File No. 70-9495
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Amendment No. 2 to
FORM U-1
UNDER THE
PUBLIC UTILITY HOLDING COMPANY ACT OF 1935
NSTAR
c/o BEC ENERGY
800 Boylston Street
Boston, MA 02199
(Name of companies filing this statement and
address of principal executive offices)
None
- --------------------------------------------------------------------------------
(Name of top registered holding company
parent of each applicant or declarant)
Thomas J. May
Chairman of the Board and Chief Executive Officer
Russell D. Wright
President and Chief Operating Officer
NSTAR
c/o BEC Energy
800 Boylston Street
Boston, MA 02199
- --------------------------------------------------------------------------------
(Name and address of agents for service)
The Commission is requested to mail copies of
all orders, notices and communications to:
Theodora S. Convisser, Esq. Michael P. Sullivan, Esq.
Clerk and Assistant General Vice President, General
Counsel Counsel and Secretary
BEC Energy Commonwealth Energy System
800 Boylston Street One Main Street
Boston, Massachusetts 02199 Cambridge, Massachusetts
02142-9150
Paul K. Connolly, Jr., Esq.
Timothy E. McAllister, Esq.
LeBoeuf, Lamb, Greene & MacRae, L.L.P
260 Franklin Street
Boston, Massachusetts 02110
<PAGE>
This pre-effective Amendment No. 2 amends the Form U-1 Application in this
proceeding, originally filed with the Securities and Exchange Commission on
March 26, 1999, as follows:
(1) Item 3.B.2 is amended by deleting the ninth paragraph thereof (added in
Amendment No. 1, filed with the Securities and Exchange Commission on July 9,
1999), and substituting therefor the following two paragraphs:
Although NEPOOL's historical function has recently changed with the
advent of the independent system operator, ISO-New England and the
development of the Restated NEPOOL Agreement, it may still be characterized
as a "tight" power pool whose objective is to assure adequate reliability
in the bulk electric power supply of New England by coordinating the
dispatch of generation resources and the planning of transmission resources
of its members. Through an agreement with NEPOOL, ISO-New England operates
in an independent, non-discriminatory manner to dispatch generation
resources in the New England control area using a bid-based system, instead
of the previous cost-based dispatch method. Generally, the procedure is
that generators submit bid prices to ISO-New England a day ahead and, based
on that information as well as load forecasts, ISO-New England will
determine which generation resources will be dispatched, ramped up or
ramped down throughout the course of the following day. Further, ISO-New
England has the ability to impose rules on generators throughout NEPOOL to
the extent required to ensure the continued efficient operation of the
energy market. Although the factors influencing the dispatch decisions have
changed, all generation resources in NEPOOL continue to be dispatched on a
coordinated basis by ISO-New England.
Further, through the Restated NEPOOL Agreement, NEPOOL continues to be
responsible for the development of a regional transmission tariff which
provides for open non-discriminatory access to the New England transmission
system. The tariff, approved by the FERC and administered by ISO-New
England through its agreement with NEPOOL, provides for access to and use
of all NEPOOL participants' pool transmission facilities, or "PTF." In
addition, each transmission owning utility in New England has its own open
access transmission tariff on file with the FERC, thus ensuring
non-discriminatory access to each non-PTF transmission system within New
England. Therefore, the generation and transmission resources of electric
utilities within New England continue to be operated as a single
interconnected and coordinated system through their participation in
NEPOOL.
(2) Amend Item 6 to add the following exhibits.
A. Exhibits
<PAGE>
D-2 Massachusetts Order
D-6 NRC Order
D-8 NRC Order
SIGNATURE
Pursuant to the requirements of the Public Utility Holding Company Act of
1935, the undersigned company has duly caused this Application to be signed on
its behalf of the undersigned thereunto duly authorized.
Date: August 23, 1999 NSTAR
By: /s/ Russell D. Wright
-----------------------------
President and Chief Operating
Officer
D.T.E. 99-19 July 27, 1999
Joint Petition of Boston Edison Company, Cambridge Electric Light Company,
Commonwealth Electric Company and Commonwealth Gas Company for approval by the
Department of Telecommunications and Energy pursuant to G.L. c. 164, ss. 94 of a
Rate Plan.
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APPEARANCES: Douglas S. Horan, Esq.
Boston Edison Company
800 Boylston Street
Boston, Massachusetts 02199
FOR: BOSTON EDISON COMPANY
Petitioner
and
Michael P. Sullivan, Esq.
John Cope-Flanagan, Esq.
COM/Energy Services Company
One Main Street
P.O. Box 9150
Cambridge, Massachusetts 02142-9150
FOR: CAMBRIDGE ELECTRIC LIGHT COMPANY COMMONWEALTH ELECTRIC COMPANY
COMMONWEALTH GAS COMPANY
Petitioners
and
Robert J. Keegan, Esq.
Robert N. Werlin, Esq.
Keegan, Werlin & Pabian, L.L.P.
21 Custom House Street
Boston, Massachusetts 02110
FOR: BOSTON EDISON COMPANY
CAMBRIDGE ELECTRIC LIGHT COMPANY COMMONWEALTH ELECTRIC COMPANY
COMMONWEALTH GAS COMPANY
Joint Petitioners
Thomas J. Reilly, Attorney General
By: George B. Dean, Assistant Attorney General
John Grugan, Assistant Attorney General
200 Portland Street
Boston, Massachusetts 02114
Intervenor
Kevin M. Nasca, Esq.
Anna Y. Blumkin, Esq.
Division of Energy Resources
100 Cambridge Street, Room 1500
Boston, Massachusetts 02202
FOR: COMMONWEALTH OF MASSACHUSETTS, DIVISION OF ENERGY RESOURCES
Intervenor
Jeffrey M. Bernstein, Esq.
Charles Harak, Esq.
Bernstein, Cushner & Kimmell, P.C.
One Court Street, Suite 700
Boston, Massachusetts 02108
FOR: CAPE LIGHT COMPACT AND
CONSTITUENT MUNICIPALITIES
Intervenors
John A. DeTore, Esq.
Maribeth Ladd, Esq.
Rubin & Rudman
50 Rowes Wharf
Boston, Massachusetts 02110-3319
FOR: MASSACHUSETTS INSTITUTE OF TECHNOLOGY AND PRESIDENTS AND FELLOW OF
HARVARD COLLEGE
Intervenors
Robert Ruddock, Esq.
Judith Silvia, Esq.
Associated Industries of Massachusetts
222 Berkeley Street, P.O. Box 763
Boston, Massachusetts 02117
FOR: ASSOCIATED INDUSTRIES OF MASSACHUSETTS
Intervenor
Bryan C. Decker, Esq.
Pyle, Rome & Lichten
90 Canal Street, 4th Floor
Boston, Massachusetts 02108
FOR: UNITED STEELWORKERS OF AMERICA
LOCAL 12004
Intervenor
Bruce Paul
42 Labor-In-Vain Road
Ipswich, Massachusetts 01938-2626
FOR: THE ENERGY CONSORTIUM
Intervenor
David A. Fazzone, Esq.
Doron F. Ezickson, Esq.
Laura S. Olton, Esq.
Emily E. Smith-Lee, Esq.
McDermott, Will & Emery
75 State Street
Boston, Massachusetts 02109
FOR: EASTERN EDISON COMPANY
Limited Participant
Stephen Klionsky, Esq.
260 Franklin Street, 21st Floor
Boston, Massachusetts 02110-3179
FOR: WESTERN MASSACHUSETTS ELECTRIC COMPANY
Limited Participant
Thomas G. Robinson, Esq.
Amy G. Rabinowitz, Esq.
New England Power Service Company
25 Research Drive
Westborough, Massachusetts 01582-0099
FOR: MASSACHUSETTS ELECTRIC COMPANY
Limited Participant
I. INTRODUCTION Page 1
II. PROCEDURAL HISTORY Page 1
III. DESCRIPTION OF THE PROPOSED RATE PLAN Page 3
IV. STANDARD OF REVIEW Page 7
V. RATE PLAN Page 13
A. Four-Year Base Rate Freeze Page 13
1. Joint Petitioners' Proposal Page 13
2. Intervenors' Proposals Page 13
a. Attorney General Page 13
b. DOER Page 14
c. MIT/Harvard Page 15
3. Positions of the Parties Page 16
a. Attorney General Page 16
b. DOER Page 17
c. MIT/Harvard Page 18
d. AIM Page 19
e. Joint Petitioners Page 20
4. Analysis and Findings Page 22
B. Cambridge Electric and ComElectric Rate Adjustments Page 27
1. Introduction Page 27
2. Joint Petitioners' Proposal Page 28
3. Positions of the Parties Page 29
a. MIT/Harvard Page 29
b. Joint Petitioners Page 30
4. Analysis and Findings Page 31
VI. COSTS TO ACHIEVE MERGER Page 33
A. Transaction and System Integration Costs Page 33
1. Joint Petitioners' Proposal Page 33
2. Positions of the Parties Page 36
a. Attorney General Page 36
b. DOER Page 36
c. AIM Page 37
d. Joint Petitioners Page 37
3. Analysis and Findings Page 37
a. Transaction and Regulatory Costs Page 37
b. System Integration Costs Page 41
c. Accounting Deferral Page 45
B. Acquisition Premium Page 46
1. Joint Petitioners' Proposal Page 46
2. Intervenors' Proposals Page 47
a. DOER Page 47
b. MIT/Harvard Page 48
3. Positions of the Parties Page 49
a. Attorney General Page 50
b. DOER Page 50
c. MIT/Harvard Page 53
d. AIM Page 54
e. Joint Petitioners Page 55
4. Analysis and Findings Page 56
C. Merger-Related Savings Page 62
1. Introduction Page 62
2. Positions of the Parties Page 66
a. Attorney General Page 66
b. DOER Page 67
c. AIM Page 67
d. Joint Petitioners Page 67
3. Analysis and Findings Page 68
D. Recovery of Merger-Related Costs Page 73
1. Joint Petitioners' Proposal Page 73
2. Positions of the Parties Page 74
a. Attorney General Page 74
b. DOER Page 75
c. MIT/Harvard Page 76
d. AIM Page 78
e. Joint Petitioners Page 80
3. Analysis and Findings Page 81
E. Allocation Issues Page 86
1. Joint Petitioners' Proposal Page 86
2. Positions of the Parties Page 89
a. Attorney General Page 89
b. DOER Page 89
c. MIT/Harvard Page 90
d. AIM Page 90
e. Joint Petitioners Page 90
3. Analysis and Findings Page 91
VII. SERVICE QUALITY PLAN Page 94
A. Joint Petitioners' Proposal Page 94
B. Position of the Parties Page 97
1. Attorney General Page 97
2. MIT/Harvard Page 97
3. AIM Page 97
4. Joint Petitioners Page 97
C. Analysis and Findings Page 99
1. Introduction Page 99
2. Performance Measures Page 100
3. Performance Benchmarks Page 102
4. Penalty Mechanism Page 106
VIII. CONFIRMATION OF FRANCHISE RIGHTS Page 107
A. Introduction Page 107
B. Analysis and Findings Page 108
IX. ORDER Page 108
I. INTRODUCTION
On February 1, 1999, Boston Edison Company ("Boston Edison"),(1) Cambridge
Electric Light Company ("Cambridge Electric"), Commonwealth Electric Company
("ComElectric") and Commonwealth Gas Company ("ComGas")(2) (together, "Joint
Petitioners") filed a petition for approval by the Department of
Telecommunications and Energy ("Department") of a rate plan pursuant to G.L. c.
164, ss. 94 ("Rate Plan"). The first three named Joint Petitioners are "electric
companies" within the meaning of G.L. c. 164, ss. 1; the fourth named is a "gas
company" within the meaning of G.L. c. 164, ss. 2. The Rate Plan is filed in
conjunction with the merger of the Joint Petitioners' parent companies, BEC
Energy and Commonwealth Energy System ("ComEnergy System"). The parent will,
upon merger, be called "Nstar," a Massachusetts business trust (Exh. JJJ-2
(Supp.) at 1; Tr. 6, at 664). In addition, the Joint Petitioners requested that
the Department determine that no transfer of the franchise rights of Boston
Edison, Cambridge Electric, ComElectric, or Commonwealth Gas will result from
the merger and related transactions, and therefore, no approval by the
Massachusetts General Court is required under G.L. c. 164, ss. 21. The
Department docketed this matter as D.T.E. 99-19.
II. PROCEDURAL HISTORY
Pursuant to notice duly issued, the Department conducted public hearings on
March 8, 1999 in Cambridge, March 9, 1999, in Hyannis, and March 10, 1999, in
Framingham. The Attorney General of the Commonwealth of Massachusetts ("Attorney
General") filed a Notice of Intervention pursuant to G.L. c. 12, ss. 11E. The
Department allowed the petitions to intervene of the Commonwealth of
Massachusetts Division of Energy Resources ("DOER"), Associated Industries of
Massachusetts ("AIM"), Cape Light Compact and Constituent Municipalities ("Cape
Light Compact"), the Energy Consortium ("TEC"), Massachusetts Institute of
Technology and President and Fellows of Harvard College (together
"MIT/Harvard"), and the United Steelworkers of America, Local 12004. In
addition, the Department allowed the petitions to participate as limited
participants of Eastern Edison Company, Massachusetts Electric Company, and
Western Massachusetts Electric Company.
The Department conducted evidentiary hearings from April 22, 1999 through May
11, 1999. The Joint Petitioners presented five witnesses: Thomas J. May,
president and chief executive officer of BEC Energy and Boston Edison; Russell
D. Wright, chief executive officer of ComEnergy System; James J. Judge, senior
vice president and treasurer of Boston Edison; Thomas J. Flaherty, national
partner of Energy Consulting and a partner in the Deloitte & Touche Consulting
Group, LLC; and John Scott Magrane, Jr., vice president in the energy and power
group of Goldman Sachs & Co.
The Attorney General presented two witnesses: Seabron Adamson, president of
London Economics, Inc.; and Raymond Hartman, director of Cambridge Economics,
Inc. Richard La Capra, principal of La Capra Associates, testified on behalf of
DOER, and MIT/Harvard offered the testimony of Sheree L. Brown, president of
SVBK Consulting Group.
The evidentiary record consists of over 400 exhibits, including responses to
information requests and record requests (Tr. 10, at 1276-1290), and the
testimony presented at the evidentiary hearings. Initial briefs were filed by
the Joint Petitioners, Attorney General, DOER, MIT/Harvard, and AIM. Reply
briefs were filed by the Joint Petitioners, DOER, MIT/Harvard, and AIM. The
Attorney General filed no reply brief. In addition, TEC filed written comments.
III. DESCRIPTION OF THE PROPOSED RATE PLAN
The Rate Plan has been proposed as part of a merger between BEC Energy and
ComEnergy System into a new holding company, Nstar.(3) Holders of BEC Energy and
ComEnergy System common shares will exchange their shares for a combination of
cash and stock in Nstar (Exhs. JJJ-2, at 2-10; JSM-1, at 7).(4) For those
shareholders who elect to exchange their shares for cash, $200 million dollars
will be allocated to BEC Energy shareholders and $100 million will be allocated
to ComEnergy System shareholders (Exhs. JJJ-1, at 2-3; JSM-1, at 7). The cash
portion of the transaction is expected to be financed primarily through current
cash balances and internally generated funds (Exh. JSM-1, at 7). At the close of
the merger, current BEC Energy shareholders are projected to own approximately
68 percent of Nstar's common stock and current ComEnergy System shareholders are
projected to own approximately 32 percent of Nstar's common stock (id.).
The Rate Plan has three major elements: (1) a four-year freeze in distribution
rates for the Joint Petitioners from the date of the consummation of the
merger;(5) (2) the recovery of merger related costs; and (3) a service-quality
plan (Exh. RDW-1, at 9). The Rate Plan affects only the distribution rates
because the other components of customer bills either are reconciling components
(i.e., costs for which dollar-for-dollar recovery is permitted) or lie outside
the Department's jurisdiction (Exh. JJJ-1, at 5-6). Accordingly, for Boston
Edison, Cambridge Electric, and ComElectric, the transition costs, transmission
services,(6) standard offer service, and default service charges are not covered
by the Rate Plan and will not be affected by the rate freeze (id.). Similarly
for ComGas, reconciling rate elements, like the cost of gas adjustment clause
and local distribution adjustment clause (see Bay State Gas Company, D.P.U.
95-104 (1995); Boston Gas Company, D.P.U. 93-60, at 267 (1993)), are not
included in the Rate Plan and are not covered by the rate freeze (id.).(7) The
existing retail distribution rates for Cambridge Electric and ComElectric under
the Rate Plan will be adjusted to include the demand-side management ("DSM") and
renewable-energy charges that were mandated as part of the Electric
Restructuring Act of 1997 ("Act")(8) (Exh. RDW-1, at 11).
The proposed Rate Plan will freeze distribution rates for a period of four years
(Exh. RDW-1, at 10-11). Following the expiration of the rate freeze,
distribution rates established by the Department in any base rate proceeding
would account for savings gained as a result of the merger, net of the recovery
of merger-related costs. There are three general categories of costs that will
be incurred to realize the benefits of the merger: (1) transaction costs
incurred in developing, executing, and obtaining the necessary approvals for the
merger; (2) system integration costs incurred to achieve the synergies
anticipated from the merger; and (3) the cost to BEC Energy's shareholders
associated with the merger; i.e., the premium over book value received by
ComEnergy System's shareholders ("acquisition premium")(9) (Exhs. JJJ-1, at 4-5;
TJF-5U). The precise amount of the acquisition premium will not be determined
until the closing of the merger because the structure of the transaction
involves an exchange ratio of 1.05 Nstar shares for each share of ComEnergy
System and because ComEnergy System's book value is subject to change between
the dates of the agreement to merge and the actual closing (Exh. JJJ-1, at
4).(10) Similarly, the exact amount of the transaction costs will not be known
until the merger is completed.(11)
The costs associated with the merger will be recovered in two ways. Under the
Rate Plan, transaction and system integration costs will be amortized for
ratemaking purposes over a ten-year period and the acquisition premium will be
amortized over a 40-year period.(12) While the transaction costs and most of the
system integration costs will be expended during the first three years, some
portion of the system integration costs will be incurred in subsequent years
(Exh. TJF-4). For ratemaking purposes,(13) the Rate Plan includes an
amortization of $13.5 million per year in transaction, system integration costs,
and associated tax effects over a period of ten years (Tr. 8, at 1040-1042). The
Joint Petitioners stated that the amortization level is subject to adjustment in
future rate proceedings if the actual transaction and system integration costs
deviate from the projected levels in later years (Tr. 8, at 1040-1042).
Similarly, the Rate Plan includes an amortization of $20.6 million per year for
40 years for the acquisition premium (Exh. JJJ-1, at 9).
Based on the estimates of merger-related costs, during the first ten years after
the merger, the average amount and associated tax effect of merger-related costs
will be approximately $34.1 million per year ($20.6 million for the amortization
of the acquisition premium plus $13.5 million for amortization of the
transaction and system integration costs) (Exh. JJJ-1, at 9). During the
subsequent 30-year period, after recovery of the transaction costs is completed,
the annual amortization of the remaining unamortized acquisition premium and
associated tax effect will total approximately $20.6 million (id.).
The final element of the Joint Petitioners' proposal is the implementation of a
service quality plan to ensure, consistent with Department precedent, that there
will be no degradation of service as a result of the merger. The Joint
Petitioners propose to track and monitor service quality in a number of areas,
to demonstrate that the level of service quality will not be adversely affected
by the merger (Exhs. RDW-1, at 19-21; RDW-6; JJJ-1, at 15-16; JJJ-3).
IV. STANDARD OF REVIEW
The petition before the Department is unlike those considered in Eastern-Essex
Acquisition, D.T.E. 98-27 (1998), NIPSCO/Bay State Acquisition, D.T.E. 98-31
(1998), or Eastern-Colonial Acquisition, D.T.E. 98-128 (1999). The instant
petition arises from a merger of two Massachusetts business trusts that are sole
owners of four regulated utilities. That merger transaction does not fall
directly under G.L. c. 164, ss. 96; but it does have G.L. c. 164, ss. 96
implications, because of the resultant request to push the acquisition premium
onto the books of the regulated subsidiaries and because of the associated Rate
Plan offered for G.L. c. 164, ss. 94 approval. This petition requires some
degree of adaptation of our standard of review to deal with the circumstances
presented by this case. Such adaptation is warranted because the public interest
standard underlies both Sections 94 and 96 of Chapter 164.
The petition seeks G.L. c. 164, ss. 94 approval of a Rate Plan designed as a
component of an overall merger of two holding companies. The Rate Plan makes
specific provision for the recovery of the costs to be incurred in completing
the merger, including transaction costs, acquisition premiums, and system
integration expenses. The Joint Petitioners consider the Rate Plan to be a
fundamental component of the merger. They argue that it is appropriate for the
Department to apply the public interest standard associated with G.L. c. 164,
ss. 96 merger petitions in evaluating the Rate Plan (Exh. TJM-1, at 12). We
agree. An evaluation of the Rate Plan in a merger context necessitates an
examination of those features of the Rate Plan that are intended to provide for
recovery of the costs associated with the merger. Accordingly, in making a
determination pursuant to G.L. c. 164, ss. 94 whether the rates that would
result from the Rate Plan are just and reasonable and in the public interest,
the Department's judgment is informed by the G.L. c. 164, ss. 96 public interest
standard.
The public interest standard is statutorily explicit in G.L. c. 164, ss. 96 and
lies at the heart of G.L. c. 164, ss. 94 by judicial construction. Although the
public interest standard is also explicit in G.L. c. 164, ss. 94's provisions
for review of contracts for sale of gas and electricity, G.L. c. 164, ss. 94
speaks generally in terms of the "propriety of rates." The Department has
considerable discretion in assessing the "propriety" of rate petitions submitted
under G.L. c. 164, ss. 94; and the Court has often so held. See American
Hoechest Company v. Department of Public Utilities; 379 Mass. 408, 411, 412, 413
(1980) (Department free to select or reject particular method of regulation as
long as choice not confiscatory or otherwise illegal). The Supreme Judicial
Court has construed G.L. c. 164, ss. 94 as requiring a public interest judgment
by the Department in a number of cases: Massachusetts Oilheat Council v.
Department of Public Utilities, 418 Mass. 798, 804 (1994); Boston Real Estate
Board v. Department of Public Utilities, 334 Mass. 477, 495 (1956) ("[t]he
controlling consideration of the [D]epartment's statutory regulatory powers is
implicit throughout the statute. It is the standard which supports the grant of
power over rates and regulations in general and it is not necessary to specify
further"); Massachusetts Institute of Technology v. Department of Public
Utilities, 424 Mass. 856, 867 (1997) ("we concur that the recovery of prudent
and verifiable stranded costs incurred by utility companies, as appropriately
authorized, is in the public interest."). See also Wolf v. Department of Public
Utilities, 407 Mass. 363, 369 (1990) ("the mission of the agency is to regulate
in the public interest," citing Zachs v. Department of Public Utilities, 406
Mass. 217, 223-224 (1989)). Recent Department orders also apply a public
interest standard in G.L. c. 164, ss. 94 cases: Tewksbury LNG, D.P.U. 97-49, at
27-28 (1997); Fitchburg Gas and Electric Light Company Energy Bank, D.P.U.
