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FILE NO. 70-09613
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
AMENDMENT NO. 3
TO
APPLICATION/DECLARATION
ON
FORM U-1
UNDER THE
PUBLIC UTILITY HOLDING COMPANY ACT OF 1935
CONSOLIDATED EDISON, INC. NORTHEAST UTILITIES
4 Irving Place 174 Brush Hill Ave
New York, New York 10003 West Springfield, MA 01090-0010
(Names of companies filing this statement and addresses of principal
executive offices.)
CONSOLIDATED EDISON INC.
(Name of top registered holding company)
Peter A. Irwin Cheryl W. Grise
Consolidated Edison, Inc. General Counsel
4 Irving Place Northeast Utilities Service Company
New York, New York 10003 107 Selden Street
Berlin, CT 06037
(Name and address of agents for service)
The Commission is requested to mail signed copies of all orders, notices and
communications to:
J.A. Bouknight, Jr. Jeffrey C. Miller, Esq.
Douglas G. Green Assistant General Counsel
James B. Vasile Northeast Utilities
Steptoe & Johnson LLP Service Company
1330 Connecticut Ave, NW 107 Selden Street
Washington, D.C. 20036-1795 Berlin, CT 06037
Item 6. Exhibits and Financial Statements
(a) Exhibits
a.1 Certificate of Incorporation of New CEI (Incorporated by
reference to Exhibit A to the Merger Agreement of Consolidated
Edison and Northeast Utilities' Joint Proxy and Registration
Statement on Form S-4 filed on March 1, 2000, Registration
No. 333-31390).*
b.1 Amended and Restated Agreement and Plan of Merger
(Incorporated by reference to Annex A of Consolidated Edison
and Northeast Utilities' Joint Proxy and Registration
Statement on Form S-4 filed on March 1, 2000, Registration
No. 333-31390).*
c.1 Joint Proxy and Registration Statement on Form S-4
(Incorporated by reference to Consolidated Edison and
Northeast Utilities' Joint Proxy and Registration Statement on
Form S-4 filed on March 1, 2000, Registration No. 333-
31390).*
d.1 Application to FERC*
d.1.1 Prepared Direct Testimony and Exhibits of
William H. Hieronymus
d.2 Filing made with the DPUC
d.3-1 Filing made with the MPUC*
d.3-2 Order of the MPUC*
d.4 Filing made with the DTE
d.5 Filing made with the DOR***
d.6 Filing made with the NHPUC*
d.7 Filing made with the NJBPU*
d.8 Filing made with the NYPSC*
d.9 Filing made with the PAPUC*
d.10-1 Filing made with the VPSB*
d.10-2 Order of the VPSB*
d.11 Filing made with the NRC
f.1 Legal Opinions**
g.1 Financial Data Schedules**
h.1 Form of Notice
i.1 Gas retention analysis for the CEI Gas Properties**
i.2 Gas Retention analysis for the NU Gas Properties**
(b) Financial Statements*
* Previously filed
** To be filed by amendment
***No filing required or made
SIGNATURES
Pursuant to the requirement of the Public Utility Holding Company Act of
1935, as amended, the undersigned companies have duly caused this statement
to be signed on their behalf by the undersigned thereunto duly authorized.
Date: June 21, 2000
Consolidated Edison, Inc.
(a New York Corporation)
By /s/ John D. McMahon
Name: John D.McHahon
Title: Senior Vice President &
General Counsel
Northeast Utilities
By /s/ Cheryl W. Grise
Name: Cheryl W. Grise
Title: Senior Vice President, Secretary
and General Counsel
Consolidated Edison, Inc.
(a Delaware Corporation)
By /s/ John D. McMahon
Name: John D. McMahon
Title: Vice President
Exhibit D.1.1
United States of America
Before the
Federal Energy Regulatory Commission
Consolidated Edison, Inc. ) Docket No. EC00- -000
Northeast Utilities )
Prepared Direct Testimony and Exhibits of
William H. Hieronymus
Table of Contents
I. Qualification
II. Introduction and Summary of Testimony
III. Description of the Parties
IV. Framework of the Analysis
V. Data Sources and Methodology for the Competitive Analysis Screen
A. Modeling Methodology and Generation Data
B. Relevant Geographic Markets
C. Transmission Charges and Transmission Congestion Contracts
D. Other Relevant Data
VI. Impact of the Merger on Competition in Electricity Markets
A. Analysis of Total Capacity
B. Analysis of Uncommitted Capacity
C. Analysis of Economic Capacity
VII. Vertical Issues
A. Sites
B. Transmission Facilities
C. Delivery of Fuels
D. Conclusion: Vertical Issues
VIII. Conclusion
1. Qualifications
Q. Please state your name and business address.
A. My name is William H. Hieronymus. I am a Senior Vice President of PHB
Hagler Bailly, Inc. in its offices at One Memorial Drive, Cambridge, MA
02142.
Q. What is your educational and professional background?
A. I received a bachelor's degree from the University of Iowa in 1965, and
a master's degree in economics in 1967 and a doctoral degree in economics in
1969 from the University of Michigan, where I was a Woodrow Wilson Fellow and
National Science Foundation Fellow. After serving in the US Army, I began my
consulting career.
In 1973, I joined Charles River Associates, Inc. and specialized in antitrust
economics. By the mid-1970s, my focus was principally on the economics of
energy and network industries. In 1978, I joined PHB where my consulting
practice has continued to focus on network industries, particularly, electric
utilities.
During the past twenty-six years, I have completed numerous assignments for
electric utilities, state and federal government agencies and regulatory
bodies; energy and equipment companies; research organizations and trade
associations; independent power producers and investors; international aid
and lending agencies; and foreign governments. While I have worked on most
economic-related aspects of the electric utility sector, a major focus has
been on public policies and their relation to the operation of utility
companies.
Since 1988, I have focused on electric industry restructuring, regulatory
innovation and privatization. In that year, I began consulting on the
restructuring and privatization of the electric utility industry of the
United Kingdom, an assignment on which I worked nearly full-time through the
completion of privatization. I also performed numerous assignments concerning
restructuring in other western European countries, eastern and central
Europe, the former Soviet Union and New Zealand.
Upon my return to the United States in 1993, I began work on the
restructuring and regulatory reform of the US electric industry. Much of this
work has focused on market power. I have testified before the Commission and
state commissions on market power issues concerning a substantial number of
utility mergers, power pool and ISO market power issues and mitigation, and
in connection with regulatory filings for asset sales and purchases and
market rate applications. More generally, I have testified before state and
federal regulatory commissions, federal and state courts, and legislatures on
numerous matters concerning electric power and other network industries. My
resume is attached as Exhibit APP-2.
II. INTRODUCTION AND SUMMARY OF TESTIMONY
Q. What is the purpose of your testimony?
A. I have been asked by Consolidated Edison, Inc. ("Con Edison") and
Northeast Utilities ("NU") (collectively, "the Applicants") to determine the
potential competitive impact of their proposed merger on electricity markets.
My analysis of horizontal market power is conducted to be consistent with the
Competitive Analysis Screen described in Appendix A to the Commission's
Merger Policy Statement ("Order No. 592"), (FN 1) which in turn is intended to
comport with the Department of Justice and Federal Trade Commission
("DOJ/FTC") Merger Guidelines ("Guidelines"). I have also analyzed potential
vertical market power, particularly as it might arise from Applicants' status
as combined utilities owning local gas distribution companies, within the
framework established by recent Commission guidance. (FN 2)
Q. What are your principal conclusions with respect to horizontal market
power?
A. The markets in which Applicants operate are, in nearly all instances,
unconcentrated. This lack of concentration has resulted from industry
restructuring and related asset divestitures in New England, New York and
Pennsylvania. Moreover, these markets are becoming still more deconcentrated
as new merchant capacity comes on-line. Applicants already have divested the
majority of their generating capacity. Con Edison will divest further
capacity in 2001 and NU has committed to auction substantially all of its
remaining regulated generating capacity, with these auctions also due to be
completed by sometime in 2001.(FN 3) Since most markets are unconcentrated
both before and after the merger, and because Applicants' small shares of
generation in any destination market mean that the effect of the merger is
small even in those markets that are not unconcentrated, the merger readily
passes the Appendix A screen. The minor effect of the merger also reflects
the fact that all of NU's capacity is in NEPOOL and nearly all of Con
Edison's capacity is in NYPP. Since the transmission limit between the two
regions is only about 1,600 MW, and Applicants' capacity must compete with
owners of large amounts of generating capacity for use of this interface,
their potential competition with each other in these, and other, markets is
quite limited.
Consistent with the requirements of Appendix A of Order No. 592, I examined
the market structure for energy as measured by HHIs for Economic Capacity and
Available Economic Capacity. My analysis covered the year 2000, during which
the Applicants expect to consummate the merger, and 2001, the first full year
after projected merger completion. In each year I examined market structure
for multiple time periods and market price levels. My analysis reflects the
fact that the northeast is comprised of three ISOs based on tight power
pools, but also reflects the major transmission constraints within these
ISOs' control areas that are relevant to the analysis. The geographic areas
used as destination markets were:
(1) the City of New York ("NYC"),
(2) that portion of New York State that is East of the Total-East
transmission constraint, excluding Long Island ("NY-ETE"),
(3) that portion of Long Island served by the Long Island Power Authority
("LIPA"),
(4) the control area of the New York Independent System Operator ("NYISO"),
formerly (and herein) referred to as the New York Power Pool ("NYPP"),
(5) the New England ISO/Power Pool ("NEPOOL" or "ISO-NE"), and
(6) the Pennsylvania-New Jersey-Maryland Interconnection ("PJM").
NYPP and NEPOOL are the primary control areas in which Applicants operate and
are, therefore, relevant geographic markets. There are no frequently binding
transmission constraints within NEPOOL; moreover, power pricing in NEPOOL is
based on a single, system-wide price. My analysis of the NYC, NY-ETE and LIPA
submarkets follows from the fact that the operation of transmission
constraints could cause Applicants' share of these markets to be higher than
in the larger NYPP market in which these submarkets are imbedded. This
approach is consistent with recent Commission precedent and with my analyses
in other proceedings concerning the New York market before the Commission.
(FN 4) I also include an analysis of the PJM Interconnection, as is required
by Order No. 592 since it is directly interconnected to Con Edison. While
there are known constraints within PJM, Applicants' shares of PJM markets
and hence the change in HHIs within PJM, necessarily are lower than their
shares in NYPP.(FN 5) I have not analyzed any destination markets in Canada.
I have examined the historic trading patterns of Applicants, summarized in
Exhibit APP-3. All meaningful trading partners are included in one of these
six destination markets.
I have not, for reasons discussed in the body of this testimony, formally
examined the effect of the merger on the Commission's traditional Total
Capacity and Uncommitted Capacity measures for NYPP and NEPOOL. Nonetheless,
it is clear that neither Applicant possesses generation dominance as measured
by the "hub and spoke" tests using these measures. The NYPP market would
include all of PJM, NYPP, NEPOOL, Hydro Quebec and Ontario Hydro. The NEPOOL
market would include NYPP and Hydro Quebec in addition to NEPOOL generation.
Applicants share of each market is far below the thresholds permitted by the
Commission under this test. Moreover, as I discuss in detail later, the
retained capacities of both Applicants are close to or below their ongoing
native load responsibilities, indicating that they have little to no
Uncommitted Capacity.
Q. What are your principal conclusions with respect to potential vertical
market power?
A. I conclude that the merger does not create any vertical market power
issues arising from control over transmission, potential sites for new
generation, or fuels supplies and delivery systems. First, Applicants already
have turned over control of their bulk transmission systems to Commission-
approved ISO's. Moreover, regarding the issue of entry specifically,
transmission access for new generators is assured both by the Commission's
open access policies and by the independent control, either by the NYISO or
ISO-NE, of Applicants' transmission systems.
Second, Applicants will not possess dominant control over potential
generating sites.
Third, Applicants have no market power in the supply of fuel that they could
use to frustrate entry or to increase rivals' costs. Neither Applicant
controls a gas transmission pipeline. While NU does own a non-controlling 5
percent share of a pipeline, used to serve one of its generating units in New
Hampshire, this share represents less than 1 percent of New England pipeline
capacity. For reasons described infra Applicants' non-dominant shares of firm
transportation rights on pipelines serving the northeast cannot give rise to
the types of vertical market concerns that the Commission has expressed in
recent orders. Moreover, the structure of control of such upstream
transportation rights is not highly concentrated.
Con Edison operates a gas local distribution company, and NU is in the
process of acquiring one. Con Edison's LDC provides transportation service to
a number of generating stations, primarily in the City of New York. This
service is limited to short-haul transportation, which is already discounted
due to favorable bypass economics. Service to new generators would be under
generic tariffs based on marginal costs and regulated by the NYPSC, and
distributors have the option to negotiate even lower rates to avoid bypass by
particular electric generators. NU's future affiliate, Yankee Energy, serves
only one small gas generating station of 81 MW; this too is served under a
bypass-avoidance discounted rate. Hence, the merger cannot result in a
significant increase in concentration of electricity market control, even if
the limited distribution service provided by Applicants was deemed to give
them "control" over this generation. Moreover, neither could favor the
generation that becomes affiliated due to the merger since neither transports
gas to the others' electricity generating facilities. Nor could the merger
create a significant ability to raise rivals' costs or convey competitively
sensitive information. Yankee Energy serves too little generation to be a
factor. Con Edison's theoretical control over, or knowledge concerning
operations of, its served generation cannot be competitively significant in
New England where NU's generation is located due to the limited interface
between the markets. Moreover, NU will soon divest virtually all of its New
England generation. More generally (i.e., irrespective of whether there is a
nexus to the merger) there is no basis for concern that Applicants will use
the ownership of gas LDCs to favor affiliated activities. Applicants have
divested virtually all of the gas-fired electric generating facilities that
had previously owned. Moreover, gas distribution tariffs are regulated by the
New York Public Service Commission ("NYPSC") and the Connecticut Department
of Public Utility Control ("CT-DPUC"), and both New York and Connecticut
statues forbid discriminatory pricing of distribution. Price transparency
required by NYPSC and CT-DPUC policies would make any discrimination easy to
detect by both the regulator and affected generators. Nor could Applicants'
LDCs raise rivals' costs, even assuming that regulated gas distribution
functions have a theoretical opportunity to do so. There are low cost bypass
alternatives that constrain distribution tariffs for all major gas-fired
generation facilities served by Applicants to below cost-of-service rates.
Since both New York and Connecticut (as to Connecticut non-residential
customers) are gas open-access states, no LDC has market power with regard to
commodity gas; purchasers may contract with any source.(FN 6) In short, none
of the vertical concerns upon which the Commission focused in the Enova-Pacific
Enterprise and Dominion-CNG mergers exist in this merger, and the transaction
does not create or enhance vertical market power.
Q. What do you conclude about the effect on competition of the proposed
merger?
A. Based on the results of the analyses I have conducted, I conclude that
the proposed merger will not adversely impact competition in any relevant
product and geographic markets.
III. DESCRIPTION OF THE PARTIES
Q. Please describe Con Edison.
A. Consolidated Edison, Inc. ("Con Edison") is an energy company whose
utility subsidiaries, Consolidated Edison Company of New York, Inc
("CECONY"). and Orange and Rockland Utilities ("O&R"),(FN 7) provide regulated
electric service to customers in New York City (with the exception of parts
of Queens) and Westchester, Orange, Rockland and Sullivan Counties, New York;
Bergen, Passaic and Sussex Counties, New Jersey; and Pike County,
Pennsylvania. These utilities also provide steam service in parts of
Manhattan and gas service in Manhattan, the Bronx and parts of Queens;
Westchester, Rockland and Orange Counties, New York; and Pike County,
Pennsylvania. At the beginning of 2000, Con Edison will have approximately
1,485 MW of capacity that it owns and operates, 462 MW of entitlements to
jointly owned units, 2,090 MW of non-utility generation ("NUG") contracts and
550 MW of other contracts. Con Edison's capacity is detailed in Exhibit APP-
4. This total of 4,587 MW is the only capacity that Con Edison controls to
provide service to an expected 2000 peak load of 11,145 MW.
CECONY will sell its share of the Roseton Generating Station, which it owns
jointly with Niagara Mohawk Power Company ("NiMo") and Central Hudson Gas and
Electric Corporation ("CHG&E"), as part of CHG&E's divestiture, which is
required by its restructuring order in New York to be completed by June 2001.
This sale will reduce Con Edison's controlled capacity by 462 MW, to 4,125
MW. Moreover, Con Edison has announced its intention to explore alternatives
to the continued ownership and operation of its Indian Point 2 Nuclear Power
Plant and associated gas turbines, which, if sold, would further reduce Con
Edison's capacity by 978 MW.
Non-utility affiliate companies of Con Edison own or have contracts for
approximately 378 MW of generation, all of it in New England. Consolidated
Edison Energy of Massachusetts, Inc. ("CEEMI") recently acquired
approximately 290 MW of capacity in western Massachusetts from Western
Massachusetts Electric Co. ("WMECO"), one of the regulated subsidiaries of
NU.(FN 8) In addition to its subsidiary's purchases of oil-fired and
hydroelectric capacity from WMECO, CEEI directly contracted for a ten percent
share of NU's Millstone 2 nuclear generating station, about 88 MW of capacity,
from January 1, 2000 through December 31, 2001.
Con Edison offers competitive retail service for electricity and gas in
New York and Pennsylvania through its Con Edison Solutions affiliate.(FN 9)
Con Edison has no traditionally defined transmission-dependent utilities
("TDUs"). Some New York Power Authority ("NYPA") wholesale customers are
located within Con Edison's service area. NYPA has its own generating
facilities and transmission rights that permit it to serve its customers
directly.
Con Edison has direct connections within the NYISO control area to NYPA,
CHG&E, NiMo, New York State Electricity and Gas Corporation ("NYSEG"), and
LIPA. It also has direct connections to Connecticut Light and Power Company
(Northeast Utilities) in NEPOOL and to PSE&G in PJM.
Q. Does Con Edison have any natural gas operations?
A. Yes. CECONY provides regulated natural gas delivery service to
approximately one million customers in the Boroughs of New York, the Bronx
and parts of the Borough of Queens and Westchester County, New York. It own
and operates approximately 4,200 miles of mains and 362,400 service lines.
O&R and its utility subsidiaries serve about 117,000 gas customers in
Rockland County, most of Orange County and part of Sullivan County, New York.
Its consolidated gas operations include three propane air gas plants, which
together have a capacity of 30,600 Mcf/d of natural gas equivalent. O&R's gas
distribution system include 1,758 miles of mains. All of Con Edison's gas
customers have retail choice.
Q. Please describe NU.
A. NU is a registered public utility holding company, with operating
utility subsidiaries in Connecticut (The Connecticut Light & Power Company
["CL&P"]), Massachusetts (WMECO and Holyoke Water Power Company ["HWP"]) and
New Hampshire (Public Service Company of New Hampshire ["PSNH"]). As of the
end of 1999, NU and its subsidiaries (including non-utility subsidiaries) own
3,893 MW of generating capacity and have total capacity, including net
contract purchases, of 4,530 MW. NU's capacity holdings are detailed in
Exhibit APP-5.
CL&P is the operating utility subsidiary of NU in Connecticut. In order to
receive stranded cost recovery, CL&P must divest all of its owned generation
and buy-out, auction or buy-down all of its NUG contracts. CL&P has divested,
or will soon close divestiture of, all of its 3,900 MW of fossil-fired and
hydroelectric generating capacity. It also sold, through competitive tender,
contracts for the output from its nuclear assets through 2001.(FN 10) CL&P
has submitted to the CT-DPUC buy-outs or auctions of substantially all of its
436 MW of NUG contracts. CL&P, in conjunction with WMECO, is selling its
ownership share of Millstone, with a contract anticipated in 2000 and closure
of the transaction in 2001.
CL&P, in accordance with Connecticut Public Act 98-28, An Act Concerning
Electric Restructuring ("PA 98-28"), has competitively procured 50 percent of
its four-year Standard Offer Service requirements from non-affiliated
suppliers. These are requirements contracts that can be used only to provide
standard offer service; CL&P cannot resell energy from these contracts or
otherwise profit from them. Also in accordance with PA 98-28, CL&P will
procure the other 50 percent from Select Energy, a wholly-owned subsidiary of
NU. Select will serve this load under the same terms and conditions as the
successful bidders for the other 50 percent. In order partially to serve its
roughly 2,400 MW standard offer responsibility, Select Energy acquired 797 MW
of the Millstone and Seabrook contracts let by CL&P for 2000 and 2001.(FN 11)
WMECO owns and operates transmission and distribution facilities and provides
transmission, distribution and Standard Offer Service to electric customers
in portions of western Massachusetts. Like CL&P, WMECO will have divested
substantially all of its generating capacity as part of state-mandated
restructuring. As noted above, WMECO sold to CEEMI all 290 MW of its wholly-
owned generating capacity. WMECO's 306 MW entitlements of Millstone 2 and 3
were contracted out along with CL&P's entitlements. WMECO sold through
competitive bids its share of the Northfield Pumping Station , a facility it
jointly owned with CL&P, and the Cabot and Turners Falls Hydro stations .
WMECO is in the process of buying out the larger of its two NUG contracts,
about 88 percent of its total of 62 MW of contracts. WMECO has conducted an
auction for supply of all its Standard Offer and Default Service requirements
and is currently reviewing bids received. I am informed by NU that Select
Energy will not be a winning bidder to provide standard offer service to
WMECO customers in the this auction.
NU also provides regulated electric service in Massachusetts through HWP. HWP
is a small utility, serving only 24 MW of peak load from its 190 MW of
capacity. This capacity and load will stay with NU through the relevant
analysis period.
In New Hampshire, PSNH owns and operates generation, transmission and
distribution facilities and provides regulated transmission, distribution and
retail service to electric customers. PSNH owns and operates approximately
1,134 MW of fossil-fired and hydro electric generating capacity. It also has
NUG contracts for about 160 MW of capacity and a power purchase agreements
for about 451 MW of the Seabrook and Millstone nuclear facilities.(FN 12)
This 1,739 MW of capacity serves a peak load of about 1,400 MW. As I discuss
later, PSNH has agreed to a restructuring settlement that awaits final state
approvals. Under the terms of this settlement agreement, PSNH will divest all
of its owned generation and its share of Seabrook. PSNH will also likely
auction its supplier of last resort supply requirements. While the timing of
these actions is dependent on legislative and regulatory actions in New
Hampshire, NU anticipates completing its divestiture of PSNH generation by
sometime in 2001.
NU has within its service territory six traditionally defined TDUs: City of
Chicopee, Connecticut Municipal Gas Cooperative, Holyoke Gas and Electric,
New Hampshire Co-op, City of South Hadley, and City of Westfield. NU is
interconnected to most other utilities in NEPOOL. It also has
interconnections with Con Edison, LIPA, CHG&E and NiMo.
Q. Does NU control any generation through non-utility subsidiaries?
A. Yes. Northeast Generating Company (NGC) will soon own approximately
1,321 MW of generation, all of which was purchased at competitive auction
from NU operating companies. By far the largest amount of its capacity, 1,120
MW, is NU's Northfield pumped storage station. All of NGC's capacity is under
long term contract to Select Energy.
Q. Does NU have any natural gas operations?
A. Yes. Select Energy Portland Pipeline, Inc. ("SEPPI"), a wholly-owned
subsidiary of NU, owns a non-controlling 5 percent equity interest in the
Portland Natural Gas Transmission System ("PNGTS"). The remaining 95 percent
is split among six other entities, none of whom are involved in electricity
generation in the Northeast. PNGTS runs from the Canadian border at
Pittsburgh, New Hampshire, where it interconnects with TQM/TransCanada, to
Dracut, Massachusetts, where it interconnects with the Tennessee Gas
transmission system. PNGTS has a target maximum capacity without compression
of 350 to 365 mmcf per day.
NU's Newington generating station is directly interconnected to PNGTS,
allowing NU to bypass the gas LDC that had served it prior to pipeline
construction. NU has a minimum daily capacity requirement of 30 mmcf per diem
for the seven months of the year beginning April 1 for 1999 through 2018. I
am informed by NU that this firm capacity requirement exists to provide
Newington's fuel requirements.
NU has reached a definitive agreement to purchase Yankee Energy System, Inc.
("YES") and is in the final stages of obtaining regulatory approvals for
that purchase. YES, is a public utility holding company incorporated in
Connecticut in 1988. The Company is primarily engaged in the retail
distribution of natural gas through its wholly-owned subsidiary, Yankee Gas
Services Company ("Yankee Gas"), a Connecticut public utility service
company. Yankee Gas serves approximately 185,000 residential, commercial and
industrial customers in 69 cities and towns and covers approximately 1,995
square miles. Until YES was formed in 1988, Yankee Gas' gas business was part
of the NU system and was operated by CL&P as a fully integrated and
coordinated part of the NU system companies. NU divested Yankee Gas in 1989
via spin-off of the stock of YES to its shareholders. YES is the holding
company for Yankee Gas and four active non-utility subsidiaries, NorConn
Properties, Inc. ("NorConn"), Yankee Energy Financial Services Company
("Yankee Financial"), Yankee Energy Services Company ("YESCo") and R.M.
Services, Inc. ("RMS"). YES's business essentially is confined to the
ownership of its subsidiaries.
Yankee Gas owns approximately 2,820 miles of distribution mains, 133,033
service lines, and 185,000 active meters for customer use, all located in
Connecticut. Yankee Gas also owns and operates five propane facilities and
six gas storage holders, also in Connecticut. Yankee Gas also contracts for
storage capacity with other energy and pipeline companies. Total throughput
(sales and transportation) for fiscal 1998 was 47.1 billion cubic feet.
Yankee Gas serves only one electric utility generator, the 81 MW oil/gas
Montville 5 unit.
Since 1996, Yankee Gas has faced retail supply competition from other gas
suppliers in the commercial and industrial market. Federal regulation also
permits customers within Yankee Gas' franchise to connect directly with
transmission pipelines and bypass Yankee Gas' distribution system. Within
Yankee Gas' service territory, Yankee makes available its transportation
services to move other parties' gas through its distribution system.
Connecticut General Statute Section statute 16-269 requires that an
interstate pipeline transmitting or selling gas within a Connecticut LDC's
franchise territory must have prior approval from the DPUC.
IV. FRAMEWORK OF THE ANALYSIS
Q. What are the general market power issues raised by merger proposals?
A. Market power analysis of a merger proposal examines whether the merger
would cause a material increase in the merging firms' market power or a
significant reduction in the competitiveness of relevant markets. Market
power is defined as the ability of a firm or group of firms to profitably
sustain a small but significant increase in the price of their products above
a competitive level.
In assessing mergers, the critical issue is the change in market
competitiveness due to the merger. While the pre-merger competitiveness of
markets may, as under the DOJ/FTC Guidelines, affect the amount of such
change that is acceptable, the focus remains on the change in market
competitiveness caused by the merger.
This focus on the effects of the merger means that the merger analysis
examines those business areas where the merging firms are competitors. In
most instances, the merger will not affect competition in markets in which
the merging firms do not compete. This is recognized in Commission procedures
which exempt mergers between firms that do not compete in relevant geographic
and product areas from the need to submit a screening analysis. Analysis of
the effects of a merger on market power in markets in which the merging firms
both participate is sometimes referred to as horizontal market power
assessment. In FERC merger analyses, the primary horizontal focus is on
competition in wholesale markets for electricity.
It is also necessary to consider the possibility of vertical market power.
Vertical market power relates to the effect of the merger on the merging
firms' ability and incentives to use their market position in a related
business to affect competition adversely. For example, vertical market power
could result if the merger of two electric utilities creates an opportunity
and incentive to operate transmission in a manner that creates or enhances
market power for the generation activity of the merged company that did not
exist previously. More generally, mergers with suppliers of inputs to
generation, particularly gas transmission providers, have been identified as
requiring an analysis of potential vertical market power. The Commission also
has identified dominant control over potential generation sites or over fuels
supplies and delivery systems that allows the merged firm to frustrate entry
as a potential vertical issue that could undercut the presumption that long-
run generation markets are competitive.
Q. What are the main elements in developing an analysis of market power?
A. Understanding the competitive impact of a merger first requires defining
the relevant market (or markets) in which the merging firms participate.
Participants in a relevant market include all suppliers and, in some
instances potential suppliers, who can compete to supply the products
produced by the merging parties and thereby diminish the ability of the
merging parties to increase prices. Hence, determining the scope of a market
is fundamentally an analysis of the potential for competitors to respond to
an attempted price increase. Typically, markets are defined in two
dimensions: geographic and product. Thus, the relevant market is composed of
companies that can supply a given product (or its close substitute) to
customers in a given geographic area. Once markets are defined, the analysis
proceeds to examine the structure of sellers to determine if a merger might
significantly increase market power.
Q. How has the Commission typically examined proposed mergers involving
electric utilities?
A. Historically, under its Commonwealth standards, the Commission examined
mergers by focusing on specific product markets and by using a "hub-and-
spoke" screening test to evaluate whether a further examination of potential
market power was warranted. With the issuance of Order No. 592 in December
1996, the Commission changed its analytic approach and adopted a "delivered
price test." Appendix A (the "Competitive Analysis Screen") of Order No. 592
outlines in detail the analytic method that applicants are required to follow
in their applications and that the Commission will use in screening the
competitive impact of mergers. If a proposed merger raises no market power
concerns (i.e., passes the Appendix A screen), the inquiry generally is
complete.
Q. What products has the Commission generally considered?
A. With electric markets, the Commission generally has defined the relevant
product markets to be long-term capacity, short-term capacity ("Uncommitted
Capacity"), and non-firm energy ("Available Economic Capacity" and "Economic
Capacity"). The Commission has determined that long-term capacity markets are
presumed to be competitive, unless special factors exist that limit the
ability of new generation to be sited or receive fuel.
In its Part 33 NOPR and in Dominion, the Commission has set out several
vertical issues potentially arising from mergers with input suppliers. The
principal issue that it has identified is whether the merger may create or
enhance the ability of the merged firm to exercise market power in downstream
electricity markets by control over the supply of inputs to rival producers
of electricity. Three potential abuses have been identified: the upstream
firm acts to raise rivals costs or foreclose them from the market in order to
increase prices received by the downstream affiliate; the upstream firm acts
to facilitate collusion among downstream firms; or transactions between
vertical affiliates are used to frustrate regulatory oversight of the
cost/price relationship of prices charged by the downstream electricity
supplier. The downstream products to be analyzed in a vertical analysis are
the same as in the horizontal analysis.
Q. How has the Commission analyzed geographic markets?
A. To examine geographic markets, the Commission traditionally has focused
on the utilities that are directly interconnected to the applicant companies,
treating each of the directly interconnected control areas as a separate
market. This "destination market" approach was continued in Order No. 592.
Each utility that is directly interconnected to the Applicants is considered
a separate "destination market." Additionally, the Commission has suggested
that utilities who historically have been customers of Applicants are also
potential "destination markets." In some recent cases, the Commission has
found that analyses based on geographic markets larger than a single
destination market are appropriate. Pennsylvania-New Jersey-Maryland
Interconnection, 81 FERC Paragraph 61,257 (1997); PJM Interconnection, 86 FERC
Paragraph 61,247 (1999); New England Power Pool, 83 FERC 61,045 (1998); New
England Power Pool, 85 FERC Paragraph 61,379 (1998); Consolidated Edison Co.
of New York, Inc. and Orange and Rockland Utils. Inc., 86 FERC Paragraph 61,064
(1999); EME Homer City Generation, 86 FERC Paragraph 61,016 (1999).
The supply alternatives to each destination market are defined using the
"delivered price test," which identifies suppliers that can reach a
destination market at a cost no more than 5 percent over the pre-merger
market price. More precisely, the supply is considered economic if a
supplier's generation can be delivered to a destination market, including
delivery costs (which include transmission rates, transmission losses and
ancillary services), at a cost that is within 105 percent of the destination
market price. Physical transmission constraints also are taken into
consideration in determining the potential supply to the destination market.
Competing suppliers are defined as those who have capacity (energy) that is
physically and economically deliverable to the destination market. Their
importance in the market (i.e., their market share) is determined by the
amount of such capacity. Applicants must allocate available transmission
capability among potential suppliers and justify the methodology used.
