News Digest
April 15, 2000
State PUCs
Natural Gas
Competition. After
reviewing a report prepared by its staff, the Iowa board rejected all
plans filed by Iowa natural gas utilities to open the natural gas market
to small-volume customers.
"[S]ome of the
utilities' plans do not proceed quickly enough and others proceed too
quickly by having the regulated utility exit the merchant function,"
the board said.
The board, while
recognizing that some issues might require legislation to resolve, attempted
to "move this process forward" by requiring each utility to propose
tariff changes that remove barriers to competition in the small-volume
sector. Comments addressing the procedural steps for designing the initial
tariffs were due April 3.
Board member
Susan J. Frye agreed with the rejection of the utilities' plans, but
dissented on the commission's attempt at moving forward on the issue
without the help of lawmakers. "[L]egislation is a better way to open
the small-volume gas market to customer choice than the interim tariff
modification approach adopted in this order," she said. Docket No.
NOI-98-3, March 3, 2000 (Iowa Ut.Bd.).
Demand-side
Management. The Kentucky PSC approved a three-year extension of
pilot programs for demand-side management administered by Kentucky Power
Co., but has encouraged the utility to seek ways to improve the cost-effectiveness
of weatherization programs designed to assist its low-income customers.
Case No. 95-427, Feb. 28, 2000 (Ky.P.S.C.).
Administrative
Rules. Interested parties must notify the Iowa board by May 1 if
they wish to participate in a comprehensive review of commission rules,
as ordered by Gov. Vilsack for all state agencies. However, the board
acknowledged that if an electric restructuring bill passes, the review
plan would have to be completely revised because restructuring rulemakings
may have to be combined with the review. A final report is to be submitted
to the governor's office on Dec. 31, 2002. Docket No. INU-00-1, Feb.
23, 2000 (IowaUtil.Bd.).
PG&E Rates.
In a highly contentious rate case, producing a decision longer than
500 pages, the California PUC on Feb.17 granted Pacific Gas & Electric
Co. a 13 percent increase ($91 million) in revenues for natural gas
distribution service (PG&E had asked for $377 million), plus an 18.9
percent increase ($361 million) in revenues for electric distribution
service (versus a $648 million request).
The net impact
on electric revenues will be smaller, however (up only $120 million
net) because the increase will be offset by the expiration of $241 million
in legislatively mandated electric revenues for reliability related
activities.
Furthermore,
consumer electric rates are not immediately affected by the authorized
increases because of the general rate freeze mandated by state law and
the 10 percent mandated rate cut for residential and small commercial
customers currently in effect under Assembly Bill 1890. On the gas side,
the PUC estimated that residential bills would rise $1.56 for a customer
using an average of 50 therms per month.
The ruling reflects
the authorized cost of capital for 1999 set in Decision 99-06-057, issued
last June. Decision 00-02-046, Feb. 17, 2000 (Cal.P.U.C.).
Rights-of-Way.
The Maine PUC OK'd a plan by Central Maine Power Co., an electric utility,
to transfer right-of-way easements to, and to share electric corridors
with, affiliated natural gas pipeline company, CMP Natural Gas LLC.
The arrangement will allow the gas company to construct a pipeline to
serve Calpine Corp.'s now-under construction, 540-MW gas-fired power
plant. Docket No. 99-739, Feb. 18, 2000 (Me.P.U.C.).
Fuel Procurement.
The Iowa board initiated a rulemaking to replace the board's annual
evaluation of electric utility contracting practices and fuel procurement.
Under the proposal, it would notify utilities each year by Jan. 31 on
whether they must file a fuel procurement plan, which would be due by
May 15. Comments were due March 28. Docket No. RMU-00-6, Feb. 17,
2000 (Iowa.U.B.).
Gas Retail
Choice. The Florida PSC adopted a rule allowing small businesses
to choose their natural gas supplier (an option previously available
only to large industrial consumers), and also allowing gas utilities
(at their discretion) to offer choice to residential customers.
The rule directs
all investor-owned gas utilities to offer transportation service to
all nonresidential customers and eliminates volume thresholds ranging
from 100,000 to 500,000 therms per year that had governed customer eligibility.
The PSC established
base line requirements for each utility's open access tariff, but imposed
minimal requirements so that each utility can tailor its tariff to its
individual needs. Each tariff must clearly specify that the utility
providing transportation service is not responsible for providing the
customers with natural gas if the customer's supplier fails to produce.