95-75, at 9 (1995); and Cambridge Electric Light Company, D.P.U. 94-101/95-36,
at 8 (1995).
The corporate consolidation proposed here results in the ownership and operation
of four utilities ultimately by a single business trust. The creation of Nstar
and the mergers of ComEnergy System and BEC Energy into Nstar-owned holding
companies occurs outside the purview of G.L. c. 164, ss. 96, but the effects of
the Rate Plan fall squarely under G.L. c. 164, ss. 94. The situation exhibits
certain features that make it one of first impression. Because "the mission of
the agency is to regulate in the public interest," Wolf, 407 Mass. at 369, we
craft and apply a standard that amalgamates both G.L. c. 164, ss.ss. 94 and 96's
kindred public interest requirements. Where statutes of general application
allow a broad range of regulatory discretion but do not speak in particularized
terms to an instant case, the Court has recognized that "the decision regarding
what standard to apply is left to the [D]epartment's discretion." Wolf, 407
Mass. at 370 (in the parallel context of G.L. c. 159).
Where a rate proposal is presented that differs from past procedures, the
Department has devised a standard appropriate to that proposal. The public
interest standard, with particular reference to G.L. c. 164, ss. 96 criteria, is
a reasonable guide for assessing the G.L. c. 164, ss. 94 Rate Plan presented
here. Both the Court and the Department itself have, as noted, recognized that
the public interest standard "supports the [Department's] grant of power over
rates." Boston Real Estate Board, 334 Mass. at 495.
The Department's authority to review and approve mergers and acquisitions is
found at G.L. c. 164, ss. 96, which, as a condition for approval, requires the
Department to find that mergers and acquisitions are "consistent with the public
interest." In Boston Edison Company, D.P.U. 850, at 6-8 (1983), the Department
construed the G.L. c. 164, ss. 96 standard of consistency with the public
interest as requiring a balancing of the costs and benefits attendant on any
proposed merger or acquisition. The Department stated that the core of the
consistency standard was "avoidance of harm to the public." Boston Edison
Company, D.P.U. 850, at 5 (1983). Therefore, under the terms of D.P.U. 850, a
proposed merger or acquisition is allowed to go forward upon a finding by the
Department that the public interest would be at least as well served by approval
of a proposal as by its denial. Eastern-Colonial Acquisition, D.T.E. 98-128, at
5 (1999); NIPSCO-Bay State Acquisition, D.T.E. 98-31, at 9 (1998); Eastern-Essex
Acquisition, D.T.E. 98-27, at 8 (1998); Boston Edison Company, D.P.U. 850, at
5-8 (1983). The Department has reaffirmed that we would consider the potential
gains and losses of a proposed merger to determine whether the proposed
transaction satisfies the G.L. c. 164, ss. 96 standard. NIPSCO-Bay State
Acquisition, D.T.E. 98-31, at 8 (1998); Eastern-Essex Acquisition, D.T.E. 98-27
at 8 (1998); Boston Edison Company/Boston Edison Mergeco Electric Company,
D.P.U./D.T.E. 97-63, at 7 (1998). The public interest standard, as elucidated in
D.P.U. 850, must be understood as a "no net harm," rather than a "net benefit"
test.(14) Eastern-Colonial Acquisition, D.T.E. 98-128, at 5 (1999); NIPSCO-Bay
State Acquisition, D.T.E. 98-31, at 9-10 (1998); Eastern-Essex Acquisition,
D.T.E. 98-27, at 8 (1998); Mergers and Acquisitions, D.P.U. 93-167-A at 7
(1994). The Department considers the special factors of an individual proposal
to determine whether it is consistent with the public interest. Eastern-Colonial
Acquisition, D.T.E. 98-128, at 5 (1999); NIPSCO-Bay State Acquisition, D.T.E.
98-31, at 9-10 (1998); Eastern-Essex Acquisition, D.T.E. 98-27, at 8 (1998);
Boston Edison Company/Boston Edison Mergeco Electric Company, D.P.U./D.T.E.
97-63, at 7 (1998); Mergers and Acquisitions, D.P.U. 93-167-A at 7-9 (1995). To
meet this standard, costs or disadvantages of a proposed merger must be
accompanied by offsetting benefits that warrant their allowance.
Eastern-Colonial Acquisition, D.T.E. 98-128, at 5-6 (1999); NIPSCO-Bay State
Acquisition, D.T.E. 98-31, at 9-10 (1998); Eastern-Essex Acquisition, D.T.E.
98-27, at 8 (1998); Boston Edison Company/Boston Edison Mergeco Electric
Company, D.P.U./D.T.E. 97-63, at 7 (1998); Mergers and Acquisitions, D.P.U.
93-167-A at 18-19 (1995).
Various factors may be considered in determining whether a proposed merger or
acquisition is consistent with the public interest pursuant to G.L. c. 164, ss.
96. These factors were set forth in Mergers and Acquisitions: (1) effect on
rates; (2) effect on the quality of service; (3) resulting net savings; (4)
effect on competition; (5) financial integrity of the post-merger entity; (6)
fairness of the distribution of resulting benefits between shareholders and
ratepayers; (7) societal costs; (8) effect on economic development; and (9)
alternatives to the merger or acquisition. Mergers and Acquisitions, D.P.U.
93-167-A at 7-9 (1995). This list is illustrative and not "exhaustive," and the
Department may consider other factors, or a subset of these factors, when
evaluating a G.L. c. 164, ss. 96 proposal. Eastern-Colonial Acquisition, D.T.E.
98-128, at 6 (1999)
Among these factors, the Department stated that it would consider societal
costs, such as job loss. Mergers and Acquisitions, D.P.U. 93-167-A at 7-8
(1994). We do not lightly regard the effect of this or any other merger on
employment. Eastern-Essex Acquisition, D.T.E. 98-27, at 44 (1998). Proponents of
mergers or acquisitions must demonstrate that they have a plan for minimizing
the effect of job displacement on employees. Id. As the bulk of the
merger-related savings relate to employment, the Department specifically
addresses the societial cost factor herein (Exh. TJF-1, at 6).
The Department's determination whether the merger or acquisition meets the
requirements of G.L. c. 164, ss. 96 must rest on a record that quantifies costs
and benefits to the extent that such quantification can be made.
Eastern-Colonial Acquisition, D.T.E. 98-128, at 7 (1999); NIPSCO-Bay State
Acquisition, D.T.E. 98-31, at 11 (1998); Eastern-Essex Acquisition, D.T.E.
98-27, at 9 (1998). To avoid an adverse result, a petitioner cannot rest its
case on generalities, but must instead demonstrate benefits that justify the
costs, including the cost of any acquisition premium sought. Eastern-Colonial
Acquisition, D.T.E. 98-128, at 7 (1999); NIPSCO-Bay State Acquisition, D.T.E.
98-31, at 11 (1998); Eastern-Essex Acquisition, D.T.E. 98-27, at 10 (1998);
Mergers and Acquisitions, D.P.U. 93-167-A at 7 (1995). Such a demonstration is
particularly relevant in this case, where the Joint Petitioners offer
merger-related savings as a way to recover the costs associated with the merger.
V. RATE PLAN
A. Four-Year Base Rate Freeze
1. Joint Petitioners' Proposal
The Joint Petitioners proposed not to raise any of Boston Edison's, Cambridge
Electric's, ComElectric's, and ComGas' distribution rates for four years
following the consummation of the merger, unless exogenous factors result in
cost changes (Exh. RDW-1, at 9). The Joint Petitioners define exogenous costs as
changes in tax laws, in accounting principles, and in regulatory, judicial, or
legislative requirements (Exh. MIT/Harvard 1-26). The Joint Petitioners have not
proposed a threshold level for petitions to recover exogenous costs (Tr. 8, at
1017-18).
2. Intervenors' Proposals
a. Attorney General
The Attorney General proposed to compare Boston Edison's, Cambridge Electric's,
ComElectric's, and ComGas' current rates to what they would be during each of
the four years of the proposed rate freeze if determined using a price cap
formula under performance-based regulation ("PBR") (Exhs. AG-1; AG-2; AG-3).(15)
The Attorney General proposed a price cap formula for Boston Edison, Cambridge
Electric, and ComElectric that used a productivity offset of 2.40 percent, which
was composed of a total factor productivity change of 1.9 percent and a consumer
dividend factor(16) of 0.5 percent (Exhs. AG-1, at 9; AG-2).
With respect to the inflation component of the price cap formula, the Attorney
General used the McGraw Hill DRI forecast, which projected inflation for each of
the years 2000 through 2004 to be 1.39, 1.65, 1.90, 1.99, and 2.12 percent,
respectively (Exh. AG-3). For ComGas, the Attorney General's price cap formula
used a productivity offset of 1.85 percent, composed of an accumulated
inefficiencies(17) factor of 0.85 percent and a future expected productivity
growth factor of 1.0 percent (Exh. AG-1, at 9-10). The Attorney General
concluded that each of the regulated companies would experience rate decreases
under PBR (Attorney General Brief at 19).
b. DOER
DOER estimated that during the four-year rate freeze period the Joint
Petitioners would forgo recovery of $136.4 million in merger-related costs, but
would retain savings projected to total $197.4 million (Exh. LAC at 6). DOER
argues that the Joint Petitioners' base rates should be lowered so that the
projected net savings of $61.0 million would go to their customers (id. at 28).
According to DOER, the rate decrease should be determined in the following
manner. First, DOER proposed that the Joint Petitioners should lower their base
rates by the projected gross savings in year five of the Rate Plan net of any
acquisition premium amortization expense and merger-related amortization expense
approved by the Department (id. at 29). Second, DOER recommended that for each
of the first four years of the Rate Plan, the Joint Petitioners should implement
a rate adder(18) that is calculated by taking the difference between the
projected gross savings in year five of the Rate Plan and the projected gross
savings for each of the first four years of the Rate Plan, respectively (id. at
29). The rate decrease would be allocated on a pro-rata basis across
distribution companies and customer classes (id. at 29).
c. MIT/Harvard
MIT/Harvard estimated that the Joint Petitioners expected to achieve
merger-related savings of approximately $197.4 million over the four-year rate
freeze period, and retain approximately $90 million, representing the sum of:
(1) $45 million in net pre-tax merger-related savings; (2) $5.5 million in
pre-merger initiatives; and (3) $40 million associated with the recovery of the
non-cash portion of the acquisition premium, over the same period (Exhs. SLB-1,
at 18-19; SLB-3). MIT/Harvard determined that the Joint Petitioners would have
net merger-related savings of approximately $95 million over the rate freeze
period, which could be shared equitably by the Joint Petitioners and their
ratepayers (Exh. SLB-1, at 42).
Therefore, MIT/Harvard proposed that the Joint Petitioners should be required to
reduce current rates by the $45 million in net savings plus the associated taxes
of $29.1 million, for a total of approximately $74.1 million during the term of
the rate freeze (for a rate reduction of approximately $18.5 million annually)
(id., at 42-43; Exh. SLB-3). MIT/Harvard proposed to allocate the rate reduction
between Boston Edison and ComEnergy System based on the number of administrative
and general employees as of 1997, whereby Boston Edison's ratepayers would
receive a annual rate reduction of approximately $10.5 million, and ComEnergy
System's ratepayers would receive an annual rate reduction totaling
approximately $8.0 million (Exh. SLB-1, at 43-44). MIT/Harvard proposes to
allocate the reduction attributable to ComEnergy System among Cambridge
Electric, ComElectric, and ComGas based on the total 1997 administrative and
general expenses as of 1997, producing annual rate reductions of approximately
$.9 million for Cambridge Electric, $3.0 million for ComGas, and $4.1 million
for ComElectric (id.).
3. Positions of the Parties
a. Attorney General
The Attorney General argues that for the proposed rate freeze to satisfy the no
net harm standard, the Joint Petitioners must first demonstrate that the current
rates are just and reasonable (Attorney General Brief at 18). The Attorney
General maintains that the Joint Petitioners made no attempt to demonstrate that
their current rates are just and reasonable (id.). In support of his position,
the Attorney General notes that the most recent full reviews of Cambridge
Electric's, ComElectric's, and ComGas' rates were in 1993, 1991, and 1991,
respectively (id., citing Cambridge Electric Light Company/Commonwealth Electric
Company/Canal Electric Company, D.P.U./D.T.E.
97-111, at 37 (1998)).
According to the Attorney General, if PBR is employed during the term of the
rate freeze, then the base rates for all four distribution companies would be
reduced (Attorney General Brief at 19). Therefore, the Attorney General
concludes that the record demonstrates that rather than producing savings for
customers, the Rate Plan deprives them of PBR-based rate decreases, to the
benefit of shareholders (id.). Consequently, the Attorney General considers that
the proposed four-year rate freeze fails to meet the no net harm standard and
therefore should be denied (id. at 18).
b. DOER
DOER argues that the Department should reject the Joint Petitioners' proposal to
freeze rates for four years, maintaining that the rates that will be in effect
during the rate freeze period should be lower than the Joint Petitioners'
current rates (DOER Brief at 18, citing Exhs. LAC; LAC-1). In support of its
position, DOER advances two reasons. First, DOER argues that the Joint
Petitioners' current rates are too high, and therefore cannot be considered just
and reasonable (DOER Brief at 18). According to DOER, pursuant to G.L. c. 164,
ss. 94, the burden is on the Joint Petitioners to demonstrate that their
proposed Rate Plan results in just and reasonable rates (DOER Reply Brief at 3).
DOER claims that industry restructuring has lowered the Joint Petitioners' costs
because of (1) a decrease in capital costs caused by the divestiture of
relatively risky generating assets, and (2) the retirement of some high-cost
debt with proceeds retained by the Joint Petitioners in excess of their debt
obligations on divested generation assets through the use of securitization
(DOER Brief at 18-19).
Second, DOER argues that the Joint Petitioners' current rates should be lowered
to ensure that their customers receive some of the savings that the Joint
Petitioners maintain will materialize (id. at 20). DOER estimates that the Joint
Petitioners would retain over $100 million in net savings over the proposed
four-year rate freeze (DOER Reply Brief at 2). DOER reasons that because the
likelihood of the merger savings materializing is primarily under the Joint
Petitioners' control, it is essential that the ratemaking treatment of the costs
and savings create an incentive for the Joint Petitioners to deliver on their
customer savings projections (DOER Brief at 20). DOER asserts that the proposed
rate freeze creates an incentive for the Joint Petitioners to achieve the
projected savings only until the point at which they are expecting a base rate
case, with decreased incentives thereafter (id. at 20-21; DOER Reply Brief at
2). Therefore, DOER concludes that the Joint Petitioners' proposed four-year
rate freeze is inconsistent with the Department's objectives of ensuring
economic efficiency and cost control (DOER Brief at 21).
c. MIT/Harvard
Like DOER, MIT/Harvard argues that the Department should reject the Joint
Petitioners' proposal to freeze Cambridge Electric's rates for four years
because it will not result in just and reasonable rates (MIT/Harvard Brief at
13). According to MIT/Harvard, a four-year rate freeze provides no additional
benefit to ratepayers beyond those mandated by the Act, i.e., an initial ten
percent rate reduction at the commencement of retail choice and a 15 percent
reduction by September 1, 1999 (id. at 14). Furthermore, MIT/Harvard notes that
the Act mandated that distribution companies preserve the economic value of
those mandated rate reductions for the seven-year duration of the transition
period required under the Act, which covers the entire rate freeze period
proposed by the Joint Petitioners (id.). Therefore, MIT/Harvard maintains that
absent the Rate Plan, it is unlikely that the Joint Petitioners would have
raised their distribution rates during the next four years (id.).
With respect to the Joint Petitioners' claim that the rate freeze protects
customers against likely rate increases, MIT/Harvard states that Cambridge
Electric failed to provide evidence demonstrating that, but for the rate freeze,
there would have been sufficient increases in distribution costs to justify rate
increases (id.). MIT/Harvard argues that the record evidence, such as Cambridge
Electric's return on equity of 16.7 percent for the year 1998, supports a full
reexamination of Cambridge Electric's costs collected through base rates (id. at
14-15). Therefore, MIT/Harvard argues that the Joint Petitioners have failed to
demonstrate that the current rates are just and reasonable (MIT/Harvard Reply
Brief at 4).
Finally, MIT/Harvard argues that the Joint Petitioners' current rates should be
lowered now, rather than wait for the next base rate case, to ensure that their
ratepayers receive some of the savings that the Joint Petitioners maintain will
materialize (MIT/Harvard Brief at 15-16, citing Exhs. SLB-1, at 18; SLB-3;
MIT/Harvard Reply Brief at 6). MIT/Harvard argues that it is not fair for the
Joint Petitioners' shareholders to keep all the projected savings that
materialize during the rate freeze period (MIT/Harvard Brief at 17). With
respect to the Joint Petitioners' assertion that there will be a six-month delay
in achieving merger-related savings, MIT/Harvard argues that the Joint
Petitioners will achieve savings during the overall term of the rate freeze
(MIT/Harvard Reply Brief at 8). By way of illustration, MIT/Harvard asserts that
the largest area of synergies, over $400 million, represents labor cost savings
that would be achieved shortly after the merger's closing date (id.).
d. AIM
AIM states that under the Rate Plan, all net savings accrued during the rate
freeze period will go to the Joint Petitioners' shareholders (AIM Brief at 10).
According to AIM, this result provides a perverse incentive for the Joint
Petitioners to achieve as much savings as possible during the first four years
and then become less aggressive on cost-containment measures in subsequent years
as the net savings incentive disappears (id. at 11). AIM argues that if the
Department grants the Joint Petitioners recovery of an acquisition premium
without passing on some of the projected savings, then all the risks associated
with the merger would be absorbed by the ratepayers, not the Joint Petitioners
(id.).
e. Joint Petitioners
According to the Joint Petitioners, by freezing rates for four years, ratepayers
are shielded from a possible rate increase that could result from: (1) failure
to achieve the anticipated cost savings in the early years, and (2) inflationary
increases in costs (Joint Petitioners Brief at 8, citing RDW-1, at 10-11). The
Joint Petitioners assert that in real terms, rates will be at or below what they
otherwise would have been in the absence of the merger (Joint Petitioners Brief
at 30; Joint Petitioners Reply Brief at 19). The Joint Petitioners maintain that
the estimated nature of merger-related costs and merger-related synergies does
not affect this conclusion (Joint Petitioners Reply Brief at 19). The Joint
Petitioners note that the four-year rate freeze is a voluntary commitment by the
Joint Petitioners that does not affect the rights of either the Department or
the Attorney General to seek a review of rates pursuant to G.L. c. 164, ss. 93
(id.). With respect to AIM's argument that the Joint Petitioners' customers are
absorbing all the risks, the Joint Petitioners state that customers would
receive all the savings in excess of the actual merger-related costs (id.).
Also, the Joint Petitioners note that the Rate Plan neither provides for any
return on the unamortized merger-related costs nor guarantees that the Joint
Petitioners will receive or benefit from any of the net merger-related savings
(id. at 19, n.13).
According to the Joint Petitioners, PBR is not a part of the Rate Plan and
therefore is not relevant in this proceeding (id. at 36-37). The Joint
Petitioners contend that, even if a price-cap analysis is a relevant proxy for
rate changes, the Attorney General's analysis is flawed (Joint Petitioners Reply
Brief at 17). The Joint Petitioners argue that the Attorney General's witnesses
provided a flawed analysis of productivity offsets to be applied in a price cap
formula (Joint Petitioners Brief at 36). The Joint Petitioners state that in the
case of the Attorney General's selected productivity factor for ComGas, the
Attorney General's witness arbitrarily adjusted historical productivity factors
and provided no credible evidentiary basis for his selected productivity offset
or accumulated inefficiencies (id. at 37, citing Exh. AG-1, at 7-9). In the case
of the electric utilities, the Joint Petitioners claim that the Attorney
General's witness measured productivity growth for the 1990 through 1995 time
period during which most electric utilities provided generation, distribution,
and transmission service (id. at 38). The Joint Petitioners state that because
they have divested their generation assets, the productivity offset proposed by
the Attorney General's witness is not relevant and should be rejected (id.).
Additionally, the Joint Petitioners argue that the inflation projections used by
the Attorney General's witnesses in their proposed price cap formula understate
inflation (Joint Petitioners Reply Brief at 17). The Joint Petitioners claim
that the Attorney General should have used the inflation forecast produced by
the Wharton Economic Forecast Association, Inc. ("WEFA") as the inflation
projections (id. at 18, citing RR-JP-1). The Joint Petitioners state that when
the WEFA inflation numbers are applied to a productivity offset of 1.5 percent,
which is the productivity offset approved for Boston Gas Company in D.P.U.
96-50-C (Phase I), ratepayers will experience an overall increase of
approximately $47 million over current rates (id. at 18, citing Exh. AG 1-39).
Therefore, the Joint Petitioners conclude that even if a Department-approved
price-cap formula were to be adopted, the four-year rate freeze would leave
customers no worse off (id.).
4. Analysis and Findings
The current distribution rates for Boston Edison, Cambridge Electric,
ComElectric, and ComGas have been approved by the Department as just and
reasonable pursuant to G.L. c. 164, ss. 94. See Boston Edison Company, D.T.E.
96-23, at 25-32 (1998); Cambridge Electric Light Company/Commonwealth Electric
Company/Canal Electric Company, D.P.U./D.T.E. 97-111, at 38-40 (1998);
Commonwealth Gas Company, D.P.U. 91-60 (1993). Nevertheless, the Attorney
General, DOER, and MIT/Harvard contend that the Joint Petitioners must
specifically demonstrate that current rates are just and reasonable for the
purposes of the proposed Rate Plan. We disagree with the intervenors for the
following reasons. First, a traditional rate case demonstration that a company's
rates produce no more or less than a reasonable level of earnings is required
when: (1) a company requests a general increase in rates pursuant to G.L. c.
164, ss. 94, or (2) the Department determines that it is necessary to review a
company's rates pursuant to G.L. c. 164, ss. 93. Neither of these conditions
apply in this case.
The Joint Petitioners are not proposing a general distribution rate increase;
rather, they are proposing to freeze rates at a level that has been determined
by the Department to be just and reasonable. In terms of the second condition,
there is no evidence that demonstrates the Joint Petitioners' current
distribution rates are not just and reasonable. The fact that Cambridge Electric
earned a return on equity greater than that provided for in D.P.U. 93-250 during
a single year and has implemented some cost saving measures is not sufficient to
demonstrate that their current rates are not just and reasonable. Until
subsequent rates for any of the Joint Petitioners are established, their current
base rates are adjudged to be just and reasonable. A mere assertion to the
contrary cannot displace those adjudicated results. Id.
