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)
<http://www.nyiso.com/services/documents/b-and-a/tsc/tscsmmry.csv>.
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.