This test is intended to be a conservative screen to determine whether
further analysis of market power is necessary. If the Appendix A analysis
shows that a merger does not create market power in Applicants' first-tier
generation markets, it generally follows that it will not create market power
in more broadly defined and more geographically remote markets. If the screen
is passed, this generally ends the inquiry into horizontal market power. If
the screening test is not passed, leaving open the issue of whether the
merger will create market power, the Commission invites applicants to propose
mitigation remedies targeted to reduce potential anti-competitive effects to
safe harbor levels. In the alternative, the Commission will initiate a
proceeding to determine whether unmitigated market power concerns indeed
signal that the merger is contrary to the public interest.
Q. What framework does the Commission use to determine whether a merger
poses potential market power concerns?
A. In Order No. 592, the Commission adopted the DOJ/FTC Guidelines for
measuring market concentration levels by the Herfindahl-Hirschman Index.(FN 13)
To determine whether a proposed merger will have a significant anti-competitive
impact, the DOJ and FTC consider the level of the HHI after the merger
(the post-merger HHI) and the change in the HHI that results from the merger.
Markets with a post-merger HHI of less than 1000 are considered
"unconcentrated." The DOJ and FTC generally consider mergers in such markets
to have no anti-competitive impact. Markets with post-merger HHIs of 1000 to
1800 are considered "moderately concentrated." In those markets, mergers that
result in an HHI change of 100 points or fewer are considered unlikely to
have anti-competitive effects. Finally, post-merger HHIs of more than 1800
are considered to indicate "highly concentrated" markets. The Guidelines
suggest that in these markets, mergers that increase the HHI by 50 points or
fewer are unlikely to have a significant anti-competitive impact, while
mergers that increase the HHI by more than 100 points are considered likely
to reduce market competitiveness.
Q. Does your analysis of horizontal market power in this case follow the
guidelines set down in Order No. 592?
A. Yes. I have analyzed the two product measures defined in the Order,
using the methodology that it describes. I have included as destination
markets the control areas in which Applicants' generation is located as well
as all domestic control areas that are first tier to them or with which
Applicants have transacted in significant amounts. In addition, I have
included constrainable regions within these control areas as potentially
relevant markets. The control areas in which the merger is taking place are
the ISO-New England and the New York ISO. I analyze each of these as a
relevant market. In addition, I analyze sub-markets within the NYISO that are
defined by constrainable transmission interfaces that potentially could
result in a greater impact of the merger than is shown by an analysis of the
NYISO control area as a whole. These constraints define three such sub-
markets: New York City, the portion of Long Island outside of the city (LIPA)
and the downstate region of New York (NY-ETE). The In-City market is a sub-
area within Con Edison's historic control area. The NY-ETE market contains
all of Con Edison's New York generation and is defined by constraints
limiting imports from upstate New York during high load periods. I analyze
the Long Island market due to its interconnection to Applicants, despite that
the generation of Applicants is outside the interfaces defining this market
and, hence, their shares necessarily will be less than their shares in NY-
ETE. The factual bases for selecting these destination markets are familiar
to the Commission (FN 14) and are discussed more fully later in my testimony.
I also have analyzed PJM (and, in workpapers, subregions within PJM) since PJM
is first tier to NYPP. Neither Applicant has significant historical
transactions with generators or utilities located outside these geographic
areas.
V. DATA SOURCES AND METHODOLOGY FOR THE COMPETITIVE ANALYSIS SCREEN
A. MODELING METHODOLOGY AND GENERATION DATA
Q. Please describe the nature of the analysis undertaken to complete the
Appendix A competitive analysis screen.
A. PHB developed the Competitive Analysis Screening model ("CASm") to
facilitate Appendix A analyses. From time to time, I have directed that the
model be changed and updated to reflect experience with its use and evolution
in the electricity industry and the Commission's preferences for how analyses
should be conducted. This model implements the delivered price test and other
calculations required in Appendix A by determining potential supply both pre-
and post-merger for each (i) destination market, (ii) relevant time period
and (iii) relevant supply measure. From these results, the model also
calculates pre- and post-merger HHIs. The relevant geographic market is
determined based on the economics of supply (including generation costs,
transmission rates, losses and ancillary services) and the physical
transmission capacity available to the competing suppliers on an open access
basis. In CASm, each transmission path has a fixed maximum capacity; CASm
also incorporates simultaneous transmission constraints. To determine the
potential supply to a destination market, the model determines an economic
delivery route for supply that meets the delivered price test via existing
transmission paths, each of which has a capability, transmission rate and
transmission losses associated with it. It then allocates the transmission
capacity among the various suppliers in a manner consistent with the
Commission's instructions in it decisions. The model is described more fully
in Exhibit APP-6.
Q. What data are required to conduct a competitive analysis screen?
A. The key data requirements for implementing the screening analysis
include:
Generating capability owned by each supplier
Long term capacity purchases and sales by each supplier
Variable costs of generation
Transmission capability
Transmission wheeling rates
Transmission line losses
Native loads (for Available Economic Capacity analyses)
Representative market prices to use in determining whether market
structure differs at varying load and seasonal conditions
To the maximum practical extent, I have used publicly available data,
consistent with those detailed in Appendix B of Order No. 592. My study
generally makes use of historic data (e.g., loads and fuel costs) as a
starting point, but my modeling assumptions are intended to approximate the
market structure in 2000 and 2001.
Q. Why did you choose to model the market structure of 2000 and 2001?
A. According to the public statements of Applicants, the merger is unlikely
to be completed much before 2001; consequently, late 2000 or early 2001 is
the earliest plausible starting date for my analysis.
The relevant geographic markets are becoming more deconcentrated over time,
and Applicants' market shares are also declining. O&R has a 400 MW capacity
contract with PSE&G that expires in October 2000,(FN 15) and Select Energy's
share of Millstone 2 will decline by 10 percentage points. Applicants will
have no additions to their capacity in 2001, so year 2000 is the most
conservative case.
I have modeled year 2001 as my "base case," however, since that will be the
first full year of operation as a merged entity.(FN 16) These analyses also
demonstrate how these markets, and Applicants' roles therein, are evolving.
By the end of 2001 NU is scheduled to have completed its divestiture of the
Millstone generating station, bought out its Massachusetts and Connecticut
NUG contracts and divested its PSNH assets, as directed by the pending
Settlement Agreement between PSNH and the New Hampshire Public Utilities
Commission ("NHPUC"). Con Edison will have divested its share of the Roseton
station and may have divested other capacity as well (e.g., Indian Point 2).
My analysis of 2001 (and 2000) conservatively assumes that these divestitures
have not occurred. Moreover, substantial new merchant capacity is scheduled
to come on-line after 2001. For these reasons, market shares of Applicants
should decline after 2001. Hence, if no market power problems are found for
2001, the merger is still less likely to create problems further in the
future.
Q. What utilities did you use in your data set?
A. I included utilities in the NYPP, PJM, NEPOOL, SERC and ECAR, as well as
Hydro Quebec ("HQ") and Ontario Hydro ("OH") (see Exhibit APP-7) as possible
competitors. Notably, this list of candidate suppliers does not pre-judge the
question of the geographic scope of the market. CASm determines (based on
economics of supply, transportation and deliverability) which of these
candidate suppliers, and to what degree, are competitors to serve a
particular destination customer.
For ease of modeling, I did not include in my data set generation owned by
small municipalities or cooperatives located within the regions. This
exclusion tends to increase Applicants' market shares and is, therefore,
conservative.
Q. What assumptions have you made regarding the entry of new generating
capacity?
A. In NYPP, PJM and NEPOOL, very large amounts of new generating capacity
are in various stages of construction or planning. In NEPOOL, over 20,000 MW
of capacity expansion has been announced; about 11,000 MW in NYPP; and about
9,000 MW in PJM. Rather than include all announced capacity in my analysis, I
conservatively have included only those projects that meet the following two
criteria: First, the capacity must be scheduled to come on-line by mid-2001.
Second, the capacity must be under construction or have secured financing and
the necessary permits to begin construction. These criteria reduce the new
capacity that I include to those projects that Exhibit APP-8 indicates are
modeled, which includes 5,369 MW in NEPOOL, 1,528 MW in PJM and no new
capacity in NYPP.
Some of this new capacity will not be available in 2000, and so I have not
included it in my analysis of that year. As indicated in Exhibit APP-8, 1,390
MW of new NEPOOL capacity is modeled only in 2001.
Con Edison informs me that it is considering three new generation projects.
One would close the Waterside steam-electric cogeneration plant and replace
that capacity with expanded generating capability at its East River site.
This expansion would add no more than 300 MW to the New York City market. The
second project under consideration would be to redevelop the West Springfield
facility that CEEMI purchased from WMECO, adding a net 170 MW to that unit.
A third project would construct a 525 MW gas-fired combined-cycle plant
adjacent to NU's Newington facility.
Since these facilities are not planned to be on-line in 2001, and none have
received final financing and permitting or have begun construction, I have
not included them in my analyses. An analysis that includes them would have
to be based on 2002; a year 2002 analysis also would take Applicants' by-
then-completed divestitures into account as well as further entry by third
parties. Since Applicants are divesting far more than they are planning to
build, it is clear that a year 2002 analysis would show smaller shares and a
lower HHI delta than my 2001 analysis.
Q. Does your year 2001 analysis take any of Applicants pending divestitures
into account?
A. No, I did not include in my analysis any divestitures that are not
complete. Thus, I have modeled Con Edison as continuing to own its share of
the Roseton station. I credit NU only with those divestitures that have
already been completed. In particular, CL&P has divested 2,235 MW of fossil
generating capacity to NRG Energy and WMECO has divested 290 MW of fossil and
hydroelectric generating capacity to Con Edison. I do not take into account
CL&P's and WMECO's buy out of their NUG contracts, totaling approximately 500
MW, despite that the terms of the buy outs have been agreed between parties
and are before the state commissions for approval. Nor do I take into account
the sale of the Millstone units despite that it likely will be completed by
approximately the time frame of my analysis. To receive recovery of stranded
costs, NU is obligated to sell these units, and NU has informed me that the
auction should occur in mid-2000, with closing in mid-2001. NU will not be
participating as a potential purchaser in this auction. Therefore, the 839 MW
of Millstone contracts in 2000 (752 MW in 2001) purchased by NU's Select
Energy unit represent the largest share of Millstone that NU could reasonably
be expected to control in the future. I also do not assume any divestiture of
PSNH capacity, even though Applicants advise me that 1,117 MW of fossil
capacity and 68 MW of hydroelectric capacity are expected to be auctioned by
the second quarter of 2001. NU also will divest its ownership of Seabrook,
which will further reduce NU's economic capacity by about 418 MW. NU informs
me that it plans to complete this sale by late 2001.
I have taken into account the long-term sales contracts for NU's share of the
Millstone station and CL&P's 4.06 percent share in Seabrook (47 MW). Since
these contracts have durations greater than one year and span the relevant
time period, the capacity is properly attributed to the purchaser of the
contracts. As discussed previously, Con Edison and a NU affiliate are buyers
of part of this capacity and are treated as controlling their purchases. As
for other utilities, I did not assume any divestitures not already
substantially complete. At this time, most of the large utilities in New York
and New England have already divested most or all of their generating
capability.
Q. What sources did you use for generating capability data?
A. Data on NYPP generating plant capability (winter and summer capacity),
including NUGs, were obtained from NYPP's 1999 report Load & Capacity Data. I
took into account planned retirements and capacity additions through 2001.
Data on generation in regions other than NYPP was taken from EIA-411 reports.
Q. How did you rate the production capacity of generators?
A. I assumed that generation capacity would be unavailable during some
hours of the year for either (planned) maintenance or forced (unplanned)
outages. I assumed that maintenance would be scheduled during the non-peak
seasons and forced outages would occur uniformly throughout the year. For
this purpose, I used data reported in the NERC Generating Availability Data
System ("GADS") for the average equivalent availability factor to estimate
total outages, and the average equivalent forced outage rate to estimate
forced outages for fossil and nuclear plants. GADS reports five-year average
availability and outages based on unit type and size. These data were
supplemented, for new technology combined cycle units, by data in the
Electric Power Research Institute Technical Assessment Guide.
Q. How did you treat the Northfield pumped storage station, which is owned
by an NU affiliate?
A. I reviewed data on the historic operation of the unit. Based on the
seasonal capacity factor of it, I determined the number of MWh that it
typically produces. I assumed that the unit operates at 100 percent capacity
factor during super-peak hours; the remainder of output is spread over peak
hours, resulting in a derated capacity during non-superpeak, peak hours. The
unit experiences a pumping efficiency loss of approximately 35 percent.
Therefore 135 percent of the output must be replaced during non-peak hours. I
treated this as the equivalent of load for NU. Thus, my Available Economic
Capacity analysis takes into account pumping load, but my Economic Capacity
analysis ignores the fact that in order to produce energy during the day, NU
must purchase energy at night.
Since I did not have access to the same detailed operations data for
other pumped storage units as I did for Northfield, I treated the other two
large pumped storage stations in NEPOOL and NYPP, viz. Bear Swamp and
Blenheim-Gilboa, as I did Northfield.
Q. How did you treat purchases and sales?
A. Data on long-term capacity purchase and sales were obtained primarily
from Load & Capacity Data for NYPP and from FERC Form 1 filings for other
utilities. The transactions taken into account in my analysis are long-term
(one year or more) firm transactions.
To the extent a utility has sold capacity under a long-term agreement, it is
assumed that control over that resource passes to the buyer. Generation
ownership is adjusted to reflect the transfer of control by decreasing the
capacity controlled by the seller and correspondingly increasing the capacity
for the buyer. System sales are assumed to be from the lowest-cost supply for
the seller.(FN 17) Therefore, the seller's lowest-cost supply was reduced by
the amount of the sale and the buyer's supply was increased by the amount of
the purchase. Dispatch prices for firm, dispatchable purchase contracts were
based on published data (from FERC Forms 1) where available, or an estimate
(generally $15 per MWh) if not available. To the extent that long-term sales
could be identified specifically as unit sales, I have tied the sale to the
capacity of a specific generating unit and transferred the relevant amount of
the unit from the seller to the buyer.
As noted earlier, Applicants have several long-term contracts. Con Edison
purchases power under contracts with NYPA (Gilboa), HQ and seven NUGs
(Lederle, Indeck, Selkirk, Sithe and, within New York City, Cogen
Technologies, Brooklyn Navy Yard Cogeneration and York Warbasse.)
NU's utility subsidiaries have a large number of NUG contracts, as shown in
Exhibit APP-9. As this exhibit indicates, most of these contracts with CL&P
and WMECO are in the process of being bought-out or auctioned. NU has
informed me that PSNH also has five small sales contracts, which together
reduce PSNH's installed capacity by 18 MW.
Applicants have at most limited dispatch rights concerning their NUG
contracts. These are primarily "must take;" the Power Purchase Agreements
specify the level of output and Applicants must schedule it or bid it into
the pool in a way that assures that they run when power is produced.
Q. What sources did you use for the cost of generation?
A. I used data from several sources to estimate the incremental cost of
generation.
Heat rates from EIA Form 860.
Fuel costs from Form 423 (1999, through September data) ,
supplemented by data from other sources, mainly RDI's COALDATr. I based the
estimated dispatch cost on spot or interruptible fuel prices. To the extent
all fuel purchases in 1999 had been made under contract rather than at spot
prices, I estimated an incremental price based on reported spot or
interruptible prices in the relevant region.
An estimate of variable O&M (by type of unit) and an SO2 adder.
For NUGs, I set the variable costs at zero, in effect assuming NUGs
were must-run. I could not identify any NUGs as dispatchable.
B. RELEVANT GEOGRAPHIC MARKETS
Q. Please describe the relevant geographic markets.
A. I examined six geographic markets for the analysis of Economic Capacity
and Available Economic Capacity: (1) the NEPOOL market, defined as the
control area of the New England Independent System Operator; (2) the NYPP
market, defined as the control area of the NYISO; (3) the "East of Total
East" ("NY-ETE") market, defined as that portion of NYPP on the eastern side
of the Total East transmission interface and related transmission
limitations;(FN 18) (4) an "In-City" (that is, New York City) market; (5) the
LIPA (or Long Island) market, defined as the control area of LIPA, and (6)
the PJM market.
Q. Why is the NEPOOL market a relevant geographic market?
A. NEPOOL is a relevant market because all of NU's generation, transmission
and distribution facilities are located within NEPOOL. NEPOOL is a single
control area and a "tight" power pool, with central economic dispatch of all
generation and transmission facilities by ISO-New England, and transmission
within NEPOOL faces a unified, non-pancaked tariff. Moreover, there are no
systematic transmission constraints within NEPOOL.(FN 19) Consequently, and
consistent with this Commission precedent, I consider NEPOOL to be a
geographic economic market for the purposes of Order No. 592 analysis.
Q. Why is the NYPP market a relevant geographic market?
A. NYPP is a relevant market because all of Con Edison's generation,
transmission and distribution facilities are located within NYPP. Like
NEPOOL, NYPP is a single control area and a "tight" power pool, with central
economic dispatch of all generation and regional transmission facilities by
ISO-New York , and transmission within NYPP faces a unified, non-pancaked
tariff. Consequently, and consistent with Commission precedent,(FN 20) I
consider NYPP to be a relevant geographic market for the purposes of Order
No. 592 analysis.
Q. Why is the East of Total-East market a relevant geographic market?
A. The "Total-East" interface within NYPP is the primary interface through
which power moves into the eastern half of New York State. This interface
constitutes a transmission constraint that can cause marginal production
costs to differ, sometimes substantially, between the downstate and upstate
portions of the state, thus creating a separate market. The current Total-
East transfer limit is 5300 MW. The other corridor through which power moves
into eastern New York is through the interface between NYPP and NEPOOL, which
has a transfer limit of 1,575 MW.
Q. Why is the In-City market a relevant geographic market?
A. In some hours, there also are constraints within Con Edison's territory.
According to Con Edison's "load pocket" study, there are six load pockets in
Con Edison's service territory, including the city as a whole (area J) and
sub-areas within the City.(FN 21) I have examined the In-City market as a
separate relevant market for purposes of my study. I did not find it
necessary to consider the individual load pockets within the city as individual
destination markets. Since NU owns no generation inside the City, its ability
to affect prices within sub-areas of the City is restricted by the City import
limit, and it will have a correspondingly and commonly restricted share of
sub-markets within the City.
Q. Why is LIPA a relevant geographic market?
A. LIPA, which serves those portions of Long Island not within New York
City, as well as Far Rockaway, a section of Queens, is a relevant geographic
market because it is directly interconnected with Con Edison and to NEPOOL.
Moreover, capacity ownership serving LIPA is highly concentrated, reflecting
in part the fact that LIPA is relatively weakly interconnected with the rest
of NYPP and with NEPOOL. Moreover, Con Edison engages in wholesale
transactions with KeySpan, the principal generation owner in LIPA.
Consequently, Order No. 592 requires that LIPA be included as a destination
market.
Since neither Con Edison nor NU own generation in the LIPA market, it is
quite unlikely that there is a merger-related market power problem within it.
It nonetheless is potentially important to reflect transmission limitations
between LIPA's service area and the rest of the region in the analysis. These
can limit the amount of generation within this sub-area that can compete with
Con Edison's generation inside the rest of East of Total-East. Accordingly,
in my analysis, I have explicitly modeled the transmission interfaces between
LIPA and the rest of East of Total-East, effectively limiting the ability of
Long Island units to compete with Con Edison and NU.
Q. Why is PJM a relevant geographic market?
A. Since Con Edison is directly interconnected to PSEG, a member of the PJM
Interconnection, PJM is first-tier to Con Edison and is therefore a relevant
market under Order No. 592. Since neither Applicant has any generating
facilities within PJM, and since there is relatively small transmission
capability between NYPP and PJM, Applicants' market shares there will
necessarily be more dilute than in the East of Total-East market and their
potential market power correspondingly lower. (FN 22) I have not, therefore,
provided as detailed an analysis of the PJM geographic market as I have
before the Commission on matters centered on PJM.(FN 23)
Q. Did you consider using the historic service areas of utilities in
NEPOOL, NYPP and PJM as a alternative to the regions that you have defined as
geographic markets?
A. Yes, but I concluded that the taxonomy of geographic markets I have
discussed is more appropriate. As discussed in the Part 33 NOPR, it is
appropriate to define markets where customers face the same supply
alternatives. Each of the markets I examined lacks relevant internal
constraints or, when such constraints exist, I also examine the constrainable
areas separately. There is no pancaking of transmission rates within them.
Hence, aggregation across historic service areas, or parts of service areas,
within these regions is warranted. Indeed, the regions I have defined
properly disaggregate the historic service areas. Key transmission
constraints, such as Total-East, cut through historic service areas; parts of
several utilities are west and parts east of it. I note also that inter-
service area transmission data are not even posted prospectively by the ISOs
for NYPP, NEPOOL and PJM.
Q. In choosing the destination markets to evaluate, did you include
Applicants' historical trading partners?
A. Yes, although this did not alter my conclusion as to the appropriate
destination markets to consider. Exhibit APP-3 shows the Applicants' recent
(l997 and 1998) purchases and sales. Notably, both Applicants were net
purchasers even before divestitures that they have now completed. The
Applicants have historically made very few energy sales into markets outside
of NYPP, NEPOOL or PJM.
Q. What sources did you use to determine transmission capability?
A. For transmission capability within NYPP and into NYPP from Canada, I
relied primarily on transfer capability data published by the NYPP in Load &
Capacity Data. These data reflect transfer capabilities between market areas
within New York (under normal conditions) as well as import capability into
New York. The inter-area NYPP data already take into account loop flow
effects that limit the interface to below the thermal limit of individual
lines.
For transfers between control areas within the United States, I relied on
OASIS postings of non-firm available transmission capability ("ATC"). To
capture potential seasonal variation in ATC, I examined postings for twelve
months forward. Where there are multiple paths between control areas with
separate postings, such as between NYPP and NEPOOL, I assumed that the posted
ATCs were not subject to a simultaneous interface limit.(FN 24) While I
believe that this assumption is correct, I note that any reduction in
transmission capability between these regions as a result of simultaneous
interactions would reduce the effects of the merger.
Q. How did you model transmission within NYPP?
A. As noted above, the Total-East interface limit is 5,300 MW. I used this
total transfer capability, adjusted for firm commitments as described below,
as the transfer capability from New York West into the NY-ETE market.
The import limit from PJM to NYPP overall is 2,000 MW, about half of which
flows directly into the East of Total-East market via the Branchburg-Ramapo
interconnection. In my analysis, I use the posted ATC, which is somewhat
below these figures and varies seasonally. The import limit from NEPOOL is
1,575 MW into NYPP overall,(FN 25) and I used the posted ATC between these
pools.(FN 26) Finally, the import limit from LILCO into NY-ETE is 1,050 MW.
Thus, the overall import capability I assumed into the East of Total-East
market is not more than 8,925 MW.
Q. How did you take account firm commitments on these transmission
interfaces within NYPP?
A. I reduced these import limits by the amount of the firm sales to
utilities in the downstate region from power sources outside of that region
for which they have firm long-term contracts or participation shares. In my
analysis, as described below, I explicitly made this adjustment for Con
Edison's purchase from Sithe, located west of Total-East. Con Edison's
purchase from HQ, however, is treated as a resource outside of Total-East
that must compete for transmission into the East of Total-East market because
Con Edison must compete to schedule energy over that interface. I also
explicitly adjusted for NYPA's rights to move power from its upstate
generating facilities to its downstate load. This is consistent with the
grandfathering policies of the NYISO.
The difference between total transfer capability into southeastern New York
and any relevant reservations is available transfer capacity ("ATC") and is
available for prorating the economic energy from all outside sources.(FN 27)
Q. How did you model transmission within NEPOOL?
A. Since transmission within NEPOOL is reasonably free of congestion, I
treated it as internally unconstrained. I note that there are no clear cases
where potential episodic constraints would show a greater effect from the
merger. Greater Boston is one potentially constrainable area, but neither
Applicant owns facilities within it. More generally, NU has resources in both
northern and southern New England and NYPP is interconnected in both the
north and the south, so any south-to-north or north-to-south constraint would
be unlikely to have a significant impact on the analysis or its conclusions.
Q. How did you model transmission within PJM?
A. PJM can be broadly divided into four zones, defined by three
transmission interfaces: West, Central and East. See Pennsylvania-New
Jersey-Maryland Interconnection, 81 FERC 61,257 (1997); PJM
Interconnection, 86 FERC Paragraph 61,247 (1999); Jersey Central Power & Light
Co., 88 FERC Paragraph 62,223 (1999). I include the transfer limits across
these interfaces in my analysis. Thus, for example, units in the far west of
Pennsylvania must compete for capacity across both the PJM-West and PJM-Central
interfaces to reach the interface between PJM-East and NY-ETE. As a practical
matter, this modeling of constraints within PJM has only a minor effect on my
analysis, since Applicants own no capacity in PJM and since PJM
capacity is of minor significance in the New York and New England markets.
Q. Please explain how you allocate transmission across constrained
interfaces.
A. Shares are allocated at each interface, with the result that the
importance of a potential supply is diluted progressively as it passes
through interfaces on the way to a destination market. Limited interfaces are
allocated proportionately to economic capacity on the outward side of the
interface. In other words, when there is economic supply competing to get
through a constrained transmission interface into market area, the
transmission capability is allocated to the suppliers in proportion to the
amount of economic supply each supplier has immediately outside the
interface, taking into account any reductions resulting from interface limits
further away from the destination market. (FN 28)
Specifically, CASm uses the amount of Economic Capacity that each supplier
could deliver to the edge of the constrained interface as the basis for
assigning shares on the transmission path in question. The algorithm does
this for each constrained path on the system, thereby "squeezing down" the
amount of power supplied by more distant utilities. Thus, for example, power
located in PJM that is potentially economic in New England is first squeezed
by allocating only a pro rata share of capacity between NYPP and PJM. This
reduced capacity then is pooled with economic capacity in upstate New York
(if traversing that part of the NYPP-PJM interface outside of the total-east
constraint) and given a pro-rata share of that interface; that which can get
into NY-ETE is pooled with the economic capacity located in NY-ETE and
allocated a share of the NYPP interface with NEPOOL.
This successive "squeezing" has the intended effect of giving higher shares
of the ultimate interface into the destination market to suppliers who are
closer to the destination market since their supply will pass through, and
hence be "squeezed" down by, fewer interface limits. Another method of
allocation that commonly is suggested is allocating transmission capacity to
the lowest cost resources. However, particularly in view of the small inter-
area transmission capability in this region, such a scheme of allocation
would give highly misleading results. For example, all of the transmission
from NYPP to ISO-New England most likely would be used up by Canadian and
upstate-New York hydro power, constraining Con Edison's New York capacity out
of a potential competitive role in the New England market.
C. TRANSMISSION CHARGES AND TRANSMISSION CONGESTION CONTRACTS
Q. How Did you model transmission charges and losses within NYPP?
A. As stated in the NYISO Tariff, transmission charges in the restructured
New York Power Pool have three components - a congestion charge, a charge for
losses and a Transmission Service Charge ("TSC").
The congestion and losses charges of the NYISO Tariff are designed to ensure
economically efficient pricing of transmission at the short-run marginal cost
of service. (FN 29) My analysis presented herein implicitly accounts for
congestion by modeling sub-regions of New York - the East of Total-East market
and New York City - as separate destination markets. Losses are modeled with a
simplifying assumption; imports into the East of Total-East market from other
New York regions incur 2.5 percent losses (an approximation of one wheel).
(FN 30) These approximations may result in minor distortions in the market
shares for the relative shares of utilities in the exporting areas in New York.
However, they are unlikely to affect Con Edison's share or materially affect
the HHI in the smaller NY-ETE region in which its share is the largest. (FN 31)
The TSC recovers the fixed cost of the transmission system and is a "license
plate" charge based on the customer's location. There is no pancaking of
charges for transmission across New York State. Rather, each LSE pays the TSC
of the service provider where its customer is located, regardless of the
location of the generation source within the state. Since the license plate
charge assessed by NYPP to deliver power to a customer is identical for all
generators, the TSC for service into and within NYPP is not explicitly
included in the model.(FN 32)
Q. How did you model transmission costs within NEPOOL?
A. NEPOOL assesses a single network transmission charge on for use of its
pool transmission facilities (PTF). Since there are no internal wheeling
charges and no wheeling-in charges, I have not included any such costs for
deliveries within NEPOOL.(FN 33)
Q. What did you assume about transmission charges into NYPP and NEPOOL from
outside power markets?
A. There are eight paths by which power may move from NYPP into NEPOOL.
While these facilities are controlled by their respective ISOs, the wheeling
charge is determined according to the transmission cost of service of each
owner. For the wheeling charges from NY-West to NEPOOL, and from LIPA to
NEPOOL, where there is only one transmission owner, I have used the filed TSC
of the appropriate owner. For the NY-ETE to NEPOOL path, I have used the
average TSC from NYPP to NEPOOL, as posted by the NYISO. (FN 34)
LSEs in the New York markets that purchase energy from outside the state are
subject to transmission charges for "through or out" service from the region
from which they purchased the energy. Consistent with Appendix A, I used the
posted transmission rates customarily offered on the OASIS sites for imports
from PJM and NEPOOL. Similarly, I used NYPP through and out rates for
wheeling into PJM and NEPOOL.
For imports from HQ, I used its filed rates;(FN 35) for imports from OH (for
which I could not locate a separate transmission tariff), I used an estimate
of $5/MWh, which approximates the maximum filed rates that I have seen for
utilities in the ECAR and Northeast regions.
For other transmission wheeling charges, I have used the filed transmission
charges from the Order No. 888 tariffs or the wheeling charge for firm
transmission posted on OASIS, if the latter was systematically lower that the
Order No. 888 tariff. Since transmission from NY-ETE into NEPOOL is owned by
several different utilities, each with its own filed tariff rate, I have used
an average of these rates weighted by the share of the total interface
transmission capacity.
Q. Did you consider firm transmission rights within NYPP in your analysis
of the relevant energy markets?
A. Yes. Under the NYISO Tariff, grandfathered transmission rights are
conferred through the ownership of Transmission Congestion Contracts
("TCCs"). In general, these grandfathered rights were allocated only when a
member utility had a long term contract with a generator located outside of
its service area. Con Edison has a long term contract with Sithe's
Independence unit, located on the west side of Total-East, for 740 MW. The
contract is for the delivery of energy to the border of Con Edison's service
territory, and Sithe owns grandfathered transmission rights, specified in
Attachment H of the NYISO Tariff, for delivery of this energy across the
Total-East interface. Therefore, economically the Sithe contract can be
treated as a NUG contract located at Pleasant Valley (the northern border of
Con Edison's control area) which is East of Total-East. I accounted for this
in my analysis by moving the unit and adjusting the transfer capability of
the Total-East interface to account for the Sithe transmission rights.
Likewise, NYPA has grandfathered TCCs that allow it to meet its downstate
load with its upstate Fitzpatrick nuclear station. These rights allow NYPA to
move 289 MW into the NY-ETE market. Again, I moved the units into NY-ETE and
removed that amount from the available transmission across Total East.
Q. Other than the Sithe contracts and NYPA transfers, did you consider
ownership of firm transmission rights or TCCs in your structural analysis of
the market?
A. No. I have included only those TCCs that are used to transport power
from an identified contractual source. TCCs that have no firm power contract
are equivalent to long term firm transmission contracts for which no power
contract exists. Commission guidance in the Part 33 NOPR is to ignore such
contracts. Moreover, TCCs, being purely financial rights, do not allow the
holder to reduce the availability of transmission or dictate its use. Nor can
the holder of TCCs, if they are transmission providers, profit from higher
prices at the potentially congested destination end of the right (e.g.,
inside NY-ETE for contracts across the Total-East interface). The NYISO
treats revenues associated with grandfathered TCCs owned by transmission
providers as an offset against that transmission provider's fixed
transmission revenue requirement. Thus, any economic value conferred to a
transmission provider through grandfathered TCCs is automatically transferred
to all customers of that transmission provider. Thus, Con Edison's
grandfathered TCCs can in no way benefit Con Edison's shareholders nor
benefit its retail service customers compared to retail customers who chose
an alternative retail access provider.(FN 36)
Further, it is impossible to know at this time who will own the TCCs in 2001.
The NYISO Tariff requires transmission providers to periodically sell, at a
minimum, the TCCs in excess of their native load responsibility.(FN 37) Thus,
it is impossible to assign TCC ownership to any specific market participant
Q. Going back to the Sithe contract, and NYPA's rights of access to its
upstate generation, why are you treating these differently than other
grandfathered firm transmission rights?