The Department has reviewed a company's earnings in the context of adopting an
alternative regulation plan, in order to determine whether the starting rates
for such a plan are reasonable. Boston Gas Company, D.P.U. 96-50, at 346-347
(1996); NYNEX Price Cap, D.P.U. 94-50 (1995). However, the Rate Plan in this
case is not an alternative form of regulation. In both NYNEX and Boston Gas, the
companies proposed regulatory plans that provided for changes in rates over the
terms of those plans. As noted above, in this case, the Joint Petitioners are
proposing simply to freeze rates, not to define how rates may change in the
future
In addition, with respect to the Attorney General's PBR comparison, the
distribution rates for Boston Edison, Cambridge Electric, ComElectric, and
ComGas are not set under a PBR. While the Act authorizes the Department to
implement PBR, the PBR regulatory scheme is not mandatory. St. 1997, c. 164, ss.
193; G.L. c. 164, ss. 1E. See Eastern-Colonial Acquisition, D.T.E. 98-128, at 16
(1999), citing Massachusetts Oilheat Council, 418 Mass. at 803-804. The Joint
Petitioners have not proposed a PBR, but a Rate Plan that incorporates a
four-year rate freeze; it is not a traditional general rate case. The Department
finds that the Joint Petitioners' proposal to freeze rates for a four-year
period does not conflict with either the Act or with the Department's efforts to
implement PBR. Eastern-Colonial Acquisition, D.T.E. 98-128, at 17 (1999). See
also Eastern-Essex Acquisition, D.T.E. 98-27 at 16-17 (1998). Therefore, the
Department finds comparing the individual companies' rates to those under the
Attorney General's hypothetical PBR is not appropriate.
With respect to the argument that the Joint Petitioners may reap excessive net
savings from the Rate Plan, there is nothing in the merger that restricts the
rights of the Attorney General or any other party to seek a review of rates in
accordance with G.L. c. 164, ss. 93 (Tr. 6, at 830-831). Eastern-Essex
Acquisition, D.T.E. 98-27, at 14 (1998). The Department will monitor the
earnings of each of the Joint Petitioners's distribution companies. Should the
Department have a reason to believe that a company's earnings are excessive, the
Department would conduct an investigation of that company's rates pursuant to
G.L. c. 164, ss. 93.
On balance, the Department considers ratepayers to be better served by a
commitment now to a four-year rate freeze than by conducting a rate case
examination now of actual cost savings and cost increases. Since the rate freeze
does not include an adjustment for inflation, it actually represents a "real"
rate decrease for customers over the four-year period. This is contrasted to the
uncertainty associated with litigating the costs and benefits associated with
this merger in a traditional rate case. In view of the time that has elapsed
since the Joint Petitioners' previous G.L. c. 164, ss. 94 rate applications, the
Department considers it probable that the results of a G.L. c. 164, ss. 94
investigation would be a conclusion that an increase over the Joint Petitioners'
present base rates would be warranted. Accordingly, the Joint Petitioners'
ratepayers would be at least as well off with the proposed base rate freeze as
they would be absent the proposed merger. Therefore, the Department finds the
Petitioners' proposal to freeze Boston Edison's, Cambridge Electric's,
ComElectric's, and ComGas' base distribution rates for four years following
consummation of the merger to be consistent with the public interest.(19)
With respect to the Joint Petitioners' proposed exogenous cost adjustment, the
Department has defined exogenous costs as positive or negative cost changes
beyond a company's control that would significantly affect the Company's
operations. Eastern-Colonial Acquisition, D.T.E. 98-128, at 55 (1999);
NIPSCO-Bay State Acquisition, D.T.E. 98-31, at 18 (1998); Eastern-Essex
Acquisition, D.T.E. 98-27, at 19 (1998). The Joint Petitioners' proposed list of
exogenous factors is identical to that set forth and accepted by the Department
in NIPSCO-Bay State Acquisition, D.T.E. 98-31 (1998), Eastern-Essex Acquisition,
D.T.E. 98-27 (1998), and Boston Gas Company, D.P.U. 96-50 (1996). For purposes
of the Rate Plan, exogenous factors shall be defined, for Boston Edison,
Cambridge Electric, and ComElectric, as those positive or negative cost changes
actually beyond the Joint Petitioners' control that uniquely affect the electric
distribution industry. For ComGas, exogenous factors shall be those positive or
negative cost changes actually beyond the Joint Petitioners' control that
uniquely affect the local gas distribution industry. See Boston Gas Company,
D.P.U. 96-50 (Phase One), at 292 (1996). If, during the term of the Rate Plan,
the Joint Petitioners seek to recover any exogenous cost, they must propose
exogenous cost adjustments, with supporting documentation and rationale, to the
Department for determination as to the appropriateness of recovery of the
proposed exogenous costs.
As noted, the Joint Petitioners have proposed no threshold for a cost change to
qualify as an exogenous cost. The Department has stated that there should be a
threshold for qualification as an exogenous cost in order to avoid costly
regulatory process over minimal dollars. Eastern-Colonial Acquisition, D.T.E.
98-128, at 55 (1999); NIPSCO-Bay State Acquisition, D.T.E. 98-31, at 18 (1998);
Boston Gas Company, D.P.U. 96-50, at 288 (1996). Therefore, the Department has
required that any individual exogenous cost must exceed a threshold in order to
qualify for recovery. NIPSCO-Bay State Acquisition, D.T.E. 98-31, at 18 (1998);
Boston Gas Company, D.P.U. 96-50, at 288 (1996). The Department considered a
threshold for the opportunity to recover exogenous costs in Eastern-Colonial
Acquisition, D.T.E. 98-128, at 55 (1999).(20) There, the Department found that
the effect of any individual exogenous cost must exceed $250,000 in a particular
year in order for those petitioners to request recovery. The Department finds
that a principle of proportionality relating to the Joint Petitioners' operating
revenues is called for and so proportions the threshold set for the Joint
Petitioners to that set for Colonial Gas Company ("Colonial"). To make a
determination regarding an appropriate threshold here, the Department compares
the Joint Petitioners' and Colonial's operating expenses in 1998. The Department
notes that Colonial's 1998 operating revenues were $167,978,495, which is
approximately 10.4 percent of those of Boston Edison, 141.5 percent of those of
Cambridge Electric, 39.6 percent of those of ComElectric, and 58.1 percent of
those of ComGas (Exh. AG 1-5).(21) The Department determines that threshold
amounts of $2,400,000 for Boston Edison, $175,000 for Cambridge Electric,
$625,000 for ComElectric, and $425,000 for ComGas are reasonable.(22) Therefore,
any individual exogenous cost must exceed $2,400,000 for Boston Edison, $175,000
for Cambridge Electric, $625,000 for ComElectric, and $425,000 for ComGas in a
particular year in order for the Joint Petitioners to request recovery of
exogenous costs.
B. Cambridge Electric and ComElectric Rate Adjustments
1. Introduction
During August of 1997, the base period relied upon in the Act, Cambridge
Electric's rates included average demand-side management ("DSM") charges of
0.099 cents per KWH, and ComElectric's rates included average DSM charges of
0.207 cents per KWH (Exh. RDW-1, at 12). Both Cambridge Electric and ComElectric
in their restructuring filing calculated their average distribution rates by
bundling the 1997 DSM costs with the distribution costs derived from a 1995 cost
of service study (Exh. DTE 1-2). However, when Cambridge Electric and
ComElectric calculated the distribution charge for each individual rate class,
it subtracted the Act-mandated DSM charge for 1998 (0.330 cents per KWH) and
Renewable Energy charge for 1998 (0.075 cents per KWH), from the bundled
distribution charge (Tr. 6, at 790-791). Since the 1998 DSM and Renewable Energy
charges are significantly higher then the 1997 DSM charge, both Cambridge
Electric and ComElectric argue that they have sustained, and continue to
sustain, large losses in their distribution revenues (id.).
2. Joint Petitioners' Proposal
In order to remedy the proposed shortfall, the Joint Petitioners propose to
increase the distribution rates for Cambridge Electric and ComElectric,
effective upon the closing of the merger (Exh. RDW-1, at 12-13). The Joint
Petitioners calculated the increase by taking the sum of the average DSM Charge
mandated by the Act for the years 2000 through 2002, which is 0.268 cents per
KWH and the average Renewable Energy Charge mandated by the Act for the years
2000 through 2002, which is 0.100 cents per KWH, and subtracting this sum from
the total DSM and Energy Conservation Service charges included in August 1997
rates (id., at 13).(23) This results in distribution rate adjustments of 0.223
cents per KWH for Cambridge Electric and 0.161 cents per KWH for Commonwealth
(id.).(24) To ensure that the total rates paid by customers will not increase,
the Joint Petitioners propose that the respective transition charges, for
Cambridge Electric and ComElectric, be reduced by an amount equal to the
increase in the respective distribution charges (id., at 12-13). Therefore, the
Petitioners contend that the overall current rates would not increase and
transition costs would be deferred.
3. Positions of the Parties
a. MIT/Harvard
MIT/Harvard notes that the distribution rates currently paid by Cambridge
Electric's customers were derived through a cost of service study based on a
test year ending June 30, 1992, that was fully litigated by the Department and
found to be reasonable in 1993 (MIT/Harvard Brief at 4, citing Cambridge
Electric Light Company, D.P.U. 92-250 (1993)). MIT/Harvard states that the
Department has not fully litigated Cambridge Electric's rates since that time
and, that in Cambridge Electric Light Company/ComElectric Company/Canal Electric
Company, D.P.U./D.T.E. 97-111, the Department made clear its intent to review
thoroughly Cambridge Electric's costs and the manner in which those costs are
allocated (MIT/Harvard Brief at 4, citing Exh. SLB-1, at 10-11; D.P.U./D.T.E.
97-111, at 39-40). MIT/Harvard argues that until that review has been performed,
no rate increase is warranted (MIT/Harvard Brief at 4). MIT/Harvard also claims
that Cambridge Electric's requested increase constitutes a single-issue rate
case (id., at 6, 9). MIT/Harvard notes that Department precedent generally does
not allow single-issue rate cases and that Cambridge Electric has made no
demonstration warranting a change or exception to this precedent (id.).
MIT/Harvard states that Cambridge Electric's proposed distribution rate increase
should be denied because it incorrectly relies on the claim that Cambridge
Electric has not fully recovered its DSM and Renewable Energy expenditures
(MIT/Harvard Brief at 6). MIT/Harvard maintains that since March 1, 1998,
Cambridge Electric has been fully recovering its mandated DSM and Renewable
Energy expenditures through changes in the current tariffs (id. at 6-8;
MIT/Harvard Reply Brief at 2). Therefore, according to MIT/Harvard, Cambridge
Electric has no basis for the requested increase (MIT/Harvard Brief at 6).
MIT/Harvard maintains that DSM and Renewable Energy costs are already being
collected from customers in full as a result of a prior Department proceeding
(MIT/Harvard Reply Brief at 3, citing Cambridge Electric Light
Company/Commonwealth Electric Company/Canal Electric Company, D.P.U./D.T.E.
97-111 (1998)). MIT/Harvard contends that the Joint Petitioners'
characterization of the proposed rate increase as akin to an exogenous
adjustment permitted in accordance with PBR price cap plans is inapposite,
because the Joint Petitioners have not proposed a PBR price cap in this case
(MIT/Harvard Reply Brief at 3). Therefore, MIT/Harvard asserts that absent a
thorough review of all costs, no increase is warranted (id.).
MIT/Harvard notes that Cambridge Electric's return on equity for 1998 was 16.7
percent, which was in excess of the 11 percent return approved in D.P.U. 92-250
(id. at 10). MIT/Harvard states that Cambridge Electric may have had high
earnings because it (1) had implemented several cost reduction measures
including a significant decrease in the number of employees, and (2) had large
increases in revenues caused by an increase in energy sales (id. at 10-11).
Therefore, MIT/Harvard argues that a full review of Cambridge Electric's costs
is needed before an increase in rates is allowed (id. at 11).
b. Joint Petitioners
The Joint Petitioners argue that the proposed adjustments to Cambridge
Electric's and ComElectric's distribution rates do not constitute a general
increase in rates, but represent an increase in the DSM charge, which has
historically been a separately computed and reconciled rate element (Joint
Petitioners Brief at 33; Joint Petitioners Reply Brief at 22). The Joint
Petitioners note that the DSM charge remains a separately stated charge whose
price is mandated by the Act and had been included in Cambridge Electric's
restructuring plan considered in D.T.E. 97-111 (Joint Petitioners Brief at 33,
citing Act, ss. 19; Cambridge Electric Light Company/Commonwealth Electric
Company/Canal Electric Company, D.P.U./D.T.E. 97-111, at 40-41). Also, the Joint
Petitioners note that customer bills will not increase because Cambridge
Electric and ComElectric will lower their transition charges by an amount equal
to the distribution charge increase (Joint Petitioners Brief at 33).
According to the Joint Petitioners, even if this distribution rate adjustment
were construed as a single-issue rate case (a construction whose validity they
do not concede), the Department has previously granted exceptions to its general
policy by allowing changes in base rates to include increases to a single cost
item (id.). For example, the Joint Petitioners state that in D.P.U. 87-21-A, the
Department required all regulated utilities to adjust base rates to incorporate
a change in the federal tax rate (id., citing D.P.U. 87-21-A at 5-12 (1987)).
Also, the Joint Petitioners analogize the proposed rate increase here to the
provisions of the Act which permit exogenous cost adjustments for PBR price cap
plans (Joint Petitioners Brief at 33, citing New England Telephone and Telegraph
Company, D.P.U. 94-50, at 172-173 (1995); Boston Gas Company, D.P.U. 96-50
(Phase One), at 289-294 (1996)). Therefore, the Joint Petitioners state that the
Rate Plan's distribution rate increases related to the DSM increase caused by
legislative action, are consistent with Department precedent, and should be
approved (Joint Petitioners Brief at 33).
4. Analysis and Findings
Cambridge Electric's and ComElectric's base rates were last changed in their
restructuring proceeding, Cambridge Electric Light Company/Commonwealth Electric
Company/Canal Electric Company, D.P.U./D.T.E. 97-111 (1998). In designing the
base rates in D.P.U./D.T.E. 97-111, Cambridge Electric and ComElectric chose to
bundle the 1997 DSM revenues with the distribution revenue requirement. However,
when Cambridge Electric and ComElectric calculated the base rates for each
customer class, they subtracted the 1998 DSM and Renewable Energy revenues
attributable to each rate class from the class' distribution revenue
requirement, including 1997 DSM revenues. Since the 1997 DSM revenues were lower
than the 1998 DSM and Renewable Energy revenue, the base rates so set
undercollect the distribution revenue requirement.
Two of the many goals of the rate design in D.P.U./D.T.E. 97-111 were to allow
Cambridge Electric and ComElectric (1) to be revenue neutral with respect to the
collection of Distribution revenues, and (2) to collect the DSM and Renewable
Energy charges mandated by the Restructuring Act. Consistent with the rate
reductions mandated by the Act, Cambridge Electric and ComElectric achieved the
second goal but inadvertently failed to achieve the first goal. Cambridge
Electric and ComElectric would have also achieved the first goal had they either
(1) kept the DSM revenues separate from the distribution costs or (2) bundled
the 1998 DSM and Renewable Energy revenue requirement with the 1998 distribution
revenue requirement, instead of the 1997 DSM revenues. If Cambridge Electric and
ComElectric were to continue billing at their current rates, they would
undercollect the distribution revenue requirement approved in D.P.U./D.T.E.
97-111 by approximately $49.8 million (Exhs. RDW-1, at 13; RDW-3).
Undercollecting the revenue requirement is inequitable for Cambridge Electric
and ComElectric because it does not allow them a fair opportunity to earn their
allowed rates of return.(25) Therefore, in order to collect the distribution
revenue requirement approved in D.P.U./D.T.E. 97-111, Cambridge Electric's and
ComElectric's proposed adjustments to their distribution rates are allowed.
Accordingly, Cambridge Electric and ComElectric may submit revised distribution
tariffs reflecting the proposed adjustments to the distribution rates.
VI. COSTS TO ACHIEVE MERGER
A. Transaction and System Integration Costs
1. Joint Petitioners' Proposal
The Joint Petitioners estimate that the total pre-tax transaction and system
integration costs associated with the merger will be $111,058,000, consisting of
$24,155,000 in pre-tax transaction and regulatory costs, and $86,903,000 in
systems integration costs considered necessary to integrate ComEnergy System's
systems into those of BEC Energy (Exhs. TJF-1, at 6; TJF-4).
The $24,155,000 in transaction and regulatory costs consist of: (1) $17,079,000
in transaction costs; (2) $5,076,000 in regulatory process costs; and (3)
$2,000,000 in communications costs (Exhs. TJF-1, at 64-65; TJF-5U, at 3).
Transaction costs are defined as professional fees paid for assistance on
certain aspects of the merger, consisting of $10,079,000 in bankers' fees,
$4,000,000 in attorney fees, $2,000,000 for stock exchange registration, and
$1,000,000 in consulting fees (Exhs. TJF-1, at 64-65; TJF-5U, at 15). Regulatory
process costs are defined as the cost of presenting this petition, as well as
required Securities and Exchange Commission ("SEC"), Federal Energy Regulatory
Commission ("FERC"), and Department of Justice ("DOJ") filings, consisting of
$4,000,000 in attorney fees, $826,000 in registration fees, and $250,000 in
consulting fees (Exhs. TJF-1, at 64; TJF-5U, at 16; Tr. 4, at 346-348).
Communications costs are defined as the cost of disseminating information to
shareholders, employees, customers, vendors, rating agencies, and regulatory
commissions (Exhs. TJF-1, at 64; TJF-5, at U11; DTE 1-33; Tr. 4, at 344-346).
The $86,903,000 in system integration costs consist of: (1) $27,118,000 in
employee separation costs; (2) $3,000,000 in employee retention costs; (3)
$1,000,000 in relocation costs; (4) $1,500,000 in facilities reconfiguration
costs; (6) $44,702,000 in information technology integration costs; (7) $700,000
in telecommunications costs; (7) $1,883,000 in directors and officers' tail
coverage liability insurance;(26) and (8) $7,000,000 in transition costs
incurred for outside services intended to facilitate the integration of BEC
Energy and ComEnergy System (Exhs. TJF-1, at 26-27; TJF-4; TJF-5H, at 1; TJF-5U,
at 1). While the majority of these costs would be incurred during the first
three years after the merger, certain information technology integration and
telecommunications costs are expected to be incurred on an annual basis through
2009 (Exh. TJF-4).
Certain types of transaction and regulatory process costs, such as investment
banker fees and some types of legal consulting fees, are not considered
deductible for income tax purposes (Exh. JJJ-1, at 8; Tr. 8, at 1024-1025).
Additionally, certain types of system integration costs, including employee
separation, relocation, and facilities-reconfiguration costs attributed to
ComEnergy System, are not considered deductible for income tax purposes (Exh.
JJJ-1, at 8; Tr. 8, at 1024-1025). For purposes of this proceeding, the Joint
Petitioners estimated that $37,000,000 in transaction and system integration
costs were not tax deductible, with a remaining $74,100,000 would be deductible
for income tax purposes (Exhs. JJJ-1, at 8; TJF-4, at U3; Tr. 8, at 1024-1025).
Application of a combined federal and state income tax factor of 39.225 percent
to the $37,100,000 non-deductible expenses produces a pre-tax expense of
approximately $60,900,000 (Exhs. JJJ-1, at 8; TJF-4, at U3 (confidential)).
Therefore, the Joint Petitioners estimated that the total pre-tax transaction,
regulatory, and system integration expense associated with the merger would be
$135,000,000 ($74,100,000 + $60,900,000) (Exh. JJJ-1, at 8-9).
While most of these costs will be expended in the first three years after the
merger, other costs will be incurred over the subsequent seven years (id., at 9;
Tr. 8, at 1032-1033, 1041). Under generally accepted accounting principles,
certain types of merger-related expenses may require different treatment for
financial accounting versus ratemaking purposes (Tr. 8, at 1031-1032). As part
of the Rate Plan, the Joint Petitioners request Department approval for the
deferral of the transaction and system integration costs that are incurred
through the year 2003, and for a ten-year amortization for ratemaking purposes
of transaction and system integration costs (Exh. JJJ-1, at 9; Tr. 8, at
1040-1042).(27) At the end of the ten-year amortization period, the Joint
Petitioners anticipate filing a "true-up" of the actual transaction and system
integration costs for reconciliation purposes (Tr. 8, at 1032-1033).
2. Positions of the Parties
a. Attorney General
The Attorney General argues that the Joint Petitioners' proposal to collect
transaction and system integration costs through base rates is not tied to a
demonstration, much less the achievement, of merger savings (Attorney General
Brief at 13-14). The Attorney General faults the Joint Petitioners' witness'
analysis of the costs and savings associated with the merger as inconsistent
with testimony provided before other regulatory agencies, maintains that the
witness lacked understanding about key parts of his testimony, and questions his
credibility (id. at 15-17). The Attorney General maintains that under the Joint
Petitioners' proposal, customers would be required to pay for merger costs, even
if no merger savings were ultimately achieved (id. at 14). Therefore, the
Attorney General concludes that this feature of the Rate Plan fails to satisfy
the Department's no net harm standard (id., citing Eastern-Essex Acquisition,
D.T.E. 98-27, at 8 (1998); Boston Edison Company/Boston Edison Mergeco Electric
Company, D.P.U./D.T.E. 97-63 at 7 (1998); Mergers and Acquisitions, D.P.U.
93-167-A at 18, 19).
b. DOER
DOER opposes the Joint Petitioners' proposed recovery of transaction and system
integration costs associated with the merger, stating that the prospective
nature of the expenses are contrary to Department precedent (DOER Brief at 11).
While conceding that certain administrative costs relative to the merger may be
reasonable, DOER argues that the Joint Petitioners have failed to make any
showing that the proposed inclusion of transaction expenses complies with
Department standards (id. at 11-12).
c. AIM
AIM argues that the Joint Petitioners' request for preapproval of transaction
and system integration cost recovery is unlike any other merger proposal
considered by the Department, and leaves ratepayers at risk for merger-related
costs, even if actual merger-related savings are minimal (AIM Brief at 8-9).
d. Joint Petitioners
The Joint Petitioners argue that the costs to achieve the merger, including
transaction, regulatory, and system integration expenses, represent real costs
to shareholders for which they must be granted the opportunity to recover, and
whose recovery is a prerequisite for the completion of the merger (Joint
Petitioners Brief at 22-23). The Joint Petitioners contend that because the
merger-related costs are small in relation to merger-related savings, and since
the vast majority of these costs would be incurred at the time the merger is
completed, or shortly thereafter, ratepayers bear virtually no risk that these
costs would exceed merger-related savings (id. at 21-22).
3. Analysis and Findings
a. Transaction and Regulatory Costs
The Department has recognized that there are transaction costs associated with a
merger or acquisition, and that these costs may be recovered in rates provided
the public interest standard of G.L. c. 164, ss. 96, is satisfied.
Eastern-Colonial Acquisition, D.T.E. 98-128, at 90 (1999); Eastern-Essex
Acquisition, D.T.E. 98-27, at 52-53 (1998); Mergers and Acquisitions, D.P.U.
93-167-A at 16, 18-19 (1994). Certain transaction costs, such as regulatory
filing fees, are elements necessary for the completion of any merger (Exh.