Docket No. 960725, Feb. 15, 2000 (Fl.P.S.C.).
Performance-Based
Rates. Kentucky Utilities and LG&E have agreed to implement an earnings
shared mechanism (ESM) suggested in January by the Kentucky PSC allowing
the utilities to keep 100 percent of their earnings up to 12.5 percent
return on equity, with any earnings above that ROE shared with shareholders
(60 percent) and ratepayers (40 percent). If company profits go below
a 10.5 percent ROE, customer rates would increase to account for 40
percent of the loss.
In response
to the orders, which impose a $63 million annual revenue reduction ($36.4
million for KU and $27.2 million for LG&E) representing more than 20
percent of the utilities' combined income, Duff & Phelps Credit Ratings
Co. has downgraded the credit ratings of both utilities and imposed
a negative rating outlook.
Stranded
Costs. The Texas PUC tentatively approved a settlement allowing
Central and South West Corp.'s subsidiary, Central Power & Light Co.,
to securitize about $764 million in stranded costs, short of the $1.27
billion CPL had requested in October 1999.
The settlement
calls for the securitized amount to be reduced to $764 million in regulatory
assets plus other qualified costs estimated at $28 million, and for
$290 million of the regulatory assets originally requested to be securitized
to be included in the calculation of stranded costs in CPL's April 2000
transmission and distribution cost filing. The PUC would issue a final
determination on stranded costs in 2004. Docket No. 21528, Feb. 10,
2000 (Tex.P.U.C.).
Utility Marketing
Affiliates. The Kentucky PSC adopted a code of conduct to govern
sharing of information and resources between investor-owned utilities
and their unregulated affiliates. Case No. 369, Feb. 18, 2000 (Ky.P.S.C.).
LDC-Marketer
Relationship. The Michigan PSC adopted a set of standards to regulate
dealings between Michigan Gas Utilities (a regulated gas utility) and
marketers, whether or not affiliated, but rejected a proposal to require
the utility to conduct all unregulated marketing activities through
a separate corporation. Case No. U-11648, Feb. 9, 2000 (Mich.P.S.C.).
QF Purchase
Obligation. Citing a new hydro project as too unreliable in its
energy output, the Alaska PSC said it would not require the local utility
to purchase project power at avoided cost rates, though the hydro project
qualified as a small power production facility (QF) under the Public
Utility Regulatory Policies Act of 1978.
The case involved
South Fork Hydro LLC (the QF) and Matanuska Electric Assoc. Inc.
U-96-93, Order No. 7, Jan. 26, 2000 (Alaska P.S.C.).
Gas Unbundling.
Massachusetts OK'd a model tariff for the state's unbundling program
for consumer choice in natural gas, which was to begin on April 1.
Nevertheless,
it warned that the new tariffs could lead to "unacceptable cost-shifting"
as the result of deaveraging of LDC-system capacity costs, and that
company-specific review of capacity allocators for each class of customers
will be reviewed as each utility completes its compliance filings in
the case. D.T.E. 98-32-D, Jan. 26, 2000 (Mass.D.T.E.).
Electric
Customer Choice. The Vermont board opened an initiative to consider
how to implement retail access policies for Central Vermont Public Service
Corp. (CVPS) and Green Mountain Power Corp. (GMP), slated for startup
in Sept. 2001 on a voluntary basis. Docket No. 6330, Jan. 14, 2000
(Vt.P.S.B.).
Mergers & Acquisitions
AEP + C&SW.
The FERC approved the merger of American Electric Power Co. and
Central & South West Corp., but only upon condition that the two halves
of the merged company (AEP East and AEP West) will transfer operational
control of their transmission facilities to a fully functioning, commission-approved
regional transmission organization (RTO) by Dec. 15, 2001, the date
specified in the final rule (FERC Order 2000) for RTO formation.
The FERC reversed
an initial decision issued last year by an administrative law judge
that had found few problems with the deal. Instead, the FERC said the
merger would enhance the potential for market power and thus impose
an adverse effect on competition absent the required condition for RTO
formation.
The commission
was satisfied by plans for the merger applicants to divest about 500
MW of generation in certain key markets, but saw competitive problems
even if the deal would not increase market share in generation. It rejected
arguments by the merger applicants that, in highlighting the mere enhancement
of market power as significant, it was improperly considering pre-merger
market power. Opinion No. 442, Docket No. EC98-40-000, March 15,
2000, 90 FERC ¶61,242.