A. These contracts are associated with firm power contracts or rights.
Moreover, they differ from other TCCs; they are designated as Third-party TWA
(Transmission Wheeling Agreements) in the NYISO Tariff. Revenues from TWAs
are not credited against Con Edison's or NYPA's TSC as is the case with other
Con Edison- or NYPA-owned grandfathered TCCs. By treating power delivered
under these contracts as being from units located within the East of Total-
East market, I conservatively have increased Con Edison's share in this
market and the overall market concentration.
Q. Are there other Third-Party TWAs listed in the NYISO Tariff?
A. Yes. There are 1,417 MW of Third-party TWAs over the Total-East
interface, of which Sithe TWA accounts for 740 MW. I have also explicitly
modeled NYPA's TWAs to bring power from its upstate nuclear facilities to its
downstate load. Other than these contracts, most of these grandfathered
rights are owned by unaffiliated small parties such as municipal utilities,
most of which are not explicitly modeled in CASm. Had I allocated this
transmission to these small parties, market concentration in the affected
region would have been reduced.
There are also Third-Party TWAs for the New York City cable interface, most
of which belong to NYPA customers in the City. None are owned by Con Edison
or companies with whom it has long-term contracts. Again, excluding
consideration of these TWAs is conservative since the amount of capacity
represented by them is assumed to be available for prorationing, including to
Con Edison generation located outside of the City.
Q. Are there any other firm transmission rights held by Applicants?
A. Yes. NUSCO, acting as an agent for CL&P, WMECO, PSNH and HWP has
reserved 500 MW of inbound service from New York to New England. NU's
original reservation expires March 1, 2000. NUSCO has first option to extend
the service. A request for extension to March 1, 2001 has been made. The
extension has not been approved by the ISO-NE.
If the firm transmission is not scheduled the day before, then the
reservation is released back to the Pool. NUSCO has the ability to reassign
the service to a third party instead of releasing it back to the Pool.
Since, prior to the proposed merger, NU neither owns nor contracts for
generating capacity in NYPP, I have followed the guidance in the NOPR and not
included these 500 MW of transmission as increasing the generating capacity
owned or controlled by NU. The 500 MW of transmission is assumed to be
available to all users and is allocated pro rata among the economic capacity
that is located in or can reach NY-ETE. Following the merger, however, the
merged Applicants could conceivably use this FTR to import Con Edison's
capacity into NEPOOL. Thus, it could be construed that while NU does not
"control" 500 MW of NYPP capacity to wheel into NEPOOL pre-merger, it does
after the merger. A conservative interpretation of Commission guidance would
therefore treat the 500 MW as being reserved fully by post-merger Applicants
to bring 500 MW of Con Edison-controlled generation into NEPOOL, removing the
500 MW of transmission from ATC available to other parties. To be
conservative, I have done the analysis assuming that the 500 MW is
exclusively available to post-merger Applicants.(FN 38) This assumption has
the effect of markedly increasing the apparent effect of the merger on
concentration in the NEPOOL market. While pre-merger the 500 MW of
transmission, approximately one-third of the NYPP-NEPOOL interface
capability, is available to all, it post-merger is assumed to be reserved,
resulting in an increase by approximately 500 MW in Applicants share of the
NEPOOL market.
Q. Have you taken any other transmission reservations into account in your
analysis?
A. Yes. Edison Mission Energy acquired firm transmission rights from PJM
into NYPP when it acquired the Homer City generation station from NYSEG. To
take these rights into account, I moved that portion of Homer City formerly
owned by NYSEG (half) into western New York and reduced the PJM-to-NY-West
ATC accordingly.(FN 39)
D. OTHER RELEVANT DATA
Q. What data sources did you use for native loads?
A. For the Available Economic Capacity analyses for which such data were
required, I used 1998 hourly load data from FERC Form 714.(FN's 40, 41) These
load data were adjusted to year 2001 using published load forecasts either from
Form 714 or EIA-411.
Q. What time periods did you examine in each market?
A. In each market, I examine peak and off-peak conditions in each of three
"seasons:" summer, winter and shoulder. The shoulder period includes both
spring and autumn. Peak and off-peak periods within a season differ in that
prices are higher (and in the Available Economic Capacity analysis, load is
higher) in the peak period. Seasons differ in my model in several respects.
As discussed earlier, scheduled maintenance outages occur in shoulder
seasons. Units with seasonal fuel-switching capability and gas-fired units
may have different costs in summer and winter. Moreover, many units have
different seasonal capacity ratings, depending on external temperatures or
availability of water. In order to capture "price spike" conditions, I also
have included for each season a "super-peak" analysis with a representative
price above the dispatch cost of any unit on the system. For the Available
Economic Capacity analyses for the super-peak, I use the average load of the
top 150 hours in each season.
Q. What was the basis for the prices used in your analysis?
A. Since the markets I examined are all within tight pool structures, the
filed system lambdas of the component utilities do not provide relevant
information on the market prices of the markets in which they are located.
Instead, I relied on two sources of data to set benchmark prices in each
market in each period.
As the best available data, I relied on 1998-99 data published by Power
Markets Week, which reports daily prices and a weekly range of low and high
on- and off-peak prices for East New York, West New York, PJM and NEPOOL as
the starting point for estimating the market prices that I used. A summary of
these data are found in Exhibit APP-10. I also examined the LBMPs in these
three pools and took into account the historical relationship of prices in
these regions. Based on these data, I developed a series of on- and off-peak
prices which provide a set of competitive market prices for all seasons. The
table below shows prices I analyzed for each peak and off-peak period. I also
include in workpapers analyses for prices $5 above and below each price shown
below.
Summer Winter Shoulder
Super Off Super Off Super Off
Market Peak Peak Peak Peak Peak Peak Peak Peak Peak
New York City 100 40 27 60 40 27 60 40 25
NY-ETE 100 32 26 50 32 26 50 31 23
Long Island 100 40 27 50 40 27 50 40 25
NE-ISO 100 32 24 50 30 24 50 29 21
NYPP 100 30 24 50 30 24 50 29 21
PJM 100 30 24 50 30 24 50 29 21
VI. IMPACT OF THE MERGER ON COMPETITION IN ELECTRICITY MARKETS
Q. Please identify the relevant product markets you analyzed.
A. Consistent with the product markets the Commission typically has
evaluated in the context of mergers, I considered the primary relevant
product market to be non-firm energy. Consistent with Commission guidance,
the product measures on which I concentrated were deliverable Economic
Capacity and Available Economic Capacity. These are used to measure market
structure in energy markets.
Consistent with Order No. 592 and Commission guidance in the Revised Filing
Requirements NOPR, I have not included a formal analysis of Uncommitted and
Total Capacity using the familiar Commonwealth standards. Such an analysis is
not required; the NOPR indicates that it is optional. As the Commission
recognized in Order No. 592, an analysis that ignores transmission
constraints and the delivered cost of power is of very limited use in
assessing the effects of a merger.
Q. What assumptions did you make regarding the extent of retail access in
the relevant markets?
A. Because the Applicants, and most other utilities in the region, are in
the process of implementing retail access plans, I took into consideration
partial retail access that lies between the level implicit in the Economic
Capacity analysis (no native load obligation) and the full retention of
native load obligation. Under the terms of the various settlements with their
state regulators, incumbent utilities in NYPP and NEPOOL will retain
responsibility to serve the portion of existing customers that choose to
remain with the utility for at least a transition period. I assumed that, for
relevant periods, Con Edison and other New York utilities would retain 75
percent of their retail load (equivalent for Con Edison to the current 2,000
MW of retail access plus an additional 500 MW of future retail access). In
New England, where the shift of consumers to retail access has been slower, I
assume that 90 percent of load in the service territories of CL&P and WMECO
stay as default or standard offer customers. Likewise, I use this 90 percent
for all other Massachusetts, Connecticut, Rhode Island and Maine utilities.
Since New Hampshire has not yet approved the PSNH Restructuring Settlement,
and Vermont has not started retail access, I assume that PSNH and all other
utilities in these states retain all of their retail load. The loads used in
my analysis, with and without retail access, are shown in Exhibit APP-11.
Q. What Provider of Last Resort (POLR) responsibilities will Applicants
have in the period covered by your analysis?
A. Each has a full POLR responsibility. However, the two Applicants have
taken different approaches for meeting the needs of customers who do not
select a competitive retailer.
Con Edison and Orange and Rockland are required by the NYPSC to retain their
POLR responsibilities during the transition to full retail competition.
Hence, they will have to acquire energy for all customers who do not select
an alternative provider. They will meet these requirements through their
existing long-term contracts and retained generating capability, possible
future contracts and through purchases of energy in the day-ahead NYPP energy
market. Due to its POLR responsibilities, Con Edison typically is a
substantial purchaser of energy. Indeed, since Con Edison Solutions has won a
significant portion of the customers who have selected an alternative
provider, a fact that my analysis of Available Economic Capacity does not
take into account, the POLR responsibilities of Con Edison and Orange and
Rockland in my analysis understate the extent to which Con Edison is a net
buyer.
NU has chosen a different strategy to meet its continuing POLR requirements
in those states where retail access has begun or soon will begin,
Massachusetts and Connecticut. CL&P and WMECO have divested or let long-term
contracts for substantially all of their generating capability. Hence they
have no resources with which to meet the POLR responsibility. These two
utilities, therefore, will have converted themselves into nearly pure
transmission and distribution companies and rely on other sellers to meet
their POLR requirements. CL&P's auction of its standard offer requirement has
been completed. As noted above, the auction covered 50 percent, with its
subsidiary, Select Energy, designated to serve the remaining half at prices
determined by the auction of the other half. A similar auction of all of
WMECO's supply responsibility in Massachusetts is in process. As noted
earlier,(FN 42) Select Energy is not on the short list of potentially winning
bidders. Since the winners of this auction have not been announced, I have
allocated one-third of WMECO's load to each of the three merchant generators
in NEPOOL with the largest amount of capacity. This assumption is
conservative, in that it reduces the amount of Available Economic Capacity;
if a supplier that lacks merchant generation in NEPOOL wins a part of the
load, the market will, in fact, be larger.
NU has indicated that it intends to follow a similar plan for PSNH,
simultaneously divesting both its generating capability and its native load
obligations, once New Hampshire has approved its restructuring settlement
agreement with PSNH. Since this settlement agreement has not yet been
finalized, however, I have conducted my analysis assuming that PSNH retains
its current resources and requirements.
A. ANALYSIS OF TOTAL CAPACITY
Q. Would an analysis of total, or installed capability using the hub-and-
spoke method demonstrate that Applicants have a problematic share of
capacity?
A. No. As I indicated above, I did not conduct a traditional Total Capacity
analysis. However, an even cursory review of data show that Applicants would
meet the Commission' standard under this test.
Con Edison currently owns or has under contract 4,587 MW of capacity in NYPP
and less than 400 MW in NEPOOL. NU retains, at the moment, approximately
4,530 MW of capacity. Since, under the Total Capacity test, the NYPP market
also would include all NEPOOL, Ontario Hydro, Hydro Quebec and PJM capacity,
and the NEPOOL market would include NYPP and Hydro Quebec, Applicants'
capacity share clearly is below 20 percent and, therefore, is below the
Commission's market power threshold using this test.
B. ANALYSIS OF UNCOMMITTED CAPACITY
Q. What would an analysis of Uncommitted Capacity show?
A. I did not conduct a traditional Uncommitted Capacity analysis of the
proposed merger, for much the same reasons as I did not undertake a
traditional Installed Capacity analysis. Further, the extensive divestitures
already completed by Applicants makes the results of this analysis readily
apparent.
As I stated above, Con Edison has retained installed capacity of only 4,587
MW in NYPP. This capacity serves a load in Con Edison's utilities' control
areas of approximately 11,285 MW, to which must be added an 18 percent
reserve requirement, for a total installed capacity requirement of about
13,300 MW. Any reasonable assumption regarding the penetration of retail
access will still show that Con Edison has substantially higher retained
native load than its installed capacity. Therefore, Con Edison has no
Uncommitted Capacity in NYPP. Even if NU has uncommitted capacity, the merger
cannot increase the share controlled by Applicants.
In fact, NU also lacks significant uncommitted capacity, having sold more
generating capability than it has shed native load responsibility. On
balance, under my conservative assumptions of retained ownership of NUG
contracts and generation, NU is slightly net capacity long in NEPOOL.
Collectively the NU companies are net long approximately from 10 to 900 MW
depending on the season and load condition. Adding Con Edison's NEPOOL
capacity of 378 MW does not materially increase Applicants' post merger
share. This level of Applicants' uncommitted capacity in the NEPOOL market is
well below the level that the Commission has established as acceptable.
C. ANALYSIS OF ECONOMIC CAPACITY
Q. Have you prepared a summary of the results of your Economic Capacity
analysis?
A. Yes. Exhibit APP-12 shows Applicants' market shares in each relevant
geographic market in each season and for super-peak, peak- and off-peak hours
for year 2001. The exhibit also displays the markets' HHIs before and after
the merger and computes the change in the HHI resulting from the proposed
merger.
Q. How did you define super-peak hours?
A. For each season, I identified the 150 hours of highest load for NU. The
remaining hours are then sorted as peak- or off-peak hours based on time of
day and whether it occurs on a weekday, weekend or holiday. Examining super-
peak hours separately allows analysis of whether the market structure is
different, or differently impacted by the merger, when the system is most
capacity-constrained.
Q. What does your analysis show for Economic Capacity in the NEPOOL market?
A. The proposed merger readily passes the Appendix A screen in NEPOOL.
NEPOOL is an unconcentrated market, with post-merger HHIs below 1,000 in all
time periods. Under the Appendix A guidelines, therefore, the merger would
pass irrespective of the merger-related change in HHI.
NU's share of the market is 11 to 15 percent and Con Edison's share is
approximately 2 percent. The "2ab" effect of the merger is, therefore, an
increase in HHI of approximately 40 to 62 points. However, my analysis shows
that the merger increases the HHI by approximately 80 to 100 points. The
change in HHI is due partly to the re-combination of the approximately 380 MW
of asset purchases and contracts that Con Edison's merchant generation
subsidiary purchased from NU with NU's remaining assets (included in the
"2ab" effect), but more substantially to the conservative assumption that my
analysis makes concerning the use of NU's 500 MW transmission reservation
from NYPP to NEPOOL. As described above, I assumed that this 500 MW was
available to all users pre-merger, but reserved fully by Applicants post-
merger to import Con Edison controlled energy. But for this differential
treatment of the transmission reservation between pre- and post-merger
states, the change in HHIs would be below 62 in all time periods.
Q. What does your analysis show for Economic Capacity in the NYPP market?
A. The proposed merger readily passes the Appendix A screen for the NYPP
market. NYPP is an unconcentrated market, with post-merger HHIs below 1,000
in all time periods. Under the Appendix A guidelines, therefore, the merger
would pass regardless of the merger-related change in HHI. Con Edison's share
of the market is around 10-15 percent and NU's share is 1-2 percent. HHI
deltas are between 11 (summer super-peak) and 41 (summer and winter off-
peak).
Q. What does your analysis show for Economic Capacity in the East of Total-
East market?
A. As with the larger NYPP market of which the East of Total-East market is
a constrainable portion, the results indicate that the proposed merger
readily passes the Appendix A screen. Like NYPP, this sub-region is
unconcentrated, with post-merger HHIs below 1,000 in shoulder seasons and
near or just above 1000 during the summer and winter. Con Edison's share of
the market is 15-19 percent and NU's share is about 1 percent. HHI deltas are
around 20-40 points, except during the shoulder off-peak period, when the
change is 66 points.
Q. What does your analysis show for Economic Capacity in the In-City
market?
A. The results indicate that proposed merger easily passes the Appendix A
screen in New York City. Con Edison's divestiture of its main generating
stations within New York City has resulted in four roughly equal-sized
competitors operating inside the City. Imports to the City can meet 5,000
MW, approximately half, of in-City peak load. Consequently, the City's
Economic Capacity market is either unconcentrated or only moderately
concentrated, with a maximum post-merger HHI of about 1200. Since HHI deltas
are less than one-third the 100 point threshold for moderately concentrated
markets, there is no screen violation.
Con Edison's share of the in-City market is similar to its share of the East
of Total-East market, 17-19 percent. NU owns no capacity inside New York
City, nor any within East of Total-East or Long Island. Consequently, to
reach the City NU must wheel its power through two constrained interfaces:
first the NEPOOL-NYPP interface, which only allows about 8 percent of the
economic capacity in NEPOOL to reach NY-ETE; and then from NY-ETE into the
City, which prorates its share of the approximately 20,000 MW of capacity
that is in or can reach NY-ETE (and is outside the City) to reflect the 5,000
MW transmission limit into the City.(FN 43) Consequently, NU's market share
for delivered economic power to the City is typically about 0.5 percent, except
in shoulder off peak periods when it rises to about 0.8 percent.
Consequently, the merger has only a minor effect on market structure in the
City, with HHIs rising by less than 20 points in all but shoulder off-peak
when the HHI increase is 30 points.
Q. Are there circumstances when the transmission capability into the City
is less than your analysis assumes?
A. Yes. A New York ISO Operating Guide requires that more generation be
dispatched within the City during periods when there is a risk of lightening
strikes on the high voltage cables north of the City. This is referred to as
"Stormwatch" conditions. Effectively, the ISO must limit the amount of energy
that can be supplied over these cables during such conditions.
Q. During Stormwatch conditions, will Applicants share of the In-City
market be larger than your more general analysis shows?
A. No, quite the opposite. All of NU's generation, and most of Con Edison's
generation, is outside of the interface that is limited during Stormwatch.
Hence this capacity will have a reduced share of the market. Con Edison's
capacity inside the City is either must-take NUG capacity, already assumed to
be fully dispatched in my analysis, or cogeneration capacity associated with
the operation of its stream system. Therefore, this capacity is not
dispatched at a higher level during Stormwatch. Thus, the principal result of
Stormwatch conditions would be to increase the output of in-City units that
Con Edison no longer owns at the expense of out-of-City units, including
Applicants'.
Q. What does your analysis show for Economic Capacity in the LIPA market?
A. The LIPA market is highly concentrated, with HHIs ranging from 2348 to
6090. This concentration level stems from the fact that most of the
generation within the LIPA service area is owned by KeySpan (and operated by
it under contract for the benefit of LIPA). Applicants own no generation in
this market area and participate minimally in it, reflecting the weak
transmission interconnections into LIPA. Con Edison's share typically is
about 3-5 percent and NU's share is typically less than 1 percent. However,
at very low price levels during off-peak periods, Con Edison has a 5.1 to 9.8
percent share and NU has a 0.9 to 1.4 percent share, resulting in HHI changes
of 10 to 31 points. All other periods show a change in the HHI of less than
10 points. The changes in HHI all are within screen values for a highly
concentrated market.
Q. What does your analysis show for Economic Capacity in the PJM market?
A. The results indicate that the proposed merger raises no competitive
concerns in PJM. PJM is unconcentrated in summer and shoulder seasons and
moderately concentrated (HHI of 1100) in the winter. Very little of NU's
economic capacity, however, reaches the PJM market, typically 0.1 to 0.2
percent of the market. Con Edison's share is at most 3 percent. The change in
the HHI resulting from the merger is near zero.
Q. How does your analysis for year 2000 differ from your findings for year
2001?
A. There are no material differences between the two analyses. In year 2000
all the markets are slightly more concentrated, and the changes to the HHI
caused by the merger tend to be slightly higher. These results flow directly
from the two principal differences between my year 2000 and year 2001
analyses: First, NU has more capacity in 2000 than 2001, since Select Energy
holds an 88 MW capacity contract that expires in late 2000. Second, some new
capacity is included in my 2001 analysis will not be available in 2000. This
new capacity tends to deconcentrate the market.
As with my year 2001 analyses, I find that the proposed merger readily passes
all Appendix A screens for Economic Capacity in year 2000.
Q. Please summarize your findings for the effect of the proposed merger on
Economic Capacity in the six relevant geographic markets for the year 2000?
A. As shown on Exhibit APP-13, the proposed merger readily passes the
Appendix A screen for Economic Capacity in all relevant geographic markets.
In NEPOOL, the one market where changes in the HHI exceed 100, the market is
not concentrated, with HHIs well below 1,000. In every other market, the
proposed merger would result in HHI increases below 100 and, with one
exception,(FN 44) below 50. The only interconnected market that is highly
concentrated, LIPA shows very small HHI deltas during all but off-peak
periods and an HHI delta within guideline values during off-peak periods. In
the at-most moderately concentrated PJM market, the merger has virtually no
effect.
Q. The HHI deltas are largest during off peak periods. Is this a result of
your treatment of NU's pumped storage capability?
A. Yes. My analysis makes the pumped storage capacity fully available
during high priced periods but does not take into account the need to pump
water to the upper reservoir during off-peak periods. In reality, NU's
ability to sell into wholesale markets is reduced by its pumping energy
requirements (up to 1,120 MW per hour) during off-peak periods. Had I netted
the average off-peak pumping energy from NU's Economic Capacity, its share
would have been materially less during off peak periods.
Q. Is there any other conservatism in your analysis that you believe is
important to interpreting these results?
A. Yes. These results are conservative in their treatment of Applicants'
pending divestitures that are scheduled to be completed before or during the
analysis year. Because these divestitures are not taken into account, these
results also are conservative as a "forward-looking" depiction of market
conditions for years subsequent to 2001.
D. ANALYSIS OF AVAILABLE ECONOMIC CAPACITY
Q. Have you analyzed Available Economic Capacity?
A. Yes, although at the outset it is worth noting that the rapidly moving
restructuring of the electricity markets in the Northeastern U.S. complicates
the analysis of Available Economic Capacity since the balance between
retained load and generation will change, literally month to month, during
the period of interest.
Q. Why is an analysis of Available Economic Capacity problematic in regions
undergoing retail access and utility restructuring?
A. The main reason is that the calculation of Available Economic Capacity
requires knowledge of each competitor's native and requirements load and
level of economic generation for each time period analyzed. Utilities in the
Northeast are in the process of both retail access and divestiture. The
Available Economic Capacity measure is highly sensitive to the relative pace
of these two activities. The pace of retail access take-up and, to a lesser
extent, future divestitures, are difficult to forecast. Any analysis will be
highly dependent on assumptions that are quite uncertain.
Even when the announced divestitures have been completed, the level of HHIs
still will be somewhat sensitive to the (unknown) buyers of divested assets
and to the amount of remaining native load responsibility of utilities and
non-utility generators under Provider of Last Resort ("POLR") provisions or
similar "default supplier" requirements. In the somewhat longer run, when all
or nearly all load is met on a market basis, the test will become identical
to the Economic Capacity analysis.
Q. What did you assume about retail access and divestiture plans in your
Available Economic Capacity Analysis?
A. As I discussed earlier, I have assumed that retail access in New York
reduces utilities' native load obligations by 25 percent, consistent with the
experience so far. Likewise, I have assumed 25 percent retail access
penetration in PJM to approximate the average take-up there. In New England,
I have assumed 10 percent retail access penetration in all states except
Vermont, which has no definitive restructuring plans in place. I
conservatively assume that no AEC was available from ECAR, SERC or Ontario.
Since the modeled Economic Capacity from Quebec already reflect seasonal
energy availability, I did not further reduce capacity from Quebec in the
Available Economic Capacity analysis.
My analysis takes into account take-back contracts and other supply
arrangements that underlie supplier of last resort responsibilities. Con
Edison has no such contracts.(FN 45) I reflect the auctions of supply
responsibilities by CL&P and WMECO. Thus, Select Energy is assumed to have 50
percent of the 90 percent of CL&P's load that is assumed to have not selected
an alternative supplier. NRG and Duke are assumed to serve 40 percent and 10
percent respectively of the POLR load. For WMECO, where no supplier has been
selected, I assume that the winning suppliers are the three largest merchant
generators in New England.
My analysis aggregates all affiliates to the corporate level for purposes of
determining the entity's Available Economic Capacity.(FN 46) Thus, all of NU's
served load (i.e., the 50 percent Connecticut POLR responsibility held by
Select Energy, the HWP and PSNH loads) and all of its Economic Capacity are
used in computing its Available Economic Capacity. Capacity that is in a
different market is not aggregated for purposes of calculating the balance
between load and economic energy. Thus, Con Edison's capacity in NEPOOL is
not used to offset net load requirements in New York but, rather, is
available in NEPOOL.(FN 47) Post-merger, with NU and Con Edison part of the
same corporation, Con Edison's NEPOOL capacity is available to offset NU's
load. During periods in which NU's load exceeds its own controlled resources,
the merger may cause Con Edison's Available Economic Capacity to disappear
from the market.(FN 48)
Q. What do you conclude about the amount of Available Economic Capacity
that Con Edison will have, absent the merger?
A. Under my assumptions regarding retail access, Con Edison will have no
Available Economic Capacity in any market within NYPP in nearly all cases. It
has de minimis Available Economic Capacity during some low-load periods. In
NEPOOL, however, Con Edison's 378 MW of former WMECO assets and its Millstone
2 contract give it a minor share of Available Economic Capacity.
Q. What do you conclude about the amount of Available Economic Capacity
that NU will have, absent the merger?
A. Under my conservative assumptions regarding the pace of NU's
divestitures, NU does have some Available Economic Capacity. According to my
analysis, NU holds between 2 and 7 percent of the NEPOOL Available Economic
Capacity.
Q. Did you conduct a detailed analysis of Available Economic Capacity in
each relevant geographic market outside of NEPOOL?
A. Yes, but the result of an analysis for relevant markets outside of New
England is pre-determined by the aforementioned facts and the results of the
NEPOOL analysis. Neither Applicant has any Available Economic Capacity
outside of NEPOOL. Applicants' share of Available Economic Capacity in any
other market cannot be greater, and indeed is certain to be less, that their
share of the NEPOOL market.(FN 49)
Q. What is the result of your Available Economic Capacity analysis for the
NEPOOL market?
A. My analysis of the NEPOOL market for 2001 is summarized in Exhibit APP-
14. The market HHI is just below the borderline between unconcentrated and
moderately concentrated. The proposed merger would increase the HHI by
substantially less than the 100 point guideline for moderately concentrated
markets in all time periods. Consequently, the proposed merger passes the
Appendix A screen for Available Economic Capacity. For the reasons discussed
above, it also will pass in all other destination markets.
Q. How does your results for year 2000 differ from your findings for year
2001?
A. As with the Economic Capacity analysis, there are no material
differences between the two analyses. As with my year 2001 analyses, I find
that the proposed merger readily passes all Appendix A screens for Available
Economic Capacity in year 2000, shown on Exhibit APP-15.
E. CONCLUSIONS ON ELECTRICITY MARKETS
Q. What conclusions flow from your examination of Total Capacity and
Economic Capacity?
A. Although I did not formally conduct a Total Capacity analysis, it is
clear from the facts I have stated that Applicants' market shares in all
relevant geographic markets are well below the 20-30 percent threshold
traditionally used by the Commission.
The proposed merger readily passes the Appendix A screens for Economic
Capacity. The Economic Capacity markets in NEPOOL and NYPP are each
unconcentrated. PJM, NY-ETE and New York City markets are all moderately
concentrated in at least some periods, but the merger would result in
increases to the HHI well below the 100 point screen threshold. In the one
highly concentrated relevant geographic market, LIPA, neither Applicant owns
any generating capacity, and the transmission constraints to LIPA limit their
pre-merger market shares, such that the effect of the merger on the HHI in
LIPA does not exceed 31 and is below 10 during peak hours.
Q. What conclusions flow from your analyses of Available Economic Capacity?
A. As a consequence of their substantial, state-mandated divestitures,
Applicants have little Available Economic Capacity. Con Edison's native load
obligations nearly always exceeds its generating capacity in NYPP. NU's
divestitures of both generation and native load responsibility have left it
closer in balance, but it still holds less than 6 percent of the NEPOOL
available economic capacity. The change in the HHI is less than the
competitive screen thresholds for a moderately concentrated market.
Consequently, the proposed merger creates no potential horizontal market
power in respect of these measures.
VII. VERTICAL ISSUES
Q. Please describe the vertical issues that you have addressed.
A. The Commission has identified three types of vertical issues. The first
is an ability to frustrate entry by control over potential sites, fuels
supplies or fuels delivery systems. The second is a concern that control over
transmission will be used to adversely affect competition in wholesale power
markets. The third is a concern, expressed in recent Orders concerning
"convergence mergers" and the NOPR on Part 33 that a control over inputs to
generation, especially gas transmission, might be used to adversely affect
competition in wholesale electricity. My analysis examines each of these
areas.
A. SITES
Q. Is there reason to be concerned that the merger will give Applicants an
untoward degree of control over generating sites?
A. No. Outside of New York City, there should be no unique difficulty in
siting generating facilities. The east of Total-East area is large and
includes major parts of the service territories of several utilities other
than Applicants, including CHG&E, NYSEG, NiMo and LIPA. NEPOOL, which is
generally uncongested, contains numerous utilities. Even if Con Edison or NU
were capable of blocking entry into their service areas, entry would not be
materially disadvantaged. The substantial level of announced entry in both
New York and New England demonstrates that entry is not inhibited.
Within New York City, there are sites available that are not controlled by
Con Edison.(FN 50) Further, Con Edison has committed to divest several sites
that it does control. As direct evidence that entry is feasible in New York
City, I note that Exhibit APP-8 includes seven projects totaling 4,045 MW of
planned new capacity within New York City by seven developers, three of whom
currently have no in-City capacity.
B. TRANSMISSION FACILITIES
Q. Do Applicants own, operate and control electric transmission facilities?
A. Applicants own substantial transmission facilities in their respective
control areas. NU owns and operates approximate 3,927 miles of high-voltage
transmission lines. Con Edison owns and operates approximately 1,209 miles of
transmission lines.
Q. Is there reason to be concerned that Applicants will use control over
transmission to impede entry or diminish competition in electricity markets?
A. No. Applicants have ceded all control area and security coordinator
functions to their respective ISOs.(FN 51) The Commission has found in many
previous merger orders that ceding control over transmission to an RTO moots
concern about vertical market power arising from electric transmission
ownership. Further, the fact that Con Edison and NU have divested, or soon
will divest, the substantial majority of their generation makes it especially
unlikely that Applicants will seek to use what little control over
transmission remains to them to disadvantage generation competitors.
C. DELIVERY OF FUELS
Q. What is the issue concerning an applicants' control over essential fuels
or delivery systems?
A. In the context of long term capacity markets, the issue is whether
applicants can foreclose or impede the entry of competing generators. Other
vertical issues arising from control over fuels delivery systems are
discussed below.
Q. Do these Applicants have the ability to frustrate entry into electricity
generation due to their control over fuels or fuel delivery systems?
A. No. Applicants lack a concerning degree of control over fuels supplies.
Neither controls gas production facilities and, in any event, the Commission
has found that the wellhead gas and gas gathering market is competitive. An
entrant into generation in the region in which Applicants are located would
have no difficulty in purchasing commodity gas from a multiplicity of
sellers. Applicants also do not control long distance gas transmission
facilities that potentially might be used to disadvantage entrants.
Applicants' participate in the natural gas market principally as regulated
local distribution companies.(FN 52) As already discussed, an entrant
competitor in electricity generation to serve any of the geographic markets
except In-City would not need to locate in the electric service areas of
Applicants. This applies with even greater force to their gas service areas,
which are smaller than their electric service areas. Even within their gas
service areas, Applicants cannot use their role as gas distribution companies
to impede entry. New gas generators of sufficient scale to affect electricity
prices routinely connect directly to pipelines and, indeed, to improve
bargaining leverage, usually select locations with access to multiple
pipelines. Even if, for some reason, a new generator felt it necessary to
purchase distribution services from an Applicant, Applicants' distribution
activities are regulated by the NYPSC and the CT-DPUC, from whom an entrant
generator who felt disadvantaged could gain redress. As public utilities,
Applicants in general are obligated by New York and Connecticut State
statutes to initiate gas service upon request.(FN 53) More specifically as to
Connecticut gas companies, the Connecticut General Statutes prohibit a gas
company from unreasonably failing or refusing to furnish adequate gas service
at reasonable rates. New York law requires that Con Edison render service in
a non-discriminatory fashion.(FN 54) The NYPSC and CT-DPUC actively oversee
Applicants' compliance with these statutory requirements.
Q. Are there other vertical issues that the Commission has found require
investigation in the context of mergers between electric utilities and gas
transportation providers?