TJF-1, at 18, 64). The Joint Petitioners estimated that the transaction and
regulatory costs resulting from this merger will be $24,155,000 (Exh. TJF-5U, at
3). Although a number of intervenors have posed general challenges to the level
of transaction costs, the Department has recognized that certain merger-related
costs are not subject to the same level of precision as generally can be
attained in a traditional cost-of-service rate proceeding. Eastern-Essex
Acquisition, D.T.E. 98-27, at 51 (1998). Mergers and Acquisitions recognized
that precise calculation of costs and benefits is not always possible and so
required quantification to the extent such quantification can be made. Mergers
and Acquisitions, D.P.U. 93-167-A at 7 (1994). Therefore, the Department
examines the basis for these transaction cost estimates in our determination of
the costs and benefits associated with the merger, to the extent that these
costs can be quantified.
The largest single component of the transaction costs, $10,079,000 in bankers'
fees, was estimated by applying rates developed through contractual fee
arrangements to the estimated market valuation of the transaction, consistent
with standard business practice (Exh. DTE 1-31; Tr. 4, at 348-350). The Joint
Petitioners estimated $4,000,000 in attorney fees related to the merger itself,
with another $1,000,000 in consulting fees; these estimates were derived based
on the anticipated complexity and length of time associated with the developing
the final merger agreement, as well as the need for outside consultants for
issues relative to synergies analysis, nuclear ownership issues,(28)
environmental issues, and unregulated operations (Exh. TJF-5U, at 15; Tr. 4, at
351). Another $2,000,000 was estimated as Nstar's required filing fee under the
rules of the New York Stock Exchange (Exh. TJF-5U, at 15; Tr. 4, at 350). The
proposed expense level is consistent with the experience of Deloitte Consulting
in previous transactions (Exh. DTE 1-31). Taking into consideration the
contractual arrangements with the investment bankers, the need for filing fees,
and Deloitte Consulting's experience from other business combinations, the
Department finds that the proposed transaction expense of $17,079,000 is
commensurate with the complexity of the merger and reasonable in amount for
purposes of evaluating the costs associated with the merger.
Regulatory approval expenses were estimated based on the anticipated complexity
and time associated with the various state and federal proceedings, the
potential need for outside consultants on discovery and potential rebuttal
issues, and filing fees required pursuant to the SEC's Rule 457(f) (Exh. TJF-5U,
at 16; Tr. 4, at 347-348). The proposed expense level is consistent with the
experience of Deloitte Consulting in previous transactions, allowing for the
single-state regulatory jurisdiction, under which the Joint Petitioners operate,
versus multi-state jurisdiction utilities involved in other utility mergers, and
the subsequent reduced level of review required by FERC (Exh. DTE 1-32). Taking
into consideration the necessity of these types of expenses and the basis by
which the Joint Petitioners estimated the level of these expenses, the
Department finds that the proposed regulatory approval expense of $5,076,000 is
commensurate with the complexity and nature of the merger and reasonable in
amount for purposes of evaluating the costs associated with the merger.
Communications costs were estimated at a level that would provide for the range
of direct mail and other media options that may be necessary to inform
employees, customers, vendors, and shareholders about the merger and its effect
upon them (Exh. DTE 1-33; Tr. 4, at 344-346). The proposed expense level is
consistent with the experience of Deloitte Consulting in previous transactions
(Exh. DTE 1-33; Tr. 4, at 346). Although these costs do not lend themselves to
the same level of quantification as may be possible with other types of
merger-related expenses, the Department recognizes the need for customers,
vendors, shareholders, and members of the public to be informed on the merger
and its particular effects on them. The Department finds the proposed
communications expense of $2,000,000 to be commensurate with the complexity and
nature of the merger and reasonable in amount for purposes of evaluating the
costs associated with the merger.
The overall scope of the transaction, as measured by the probable value of the
stock transfer, is approximately $948 million.(29) The Department has considered
transaction costs in the context of the magnitude of assets involved and the
complexity of the transaction. See Eastern-Essex Acquisition, D.T.E. 98-27, at
52 (1998). The merger transaction involves the formation of a Massachusetts
business trust, the creation of two limited liability corporations as shell
entities, and the merger of two other Massachusetts business trusts with a total
market capitalization of $2.8 billion with these shell entities (Exhs. JJJ-1
(Supp. at 1); TJF-5U, at 15). This transaction involves the Department, SEC,
FERC, and DOJ for various regulatory approvals. Transaction costs of $24,155,000
are reasonable in view of the magnitude of the combined system's market assets
of $2.8 billion and the multiple transactions required to complete the business
consolidation. Accordingly, the Department includes the full $24,155,000 in
transaction costs in our estimate of the costs associated with the
consolidation. For present purposes, the estimates of costs are reliable.
While the Department will consider these transaction costs in our evaluation of
the costs and benefits associated with the consolidation, the transaction and
regulatory expenses will be determined with finality soon after the completion
of the merger (Tr. 4, at 352-353). The Joint Petitioners intend to provide the
Department with updated transaction costs shortly after the close of the merger,
at the end of the 90-day post-merger closing period (Tr. 7, at 873). However,
the Joint Petitioners anticipate that the final level of communications expenses
will not be fully determined until early in the year 2000 (Tr. 4, at 353).
Accordingly, the Department directs the Joint Petitioners to provide the
Department with an accounting of the final transaction costs within 90 days from
the date of the closing of the merger, to the extent available. Specifically,
the Joint Petitioners shall provide a detailed listing of the transaction,
regulatory, and communications costs incurred to date to the Department within
90 days, which shall be updated to include final communication-related expenses
no later than March 30, 2000.
b. System Integration Costs
As with merger-related transaction costs, the Department has recognized that
there are post-merger costs associated with a merger or acquisition which may be
recoverable if the public interest standard of G.L. c. 164, ss. 96 is satisfied.
Eastern-Essex Acquisition, D.T.E. 98-27, at 51-52 (1998); Mergers and
Acquisitions, D.P.U. 93-167-A at 16, 18-19 (1994). The Joint Petitioners
estimated that the system integration costs resulting from this merger will be
$86,903,000 (Exh. TJF-4). Intervenors have challenged the level of system
integration costs and the Joint Petitioners' analytical methods in general
terms; however, no specific challenges to the assumptions or calculations have
been made. The Department examines the bases for these system integration cost
estimates in our determination of the costs allowed to be recovered under the
Rate Plan.
Separation costs were estimated on the basis of the Joint Petitioners'
determination of the number of employee reductions based on post-merger staffing
needs, the compensation ranges for the affected employee classifications, and
assumptions about the form of severance packages and separation assistance
programs for employees (Exhs. TJF-1, at 62; TJF-5U, at 1-7; Tr. 3, at 219-223;
Tr. 4, at 321-324, 334-335). Although these costs are estimated, the Department
recognizes that the merger will result in employee reductions through a
combination of new hiring policies, attrition, and layoffs (Exh. TJF-1, at 62,
Tr. 3, at 322-324). The Joint Petitioners have made a reasonable estimate of the
number and types of employees that are likely to be separated as a result of the
merger, as well as a reasonable estimate of the projected savings in
compensation expense. The projected severance packages are fairly representative
of those that are likely to be negotiated with these employees, based on the
experience of Deloitte Consulting (Exh. TJF-5U, at 5; Tr. 4, at 423). The
projected employee-assistance program expense level is consistent with the
experience of Deloitte Consulting in previous transactions involving companies
of this size (Exh. TJF-5U, at 7; Tr. 4, at 421-422). Therefore, the Department
concludes that the proposed separation expense of $27,118,000 is reasonable in
amount. Accordingly, the Department includes these costs in our evaluation of
the costs and benefits associated with the merger.
Employee relocation costs were estimated using the assumption that, as a result
of the centralization of certain functions, a number of management employees
would need to relocate their homes closer to their new work sites (Exhs. TJF-1,
at 63, TJF-5U, at 9; Tr. 4, at 420). The Joint Petitioners estimated that, based
on an analysis of employee positions, 20 employees could be potentially be
affected and thereby take advantage of an employee relocation program, which may
include moving expenses, house hunting expenses, cost of living differentials,
and closing costs (Exh. TJF-1, at 63; Tr. 4, at 420). The Joint Petitioners
estimated a cost per employee relocation of $50,000 (Exhs. TJF-1, at 63, TJF-5U,
at 9). The Department recognizes that post-merger staffing changes may result in
employee transfers to other work sites, which in some cases may require the
affected employee to change residence. The Joint Petitioners have made a
reasonable estimate of the number of employees who may be affected by work site
transfers. Although the scope of the employee relocation program has yet to be
formulated, the proposed cost per employee relocation is consistent with the
experience of Deloitte Consulting in previous transactions (Exh. TJF-1, at 62).
Therefore, the Department includes the employee relocation costs of $1,000,000
in our evaluation of the costs and benefits associated with the merger.
Employee retention costs, represented by bonuses to be paid to certain key
employees in exchange for their decisions to remain with Nstar during the
transition period, were estimated on the assumption that 100 key employees,
mostly in the information technology area, would be paid a $30,000 bonus each to
remain with Nstar (Exhs. TJF-1, at 62, TJF-5U, at 8). The Joint Petitioners'
assumption about the bonus level corresponds to six months' salary, based on the
Joint Petitioners' average employee salary of $60,000 per year (Exh. TJF-1, at
35). The Department recognizes that financial inducements to certain key
personnel, particularly those in the information technology area, would be
reasonable in order to encourage these employees to remain with Nstar during the
transition period. The Joint Petitioners have made a reasonable estimate of the
number of employees who may be eligible for retention bonuses. The proposed
bonus level, while subject to final determinations by management, is consistent
with the experience of Deloitte Consulting in previous transactions (Exh. TJF-1,
at 62). Therefore, the Department includes the employee retention costs of
$3,000,000 in our evaluation of the costs and benefits associated with the
merger.
Directors and officers liability tail coverage was based on an assumed 1.5 times
the annual directors and officers liability premiums for BEC Energy and
ComEnergy System (Exh. TJF-5U, at 16). The proposed expense level is derived
from the 1997 premiums paid by BEC Energy and ComEnergy System, to which a
multiple of 1.5 has been applied based on discussions with an insurance broker
(id.; Tr. 4, at 418-419). The Department recognizes that former directors would
be entitled to insurance coverage to protect them from legal liabilities arising
from their acts while serving as directors. The proposed directors and officers
liability tail coverage of $1,883,000 is consistent with the experience of
Deloitte Consulting in previous transactions (Exh. TJF-1, at 63). Therefore, the
Department includes the proposed directors and officers liability tail coverage
costs in our evaluation of the costs and benefits associated with the merger.
Facilities reconfiguration costs, information technology integration costs,
telecommunications costs, and transition costs were estimated based on a number
of considerations, including previous transactions (Exh. TJF-5U, at 3, 10-14).
Although these costs are estimates, the Department recognizes that the merger
will result in the restructuring of Nstar affiliates' physical plant
requirements, as well as system reconfigurations which will require a number of
years to complete with outside assistance. The Joint Petitioners have provided
the basis for the cost estimates, which rely extensively on the experience of
other utility mergers (Tr. 4, at 424-425). The proposed reconfiguration,
information technology, telecommunications, and transition costs are
commensurate with the complexity and nature of the merger and are reasonable in
amount. Therefore, the Department includes these costs in our evaluation of the
costs and benefits associated with the merger.
While the Department will consider these system integration costs in our
evaluation of the costs and benefits associated with the consolidation, these
expenses cannot be quantified with finality until 2009, when the final
information technology integration and telecommunications expenditures are made.
Accordingly, the Department directs the Joint Petitioners to provide a detailed
listing of the system integration costs, to the extent available, no later than
the filing date of the first rate proceeding brought by any one of Nstar's
regulated companies. Eastern-Essex Acquisition, D.T.E. 98-27, at 57 (1998).
c. Accounting Deferral
The Joint Petitioners seek Department approval of an accounting deferral of the
transaction and system integration costs incurred through the year 2003. The
Department has previously held that financial accounting treatment does not
automatically dictate ratemaking treatment. Massachusetts Electric Company,
D.P.U. 92-78, at 80-81 (1992); Bay State Gas Company, D.P.U. 89-81, at 33
(1989). For financial accounting purposes, it is appropriate to levelize the
annual transaction and system integration costs associated with this merger, in
order to facilitate an evaluation of the costs and benefits contemplated by the
merger. Accordingly, the Joint Petitioners are permitted to book the annual
transaction and system integration expenses incurred to Account 186 through the
year 2003, with an annual expense of $13,500,000 to be written off against the
respective accounts which gave rise to these expenses. At the end of the
deferral period, the Joint Petitioners shall provide the Department with an
itemization of the actual transaction and system integration costs, along with
the remaining unamortized balance, if any, in the account.
B. Acquisition Premium
1. Joint Petitioners' Proposal
The Joint Petitioners estimate that the merger will result in an acquisition
premium of approximately $502 million, equal to the difference between the $948
million purchase price for which ComEnergy System's shareholders will be able to
either convert their shares into those of Nstar or redeem for cash and ComEnergy
System's book value of approximately $446 million (Exhs. TJM-1, at 8; JJJ-1, at
4). This estimate was developed by multiplying the imputed purchase and exchange
price per share of ComEnergy System common stock, $44.10, by the 21.5 million
outstanding shares, for a total of $948 million, and then subtracting ComEnergy
System's December 31, 1998 book value of approximately $446 million, determined
by multiplying the December 31, 1998 book value per share of $20.75 by 21.5
million shares (Exh. JJJ-1, at 4). According to the Joint Petitioners, the
acquisition premium can not be precisely determined until the closing of the
merger, because of book value fluctuations for ComEnergy System and the 1.05 to
1.00 exchange ratio intended for shares, which would have an effect on the
number of Nstar shares that would be issued (id., at 5). The Joint Petitioners
intend to inform the Department of the actual amount of the acquisition premium
and related accounting entries within 90 days from the closing of the merger
(Tr. 5, at 486).
Because the transaction will be recorded using purchase accounting, the
acquisition premium, assuming an acquisition premium of $502 million, will be
recorded on the books of the Joint Petitioners, and consequently, on the books
of Nstar, and amortized over a period of 40 years as an annual charge to
earnings of approximately $12.6 million before income taxes, and $20.6 million
including income taxes (Exh. JJJ-1, at 7-8; Tr. 5, at 477-478). The Joint
Petitioners propose to allocate the acquisition premium among both ComEnergy
System's and BEC Energy's regulated operations on the basis of the estimated
savings each regulated utility would accrue as a result of the merger (Exhs. DTE
1-14; DTE 1-16; Tr. 5, at 474, 485-486, 520; Tr. 6, at 812-813). The Joint
Petitioners state that some allocation of the acquisition premium to BEC Energy
is reasonable because the merger-related savings will benefit both ComEnergy
System's and BEC Energy's regulated operations (Exh. DTE 1-14).
2. Intervenors' Proposals
a. DOER
DOER contested the Joint Petitioners' calculation of the recoverable acquisition
premium level. In considering the level of recoverable acquisition premiums,
DOER considered acquisition premiums to consist of two components: (1) the
difference between book and "true" market value as represented by the acquired
company's stock price at the time the merger was announced ("stock premium");
and (2) the difference between the actual purchase price and the stock premium
("control premium") (Exh. LAC at 16-17). DOER stated that inclusion of both the
stock premium and the control premium in the allowable acquisition premium would
overstate the costs of the merger, because shareholders would experience a
post-merger increase in the market value of their investment equal to the level
of the acquisition premium, allowing them subsequently to sell those shares for
the new, increased value (id. at 18). Therefore, DOER concluded that it was
neither necessary nor appropriate to require ratepayers to compensate
shareholders for anything more than the control premium (id. at 19-20).
DOER stated that it was possible that shareholders may experience dilution of
their stock value if the purchase price exceeded the "true" market value of the
acquired firm, based on a comparison of pre-merger and post-merger stock prices
(id. at 21). DOER estimated that the proposed merger may result in dilution to
BEC shareholders of approximately $50 million, at the most (id. at 21-22; Tr.
10, at 1246-1247). Regardless of the amount of the potential earnings dilution,
DOER stated that the Joint Petitioners must demonstrate that recovery of this
earnings dilution through rates is necessary to permit the merger to be
completed, which DOER noted is not necessary for business combinations in other
industries (Exh. LAC at 22).
b. MIT/Harvard
MIT/Harvard proposed that the acquisition premium be limited to approximately
$100,000,000, representing the actual cash component of the total purchase
price. According to MIT/Harvard, amortization of the non-cash portion of the
acquisition premium would allow shareholders to benefit through the "markup" of
book assets to market value, which would result in increased cash flow and be
likened to allowing regulated utilities to increase rate base to include
unrealized market value (Exh.
SLB-1, at 30).
MIT/Harvard determined the non-cash portion of the acquisition premium by first
recalculating the acquisition premium based on ComEnergy System's 1998 Form 10K,
assuming that the maximum number of shares are converted to cash and ignoring
the revaluation of ComEnergy System's unregulated subsidiaries (id., at 26).
Using the data from the 1998 Form 10K, MIT/Harvard estimated that the total
acquisition premium would be $500,059,252 (id.). MIT/Harvard then subtracted
$100,000,000 representing the cash payment option provided to ComEnergy System's
shareholders (id.; Exh. SLB-4). Therefore, MIT/Harvard concluded that the Joint
Petitioners' proposed acquisition premium was overstated by approximately $400
million (Exh. SLB-1, at 30-31).
According to MIT/Harvard, recovery of the full acquisition premium would result
in significant benefits for shareholders (Exh. SLB-1, at 31). In support of its
position, MIT/Harvard first noted that BEC Energy's earnings per share ("EPS")
for 1997 and 1998 were $2.71 and $2.77, respectively, while ComEnergy System's
EPS were $2.27 and $2.48, respectively (Exhs. SLB-1, at 31; SLB-4). After
factoring in the Joint Petitioners' calculations of the effects of the merger
and related transactions, including merger-related costs and savings, on Nstar's
total earnings and balance sheet, MIT/Harvard determined that even with the
inclusion of the amortization of the non-cash portion of the acquisition
premium, Nstar's post-merger EPS would increase to $2.986 (Exhs. SLB-1, at 32;
SLB-4). Exclusion of the non-cash portion of the acquisition premium increases
the EPS to $3.1438 (Exhs. SLB-1, at 32; SLB-4).
3. Positions of the Parties
a. Attorney General
The Attorney General argues that the Joint Petitioners inappropriately seek to
shift all the risks related to merger costs and savings, including the
acquisition premium, onto their respective ratepayers (Attorney General Brief at
14). The Attorney General maintains that the Joint Petitioners have failed to
demonstrate the presence of merger savings, much less the ability to achieve
such savings, in contravention of the Department's no net harm standard (id.).
The Attorney General faults the Joint Petitioners for failing to specify the
level of acquisition premium intended to be "pushed down" to each of the
distribution companies, or the basis for any allocation, thus rendering it
impossible for the Department to make any findings on the costs and benefits of
the proposed merger (id. at 14-15).
The Attorney General argues that mergers have occurred, and will continue to
occur, without specific "customer support mechanisms" such as acquisition
premium recovery, because benefits to shareholders exceed true merger costs (id.
at 29). The Attorney General recommends that the Department reject the requested
recovery level of acquisition premiums in this case, because of the failure of
the Joint Petitioners to provide sufficient information as to the allocation of
the acquisition premium among their operating subsidiaries (id. at 29-30, citing
Exhs. LAC-1, at 17-18; SLB-1, at 30, 32-34). In the alternative, the Attorney
General proposes that the recoverable acquisition premium be limited to the
control premium, as derived by DOER (Attorney General Brief at 29-30).
b. DOER
DOER notes that the Department has repeatedly found that the recovery of
acquisition premiums must be made on a case-by-case basis, after a petitioner
has demonstrated that such recovery is necessary to implement a merger that will
benefit customers and serve the public interest (DOER Brief at 15-16, citing
Mergers and Acquisitions, D.P.U. 93-167-A at 18-19 (1994); DOER Reply Brief at
3, citing Bay State-NIPSCO, D.T.E. 98-31, at 38 (1998); Eastern-Essex
Acquisition, D.T.E. 98-27, at 61 (1998); Mergers and Acquisitions, D.P.U.
93-167-A at 18-19 (1994)). Despite this requirement, DOER argues that the Joint
Petitioners have failed to demonstrate that their proposal meets Department
requirements, by providing almost no evidence to support their position that
recovery of the acquisition premium is warranted beyond "simple assertions" that
recovery of acquisition premiums is a condition of the merger agreement (DOER
Brief at 16-17, citing Exhs. TJM-1 at 12; JJJ-1 at 10). DOER argues that because
the Joint Petitioners have failed to present the full range of benefits the
merger will afford shareholders, the Department has been left unable to fully
examine the costs and benefits of the merger (DOER Brief at 35). Moreover, DOER
maintains that the merger will result in revenues for the Joint Petitioners in
the latter years of the proposed 40-year amortization that are significantly in
excess of those necessary to recover the costs associated with the merger (id.).
DOER contends that permitting recovery of the full acquisition premium would
overstate the costs of the merger, because the post-merger market value of the
combined companies would increase to a value equal to the acquisition premium,
allowing shareholders subsequently to sell those shares for the new value and
experience a windfall profit that had been funded by ratepayers (id. at
22-23).(30) By way of example, DOER points out that, if the merger is approved
and Nstar ultimately divests itself of its gas operations, that portion of the
acquisition premium allocated to ComGas may be included in the total selling
price for that utility (id. at 23-24). Therefore, DOER argues that while Nstar's
shareholders would immediately recoup that portion of the total acquisition
premium from the purchasing entity, the purchasing party would be seeking
recovery of an additional acquisition premium, thus forcing ratepayers to pay
twice for the acquisition premium (id. at 24). DOER urges the Department to
restrict any amortization of acquisition premiums to the amount that corresponds
to the control premium (id. at 33-34).
DOER argues that, contrary to the claims of the Joint Petitioners, the required
accounting entries associated with this merger would not give rise to true costs
for which shareholders must be compensated, reasoning that a "charge against
earnings" as postulated by the Joint Petitioners is an artificial construct.
According to DOER, financial texts caution against an overemphasis on charges
against earnings resulting from business combinations (id. at 30-31, citing
Copeland and Weston, Financial Theory and Corporate Policy at 25 (1983)).
Additionally, DOER contends that goodwill, as represented by an acquisition
premium, has an indeterminate useful life, which suggests that an examination of
whether to provide for an amortization of acquisition premiums should be
premised on whether the underlying asset is being "consumed" and whom the asset
is intended to benefit (DOER Brief at 32-34).
DOER distinguishes the acquisition premium from the concept of earnings
dilution, explaining that acquisition premiums relate to pre-merger prices,
whereas earnings dilution is a function of post-merger conditions to the extent
to which the purchase price of a firm exceeds its pre-merger market value (id.
at 25). DOER posits that, in the case of companies with multiple revenue
streams, such as regulated utilities involved in non-regulated ventures, it is
possible that the additional revenues associated with non-regulated ventures
will result in increased EPS, and thereby not subject that utility to earnings
dilution (id. at 25-27, citing Exhs. LAC at 22; DOER 1-3).