Commissioner
Curt Hébert dissented, saying the majority's theory wrongly treated
the merger as a vertical combination. He noted that just two weeks prior
to the commission's order, the International Competition Advisory Committee
at the U.S. Dept. of Justice had recommended ending the FERC's role
in looking at antitrust issues in the merger context. (See News Digest,
April 1, 2000, p. 18.)
"Our claimed
expertise leads today's majority to invent market power out of thin
air," said Hébert."Congress should remove us from the merger business."
NEES + Eastern
Utilities. The U.S. Nuclear Regulatory Commission approved the merger
between New England Electric System and Eastern Utilities Associates,
according to NEES president and chief executive officer Rick Sergel.
The merger still requires approval by the federal Securities and Exchange
Commission, as well as Massachusetts and Rhode Island regulators. "We
continue our progress toward completing this merger early this year,"
Sergel said.
LG&E + PowerGen.
PowerGen plc would acquire LG&E Energy Corp. at $24.85 per share in
cash under a definitive agreement signed in February between the two
companies, marking the first entry by PowerGen into the U.S. market.
The deal was valued at $3.2 billion. The cash offer would represent
a 9.8 percent premium over LG&E's $22.63 closing share price on March
16, the same day the parties said they had filed a joint merger application
with the Kentucky Public Service Commission.
LG&E CEO Roger
W. Hale appeared confident of approval, noting that on March 15, the
U.S. Securities and Exchange Commission had OK'd the merger between
the UK's National Grid Group plc and New England Electric System.
"The SEC's approval
of foreign ownership of a U.S. utility company clearly helps," said
Hale. "Our transaction is very similar to [that] deal."
NiSource
+ Columbia Gas. NiSource said on Feb. 28 it had reached a definitive
agreement to acquire Columbia Energy Group in a stock deal valued at
approximately $6 billion. Columbia shareholders would receive $70 in
cash for each Columbia share, plus a $2.60 face value SAILS (a unit
consisting of a zero coupon debt security with a forward equity contract).
On completion of the deal, the two companies would become subsidiaries
of a new holding company.
State Legislatures
Hydro Divestiture.
California Assembly Speaker Fred Keeley introduced a bill on Feb. 22
that would allow the state temporarily to purchase the assets of Pacific
Gas and Electric Co. so as to remove them from FERC jurisdiction and
allow California to impose environmental and financial restrictions.
The measure (Assembly Bill 1956) would allow the state's Consumers Energy
& Environmental Security Authority to buy the assets, with the backing
of Gov. Gray Davis.
PG&E currently
has a proposal before the California PUC to divest its hydroelectric
generating plants in a competitive auction. In a Jan. 18 letter to Gordon
R. Smith, president and CEO of PG&E, Keeley argued that an immediate
sale by PG&E to the state would provide the "mandate, time, and money
to address the environmental, ratepayer/market power, and other important
issues of divestiture at no expense to the taxpayer, ratepayer, or shareholder."
Electric
Restructuring. The West Virginia House was considering HCR 27, which
would restructure the state's electric industry to allow choice of electric
supplier. The West Virginia PSC recently presented a restructuring plan
to the legislature, finding choice is needed to ensure West Virginia's
future economic viability.
Power Plants
Allocating
Sale Proceeds. The Washington commission ruled that ratepayers should
receive the excess in proceeds above net book value (up to original
cost) on the sale of utility-owned generating plants, and 50 percent
of any appreciation above original cost, in a decision that OK'd the
sale of interests held by the state's three private electric companies
(PacifiCorp, Avista Corp., and Puget Sound Energy) in the 1,340-megawatt
Centralia power plant to TransAlta Corp. of Calgary, Alberta.
It added that
it would factor in such payments in pending and future rate cases for
the three utilities.
Commissioner
Richard Hemstad dissented, saying that customers should receive any
and all appreciation in plant values "to compensate them for risks they
have borne while the facilities were in rate base." Docket No. UE991255,
March 6, 2000 (Wash.U.T.C.).
Auction Participants.
The New York PSC OK'd Central Hudson Gas & Electric Corp.'s auction
plan for the sale of its Danskammer fossil generation facility and its
35 percent interest in the Roseton fossil generation facilities, after
accepting the utility's offer to exclude its unregulated affiliate from
the auction.