A. Yes. The Commission has indicated that under some circumstances such
mergers could give rise to vertical concerns. Potential market power arising
from a merger between an electric utility and a gas pipeline is discussed by
the Commission principally in its final order on the Enova/Pacific
Enterprises merger in 1997,(FN 55) the April 1998 Notice of Proposed Rulemaking
(NOPR) on Part 33,(FN 56) and in the recent Order on the Dominion/CNG merger,
Docket No. EC99-81-000. Briefly, the main areas of concern are the creation of
incentives for the upstream activities (i.e., gas-related) to raise costs for
rivals of the electricity generation affiliate, enhanced ability to facilitate
coordination of pricing in upstream or downstream markets and enhanced ability
to evade regulation, primarily through self dealing. The Commission has also
expressed specific concerns that convergence mergers involving an upstream gas
supplier serving the downstream merger partner, as well as competitors of that
partner, could provide preferential terms of service and that a pipeline
serving electric generation could provide commercially valuable information
to newly affiliated electricity generating or marketing operations. As shown
below, none of these concerns will be appropriate to this merger.
Q. What are the business activities into which the upstream and downstream
markets can be divided?
A. In the upstream market, these include (a) control over commodity gas
supplies, (b) the transportation of these supplies from gas-producing regions
and remote storage facilities into the market area and (c) to the degree that
it is relevant, the local distribution of these supplies to gas-fired
electric generating facilities.
The relevant downstream product for purposes of this portion of my analysis
is wholesale electric energy within the relevant geographic markets in NYPP
and NEPOOL. Applicants have no natural gas facilities that serve generators
located in the PJM market and, as my analysis has shown, little participation
in PJM electricity markets, so it is not relevant to my vertical market power
analysis.
Q. Please focus first on the commodity gas market. Do Applicants have
potential market power in that market?
A. Clearly not. The Commission has found that this market is competitive.
Further, neither Applicant is a gas producer, nor does it hold gas commodity
contracts to supply unaffiliated retailers and off-system consumers.
Applicants' sole role in the commodity market is as buyers, primarily on
behalf of franchise customers. Hence, they cannot have sellers' market power.
While Applicants have purchase contracts for significant volumes of gas, they
account for but a small portion of production volumes in relevant producing
areas.
Applicants' gas contracts and firm transportation contracts exist to serve
their regulated customers. Applicants have no control over the consumption of
their customers and, as further discussed below, little storage injection or
withdrawal capacity that could be used to vary their use of gas and gas
transportation separate from the send out to their customers.(FN 57) Hence,
quite clearly, Applicants lack market power in commodity gas.
Q. Please describe the current competitive conditions for long-haul gas
transportation services.
A. The relevant geographic market for gas transportation is more restricted
than the natural gas commodity market. Con Edison, draws its supplies from
the transportation system into southeastern New York, northeastern
Pennsylvania and the northern half of New Jersey. I will call this the "New
York Metro" area. The transportation market is larger than simply the
downstate New York area and is defined by the flexible receipt and delivery
point entitlements within a rate zone under the pipelines' tariffs.(FN 58) As
shown in Exhibit APP-16, the regional gas transmission network is highly
interconnected, and is supplied by no less than five independent long-haul
pipeline companies delivering gas supplies from diverse geographic regions
across the North American continent. Columbia, Transco, Texas Eastern and
Tennessee transport gas supplies from the Gulf Coast and Southwest. In
addition, Tennessee transports gas produced in western Canada, as does
Iroquois. Columbia is also a major transporter of gas produced in the
Appalachian Basin.
The preponderance of gas supplies delivered into the New England currently
passes through the New York metro area and uses this same delivery
capability. Over the next several years, the current pipeline configuration
will be significantly and predictably altered, resulting in a still larger
scope for commodity gas competition. New pipeline transmission facilities and
expansions to existing pipeline systems will deliver significant quantities
of new gas supplies to New England from non-traditional sources without
transiting through New York and New Jersey. Gas production from the Sable
Island Offshore Project will flow into the existing New England gas
transmission system from the northeast via the Maritimes & Northeast Pipeline
("MNP").(FN 59) Additional western Canadian gas production is now arriving from
the north via the Portland Natural Gas Transmission System ("PNGTS").
Additional liquefied natural gas ("LNG") supplies from new production
facilities in the Caribbean Basin will arrive at the Distrigas of
Massachusetts ("DOMAC") terminal in Everett, Massachusetts, which is
expanding its vaporization and compression capabilities. Competition between
gas transported though the New York metro area and gas delivered over these
new facilities will expand the area over which the price of delivered gas is
arbitraged. A tabulation of these facilities and their ownership is provided
in Exhibit APP-17.
Q. Do Applicants compete in the gas transmission business?
A. Con Edison does not own any portion of any gas transmission system. NU
has a non-controlling, 5 percent, equity share in the PNGTS. This is the
smallest share among the seven partners in that project. As described briefly
above, PNGTS is a single pipe located wholly within New England that connects
up with long haul pipelines at the Canadian border and in Massachusetts.
PNGTS was completed in 1998; over most of its length it parallels pre-
existing pipelines which are connected to most of its customers. The PNGTS
provides NU's Newington Station with direct gas interconnection. The PNGTS
represents less than 10 percent of gas transmission capability into New
England, so NU's share of PNGTS gives it well below a 1 percent ownership
share of the region's gas transmission.
Since NU does not have a controlling interest in the PNGTS, it cannot use its
gas transmission ownership to attempt to exercise vertical market power.
Furthermore, the only existing or planned generation capacity directly served
by PNGTS is owned by Applicants, so there would be no "raising rivals' costs"
issue, even if NU had a controlling interest in PNGTS, which it does not.
Q. In the Memorandum attached to the Dominion-CNG Order, the Commission
noted that, in measuring concentration in upstream markets, "Relevant
alternative sellers might include shippers with firm rights that could sell
capacity in competition with CNG under its capacity release program." Do
Applicants have firm transmission rights for gas transmission?
A. Yes. Both Applicants have firm transmission rights (FTRs).(FN 60) The
merging parties' contract entitlements to the region's interstate gas
pipelines, as taken from the Index of Customers file with the Commission
for these facilities, is provided in Exhibit APP-18.
Con Edison (including both CECONY and O&R) is reported as having 414 MMcf/d
of FTRs into the Metro New York region. These rights are used to serve their
LDC gas customers' requirements. These rights represent about 8 percent of
the 5,237 MMcf/d transportation capacity serving Metro New York and southern
New England.
NU (including prospectively Yankee Energy Systems) is reported as having FTRs
for 435 MMcf/d. This capacity is 8 percent of the combined 5,237 MMcf/d
capacity into the Metro New York/Southern New England market.
At present (i.e. prior to completing the Yankee Energy Systems acquisition),
NU has rights to transport a minimum of 30 mmcf/d for seven off-peak months
of the year (April through October) on PNGTS; this volume represents 14.1
percent of the contracted firm capacity on the PNGTS as of November 1999 and
about 8 percent of the PNGTS maximum capacity without compression during the
off-peak period.
Q. Do these rights holdings create a potential vertical market power issue?
A. No, and I do not believe that the Commission was suggesting that they
do. The Commission rightly observed that the existence of a pool of
resellable rights in the hands of shippers is relevant to an analysis of the
competitive structure of the pipeline market, since such resale could compete
with the pipelines' attempts to withhold the supply of, or increase the price
of, gas transmission. However, if one examines the potential vertical abuses
that the Commission discusses in Dominion-CNG and in previous Orders, they
all require that the upstream affiliate be the operator of the pipeline. As a
mere holder of rights, these Applicants lack these capabilities. Rights
holders cannot withhold capacity or take other actions (e.g. curtail service,
close windows or require alternative nomination locations) that theoretically
might be available to a pipeline seeking to raise the costs of rivals to
affiliated downstream generation. They cannot share competitively sensitive
information with affiliates, since they have no inside knowledge of the
operations of generators connected to the pipeline on which they have rights.
Nor can they impede entry, since they have no control over pipeline expansion
or the availability and costs of new connections.
Moreover, even if rights were somehow equivalent to pipeline ownership in
terms of their potential for vertical abuse, the Dominion-CNG Memorandum
suggests that they will count only to the extent that the holder could sell
capacity on terms comparable to the pipelines. In the case of these
Applicants, essentially all firm rights are held to support the firm native
load requirements of the LDC's customers. Applicants are in no position to
sell these rights. At most, they could sell interruptible or short term firm
rights for a portion of them during periods of low demand on the LDC's
systems.
Q. Assuming that the mere capacity rights on gas transmission power were
viewed as a potential source of vertical market power, would the merger, by
bringing Yankee's and Con Edison's rights under common ownership confer
potential vertical market power?
A. No. I note first that it is not clear what the appropriate geographic
market for transportation rights is in the context of this merger. The
Commission has given little guidance concerning appropriate geographic market
definition. One possible definition, relevant to a vertical market power
analysis (though not necessarily to an analysis of the upstream market
itself) would be to define the relevant geographic markets for gas
transportation services as the geographic areas where generation competes
importantly.(FN 61) For example, if NEPOOL is a relevant downstream market,
then NEPOOL and areas that are important suppliers of electricity into the
NEPOOL market would also comprise a relevant upstream market. If this approach
to defining the upstream market is adopted, then either 1) NYPP generators
are not competitively significant in NEPOOL, due to limited interpool
transmission links, in which case Con Edison's and Yankee/NU's gas
transportation rights are not in the same upstream market, or 2) NYPP and
NEPOOL are in the same downstream market and hence upstream market, in which
case the upstream market is at least New York plus New England, in which case
Applicants have a small share.
Alternatively, one might seek to define an upstream market according to the
competitive conditions in gas markets. The smallest such market that is
plausibly relevant (albeit it is likely to be overly restricted in scope) is
the sum of the NEPOOL and Metro New York markets since this is the smallest
market that contains Applicants' FTRs. Moreover, as noted above, a large
proportion of gas transmission into New England passes through the Metro New
Jersey market, and thus it competes for the same capacity. In this case
Applicants' combined share is only 16 percent of the of firm transportation
(FT) capacity entitlements into the region, which is not a share sufficient
to cause a concern that they have market power.
Q. Have you performed the analysis of the upstream market that the
Memorandum attached to the Dominion-CNG Order outlines?
A. Yes. In performing this analysis I have attributed the capacity
underlying the FTRs of major shippers to them. Since Applicants control no
pipelines directly, this is the only way of attributing "control" in the
upstream market that gives Applicants any share. In reallocating control from
the pipelines to the holders of FTRs, I have considered only large LDCs in
New York and New England. The balance of pipeline capacity, which includes
FTRs that are held by shippers other than those that my analysis specifically
takes into account, is attributed to the pipeline. This systematically
overstates concentration in the pipeline market.
Q. What does this analysis of the upstream market show?
A. This analysis is summarized on Exhibit APP-19. Despite the fact that my
analysis attributes a greater share of pipeline rights to the pipelines than
is warranted, the pipeline market is not highly concentrated; the post-merger
HHI is 1,361. Since the vertical market test outlined in the Part 33 NOPR
requires that both upstream and downstream markets be highly concentrated in
order to violate the vertical screen, this analysis demonstrates that there
is not a vertical market power problem arising from concentration of the
upstream and downstream markets.
Q. Is there any impact of the merger resulting from combining natural gas
storage assets?
A. No. Con Edison owns a minority interest (28.8%) in the Honeoye Storage
Facility in western New York State, effectively controlling 1.2 billion cubic
feet of working storage capacity, representing a de minimus market share of
the storage fields predominantly located in central Pennsylvania and western
New York.(FN 62) Yankee has 30 Mdt/day of injection and 60 Mdt/day of
withdrawal with 235 Mdt/day of gas delivery capacity. Con Edison holds 18.6
MMdt of working capacity, while NU holds 5.1 MMdt, out of the total regional
working capacity of 487 MMdt. Even if, for the sake of argument, one treats
these contract quantities as equivalent to outright ownership, the
concentration of storage ownership/entitlement represented by this merger
represents a delta HHI of 8 points. Thus, the merger has minimal effect on
the market for gas storage.(FN 63)
Q. Please turn now to Applicants' LDC operations. Do Applicants serve
electricity generators as local distribution companies?
A. Yes. Both Con Edison and NU (after the YES acquisition) provide gas
distribution services to generators in their service areas. As shown in
Exhibit APP-20, Con Edison provides gas distribution service to twelve
generating facilities in downstate New York, including the large in-City
Astoria, Poletti and Ravenswood stations and the Bowline and Lovett plants in
Rockland County. As discussed below, these facilities pay negotiated
distribution rates that are markedly below the just and reasonable rate for
distribution service embodied in the NYPSC general tariff. The NYPSC recently
approved generic rates for electricity generating customers to reflect the
ease of bypass. The generic rate schedule removes the potential flexibility
that the LDC had in negotiating bypass rates which might have been used to
advantage particular generating units relative to others. (FN 64)
No current NU company provides gas distribution service to any electric
generator. Its pending acquisition, Yankee Energy System, provides gas
distribution service to only one electric generating station, Montville 5.
This 81 MW unit in Connecticut can burn either gas or oil. The ease with
which Yankee can be bypassed with a direct interconnection to the Algonquin
pipeline is reflected in the discounted rate that Montville pays for
distribution.
Q. Would it be appropriate to treat the fact that Applicants serve
electricity generators as LDCs as somehow giving them control over those
generators in a manner similar to direct ownership of them?
A. No. As regulated LDCs, Applicants have very little even theoretical
ability to affect the cost or availability of these generators.(FN 65) The
Commission has found potential competitive problems with combination mergers
between gas and electric utilities located in the same geographic area in the
Dominion-CNG merger, the Enova-Pacific Enterprises merger and the Brooklyn
Union Gas ("BUG")-LILCO merger. The facts in this case are readily
distinguished.
The single most important distinction is that in each of these three prior
cases, the merger was between previously unaffiliated companies in
overlapping geographic markets. This is not the case here. Con Edison already
is affiliated with the gas LDCs in its area that would be part of the merged
company. The merger between NU and Yankee, which I assume to have been
completed, is not part of this transaction.
This merger does create an affiliation of a New York-New Jersey utility with
a Connecticut gas LDC that did not exist previously, and a similar
affiliation between a New England electric generator and a New York-New
Jersey LDC. However, the limited size of the interconnection between ISO New
England and ISO New York means that there is little potential competitive
significance to these new affiliations.
In contrast, the Dominion-CNG merger was a merger between a large interstate
pipeline company and a large electricity generator. CNG was a supplier to
actual and potential generators in a wide area, including the highly
concentrated market in which most of Dominion's electricity generation was
located. In this case, neither Applicant is an interstate pipeline. Neither
serves generation in the areas where the others' generation is located.
Yankee serves only 81 MW of utility generation. Moreover, none of the markets
in which Applicants own generation are highly concentrated.
Because Yankee serves so little gas-fired utility generation, adding Yankee
to the Con Edison family clearly could have no effect on the downstream
electricity market in New York.(FN 66) The only potential vertical issue with
a nexus to the merger would be the merging of NU's New England generation with
Con Edison's LDC operations.(FN 67) The "downstream" New England generation
market is unconcentrated and surely would remain less than highly concentrated
even if, as suggested in the Memorandum attached to the Dominion-CNG order,
downstream market HHIs are calculated with all gas-fired generation attributed
to the LDC or pipeline that serves it. Since the vertical test proposed in the
NOPR and the Dominion-CNG Memorandum is passed if either the upstream or
downstream market is not highly concentrated, this merger would pass the
vertical screen were it deemed to be relevant to a merger involving only LDC
operations.
In Enova-Pacific Enterprises, a concern was that Pacific Enterprises would,
by reason of its affiliation with an electric generator, acquire an incentive
to manipulate the price and availability of gas to favor the newly affiliated
electricity generation activity. The concern was due to its control of the
transmission pipeline that served a large and constrainable electric
generation area, and to its control over all of the gas storage in the area
and its flexibility in using that storage to meet its large sendout
requirements. I participated in the Enova-Pacific Enterprises merger and am
very familiar with the intervenor allegations to which the Commission
responded in that proceeding. Applicants in this case, as mere LDCs, clearly
lack the ability to affect electricity prices that Southern California Gas
was alleged to have. In particular, they do not control high pressure
pipelines covering a wide and constrained area. Nor do they control material
amounts of storage that hypothetically might be used to manipulate short term
prices. Since they are selling essentially all of their gas-fired generation,
they cannot favor affiliated generators. Most of their remaining generation
is inflexible (primarily must-take contracts and a nuclear unit), and cannot
benefit from market information that their gas operations might (but for code
of conduct restrictions) make available.
In BUG-LILCO, the concern was that BUG might gain an incentive that it lacked
previously to impede the siting of generation in the LILCO service area due
to its acquisition of generation. In this case, Con Edison and NU already are
combination utilities serving some of the potential generating sites in their
electric service territories. Neither can deliver gas to generators in the
other's electric service area. Hence, any incentive issues of the type that
concerned the Commission in BUG-LILCO are pre-merger and have no nexus to it
Q. Please describe the potential for bypassing Applicants' distribution
services.
A. All of the large generating stations served by Applicants have
relatively low cost bypass alternatives. Evidence of this for Con Edison's
existing stations is the record in a New York case establishing the rates
charged by Con Edison's gas division for service to its gas generating
stations. As discussed in the Recommendation of the Gas & Water Division,
adopted by the NYPSC, Con Edison submitted a detailed study showing the total
cost of bypass pipelines to connect its electric generation facilities that
are served by its gas LDC directly to transmission facilities not owned by
Con Edison to be approximately $75 million, resulting in an amortized
incremental cost of local transportation service of just $0.01 per dt.
Commission staff found the estimate to be reasonable.(FN 68)
Exhibit APP-20 provides relevant facts concerning economic bypass for the
electric generators served by Con Edison. The unit served by NU, Montville 5,
also has economic bypass opportunities, since it is approximately 8,100 feet
from the nearest gas transmission pipeline.
Q. Can Applicants' LDC activities discriminate in favor of their owned
facilities as was alleged in Enova-Pacific Enterprises?
A. There is no basis for this concern since Applicants are divesting
essentially all of their gas-fired generation. Even were this not the case,
both distribution rates and terms of service, most notably curtailment
priorities, are regulated by the NYPSC or the CT-DPUC.
Q. Can Applicants' gas LDCs charge different prices to different
electricity generators?
A. Historically, yes. Until recently, NYPSC and CT-DPUC policy permitted
discounted pricing on a customer-by-customer basis to avoid the loss of
contribution caused by uneconomic bypass. These negotiated prices were, and
in the case of Yankee Gas in Connecticut still are, subject to a floor of the
incremental cost of delivery and a ceiling of the otherwise applicable tariff
rate. Both the generation currently operated by Applicants and the generation
that they serve that is owned by others receive discounted distribution
services. This is the result of the low bypass cost discussed above.
Negotiated prices for gas transportation are required by statute to be non-
discriminatory and are publicly available, so that customers can determine
what like-situated customers are paying. Individually negotiated contracts
were reconsidered in the Gas Restructuring Proceeding. The NYPSC concluded
that ".price differentiation should be permitted if it does not result in
injuries to competition in either the primary market (either natural gas
alone or all relevant sources [of] energy.) or secondary markets (the various
lines of business in which customers in a given region are engaged)."(FN 69)
The Connecticut DPUC has made similar decisions in several dockets over the
years involving the Connecticut gas companies that it regulates.
The NYPSC recently concluded that the restructuring of the electricity
industry in New York requires that it revisit the issue of individually
negotiated delivery charges, citing potential injuries to competition in the
electricity market.(FN 70) This proceeding was recently completed and the
NYPSC adopted a generic and non-discretionary basis for settling tariffs for
gas transportation service by LDCs to electric generators. (FN 71)
Q. Setting aside the issue of pricing, are there other ways in which
Applicants' gas LDCs could affect gas availability or otherwise significantly
impact competition in the electricity market?
A. No. Concerning existing generation facilities, the only plausible way in
which Applicants might seek to either favor one over another is to curtail
availability, interrupting the ill-favored generator. In fact, curtailment of
deliveries must be allocated on a pro rata basis in an established succession
of service categories or priorities, beginning with interruptible dual-fuel
customers.(FN 72) If one such customer is notified of a 30 percent curtailment
in gas deliveries due to low system pressure, for example, all similar
customers must be curtailed to the same degree. In any event, Applicants have
no incentive to engage in discriminatory behavior since they will not own
significant gas-fired generation. Moreover, since Applicants are net buyers
during most foreseeable load conditions, their incentive is to lower, not
raise, electricity market prices. ]
D. CONCLUSION: VERTICAL ISSUES
Q. What conclusions do you reach regarding the potential for this merger to
create vertical market power?
A. The proposed merger will not create vertical market power arising from
Applicants' control of transmission facilities or generating sites, nor from
their activities in the natural gas markets. All relevant portions of
Applicants' electric transmission facilities are controlled by their
respective ISOs. Applicants do not control most generating sites within their
constrainable regions, as evidenced by the substantial announced new entry in
and around the service territory of each Applicant.
With regards to natural gas transmission, Applicants do not control any gas
transmission pipeline. Applicants' FTRs on long haul pipelines do not confer
any of the vertical market powers that have concerned the Commission;
moreover, neither the upstream market nor relevant downstream markets are
highly concentrated.
Applicants' gas service is restricted to short-haul transportation, which is
already discounted due to favorable bypass options. Neither transports gas to
the other's electricity generating facilities or to other generating
facilities in the market containing the other's electric generation, creating
a merger-related ability to evade regulation or raise rivals costs. The
electricity generation served by each Applicant is competitively
insignificant in the electricity markets served by the merger partner. This
is particularly true of NU, which will serve only a single, small, gas
generator. The only electricity market where a theoretical vertical effect
arising from the merger might exist is New England; due to transmission
limits, the generation served by Con Edison's LDC is competitively
insignificant. In any event, the NEPOOL market is unconcentrated, so that the
Commission's vertical test is passed irrespective of the structure of the
upstream gas market. Finally, the upstream gas transmission market is not
highly concentrated. Based on these facts, I conclude that the proposed
merger will not create vertical market power.
VIII. CONCLUSION
Q. Does this conclude your testimony?
A. Yes
Footnotes
1. Inquiry Concerning The Commission's Merger Policy Under the Federal Power
Act: Policy Statement, Order No. 592, 61 Fed. Reg. 68,595 (1996), III FERC
Stats. & Regs, Regs. Preambles 31,044 (1996), order on reconsideration,
Order No. 592-A, 62 Fed. Reg. 33,341 (1997), 79 FERC 61,321 (1997).
2. With reference in particular to Revised Filing Requirements Under Part 33
of the Commission's Regulations, 63 Fed. Reg. 20,340 (1998), IV FERC Stats.
and Regs., Proposed Regs. 32,528 (1998) ("Part 33 NOPR") and its
subsequent interpretation in Dominion Resources, Inc. and Consolidated
Natural Gas Co., 89 FERC 61,162 (1999) ("Dominion").
3. NU retains the option of bidding, through an unregulated subsidiary, on
the non-nuclear assets owned by Public Service Company of New Hampshire (PSNH).
4. For example, Docket Nos. EC98-60-000, EC98-62-000, EC98-68-000, EC98-82-000
and EC99-97-000.
5. Constraints within PJM limit west-to-east flows across interfaces dividing
west from central and central to eastern PJM. Pennsylvania-New Jersey-Maryland
Interconnection, 81 FERC 61,257 (1997); PJM Interconnection, 86 FERC 61,247
(1999), aff'd 88 FERC 61,274 (1999); Testimony of William
H. Hieronymus in Commonwealth Edison Co., Docket No. EC00-26-000
(Nov. 22, 1999). NYPP is connected between western New York and the
western part of PJM and NYPP-ETE is connected with eastern PJM. The reason
why shares and resulting HHI deltas in PJM must be less than in NYPP is
that Applicants' share of imports from NYPP and NEPOOL into PJM are equal
to their shares in NYPP. Proration of the NYPP-PJM interfaces will be
according to the shares on the NYPP side of the interface, i.e. the shares
in NYPP. Within any area in PJM, those shares will be diluted by other
Economic Capacity located within the area or that can reach that area from
elsewhere in PJM or from non-NYPP interfaces with other regions (SERC and
ECAR). Hence, Applicants PJM shares necessarily are smaller than their NYPP
shares. My analysis of PJM does take the intra-PJM constraints into
account. While I report results only for PJM as a whole, results for
constrainable sub areas within it are contained in my workpapers.
6. In Connecticut, residential gas service has not yet been unbundled.
7. O&R includes the regulated utilities of Rockland Electric Company and
Pike County Light & Power.
8. CEEMI is a wholly-owned subsidiary of Consolidated Edison Energy, Inc.
("CEEI"), which in turn is a wholly-owned subsidiary of Consolidated
Edison, Inc.
9. Con Edison Solutions also offers retail gas service in New Jersey.
10. Specifically, it sold contracts for its 81 percent entitlement in
Millstone Unit 2 (711.1 MW), its 52.933 percent entitlement in Millstone
Unit 3 (603.4 MW) and its 4.05985 percent entitlement in Seabrook (47.1 MW).
11. Select also won an additional 10 percent (88 MW) of Millstone 2 for
calendar year 2000.
12. NU holds its PSNH ownership share of Seabrook in its unregulated
affiliate, North Atlantic Energy Company. This contract is for this
affiliate's share of Seabrook capacity and energy.
13. The HHI is calculated as the sum of the squares of each company's market
share, expressed in percentage terms.
14. See, e.g., Central Hudson Gas & Elec. Corp., 83 FERC 61,352 (1998),
order on reh'g, 87 FERC 61,135 (1999); Central Hudson Gas & Elec. Corp.,
88 FERC 61,229 (1999); Consolidated Edison, 86 FERC 61,064 (1999); Order
Authorizing the Process for Auctioning of Generation Plant, Consolidated
Edison Co. of New York, Inc., Case 96-E-0897 (issued and effective July 21,
1997.)
15. This contract allows O&R to purchase energy as well, but at the market
price. Hence Con Edison does not enjoy any equity-like ownership of this
energy.
16. Throughout my testimony, capacities and market shares always refer to year
2001 values unless explicitly noted otherwise.
17. This convention, which is consistent with guidance in Appendix A, arises
from the fact that firm sales reduce capacity "controlled" by the seller
during all hours. Assigning the lowest cost capacity to the sale assures
that the transfer of economic interest in the sold capacity to the buyer
from the seller will be reflected in the analysis.
18. Power flows in New York are principally from the north and west to the
southeast. Hence, the NY-ETE sub-market is on the constrained side of the
interface. Moreover, Con Edison's New York capacity is within NY-ETE.
19. NEPOOL's restructuring and market rate filings were based on a single
market without systematic internal constraints. The Commission's findings
on market power relied, in part, on the absence of constraints and the
Commission noted that no intervenor contested the use of a single NEPOOL
market for market power analysis purposes. "We accept NEPOOL's definition
of the geographic market as New England during periods when transmission is
not constrained. Historically, transmission constraints within New England
have been rare. No intervenor disputes NEPOOL's definition." New England
Power Pool, 85 FERC at 62,477.
20. See citations in footnote 14.
21. A load pocket is a geographic load area that, because of transmission
limitations, must have internal generation to ensure reliable service in
the area under normal and contingency conditions.
22. Applicants' shares of capacity that is subject to proration at the
NYPP-PJM interfaces is identical to their shares in NYPP. However, their
capacity will be reduced in proportion along with all other such capacity
as it is "squeezed" through the interface. Hence, its proportionality with
other such capacity will be maintained. However, the fact that the market will
now include capacity located in PJM (and, to a degree, SERC and ECAR) that
was not included in the NYPP market assures that Applicants shares will be
less in PJM than they were in NYPP. From this it also follows that the HHI
delta will be less.
23. See Testimony of William H. Hieronymus in Commonwealth Edison Co. et al.
Docket No. EC00-26-000, and Jersey Central Power & Light Co., 88 FERC
62,223 (1999). As noted in a previous footnote, analyses of the PJM
market have taken into account the sub-markets created by a series of
constraints that can limit the typically west-to-east flows within PJM. I
have reflected these constraints in my analysis. Moreover, while I do not
report results for PJM sub-regions in my testimony, my workpapers show such
results and confirm that there are no screen failures associated with the
merger.
24. The one exception to this rule is the imports into western PJM from ECAR
and SERC, which are subject to a simultaneous import constraint that is
described in detail on the PJM OASIS. This simultaneous constraint is
modeled in my analysis to mirror the OASIS description.
25. New York Power Pool Load and Capacity Data 1999.
26. NEPOOL's OASIS postings to and from NYPP list 3 paths, corresponding to
transmission capacity into LIPA, NY-ETE and NY-West. I model each path
separately.
27. The NYISO auctions transmission congestion contracts across internal
interfaces. These TCCs confer only financial rights, however, and are re-
auctioned every six months.
28. This is consistent with the Commission's approach in Ohio Edison Co., 80
FERC 61,039 at 61,104 (1997).
29. The congestion charge for each hour is equal to the difference in the
hourly locational based marginal pricing ("LBMP") between the point of
receipt and the point of delivery within New York State. The charge for
losses is the incremental cost of the losses incurred between the point of
receipt and the point of delivery.
30. I have modeled a 2.5 percent loss on all transmission wheels between
control areas.
31. Under NYPP congestion pricing rules, the only upstate capacity that is
economic in NY-ETE is the capacity that is in the market at the LBMP in the
upstate region. My analysis prorates transmission to all capacity that is
economic at the market price in the downstate region, which is higher
during times when the constraint is binding. This could not be avoided;
under Appendix A procedures, the upstate LBMP is not observable. The
impact of this simplification is to distort modestly the relative shares of
upstate generators, in a non-systematic fashion. However, it will not
affect Con Edison's share, since Con Edison's capacity is within NY-ETE and
the total amount of import into the region is not affected by the existence
of congestion charges. Since congestion charges will generally not exist
except when the transmission capability is fully utilized, the analysis
results in the appropriate market size and hence an appropriate Con Edison
share. Similarly, the use of a 2.5 percent loss factor, instead of an
incremental loss factor that may be higher, may allow some capacity with
delivered costs in excess of 105 percent of the NY-ETE price to share in
the allocation of the interface, but will not change the total amount of
imports used in calculating market concentration. There is far more
economic capacity that can reach the key interfaces than the amount that
can pass through them, so this simplification cannot have a material effect
on the analysis.
32. If the license plate charge is, for example, $3 per MWh and is paid
irrespective of the location of generation, then all power would have a $3
higher delivered price. Since relative prices among generation sources and
relative to the price used to define what capacity is economic will be
unaffected, leaving out the uniform delivery charge does not affect the
analysis.
33. A small number of generating units are not directly connected to PTFs
and are subject to a non-pool transmission charge assessed by the distribution
utility. I have not explicitly taken these into account, but since the units
subject to such charges represent a small fraction of NEPOOL
capacity, the effect of that omission is likely to be inconsequential.
34. NYISO, (last modified Dec. 1, 1999)
.
35. H.Q. Energy Services (U.S.) Inc., Docket No. ER97-851-000.
36. Con Edison (and possibly the other utilities) have placed all non-contract
related grandfathered TCCs, including those to move power through the service
territory, into the ISO's TCC auction. If Con Edison's merchant
function wanted the TCCs, it would have to bid on them in the auction.
37. Revenue from the sale of these TCCs is also credited against the TSC.
38. I have applied this approach notwithstanding the fact that Con Edison will
not have significant economic capacity to utilize all this transmission
reservation, especially if it sells its interest in Indian Point 2.
39. A review of the posted ATC from PJM into western NYPP seems to indicate
that EME has not exercised its transmission rights. By reducing the ATC to
reflect the potential exercise of the rights, I conservatively overstate
EME's share in western NYPP and understate the opportunity of other
generation owners to compete in NYPP and NEPOOL.
40. In some instances a utility that had reported detailed load in 1997 did
not do so in 1998. In these cases, I use the 1997 data, adjusted for load
growth.
41. NU reports in Form 714 only an aggregate load for its 4 utilities. NU
supplied me with the constituent loads for CL&P, WMECO, HWP and PSNH.
42. HWP is not now in the process of deregulation, owing to its small size.
NU has indicated that it will continue in its current structure through the
relevant time period.
43. The CASm model also allows power to flow from NU to the City through Long
Island, but the interfaces from NEPOOL to Long Island and from Long Island to
the City are even more constrained than the main path through
Westchester County.
44. The one exception is the NY-ETE market in shoulder off-peak periods, where
the HHI change is 64.