DOER notes that the Joint Petitioners anticipate that this merger will result in
increased EPS for the combined companies, offsetting the effects of any premium
paid in the acquisition (DOER Brief at 27-28, citing Exhs. LAC at 22; DOER 1-3).
In view of the opportunities afforded by Nstar's unregulated ventures, DOER
concludes that acquisition premiums be allowed only if (1) the merger has been
completed and is producing substantial net benefits, (2) the control premium and
other merger-related costs have been prudently incurred, and (3) the acquiring
firm's shareholders have experienced a reduction in value through post-merger
stock prices (DOER Initial Brief at 23, 29). DOER reasons that, given the
apparent benefits that the merger would bring to shareholders as described
above, it is "highly unlikely" that a reduction in the allowed acquisition
premium level would prevent the merger from taking place (id. at 35-36).
c. MIT/Harvard
MIT/Harvard argues that the Joint Petitioners' proposed treatment of the
acquisition premium unjustly benefits shareholders by allowing recovery of some
$400 million in non-cash-related acquisition premiums representing asset gains
beyond the actual level of investment or potential earnings dilution,
representing the non-cash portion of the acquisition premium (MIT/Harvard Brief
at 15). According to MIT/Harvard, the effect of the proposed merger will be an
increase in combined EPS for the Joint Petitioners, and a substantially greater
increase in EPS with the removal of the non-cash portion of the acquisition
premium, with shareholders reaping all of the benefits (id. at 17, citing Exh.
SLB-1, at 30-31). MIT/Harvard contends that although the entire acquisition
premium would be recognized as a cost for accounting purposes, the non-cash
portion does not require a cash outlay by the merging parties, and thus does not
constitute a recoverable merger-related expense (MIT/Harvard Reply Brief at 8).
d. AIM
AIM requests that the Department reevaluate its standards concerning recovery of
acquisition premiums (AIM Brief at 5-6). According to AIM, the Department's
standard provides no incentive for gas or electric companies to provide real and
substantial savings to ratepayers through mergers which would occur in any
event, even in the absence of acquisition premium recovery (id. at 6).
In the alternative, AIM advocates that if the Department determines that
recovery of acquisition premiums is permissible, ratepayers must be provided
with immediate and equitable customer rate reductions as a condition of any
merger (id.). Furthermore, AIM proposes that the Department apply a "least-cost"
standard(31) in evaluating the level of allowable acquisition premium, in order
both to evaluate BEC Energy's and ComEnergy System's System's decisionmaking
process independently, and to be consistent with the Department's findings in
Mergers and Acquisitions that the acquisition premium should be limited to the
amount necessary to permit a beneficial merger to take place (id. at 10, citing
Exh. LAC at 14; Mergers and Acquisitions, D.P.U. 93-167-A (1994)).
e. Joint Petitioners
The Joint Petitioners argue that recovery through rates of the acquisition
premium is a prerequisite for the merger to be completed, as expressed in the
Merger Agreement (Joint Petitioners Brief at 22-23, citing Exh. JJJ-3 (Supp.) at
59). The Joint Petitioners maintain that the level of the acquisition premium
was the result of arm's-length negotiations between the respective managements
of BEC Energy and ComEnergy System, performed consistent with their respective
fiduciary duties to their shareholders (Joint Petitioners Brief at 25-26).
According to the Joint Petitioners, the acquisition premium represents a real
cost to shareholders that, under purchase accounting, must be recorded on the
consolidated books of the Joint Petitioners and, ultimately, Nstar in order to
prevent earnings dilution for shareholders (id. at 25; Joint Petitioners Reply
Brief at 7-8). The Joint Petitioners argue that the intervenors have presented
no evidence that the purchase price paid for ComEnergy System's common stock was
excessive or significantly different from prices paid in other mergers recently
approved by the Department (Joint Petitioners Reply Brief at 9-10, citing
RR-DTE-1; Eastern-Essex Acquisition, D.T.E. 98-27, at 5, n.7 (1998)).
The Joint Petitioners contend that the intervenors' arguments concerning the
application of the control premium standard to define the recoverable level of
the acquisition premium are misplaced. The Joint Petitioners challenge the
theoretical assumptions behind the use of the control premium, and note that the
intervenors' own witnesses conceded that the acquisition premium, computed as
the difference between purchase price and book cost, represents a real,
non-tax-deductible charge against earnings (Joint Petitioners Brief at 33-34,
citing Tr. 10, at 1186-1187, 1245; Joint Petitioners Reply Brief at 6-7).
4. Analysis and Findings
The Department has stated that it will consider individual merger or acquisition
proposals that seek recovery of an acquisition premium, as well as the recovery
level of such premiums, on a case-by-case basis.(32) NIPSCO/Bay State
Acquisition, D.T.E. 98-31, at 38 (1998); Eastern-Essex Acquisition, D.T.E.
98-27, at 61 (1998), citing Mergers and Acquisitions, D.P.U. 93-167-A at 18-19
(1994). Under the Department's G.L. c. 164, ss. 96 public interest standard, a
company proposing a merger or acquisition must demonstrate that the costs of the
transaction are accompanied by benefits that warrant their allowance. Thus,
allowance or disallowance of an acquisition premium would be just one part of
the cost/benefit analysis under the G.L. c. 164, ss. 96 standard. Mergers and
Acquisitions, D.P.U. 93-167-A at 7 (1994). The fact that a merger agreement may
include, as one of its provisions, language to the effect that recovery of
acquisition premiums is a necessary condition of the merger, although useful to
know, would not, in and of itself, provide sufficient justification for approval
of recovery of the acquisition premium.
Concerning the Attorney General's and DOER's arguments favoring the use of the
control premium as the appropriate measure of the recoverable acquisition
premium, we note that the total difference between book value and the actual
purchase price represents a real cost that must be recorded on the books of
Cambridge Electric, ComElectric, and ComGas. Contrary to DOER's assertions, the
actual purchase price is the true market value of the acquired entity because it
is the intersection of what the sellers believe the acquired company is worth
and what the purchasers are willing to pay. BEC Energy is paying approximately
$948 million for assets with a reported book value of approximately $446
million. This payment over book value results in an acquisition premium of $502
million (Exh. TJM-1, at 8). The acquisition premium will be amortized over a
period of 40 years, with a corresponding effect on Nstar's balance sheet and
earnings equal to an annual charge of approximately $12.6 million over 40 years
(Exh. JJJ-1, at 7). Both the Joint Petitioners and the intervenors acknowledged
that the Joint Petitioners' definition of the acquisition premium amortization
constitutes a non-deductible charge against earnings (id.; Tr. 10, at 1186-1187,
1245). In order to recover after-tax earnings sufficient to offset the $12.6
million annual amortization, the distribution companies would have to generate
$20.6 million in annual revenues (Exh. JJJ-1, at 7-8). Contrary to DOER's
assertion, non-cash costs, such as those represented by the acquisition premium,
do have an effect on a utility's earnings. Unless Nstar obtains a reasonable
opportunity to maintain its EPS and common equity balance through recognition of
the acquisition premium, the result will be a loss in Nstar's earnings stream
and a diminution in the market value of Nstar's common stock (id., at 10).
Application of the control premium standard here would be genuinely harmful to
Nstar's shareholders to such a degree that the loss likely would eliminate any
reason for BEC Energy and ComEnergy System to consummate the merger, to the
ultimate detriment of ratepayers through loss of future economies that could be
realized under the proposed merger. NIPSCO/Bay State Gas Acquisition, D.T.E.
98-31, at 41 (1998).
Similarly, the Department does not agree with DOER on the need to link the
acquisition premium with particular assets. The Joint Petitioners are not
seeking inclusion of the acquisition premium in rate base, nor are they seeking
a return on the unamortized balance (Tr. 5, at 477-478).(33) The amortization of
the acquisition premium will have an effect on earnings that must be accounted
for as part of the Department's evaluation of the costs and benefits related to
the proposed merger.
Turning to MIT/Harvard's argument that the approximately $100 million actual
cash outlay by shareholders represents the appropriate level of the recoverable
acquisition premium, the Department notes that MIT/Harvard's witness
acknowledged that the entire balance of the acquisition premium represents an
actual cost that would be recorded on ComEnergy System's books (Tr. 10, at
1186-1187). Regardless of the form of payment being used in this merger, whether
represented by cash or common stock, there is a difference between ComEnergy
System's purchase price of approximately $948 million and reported book value of
approximately $446 million, of approximately $502 million (Exh. TJM-1, at 8).
Although MIT/Harvard has correctly pointed out that accounting principles do not
necessarily mandate ratemaking treatment, the Department has concluded above
that unless Nstar is accorded a reasonable opportunity to maintain its EPS and
common equity balance, the result would be a loss in Nstar's earnings stream and
a diminution in the market value of Nstar's common stock. Limiting recovery of
the acquisition premium to the approximately $100 million cash outlay would also
be genuinely harmful to Nstar's shareholders, to a degree that may render the
proposed merger between BEC Energy and ComEnergy System not viable. The negative
effect on this proposal and on future merger negotiations would be to the
ultimate detriment of ratepayers. Therefore, the Department rejects the use of
either a control premium standard or a cash outlay standard as the appropriate
measure of recoverable acquisition premium levels. The difference between the
purchase price and book value of ComEnergy System is fairly representative of
the economic costs that Nstar's shareholders would bear as a result of this
merger.
With regard to DOER's concern that future business decisions by Nstar may result
in ratepayers paying for multiple acquisition premiums, the Department
recognizes that a balance representing unamortized acquisition premiums may
remain on the books of a regulated utility that has been reacquired by a third
party.(34) As we noted in Mergers and Acquisitions, D.P.U. 93-167-A at 18-19
(1994), the Department will not automatically allow recovery of acquisition
premiums, but rather require a showing that such premiums are allowable to the
extent that there are benefits resulting from the merger at issue. Petitions for
recovery of future acquisition premiums that would be incurred as a result of
subsequent mergers would stand or fall on their own merits.(35)
With respect to the level of consideration paid by BEC Energy for ComEnergy
System, the record evidence demonstrates that the purchase price was evaluated
by the Joint Petitioners in comparison with purchase prices associated with
other recent mergers and acquisitions by LDCs, and in light of the potential
long-term benefits (Exhs. JSM-1, at 5-6; RDW-1, at 6-7; TJM-1, at 6; MIT/Harvard
1-22 (confidential)). A purchase price at a multiple of book value expresses a
buyer's expectations of the acquired company's future contributions to combined
operations. Eastern-Essex Acquisition, D.T.E. 98-27, at 64 (1998). The
particular exchange rate in merger or acquisition stock transactions involves a
number of matters of value to the buyer, including a premium for management
control and long-term strategic and economic value perceived by the buyer as
accruing from the transaction. Id.
Between 1987 and 1999, acquisition prices in gas and electric distribution
company mergers have ranged between 0.6 times and 3.0 times the book value of
the acquired company, with an average of 1.9 times book value (Exh. JSM-2;
RR-DTE-1). These prices represented price-earnings multiples ranging from 7.3 to
26.7 times earnings, with an average of 15.9 times earnings (RR-DTE-1). In more
recent transactions, i.e., those occurring since 1997, gas and electric
distribution company mergers have been based on purchase prices ranging between
1.0 times and 3.0 times the book value of the acquired company, with an average
of 2.1 times book value, and price-earnings multiples ranging from 9.9 times to
26.7 times earnings, with an average of 17.3 times earnings (id.). The 2.1 times
multiple over book value that BEC Energy paid for ComEnergy System is well
within the range of values paid and actually equal to the average since 1997.
Thus, it is clear that BEC Energy, as a knowledgeable and willing buyer, was
prepared to pay a premium over ComEnergy System's book value in exchange for
long-term growth potential, while remaining cognizant of its fiduciary
responsibilities to its shareholders to minimize any purchase price (Exh.
MIT/Harvard 1-39).
The proposed purchase price for ComEnergy System's stock is equal to 2.1 times
the reported book value (Exh. JSM-2; RR-DTE-1). This price represents a
price-earnings multiple of 21.2 times ComEnergy System's most recent earnings,
and a stock price 16.5 percent greater than the price prior to the announcement
of the merger (RR-DTE-1). The proposed purchase price and exchange ratio in this
case are consistent with industry experience (Exhs. JSM-2; RR-DTE-1). Both BEC
Energy's and ComEnergy System's independent advisors, Goldman Sachs and Barr
Devlin, have severally opined that the terms of the transaction are reasonable
(Exhs. RDW-1, at 6-7; MIT/Harvard 1-39; Tr. 4, at 349-350). Moreover, the
Department's review of ComEnergy System's financial and operating data, as
represented by its annual returns to the Department, SEC, and shareholders,
supports the analysis provided by the Joint Petitioners that these independent
analyses provide a reasonable market valuation for ComEnergy System. In the case
where negotiations occur between knowledgeable parties bargaining in good faith
to fulfill their fiduciary duties to their respective shareholders, the outcome
of that process is very likely to state or approximate the market value of the
acquired assets. That outcome obtains here. Therefore, the Department finds that
the proposed purchase price for ComEnergy System's common stock and proposed
exchange ratio are in line with experience in other acquisitions and represent
reasonable and valid expressions of today's market conditions. Eastern-Essex
Acquisition, D.T.E.
98-27, at 64-65 (1998).
Turning to the actual level of the acquisition premium, the Joint Petitioners
have estimated an acquisition premium level of $502,000,000, while MIT/Harvard
has estimated an acquisition premium level, including the non-cash portion, of
$500,059,252 (Exhs. SLB-1, at 26; SLB-4). Although the difference between the
two estimates is small, the Department must determine a reasonable measure of
the allowable acquisition premium level to arrive at the total estimated costs
associated with the merger, in order to complete our review of the general
balancing of costs and benefits required under our G.L. c. 164, ss. 96
consistency standard. MIT/Harvard relied on ComEnergy System's Form 10K for the
year 1998 to develop the acquisition premium estimate provided in Exhibit SLB-1
(Exh. SLB-1, at 26). The Form 10K provides the most currently-available
information concerning asset book values and the number of common shares
outstanding, in greater detail than would have been available to the Joint
Petitioners at the time of their filing. The Department accepts MIT/Harvard's
acquisition premium calculation of $500,059,252 as a reasonable estimate for
purposes of our evaluation of the costs associated with the merger. The
Department finds that the Joint Petitioners have demonstrated that recovery of
$500,059,252 in acquisition premiums is necessary in order to consummate the
merger.
The actual level of the acquisition premium will be dependent upon a number of
factors, including the actual number of ComEnergy System shares outstanding upon
the closing date, ComEnergy System's book value as of the completion of the
merger, the extent to which ComEnergy System shareholders exercise the cash
buyout option, and the revaluation of ComEnergy System's unregulated assets.
Thus, the actual amount of the acquisition premium cannot be precisely
calculated until the consummation date or shortly thereafter, although its range
is formulaically determined. Eastern-Essex Acquisition, D.T.E. 98-27, at 65
(1998). The formula for calculating the amount is sound and acceptable. The
Joint Petitioners are hereby directed to provide the Department with a copy of
the journal entries or a schedule summarizing such entries upon completion of
the merger, in sufficient detail so as to provide the actual acquisition
premium.
C. Merger-Related Savings
1. Introduction
The Joint Petitioners state that the merger of BEC Energy and ComEnergy System
should result in approximately $667 million of estimated savings during the
ten-year period 2000 through 2009, less $24 million in pre-merger cost-reduction
measures already planned or initiated, for merger-related savings of
approximately $643 million (Exh. TJF-1, at 5-6; Tr. 4, at 330).(36) Although the
Joint Petitioners considered that merger-related savings generally would
continue into future periods, the savings estimates were presented in nominal
dollars and limited to the first ten years following the merger (Exh. TJF-1, at
11). The savings calculation was based on savings that were attributable to the
merger, i.e., those savings would not be attainable but for the merger of the
two business trusts and their combination under Nstar (id. at 7, Exh. TJM-1 at
7). The Joint Petitioners considered the potential for merger-related savings in
(1) corporate, field, and field support staff, (2) corporate and administrative
programs, (3) purchasing economies, and (4) energy sourcing (Exh. TJF-1, at
24-25).
2. Corporate, Field, and Field Support Staff
The Joint Petitioners estimate that $403 million in savings will result from
corporate, field, and field support staffing reductions (id., at 37). In
calculating the estimate, the Joint Petitioners assumed that existing corporate,
administrative, and technical support functions within the two holding companies
could be consolidated (id., at 33).(37) The Joint Petitioners determined the
payroll reductions by first identifying employment positions at BEC Energy and
ComEnergy System that could be reduced through the merger, primarily through the
creation of an integrated corporate and administrative organization (id., at
34). As a result of this analysis, the Joint Petitioners estimated that 362
positions could be eliminated as a result of the merger, of which 296 positions
are in corporate and operations support functions, and the remaining 66
positions are in field services (id., at 37). The Joint Petitioners then applied
an average salary level by function to each of the position reductions in these
respective areas, based on 1998 salary levels for each company and escalated by
one year, to derive an average blended salary of $60,000 per position (id., at
35; Tr. 4, at 321-322, 332-335). To calculate payroll overhead, the Joint
Petitioners relied on a blended benefits loading rate of 42.4 percent to
estimate aggregate benefits costs (Exhs. TJF-1, at 33-37; TJF-5B at 1; Tr. 4, at
360-361). To account for capitalized payroll, a blended capitalization rate of
7.8 percent for corporate positions and another blended capitalization rate of
30.4 percent for field and field support positions was applied based on the
stand-alone companies (Exhs. TJF-1, at 36; TJF-5B at 2). As a result of this
analysis, the Joint Petitioners concluded that corporate, field support, and
field staff savings of $403 million would result from the merger.
3. Corporate and Administrative Programs
The Joint Petitioners estimate that the merger will result in savings of
approximately $210.2 million in corporate and administrative programs. These
savings are distributed into 12 categories: (1) $17.4 million in administrative
and general overhead savings; (2) $8.8 million in public relations; (3) $20.4
million in benefits administration; (4) $16.1 million in insurance; (5) $25.7
million in information services operations and maintenance; (6) $50.8 million in
capitalized information services costs; (7) $22.6 million in professional
services; (8) $42.3 million in facilities costs; (9) $1.7 million in shareholder
services; (10) $1.0 million in vehicles expense; (11) $2.4 million in
association dues; and (12) $1.9 million in credit facilities expenses (Exh.
TJF-1, at 38-59). For each of these expense categories, the Joint Petitioners
developed savings estimates based on a number of considerations, including
conversations with selected BEC Energy and ComEnergy System personnel, analysis
of fixed and variable expenses, and the use of assumptions (Exhs. TJF-5D -
TJF-5P; Tr. 4, at 342-343; 354-396).
4. Purchasing Economies
The Joint Petitioners estimate that the merger will result in a total of $46.3
million in savings through purchasing economies over a ten-year period. These
savings represent: (1) $34.9 million in procurement savings resulting from the
increased purchasing volumes of materials and supplies and the greater
purchasing power created by the merger, (2) $1.4 million in inventory savings
resulting from standardization and sharing of spare parts and components, and
(3) $10.0 million in contract service savings resulting from the aggregation of
work activities and increased purchasing leverage with service providers (Exh.
TJF-1, at 55-58). For each of these expense categories, the Joint Petitioners
developed savings estimates based on a number of considerations, including
historical inventory experience, inventory turnover, and contract service
requirements (Exhs. TJF-5Q, TJF-5R; TJF-5S; Tr. 4, at 400-413). The Joint
Petitioners explained that procurement and inventory savings are difficult to
quantify, because they hinge on a prediction of how well the combined system
will be able to use its increased size to negotiate lower unit prices (Exh.
TJF-1, at 58). The Joint Petitioners claimed that the results of prior mergers
show that estimated savings in purchasing have been achieved (id.; Exh. DTE
1-30; Tr.
4, at 412-413).
5. Energy Sourcing
The Joint Petitioners expect that, because the electric distribution companies'
different load and peaking profiles, the combination of Boston Edison, Cambridge
Electric, and ComElectric into one system entity will result in avoided capacity
costs associated with the solicitation and procurement of standard offer and
default service of $7.1 million over the 2000-2009 period (Exh. TJF-1, at 60;
Tr. 7, at 849-852). The Joint Petitioners calculated the savings by using a base
forecast of estimated capacity payments over the 2000-2009 period, and
multiplying the base forecast by the estimated reduction in demand (capacity) to
arrive at the monthly savings (Exh. TJF-5T). The Joint Petitioners expect to
solicit bids for combined standard offer service at the end of 1999, covering
100 percent of Boston Edison's load and 64 percent of Cambridge Electric's and
ComElectric's combined load (Tr. 7, at 852-853).(38) This combined load will
then be adjusted for attrition for each successive year of the standard offer
(id.). Because the combined load of the two companies is expected to be less
than the sum of their individual loads, the savings in standard offer service
purchases will be included in the bids the electric distribution companies
expect to receive (id., at 851-852). In preparing this estimate, the Joint
Petitioners assumed that the electric distribution companies would continue to
supply a decreasing portion of the standard offer service until the end of the
standard offer period in 2004 (id., at 851-855). The Joint Petitioners also
assumed that 100 percent of the default service load will be supplied by the
electric distribution companies through the year 2009 (Tr. 7, at 856).
2. Positions of the Parties
a. Attorney General
The Attorney General asserts that the benefits of a merger must at least equal
the associated costs, including the acquisition premium, to consumers before the
costs may be allowed for ratemaking purposes (Attorney General Brief at 14,
citing Eastern-Essex Acquisition, D.T.E. 98-27, at 8 (1998); Mergers and
Acquisitions, D.P.U. 93-167-A at 18-19 (1994)). The Attorney General maintains
that the record does not contain cost and savings information specific to the
four distribution companies (Attorney General Brief at 14). Therefore, the
Attorney General concludes that the Department would be unable to make any
findings as to the costs and benefits that the proposed merger and Rate Plan
might produce for each of the distribution companies (id. at 15).
b. DOER
DOER opposes what it considers the Joint Petitioners' reliance on merger savings
produced from through internal estimates (DOER Brief at 13). DOER contends that
because an independent evaluation of the prudency of the costs and projected
savings does not exist, the Department has been left dependent upon the Joint
Petitioners' assessment of the costs necessary for the merger to proceed and the
level of projected merger-related savings (id.).
c. AIM
AIM contends that the Joint Petitioners have made it clear that merger-related
savings are wholly dependent upon how the Joint Petitioners execute their
post-merger plans (AIM Brief at 8). AIM argues that although the actual level of
merger-related savings is dependent upon the actions of the Joint Petitioners,
there is no incentive for the Joint Petitioners to achieve the level of savings
proposed here (id.).
d. Joint Petitioners
The Joint Petitioners contend that the savings demonstrated in this proceeding
likely make the Rate Plan the single most beneficial utility proposal ever
reviewed by the Department (Joint Petitioners Brief at 17). The Joint
Petitioners argue that Deloitte Consulting conducted a comprehensive, detailed,
and well-documented analysis of merger-related savings using direct analysis,
estimation, and comparisons to other transactions, and that the results of this
analysis are unrebutted (id. at 17-18). The Joint Petitioners maintain that the
Attorney General's criticisms of Deloitte Consulting's analysis are based on
misleading and inaccurate assertions about the record evidence (Joint
Petitioners Reply Brief, at 12-14). Additionally, the Joint Petitioners contend
that the identified merger-related savings will increase through the compounding
effect of future inflation, and will continue indefinitely into the future
(Joint Petitioners Brief, at 21, citing Exh. TJF-1, at 11; Tr. 3, at 298; Tr. 5,
at 565)
3. Analysis and Findings
To meet the G.L. c. 164, ss. 96, public interest standard, merger-related costs
must be accompanied by offsetting merger-related benefits that warrant their
recovery, including the cost of any premium sought. Eastern-Colonial
Acquisition, D.T.E. 98-128 at 5-6 (1999); NIPSCO-Bay State Acquisition, D.T.E.
