)
G-41.9687R-1.8602
G-42/43.9725R-2.9031
G-50.9029R-3.9100
G-51.8926R-4.9259
G-52/53.9028R-5.8872
R-6.9147
BERKSHIRE GAS($/Ccf)E-1.8312
All Classes.8483G-41.9090
G-42.9198
BLACKSTONE GAS($/Ccf)G-43.8449
All Classes0.7723G-51.8891
G-52.8874
BOSTON GAS($/Therm)G-53.8926
All Classes1.0626
G-44/G-54 MDCQ2.6251FALL RIVER GAS($/Ccf)
Volumetric.7600All Classes.9253
COLONIAL GAS($/Ccf)FITCHBURG GAS($/Therm)
Cape Division R-1, R-2, G-52, G-53, G-51.9863
All Classes.9170R-3, R-4, G-41, G-42, G-43.9594
Lowell Division
All Classes.9336NO. ATTLEBORO GAS($/Therm)
All Classes1.0068

TABLE 2: PEAK CGAC Filings

UNDER-RECOVERY POSITIONS

CompanyProjected under-recovery amount
April 30, 2001
no revision to current GAF
Peak
Sales
Dollar per unitProjected under-recovery amount
April 30, 2001
GAF as proposed
Dollar per unit
Bay State Gas Co.$ 38,301,832277,034,630$ 0.14$ -$ -
Berkshire Gas Co.$ 7,400,00037,401,470$ 0.20$ 5,200,000$ 0.14
Blackstone Gas Co.$ 246,692942,380$ 0.26$ 123,305$ 0.13
Boston Gas Co.$219,000,000524,304,000$ 0.42$ -$ -
Colonial Gas Co.$ 49,000,000160,125,580$ 0.31$ -$ -
Commonwealth Gas Co.$ 50,000,000137,670,000$ 0.36$ 11,667,000$ 0.08
Essex Gas Co.$ 17,000,00048,808,865$ 0.35$ -$ -
Fall River Gas Co.$ 17,000,00041,675,985$ 0.41$ 13,000,000$ 0.31
Fitchburg Gas & Electric Co.$ 4,000,00015,860,488$ 0.25$ 1,300,000$ 0.08
North Attleboro Gas Co.$ 678,7983,960,682$ 0.17$ 202,100$ 0.05
Total$402,627,322

$ 31,492,405

  1. The GAF is stated in cents per therm or hundred cubic feet ("Ccf") of gas. A therm or Ccf is 100,000 Btu (about .71 gallons of heating oil). A typical residential customer (heat, cooking, hot water) would use 150 therms in a "normal" January or February.
  2. The Department docketed each LDC request as follows:
    Bay State Gas Company, D.T.E. 01-09; Berkshire Gas Company, D.T.E. 01-10; Blackstone Gas Company, D.T.E. 01-11; Boston Gas Company, D.T.E. 01-12; Colonial Gas Company, D.T.E. 01-13; Commonwealth Gas Company, D.T.E. 01-14; Essex Gas Company, D.T.E. 0-1-15; Fall River Gas Company, D.T.E. 01-16; North Attleboro Gas Company, D.T.E. 01-17; Fitchburg Gas and Electric Light Company, D.T.E. 01-18;
  3. National energy policy has oscillated widely on this use. In the 1970s, the federal Fuel Use Act forbade power plant use of natural gas. Today's energy and environmental regulatory policies promote its use, with the effects that we now see.
  4. The Department held hearings on January 16, 2001, in Blackstone and Haverhill; January 17, 2001, in Chelsea; January 18, 2001, in Pittsfield and Lowell; January 22, 2001, in New Bedford and Fall River; January 23, 2001, in Springfield and Hyannis; and on January 24, 2001, in Fitchburg, North Attleboro and Rockland.
  5. Although now quite outdated, but still on the statute books, G.L. c. 164, § 94F captures this notion.
  6. Continuity "means that rate structure changes should be made in a predictable and gradual manner which allows consumers reasonable time to adjust their consumption patterns in response to a change in structure." Cambridge Electric Light Company, D.P.U. 87-221-A, at 7-8 (1988).The CGAC operates outside the structure of base rates; but even so, its costs affect the total bill. After 15 years of CGAC stability, rate continuity has suddenly become a concern in managing that bill component.
  7. Some gas companies may be at or near their borrowing limits.
  8. If there is no adjustment to the GAFs currently in effect, the total deferred amount for all LDCs would be approximately $402 million by April 30, 2001. See Table 2, attached.
  9. For example, Boston Gas Company's projected under-recovery of $219 million is approximately one-third of the Company's annual revenues, or nine times its net income (Tr. Vol. A, January 24, 2001, at 37-38). Such a situation, left unaddressed, would threaten solvency. A threat to solvency is a threat to customer service, plain and simple.
  10. On November 30, 2000, the Department adopted an emergency regulation revising the definition of "financial hardship" contained in the Department's billing and termination procedures, 220 C.M.R. §§25.00 et seq., D.T.E. 00-89-A. The definition was expanded to include all persons eligible for state fuel-assistance funds from the Low-Income Home Energy Assistance Program.
  11. Companies should also notify their customers of the applicable deadlines to apply for transitional care and federal fuel assistance funds.
  12. See note 1, above for explanation of the GAF.
  13. Bay State, Essex, and Fitchburg are the only companies that differentiate their GAF by customer classes. Others have a flat rate per therm across classes.
  14. Blackstone is the smallest, by far, of the ten LDCs. There is far less latitude in dealing with its situation.
  15. Colonial's Lowell Division supplies are delivered on Tennessee Gas Pipeline, while its Cape Division's supplies are carried on the Algonquin Gas Transmission System. Gas costs differ accordingly. These Divisions are geographically and operationally separate, and Colonial does not average its GAF.

This information is provided by the Department of Public Utilities