45. The energy portion of O&R's buy-back contract with Southern Energy, Inc.
expires on April 30, 2000, and so I did not include it in my analysis of
either 2000 or 2001.
46. Aggregating affiliated companies is mandated by Order No. 592. While the
Order likely did not consider the propriety of aggregating regulated
utilities and merchant functions, this aggregation remains appropriate even
if some of the affiliated generation is not dedicated to serving native
load. In NU's case, Select Energy must serve its POLR load at pre-
determined prices. Moreover the generation controlled by its merchant
affiliate, NGC, is dedicated to the Select Energy load. Even if it were
not, when NU as a corporation is a net buyer in NEPOOL, it has no incentive
to increase prices since the profit impact of the higher price received for
the energy that it sells at the market price is more than offset by the
higher cost that it must pay to meet its POLR responsibility.
47. An alternative would have been to allow Con Edison's NEPOOL capacity to
offset part of its Available Economic Capacity deficit in New York. As
shown below, Con Edison has insufficient controlled resources to meet its
POLR responsibilities in New York. Thus, had I allowed its New England
resources to be made available in New York, Con Edison would have had no
Available Economic Capacity and the absence of a merger-related increase in
HHI would have been a foregone conclusion.
48. This treatment cannot mask a merger-related Available Economic Capacity
screen failure. If NU has Available Economic Capacity in a time period,
this treatment properly shows the effect of a merger between two market
participants. If it does not have Available Economic Capacity, the screen
cannot be failed irrespective of how Con Edison's capacity is treated
49. AEC in NEPOOL must be "squeezed" by transmission limits between NEPOOL
and NYPP and again by limits within NYPP and between NYPP and PJM. Moreover,
any AEC that Con Edison could import from its subsidiary that owns capacity
in NEPOOL, CEEI, into NYPP would be insufficient to meet its net negative
AEC in NYPP. Consequently, Con Edison's share of AEC in NYPP or any
submarket of NYPP is identically zero, and so the change in the HHI
following the merger must also be zero. This same logic applies to the PJM
market.
50. Feasibility Study for In-City Electric Generation, Stone & Webster,
April 22, 1998, page 2.
51. Con Edison retains real-time control of some transmission facilities
within New York City necessary for system regulation.
52. Throughout this discussion on vertical market issues, I have assumed
that NU's reacquisition of Yankee Energy Systems will have been completed
prior to the proposed merger.
53. Transportation Corporations Law, Section 12. (Connecticut General
Statutes, Section 16-20.)
54. New York Public Service Law, Section 65.
55. Order in Docket No. EC-97-12-001 et al. (Enova-Pacific Enterprises).
56. Part 33 NOPR.
57. Con Edison has maximum daily storage injection rights of 116 Mdt/d and
withdrawal rights of 241 Mdt/d in a market area with daily gas delivery
capacity of approximately 6,000 Mdt/d. NU via YES has maximum daily storage
injection rights of 33.968 Mdt/d and withdrawal rights of 65.867 Mdt/d in a
market area (New England) with daily gas delivery capability of
approximately 2,942 Mdt/d. (See discussion of long-haul gas transportation
below)
58. This criterion would not be met in the instance of a requested change in
delivery point from Camden or Philadelphia to Manhattan, thereby excluding
southern New Jersey and metropolitan Philadelphia.
59. According to James Tobin of the Department of Energy's Energy Information
Agency, the MNP is filled and ready to operate, pending final negotiations with
certain Native American tribes. Consequently, I have included MNP in my
analysis.
60. As noted above, I am considering the Yankee Energy System to have already
been acquired by NU.
61. Applicant market power in, or indeed concentration in, an upstream market
that is not relevant to supply conditions in the area in which Applicants own
generation would lack a vertical nexus to their market power in electricity
markets.
62. This system consists of numerous gas storage fields, which are connected
to the major gas transmission facilities in the region. An INGAA survey
identified 477.3 billion cubic feet of working gas storage capacity in the
Mid-Atlantic region (New Jersey, New York and Pennsylvania). These storage
facilities essentially maintain pressure throughout the gas transmission
network during periods of high demand. (Foster Associates, Inc., Profile of
Underground Natural Gas Storage Facilities and Market Hubs, prepared for
the Interstate Natural Gas Association of America (INGAA) Foundation, Inc.,
1995, Figure 3.)
63. Like most LDCs, Applicants operate peak shaving facilities within their
service territories, designed to manage sudden weather-related swings in
firm customer demand within each Applicant's distribution system. O&R
operates three small air-propane facilities on its system; Con Edison
operates an LNG facility in Astoria; Yankee has 5 on-site propane plants
containing a capacity of 57,515 MMBtu/d. Inasmuch as they are operated to
maintain operating integrity within the confines of the low-pressure
distribution system, however, gas production from these local peak shaving
facilities does not participate in the broader regional peaking supply
markets. These facilities, with their low operating pressures, are
physically isolated from the high-pressure regional gas storage system,
providing service and contract capacity to LDCs and gas consumers
throughout New Jersey, New York and Pennsylvania.
64. Proceeding on Motion of the Commission to Review the Bypass Policy
Relating to the Pricing of Gas Transportation for Electric Generation,
Case 98-G-0122, Memorandum Order, issued and effective November 2, 1999.
65. Indeed, the Commission also has found that even transmission pipeline
ownership does not confer any meaningful control over generation. In the
Attachment to the Dominion-CNG Order, the Commission stated that
"Applicants have no operational control over generation owned exclusively
by others, pre- or post-merger, regardless of the fuel supply
arrangements."
66. For example, to reach NY-ETE, Montville 5 would have to traverse the
constrained Total East interface in competition with tens of thousands of
MW of supply in New England and western New York, and its share of the
market would be infinitesimal.
67. As an LDC, Con Edison will have access to information concerning the daily
nominations of its electric generation customers. Yankee Energy has an
insufficient generation customer base to be of even theoretical competitive
significance.
68. Case 95-G-1037, Recommendation by the Gas & Water Division, April 4, 1996,
p. 7.
69. Opinion No. 94-26 (issued December 20, 1994), p.45 as quoted in Order
Instituting Proceeding and Technical Conference, Case 98-G-0122 Proceeding
on Motion of the Commission to Review the Bypass Policy Relating to the
Pricing of Gas Transportation for Generation, pp.2-3.
70. Order Instituting Proceeding and Technical Conference, Case 8-G-0122,
op. cit. p. 3.
71. Proceeding on Motion of the Commission to Review the Bypass Policy
Relating to the Pricing of Gas Transportation for Electric Generation, Case
98-G-0122, Memorandum Order, issued and effective November 2, 1999.
72. O&R's tariff allows interruptible customer curtailment according to a
prioritization based on revenue contribution. The principle is, however,
the same: curtailment priorities are not discretionary.
Exhibit d.2
STATE OF CONNECTICUT
DEPARTMENT OF PUBLIC UTILITY CONTROL
JOINT APPLICATION OF :
CONSOLIDATED EDISON, : DOCKET NO. 00-01-11
INC. AND NORTHEAST :
UTILITIES FOR APPROVAL :
OF A CHANGE OF CONTROL : JANUARY 12, 2000
JOINT APPLICATION
FOR
APPROVAL OF A CHANGE OF CONTROL
For Consolidated Edison, Inc. For Northeast Utilities
John D. McMahon Cheryl W. Grise
Edwin W. Scott Daniel P. Venora
Consolidated Edison Company of Kenneth H. Eagle
New York, Inc. Northeast Utilities
4 Irving Place 107 Selden Street
New York, NY 10003 Berlin, CT 06037
Tel. (212) 460-6330 Tel. (860) 665-3416
Fax: (212) 677-5850 Fax: (860) 665-5504
Robert P. Knickerbocker, Jr.
Day, Berry & Howard LLP
City Place I
Hartford, CT 06103-3499
Tel. (860) 275-0122
Fax: (860) 275-0343
TABLE OF CONTENTS
PAGE
I. EXECUTIVE SUMMARY
II. ORGANIZATION OF APPLICATION
III. THE APPLICANTS
A. CEI
1. CEI's Regulated Utility Subsidiaries
a. CECONY
b. O&R and its Subsidiaries
2. CEI's Non-Regulated Subsidiaries
3. Electric Industry Restructuring in New York State and CEI's Divestiture
of Generating Assets
B. Northeast Utilities
1. NU System Electric Utility Operating Companies
2. NU System Gas LDC Operations
3. NU System Support Subsidiaries
4. NU System Non-Regulated Subsidiaries
IV. REASONS FOR THE MERGER
A. NU's Reasons for the Merger
B. CEI's Reasons for the Merger
C. Benefits of the Merger
V. DESCRIPTION OF THE PROPOSED MERGER
A. Mechanics of the Proposed Merger
B. Post-Merger Organization and Operations
C. Effect of Merger on the Department's Ability to Regulate NU's
Public Service Company Subsidiaries
D. Other Regulatory Approvals Required
E. Accounting Issues
VI. THE MERGER SATISFIES THE REQUIREMENTS OF CONN. GEN. STAT. Section 16-47
A. CEI is Financially Suitable to Exercise Control of CL&P and Yankee Gas
B. CEI is Managerially and Technologically Suitable to Exercise Control of
CL&P and Yankee Gas
C. The Ability of CL&P and Yankee Gas to Provide Safe, Adequate and Reliable
Service Will Be Enhanced by the Proposed Merger
VII. COMPLIANCE WITH THE DEPARTMENT'S REGULATIONS
A. Compliance With Section 16-1-46 of the Department's Regulations
Section 16-1-46(a) Statement of Application
B. Compliance with Section 16-1-65 of the Department's Regulations
C. Compliance With Section 16-1-65B of the Department's Regulations
D. Compliance With Section 16-1-61 of the Department's Regulations
(Conn. Gen. Stat. Section 16-43)
E. List of Exhibits
F. Statutory Bond Requirement
VIII. CONCLUSION AND REQUEST FOR APPROVAL
II. EXECUTIVE SUMMARY
Northeast Utilities ("NU") and Consolidated Edison, Inc. ("CEI")
(collectively the "Applicants") jointly submit this application for approval
by the Department of Public Utility Control (the "Department"), pursuant to
Conn. Gen. Stat. Section 16-47, of a proposed transaction between them (the
"Merger") through which NU would become a wholly-owned subsidiary of a newly
formed public utility holding company (referred to hereafter as "New CEI").
New CEI's outstanding shares of common stock will be wholly-owned by the
holders of CEI and NU common shares. Pursuant to Section 16-47(d), NU and
CEI will demonstrate: (i) that New CEI has the requisite financial,
technological and managerial suitability to become an additional holding
company for The Connecticut Light and Power Company ("CL&P"), NU's electric
utility subsidiary, and Yankee Gas Services Company ("Yankee Gas"), which
will become NU's natural gas local distribution company ("LDC") subsidiary
upon closing of the proposed merger between NU and Yankee Energy, which is
expected during the first quarter of this year; and (ii) that the Merger will
not impair the ability of CL&P or Yankee Gas to provide safe, adequate and
reliable service to their customers.
The Department is familiar with NU and its regulated and unregulated
subsidiaries. Although NU is the largest electric utility in New England,
the rapidly changing electric and natural gas industry requires NU to
consider its competitive position as measured against competitors whose
operations and vision are focused on national and even international markets.
NU has responded to the changes in its market and its new and stronger
competitors by implementing a strategic plan that in combination with CEI
will enable it to become a premier regional energy and energy services
provider, concentrating on its core regulated electric and gas business and
on its non-utility energy marketing, services and generation businesses.
NU's ability to compete effectively in these core regulated and unregulated
energy businesses requires that it diversify and enhance both the scale of
its operations and the scope of its customer base. NU's acquisition of
Yankee Energy System, Inc. ("YES"), approved by the Department on December
29, 1999 is in furtherance of NU's strategic plan. NU's merger with CEI is
another significant step in implementing that plan.
CEI is a financially successful electric and gas utility holding company
that is, by several measures, about twice the size of NU. CEI, through its
regulated utility subsidiaries, serves New York City, Westchester County and
southern New York State, northern New Jersey and northeastern Pennsylvania
and is one of the nation's largest investor-owned energy companies, with more
than $7 billion in annual revenues and $14 billion of assets. It also is one
of the ten largest gas distribution companies in the United States, and
produces and distributes steam to nearly 2,000 customers in New York City.
CEI is not only larger than NU, but also enjoys stronger financial
indicators, including credit ratings, capital structure, growth in earnings
and dividends and market performance. CEI enjoys excellent management, and
operates the most reliable electric distribution system, with fewer power
outages per customer than any other electric utility in the nation. CEI has
contributed to the recent, vibrant growth in New York's economy. It is an
aggressive advocate for retail choice and has divested most of its in-City
generating facilities, except those supporting its steam system and Indian
Point Unit 2 (CEI recently announced it was exploring alternatives to the
continued ownership and operation of Indian Point 2). It has developed
opportunities for growth in the new energy markets through non-utility
businesses. CEI readily meets the financial, technological and managerial
suitability tests to become a holding company for CL&P and Yankee Gas under
Section 16-47.
The second prong of Section 16-47 also is satisfied. Placing CEI in the
position of a holding company for CL&P and Yankee Gas will not impair their
ability to continue to provide safe, adequate and reliable service to their
customers. In a recent industry survey, CEI's electric system was found to
be nearly thirteen times more reliable than the median U.S. utility. Its gas
business is one of the ten largest in the nation, and has been well-
recognized for its accomplishments, including technological innovation and
research and development efforts designed to enhance safety, as will be
discussed later in this application. CEI's corporate goals include
maintaining unparalleled reliability, providing outstanding customer service,
continuing its leadership in developing energy markets, protecting the
environment and the health and safety of its employees, contributing to the
economic growth of its service territories and generating strong earnings
through productivity gains and growth. These attributes of CEI are entirely
consistent with maintaining (and enhancing) the service levels that the
Department demands from Connecticut utilities, including CL&P and Yankee Gas.
Merging NU's and CEI's electric and gas operations will result in the
largest combination electric and gas distribution company in the country,
with approximately 5 million customers and serving 13 million people living
in an area stretching from northern Pennsylvania through New York and New
England to the Canadian border. The Merger will combine NU's experience in
New England energy markets with the many enhanced resources of CEI, enabling
the combined company to compete effectively with the large national and
international players in the Northeast energy markets. NU and CEI believe
that the Merger will enable the combined company to successfully implement
its long-term goals through its increased customer base (economies of scale),
its enhanced financial resources, its expanded geographic reach (economies of
scope) and the combined managerial and employee talent necessary to compete
effectively.
As described more fully in this application, the Merger also provides
many other benefits to NU's customers, employees and shareholders --
including an improved ability to weather regional economic changes, to create
new opportunities for growth, to reduce costs through greater purchasing
power and economies of scale, and the potential to realize significant long-
term cost savings generated by merger-related growth and synergies. Absent
the Merger, these benefits would not be available to NU, its customers,
employees or shareholders.
As the Department is aware from many of its recent dockets, the energy
industry is undergoing radical and dramatic changes. Combinations of energy
providers are a fact of life in today's environment. There are no longer any
remaining significant independent gas LDCs in New England. The region's
largest gas LDC holding company, Eastern Enterprises, is being acquired by
KeySpan Energy, creating the largest LDC in the nation with 2.4 million
customers. On the electric side, the newly-created NSTAR now combines the
operations of Boston Edison, Commonwealth Electric Company, Cambridge
Electric Light Company and Commonwealth Gas, with 1.3 million customers. The
New England Electric System and Eastern Utilities Associates are merging,
creating a company with 1.6 million customers, and New England Electric
System will be acquired by National Grid Group plc. Energy East is acquiring
Central Maine Power Company, Connecticut Energy Corp. and CTG Resources, Inc.
Following the completion of these mergers, Energy East will have 1.3 million
electric customers and more than 500,000 natural gas customers.
Unregulated affiliates of such industry giants as Southern Company,
Sempra Energy, Duke Energy, FPL Group, Reliant Energy, and Enron are
competing in the generation or marketing of energy in New England. These
companies are strong national competitors, with an international presence.
While NU could once say that it was the largest utility in New England, it
certainly is not the largest utility in today's New England marketplace.
After NU's announced nuclear divestitures take place, it will hold only a
fraction of its once extensive generating facilities through its unregulated
affiliate, Northeast Generation Company.
For a company in NU's position, growth in this new environment can only
be achieved through the acquisition by NU of other companies, or a merger of
NU with another large partner. In order to prosper in this marketplace, NU
needs to achieve greater economies of scale and scope. Those greater
economies will strengthen CL&P and Yankee Gas. The Merger with CEI provides
NU with a unique opportunity to shape its own destiny with the best possible
merger partner.
CEI is a large and financially strong energy company with an adjacent,
interconnected service territory and a vision, business focus and philosophy
that are consistent with those of NU. This combination also provides a
unique opportunity for the customers, employees and shareholders of NU and
CEI to share in the benefits of a larger and more competitive multi-product
energy services provider in the rapidly evolving, nationally-focused energy
market.(FN 1)
Perhaps most importantly, CL&P's and Yankee Gas' strong presence in and
commitment to Connecticut will in no way diminish as a result of the Merger.
NU and its subsidiaries will continue to be located in, and managed on a day-
to-day basis from, the Connecticut communities they currently serve. NU will
continue to have a major presence in Berlin. The headquarters and primary
field offices of its public service company subsidiaries, CL&P and Yankee
Gas, will remain in Connecticut. Michael G. Morris, who will become
President of the combined company, will continue to be actively involved in
the management of NU and its operating utility subsidiaries. NU and CEI will
seek to retain key management of NU's operating companies, so that the
important role that these individuals play in Connecticut's communities will
not diminish. Thus, NU's Connecticut companies will remain, as they have
been for the past 100 years, firmly anchored to Connecticut.
For all of these reasons, described more fully below and in the
supporting testimony and documentation filed with this application, NU and
CEI jointly request that the Department approve the Merger pursuant to Conn.
Gen. Stat. Section 16-47, and such other statutes and related regulations, if
any, that the Department deems applicable.(FN 2) NU and CEI also
respectfully request that the Department consider this application
expeditiously, and act favorably on it prior to June 1, 2000, in order
that the Merger can become effective in July 2000.
III. ORGANIZATION OF APPLICATION
Section III of this application will introduce CEI to the Department and
describe the restructuring of the electric industry in New York State, the
dominant jurisdiction in which CEI's utility subsidiaries operate. Section
III will also describe NU and its regulated and non-regulated subsidiaries.
Section IV of this application will describe the proposed Merger itself.
That section includes a discussion of the transaction, the resulting
corporate structure and organization of the combined company and of NU within
that structure, the effect of the Merger on the Department's ability to
regulate NU's jurisdictional public service company subsidiaries, other
regulatory approvals that are required to complete the Merger and certain
accounting and ratemaking issues.
Section V will explain why NU and CEI decided to merge. Section VI will
demonstrate that the Merger satisfies the requirements of Conn. Gen. Stat.
Section 16-47. Section VII includes the detailed information required by
Sections 16-1-61, 16-1-65 and 16-1-65B of the Department's regulations.
For the reasons set forth more fully herein, all criteria for approval of
the Merger under Conn. Gen. Stat. Section 16-47 have been met and the
Department should approve the Merger.
IV. THE APPLICANTS
A. CEI
The legal name and principal place of business of CEI is:
Consolidated Edison, Inc.
4 Irving Place
New York, New York 10003
CEI, incorporated in New York in 1997, is the public utility holding company
for Consolidated Edison Company of New York, Inc. ("CECONY") and Orange and
Rockland Utilities, Inc. ("O&R"), both of which are regulated utilities.
CECONY and O&R, which are described more fully below, serve 3.2 million
electric customers in New York, New Jersey and Pennsylvania and 1.1 million
gas customers in New York and Pennsylvania. CECONY also serves approximately
2,000 steam customers in Manhattan. The franchise territory of CEI's
subsidiaries is shown in Exhibit 16.
CEI also has four non-utility subsidiaries which provide electric and
gas supply services, invest in energy infrastructure projects, market
technical services and develop and manage infrastructure for a communications
business. CEI's present corporate structure is illustrated in Exhibit 8 to
this application. CEI has no employees and no significant business
operations other than through its regulated and non-regulated subsidiaries.
For the 12 months ending September 30, 1999, CEI had approximately
$7.2 billion in consolidated operating revenues.
1. CEI's Regulated Utility Subsidiaries
a. CECONY
CECONY, incorporated in New York State in 1884, provides electric
service to over 3 million customers and gas service to over one million
customers in New York City and Westchester County, as well as steam service
to parts of New York City. CECONY's principal place of business is in New
York City and it has approximately 14,200 employees. CECONY is regulated by
the New York State Public Service Commission ("NYPSC").
For 1998, which was prior to the closing of CEI's acquisition of O&R,
substantially all of CEI's operating revenues, operating income, net income
and total assets were those of CECONY. CECONY's 1998 operating revenues were
approximately $7.0 billion, of which $5.0 billion (81.7 percent) were
electric operating revenues, $1.0 billion (13.7 percent) were gas operating
revenues and $322 million (4.6 percent) were steam operating revenues. In
1998, CECONY had $5.7 billion in electric sales, of which 36.5 percent was to
residential customers, 62 percent was to commercial and industrial customers
and the balance to railroads and public authorities.
As of December 31, 1998, CECONY's electric transmission system had
approximately 432 miles of overhead circuits operating at 138, 230, 345 and
500 kV; approximately 381 miles of underground circuits operating at 138 and
345 kV; 267 miles of radial subtransmission circuits operating at 138 kV; and
14 transmission substations supplied by circuits operated at 69 kV and above
with a total transformer capacity of 15,731 megavolt amperes. CECONY has
transmission interconnections with Niagara Mohawk, Central Hudson, O&R, New
York State Electric and Gas Corporation, CL&P, Long Island Lighting Company,
the New York Power Authority and Public Service Electric and Gas Company.
These transmission facilities are located in New York City and Westchester,
Orange, Rockland, Putnam and Dutchess counties in New York State. CECONY's
electric distribution system includes 290 distribution substations in New
York City and Westchester County, New York, with a transformer capacity of
20,168 megavolt amperes, 32,429 miles of overhead distribution lines and
87,910 miles of underground distribution lines.
At the beginning of 2000, CECONY will have approximately 1,500 MW of
capacity it owns and operates, 462 MW of entitlements to jointly owned units,
2,090 MW of non-utility generation ("NUG") contracts and 550 MW of other
contracts. The owned capacity includes the 931 MW Indian Point 2 ("IP2")
nuclear generating station located in Westchester County. In December 1999,
CECONY announced that it was pursuing operating and ownership for IP2. The
balance of CECONY's owned capacity includes approximately 460 MW that produce
both electricity and steam for its steam distribution system in Manhattan and
some small combustion turbines located in various facilities in New York
City. CECONY has agreed in principle to sell its share of the Roseton
Generating Station, which it jointly owns with Niagara Mohawk Power Company
and Central Hudson Gas and Electric Corporation ("CHG&E"), as part of CHG&E's
divestiture, which is required to be completed by June 2001. This sale will
reduce CECONY's capacity, including NUGs, by 462 MW to 4,149 MW.
CECONY's natural gas distribution system includes approximately 4,200
miles of mains and 362,300 service lines. CECONY owns a natural gas
liquefaction facility and storage tank at its Astoria property in Queens.
This plant can store approximately 1,000 mdth, of which a maximum of about
250 mdth can be withdrawn per day. CECONY has an additional 1,230 mdth of
additional natural gas storage capacity at a field in upstate New York owned
and operated by Honeoye Storage Corporation, in which CECONY has a 28.8
percent ownership interest.
CECONY also generates steam for distribution at three steam/electric
generating stations and five steam-only generating stations. Steam is
distributed to customers through approximately 86 miles of mains and 18 miles
of pipelines. (FN 3)
b. O&R and its Subsidiaries
In July 1999 CEI completed its acquisition of O&R for $791.5 million in
cash. As a wholly-owned utility subsidiary of CEI, O&R, along with its two
utility subsidiaries, Rockland Electric Company ("RECO") and Pike County
Light and Power Company ("Pike"), provides electric service to 274,000
customers and natural gas service to 117,000 customers in southeastern New
York State and adjacent sections of New Jersey and Pennsylvania. O&R's,
RECO's and Pike's service territories cover approximately 1,350 square miles,
extending along the west bank of the Hudson River, directly across from
CECONY's service territory, as illustrated in Exhibit 16.
O&R, a New York corporation with its principal office in Pearl River,
New York, has been providing electric and gas service in New York State for
approximately 100 years. In 1998, O&R had operating revenues of approximately
$626 million, of which approximately $490 million (78.2 percent) were
electric operating revenues and $136 million (21.7 percent) were gas
operating revenues. O&R has approximately 1,000 employees.
O&R owns and operates 617 circuit miles of transmission lines, 78
substations, 84,509 in-service line transformers, 4,967 pole miles of
overhead distribution lines, and 2,271 miles of underground distribution
lines. O&R's gas operations include three propane air gas plants, which have
a combined capacity of 30,600 Mcf per day natural gas equivalent. The gas
distribution system includes 1,758 miles of mains.
O&R is regulated by the NYPSC, RECO is regulated by the New Jersey Board
of Public Utilities ("NJBPU") and Pike is regulated by the Pennsylvania
Public Utility Commission ("PaPUC"). RECO has two wholly-owned non-utility
subsidiaries, which in turn have subsidiaries engaged in the energy service
and real estate businesses. (FN 4)
O&R also has three wholly-owned non-utility subsidiaries: Clove
Development Corporation ("Clove"), a New York corporation, and O&R Energy
Development, Inc. and O&R Development, Inc., both Delaware corporations.
Clove holds approximately 5,200 acres of real estate, located primarily in
the Mongaup Valley region of Sullivan County, New York. O&R Development,
Inc., which was formed to promote industrial and corporate development in
O&R's service territory by providing improved sites and buildings, owns
approximately 200 acres of land, which are being marketed for sale. O&R
Energy Development, Inc. is currently inactive.
2. CEI's Non-Regulated Subsidiaries
CEI currently has four wholly-owned, non-utility, non-regulated
subsidiaries: Consolidated Edison Solutions, Inc. ("CES"), Consolidated
Edison Development, Inc. ("CED"), Consolidated Edison Energy, Inc. ("CEE")
and Consolidated Edison Communications, Inc. ("CECI").
CES is an energy service company providing competitive gas and electric
supply and energy-related products and services. CES has an interest in
Inventory Management & Distribution Company, Inc. ("IMD"), an energy
marketing firm, and in Remote Source Lighting International, Inc. ("RSLI"), a
lighting technology company.
CED invests in energy infrastructure projects and markets CECONY's
technical services. CED has invested in electric generating plants in
California, Michigan, Guatemala and the Netherlands. (FN 5)
Another wholly-owned CEI subsidiary, CEE, markets specialized energy
supply services to wholesale customers in the Northeast and Mid-Atlantic
states. In July 1999, CEE, through its subsidiary Consolidated Edison Energy
Massachusetts, Inc., purchased from Western Massachusetts Electric Company
290 MW of electric generating capacity, which it currently owns and operates.
The remaining wholly-owned CEI subsidiary, CECI, was formed to explore
opportunities to build a communications business by leveraging CECONY's
expertise in building and managing infrastructure, including fiber optic
cable. On November 23, 1999, CECI executed an agreement to purchase 10.75
percent of the common stock, on a fully-diluted basis, of NorthEast Optic
Network, Inc. ("NEON"), a Westborough, Massachusetts-based provider of
broadband telecommunications services in New England and New York State. NU
owns approximately 30 percent of NEON.
3. Electric Industry Restructuring in New York State and CEI's
Divestiture of Generating Assets
As further background for the Department regarding CEI, and for the
Department's convenience, NU and CEI have included in this section a summary
of the restructuring of the electric industry in New York State, and CEI's
activities related to orders issued by the NYPSC with respect to
restructuring.
In the context of its electric industry restructuring process, the NYPSC
directed CEI (and four other electric utilities) to submit rate and
restructuring plans consistent with the NYPSC's policy and vision for
increased competition. (FN 6) These plans were to address, at a minimum: (1)
the structure of the utility, both in the short and long term, including a
description of how that structure complies with the NYPSC's vision and goals
for a future electric regulatory environment, and in cases where divestiture
is not proposed, effective mechanisms that adequately address resulting
market power concerns; (2) a schedule for the introduction of retail access
to all of the utility's customers, and a set of unbundled tariffs that is
consistent with the retail access program; (3) a rate plan to be effective
for a significant portion of the transition; and (4) numerous other issues
relating to strandable costs, load pockets, energy services and public policy
costs.
In response to the NYPSC's directive, CECONY submitted its proposed
plan, which was ultimately approved by the NYPSC in September 1997, as a
settlement agreement among CECONY, the Staff of the NYPSC and other parties
(the "Settlement Agreement"). The Settlement Agreement provides for: (1) a
transition to a competitive electric market through the implementation of a
retail access plan, (2) a rate plan providing for retail rate reductions
through March 31, 2002, (3) a reasonable opportunity to recover costs in
excess of market value, and (4) the divestiture by CECONY to unaffiliated
third parties of at least 50 percent of its New York City fossil-fueled
electric generating capacity.
Under the Settlement Agreement, CECONY submitted a divestiture plan for
its fossil-fueled electric generation in New York City, which was approved by
the NYPSC in orders issued July 21 and August 5, 1998. As the divestiture
plan requires, CECONY has divested its New York City electric generation,
except for approximately 460 MWs that is used to support its steam system,
to unaffiliated third parties. In June and August of 1999, CECONY completed
the sales of all of its electric only fossil plants, approximately 6,300 MW
of its approximately 8,300 MW of electric generating assets for an aggregate
price of approximately $1.8 billion. The proceeds from these sales were used
to purchase O&R, repay commercial paper and continue CEI's common stock
repurchase program.
In addition, CECONY has agreed to divest its 462 MW interest in the
Roseton station located in CHG&E's service area in conjunction with CHG&E's
divestiture auction.
In April 1999, CECONY announced that the East River Generating Station
would not be auctioned off but rather CECONY proposed to have the New York
State Board on Electric Generation Siting and the Environment ("Board")
approve the repowering of the plant to serve the steam and electric systems.
CECONY has commenced the formal regulatory process under which an application
for repowering will be submitted to the Board for approval.
As a result of the divestiture program described above, CECONY will no
longer own dispatchable generation resources, though it currently retains its
interest in the IP2 nuclear generating facility. CECONY will, however,
retain a load serving obligation which it will meet through capacity and
energy purchases in the competitive market.
As with CECONY, O&R filed a plan to divest all of its electric
generation facilities, which was approved by the NYPSC in orders issued on
April 16 and May 26, 1998. In accordance with the O&R divestiture plan, O&R
sold all of its electric generating facilities to Southern Energy, Inc., a
subsidiary of The Southern Company on November 24, 1998, including CECONY's
two-thirds interest in the Bowline Point Station, which was operated by O&R.
B. Northeast Utilities
The legal name and principal place of business of NU is:
Northeast Utilities
174 Brush Hill Avenue
West Springfield, MA
01090-2010
NU, a Massachusetts business trust headquartered in Berlin, Connecticut,
is the parent company of the Northeast Utilities system (the "NU System") and
a registered holding company under the Public Utility Holding Company Act of
1935 ("PUHCA"). The NU System currently serves approximately 30 percent of
New England's electric needs, with approximately 1.7 million utility
customers, and is one of the 24 largest electric utility systems in the
country as measured by revenues.
As the result of the Department's recent approval of NU's acquisition of
YES, a holding company with both regulated and non-regulated energy and
energy services subsidiaries, the NU System utility company operations will
expand to include the gas distribution business of Yankee Gas, YES's
regulated gas utility subsidiary. (FN 7) On a pro forma basis, giving effect
to that transaction, the combined company would serve approximately 1.9 million
utility customers (14 percent of which would be gas utility customers), with
combined assets of approximately $11 billion as of March 31, 1999 and
approximately $4.06 billion in combined operating revenues for the year ended
December 31, 1998.
NU is not itself an operating company or a public service company. As
of March 31, 1999, NU had total assets of $10.4 billion, with operating
revenues of $3.77 billion for the year ended December 31, 1998. As of June
30, 1999, NU System companies had 9,034 full and part-time employees. That
number will increase with the addition of the approximately 830 employees of
the YES System companies.