98-31, at 9-10 (1998); Eastern-Essex Acquisition, D.T.E. 98-27, at 8-10 (1998).
Therefore, in order to recover merger-related costs, a petitioner must
demonstrate savings related to the merger that are at least equal to the costs
of the merger.
The Department recognizes that the savings presented by the Joint Petitioners
are based on forecast amounts. However, the determination of savings through
2009 requires the Department to consider both historic and projected savings.
Reliance on precedent based solely on historic test-year cost of service is not
a sufficient guide in this case. Eastern-Colonial Acquisition, D.T.E. 98-128, at
20 (1999). The evaluation of these savings is not subject to the same level of
precision as generally can be attained in a traditional rate case setting. Id.
Therefore, the Department's review of the Joint Petitioners' savings estimates
must be based on whether the figures proposed by the Joint Petitioners are
reasonable estimates.(39)
With respect to the Joint Petitioners' estimate that $403 million in savings
will result from corporate, field, and field support staffing reductions, the
Joint Petitioners have presented a reasonable, considered estimate that 296
corporate and operations support positions, and 66 field support positions,
could be eliminated through the creation of an integrated corporate and
administrative organization (Exh. TJF-1, at 34). The Department also accepts the
Joint Petitioners' use of an average blended salary of $60,000 per position as
consistent with the compensation levels associated with the employee positions
that may be eliminated (id., at 35). The Department also accepts the Joint
Petitioners' selection of a 42.4 percent blended benefits loading rate as a
well-developed estimate of the payroll overhead associated with the employee
positions proposed to be eliminated as a result of the merger. Finally, the
Department accepts the Joint Petitioners' capitalized payroll estimates as
consistent with the recent experience of the Joint Petitioners (Exhs. TJF-1, at
36; TJF-5B at 2). The Department concludes that the Joint Petitioners have
provided a fair and reliable estimate of the savings that would result from the
merger. Accordingly, the Department uses a corporate operations and support
staffing savings estimate of $403 million for purposes of evaluating the costs
and benefits associated with the proposed merger.
The Department notes that the vast majority of anticipated merger-related
savings is due to corporate, field, and field support staff reductions. The
Department's standard of review for mergers lists societal costs as a factor,
among others, that must be weighed and balanced against the benefits resulting
from the merger and Rate Plan. The Department has interpreted societal costs to
include effects on employees. Eastern-Colonial Acquisition, D.T.E. 98-128, at 86
(1999); Eastern-Essex Acquisition, D.T.E. 98-27, at 42 (1998). We do not lightly
regard the effect of this or any other merger on employment. While perpetuation
of job redundancies in a consolidated Nstar system would impose avoidable costs
and thus be detrimental to ratepayers, the elimination of these redundancies can
and should be accomplished in a way that mitigates the effect on BEC Energy's
and ComEnergy System's employees. Eastern-Essex Acquisition, D.T.E. 98-27, at 42
(1998). The Joint Petitioners have stated their commitment to undertake all
reasonable efforts to mitigate the effect of the consolidation of BEC Energy's
and ComEnergy System's operations on the estimated 362 employees whose positions
are expected to be eliminated as a result of the merger (Exh. JJJ-1, at 21). To
follow up on the effectiveness of the Joint Petitioners' proposed efforts to
assist displaced workers, the Department directs the Joint Petitioners to submit
annual reports detailing their displaced employee assistance efforts. Three
reports are required. The first report is to be filed one year after the
consummation of the merger, with the second and third reports to be submitted
annually thereafter. Eastern-Essex Acquisition, D.T.E. 98-27, at 44 (1998).
Turning to the area of corporate and administrative program savings, the
Department notes that the Joint Petitioners estimate that $50.8 million of the
$210 million in corporate and administrative program savings are associated with
foregoing duplicative or unnecessary information and computer-related systems
(Exh. TJF-5H). The Joint Petitioners took into account projected savings of
computer and information projects that would have likely been implemented
between the years 2000-2003 in the absence of the merger (id., at 15). The Joint
Petitioners used 1998 estimates and an escalation rate of 2.5 percent to project
the costs of computer and other information systems during the latter part of
the four-year rate freeze, and consequently overlook technological innovation
and advancements that would be expected during that period. Therefore, the
Department considers the Joint Petitioners' estimate information-system savings
to be somewhat overstated. For purposes of this analysis, the Department has
removed the 2.5 percent annual escalation factor applied by the Joint
Petitioners to the information-system cost estimates, and has recalculated the
savings estimate. Based on this analysis, the Department concludes that the
Joint Petitioners' information systems-related savings estimate of $50.8 million
should be reduced by $1.3 million, to $49.5 million.
The Department has reviewed the Joint Petitioners' estimates in the other 11
corporate and administrative programs areas where savings estimates were
developed. The Joint Petitioners have estimated these savings based on a review
of the fixed and variable costs associated with each of these cost categories,
and Deloitte Consulting's experience attained through other utility mergers for
these types of expenses (Exhs. TJF-5D -5P; Tr. 3, at 310). The Joint Petitioners
have provided a fair and reasonable estimate of the savings that would result
from the merger in each of these areas. Therefore, the Department accepts the
Joint Petitioners' savings estimated in these 11 corporate and administrative
program areas. Accordingly, the Department uses a corporate and administrative
savings program estimate of $208.9 million, as compared with the Joint
Petitioners' estimate of $210.2 million, for purposes of evaluating the costs
and benefits associated with the proposed merger.
With respect to purchasing economies, the Joint Petitioners assumed that the
cost reduction for engineered materials would be five percent, with a cost
reduction for consumables and stock/standard materials of seven percent, based
on management expertise and experience with prior transactions (Exh. TJF-1, at
56). The Department has reviewed the analogous savings projections for the 16
mergers and acquisitions in the gas and electric industry described in Exhibit
AG 4-8. Based on that set of transactions, the highest expected cost reduction
for both engineered and stock/standard material was five percent (RR-DTE-5). The
Department concludes that the seven percent reduction for consumables and
stock/standard materials is insufficiently unsupported on the record. Based on
the experience from other utility mergers, the Department concludes that a five
percent reduction in the cost of consumables and stock/standard materials may be
reasonably expected as a result of the merger. Application of the five percent
savings rate in lieu of the Joint Petitioners' seven percent rate for combined
stock materials of $33.8 million and consumable materials of $2.1 million,
escalated at a rate of 2.5 percent for two years as provided in Exhibit TJF-5Q,
results in savings to engineered materials, consumables and stock/standard
materials of approximately $26.1 million, versus the Joint Petitioners' estimate
of $34.9 million for this particular cost category. Additionally, the Joint
Petitioners have proposed savings estimates for inventory and contract services
totaling $11.4 million, which the Department accepts as consistent with the
experience of Deloitte Consulting (Exhs. TJF-5R; TJF-5S; Tr. 4, at 405-413).
Accordingly, the Department uses a purchasing savings estimate of $37.5 million,
as compared with the Joint Petitioners' estimate of $46.3 million, for purposes
of evaluating the costs and benefits associated with the proposed merger.
With respect to energy purchases, the Department has reviewed the savings
estimate, including the data and assumptions relied upon by the Joint
Petitioners. There are difficulties inherent in estimating cost savings in these
areas, particularly those related to standard offer service. However, the Joint
Petitioners have provided a fair and reliable estimate of the savings that would
result from the merger, taking into account load and peaking profiles and the
opportunities afforded by vendor leveraging (Exh. TJF-1, at 59-60). Accordingly,
the Department uses an energy savings estimate of $7.1 million for purposes of
evaluating the costs and benefits associated with the proposed merger.
The Department recognizes that the savings presented by the Joint Petitioners
are based on forecast amounts. As noted in Eastern-Colonial Acquisition, D.T.E.
98-128, at 18 (1999), projections of future events are not subject to the same
standards of measurement and evaluation that the Department uses in a rate case;
rather, they can be judged in terms of whether they are substantiated by past
experience, and supported by logical reasoning founded on sound theory. The
evidence demonstrates that the projected merger-related savings will be $656.9
million over the ten-year period between the years 2000 and 2009, less $24
million in pre-merger initiatives, for total merger-related savings of $632.5
million.
D. Recovery of Merger-Related Costs
1. Joint Petitioners' Proposal
Under the Rate Plan, the costs associated with the merger will be recovered in
two ways. The transaction costs and system integration costs will be amortized
for ratemaking purposes over a ten-year period, and the acquisition premium will
be amortized over a 40-year period (Exh. RDW-1, at 10-11). As described above,
the Joint Petitioners estimated that the combined transaction costs and system
integration expense would be approximately $111 million, with an estimated
acquisition premium of approximately $502 million (Exhs. TJF-5U; JJJ-1, at 4).
During the first ten years after the merger, the average amount and associated
tax effect of the transaction costs, system integration costs, and acquisition
premium would be approximately $34.1 million per year (Exh. JJJ-1, at 9). During
the subsequent 30-year period, when the recovery of transaction and system
integration costs is completed, the annual amortization of the remaining
unamortized acquisition premium and associated tax effect will total
approximately $20.6 million (id.). During the distribution rate freeze, the
Joint Petitioners will be at risk to achieve cost synergies sufficient to offset
these costs (Exh. RDW-1, at 10-11). After the distribution rate freeze, rate
proceedings for any of the four distribution utilities will take into account
both the recovery of merger costs (including the acquisition premium) and
savings associated with the merger (id.).
Because the Joint Petitioners are seeking to demonstrate through this proceeding
that merger-related savings will exceed merger-related costs, the Joint
Petitioners consider a fundamental feature of the Rate Plan to be the recovery
of their merger-related costs (including the acquisition premium) through base
rates at the time of their next base rate proceedings (Exh. TJM-1, at 11; Tr. 5,
at 489-504). While the Joint Petitioners may request recovery of merger-related
costs through base rates after the end of the four-year rate freeze, the Rate
Plan does not require the filing of a base rate case at that time (Tr. 5, at
489-504; Tr. 8, at 1027-1029). Because the Joint Petitioners seek to make a
demonstration here of merger-related savings, they do not propose to demonstrate
continued net savings resulting from the merger as part of any future rate
proceeding (Tr. 8, at 1027-1029).
2. Positions of the Parties
a. Attorney General
The Attorney General states that the Rate Plan should not be approved on the
terms and conditions proposed by the Joint Petitioners (Attorney General Brief
at 12). According to the Attorney General, because the Rate Plan would permit
the Joint Petitioners to recover merger-related costs without any commitment to
restrain these costs and offset them by demonstrated merger-related savings, the
Joint Petitioners have not provided any assurances that ratepayers will not be
harmed by the Rate Plan (id at 12, citing Tr. 8, at 1027-1028). Therefore, the
Attorney General concludes that the Department would be unable to make any
findings as to the costs and benefits that the proposed merger and Rate Plan
might produce for each of the distribution companies (Attorney General Brief at
15).
b. DOER
DOER contends that Department precedent establishes that expenses for which a
utility seeks base rate recovery be based on actual expenses incurred in a
historical test year (DOER Brief at 11, citing Boston Gas Company, D.P.U. 96-50
(Phase I) at 50 (1996)). DOER asserts that because the Petitioners are
presenting expenses prospectively for ratemaking purposes, their filing is
inconsistent with Department precedent. DOER contends that the only mechanism
established by the Department for the preapproval of costs focused on the
preapproval of electric company investment in new generating facilities and
other resource acquisitions under a prudency standard (DOER Brief at 9, 12).(40)
Further, DOER states that the merger-related costs did not encompass "major
incremental electric company investment" (id. at 9, citing Electric Generating
Facilities, D.P.U. 86-36-C at 98 (1988); D.P.U. 86-36-E at 1 (1988); 220 C.M.R.
ss. 9.00, et seq.).
DOER states that in order to recover investment costs (i.e., acquisition
premiums) in base rates, the Department requires a company to demonstrate that
the investment is "least cost" from the standpoint of ratepayers and that all
reasonable alternatives have been sought (DOER Brief at 14; DOER Reply Brief at
4). DOER asserts that the Department typically requires investments for which
preapprovals are being sought be put to a competitive test before the costs are
placed into rates (DOER Brief at 14; DOER Reply Brief at 4, citing Electric
Generation Facilities, D.P.U. 86-36-E at 3; IRM Streamlining, D.P.U. 94-162). In
contrast to the requirements established by the Department, DOER argues that the
Joint Petitioners have not made a reasonable demonstration that the
merger-related costs represent a "least cost" investment from the standpoint of
ratepayers (DOER Brief at 15; DOER Reply Brief at 4). Therefore, DOER concludes
that the Joint Petitioners' proposed recovery of the acquisition premium does
not comply with the "least cost" standard and as such, should be denied (DOER
Brief at 15; DOER Reply Brief at 4).(41)
c. MIT/Harvard
MIT/Harvard raises two issues relating to the Joint Petitioners' proposed
preapproval of the merger-related costs. First, MIT/Harvard states that the
Joint Petitioners' basis for seeking approval to recover the merger-related
costs rests upon projected merger related savings anticipated to occur as a
result of operational synergies (MIT/Harvard Brief at 4). Second, the
integration of COM/Energy's and Boston Edison's operations will introduce issues
of cross-subsidization relating to the allocation of the merger-related costs
and savings among the respective utilities and ratepayers (id.).
MIT/Harvard contends that if the level of projected merger-related savings are
realized, these savings should be shared in an equitable manner with ratepayers
(MIT/Harvard Reply Brief at 6).(42) MIT/Harvard argues that rather than sharing
the "substantial and demonstrated" merger-related savings with ratepayers
immediately when they occur, the Joint Petitioners' proposal only offers an
"illusionary assurance" that cost savings will flow to ratepayers through the
normal ratemaking process (id.). According to MIT/Harvard, the Petitioners
actually intend to account for merger-related savings at some indefinite point,
only when the Joint Petitioners file a distribution base rate case after the
expiration of the Rate Plan (id.). Therefore, MIT/Harvard contends that the
Joint Petitioners are able to enjoy savings into perpetuity, while preserving
the right to increase rates if the savings are not realized (id.).
In addition, MIT/Harvard argues that the Joint Petitioners have not offered any
assurances that excessive earnings will not occur during the term of the Rate
Plan or after the proposed Rate Plan (id.). MIT/Harvard maintains that the
effect of the merger will be to increase Nstar's EPS (MIT/Harvard Brief at 17;
citing Exh. SLB-1, at 30-31).(43) Although the Joint Petitioners state that the
proposed rate freeze does not preclude the ability of the Department or the
Attorney General to seek a review of rates in accordance with G.L. c. 164, ss.
93, MIT/Harvard contends that the Joint Petitioners seek inappropriately to
place the burden on the other parties to determine whether the Joint Petitioners
are receiving excessive earnings (MIT/Harvard Reply Brief at 7). MIT/Harvard
asserts that based on the record evidence substantiating the level of
merger-related savings, the Joint Petitioners' approach is inconsistent with the
Department's obligation to establish just and reasonable rates (id.). Further,
MIT/Harvard argues that by the time excess earnings are detected, investigated,
and rectified, "any excess gains would inure solely to shareholders with no
refund to ratepayers legally available" (id.).
d. AIM
AIM states that the Department should reject the proposed Rate Plan because it
is not consistent with the public interest (AIM Brief at 5).(44) AIM contends
that guaranteeing recovery of the merger-related costs without demonstration of
immediate ratepayers savings results in an economic benefit to shareholders at
the expense of ratepayers (id.).(45) AIM asserts that the estimated
merger-related savings are contingent upon how the Joint Petitioners execute
their Rate Plan and as such, are within their control (id. at 8). AIM contends
that ratepayers will only realize any significant incentives during the
four-year rate freeze period, with no assurance that the Joint Petitioners will
be diligent in their effects to produce savings thereafter (id. at 10).
Further, AIM argues that if the merger-related savings do not materialize, the
Rate Plan does not include a method that would tie the projected savings
achieved to the recovery of the acquisition premium (id. at 8-9). AIM asserts
that since the Rate Plan fails to treat ratepayers and shareholders equally the
Department should modify the Rate Plan so that ratepayers are guaranteed
recovery of all merger-savings (46) (id. at 8).
AIM concurs with the testimony of MIT/Harvard's witness requiring a "least-cost"
approach to assess the prudency of merger and acquisition deals that had been
negotiated "behind closed doors" (id. at 10). Citing DOER's witness, AIM asserts
that this process will eliminate the need for a speculative examination of
whether the merger yields the optimal solution to benefit ratepayers (id.;
citing Exh. LAC at 14). Further, AIM contends that the "least-cost" standard is
consistent with Mergers and Acquisitions requiring merging entities to
demonstrate that the acquisition premium is limited to the amount necessary to
permit a beneficial merger to occur (AIM Brief at 10).
AIM recommends that the Department hold the Joint Petitioners to the estimated
cost savings projections stated in its Rate Plan. Furthermore, AIM requests that
the Joint Petitioners be required to use the "rate adder" method (47) discussed
by MIT/Harvard's witness to identify savings before allowing any recovery of
merger-related costs (id. at 12).
e. Joint Petitioners
The Joint Petitioners assert that the record establishes that the costs of the
merger will not exceed merger-related savings (Joint Petitioners Reply Brief at
9). Further, the Joint Petitioners assert that because shareholders bear the
risk of successful implementation of the savings initiatives, the Rate Plan
maximizes the incentive for the Joint Petitioners to achieve the savings
(id.).(48)
The Joint Petitioners contend that the ten-year, straight-line amortization of
the costs to achieve the merger, subject to adjustment to actual expenditures,
is a reasonable cost-recovery method (Joint Petitioners Brief at 25). According
to the Joint Petitioners, the proposed Rate Plan ensures that the merger-related
savings will flow to ratepayers through the normal ratemaking process and the
merger-related costs that make the savings possible must also be accounted for
in rates to avoid earnings dilution (id. at 22).(49) The Joint Petitioners state
that the manner in which merger-related costs will be recovered under the
proposed Rate Plan is reasonable and is to the benefit of ratepayers (id. at
23).
The Joint Petitioners state that the precedent relating to "least-cost"
transactions involves investments and contractual obligations in electric
generation facilities and that the Department would be "hard pressed" to find
any investment or contractual obligation that will result in the level of
long-term customer benefits as presented and demonstrated by the proposed merger
(Joint Petitioner Reply Brief at 9). The Joint Petitioners further assert that
the merger between the Joint Petitioners cannot be judged against least-cost
"notions" and "discarded regulatory mechanisms" that assume the appropriateness
of a competitive bidding process (Joint Petitioners Brief at 35). According to
the Joint Petitioners, the merger is a direct result of detailed negotiations
bargained in "good faith" between two parties that provides substantial
long-term benefits to ratepayers and shareholders and therefore, does not fall
under the "least cost" standard (id.).
3. Analysis and Findings
The Rate Plan in this proceeding raises issues similar to those addressed by the
Department in our previous G.L. c. 164, ss. 96 reviews of the propriety of
allowing recovery of acquisition premiums and other costs associated with a
merger. See, e.g., Eastern-Colonial Acquisition, D.T.E. 98-128 (1999);
NIPSCO-Bay State Acquisition, D.T.E. 98-31 (1998); Eastern-Essex Acquisition,
D.T.E. 98-27 (1998); Mergers and Acquisitions, D.P.U. 93-167-A (1994). In those
cases, the Department found that mergers and associated cost recovery proposals
must be "consistent with the public interest." Eastern-Colonial Acquisition,
D.T.E. 98-128 at 4-5 (1999). See also, NIPSCO-Bay State Acquisition, D.T.E.
98-31 at 9-11 (1998); Eastern-Essex Acquisition, D.T.E. 98-27 at 8-10 (1998).
The Department has reaffirmed that the public interest standard must be
understood as a "no net harm" standard. Eastern-Colonial Acquisition, D.T.E.
98-128 at 4-5 (1999). See also, NIPSCO-Bay State Acquisition, D.T.E. 98-31 at
9-10 (1998); Eastern-Essex Acquisition, D.T.E. 98-27 at 8 (1998). Here, the
Joint Petitioners' G.L. c. 164, ss. 94 Rate Plan's conformance to the public
interest will be similarly assessed.
The transaction and system integration cost recovery features of the Rate Plan
differ from those found in previous merger proposals, in that the Joint
Petitioners are seeking specific findings as part of this proceeding on
projected merger-related costs, so that the merger-related costs may be
recovered. The cost recovery features here can be contrasted with those in other
merger petitions recently considered by the Department.
In Eastern Enterprises' acquisition of Essex County Gas Company, the Department
permitted those petitioners the opportunity to recover their merger-related
costs during a 10-year rate freeze, with shareholders bearing the risk that
merger-related costs might exceeded merger-related benefits. Eastern-Essex
Acquisition, D.T.E. 98-27, at 68 (1998). In NIPSCO Industries' acquisition of
Bay State Gas Company, the Department accepted that a showing of quantifiable
benefits would be made in a future proceeding after the end of a two-year rate
freeze, but made future recovery of merger-related costs dependent on such a
showing. NIPSCO-Bay State Acquisition, D.T.E. 98-31, at 47 (1998).(50) In
Eastern Enterprises' acquisition of Colonial, the Department approved the
petitioners' proposed tracking mechanism which will be used to determine the
amount of merger-related costs be allowed into cost-of-service in the future,
after the end of the 10-year rate freeze. That tracking mechanism would measure
future merger-related savings by comparing actual cost-of-service to a model of
what Colonial's costs would have been absent the merger. Eastern-Colonial
Acquisition, D.T.E. 98-128, at 65 (1999). All acquisitions will have unique
characteristics, and the Department has committed to a case-by-case review,
tailored to circumstances presented. Id., at 20 n.23 (1999); Mergers and
Acquisitions, D.P.U. 93-167-A at 7.
In order for the Department to approve, in this proceeding, the future amounts
of merger-related costs that will be allowed in cost-of-service in a future rate
proceeding, the Department would have to have a high degree of confidence in the
demonstration that offsetting savings will be realized. Reaching that level of
confidence requires an evaluation of both the margin between projected
merger-related costs and savings (i.e., a margin of error in projections) and
the quality of the evidence supporting those projections. As noted earlier, the
quality of projections can be judged in terms of whether they are substantiated
by past experience, and supported by logical reasoning founded on sound theory.