The PSC directed
Central Hudson to use the Federal Energy Regulatory Commission's market
power guidelines "for selecting bidders that can survive market power
scrutiny," and required the company to be able to certify to the commission
that the winning bidder meets the horizontal market power guidelines
set out in previous auctions.
The PSC noted
that the auction plan largely resembles "the process that has been successfully
deployed in other auctions," citing the Niagara Mohawk auction order
Case 96-E-0-891, April 24, 1998 (N.Y.P.S.C.). Case 96-E-0909, Feb.
23, 2000 (N.Y.P.S.C.).
Hydro Relicensing.
Hydroelectric project sponsors won one and lost one in a pair of orders
issued by the FERC.
-
Collaborative
Process. The
FERC relicensed two hydroelectric projects owned by Avista Corp. on
the Clark Fork River, marking the first successful use of an alternative
licensing process that shaved two years off the normally three-year
process. Over 40 organizations agreed to the granting of the 45-year
licenses. Docket Nos. O-2058-014, P-2075-014, Feb. 23 (F.E.R.C.).
- Fish Ladders. On
the same day, the FERC rescinded a license granted to Public Utility
District No. 1 of Okanogan County, Wash. for the proposed 4.1-MW Enloe
Dam, saying that fish ladders required by the National Marine Fisheries
Service (NMFS) of the U.S. Department of Commerce would greatly increase
costs when the project already appeared to be uneconomical. The Canadian
government also opposed the fish ladder, saying it would introduce nonindigenous
fish, creating disease risk. Project No 10536- 005, Feb. 23, 2000
(F.E.R.C.).
Studies & Reports
Changes to billing
systems represent the largest back-office expense for utilities and
suppliers preparing for competitive energy markets, according to a study
from Xenergy Inc., which notes that billing problems in some cases have
led to lawsuits or bankruptcies.
The study says
utilities report spending anywhere from $1.22 to $22 per customer, with
one utility reportedly spending up to $82 million to make billing system
changes needed to accommodate retail access.
"Having the
right systems in place is critical to the success or failure of competition,"
said Jill Feblowitz, XENERGY senior consultant and project manager for
the study.
Transmission
& ISOs
RTO Workshops.
Philip J. Pellegrino, CEO of ISO New England, Inc., caused a stir on
the first day of the FERC's two-day workshop on regional transmission
organizations (RTOs) held March 15-16 in Philadelphia, when he acknowledged
that in the "mid-term," or between three and five years out, it was
likely that the independent system operators (ISOs) for New York, New
England, and PJM would combine to form a single RTO in the Northeastern
United States. Pellegrino's acknowledgment drew no protest from William
Museler (CEO of the New York ISO) or Richard Wodyka (COO for PJM) when
they took the podium later in the day.
Pellegrino added
that a binary form of RTO was the "ideal structure" for such a mega-RTO,
with an ISO serving as a standard-setting group, and a single for-profit
company owning all the transmission assets now owned by individual investor-owned
utilities.
"So far it hasn't
been fun to be in the transmission business," said Pellegrino. "We need
a profit motive. The rat has to smell the cheese."
New England
ISO. Reviewing market flaws affecting ISO New England and the New
England Power Pool, the FERC granted an extension through June 30 for
the temporary price cap for the operating reserve market that had been
set to expire on Dec. 31, 1999. Commissioner Curt Hébert dissented.
Docket Nos. ER00-984-000, ER00-971-000, Feb. 23 (F.E.R.C.).
Transco Formation.
The Ohio PUC issued conditional approval of a proposal by FirstEnergy
Corp. to transfer transmission assets to a wholly owned subsidiary,
American Transmission Services Inc., in what it described as an "intermediate
and facilitating" step in the formation of a regional transmission organization,
despite objections that formation of a private for-profit transmission
company might lead to pancaking of transmission rates and deprive consumers
of the benefits of electric competition.
The PUC conditioned
approval on its later determination that the assets to be transferred
will qualify as "transmission" under the FERC's seven-factor test for
distinguishing transmission from distribution assets.
A second condition
would require ATS to "fully succeed" to FirstEnergy's native load obligations.
Case No. 98-1633-EL-UNC, Feb. 17, 2000 (Ohio P.U.C.).