1. NU System Electric Utility Operating Companies
The NU System has traditionally furnished franchised retail electric
service in Connecticut, New Hampshire and western Massachusetts through NU's
wholly-owned operating company subsidiaries: CL&P, Public Service Company of
New Hampshire ("PSNH"), Western Massachusetts Electric Company ("WMECO") and
Holyoke Water Power Company ("HWP") (collectively, the "NU Electric Operating
Companies"). In addition to their retail electric service business, the NU
Electric Operating Companies (including HWP through its wholly-owned
subsidiary, Holyoke Power and Electric Company) also furnish wholesale
electric service to various municipalities and other utilities and
participate in limited retail access programs, providing off-system retail
service. North Atlantic Energy Corporation, which owns 36 percent of the
Seabrook nuclear generating plant, also can be considered a regulated
operating company for certain purposes.
2. NU System Gas LDC Operations
Yankee Gas, a Connecticut public service company subject to the
Department's jurisdiction and the principal subsidiary of YES, purchases,
distributes and sells natural gas to approximately 185,000 residential,
commercial and industrial users in Connecticut. The Yankee Gas service
territory consists of 69 Connecticut cities and towns, and covers
approximately 1,995 square miles (or approximately half of Connecticut's land
area), all within the service territory of CL&P. Yankee Gas owns
approximately 2,820 miles of distribution mains, 133,033 miles of service
lines, various propane facilities with a combined storage capacity equivalent
to approximately 245 million cubic feet ("Mcf"), and six gas storage holders.
All of these assets are located in Connecticut.
3. NU System Support Subsidiaries
Several wholly-owned subsidiaries of NU provide support services for the
NU System companies and, in some cases, for other New England utilities.
Northeast Utilities Service Company ("NUSCO") provides centralized
accounting, administrative, information resources, engineering, financial,
legal, regulatory, operational, planning, purchasing and other services to
the NU System companies. North Atlantic Energy Service Corporation has
operational responsibility for the Seabrook nuclear power plant. Northeast
Nuclear Energy Company acts as agent for the NU System companies and other
New England utilities in operating the Millstone nuclear generating
facilities. Rocky River Realty Company, The Quinnehtuk Company, and
Properties, Inc., build, acquire or lease some of the property and facilities
used by the NU System companies.
4. NU System Non-Regulated Subsidiaries
The NU System also includes a number of non-regulated subsidiaries.
These include: NU Enterprises, Inc., a direct subsidiary of NU, which acts as
a holding company for non-regulated businesses; Northeast Generation Company,
formed to acquire and manage generating facilities; Northeast Generation
Service Company, which provides operating and environmental services,
preventative maintenance and other services to generators and large
customers; and Select Energy, Inc., a retail energy services and power
marketing company.
Other non-regulated NU subsidiaries include: HEC, an energy engineering
and design firm serving energy and water utilities and large consumers; Mode
1 Communications, which owns approximately 30 percent of NEON, a fiber-optic
telecommunications carrier; and Select Energy Portland Pipeline, Inc., formed
to hold a 5 percent partnership interest in the Portland Natural Gas
Transmission System pipeline which has recently commenced operations in
northern New England.
Also to be included within the NU System are YES's non-utility
operations which are conducted through four YES subsidiaries: NorConn
Properties, Inc., which holds property such as the YES headquarters building
in Meriden and a Yankee Gas service building in East Windsor; Yankee Energy
Financial Services Company, which provides equipment and home improvement
financing to energy consumers and municipal utilities across the country;
Yankee Energy Services Company, which provides building automation services,
heating, ventilation and air-conditioning, boiler and refrigeration equipment
services and installation; and R. M. Services, Inc., created initially to
provide debt collection service to Yankee Gas, but now marketing its services
to other utilities and to Dun & Bradstreet Receivables Management Services,
and providing consumer collections services focused primarily on utility and
telecommunications entities.
V. REASONS FOR THE MERGER
A. NU's Reasons for the Merger
Based on its analysis of the prospects of utility deregulation, the
increasing competitive pressure faced by electric and gas utility companies,
and NU's position and ability to compete effectively and succeed in this new
environment, the NU Board of Trustees concluded that NU must have a larger
customer and geographic base with increased economies of scale and scope to
enable NU to remain a competitive and efficient supplier of energy and
related services. Beginning with the implementation of its strategic plan
for the future in May 1998, NU fully explored a number of potential
opportunities and means to attain its goals. The Board concluded that a
combination with CEI would result in the greatest overall value to
shareholders, customers and employees of NU and its subsidiaries. This
combination would join two well-managed companies with complementary and
contiguous operations and a shared vision of the future energy markets in the
Northeast, and which would have the scale and scope necessary to be
successful in the restructured energy market. Moreover, this particular
combination maximized NU's ability to shape its own destiny and accelerate
its growth in unregulated markets.
As part of the largest combination electric and gas distribution company
in the country, with a strong regional focus, NU will be positioned to be an
effective participant in the emerging and competitive energy markets. The
combined company will be substantially stronger financially than NU.
This particular combination is also expected to create a number of
potential synergies. One synergy arises from the fact that the service
territories of NU and CEI are contiguous and directly inter-tied,
facilitating NU's ability, as part of the combined company, to take advantage
of operating efficiencies, economies of scale and cross-selling
opportunities. The economies of scale created by the Merger will also
enhance NU's ability to implement state-of-the-art technology across its
operations, including maintenance and improvement of infrastructure, customer
service, research and development, call center operations, and information
technology. Consolidating with a larger partner, which has more favorable
financial indicators that permit financing these types of costs more
competitively, will allow NU to improve and expand service at a lower cost
than otherwise would have been achievable.
B. CEI's Reasons for the Merger
CEI, like NU, has also focused on its core energy business. Like NU, it
has pursued a strategy of growing this business in its service territory as
well as expansion in the Northeast region through mergers and acquisitions.
Most importantly, CEI is similarly situated to NU because its ability to
compete effectively and succeed in the new environment will be enhanced by an
increase in scale and scope.
The CEI Board of Directors concluded that the common vision of NU and
CEI, and their complementary strategies, in combination with their
management, personnel, technical expertise and depth of experience in their
respective markets, will create an energy company that is appropriately
positioned and has the capabilities and resources to succeed in the new
competitive energy marketplace.
C. Benefits of the Merger
NU and CEI anticipate that the Merger will have benefits for CL&P's and
Yankee Gas' customers and employees, as well as the State of Connecticut, and
that the Merger will be pro-competitive. Customers will enjoy the benefits
of having a stronger and more efficient company. The combined company will
be a region-wide integrated energy supplier with an enhanced ability to
provide better services more efficiently and at lower costs. Customers will
benefit from long-term synergy-related cost savings which would not be
available absent the Merger. These savings are presently expected to be
realized over time in areas such as reduced operating costs and expenditures
resulting from integration of corporate and administrative functions,
elimination of duplicative positions, reduction of duplicative capital
expenditures for administrative and customer service programs and information
systems, and savings in areas such as legal, audit and consulting fees.
Customers will also benefit over the long-term from the greater purchasing
power of the combined company for items such as fuel and transportation
services, general and operational goods and services. The economic benefits
achievable through the proposed Merger serve the public interest through
enabling energy suppliers to satisfy the needs of consumers more efficiently
and at a lower cost.
As part of the combined company, NU will be able to draw from an
expanded and more diverse pool of human resources to provide management,
engineering, technological and customer services. Because of the larger size
and greater financial strength of the combined company, NU and CEI will be
able to compete for talent more effectively than either could on its own.
The Merger also benefits Connecticut by creating a financially stronger
company that, through the use of the combined equity, management, human
resources and technical expertise of each company, will be able to achieve
greater financial stability and strength and greater opportunities for
earnings and dividend growth.
As a strategically positioned competitive energy supplier, the combined
company will be positioned to continue programs to attract new business
development in the NU service territory, thereby contributing to growth in
Connecticut's economy and providing additional opportunities to existing and
future employees. The combined company will also benefit NU employees and
the State of Connecticut with its enhanced ability to create and take
advantage of opportunities for expansion into related energy businesses and
to benefit from coordinated efforts in these areas. NU has a long history of
supporting Connecticut's charities and other volunteer organizations, and has
been a generous corporate citizen in both time and financial commitments.
These aspects of NU's community involvement will not change as the result of
the Merger.
The creation of a financially strong energy and energy services company
with a solid regionally-based foundation and the combined managerial,
technological, engineering and customer service expertise of the NU and CEI
companies will also enhance competition in Connecticut and the other markets
in which the combined company will operate.
VI. DESCRIPTION OF THE PROPOSED MERGER AND ITS EFFECTS
A. Mechanics of the Proposed Merger
The Merger will be consummated under an Agreement and Plan of Merger
dated as of October 13, 1999 by and between CEI and NU (the "Merger
Agreement"), a copy of which is attached hereto as Exhibit 1. The Merger
Agreement was approved by both the NU Board of Trustees and the CEI Board of
Directors in meetings on October 12, 1999.
Under the Merger Agreement, CEI will acquire NU for a base price of $25
per NU common share, subject to adjustments as described more fully below.
To effect the acquisition, CEI will merge into New CEI, a new parent holding
company incorporated in Delaware, formerly called CWB Holdings, Inc. A
subsidiary of New CEI, N Acquisition Corp., will then merge into NU, with NU
being the entity surviving that merger. As a result of these transactions,
NU will become a direct, wholly-owned subsidiary of New CEI, the parent of
the combined company. These two transactions collectively constitute the
Merger referred to in this application. The combined company will conduct
business under the name "Consolidated Edison, Inc."
Upon completion of the Merger, the former holders of CEI and NU common
shares will together own all of the outstanding shares of common stock of New
CEI. New CEI will in turn own all of the outstanding common shares of
CECONY, NU, O&R and CEI's non-utility subsidiaries. NU will continue to own
its regulated utilities. New CEI will register with the Securities and
Exchange Commission ("SEC") as a public utility holding company pursuant to
the PUHCA.
As the result of the Merger, each CEI shareholder will receive one share
of New CEI common stock for each CEI common share that he or she holds. NU
shareholders may elect to receive stock or cash consideration. Each NU
shareholder may elect to receive, for each NU common share, a fraction of a
share of New CEI common stock equal to a numerator of $25.00 divided by the
weighted average trading price of a CEI common share over 20 trading days
randomly selected from the 40 trading days ending five trading days prior to
the closing of the Merger. However, the CEI share price used to calculate
this fraction will not be less than $36.00 nor greater than $46.00. The
Merger Agreement further provides that $1.00 is to be added to the numerator
if, prior to the closing of the Merger, NU enters into binding agreements to
sell certain nuclear facilities which meet specific conditions set forth in
the Merger Agreement (the "Divestiture Condition"). In addition, $0.0034
will be added to the numerator for each day after August 5, 2000, should the
merger not have closed by then, through the day prior to the closing of the
Merger.
In the alternative, holders of NU common shares may elect to receive,
for each NU common share, cash consideration equal to $25.00 per NU common
share, provided that an additional $1.00 per share will be payable if, prior
to the closing of the Merger, NU satisfies the Divestiture Condition, and an
additional $0.0034 will be added to the numerator for each day after August
5, 2000 through the day prior to the closing of the Merger.
Elections by NU shareholders of stock or cash consideration will each be
subject to allocation and proration procedures. These procedures provide
that not more than 50 percent of the aggregate number of NU shares eligible
to receive Merger consideration will be converted into the right to receive
cash consideration, and not more than 50 percent of the aggregate number of
NU shares eligible to receive Merger consideration will be converted into
common stock of the combined company.
If the Merger closes on or prior to December 31, 2000, and the
Divestiture Condition has not been satisfied, but thereafter on or prior to
December 31, 2000 the Divestiture Condition is satisfied, then each NU
shareholder (whether the shareholder elected stock or cash consideration)
will be entitled to $1.00 per converted NU common share to be paid in cash by
New CEI.
The aggregate price to be paid to NU shareholders (including the value
of the stock consideration), which is estimated to be not more than $3.8
billion, will depend upon the adjustments described above and the number of
NU common shares outstanding at the completion of the Merger.
CEI and NU seek to complete the Merger in July 2000. In addition to
various regulatory filings and approvals, completion of the Merger requires,
among other things, the approval of at least a majority of the CEI shares
outstanding and entitled to vote and at least two-thirds of the NU shares
outstanding and entitled to vote.
B. Post-Merger Organization and Operations
Upon completion of the Merger, NU will become a wholly-owned subsidiary
of New CEI. NU will continue to be the parent of the regulated utilities in
New England.
The combined company will be headquartered in New York, but will have a
substantial Connecticut presence. CL&P and Yankee Gas will be headquartered
in Connecticut. The headquarters of the combined company's unregulated
businesses will be in Connecticut. As a regulated holding company under
PUHCA, certain services will be provided to New CEI's subsidiaries through a
service company similar to NUSCO. Although the details have not been
decided, it is expected that there will be substantial service company
operations in both Connecticut and New York. Eugene R. McGrath, CEI's
current chairman and CEO, will continue as Chairman and CEO of the combined
company. Michael G. Morris will become President of the combined company.
The combined company's Board of Directors will include four members from the
current NU Board of Trustees, including Mr. Morris. Many of the members of
the management teams of NU and YES are expected to have continuing roles in
the management of the combined company. This structure will preserve all the
benefits of localized management that each of the companies presently enjoy
while simultaneously allowing for the efficiencies and economies that will
derive from the Merger.
NU and CEI anticipate substantial merger savings in both the regulated
and unregulated businesses arising primarily from the elimination of
duplicate corporate and administrative programs and greater efficiencies in
operations and business processes, as well as increased purchasing
efficiencies. These savings have been preliminarily estimated to be $1.3
billion on a cumulative nominal basis over ten years. The savings are
discussed in the testimony of Hyman Schoenblum and John J. Roman.
Identification of the means by which the Merger efficiencies will be
developed, and any resultant impact on the workforce of the combined company,
have yet to be determined, and will be the subject of analysis by transition
teams established to look at these issues. The combined company commits to
minimize the impact of the Merger on the workforce through a combination of
programs including attrition, retraining, reduced hiring and other measures.
All union contracts will be honored. Existing benefits related to employee
compensation, benefit plans, fringe benefits, or benefits comparable thereto
will be maintained for a period of at least one year after the closing date
of the Merger.
C. Effect of Merger on the Department's Ability to Regulate NU's
Public Service Company Subsidiaries
The Merger will not impair the Department's ability to regulate CL&P or
Yankee Gas, both of which will continue to operate as public service
companies subject to the Department's jurisdiction as before completion of
the Merger, and in light of the recently approved NU/YES merger.
D. Other Regulatory Approvals Required
In addition to review and approval by the Department, completion of the
Merger requires the approval of or review by the SEC, the Federal Energy
Regulatory Commission ("FERC"), the Nuclear Regulatory Commission ("NRC"),
and filings or approvals of regulators in Maine, Massachusetts, New
Hampshire, New York, New Jersey, Pennsylvania and Vermont. In addition, the
minimum 30-day waiting period (and any extensions thereof) under the Hart-
Scott-Rodino Antitrust Improvements Act must have expired or been terminated.
Expeditious review and approval by the Department of this transaction will
facilitate completion of the regulatory approval process in some of the other
jurisdictions identified above.
E. Accounting Issues
The Merger will be accounted for under the purchase method of accounting
in accordance with generally accepted accounting principles. Under the
purchase method of accounting, New CEI will add NU's assets to its own at
their fair market value, and any premium paid over and above the fair market
value of NU's assets will be reflected as goodwill and written off against
future earnings.
NU and CEI estimate that the acquisition premium incurred in connection
with this Merger will be approximately $1.5 billion. The acquisition premium
will be accounted for as described in Mr. Schoenblum's testimony. CEI and NU
are not seeking any recovery of the acquisition premium from customers
through higher rates, but rather are requesting the Department to permit them
to retain Merger savings for a sufficient time to allow a reasonable
opportunity to recover the investment for the purchase of NU. Both Mr.
Schoenblum and Mr. Roman discuss ratemaking treatment of the Merger savings
in their testimony.
VII. THE MERGER SATISFIES THE REQUIREMENTS OF CONN. GEN. STAT. Section 16-47
Pursuant to Section 16-47, the Department must determine that CEI has
the level of management experience, financial resources and technological
expertise to enable it to assume the ownership, ultimate management and
control of CL&P and Yankee Gas. The Department must also determine that the
change of control will not impair or adversely affect the ability of CL&P and
Yankee Gas to provide safe, reliable and adequate service to their customers.
NU and CEI have demonstrated, through this application and the attached
exhibits and testimony, that CEI easily satisfies these requirements, and
that the application should be approved.
A. CEI is Financially Suitable to Exercise Control of CL&P and Yankee
Gas
CEI easily meets the financial capability requirements of Section 16-47.
As of September 30, 1999, CEI's total capitalization was $10 billion, nearly
double NU's. CEI's market capitalization on October 6, 1999, the last full
trading day prior to public speculation about the Merger, was approximately
$9 billion, as compared to $2.5 billion for NU. CEI's total operating
revenues for the twelve months ended September 30, 1999 were $7.2 billion,
nearly double the comparable figure for NU.
While CEI is clearly a larger company with more financial resources than
NU, there are also significant qualitative differences in their current
financial indicators. For example, CECONY's bond ratings are A1 by Moody's,
A+ by Standard & Poor's and AA- by Fitch. The comparable ratings for NU's
principal subsidiaries are Baa3, BBB- and BB+, respectively. CEI's balance
sheet is not only larger than NU's, it is also stronger. Its common equity
ratio is approximately 55 percent, as opposed to NU's 36 percent.
In January 1999 CEI increased its dividend to an annual rate of $2.14,
marking the 25th straight year that its dividend has been increased. In
contrast, NU recently reinstated its dividend (after the second quarter of
1997, when NU's dividend was suspended), at a $0.40 per share level, well
below the 1995 level of $1.76 per share. CEI's earnings per share rose from
$2.95 in 1997 to $3.04 in 1998, an all-time high. NU is still operating at a
net loss per share, reflecting the remaining impacts from the Millstone
Station operating difficulties in the recent past.
CEI's net income was $712.7 million in 1998, up 2.7 percent from $694.5
million in 1997. Earnings per share were $3.04 in 1998, an increase of 3.1
percent compared to earnings per share of $2.95 in 1997. Financial ratios
for CEI for the 12 months ended December 31, 1998 are as follows:
Pretax (EBIT) interest coverage:
4.29 times
Total debt/total capital:
39.2 percent
Funds from operations/total debt:
0.319
Net (free operating) cash flow/average total debt:
0.160
Net cash flow/capital expenditures:
1.152
To realign its capital structure with its evolving business risk, in May
1998, CEI commenced a repurchase program for up to $1 billion of its common
stock, which is substantially complete. In addition to these activities, CEI
successfully completed its $790 million acquisition of O&R in June 1999, and
has successfully completed the divestiture of its generating assets as
directed by the NYPSC.
CEI expects that the cash consideration to be paid to NU shareholders
will be financed from a combination of short-term borrowings, the issuance of
new securities and internal sources.
CEI's solid credit ratings, strong capital structure, steady growth in
earnings and dividends, its favorable reception in the equity markets and its
large size and superior ability to attract capital serve as strong evidence
of its ability to pass the Department's financial qualifications test with
ease. A combined CEI and NU will present a much stronger financial picture
than NU currently does on a stand-alone basis.
B. CEI is Managerially and Technologically Suitable to Exercise
Control of CL&P and Yankee Gas
In addition to satisfying the financial suitability criterion of Section
16-47, CEI also easily satisfies the managerial and technological suitability
criteria for approval. For years, CEI has been recognized as the operator of
the most reliable electric distribution system in the nation. In a recent
annual industry ranking, Theodore Barry & Associates found that CEI had fewer
power outages per customer than any other United States electric utility.
The 1998 Hagler Bailly-Theodore Barry and Associates Annual Transmission and
Distribution Best Practices survey compared 42 North American utilities and
showed that CECONY's 1998 customer system interruption rate ("SAIFI") of .123
was 12.3 times better than the survey average of 1.5141 customers interrupted
per customers served per year. The next best utility to CECONY's SAIFI was
0.40 or 3.25 times higher. CECONY has had the lowest SAIFI in each year of
this annual survey throughout the 1990's.
CEI has developed comprehensive systems to support reliability,
including managerial systems such as performance tracking and root-cause
analysis; systematic operating procedure and specification development;
remote substation and overhead system monitoring; outage management systems;
and power quality services. These systems can be adopted to enhance similar
existing NU systems.
The upper management of CECONY's electric side has utility experience
matching any company in the country. The three chief operating officers in
CECONY have over 100 years of electric utility experience in generation,
transmission, distribution, customer operations and customer service. J.
Michael Evans is CECONY's President and Chief Operating Officer and is
responsible for the Company's power production, customer service and
electric, gas and steam operations. He began his utility career in 1974 with
Kansas City Power and Light Company, rising to the position of President and
Chief Operating Officer. He joined CECONY in 1991 as an Executive Vice
President and has had various operational responsibilities since that time.
Stephen B. Bram is Senior Vice President of Central Operations with
responsibilities for system and transmission operations, substation
operations, steam operation, maintenance and construction services and energy
management. He began his CECONY career in 1963.
Robert W. Donohue, Jr. is Senior Vice President of Electric Operations.
He is responsible for all electric distribution operations throughout New
York City and Westchester County. He is CECONY's distribution system expert.
He began his career at CECONY in 1961.
CECONY's gas department is well recognized for its accomplishments. It
is a charter member of the EPA Gas STAR program, and in 1999 it received the
"Partner of the Year" award. Its research and development efforts have
produced various technologies, including the ConSplit robot and patents on
Smart Regulator devices. In addition, CECONY is the only urban LDC that is
designing, constructing, installing and testing underground remote operating
valves intended to minimize the impact of a catastrophic transmission
pipeline failure.
CECONY's upper management in the gas department has a solid background
in gas and is very involved in gas organizations, including the American Gas
Association, the Gas Industry Standards Board and the New York Gas Group.
That experience will be supplemented with the experience and expertise of
NU's and YES's management.
CECONY has consistently provided a high level of customer service.
CECONY'S performance in a number of other areas also indicate its managerial
and technological suitability to assume control of NU, CL&P and Yankee Gas.
In 1998, CECONY had its best overall environmental performance record. The
company launched major new efforts to create a "culture of excellence" in the
workforce during 1998. Efforts focused on teamwork, open communications,
pre-planning work, and functioning as a learning organization. CECONY
launched the Pinnacle program in 1998 to achieve the corporate goal of
becoming one of the safest companies in the energy industry and a world-class
leader in safety and industrial health management. The Pinnacle program
promotes excellence by emphasizing teamwork, focusing on health and safety
solutions rather than problems, and ensuring that lessons learned and
solutions developed are communicated throughout the company.
CECONY's Energy Control Center uses information technology and fiber
optic transmission to continuously gather and analyze system data for an up-
to-the-second picture of the electric system's operating status. CECONY's
underground electric system, which is the world's largest, includes thousands
of remote computer terminals that constantly feed data to the Energy Control
Center and similar control centers in its operating areas to provide the
system operators with the information they need to insure reliability.
CECONY is recognized worldwide among its industry peers for using robots
to perform tasks more efficiently. The company's latest generation of robots
can inspect and repair gas mains for 1,000 feet in each direction without
disrupting service. Other examples of CECONY's robotic technology include
the RAPTOR (Rapid Cutter of Concrete), which replaces the jackhammer and cuts
concrete pavement quickly, quietly and safely, and the AROLL (Advanced Robot
for Leak Location), which is currently in development, and which will be able
to detect insulating fluid leaks, thereby reducing the cost of locating cable
faults in the electric system.
Starting with its "Save A Watt" program in the 1970s, CECONY was the
first utility in the nation to actively promote energy conservation. In the
early 1990s, under a program called Enlightened Energy, CECONY engineers
pioneered energy-efficient lighting as a means to protect the environment
while helping customers save money. More recently, CECONY has been using its
experience in energy efficiency to help create and promote a new generation
of environmentally friendly lighting technologies.
CECONY sponsors many educational initiatives in its service area,
including internships, literacy programs, school-to-work programs, volunteers
for education, creative writing contests, youth athletic programs and support
for the arts and education. At the CECONY Learning Center, workshops are
offered for math and science teachers so they can bring new instructional
methods and technologies back to the classrooms.
CECONY's efforts to assure the retention and advancement of its female
employees, particularly in management areas, was recently recognized by
Working Woman magazine in its second annual survey of Fortune 1000 companies.
Although CEI did not rank within the top 25 performers in this survey, it
made an "honor roll" of 10 companies that the magazine predicted would soon
break into the top 25 companies. CECONY was cited for its efforts to assure
the retention and advancement of its female employees. In the magazine's
view, "Con Ed seems to know how to hold on to and develop its female
employees. Though only 14 percent of its workers are women, 29 percent of
corporate senior officers are female, including one of the top five corporate
earners." Working Woman, Dec.-Jan. 2000, at 60. CEI has four female Board
members.
CECONY's Economic Development program works to attract businesses to its
service area that are likely to thrive there by providing them with
attractive incentives. Specifically, it has been focusing on attracting "new
media" companies, such as computer software engineering firms and multimedia
designers, biotechnology companies, food companies and recycling companies to
its service territory. The new media industry alone has grown nearly 50
percent in the past two years. CECONY's Minority Business Program encourages
minority owned business to compete for contracts to supply products and
services to the company.
CEI and NU are aware that concerns have been raised about the outage in
the Washington Heights section of New York City on July 6-7, 1999. Following
that outage, CECONY assembled a Corporate Review Team and an Independent
Review Board, which was comprised of electric industry experts, to review the
outage. In December 1999, both the Corporate Review Team and the Independent
Review Board concluded that the outage resulted from a combination of record
electrical loads and record heat, which caused an unusually high number of
component failures in the network leading to the outage of 8 of the 14 feeder
cables in the Washington Heights network, and a fire in CECONY's Sherman
Creek substation, which serves the Washington Heights network, which caused
two additional feeder cables to be removed from service. None of these
events would have resulted in a network shutdown in and of themselves.
However, in combination these events necessitated the temporary shutdown of
the Washington Heights network in order to avoid more prolonged electrical
service outages and more serious damage to the electrical system.
Since the summer of 1999, CECONY has spent an additional $28 million
above its 1999 scheduled capital spending to provide load relief and
increased reliability in Washington Heights and throughout its service area.
In addition, based on the recommendations of both the Independent Review
Board and the Corporate Review Team, CECONY will take several steps to
further improve the reliability of its electrical transmission, substation
and distribution system: (1) implementing a $315 million, multi-year plan
that builds upon CECONY's existing capital programs to provide for load
relief and increase reliability; (2) completing a thorough technical review
of the performance of its electrical distribution system; (3) exploring
additional technological applications and operational techniques to expedite
the restoration of out-of-service feeders; and (4) researching the
development of new, real-time thermal modeling techniques designed to more
accurately predict the temperature of individual feeder cables.
C. The Ability of CL&P and Yankee Gas to Provide Safe, Adequate and
Reliable Service Will Be Enhanced by the Proposed Merger
The ability of CL&P and Yankee Gas to provide safe, adequate and
reliable service through their plant, equipment and manner of operation will
not be adversely effected by the Merger, and in fact will be enhanced. As
described above, CEI has the necessary financial, managerial and
technological expertise to assure that CL&P and Yankee Gas will continue to
provide safe adequate and reliable service.
It also is anticipated that local management teams of CL&P and Yankee
Gas will exist after the Merger. Both CL&P and Yankee Gas will continue to
focus on improving services and increasing their operations. CL&P and Yankee
Gas each will remain a strong and vital presence in the communities they
serve. The combined company is committed to continue the level of support NU
has demonstrated in the communities served by CL&P and Yankee Gas.
The combined company will continue NU's strong commitment to customer
service. CEI's ability to fund capital improvements and its shared commitment
to excellence and the adoption of the best practices of both companies will
assure improvements in the already high level of service provided. The
combined company will also have an expanded and more diverse pool of
management and engineering, technological and customer service talent and
experience from which to draw.
VIII. COMPLIANCE WITH THE DEPARTMENT'S REGULATIONS
This Part of the application demonstrates compliance with Sections 16-1-
46, 16-1-61, 16-1-65, 16-1-65B of the Department's Regulations.
A. Compliance With Section 16-1-46 of the Department's Regulations
Section 16-1-46(a) Statement of Application
As stated above, NU and CEI respectfully request the Department's
approval pursuant to Conn. Gen. Stat. Section 16-47, and any other statute or
regulation that the Department deems applicable, of CEI's exercise of control
over NU and the carrying out of the other transactions contemplated by this
application and the Merger Agreement.
Section 16-1-46(a)(2)
For NU:
Cheryl W. Grise
Daniel P. Venora
Kenneth H. Eagle
Northeast Utilities Service
Company
107 Selden Street
Berlin, CT 06037
Tel: (860) 665-3639
Fax: (860) 665-4886
e-mail: grisecw@nu.com
Robert P. Knickerbocker, Jr.
Day, Berry & Howard LLP
City Place I
Hartford, CT 06103-3499
Tel: (860) 275-0122
Fax: (860) 275-0343
e-mail:
rpknickerbocker@dbh.com
Individuals to Whom All
Correspondence and
Communication Regarding This
Application are to be
Addressed
For CEI:
John D. McMahon
Edwin W. Scott
4 Irving Place
New York, NY 10003
Tel: (212) 460-6330
Fax: (212) 677-5850
e-mail: mcmahonjo@coned.com
scotte@coned.com
Section 16-1-46(a)(3) - Statement of Facts
The facts on which the Department is expected to rely in granting its
approval of the application are set forth in this application and the
Exhibits, including the pre-filed testimony, filed herewith. NU and CEI
reserve the right to supplement that information as they may deem necessary
or desirable or as the Department may request.
Section 16-1-46(a)(4) - Special Circumstances
NU and CEI hope to effectuate the Merger in July 2000. Action by the
Department on this application on or before June 1, 2000 will facilitate
completion of the Merger as promptly as possible. Because NU and CEI believe
that the Merger satisfies the applicable statutory requirements, prompt
Department consideration and approval is requested.
B. Compliance with Section 16-1-65 of the Department's Regulations
This application is jointly sponsored by NU and CEI. For purposes of
Regulations Section 16-1-65, however, the "applicant" is interpreted to mean
CEI.
Section 16-1-65(a) - General Description of the Property, Field of
Operation and Existing Business Interests of the Applicant
In addition to the information provided in Sections III and IV above,
see Exhibit 2 (CEI 1998 Annual Report), Exhibit 3 (CEI SEC Form 10-K for year
ended December 31, 1998) and Exhibit 4 (CEI SEC Form 10-Q dated September 30,
1999).
Section 16-1-65(b) - Financial Statement for the Most Recent Fiscal
Year and Pro Forma Period (Including Assumptions) Giving Effect to the Proposed
Transaction, To Include Balance Sheet, Income Statement and Statement of Source
and Application of Funds
See Exhibit 3 (CEI SEC Form 10-K for year ended December 31, 1998) and
Exhibit 5 (Pro forma financial statements).
Section 16-1-65(c) - CEI's Most Recent Form 10-K and Subsequent Forms 10-Q
filed with the Securities and Exchange Commission
See Exhibit 3 (CEI SEC Form 10-K for year ended December 31, 1998) and
Exhibit 4 (CEI SEC Form 10-Q dated September 30, 1999).
Section 16-1-65(d) - CEI's Most Recent Form 8-K Filed with the Securities and
Exchange Commission
See Exhibit 6 (CEI SEC Form 8-K, filed October 15, 1999).
Section 16-1-65(e) - CEI's Most Recent Annual Report to Shareholders
See Exhibit 20 (CEI 1999 Annual Shareholders Meeting Proxy Statement).
Section 16-1-65(f) - CEI's Latest Proxy Statement Sent to Shareholders
See Exhibit 20 (CEI 1999 Annual Shareholders Meeting Proxy Statement).
Section 16-1-65(g) - Description of the Transaction, Including Intended
Financing, by which the Proposed Transaction will be Effected, and Agreement
or Other Instruments Associated with the Proposed Transaction
To effect the acquisition, CEI will merge into New CEI, a new parent
holding company incorporated in Delaware. A wholly-owned subsidiary of New
CEI will then merge into NU, with NU being the entity surviving that merger.
As a result of these transactions, NU will become a direct, wholly-owned
subsidiary of New CEI, the parent of the combined company. Further details
regarding the Merger are set forth in Section IV above, and in Exhibit 1
(Merger Agreement), Exhibit 5 (Pro forma financial statements), Exhibit 7
(joint press release dated October 13, 1999) and Exhibit 11 (SEC Form U-1),
which is being prepared and will be filed with the Department when it is
filed with the SEC. Additional information is also provided in Exhibit 10
(Prospectus/Proxy Statement), which is being prepared and will be filed with
the Department.