Eastern-Colonial Acquisition, D.T.E. 98-128, at 18 (1999).
The Department has found that projected merger-related savings of $632.5 million
would probably be realized through the merger between the years 2000 and 2009.
The Joint Petitioners have provided detailed, substantial, and credible evidence
in support of these projections, as Mergers and Acquisitions, D.P.U. 93-167-A at
7, requires (Exhs. TJF-3, TJF-4, TJF-5A though 5V; Tr. 3, at 310). The projected
merger-related costs during that same period, including the amortization of the
acquisition premium, are estimated to be $308.7 million. These merger-related
costs consist of $135 million in after-tax transaction and system integration
costs and $205.7(51) million in acquisition premium amortizations.(52)
Therefore, merger-related benefits are projected to exceed merger-related costs
by approximately $323.8 million, which goes well beyond meeting the Department's
"no net harm" standard to the point of actually providing net benefits to
customers. Even if the merger does not produce the level of net savings
anticipated by the Joint Petitioners, the magnitude of the difference between
the approximately $632.5 million in savings and $308.7 million in costs supports
the conclusion that significant savings to ratepayers will likely result from
the merger.(53)
Because the acquisition premium would continue to be amortized over a remaining
period of 30 years after the ten-year rate freeze from which merger-related
savings were derived, the effect of the acquisition premium would remain a cost
which must be accounted for as part of our G.L. c. 164, ss. 96 standard as
applied to the recovery of acquisition premiums. The net present value of the
$20.6 million annual amortization of the acquisition premium, discounted at a
rate of 11 percent(54) over the remaining period of 30 years, is approximately
$179 million.(55) Therefore, even without consideration of merger-related
savings that may continue beyond the ten-year savings timeframe, the total costs
related to the merger of $486.7 million(56) are still considerably less than the
merger-related savings of $632.5 million. Accordingly, upon this conclusive
showing, the Department finds that the merger will produce significant benefits
for ratepayers and, as discussed below, will allow the merger-related costs
proposed by the Joint Petitioners to be included in the cost of service of any
future rate proceeding.
Under the Rate Plan, during the distribution rate freeze, the Joint Petitioners
will be at risk to achieve cost synergies sufficient to offset the costs of the
merger (Exhibit RDW-1, at 10-11). When the rate freeze is over, rate proceedings
for each of the Joint Petitioners will account for the opportunity to recover
merger costs and for savings resulting from the merger. As in Eastern-Essex
Acquisition, D.T.E. 98-27, at 14 (1998), the opportunity to recover is expressly
acknowledged. The record here amply supports the probable validity of the Joint
Petitioners' forecast of savings (Exhs. TJF-5A through TJF-5U). All forecasts
have, however, their limitations, especially in later years. During the initial
rate freeze period, the incentive is strongest for the companies to seek
synergies and consequent savings (which, of course, is not to say that
regulatory incentives after the rate freeze are not also strong, although the
Department has recognized the limitations of cost-plus regulation. NYNEX Price
Cap, D.P.U. 94-50, at 114-115 (1995)).(57) To confirm the confidence in the
forecast of savings and to document for future proceedings that merger-related
cost-cutting measures were implemented during the rate freeze, the Department
directs the Joint Petitioners to file a one-time report of cost-saving measures
taken and results achieved during the rate freeze. That joint report of all four
companies will be due not later than 90 days after the end of the rate freeze
(or not later than the filing by any of the four companies of a future rate
proceeding, should such a proceeding occur first). The report should draw upon
contemporaneous documentation developed and maintained through the period of the
rate freeze. A thorough and well-documented report can offer sufficient
assurance that the savings achieved during the rate freeze can and will persist
well beyond the initial period. The savings initiatives described by the Joint
Petitioners are of a kind that, once instituted, will serve as a baseline for
future rate proceedings.
E. Allocation Issues
1. Joint Petitioners' Proposal
In their initial filing, the Joint Petitioners proposed to attribute the
acquisition premium exclusively to BEC Energy's and ComEnergy System's regulated
entities. The Joint Petitioners claimed that the provisions of Accounting
Principles Board Opinion No. 16 "Business Combinations"(58) require ComEnergy
System to revalue its unregulated subsidiaries to their respective fair market
values prior to the completion of the merger (Exhs. JJJ-1, at 5; RDW-1, at 11;
DTE 1-13; DTE 1-15; MIT/Harvard 1-36). During the hearings, the Joint
Petitioners explained that by revaluing ComEnergy System's unregulated
subsidiaries to establish their fair market value,(59) a portion of the total
system acquisition premium would be implicitly "captured" by the unregulated
subsidiaries, and thus not passed on to regulated operations (Tr. 5, at 481-485;
RR-DTE-6).(60)
The Joint Petitioners propose to assign transaction and system integration
costs, as well as merger-related savings, among the affiliates of both BEC
Energy and ComEnergy System (Exh. RDW-1, at 14-16). The Joint Petitioners did
not propose a specific allocation method to assign these merger-related costs
and savings to their regulated and unregulated subsidiaries (id., at 18; Exh.
MIT/Harvard 2-13; Tr. 6, at 804-805). The Joint Petitioners propose that,
consistent with traditional allocation methods,(61) the net savings resulting
from the merger would be allocated in a way that will capture economies and
apportion synergies and costs to customers of all entities (Exhs. RDW-1, at
16-18; MIT/Harvard 2-13). The objective of the allocation approach would be to
align incurred costs to realized savings among all the subsidiaries benefitting
from the merger (Exhs. DTE 1-15; DTE 1-16; Tr. 5, at 475-476; Tr. 6, at 818).
The Joint Petitioners anticipate that the cost savings will likely be achieved
in approximately the same proportion as the percentage of shared services and
costs that will be allocated and charged to the subsidiaries (Exh. RDW-1, at
17-18; Tr. 6, at 812-813). In this respect, the Joint Petitioners claim that,
given the small magnitude of the unregulated operations relative to the
regulated activities, most of the costs and synergies from the merger will
accrue to the regulated subsidiaries (Exh. DTE 1-16; Tr. 5, at 475-476; Tr. 6,
at 818-819).(62) The Joint Petitioners will submit their proposed allocation
method to the Department in time for it to be in place by the end of the
four-year rate freeze (Exh. AG-3-12; Tr. 6, at 805). The Joint Petitioners
consider that this would provide sufficient experience with regard to the
integration of operations and the appropriate allocation of cost responsibility
to propose a specific cost-allocation plan to the Department (Exhs. JJJ-1, at
11).
2. Positions of the Parties
a. Attorney General
The Attorney General contends that the lack of any evidence regarding how
merger-related costs will be allocated between regulated and non-regulated
subsidiaries of each holding company, between wholesale and retail operations,
or among the four utility companies precludes any Department review of the
propriety of costs and benefits that the proposed Rate Plan might produce for
each individual utility company and unregulated affiliate (Attorney General
Initial Brief at 12, 14-15). In particular, the Attorney General points out that
even though the Joint Petitioners represented before FERC that merger-related
savings will accrue for Belmont Municipal Light Department, a wholesale customer
of Cambridge Electric, wholesale customers will not be charged for any of the
merger-related costs (id. at 25). According to the Attorney General, since the
wholesale contract rates are locked for several years, the Joint Petitioners'
proposal would allow their shareholders to retain all of the merger-related
savings associated with those wholesale contracts, while charging the retail
customers the merger-related costs (id.).
The Attorney General argues that the failure of the Joint Petitioners to address
the issue of allocating costs of the merger to unregulated subsidiaries
contravenes the Department's long-standing precedent regarding allocation of
costs, which includes the allocations of costs among affiliates (id. at 26). As
a result of this failure, the Attorney General concludes that the proposed Rate
Plan should not be approved (id. at 15).
b. DOER
DOER contends that the best mechanism by which to allocate merger-related costs
and benefits is through a full and formal review of the Joint Petitioners' base
rates (DOER Brief at 39).
c. MIT/Harvard
MIT/Harvard argues that the Joint Petitioners' failure to incorporate any
proposal establishing a means of allocating merger-related costs and savings
among ratepayers of the four individual utilities introduces the prospect of
cross-subsidization and represents a fundamental flaw in the Rate Plan
(MIT/Harvard Initial Brief at 2, 21). MIT/Harvard asserts that, absent a
reasonable and equitable allocation method, the Department cannot conclude that
the rates resulting from the merger will be just and reasonable (id. at 21).
MIT/Harvard contends that if the Joint Petitioners are guaranteed recovery of
the merger-related costs, they should be ordered to develop an equitable cost
allocation method at the outset in order to protect ratepayers against
cross-subsidization (id.).
d. AIM
AIM argues that because the Joint Petitioners have failed to demonstrate the
allocation of either the merger-related expenses or the acquisition premium, the
Department and ratepayers are left to "guess at" the magnitude of merger-related
savings that will accrue to each operating company (AIM Brief at 8).
e. Joint Petitioners
The Joint Petitioners argue that the creation of an allocation system is not
necessary at this time to meet the "no net harm" standard because the allocation
of net savings will not have an effect on rates until after the four-year rate
freeze is over (Joint Petitioners Brief at 17, citing Exh. RDW-1, at 19).
Therefore, the Joint Petitioners maintain that as long as a Department-approved
allocation procedure is in place by the end of the initial four years,
ratepayers will be assured of Department protection against the risk of
cross-subsidization (id.).
Concerning the Attorney General's claim of cross-subsidization of wholesale and
unregulated operations by retail ratepayers, the Joint Petitioners assert that
the unregulated businesses will be allocated their proportionate share of
merger-related costs. Moreover, the Joint Petitioners contend that because
wholesale rates will not be affected by cost changes and because revenues from
wholesale sales are credited to retail rates, there will be no cost shifting to
retail customers (id. at 16). With regard to the Intervenors' complaints that a
final allocation method has not been established, the Joint Petitioners claim
that it is not possible at this time to provide precise numbers as to the
allocation of costs and benefits over an extended period of time (id. at 15).
Therefore, given the Department's continuing jurisdiction over the allocation of
costs among the companies, the Joint Petitioners conclude that there will be no
net harm to customers (id.).
3. Analysis and Findings
The Joint Petitioners proposed to allocate the acquisition premium among BEC
Energy's and ComEnergy System's regulated operations, with what they consider a
small portion of the total acquisition premium assigned to ComEnergy System's
unregulated operations through an asset revaluation. The Joint Petitioners state
the assignment of the unregulated operations' share of the acquisition premium
would be made by independent accounting firms, using valuation methods
consistent with standard business practice (Tr. 5, at 484-485). The Joint
Petitioners' method for assigning a portion of the acquisition premium to
ComEnergy System's unregulated operations is consistent with generally accepted
business practices (Exhs. DTE 1-13; DTE 1-15; MIT/Harvard 1-36). Moreover, the
proposed allocation method produces a reasonable result which remedies any
concerns about cross-subsidies of unregulated operations by regulated
operations.
With respect to the allocation of merger-related savings among the regulated
entities, the Joint Petitioners extensively discussed their intentions regarding
the future allocation of merger-related costs and benefits, but did not propose
a specific allocation formula (Tr. 6, at 805-807, 815). In determining whether
the Rate Plan is consistent with the public interest, the Department may examine
affiliate transactions to ensure that dealings between affiliated companies
provide direct benefits to ratepayers and that associated costs are reasonable
and allocated in a nondiscriminatory manner. Eastern-Essex Acquisition, D.T.E.
98-27, at 46 (1998), citing G.L. c. 164, ss. 76A; Cambridge Electric Light
Company, D.P.U. 92-250, at 78 (1993); Bay State Gas Company, D.P.U. 92-111, at
134-135 (1992). The Department historically has exercised its obligation and
authority to ensure that a company's affiliate costs passed on to the company's
ratepayers are reasonable and that ratepayers pay no more than a fair portion of
the costs. Id., citing Bay State Gas Company, D.P.U. 92-111, at 136-137 (1992);
New England Telephone and Telegraph Company, D.P.U. 86-33-G at 113-211 (1989);
Oxford Water Company, D.P.U. 1699, at 10-13 (1984).
In evaluating the Joint Petitioners' proposal the Department needs to verify
that ratepayers of each of the four utility companies will pay no more than a
fair portion of the merger costs. Even though the Joint Petitioners have shown
that estimated aggregate savings from the merger would exceed the expected
aggregate merger costs, the Department has no assurance that individual
regulated utilities would not be assigned merger-related costs which are not
commensurate with savings. The Joint Petitioners themselves recognized this
outcome as a possibility (Tr. 6, at 817-818).
The reliance of the Department on an aggregate analysis of costs and benefits
could be sufficient if combined with an established formula that designates
proper allocators of costs among all subsidiaries. Under these conditions, it
would be possible to align merger-related costs to be recovered from an
individual company's ratepayers to merger-related savings specifically
beneficial to that company.
Accordingly, the Joint Petitioners are hereby directed to develop a cost
allocation system for transactions among the subsidiaries of BEC Energy and
ComEnergy System consistent with Department precedent. In order to recover costs
incurred from an affiliate, a company must show that those costs: (1) are
specifically beneficial to the individual company seeking rate relief (as
opposed to other subsidiary members of the system as a whole); (2) compare
reasonably to competitive prices; and (3) are allocated by a formula that is
cost-effective and nondiscriminatory. Eastern-Essex Acquisition, D.T.E. 98-27,
at 46 (1998), citing Oxford Water Company, D.P.U. 1699, at 13 (1984). In
preparing this system, the Joint Petitioners must functionalize all costs,
classify the expenses in each functional category, identify the appropriate
allocators, and allocate all costs. Eastern-Essex Acquisition, D.T.E. 98-27, at
47 (1998), citing Cambridge Electric Light Company, D.P.U. 92-250, at 90 (1993).
Furthermore, the Joint Petitioners must explain the underlying criteria or
rationale for the choice of allocators used to assign the costs among the
operating companies. Id.
The Department acknowledges that the establishment of a cost allocation method
requires the Joint Petitioners to gain sufficient experience with regard to the
integration of operations and the appropriate allocation of cost responsibility
among the subsidiaries, as well as the complexity of the two corporate
structures to be merged and the uncertainty regarding the final structure of the
post-merger entity (Exh. DTE 1-11; Tr. 5, at 471-472; Tr. 6, at 668, 807).
Therefore, the Joint Petitioners shall provide the Department with their
proposal for an allocation method encompassing the entire corporate system
created by the merger, either 90 days after the close of the rate freeze or no
later than the date that any one of Nstar's regulated operations files a
petition for rate relief pursuant to G.L. c. 164, ss. 94, whichever event is
earlier.
VII. SERVICE QUALITY PLAN
A. Joint Petitioners' Proposal
The Joint Petitioners' proposed Rate Plan includes a service quality plan that
would apply to all four retail distribution companies. For the electric
companies (i.e., Boston Edison, Cambridge Electric, and ComElectric), the
service quality plan establishes performance standards, based on each company's
historic performance, for four areas of service quality: (1) system reliability,
as measured by a system average interruption duration index ("SAIDI," expressed
as minutes of interruptions per customer per year) and a system average
interruption frequency index ("SAIFI," expressed as number of interruptions
greater than one minute per customer per year); (2) customer service, as
measured by the percentage of telephone calls answered within a specified
time(63) and the percentage of new customers who received service within a
specified time of the customer's completion of required permits and inspection
("on-time in-service");(64) (3) safety, as measured by the incidence rate for
lost-time accidents, expressed as the average number of incidents per 100
full-time employees; and (4) billing, as measured by the percentage of meters
read on schedule (Exhs. JJJ-3, at 1-3; RDW-6, at 1-3). The historic benchmarks
and performance years for each measure are summarized in Table 1, below.
For ComGas, the service quality plan establishes performance standards, based on
ComGas' historic performance, for three areas of service quality: (1) customer
service, as measured by the percentage of telephone calls answered within 30
seconds; (2) safety, as measured by the incidence rate for lost-time accidents
(expressed as the average number of incidents per 100 full-time employees), and
emergency gas odor or leak calls responded to within 60 minutes; and (3)
billing, as measured by the percentage of meters read on schedule (Exh. RDW-6,
at 3-4).
Each company's post-merger performance in these service areas would be reported
annually to the Department and compared to its historic performance in order to
determine whether there has been a degradation in service (Tr. 7, at 965-966).
The Joint Petitioners stated that they intend to review their respective service
quality data to determine if there would be benefits to customers in integrating
their existing systems or developing new systems to track data in a uniform
manner (Exh. JJJ-3, at 3). The Joint Petitioners stated that if they determine,
in the future, that such system integration or development is beneficial to
customers, they will report any new data collected to the Department for our
review (id.; Exh. RDW-6, at 3-4). The proposed service quality plan did not
include a mechanism to penalize the companies for degradation in service.
TABLE 1 SUMMARY OF PROPOSED BENCHMARKS FOR SERVICE QUALITY PLAN
<TABLE>
<CAPTION>
SYSTEM CUSTOMER SAFETY BILLING
RELIABILITY SERVICE
SAIDI SAIFI Telephone On-Time In-Service Lost Time On-cycle Meter
Response Accidents Reads
years (min.) years (inter.) years %/ years %/time (5) years # years %
(1) (2) (1) (3) (1) time (4) (1) (1) incid. (1) (7)
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
ComElec 1988-'97 115 1990-97 1.484 1997-98 67%/30 1997-98 96.3%/5days 1996-'98 2.13 1/97-11/98 97.5%
sec
Camb. 1988-'97 44.7 1990-97 0.511 1997-98 67%/30 1997-98 96.3%/5days 1996-'98 2.13 1/97-11/98 99.1%
sec
BECo 1989-'98 108.8 1989-98 1.04 1996-98 70%/20 1996-98 93.3%/2days 1996-'98 0.62 1996-98 89.2%
sec
72%/30
sec
</TABLE>
<TABLE>
<CAPTION>
CUSTOMER SAFETY BILLING
SERVICE
Telephone Emergency Calls Lost Time On-cycle Meter
Response Accidents Reads
years % years % within 1 years # years % (7)
(1) /time (1) hr (8) (1) incid. (1)
(4) (6)
<S> <C> <C> <C> <C> <C> <C> <C> <C>
ComGas 1997-98 35%/30 1998 98.5% 1996-'98 9.54 1/97-11/98 96.2%
sec
</TABLE>
Notes
(1) Years upon which performance standard is based
(2) Minutes of interruptions per customer per year, excluding interruptions
less than one minute
(3) Number of interruptions per customer per year, excluding interruptions less
than one minute
(4) Percentage of telephone calls answered within specified time
(5) Percentage of new customers who received service within specified time
after completion of required permits and inspections
(6) Average number of incidents per 100 full-time employees
(7) Percentage of meters read on schedule
(8) Emergency calls responded to within 60 minutes
(Exhs. JJJ-3; RDW-6)
B. Position of the Parties
1. Attorney General
The Attorney General asserts that the Joint Petitioners' proposed service
quality plan would not provide adequate protection against degradation in the
service provided to customers and suggests two modifications to the proposed
plan (Attorney General Brief at 26-29). First, the Attorney General argues that
the Department should establish maximum penalties equal to at least one percent
of each company's annual revenue, in order to ensure maintenance of minimal
service quality standards (id.). Second, the Attorney General proposes that the
Department should require that the service quality plan include a performance
measure based on statistics compiled by the Department's Consumer Division
(id.). The Attorney General asserts that the Consumer Division statistics
constitute the only data which lie outside the Joint Petitioners' control, and
therefore provide an independent assessment of how well the companies are (1)
handling service complaints, and (2) applying the Department's billing and
termination regulations (id. at 28-29).
2. MIT/Harvard
MIT/Harvard asserts that, given the lack of a penalty provision, the proposed
service quality plan does not provide adequate incentive to meet the established
service quality targets (MIT/Harvard Initial Brief at 18).
3. AIM
AIM criticizes the Joint Petitioners' service quality plan for failing to
include either penalties or Consumer Division statistics (AIM Brief at 12-13).
AIM argues that any approval of the Rate Plan must provide for both of these
features as a precondition to the merger (id.).
4. Joint Petitioners
The Joint Petitioners assert that their proposed service quality plan includes
comprehensive and reliable performance measures and historic performance data
that will allow the Department to determine whether there has been a degradation
in the companies' service quality as a result of the merger (Joint Petitioners
Brief at 26-29). The Joint Petitioners maintain that, because the historic
performance data are based on multi-year periods, the data provide the
Department with reasonable proxies against which to compare post-merger
performance (id. at 28).
The Joint Petitioners state that the measures included in their proposed plan
are based on the measures approved by the Department in previous gas merger
proceedings, citing NIPSCO-Bay State Acquisition, D.T.E. 98-31 (1998);
Eastern/Essex Acquisition, D.T.E. 98-27 (1998), with two exceptions: (1) the use
of SAIDI and SAIFI to measure system reliability; and (2) the exclusion of
complaint statistics provided by the Department's Consumer Division (Joint
Petitioners Initial Brief at 27-28). The Joint Petitioners state that the use of
a SAIDI and SAIFI to measure the duration and frequency of power outages is a
"logical means of tracking the Companies' success in maintaining reliable
electric service, the core function of an electric utility" (id. at 28).
With respect to the Consumer Division's complaint statistics, the Joint
Petitioners state that they have not included these statistics in their service
quality plan because: (1) the subjective nature of calls to the Department, and
(2) the likelihood of increased calls to the Department due to industry
restructuring in both the electric and gas industries makes the use of these
complaint statistics an unreliable indicator of the Joint Petitioners' service
quality (id. at 28).(65)
Finally, the Joint Petitioners argue that, although the Department can take many
actions under its general supervisory authority if service quality provided by a
utility were to suffer, the Department lacks legal authority in this case to
impose automatic monetary penalties in conjunction with the proposed Rate Plan
(Joint Petitioners Reply Brief at 25-26). The Joint Petitioners maintain that,
although the Act grants the Department authority to impose penalties for failing
to meet service quality standards, these standards must be established in
accordance with regulations that are developed to establish a comprehensive
system of PBR (id.). The Joint Petitioners assert that, because regulations to
establish and require performance-based rates have not yet been promulgated, no
provision of the Department's governing statutes grants the Department the
authority to impose monetary penalties (id.).(66)
C. Analysis and Findings
1. Introduction
The Department's position regarding service quality plans was expressed in
Eastern-Essex Acquisition, D.T.E. 98-27 (1998), in which the Department stated
that quality of service is an essential factor in reviewing a merger and that a
service quality plan can be an important bulwark against deterioration of a
company's quality of service. Eastern-Essex Acquisition, D.T.E. 98-27, at 32
(1998). The Department directed "companies filing requests for approval of
mergers and acquisitions to include a service quality plan that is designed to
prevent degradation of service following the merger." Id. at 33, n.27. In this
section, the Department addresses whether the Joint Petitioners' proposed
service quality plan would reasonably protect customers against degradation in
the Joint Petitioners' performance. The Department addresses the major
components of the proposed plan: (1) the proposed performance measures and (2)
the proposed performance benchmarks. In addition, the Department addresses the
absence of a penalty mechanism.