Native Load
Reservations. In granting a complaint by Aquila Power Corp., the
FERC ruled that Entergy violated the commission's pro forma transmission
tariff and the comparability requirements of Order 888 by failing to
designate the network resources (generation) associated with its reservations
for firm transmission import capacity.
Entergy had
said it wanted only to serve native load reliably, but the FERC observed
that Entergy had reserved virtually all of the firm capacity on four
key interfaces, and was essentially using its reservations to keep capacity
open to buy off-system power whenever it might prove economical to do
so. Aquila Power Corp. v. Entergy Services, Inc., Docket No. ER91-569-009,
March 16, 2000, 90 FERC ¶61,260.
Mountain
West ISA. The Nevada PUC has refused to issue a guarantee to Nevada
Power Co. and Sierra Pacific Power that they can recover losses from
ratepayers if the Mountain
West Independent System Administrator should default on funding loans
from the utilities, but at the same time the PUC ruled that the parties
had complied with all requirements for ISA formation that the PUC set
earlier as a condition for their proposed merger, so that from a legal
standpoint, the PUC had nothing left to do.
The PUC acknowledged
the paradox: "The MWISA cannot function without startup funds. However,
the funding proposal ... requires a guarantee [that] would constitute
an irresponsible risk of consumer funds."
The PUC added
that when it required ISA formation earlier as a condition for the merger,
it had set no test or conditions for funding. Thus, the PUC ruled it
had "no basis for review" of any proposed funding mechanism, and thus
no grounds to act further. To move the process forward, the PUC said
it would first have to rule that a specific funding mechanism for the
ISA was required for the economic and reliable operation of transmission
facilities.
Meanwhile, the
PUC noted that the MWISA so far had been conducting management activities
through an interim stakeholder board and needed to hurry up and form
an independent board to legitimize the governing process. Earlier, the
MWISA's stakeholder board had selected Automated Power Exchange to provide
software support, but the PUC questioned that move when it declared:
"The decision as to the selection of a vendor should be left until the
independent board is in place." Docket No. 98-7023, Feb. 16, 2000
(Nev.P.U.C.).
The Fortnightly
questioned Rosalie Day, chairman of the current interim stakeholder
board, on how the ISA could form a new board, satisfy tests of independent
governance, and conduct another solicitation for a software vendor and
operator - all without funding.
She answered,
"Has the train left the station without an engineer? Heck, it doesn't
even have tracks."
Courts
APX Oversight.
Noting the "broad language," Congress used in the Federal Power Act,
a federal appeals court upheld a ruling by the Federal Energy Regulatory
Commission that had claimed jurisdiction to regulate the Automated Power
Exchange as a public utility under the Federal Power Act. APX, which
had argued that it wasn't a public utility because it will not transmit
or take title to power, instead called itself an "information management
agent."
The court agreed
with the FERC that the software used by APX played a role in markets
by assigning a price to bilateral transactions where a gap might still
exist between the bid and offer prices submitted by transacting parties.
Automated Power Exchange, Inc. v. FERC, No. 98-1415, March 7, 2000
(D.C.Cir.).
After the ruling
was issued, APX announced that its latest software and product design
would not incorporate this feature of automatically setting a price
(where a buyer and seller had not yet agreed) for private power exchanges
planned in Illinois (working with Commonwealth Edison) and Ohio (working
with FirstEnergy).
NOx Emissions.
A federal appeals court rejected a claim that the Environmental Protection
Agency has not explained adequately what volume of nitrogen oxide emissions
flowing from one state to another contributes "significantly" to NOx
nonattainment under Section 110 of the Clean Air Act.
The appeal was
based on last May's decision in American Trucking Assoc. v. EPA,
which ruled that the EPA had interpreted the Clean Air Act so loosely
that the power delegated to it by Congress was unconstitutional. Yet
the court sought to limit the consequences of that ruling.
The court noted
that "a mass of cases" had upheld delegations of "effectively standardless
discretion," even where the scope of agency power was narrow.
It said the
EPA need only do three things to show a significant contribution to
nonattainment: (1) identify emissions activity within a state, (2) show
evidence that emissions migrate to another state, and (3) show that
the emissions contribute to nonattainment. Michigan v. EPA, No. 98-1497,
March 3, 2000 (D.C.Cir.).
QF Certification.