Section 16-1-65(h) - Statement of Purpose and Intent of CEI in Undertaking the
Proposed Transaction
This information is provided in detail in Section V of this application
and in Exhibits 22 and 23, the Pre-filed Testimony of Mr. Morris and Mr.
Schoenblum, submitted herewith. See also Exhibit 11 (SEC Form U-1) and
Exhibit 10 (Prospectus/Proxy).
Section 16-1-65(i) - A Statement of the Benefits That Would Result
to the Customers and Shareholders of NU
This information is provided in detail in Sections IV, V and VI of this
application and in Exhibit 22, the Pre-filed Testimony of Mr. Morris, Exhibit
23, and the Pre-filed Testimony of Hyman Schoenblum submitted herewith. See
also Exhibit 11 (SEC Form U-1) and Exhibit 10 (Prospectus/Proxy Statement).
Section 16-1-65(j) - Any Prospectus, Official Statement, Preliminary
Prospectus or Preliminary Official Statement Prepared by or on Behalf of CEI or
any Other Person with Regard to the Proposed Transaction
See Exhibit 10 (Prospectus/Proxy Statement).
Section 16-1-65(k) - CEI's Capital Structure and Capitalization Ratios, Present
and Pro Forma (Include Assumptions), Assuming Approval of the Proposed
Transaction
See Exhibit 5 (Financial statements, present and pro forma).
Section 16-1-65(l) - CEI's Interest (Before and After Income Taxes)
and Fixed Charge Coverage, Present and Pro Forma (Include Assumptions),
Assuming Approval of the Proposed Transaction
See Exhibit 5 (Financial statements, present and pro forma).
Section 16-1-65(m) - Table of Organization of Management After Giving Effect
to the Proposed Transaction, Including the Name of Each Executive Officer
See Exhibit 8 (CEI and NU corporate organization, pre-merger and post-
merger; CEI and NU executive officers, pre-merger and post-merger).
Section 16-1-65(n) - Proposed Members of the CEI Board of Directors
After Giving Effect to the Proposed Transaction
See Exhibit 9 (CEI and NU Board of Directors, pre-merger and post-
merger).
Section 16-1-65(o) - A Narrative of the Proposed Operations of the
Combined Company for the First Calendar Year Following the Effectiveness
of the Proposed Transaction, Including but Not Limited to Employment Levels
and Office and Service Center Locations, and Details of all Changes from
the Existing Operations of NU
Please refer to Sections IV, V and VI above, particularly Section V.B's
discussion of "Post-Merger Organization and Operations," and to the Pre-filed
Testimony of Mr. Morris, Mr. Schoenblum and Mr. Roman, submitted herewith as
Exhibits 22, 23 and 24, respectively.
Section 16-1-65(p) - A Description of the Experience of CEI in the
Operation, Management and Control of any Public Service Company, and, to the
Extent Not Otherwise Provided, a Statement as to the Suitability of CEI to
Control NU
Detailed information on these matters is provided in Sections III, V and VI
of this application and in the Pre-filed Testimony submitted herewith as
Exhibit 23. CEI has extensive experience in operating, managing and
controlling electric and gas public service companies.
Section 16-1-65(q) - A List of All Department Orders, Rulings and
Regulations In Effect and Applicable to NU, including YES, and an Indication
of those Which the Applicants Propose Would be Discontinued in Connection with
the Proposed Transaction, Together with a Statement of the Reason for Each Such
Proposed Discontinuance
The Applicants do not anticipate that the Merger will have any impact on
any Department orders, rulings or regulations in effect and applicable to NU
or its subsidiaries, including YES and its subsidiaries.
Section 16-1-65(r) - A List of Stockholder Approval and All Federal,
State and Local Governmental Approvals Required to Effect the Proposed
Transaction, Together with a Description of the Status of the Efforts to obtain
Such Approval as of the Date Reasonably Proximate to the Date of the
Application
The Merger was approved by the NU Board of Trustees on October 12, 1999
and by the CEI Board of Directors on October 12, 1999. Approval by the
holders of outstanding CEI common shares and NU common shares is expected at
a special stockholders meetings presently scheduled to take place in early
2000.
The Applicants will submit as Exhibit 10 a Prospectus/Proxy filed with
the SEC. The Applicants will also make a filing with the SEC contemporaneously
with or shortly after this application for approval of the
Merger under the provisions of the PUHCA, a copy of which will be filed as
Exhibit 11 hereto.
The Applicants will file an application with the FERC contemporaneously
with or shortly after this application requesting the required approvals. In
addition, the Applicants will file an application with the NRC
contemporaneously with or shortly after this application requesting the
required approvals.
The Applicants will file an application with the Antitrust Division of
the DOJ and the FTC contemporaneously with or shortly after this application
under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended.
In addition, certain regulatory filings and requests for approvals will
be made, as applicable, prior to the consummation of the Merger in Maine,
Massachusetts, New Hampshire, New Jersey, New York, Pennsylvania and Vermont.
Section 16-1-65(s) - A Statement of the Percentage of Voting
Securities of NU Owned or Controlled by CEI, and Control Exercised or Capable
of Being Exercised Over the Public Service Company After the Conclusion of the
Proposed Transactions
After completion of the proposed Merger, NU will be a wholly-owned
subsidiary of New CEI.
C. Compliance With Section 16-1-65B of the Department's Regulations
This application is jointly sponsored by CEI and NU. However, for
purposes of these Regulations, the "affected company" is interpreted to mean
NU, or its public service company subsidiaries (CL&P and Yankee Gas) as
appropriate.
Section 16-1-65B(a) - NU's Financial Statement for the Most Recent
Fiscal Year and Pro Forma Period (Including Assumptions) Giving Effect to the
Proposed Transaction, to Include Balance Sheet, Income Statement and Statement
of Source and Application of Funds
See Exhibit 5 (Financial statements, present and pro forma); Exhibit 13
(NU SEC Form 10-K).
Section 16-1-65B(b) - Existing Reporting Structure for Personnel,
from Connecticut Local Operations to Chief Executive Officer, Including
Board of Directors
See Exhibit 8, which identifies NU's existing corporate reporting
structure, and Exhibit 9, which identifies NU's existing Board of Trustees.
Section 16-1-65B(c) -Capital Structure and Capitalization Ratios,
Present and Pro Forma (Include Assumptions) Giving Effect to the Proposed
Transaction
See Exhibit 5 (Financial statements, present and pro forma).
Section 16-1-65B(d) - Any Prospectus, Official Statement, Preliminary
Prospectus or Preliminary or Official Statement Associated with the Transaction
for which Approval Is Sought
See Exhibit 10 (Prospectus/Proxy Statement).
Section 16-1-65B(e) - A Statement of the Control That CEI is Capable
of Exercising over NU After Completion of the Proposed Transaction
After completion of the proposed Merger, NU will be a wholly-owned
subsidiary of New CEI.
D. Compliance With Section 16-1-61 of the Department's Regulations
(Conn. Gen. Stat. Section 16-43)
To the extent that the Department determines that Conn. Gen. Stat. Section
16-43 is applicable, NU and CEI provide the following information in
compliance with Section 16-1-61 of the Department's Regulations. This
application is jointly sponsored by NU and CEI. However, for purposes of
these Regulations, the "applicant" is NU, or its public service company
subsidiaries (CL&P and Yankee Gas) as appropriate.
Section 16-1-61(a)(1) - Statement of financial condition of NU and the
surviving company, reflecting the financial condition of the surviving company
before and after the Merger
See Exhibit 12 (NU 1998 Annual Report, including audited financial
statements); Exhibit 13 (NU SEC Form 10-K); Exhibit 14 (NU SEC Form 10-Q);
Exhibit 15 (NU SEC form 8-K dated October 27, 1999; Exhibit 17 (NU capital
structure and capitalization ratios). Changes to NU's financial condition as
a result of the Merger are illustrated in the pro forma statements provided
in Exhibit 5. NU and CEI also request that the Department take notice of the
information contained in the most recent annual reports filed by CL&P and
Yankee Gas with the Department.
Section 16-1-61(a)(2) -Copy of the Merger Agreement
See Exhibit 1.
Section 16-1-61(a)(3)- Description of NU's Property, Field of Operation,
Property, Equipment, Depreciation and Amortization Reserves
In addition to the information provided in Section III above, see
Exhibit 10 (Prospectus/Proxy Statement). NU and CEI also request that the
Department take notice of the information contained in the most recent annual
reports filed by CL&P and Yankee Gas with the Department.
Section 16-1-61(a)(4)-Financial Structure of the Deal
See Exhibit 1.
Section 16-1-61(a)(5) - Copies of Instruments Defining the Terms of Any
Proposed Security, Any Plans or Offers of Reorganization or Readjustment of
Indebtedness or Capitalization, and Any Plan for the Retirement or Exchange
of Securities
Generally not applicable except to the extent that the Merger Agreement
(Exhibit 1) provides for the retirement or exchange of NU common stock.
Section 16-1-61(a)(6) - Statement of the Purpose For Which the Securities
Are to be Issued
Not applicable.
Section 16-1-61(a)(7) - Complete Description of Obligations/Liabilities
Assumed by NU
Not applicable.
Section 16-1-61(a)(8)- Copy of the Latest Proxy Statement and Annual
Report of Applicant or Parent Company
See Exhibit 12 (NU Annual Report for the fiscal year ended 1998);
Exhibit 10 (Prospectus/Proxy Statement to be filed with the Department), and
Exhibit 18 (NU Proxy Statement for 1999 Annual Meeting); Exhibit 20 (1999 CEI
Annual Shareholders Meeting Proxy Statement).
Section 16-1-61(a)(9)- Copies of All SEC Filings of Applicant or Parent
Company in Connection with the Merger
See Exhibit 10 (Prospectus/Proxy Statement to be filed with the
Department); Exhibit 6 (CEI SEC Form 8-K filed October 15, 1999); Exhibit 15
(NU SEC Form 8-K dated October 27, 1999).
Section 16-1-61(a)(10)- Description of Property Involved In the
Transaction
In addition to the information provided in Section III above, NU and CEI
also request that the Department take notice of the information contained in
the most recent annual reports filed by CL&P and Yankee Gas with the
Department.
Section 16-1-61(a)(11) - Certified Copy of the NU Board of Trustees
Resolutions Approving the Initiation of the Transaction
See Exhibit 9.
E. List of Exhibits
Exhibit 1 Merger Agreement
Exhibit 2 CEI 1998 Annual Report with audited financial statements
Exhibit 3 CEI SEC Form 10-K for year ended December 31, 1998
Exhibit 4 CEI SEC Form 10-Q dated September 30, 1999
Exhibit 5 Pro forma financial statements for the most recent fiscal year
and pro forma period giving effect to the Merger
Exhibit 6 CEI SEC Form 8-K filed October 15, 1999
Exhibit 7 Joint press release dated October 13, 1999
Exhibit 8 CEI and NU corporate organization, pre-merger; CEI executive
officers, pre-merger
Exhibit 9 Members of CEI Board of Directors, pre-merger and post-merger.
Exhibit 10 Prospectus/Proxy Statement (to be filed subsequently)
Exhibit 11 SEC Form U-1 (to be filed with the Department
subsequently)
Exhibit 12 NU 1998 Annual Report, including audited financial statements
Exhibit 13 NU SEC Form 10-K for the period ending December 31, 1998
Exhibit 14 NU SEC Form 10-Q
Exhibit 15 NU SEC Form 8-K dated October 27, 1999
Exhibit 16 Map of the service territory of CECONY and O&R
Exhibit 17 NU capital structure and capitalization ratios as of
September 30, 1999
Exhibit 18 NU Proxy Statement for 1999 Annual Meeting
Exhibit 19 NU Board of Trustees resolutions
Exhibit 20 1999 CEI Annual Shareholders Meeting Proxy Statement
Exhibit 21 Surety Bond
Exhibit 22 Pre-filed Testimony of Mr. Morris
Exhibit 23 Pre-filed Testimony of Mr. Schoenblum
Exhibit 24 Pre-filed Testimony of Mr. Roman
F. Statutory Bond Requirement
Pursuant to Conn. Gen. Stat. Section 16-47(c), a bond in the amount of
$50,000 is required to indemnify the Department for the reasonable expenses
incurred by the Department in reviewing this Application. The required bond
is furnished as Exhibit 21.
IX. CONCLUSION AND REQUEST FOR APPROVAL
NU and CEI respectfully request approval of the transactions described
herein, and in the Merger Agreement, pursuant to Conn. Gen. Stat. Section 16-47
and any other statute or regulation the Department finds applicable, as set
forth herein and in the Exhibits hereto, and for the reasons set forth
herein.
RESPECTFULLY SUBMITTED,
CONSOLIDATED EDISON, INC.
By:
/S/ John D. McMahon
Senior Vice President
and General Counsel
NORTHEAST UTILITIES
By:
/S/ Cheryl W. Grise
Senior Vice President,
Secretary and General Counsel
Footnotes:
1. Current levels of consolidation in the energy industry have not reached
those that are evolving in telecommunications. Consider the mergers of MCI,
WorldCom and Sprint, or NYNEX, Bell Atlantic and GTE, or AT&T, TCI and Media
One. This Department is familiar with the recent acquisitions by SBC
Communications. In April 1997, SBC acquired Pacific Telesis Group, another
regional Bell operating company ("RBOC"), before acquiring SNET in October
1998. SBC's recent merger with Ameritech, still another RBOC, resulted in
a combined company serving more than 55.5 million local exchange access
lines, or about one-third of the nation's total access lines, with more than
200,000 employees and annual revenues in excess of $45 billion. Even at that
size it is the second largest telecommunications company in the nation,
behind AT&T.
2. NU and CEI believe that Conn. Gen. Stat. Section 16-43 is not applicable
to this transaction, and that the Department's review is properly limited to
Conn. Gen. Stat. Section 16-47. See, e.g., Docket 99-07-20, Joint Application
of Energy East Corporation and Connecticut Energy Corporation for Approval of a
Change of Control (December 16, 1999); Docket No. 98-09-15, Application of AT&T
Corp. and Tele-Communications, Inc. for Approval of a Change of Control
(January 6, 1999); Docket No. 98-02-20, Joint Application of SBC
Communications, Inc. and Southern New England Telecommunications Corporation
for a Change of Control (September 2, 1998). To the extent that the Department
determines that Conn. Gen. Stat. Section 16-43 is applicable to the proposed
transaction, the Applicants have included all information required by the
Department's regulations for approval of an application under that statute
and have demonstrated that the application satisfies its requirements.
3. CECONY has two wholly-owned subsidiaries: Davids Island Development
Corporation ("Davids Island") and D.C.K. Management Corporation ("DCK").
Davids Island owns real property acquired as a possible site for an electric
generating plant in Dutchess and Columbia Counties in New York State, which
it is in the process of disposing. DCK owns real property in New York City.
4. RECO's two wholly-owned non-utility subsidiaries are Enserve Holdings, Inc.
and Saddle River Holdings Corp., both Delaware corporations. Enserve has two
wholly-owned currently inactive non-utility subsidiaries, Palisades Energy
Services, Inc., which provided non-regulated energy services to industrial,
commercial, institutional and government energy users, and Compass Resources,
Inc., which was formed to invest in energy technology ventures and new energy
processes. RECO's other non-utility subsidiary, SRH,was established for the
purpose of investing in non-utility business ventures. SRH has two
wholly-owned non-utility subsidiaries, NORSTAR Holdings, Inc. and Atlantic
Morris Broadcasting, Inc. NHI has two wholly-owned non-utility subsidiaries,
NORSTAR Management, Inc., and Millbrook Holdings, Inc. NHI is the sole general
partner of NORSTAR Energy Limited Partnership, a gas marketing company that is
discontinuing operations. The NORSTAR Partnership is the majority owner of
NORSTAR Energy Pipeline Company,LLC, which is currently inactive. NHI's
Millbrook subsidiary holds a leasehold interest in non-utility real estate
in Morris County, New Jersey. SRH's other non-utility subsidiary, AMB, which
owned six radio stations, is currently inactive.
5. CED has five direct operating subsidiaries: (i) Con Edison Development,
Guatemala, Ltd. invests in projects in Latin America; (ii) Consolidated Edison
Leasing, Inc. has an investment in a leveraged-lease transaction in a power
plant in the Netherlands; (iii) Con Edison Leasing, LLC, has an investment in
a leveraged-lease transaction in a gas distribution system in the Netherlands;
(iv) CED Ada, Inc. which has an indirect interest in a qualifying cogeneration
facility in Michigan; and (v) Carson Acquisition, Inc. which has an indirect
leasehold interest in a qualifying cogeneration facility in California.
6. The NYPSC defined its vision and policy in its May 20, 1996 order in the
Matter of Competitive Opportunities Regarding Electric Service, Opinion
No. 96-12. That vision and policy includes: (1) effective competition in the
generation and energy services sectors; (2) reduced prices resulting in
improved economic development for New York as a whole; (3) increased consumer
choice of supplier and service company; (4) a system operator that treats all
participants fairly and ensures reliable service; (5) a provider of last
resort for all consumers and the continuation of a means to fund necessary
public policy programs; (6) ample and accurate information for consumers to use
in making informed decisions; and (7) the availability of information that
permits adequate oversight of the market to ensure its fair operation.
7. The NU/YES transaction is currently anticipated to be completed on or
before April 1, 2000. Upon completion of that transaction, YES and its
operating utility subsidiary, Yankee Gas, will become wholly-owned
subsidiaries of NU.
Exhibit d.4
January 13, 2000
VIA HAND DELIVERY
Mary L. Cottrell, Secretary
Department of Telecommunications
and Energy
One South Station
Boston, MA 02110
Re: Merger of Consolidated Edison, Inc. and Northeast Utilities
Dear Secretary Cottrell:
As announced on October 13, 1999, the Boards of both Consolidated Edison,
Inc. ("Consolidated Edison") and Northeast Utilities ("NU") approved a
definitive merger agreement to combine the two companies. Western
Massachusetts Electric Company, a subsidiary of NU, is a company subject to
the jurisdiction of the Department of Telecommunications and Energy
("Department"). Under the agreement, Consolidated Edison will acquire all of
the common stock of NU for $25.00 per share in a combination of cash and
Consolidated Edison common stock, subject in the case of the common stock, to
certain collar provisions. Because Consolidated Edison and NU are both
holding companies, the merger does not require the approval of the
Department. However, Consolidated Edison and NU believes that an element in
the review of the merger by the Securities and Exchange Commission ("SEC")
may be certifications from the relevant state regulatory commissions
regarding each commission's jurisdiction and resources over the operating
companies in their state. Based on previous cases, it is possible that the
SEC will want the Department to certify, in a manner similar to that required
in Section 33(a)(2) of the Public Utility Holding Company Act of 1935
("35 Act"), that the Department has the authority and resources to protect
ratepayers in matters such as rates, financings, affiliate transactions and
financial integrity, and that the Department intends to exercise its authority.
In our view, the Department has the existing authority and resources to
protect Western Massachusetts Electric Company's ("WMECO") customers in each
of the areas in which the SEC wants assurances. The proposed merger will not
affect the Department's jurisdiction or authority over WMECO in any way. For
instance, the Department will continue to have full jurisdiction over WMECO's
rates under G.L. c. 164, Sections 93 and 94; the companies' financings will
still be subject to approval under c. 164, Section 14; affiliate transactions
will be subject to Department review and approval under c. 164, Sections 76A,
85 and 94B; and the Department also retains general supervisory authority
over the companies with the ability to make all inquiries needed to assure
itself that the "safety and convenience" of the public is protected. Nor
will the merger adversely affect the Department's resources to protect
WMECO's customers. To eliminate any concerns the Department may have with
regard to the acquisition premium and its allocation, we agree that neither
the above requested certification nor the approval of the merger by the SEC
under the 35 Act and any allocation of the acquisition premium to WMECO
resulting from SEC's jurisdiction over the merger will have any pre-emptive
effect on the Department's consideration of the amounts, if any, of the
acquisition premium it will allow in rates in any future proceeding by WMECO
seeking recovery of such acquisition premium in their retail delivery rates.
As a result, for ratemaking purposes, the Department will have complete
authority to establish the appropriate allocation of the acquisition premium
to WMECO and the amount of the recovery of that premium in WMECO's rates.(FN1)
Additionally, because we want the Department to have a full understanding of
the merger and its benefits to ratepayers we are making an informational
filing describing the transaction. This filing includes testimony submitted
by WMECO's affiliate, The Connecticut Light and Power Company with the
Department of Public Utility Control. Included is: 1) testimony of Michael
G. Morris, Chairman, Chief Executive Officer and President of NU who
discusses the merger and how it will affect the operation of the operating
companies of NU and the benefits of the merger; 2) testimony of John J.
Roman, Vice President and Controller of NU who explains the effects of NU's
merging with Consolidated Edison on the costs, accounting and rates of the
operating companies of NU; and 3) testimony of Hyman Schoenblum, Vice
President and Controller of Consolidated Edison who will introduce
Consolidated Edison, discuss the merger and demonstrate that Consolidated
Edison has the necessary financial, technological and managerial suitability
to become the parent holding company for NU and its subsidiaries.
The Consolidated Edison/NU merger is important in allowing WMECO to continue
to provide high quality, low cost delivery service to our customers in the
western portion of the Commonwealth.
Very truly yours,
cc: George B. Dean, Esq.
/s/ Robert F. Sidney, Esq.
footnote:
(1) A simple example will illustrate the effect of this commitment. If
WMECO were allocated $100 of acquisition premium following this transaction,
the Department would be free to disallow its recovery either on the grounds
that the $100 was not reasonably allocated to WMECO or that WMECO had not
demonstrated sufficient offsetting savings to warrant recovery. Thus, the
Department would have the authority to limit WMECO's recovery of the
acquisition premium to $80 if the Department determined $80 was a reasonable
allocation, even though WMECO had demonstrated that $150 of savings had been
produced by the transaction.
Exhibit d.11
January 13, 2000
U.S. Nuclear Regulatory Commission
Document Control Desk
Washington, DC 20555
Subject: Notification/Application pursuant to 10 CFR Section 50.80 regarding
Operating License Nos. DPR-5 for Indian Point-1 (Docket No.50-3), DPR-26 for
Indian Point-2 (Docket No.50-247), DPR-21 for Millstone-1 (Docket No. 50-
245), DPR-65 for Millstone-2 (Docket No. 50-336), NPF-46 for Millstone-3
(Docket No.50-423), and NPF-86 for Seabrook (Docket No. 50-443)
Dear Sirs:
This letter is to advise and notify the Commission of the proposed
merger of Consolidated Edison, Inc. ("CEI") and Northeast Utilities ("NU")
pursuant to the terms and conditions of a merger agreement dated October 13,
1999. The companies intending to merge are the parent corporations of the
Operating License holders for the Indian Point 1 and 2, Millstone 1, 2 and 3,
and Seabrook nuclear power plants. To the extent required by Section 184 of
the Atomic Energy Act, as amended, and 10 CFR. Section 50.80, Consolidated
Edison Company of New York, Inc, Northeast Nuclear Energy Company, and North
Atlantic Energy Service Corporation, the licensed operators of the above-
referenced nuclear power plants, jointly request the Commission's consent to
any indirect transfer of control of the operating licenses for such plants
that the Commission may deem associated with the merger transactions. The
consummation of the merger is dependent upon the receipt of various federal
and state regulatory approvals. Assuming all required regulatory and
shareholder approvals are obtained in a timely fashion, the parties
anticipate consummating the merger in mid-2000.
Through its subsidiaries and affiliates CEI provides service to over
three million electric customers and over one million gas customers in New
York City and Westchester, Rockland and Orange Counties in New York, and
adjacent sections of New Jersey and Pennsylvania. For the year ending
December 31, 1998, CEI had approximately $7 billion in consolidated operating
revenues.
Northeast Utilities is a public utility holding company for a number of
companies comprising the Northeast Utilities system. Through its
subsidiaries and affiliates, NU provides electric service to over 1.7 million
customers in Connecticut, New Hampshire and Massachusetts. In June 1999 NU
entered into an agreement to acquire Yankee Energy System, Inc. ("YES").
This merger is expected to become effective as early as the first quarter of
2000. YES, through a wholly-owned subsidiary, is the largest natural gas
distributor in Connecticut. For the year ending December 31, 1998, NU had
approximately $3.8 billion in consolidated operating revenues.
The October 13, 1999 CEI/NU merger agreement provides for the
combination of CEI and NU to occur through two simultaneous mergers: the
merger of CEI into New CEI, a Delaware corporation, and the merger of an
indirect wholly-owned subsidiary of New CEI with NU. Upon the completion of
all of the related merger transactions New CEI will own all of the assets of
CEI, and NU will be a wholly-owned subsidiary of New CEI. The utility
subsidiaries of CEI and NU, including the Operating License holders of the
affected nuclear units, will retain their individual names and identities and
continue to serve their respective service territories.
The combined company, New CEI, will be the nation's largest electric
distribution utility with over 5 million electric customers, as well as 1.4
million gas customers, serving large areas of the northeastern United States
with a population of more than 13 million. The combined company will have
revenues on a pro forma basis of approximately $11 billion and total assets
of almost $28 billion.
It should be noted that: (1) after the consummation of the merger
transactions the corporate parents of each of the licensed operators of the
affected nuclear units will remain the same, and such licensees will continue
to exercise direct control over licensed activities at their nuclear
facilities; (2) Consolidated Edison Company of New York, Inc. and
subsidiaries of NU will continue to hold their respective NRC licenses to own
their respective interests in and operate the Indian Point 1 and 2, Millstone
1, 2 and 3, and Seabrook nuclear plants; (3) no change in the management or
operation of any of the affected nuclear units will result from the merger;
(4) Consolidated Edison Company of New York, Inc. and the subsidiaries of NU
that own interests in the plants will each continue to be an "electric
utility" as provided in 10 CFR Section 50.2, in that each will continue to be
subject to regulation by cognizant state public utility commissions and the
Federal Energy Regulatory Commission ("FERC") after the merger; (5) neither
New CEI nor NU will be owned, controlled or dominated by any non-U.S.
citizen, foreign corporation or foreign government; and (6) all of the
members elected to the New CEI Board of Directors will be U.S. citizens.
Finally, NRC antitrust review of the merger transaction does not appear
to be necessary or appropriate consistent with the Commission's June 18, 1999
decision in Kansas Gas and Electric Company (Wolf Creek Generating Station).
A review of market and economic issues related to the merger will be
conducted by sister federal agencies under the Hart-Scott-Rodino Antitrust
Improvements Act (Department of Justice) and the Federal Power Act (FERC).
To the extent that the NRC believes the CEI/NU merger entails an
indirect transfer of control of the respective NRC license interests of
Consolidated Edison Company of New York, Inc. or the referenced subsidiaries
of Northeast Utilities, consent to any such transfers is requested. The
enclosed Notification/Application sets forth further information as provided
in 10 CFR Sections 50.80 and 30.34(b). A copy of the referenced merger
agreement is appended to the Notification/Application. A copy of the merger
Joint Proxy Statement will also be filed with the Commission as soon as it is
available.
As we note, the parties contemplate that the merger will be effected,
subject to regulatory and shareholder approvals, in mid-2000. In the event
the NRC has any questions or requires additional information, please contact
either the undersigned or Mr. Richard M. Kacich, NU Director of Business
Services, at your earliest convenience. Mr. Kacich can be contacted by
telephone at 860.440.2076, or by E-mail at kacicrm@gwsmtp.nu.com. We will
be pleased to cooperate fully in facilitating the consideration of our
request and in supplying any further information that the NRC may require.
Service upon the applicants of comments, hearing requests, intervention
petitions or other pleadings, if applicable, should be made to Brent L.
Brandenburg, Esq., Consolidated Edison Co. of New York, Inc., 4 Irving Place
- - 1830, New York, NY 10003, and William J. Quinlan, Esq., Northeast
Utilities, 107 Selden Street, Berlin, CT 06037. Mr. Brandenburg's phone
number is 212.460.4333; his E-mail address is brandenburgb @coned.com; Mr.
Quinlan's phone number is 860.665.3761; his E-mail address is quinlwj@nu.com.
Very truly yours,
John F. Groth Bruce D. Kenyon
Sr. Vice President and President - Generation Group
Chief Nuclear Officer Northeast Utilities
Consolidated Edison Company P. O. Box 270
of New York, Inc. Hartford, CT 06141
Broadway & Bleakley Avenue
Buchanan, NY 10511
cc: Distribution List attached
CE/NU 10 CFR. Section 50.80 Notification/Application
Distribution List
Samuel J. Collins
Director, Office of Nuclear Reactor Regulation
U.S. Nuclear Regulatory Commission
Mail Stop 5E7
Washington, DC 20555
Hubert J. Miller
Regional Administrator, Region I
U.S. Nuclear Regulatory Commission
475 Allendale Road
King of Prussia, PA 19406
* Paul Eddy
New York State Department of
Public Service
3 Empire State Plaza
Albany, NY 12223
* Charles Donaldson, Esq.
Assistant Attorney General
New York Department of Law
120 Broadway
New York, NY 10271
* The Honorable Alfred Donahue
Mayor, Village of Buchanan
236 Tate Avenue
Buchanan, NY 10511
* William F. Valentino
President, New York State Energy
Research and Development Authority
Corporate Plaza West
286 Washington Avenue Ext.
Albany, NY 12223-6399
* Dr. Edward L. Wilds
Director, Division of Radiation
Department of Environmental Protection
State of Connecticut
79 Elm Street
Hartford, CT 06106-5127
* Woodbury P. Fogg
Director, New Hampshire Office of
Emergency Management
State Office Park South
107 Pleasant Street
Concord, NH 03301
* William J. Raymond
Senior Resident Inspector - Indian Point Station
U.S. Nuclear Regulatory Commission
P.O. Box 38
Buchanan, NY 10511
* Paul C. Cataldo
Senior Resident Inspector - Millstone Unit 1
U.S. Nuclear Regulatory Commission
P. O. Box 513
Niantic, CT 06357
* David P. Beaulieu
Senior Resident Inspector - Millstone Unit 2
U.S. Nuclear Regulatory Commission
P. O. Box 513
Niantic, CT 06357
* Antone C. Cerne
Senior Resident Inspector - Millstone Unit 3
U.S. Nuclear Regulatory Commission
P. O. Box 513
Niantic, CT 06357
* Raymond K. Lorson
Senior Resident Inspector - Seabrook Unit 1
U.S. Nuclear Regulatory Commission
P. O. Box 1149
Seabrook, NH 03874
Robert S. Wood
Office of Nuclear Reactor Regulation
U.S. Nuclear Regulatory Commission
Mail Stop 10E46
Washington, DC 20555
Steven R. Hom
Office of General Counsel
U.S. Nuclear Regulatory Commission
Mail Stop 15D21
Washington, DC 20555
* John L. Minns
Project Manager - Indian Point Unit 1
Division of Reactor Program Management
U.S. Nuclear Regulatory Commission
Mail Stop 10D-4
Washington, DC 20555
* Jefferey F. Harold
Project Manager - Indian Point Unit 2
Project Directorate I-1
U.S. Nuclear Regulatory Commission
Mail Stop 14B-2
Washington, DC 20555
* Louis L. Wheeler
Project Manager - Millstone Unit 1
Project Directorate I-2
U.S. Nuclear Regulatory Commission
Mail Stop 11D19
Washington, DC 20555
* Jacob I. Zimmerman
Project Manager - Millstone Unit 2
Project Directorate I-2
U.S. Nuclear Regulatory Commission
Mail Stop 8B1
Washington, DC 20555
* Victor Nerses
Project Manager - Millstone Unit 3
Project Directorate 1-2
U.S. Nuclear Regulatory Commission
Mail Stop 8C2
Washington, DC 20555
Robert M. Pulsifer
Project Manager - Seabrook Unit 1
Project Directorate 1-2
U.S. Nuclear Regulatory Commission
Mail Stop 4H6
Washington, DC 20555
* Excluding merger agreement
UNITED STATES OF AMERICA
NUCLEAR REGULATORY COMMISSION
In the Matter of ) Docket Nos.
)
Consolidated Edison Company of ) 50-3
New York, Inc. and Northeast ) 50-245
Utilities, et al. ) 50-247
) 50-336
Indian Point Unit 1 and 2, ) 50-423
Millstone Unit 1, 2 and 3, ) 50-443
and Seabrook Station Unit 1 )
NOTIFICATION OF MERGER/APPLICATION
FOR TRANSFERS OF CONTROL REGARDING
INDIAN POINT 1 AND 2, MILLSTONE 1, 2 AND 3,
AND SEABROOK NUCLEAR POWER STATIONS
INTRODUCTION AND BACKGROUND
Consolidated Edison Company of New York, Inc. is the holder of NRC
Facility License Nos. DPR-5 dated March 26, 1962, and DPR-26 dated September
28, 1973. The operating licenses authorize the holder to possess the Indian
Point Nuclear Generating Station Units 1 and 2, respectively, and authorize
Consolidated Edison Company of New York, Inc. to use and operate Indian Point
1 and 2 in accordance with the conditions and requirements set forth in the
respective operating licenses. Consolidated Edison Company of New York,
Inc. is the sole license holder for Indian Point 1 and 2.
Northeast Utilities subsidiaries The Connecticut Light and Power Company
("CL&P") and Western Massachusetts Electric Company ("WMECO") are the holders
of NRC Facility License Nos. DPR-21 dated October 7, 1970, and DPR-65 dated
September 26, 1975. The operating licenses authorize the holders to
possess the Millstone Nuclear Generating Station Units 1 and 2, respectively,
and authorize Northeast Utilities' ("NU") subsidiary Northeast Nuclear Energy
Company ("NNECO") to possess, use and operate Millstone Units 1 and 2 in
accordance with the conditions and requirements set forth in the respective
operating licenses. The referenced NU subsidiaries are the sole license
holders for Millstone 1 and 2.
NU subsidiaries CL&P, WMECO and Public Service Company of New Hampshire
("PSNH"), together with eleven other investor-owned and municipal entities
unaffiliated with NU, are the holders of NRC Facility License No. NPF-46
dated January 31, 1986. The operating license authorizes the holders to
possess Millstone Nuclear Generating Station Unit 3, and authorizes NNECO to
use and operate Millstone 3 in accordance with the operating license
conditions and requirements.
NU subsidiaries CL&P and North Atlantic Energy Corporation ("NAEC"),
together with nine other investor-owned and municipal entities unaffiliated
with NU, are the holders of NRC Facility License No. NPF-86 dated March 15,
1990. The operating license authorizes CL&P and NAEC to possess Seabrook
Station Unit No. 1 ("Seabrook"), and authorizes another NU subsidiary, North
Atlantic Energy Service Corporation ("NAESCO"), to possess, use and operate
Seabrook in accordance with the conditions and requirements set forth in the
operating license.
CL&P, WMECO and PSNH are wholly-owned subsidiaries of NU. The primary
business of these three companies is the transmission, distribution and
generation of electric energy in the states of Connecticut, Massachusetts,
and New Hampshire, respectively. CL&P has ownership interests in the
Millstone and Seabrook units, WMECO has ownership interests in the Millstone
units, and PSNH has an ownership interest in Millstone 3.
NAEC is a wholly-owned, special-purpose operating subsidiary of NU that
owns a 35.98 percent interest in Seabrook, and sells its share of the
capacity and output from Seabrook to PSNH under two life-of-unit, full-cost
recovery contracts. NNECO and NAESCO are wholly-owned subsidiaries of NU.
They act as agents for NU affiliated companies and other New England entities
in operating the Millstone and Seabrook nuclear units, respectively, but have
no ownership interests.
The parent companies and the assignment of operating and ownership
responsibilities for the Indian Point, Millstone and Seabrook units as
described above have previously been recognized by the Commission.
Consolidated Edison Company of New York, Inc. is a wholly-owned subsidiary of
Consolidated Edison, Inc. ("CEI"). The restructuring leading to the
formation of CEI as the corporate parent of Indian Point 1 and 2 license
holder Consolidated Edison Company of New York, Inc. was approved by the NRC
in an Order dated December 4, 1997. NU was formed in 1966 with Millstone
license holders CL&P and WMECO as wholly-owned subsidiaries. The NRC
approved PSNH as a licensee of Millstone 3 in its January 31, 1986 order
authorizing full power operation of Millstone 3. The NRC approved CL&P as a
licensee of Seabrook in its March 15, 1990 order authorizing full power
operation of Seabrook. In two May 29, 1992 orders the NRC approved NAEC as
a licensee of Seabrook, and further authorized NAESCO to act as the managing
authority for Seabrook.
The purpose of this notification/application is to describe the proposed
merger transaction between CEI and NU pursuant to a merger agreement dated
October 13, 1999, and to the extent required by Section 184 of the Atomic
Energy Act, as amended, and 10 CFR Section 50.80, to seek the Commission's
consent to any indirect transfer of control of the operating licenses for the
referenced nuclear units that the Commission may deem associated with the
merger. The October 13, 1999 CEI/NU merger agreement provides for the
combination of CEI and NU to occur through two simultaneous mergers: the
merger of CEI into New CEI, a Delaware corporation, and the merger of an
indirect wholly-owned subsidiary of New CEI with NU. Upon the completion of
all of the related merger transactions New CEI will own all of the assets of
CEI (substantially all of which is the stock of its subsidiaries, including
Consolidated Edison Company of New York, Inc.), and NU will be a wholly-owned
subsidiary of New CEI. The related merger transactions are described in
more detail in the October 13, 1999 merger agreement which is appended to and
filed with this notification/application as an exhibit. A copy of the
merger Joint Proxy Statement will also be filed with the commission as a
further exhibit to this notification/application as soon as it is available.
The merged companies anticipate achieving significant cost savings and
efficiencies, principally through the consolidation of duplicative
activities, increased scale, and improved purchasing power. These changes
will reduce the operating costs of the merged companies to the benefit of
their customers, employees, shareholders and the communities they serve.
The merger will therefore enhance the licensees' financial resources to
possess and operate the Indian Point 1 and 2, Millstone 1, 2 and 3, and
Seabrook nuclear plants.
The merger will have no adverse effect on the management or operation of
the affected nuclear plants. The technical qualifications of the plant
operators -- Consolidated Edison Company of New York, Inc. for Indian Point 1
and 2, Northeast Nuclear Energy Company for Millstone 1, 2 and 3, and North
Atlantic Energy Service Corporation for Seabrook -- will not be diminished,
since the technical management and nuclear organizations currently
responsible for operating and maintaining these plants will not be changed as
a result of the merger and will remain responsible for their operation and
maintenance.
In addition to NRC review, the merger will be reviewed or approved by
numerous other federal and state agencies. Among the federal agencies
reviewing the merger are the Federal Energy Regulatory Commission ("FERC"),
the Securities and Exchange Commission ("SEC"), the U.S. Department of
Justice ("DOJ"), and the Federal Trade Commission ("FTC"). New CEI will be
required to register under Section 5 of the Public Utility Holding Company
Act within 30 days of the merger effective date, and will thereafter become
subject to the restrictions imposed on registered holding companies.
Among the matters that will be considered by these agencies are the
competitive aspects of the merger. The NRC need not undertake any
additional antitrust review related to the merger because (1) no such review
is necessary or appropriate in accordance with the Commission's decision in
Kansas Gas and Electric Company (Wolf Creek Generating Station, Unit 1), CLI-
99-19 (June 19, 1999), (2) the licensees do not seek any change to the terms,
conditions or provisions of the affected NRC licenses, (3) no significant
changes in the activities of the licensees have occurred since prior NRC
antitrust reviews, nor will any such changes occur as a result of the merger,
and (4) the competitive aspects of the merger will be thoroughly reviewed by
other federal agencies.
Part I below sets forth the information required by 10 CFR Section 50.80
pertaining to the proposed merger. Part II discusses the likely effective
date of the merger, and thus the desired timing of such review as the NRC
determines to conduct.
I. INFORMATION FOR TRANSFERS OF CONTROL
A. General Information Concerning Consolidated Edison Company of New York,
Inc.
1. Name and Address
Consolidated Edison Company of New York, Inc.
4 Irving Place
New York, New York 10003
2. Description of Business
Consolidated Edison Company of New York, Inc., is a wholly-owned
subsidiary of Consolidated Edison, Inc. ("CEI"), a New York corporation and
exempt holding company under the Public Utility Holding Company Act
("PUHCA"). CEI's stock is publicly held. Following the merger,
Consolidated Edison Company of New York, Inc. will be a wholly-owned
subsidiary of New CEI, which will succeed CEI. Consolidated Edison Company
of New York, Inc.'s principal business will remain the same as it is now,
which is to provide electric energy in New York City and Westchester County
to residential, commercial and industrial customers for their own use, and in
New York and elsewhere for resale.
3. Organization and Management
Consolidated Edison Company of New York, Inc. is, and after the merger
will remain, a corporation organized and existing under the laws of the State
of New York. All of Consolidated Edison Company of New York, Inc.'s
officers are citizens of the United States. All of the directors and
officers of CEI are also citizens of the United States.
Upon completion of the merger, New CEI and NU will be the surviving
companies, and the former holders of CEI and NU common stock will together
own all of the outstanding shares of common stock of New CEI. The merger
agreement contemplates that four members of the New CEI Board of Directors
will be recommended by NU, and that the remaining directors will be
designated by CEI. The merger agreement provides that Eugene R. McGrath
(Chairman, President and Chief Executive Officer of CEI) will be the Chairman
and Chief Executive Officer of New CEI. Michael G. Morris (Chairman and
Chief Executive Officer of NU) will become President of New CEI. Neither
CEI nor NU has designated the Board of Directors for New CEI, however all
members of the New CEI Board will be U.S. citizens. Once the Board members
have been nominated their names will be provided to the Commission.
Following the proposed merger New CEI will not be owned, controlled or
dominated, directly or indirectly, by an alien, foreign corporation or
foreign government. Consolidated Edison Company of New York, Inc. is not
acting as an agent or representative of any other person in this notification
of (or, to the extent deemed necessary by the NRC, application for consent
to) the proposed merger.
B. General Information Concerning Northeast Utilities
1. Name and Address
Northeast Utilities
174 Brush Hill Avenue
West Springfield, Massachusetts 01090
and
107 Selden Street
Berlin, Connecticut 06037
2. Description of Business
NU is a registered holding company under PUHCA. NU's stock is publicly
held. Following the proposed merger, NU will be a wholly-owned subsidiary
of New CEI. Its principal business will remain the same as it is now, which
is to provide through its subsidiaries and affiliates electric energy in the
states of Connecticut, Massachusetts and New Hampshire to residential,
commercial and industrial customers for their own use, and in these states
and elsewhere to wholesale customers for resale.
3. Organization and Management
NU is, and will remain after the merger, a business trust organized and
existing under the laws of the State of Massachusetts. All of NU's trustees
and officers are citizens of the United States.
Following the proposed merger NU will not be owned, controlled or
dominated by an alien, foreign corporation or foreign government. NU is not
acting as an agent or representative of any other person in this
notification/application.
C. Technical Qualifications
The proposed merger will have no adverse effect on either the management
organization or technical personnel of either: Consolidated Edison Company of
New York, Inc., the entity currently responsible for operating and
maintaining Indian Point 1 and 2; Northeast Nuclear Energy Company, the
entity currently responsible for operating and maintaining Millstone 1, 2 and
3; or North Atlantic Energy Service Corporation, the entity currently
responsible for operating and maintaining Seabrook. The technical
qualifications of these plant operating entities will be undiminished by the
merger since the current nuclear organizations and personnel will continue to
be responsible for the operation and maintenance of the affected nuclear
facilities after the merger. The merger may also present enhanced
opportunities to share specialized expertise and best practices among various
organizations.
The present Indian Point 1 and 2 organization consists of fifteen
departments staffed by Consolidated Edison Company of New York, Inc.
personnel: Operations, Maintenance, Radiation Protection, Nuclear Safety and
Licensing, Corrective Action Group, Site Engineering, Environmental Health
and Safety, Test and Performance, Nuclear Projects, Nuclear Training, Design
Engineering, Outage Planning, Configuration Management and Control, Reactor
and Fuel Engineering, and Emergency Planning. These departments report to
either the Consolidated Edison Company of New York, Inc. Vice President,
Nuclear Operations or the Consolidated Edison Company of New York, Inc. Vice
President, Nuclear Engineering, who in turn both report to the Consolidated
Edison Company of New York, Inc. Senior Vice President, Nuclear.
The merger does not involve any change in these reporting relationships.
The nuclear organization will continue to have well-delineated lines of
authority, and the technical and administrative competency of the
organization will not be changed as a consequence of the merger transaction.
Therefore, the technical qualifications of Consolidated Edison Company of New
York, Inc. to carry out its responsibilities under the Indian Point 1 and 2
operating licenses will not be adversely affected by the proposed merger.
The present Millstone 1, 2 and 3 organization consists of 15 departments
staffed by NNECO personnel: Business Services, Design Engineering, Employee
Concerns Program, Human Resources, Information Technology, Maintenance
Services, Materials & Document Control, Nuclear Communications, Nuclear
Engineering, Operations, Oversight & Regulatory Affairs, Plant Engineering,
Site Services, Training, Work Management, and a Millstone 1 decommissioning
organization. These departments report to either the NNECO Vice President -
Nuclear Operations, the NNECO Vice President - Nuclear Technical Services,
the NNECO Vice President - Nuclear Work Services, or the NNECO Vice
President, Human Services - Nuclear, who in turn all report to the NNECO
Senior Vice President & Chief Nuclear Officer. The NNECO Senior Vice
President & Chief Nuclear Officer in turn reports to the Chief Executive
Officer of NNECO, who also holds the NU title of President - Generation
Group.
The merger does not involve any change in these reporting relationships.
The NNECO organization will continue to have clear and direct lines of
responsibility and authority, and the overall technical and administrative
abilities of the organization will remain unchanged after the merger.
Therefore, the technical qualifications of NNECO to carry out its
responsibilities under the Millstone Units 1, 2 and 3 operating licenses will
not be adversely affected by the proposed merger.
In its May 29, 1992 order the Commission concluded that NAESCO is
technically qualified to operate Seabrook. The NAESCO organization consists
of three divisions: the Station, Engineering and Support Services. Each of
these divisions is headed by a Director who reports to the Executive Vice
President and Chief Nuclear Officer at Seabrook Station. Also reporting
directly to the Executive Vice President and Chief Nuclear Officer are
Nuclear Oversight and several other support departments such as Human
Resources and Organizational Development, and Environmental, Government and
Owner Relations.
After the merger, NAESCO will continue to serve as the managing agent
for Seabrook and the internal reporting relationships will be unchanged as a
result of the merger. The merger will not alter the staffing of NAESCO nor
its reporting relationship within NU in such a manner that the Commission's
earlier conclusion would be affected. The Executive Vice President and
Chief Nuclear Officer for Seabrook will continue to report directly to the
Chief Executive Officer of NAESCO, who also holds the NU title of President -
Generation Group, and will continue to operate under the oversight and
control of the Seabrook joint owners.
The merger will therefore leave fully intact the technical and
operational capabilities of the three nuclear operating organizations to
carry out their respective license obligations.
D. Financial Qualifications
The subsidiaries and affiliates of CEI and NU that currently possess
either operational or ownership responsibilities for the affected nuclear
plants are at present all electric utilities within the definition set forth
in 10 CFR Section 50.2, and the status of each such entity will remain
unchanged as a result of the merger. After the proposed merger Consolidated
Edison Company of New York, Inc. and the NU subsidiaries and affiliates
occupying an ownership and/or operational role with respect to the affected
nuclear plants will continue to recover their costs through rates authorized
by applicable state public utility commissions and by the FERC. As part of
electric industry restructuring initiatives, some or all of the affected
nuclear facilities may become increasingly dependent on operating revenues from
wholesale electric sales, however the timing and full extent of such
developments are currently uncertain, largely dependent on future events, and
unrelated to the proposed merger. The financial qualifications of each such
CEI and NU affiliate is presumed by 10 CFR Section 50.33(f) since the electric
utility status of each such entity under 10 CFR Section 50.22 is unaffected
by the merger.
E. Decommissioning Funding
NRC regulations require information showing "reasonable assurance . . .
that funds will be available to decommission the facility," 10 CFR Section
50.33(k). Consolidated Edison Company of New York, Inc., Northeast Nuclear
Energy Company and North Atlantic Energy Service Corporation have filed
decommissioning funding status reports with the NRC pursuant to 10 CFR Section
50.75(b) for the Indian Point 1 and 2, Millstone 1, 2 and 3, and Seabrook
nuclear plants, respectively, most recently as of March 31, 1999. Each CEI
and NU subsidiary and affiliate is providing financial assurance for
decommissioning their respective ownership interest(s) in the affected
nuclear plant(s) in accordance with those reports through external nuclear
decommissioning trusts into which deposits are made at least annually.
After the merger the applicable CEI and NU subsidiaries and affiliates will
remain responsible for the decommissioning liabilities associated with their
respective nuclear plant ownership interests, and will continue to fund their
respective decommissioning trusts in accordance with applicable NRC
regulations. Thus no change in current decommissioning funding practices
will occur as a result of the merger.
F. Antitrust Considerations
The licensees do not seek changes to any antitrust conditions contained
in the affected licenses, and are of the view that antitrust review by the
NRC associated with the merger is unnecessary. Recent developments
generally pertaining to FERC-mandated open-access tariffs requiring utilities
to provide unaffiliated entities with access to transmission lines on terms
comparable to owned generation have enhanced the ability of alternative
sources of generation to compete in markets where generation from the
affected nuclear plants is sold. The NRC has now determined that the
conduct of antitrust reviews subsequent to the initial issuance of operating
licenses is not required by the Atomic Energy Act, and that from both public
policy and legal perspectives such reviews should not be conducted, see
Kansas Gas and Electric Company (Wolf Creek Generating Station, Unit 1), CLI-
99-19 (June 18, 1999). The Commission's conclusions in Wolf Creek were to a
great extent driven by the recognition that antitrust reviews would as a
matter of course be conducted by other federal agencies. In connection with
the CEI/NU merger the approval of the FERC is necessary, and there will also
be review by the DOJ or FTC pursuant to the Hart-Scott-Rodino Antitrust
Improvements Act of 1976.
In sum, the proposed merger of CEI and NU will not result in any
significant changes in the competitive environments in which any of the
affected nuclear plants operate so as to require any further antitrust review
by the NRC in connection with the merger.
G. Restricted Data and Classified National Security Information
This notification/application does not contain any restricted data or
other classified defense information, and it is not expected that any such
data will be implicated in connection with the NRC's review of the proposed
merger. Were any such information to become involved, Consolidated Edison
Company of New York, Inc. and the affected subsidiaries and affiliates of NU
agree that they will appropriately safeguard such information consistent with
NRC determinations pursuant to 10 CFR Parts 25 and 95 that access by any
person will not endanger the common defense and security of the United
States.
H. No Environmental Impact
The Commission's regulations, at 10 CFR Section 51.22(c)(21), provide
that Commission consideration of direct or indirect transfers of a NRC
license are entitled to a categorical exclusion from environmental review.
Commission actions within the scope of the environmental categorical
exclusions require a showing of special circumstances before an environmental
review is appropriate. The CEI/NU merger fully qualifies as a categorical
exclusion under 10 CFR Section 51.22. However, even if this were not the
case, the complete absence of any environmental impacts is apparent. The
merger does not involve any changes to the operations of the affected nuclear
plants or equipment and does not change or modify any environmental impact
previously evaluated in the Final Environmental Statements for the affected
facilities. No amendments or changes to the operating licenses for the
plants are associated with the merger. Effectuation of the merger will not
result in any increase in the amounts, or a change in the types, of any
radiological or non-radiological effluents that may be allowed to be released
to the off-site environment. No increase in individual or cumulative
occupational radiation exposures is associated with the proposed merger.
Accordingly, this notification/application does not involve any significant
environmental impact warranting NRC review.
II. EFFECTIVE DATE
As noted, the proposed merger of CEI and NU is subject to DOJ or FTC
review pursuant to Hart-Scott-Rodino, and also requires the approval of other
federal regulatory authorities in addition to the NRC, including SEC and
FERC. Certain state regulatory filings will also be made either to provide
notice or to seek acknowledgement, endorsement or consent. Merger filings
will be made with the following state regulatory agencies:
the Connecticut Department of Public Utility Control,
the Maine Public Utilities Commission,
the Massachusetts Department of Telecommunications and Energy and the
Massachusetts Department of Revenue,
the New Hampshire Public Utilities Commission,
the New Jersey Board of Public Utilities,
the New York State Public Service Commission,
the Pennsylvania Public Utility Commission, and
the Vermont Public Service Board.
Approval by CEI's and NU's shareholders is also required. Until all of the
approvals deemed necessary by CEI and NU have been obtained, the merger
cannot be implemented.
CEI and NU intend to consummate the merger as soon as practicable after
all the requisite approvals have been obtained. The merger is currently
projected to close in mid-2000. Therefore, the NRC is requested to review
this notification/application on a schedule that will permit it to act as
promptly as possible on and provide its final merger consent to the extent
the NRC deems such consent to be necessary, and in any event no later than by
June 15, 2000. CEI and NU also request that such consent as the NRC may
deem necessary be immediately effective upon issuance and allow the merger to
be consummated at any time within twelve (12) months following the date of
such NRC consent in order to accommodate other regulatory approvals and
administrative activities associated with the merger.
CONCLUSION
For the foregoing reasons the NRC is requested to consider whether
pursuant to the Atomic Energy Act and the Commission's rules and regulations,
its consent is required for the merger of CEI and NU on the terms set forth
herein and in the accompanying merger agreement, and if such consent is
deemed necessary that it be granted on the bases set forth herein.
CERTIFICATION
I, John F. Groth, being duly sworn, state that:
(1) I am Senior Vice President, Nuclear, of Consolidated Edison Company of
New York, Inc.;
(2) I am duly authorized to execute and file this certification on behalf of
said company;
(3) The statements set forth in the attached notification/application are
true and correct to the best of my information, knowledge and belief.
John F. Groth
Sworn and subscribed to before me
this day of January, 2000.
Notary Public
CERTIFICATION
I, Bruce D. Kenyon, being duly sworn, state that:
(1) I am President - Generation Group of Northeast Utilities;
(2) I am duly authorized to execute and file this certification on behalf of
said company;
(3) The statements set forth in the attached notification/application are
true and correct to the best of my information, knowledge and belief.
Bruce D. Kenyon
Sworn and subscribed to before me
this day of January, 2000.
Notary Public
EXHIBIT h.1
FORM OF NOTICE
SECURITIES AND EXCHANGE COMMISSION
(Release No. 35- )
Filings Under the Public Utility Holding Company Act of 1935 ("Act").
June xx, 2000
Notice is hereby given that the following filings has/have been made
with the Securities and Exchange Commission (the "Commission") pursuant to
provisions of the Act and rules promulgated thereunder. All interested
persons are referred to the application(s) and/or declaration(s) for complete
statements of the proposed transaction(s) summarized below. The
application(s) and/or declaration(s) and any amendments thereto is/are
available for public inspection through the Commission's Office of Public
Reference.
Interested persons wishing to comment or request a hearing on the
application(s) and/or declaration(s) should submit their views in writing by
July xx, 2000 to the Secretary, Securities and Exchange Commission,
Washington, D.C. 20549, and serve a copy on the applicant(s) and/or
declarant(s) at the address(es) specified below. Proof of service (by
affidavit or, in case of an attorney at law, by certificate) should be filed
with the request. Any request for hearing shall identify specifically the
issues of fact or law that are disputed. A person who so requests will be
notified of any hearing, if ordered, and will receive a copy of any notice or
order issued in the matter. After said date, the application(s) and/or
declaration(s), as filed or as amended, may be granted and/or permitted to
become effective.
CONSOLIDATED EDISON, INC. (File 70-9613)
Consolidated Edison, Inc. ("New CEI") 4 Irving Place, New York, N.Y.,
10003, a Delaware Corporation currently not a public utility holding company,
Consolidated Edison, Inc. ("CEI"), a New York corporation, 4 Irving Place,
New York, N.Y., 10003, a gas and electric holding company exempt from
registration under the Public Utility Holding Company Act of 1935 (the "Act")
and Northeast Utilities, 174 Brush Hill Avenue, West Springfield, MA 01090, a
registered gas and electric public utility holding company ("NU") have filed
an application/declaration (the "Application") under sections 6(a), 7, 8,
9(a), 10 and, by reference, Section 11 and Rule 58 under the Act.
The Application seeks approvals relating to the proposed combination of
CEI and NU under New CEI. Under the proposal, CEI will merge with and into
New CEI, which is currently a wholly-owned subsidiary of CEI, with New CEI
being the surviving entity, and NU will merge with N Acquisition LLC, a
Massachusetts limited liability company controlled by New CEI, with NU being
the surviving entity, all as set forth in an Amended and Restated Agreement
and Plan of Merger dated as of January 11, 2000 (the "Merger Agreement").
Upon consummation of the merger, (i) the holders of CEI's common shares and
NU's common shares will together own all of New CEI's outstanding shares of
common stock, (ii) New CEI will register as a public utility holding company
under the Act, (iii) New CEI will own all of the assets of CEI and (iv) NU
will be a wholly-owned subsidiary of New CEI and continue to be registered
under the Act.
CEI is a public utility holding company for Consolidated Edison Company
of New York, Inc. ("CECONY") and Orange and Rockland Utilities, Inc. ("O&R"),
and certain non-utility subsidiaries and is not itself an operating company.
CEI is exempt from all provisions of the Act by virtue of Section 3(a)(1)
except for Section 9(a)(2) thereof. CECONY provides electric service and
natural gas service to customers in New York City and Westchester County.
CECONY also supplies steam service to customers in parts of Manhattan. O&R
provides electric service and natural gas service to customers in
southeastern New York State and, through its public utility subsidiaries,
Pike County Light and Power Company and Rockland Electric Company, adjacent
sections of Pennsylvania and New Jersey. O&R is exempt from all provisions
of the Act by virtue of Section 3(a)(2) except for Section 9(a)(2) thereof.
As of March 31, 2000, CEI had total assets of $15.5. billion and had
operating revenues for the 12-month period ending March 31, 2000 of
approximately $8 billion, and had approximately 3.2 million electric utility
customers in New York, New Jersey and Pennsylvania and 1.1 million gas
utility customers in New York, Pennsylvania and New Jersey. CEI also holds
various nonutility companies engaged in various energy related activities.
Northeast Utilities is the parent of a number of companies comprising
the Northeast Utilities system (the "System") and is not itself an operating
company. The System furnishes franchised retail electric service in
Connecticut, New Hampshire and western Massachusetts through three of NU's
wholly-owned subsidiaries, The Connecticut Light and Power Company ("CL&P"),
Public Service Company of New Hampshire ("PSNH") and Western Massachusetts
Electric Company ("WMECO"), and additionally furnishes retail electric
service to a limited number of customers through another wholly-owned
subsidiary, Holyoke Water Power Company ("HWP"), doing business in and around
Holyoke, Massachusetts. In addition to their retail electric service
business, CL&P, PSNH, WMECO and HWP (including its wholly-owned subsidiary,
Holyoke Power and Electric Company) (collectively, the "NU Operating
Companies") together furnish wholesale electric service to various
municipalities and other utilities throughout the Northeast. The System
serves approximately 30 percent of New England's electric needs. As of March
31, 2000, NU had total assets of $9.8 billion (not including YES assets) and
had total revenues for the 12-month period ending March 31, 2000 of $4.8
billion and had approximately 1.7 million electric utility customers in
Connecticut, Massachusetts and New Hampshire. NU also holds various
nonutility companies engaged in various energy related activities.
In addition, in March, 2000, Yankee Energy System, ("YES"), a gas
utility holding company merged with and into NU. YES is a public utility
holding company incorporated in Connecticut. In addition to being the
holding company for Yankee Gas, it also is the holding company for four
active non-utility subsidiaries, NorConn Properties, Inc. ("NorConn"), Yankee
Energy Financial Services Company ("Yankee Financial"), Yankee Energy
Services Company ("YESCo") and R.M. Services, Inc. ("RMS"). YES had total
assets of $926.3 million for the period ended March 31, 2000 and total
revenues for the 12-month period ended March 31, 2000 of $327.1 million and
served approximately 185,000 customers in Connecticut
After the Merger is consummated, New CEI will be a registered public
utility holding company under the Act. It will own, directly, two public
utilities, O&R and CECONY, a public utility holding company, NU, and various
nonutility subsidiaries. O&R will also own two public utilities, Pike and
RECO, and various nonutility subsidiaries. O&R will remain an exempt holding
company under Section 3(a)(2) of the Act. NU will continue as a registered
public utility holding company under the Act and will own, directly, five
public utilities, WMECO, CL&P, PSNH, NAEC and HWP, along with various other
non-utility subsidiaries. NU will also own, directly, YES, which will be an
exempt public utility holding company under the Act which will own one public
utility, Yankee Gas, and various other nonutility subsidiaries. The combined
system will provide electric service to parts of New York, Pennsylvania, New
Jersey, Connecticut, Massachusetts and New Hampshire and gas service to parts
of Connecticut, New York, and Pennsylvania.
Under the Merger Agreement, (i) CEI will merge into New CEI, with New
CEI being the surviving corporation, and (ii) N Acquisition LLC, a
Massachusetts limited liability company controlled by CEI, will merge with
and into NU, with NU being the surviving entity. Upon completion of the
Merger, the holders of CEI common shares and NU common shares will together
own all of New CEI's outstanding shares of common stock, New CEI will own all
of the assets of CEI and NU will be a wholly-owned subsidiary of New CEI.
The Merger Agreement provides that NU shareholders may elect to receive,
for each NU common share they own, a fraction (the "Exchange Ratio") of a
share of New CEI common stock equal to a numerator of $25.00 divided by the
weighted average trading price of a CEI common share over 20 trading days
randomly selected from the 40 trading days ending five trading days prior to
the closing. However, the CEI share price used to calculate the Exchange
Ratio will not be less than $36.00 nor greater than $46.00. Also, $1.00 will
be added to the numerator if, prior to the closing of the Merger, certain NU
subsidiaries enter into binding agreements to sell to one or more non-
affiliated third parties their respective interests in the Millstone Station
Unit 2 and Millstone Station Unit 3 nuclear power plant assets, in
accordance, in all material respects, with applicable law and the rules and
regulations of the Connecticut Department of Public Utility Control ("DPUC")
for approval of such agreements and (x) the Utility Operations and Management
Unit of the DPUC has submitted a formal written recommendation to the DPUC
for approval of the agreements or (y) the DPUC has issued a final order
approving the agreements (the "divestiture condition"). In addition, in the
event the Merger does not close by August 5, 2000, $.0034 will be added to
the numerator for each day after August 5, 2000 through the day prior to the
closing of the Merger.
In the alternative, holders of NU common shares may elect to receive
cash consideration equal to $25.00 per NU common share, provided that an
additional $1.00 per share will be payable if, prior to the closing of the
Merger, NU satisfies the divestiture condition and an additional $.0034 per
share will be payable for every day after August 5, 2000 through the day
prior to the closing of the Merger.
If the Merger closes on or prior to December 31, 2000, and the
divestiture condition has not been satisfied but thereafter and on or prior
to December 31, 2000, NU satisfies the divestiture condition, then each NU
shareholder (whether the shareholder elected stock or cash consideration)
will be entitled to $1.00 per converted NU common share to be paid in cash by
New CEI.
The Merger Agreement is subject to customary mutual closing conditions
such as approval by the CEI and NU shareholders, absence of legal
prohibitions on completion of the Merger, New CEI's registration statement on
Form S-4 not being subject to any stop order or proceeding seeking a stop
order, and approval for listing on the New York Stock Exchange of the shares
of New CEI common stock to be issued in the Merger, subject to official
notice of issuance. In addition, the Merger Agreement is subject to customary
closing conditions specific to each party, such as the accuracy of the
representations and warranties given by the other party, the absence of a
material adverse change in the financial condition of the other party and
receipt of all regulatory approvals.
The Merger Agreement also contains certain covenants relating to the
conduct of business by NU pending the consummation of the Transaction, which
are customarily contained in merger transactions generally. Among other
things, NU must carry on its business in the ordinary course consistent with
past practice, and may not increase dividends beyond specified levels or
issue capital stock, all except as otherwise specified. The Merger Agreement
also contains customary restrictions on, among other things, charter and
bylaw amendments, capital expenditures, acquisitions, dispositions,
incurrence of indebtedness and certain increases in employee compensation and
benefits and affiliate transactions.