A federal appeals court affirmed a ruling by the Federal Energy Regulatory
Commission that had upheld certification for a qualifying cogeneration
facility (QF) even though the QF's corporate voting rules allowed electric
utility affiliates (controlling a 45 percent ownership interest) to
block significant corporate action, a feature that had led to complaints
alleging a violation of QF rules regarding utility ownership. Brazos
Elec. Pwr. Co-op., Inc. v. FERC, No. 98-60568, 2000 WL 228302, Feb.
29, 2000 (5th Cir.).
Business Wire
DTE Energy
Technologies, an unregulated subsidiary of DTE Energy Co.,
has reached a distribution agreement with GENERAC Power Systems,
a manufacturer of prepackaged standby power systems for homes and small
businesses, for DTE to market the Generac GUARDIAN product, which provides
fully automated standby power systems for homes and small businesses
in Southeastern Michigan. DTE also will market custom-designed engineered
systems for larger commercial and industrial customers. "The addition
of the Generac product line to our portfolio represents a key step toward
attaining our vision of DTE Energy Technologies as a preeminent supplier
of distributed generation products and services," said Paul Horst, president
of DTE Energy Technologies.
Consumers
Energy and Chubu Electric Power Co. of Nagoya, Japan have signed
what is believed to be the first-ever agreement to form a purchasing
alliance between an American and Japanese utility company. The agreement
supports an objective of the Japanese and U.S. governments to promote
increased exports of U.S.-made utility equipment to Japan. The goals
of the agreement are to examine product cost, productivity standardization,
new product development, electronic technology, resource and knowledge
sharing, and procurement process improvement and streamlining.
United Energy
of Australia has signed a multi-year, multi-million dollar contract
with CES International, a provider of real-time infrastructure
reliability solutions, for the deployment of its Centricity operations
resource management suite of solutions. With the agreement, CES becomes
United Energy Distribution's prime contractor, systems integrator, and
project management services provider for its electric and gas distribution
management systems project.
Public Power
Las Cruces-El
Paso Elec. Dispute. A settlement that would end the long-running
dispute between the City of Las Cruces and El Paso Electric Co. over
municipalization of EPE's electric distribution system in the city would
give EPE a seven-year franchise to serve the city.
EPE would pay
the city an annual 2 percent franchise fee (about $800,000/ year) and
a lump sum of $21 million, and after seven years, Las Cruces would be
able to buy EPE's distribution system for book value plus 30 percent.
Congress
Reliability
& Restructuring. Without calling it an electric restructuring bill,
Senate Energy and Natural Resources Committee Chairman Frank Murkowski
(R-Alaska) on Feb. 24 introduced legislation that would repeal the Public
Utility Holding Company Act of 1935 and the mandatory purchase requirement
in Public Utility Regulatory Policies Act of 1978, in addition to allowing
for stranded cost recovery.
The measure,
Senate Bill 2098, addresses reliability by calling for eminent domain
to construct new interstate transmission lines, and for the North American
Electric Reliability Council to file with the Federal Energy Regulatory
Commission proposed reliability standards, over which the commission
would have approval authority. Cosponsored by Sen. Mary Landrieu (D-La.),
the bill also allows for FERC oversight of regional transmission organizations.
See http://thomas.loc.gov/cgi-bin/query/z?c106:S.2098:.
Electric Rates
Oregon Electric
Rates. Finding the request inconsistent with a previous rate-setting
agreement, the Oregon PUC rejected a request by PacifiCorp for a 12.6
percent residential rate hike, and told the company it must correct
the deficiencies and extend the period of investigation of its filing
by two months or the request would be dismissed.
PacifiCorp had
argued that the filing was sufficient because it assigned the same 30
percent to distribution and 70 percent to generation and transmission
as was used in the previous agreement. But PUC Chairman Ron Eachus pointed
out, "Our previous agreement applied to the distribution function, not
to a specified percentage of revenues. If the company wants an increase
for generation and transmission, it has to break those costs and revenues
out separately." Docket No. UE111, Feb. 17, 2000 (Ore.P.U.C.).
News Digest
was compiled by Carl J. Levesque, associate editor, Lori Burkhart and
Phillip Cross, contributing legal editors, and Bruce W. Radford, editor-in-chief.
For more frequent updates, see www.pur.com.
Articles found on this page are available to Internet subscribers only. For more information about obtaining a username and password, please call our Customer Service Department at 1-800-368-5001.
Public
Utilities Fortnightly & Spark