2. Performance Measures
As stated above, the Joint Petitioners' proposed service quality plan includes
measures for four performance areas; system reliability, customer service,
safety, and billing.(67) The Attorney General and AIM recommend that additional
measures be included for customer service, based on statistics compiled by the
Department's Consumer Division. For all of the regulated utilities in the
Commonwealth, the Department's Consumer Division maintains a record of calls
received by customers regarding a company's service quality and billing. The
Department has directed companies to use the Consumer Division's data to
establish benchmarks to assess service quality, in the context of both PBR plans
and merger-related rate plans. See Eastern-Colonial Acquisition, D.T.E. 98-128,
at 82-83 (1999); Eastern-Essex Acquisition, D.T.E. 98-27, at 39 (1998); Boston
Gas Company, D.P.U. 96-50-C at 66-69 (1997).
The Consumer Division statistics can provide a useful measure of a company's
service quality in that the number of customer calls logged by the Consumer
Division could indicate inadequate communications between a company and its
customers on matters concerning invoices, billing adjustments, or other service
quality concerns. See Eastern-Colonial Acquisition, D.T.E. 98-128, at 82-83
(1999). Moreover, in cases where companies are merging, the Department concludes
that the number of complaints made by the companies' customers to the Consumer
Division provides a means to compare the companies' service quality pre- and
post-merger. Id. Accordingly, the Department directs the Joint Petitioners to
include, in the service quality plan for all of the companies, performance
measures using the Consumer Division statistics that track customer complaint
cases and customer bill adjustments. Other information may also prove pertinent
and useful. The benchmarks for these measures shall be based on each company's
performance during the three years preceding the performance year (e.g., for the
year 2000, the benchmark will include the years 1997-1999). As in
Eastern-Colonial Acquisition, D.T.E. 98-128, at 83 n.63 (1999), the Department
directs the Joint Petitioners to work with the Department's General Counsel and
the Consumer Division to adapt the Consumer Division data for use in the service
quality index ("SQI). The results of this effort shall be filed within six
months from the consummation of the merger.
While the Joint Petitioners may have concerns regarding the appropriateness of
using statistics derived from the Consumer Division's data in the changing
electric and gas industries, the appropriate forum to address these concerns is
the generic proceeding that the Department will hold regarding PBR issues and
service quality plans.(68) The Department may revise the measures using the
Consumer Division statistics based on the results of the generic proceeding and
based on the cooperative efforts of the Joint Petitioners, the Consumer
Division, and the Department's General Counsel.
The Department finds that the service quality areas included in the proposed
plan, system reliability, customer service, safety, and billing, are
appropriate, noting that they are consistent with the service areas included in
previous Department-approved plans. See Eastern-Colonial Acquisition, D.T.E.
98-128, at 74-83 (1999); NIPSCO-Bay State Acquisition, D.T.E. 98-31, at 29-32
(1998); Eastern-Essex Acquisition, D.T.E. 98-27, at 32-39 (1998); Boston Gas
Company, D.P.U. 96-50 (Phase One), at 307-308 (1996). The Department
additionally finds that, with the inclusion of the Consumer Division statistics,
the measures proposed to compare post-merger performance to pre-merger
performance will allow the Department to determine whether there has been
degradation of service. Accordingly, the Department approves the performance
measures as proposed.
3. Performance Benchmarks
As stated above, the proposed Rate Plan includes performance benchmarks for each
of the proposed measures, based on each company's actual performance during a
specified historic periods. The purpose of the benchmarks is to represent the
level of pre-merger performance that the Joint Petitioners would be expected to
maintain (or exceed) during the post-merger period. A comparison of the
companies' post-merger performance to the benchmark for each measure should
allow the Department to determine whether there has been degradation of service.
In this section, the Department identifies three benchmarks for Boston Edison
and ComGas that, because of these companies' performance during the years on
which the benchmarks were based, would not represent the level of pre-merger
performance that the Joint Petitioners would be expected to maintain (or exceed)
during the post-merger period and, therefore, would not allow the Department to
determine whether there has been degradation of service.
The first such benchmark is associated with Boston Edison's telephone call
answering measure, which was based on Boston Edison's performance during the
three-year period 1996-1998. The record demonstrates that Boston Edison's
performance in this area improved significantly during the years 1997 and 1998,
when compared to its performance during 1996.(69) Boston Edison's witness
testified that its performance in this area during 1996 was "less than ideal."
As a result, Boston Edison undertook a "very focused effort" during 1997 to
ensure that telephone calls were answered more quickly (Tr. 7, at 919, 966-967).
Boston Edison implemented additional changes in its telephone answering
operations during 1998 to balance the need to answer telephone calls quickly
with the need to provide high quality service to its customers.(70) Boston
Edison testified that, although its telephone answering statistics declined
during 1998 (as compared to 1997), it believes that the overall quality of its
service improved (Tr. 7, at 919-920). The Department finds that: (1) based on
Boston Edison's testimony regarding its "less than ideal" performance in this
area during 1996, and (2) because the "one and done" approach introduced during
1998 will continue to be in effect during the post-merger period, Boston
Edison's telephone answering performance in 1996 and 1997 does not represent the
level of pre-merger performance that Boston Edison should be expected to
maintain (or exceed) during the post-merger period. Therefore, the Department
rejects the use of 1996 and 1997 performance in the proposed benchmark for
Boston Edison's telephone call-answering-time performance measure. The
Department finds that, in order for the telephone answering benchmark to
represent the level of pre-merger performance that Boston Edison should be
expected to attain (or exceed) during the post-merger period, the benchmark
should be based on Boston Edison's performance during 1998.(71) Therefore, the
Department directs the Joint Petitioners to use the values for 1998 included in
Exhibit JJJ-3, Attachment B as the benchmark for this measure.(72)
The second benchmark identified by the Department is associated with Boston
Edison's on-cycle meter readings, which was based on Boston Edison's performance
during the three-year period 1996-1998. The record demonstrates that Boston
Edison's performance in this area continually improved during the years 1996
through 1998.(73) The record also demonstrates that during the years 1996 and
1997, approximately 180,000 automatic meter reading ("AMR") devices were
installed, with an additional 10,000 installed during 1998 and an additional
60,000 projected to be installed during 1999 (RR-DTE-14). Boston Edison
testified that the recent installation of these devices was "one of the reasons"
that contributed to Boston Edison's improved performance in this area (Tr. 7, at
974-975). The Department finds that, because of the significant number of AMR
devices installed since the beginning of 1996, and the corresponding increase in
on-cycle meter reads, Boston Edison's meter reading performance during 1996 and
1997 does not represent the level of pre-merger performance that Boston Edison
should be expected to attain (or exceed) during the post-merger period.
Therefore, the Department rejects the use of 1996 and 1997 performance in the
proposed benchmark for Boston Edison's on-cycle meter read performance measure.
The Department finds that, in order for the on-cycle meter read benchmark to
represent the level of pre-merger performance that Boston Edison should be
expected to attain (or exceed) during the post-merger period, the benchmark
should be based on Boston Edison's performance during 1998. Therefore, the
Department directs the Joint Petitioners to use the value for 1998 included in
Exhibit JJJ-3, Attachment E (92.5 percent) as the benchmark for this measure.
The third benchmark identified by the Department is associated with
Commmonwealth Gas' telephone call answering time measure, which was based on
ComGas' performance during 1997-1998.(74) The Petitioners acknowledged that
ComGas' performance during 1997 and most of 1998 was not "what we would want to
see happen. We would much prefer that these [numbers] improve. Our internal goal
would clearly be to at least exceed 50 percent within 30 seconds" (Tr. 7, at
984-985). The Department finds that ComGas' historic performance clearly does
not represent the level of pre-merger performance that ComGas should be expected
to maintain (or exceed) during the post-merger period. Therefore, the Department
rejects the Joint Petitioners' proposed benchmark for ComGas'
telephone-call-answering time performance measure. The record is not clear
regarding an appropriate benchmark for this measure. Therefore, the Department
directs ComGas to track its 1999 performance in this area and submit this
information to the Department by January 31, 2000. The Department will determine
the appropriate benchmark at that time.
4. Penalty Mechanism
As stated above, the proposed service quality plan does not include a mechanism
to penalize the companies for degradation in service. The Department previously
has found that a penalty provision is an important and necessary component of a
service quality plan in that it provides companies with a direct financial
incentive motivation to meet or exceed established performance standards. See
NIPSCO-Bay State Acquisition, D.T.E. 98-31 at 31-32 (1998); Boston Gas Company,
D.P.U. 96-50-C at 71-72 (1997); Boston Gas Company, D.P.U. 96-50 (Phase One) at
310 (1996);(75) NYNEX Price Cap, D.P.U. 94-50, at 235-238 (1995). In addition,
in our orders on previous merger cases, the Department has stated that we will
investigate establishing penalties at such time that the companies file their
completed service quality plans. See Eastern-Colonial Acquisition, D.T.E.
98-128, at 78-79 (1999); Eastern-Essex Acquisition, D.T.E. 98-27, at 34 (1998).
The Joint Petitioners' proposed service quality plan does not include a
mechanism to penalize the companies for degradation in service. Consequently,
the plan may not provide the companies with the direct financial incentive or
motivation to meet or exceed the established benchmarks, which the Department
has previously found necessary. Eastern-Essex Acquisition, D.T.E. 98-27, at 33
(1998). Therefore, the Department directs the Joint Petitioners to file a
proposal for a penalty mechanism within six months of the date of the closing of
the merger. The Department will then investigate establishing a penalty
provision as part of the Joint Petitioners' SQIs as a disincentive or safeguard
against the degradation of service. Eastern-Colonial Acquisition, D.T.E. 98-128,
at 78-79 (1999); Eastern-Essex Acquisition, D.T.E. 98-27, at 33 (1998).
VIII. CONFIRMATION OF FRANCHISE RIGHTS
A. Introduction
The Joint Petitioners have requested that the Department confirm that no
transfer of the franchise rights of Boston Edison, Cambridge Electric,
ComElectric, or ComGas will result from the merger and, therefore, no approval
by the Massachusetts General Court is required under G.L. c. 164, ss. 21
(Petition at 4-5). Although the Joint Petitioners restated their request on
brief, the intervenors did not submit briefs on this issue.
B. Analysis and Findings
While the Joint Petitioners have proposed to consolidate many of the operations
of Boston Edison, Cambridge Electric, ComElectric, and ComGas, the corporate
existence of these distribution companies would continue after the merger of BEC
Energy and ComEnergy System as if no merger had taken place. No sale of assets
or surrender of these distribution companies' ability to provide service is
proposed here. There will merely be a wholesale change in the stock ownership of
these companies from shareholders of BEC Energy and ComEnergy System to
shareholders of Nstar.(76) Thus, the Department finds that no transfer of any
franchise rights would result from this merger, and that no legislative approval
under G.L. c. 164, ss. 21 is required.
IX. ORDER
Accordingly, after due notice, hearing and consideration, it is
ORDERED: That pursuant to G.L. c. 164, ss. 94, and subject to the terms or
conditions of this Order, the Rate Plan for Boston Edison Company, Cambridge
Electric Light Company, Commonwealth Electric Company, and Commonwealth Gas
Company is hereby approved; and it is
FURTHER ORDERED: That, it is confirmed that upon consummation of the merger of
BEC Energy and Commonwealth Energy System, Boston Edison Company, Cambridge
Electric Light Company, Commonwealth Electric Company, and Commonwealth Gas
Company shall have all rights, powers, privileges, franchises, properties, real,
personal or mixed, and immunities to engage in all activities in all the cities
and towns in which Boston Edison Company, Cambridge Electric Light Company,
Commonwealth Electric Company, and Commonwealth Gas Company were engaged in
immediately prior to the merger, and that further action pursuant to G.L. c.
164, ss. 21 is not required to consummate the merger of BEC Energy and
Commonwealth Energy System; and it is
FURTHER ORDERED: That a copy of the journal entries, or a schedule summarizing
such entries, recording the effect of the merger shall be filed with the
Department upon consummation of the merger.
FURTHER ORDERED: That the Petitioners shall comply with all directives
contained in this Order.
By Order of the Department,
_____________________________________ Janet Gail Besser, Chair
_____________________________________ James Connelly, Commissioner
_____________________________________
W. Robert Keating, Commissioner
_____________________________________
Paul B. Vasington, Commissioner
_____________________________________
Eugene J. Sullivan, Jr., Commissioner
Appeal as to matters of law from any final decision, order or ruling of the
Commission may be taken to the Supreme Judicial Court by an aggrieved party in
interest by the filing of a written petition praying that the Order of the
Commission be modified or set aside in whole or in part.
Such petition for appeal shall be filed with the Secretary of the Commission
within twenty days after the date of service of the decision, order or ruling of
the Commission, or within such further time as the Commission may allow upon
request filed prior to the expiration of twenty days after the date of service
of said decision, order or ruling. Within ten days after such petition has been
filed, the appealing party shall enter the appeal in the Supreme Judicial Court
sitting in Suffolk County by filing a copy thereof with the Clerk of said Court.
(Sec. 5, Chapter 25, G.L. Ter. Ed., as most recently amended by Chapter 485 of
the Acts of 1971).
1. A wholly-owned subsidiary of BEC Energy, a Massachusetts business trust.
2. Cambridge Electric, ComElectric, and ComGas are wholly-owned subsidiaries of
Commonwealth Energy System, a Massachusetts business trust.
3. To effect the merger, Nstar has created two limited liability companies, BEC
Acquisition Company LLC, and CES Acquisition LLC (Exh. JJJ-1 (Supp.) at 1). BEC
Energy will merge with BEC Acquisition LLC, with BEC Energy as the surviving
entity (id.). ComEnergy System will merge with CES Acquisition LLC, with
ComEnergy System as the surviving entity (id.).
4. The Joint Petitioners reported that BEC Energy and ComEnergy System are
expected to operate for some indeterminate period after the merger as subholding
companies of Nstar (Tr. 5, at 471-472).
5. The Joint Petitioners characterize the rate freeze as a unilateral commitment
that does not affect the rights of the Department or the Attorney General to
seek a review of rates in accordance with G.L. c. 164, ss. 93 (Tr. 6, at
830-831).
6. Transmission rates are regulated by the Federal Energy Regulatory Commission
("FERC").
7. The Rate Plan proposes to allow the Joint Petitioners' companies to increase
distribution rates to include cost changes resulting from exogenous factors such
as changes in tax laws, accounting changes and regulatory, judicial or
legislative changes (Exh. JJJ-1, at 6).
8. "An Act Relative to Restructuring the Electric Utility Industry in the
Commonwealth, Regulating the Provision of Electricity and Other Services, and
Promoting Enhanced Consumer Protection Therein," St. 1997, c. 164.
9. An acquisition premium represents the difference between the acquisition
price and the net book value of the acquired company. Eastern-Colonial
Acquisition, D.T.E. 98-128, at 4 n.4 (1999); Mergers and Acquisitions, D.P.U.
93-167-A at 9 (1994). Accounting rules require that any acquisition premium paid
be recorded on the books of the acquired company and be amortized over a period
not to exceed 40 years (Exhs. JSM-1, at 8; DTE 1-14). Eastern-Colonial
Acquisition, D.T.E. 98-128, at 4 n.4 (1999).
10. The merger provides for an exchange ratio of one Nstar share for each BEC
Energy share (Exh. JJJ-2 (Supp.) at 6).
11. With the exception of some of the system integration costs, the costs to
achieve the merger and the acquisition premium will be final shortly after
consummation of the merger, and will be reported to the Department in the 90-day
post-closing filing (Tr. 5, at 486; Tr. 8, at 1042-1043).
12. The Joint Petitioners report that the accounting for ratemaking purposes may
deviate from the manner in which the merger-related costs will be booked for
financial reporting purposes (Tr. 8, at 1031).
13. The Joint Petitioners will report in their 90-day, post-merger filing an
accounting of the taxable and non-taxable portions of the transaction costs (Tr.
8, at 1042-1043).
14. The Department notes that a finding that a proposed merger or acquisition
would probably yield a net benefit does not mean that such a transaction must
yield a net benefit to satisfy G.L. c. 164, ss. 96 and Boston Edison Company,
D.P.U. 850.
15. The Attorney General's price cap formula consists of an inflation index less
a productivity factor.
16. The Attorney General defines the consumer dividend factor as the expected
future rate of productivity growth among regulated firms, including improvements
arising from the change from cost of service-based regulation to PBR (Exh. AG-1,
at 2-3).
17. The Attorney General defines accumulated inefficiencies as inefficiencies
built into a utility's base rates because of the historical use of cost of
service regulation, estimated as the difference between the actual efficiency
level of the firm and the "best practice" level that can be currently observed
(Exh. AG-1, at 3).
18. DOER describes its rate adder as a mechanism to be applied to the Joint
Petitioners' distribution rates to account for merger-related savings during the
first four years of the Rate Plan (Exh. LAC at 29).
19. In D.P.U./D.T.E. 97-111, the Department stated that it would conduct a
thorough review of the distribution rates of Cambridge Electric and ComElectric.
D.P.U./D.T.E. 97-111, at 40. Such a review was not conducted as a part of our
investigation, and we will not mandate it prior to the end of the rate freeze.
While review of the rates for Cambridge Electric and ComElectric will likely not
take place before the end of the rate freeze, it could if the need for an
earlier review is otherwise demonstrated.
20. Threshold requirements were also examined in NIPSCO-Bay State Acquisition,
D.T.E. 98-31, at 18 (1998).
21. In accordance with 220 C.M.R. ss. 1.10(3), the Department takes
administrative notice of Colonial's 1998 annual report.
22. These threshold levels are equal to approximately between 0.147 to 0.150
percent of the Joint Petitioners' 1998 operating revenues.
23. The proposed distribution rate increase for Cambridge Electric is:
(0.268 cents/KWH + 0.100 cents/KWH) - (0.145 cents/KWH) = 0.223 cents/KWH.
The proposed distribution rate increase for ComElectric is:
(0.268 cents/KWH + 0.100 cents/KWH) - (0.207 cents/KWH) = 0.161 cents/KWH.
24. In their filing, the Joint Petitioners proposed an adjustment of 0.269 cents
per KWH for Cambridge Electric (Exh. RDW-1, at 12-13). During evidentiary
hearings, the Joint Petitioners' witness testified that $579,150 in DSM-related
revenues should have been subtracted from Cambridge Electric's distribution
revenue requirement when, in fact, they were inadvertently subtracted from its
transition charge revenue requirement (Tr. 6, at 785-786). Accordingly, the
Joint Petitioners propose to reduce the Rate Plan's adjustment in distribution
rates for Cambridge Electric from 0.269 cents per KWH to 0.223 cents per KWH
(Petitioners Reply Brief at 23).
25. As we noted in Section V.A.4, above, this proceeding is not a general
rate case; therefore, the Department does not consider it necessary or
appropriate to use this petition as a forum to conduct the cost allocation
analysis discussed in D.P.U./D.T.E. 97-111.
26. Directors and officers tail coverage provides liability insurance coverage
for former directors for claims arising out of, but raised subsequent to, their
terms of service as directors or officers (Exh. TJF-5U, at 1).
27. Expenditures made after the year 2003 will be expensed in the year they are
incurred (Exh. JJJ-1, at 9).
28. Nuclear ownership was at issue until the conveyance of Boston Edison's
Pilgrim Nuclear Power Station to Entergy in July, 1999. Divestiture of the
nuclear plant was approved by the Department in Boston Edison Company, D.T.E.
98-119 (1999) as the first sale of a nuclear plant to a merchant owner in the
United States.
29. This estimate was developed by multiplying the imputed purchase and exchange
price per ComEnergy System share of $44.10 by approximately 21.5 million
outstanding shares. (Exh. JJJ-1, at 4).
30. DOER notes that both Boston Edison and ComEnergy promoted the control
premium standard as the appropriate measure for the acquisition premium in
Mergers and Acquisitions (DOER Initial Brief at 22, n.4, citing Mergers and
Acquisitions, D.P.U. 94-167-A at 15 (1994)).
31. In this context, "least cost" refers to limiting recovery to the amount
necessary to permit a beneficial merger to be completed, after a petitioner has
made such a demonstration (Exh. LAC at 14-15).
32. As noted in the Standard of Review discussion, above at Section IV, the
instant petition presents some novel features that bear out Mergers and
Acquisitions' prediction that case-by-case review would prove warranted.
33. In Eastern-Colonial Acquisition, D.T.E. 98-128, at 98-100 (1999), the
Department approved a return on Eastern Enterprises' cash investment of $144
million that was used as part of the acquisition of Colonial, upon a
demonstration that the use of this cash reduced the overall cost of the merger.
In this case, the Joint Petitioners have not sought a return on any portion of
the acquisition premium (Tr. 5, at 477-478).
34. Concerns over the effect of "pyramiding" acquisition premiums in terms of
utility rate base was a driving force behind the Department's adoption of an
original cost rate base policy. See Report of the Special Commission on Control
and Conduct of Public Utilities, D.P.U. 3243, at 54 (1930). No case since
Mergers and Acquisitions has presented this issue; and so we need do no more
than note it for future reference.
35. DOER correctly notes that the selling company would have the opportunity to
recover its unamortized acquisition premium through negotiations with the
purchaser.
36. The estimated $24 million in pre-merger initiatives is included in the $667
million savings estimate (Exh. TJF-5A, at 1-5).
37. The Joint Petitioners noted that decentralization of certain functions or
activities may be necessary to avoid over-centralization and promote
accountability (Exh. TJF-1, at 33).
38. The Cambridge Electric and ComElectric load consists of power being supplied
by Select Energy under a contract that expires at the end of 1999 (Tr. 7, at
854). The remaining 36 percent is provided by the Southern Company under a
contract that expires in 2005 (Tr. 7, at 854).
39. The Department discussed the pertinence and utility of rate case precedent
to G.L. c. 164, ss. 96 determinations in Eastern-Colonial Acquisition, where we
stated that rate case precedent provide analogies that may be analytically
useful. Eastern-Colonial Acquisition, D.T.E. 98-128, at 19 n.22 (1999).
40. DOER states that under this approach, once the unit entered commercial
operation, and the company demonstrated a "need" for the facility and that the
decision to construct the facility was generally prudent, costs would be
included in rates and would remain provided that the facility continued to be
"used and useful" (DOER Brief at 13).
41. DOER notes that the "least cost" standard is consistent with what is set
forth in the Mergers and Acquisitions, which suggests that the recovery of the
acquisition premium be limited to the minimum amount necessary to permit a
merger to be completed and only after the company has made such demonstration.
Further, DOER states that failure to address these established standards, the
Petitioners have not complied with Department's traditional goal in ratemaking
to procure the least-cost energy service. (DOER Initial Brief at 15, citing
Boston Gas Company, D.P.U. 96-50 (Phase I) at 242-243 (1996)).
42. MIT/Harvard argues that the Joint Petitioners' characterization of the
merger-related saving as substantial, permanent, quantifiable, and benefitting
ratepayers while refusing to demonstrate when and how these savings will be
allocated to ratepayers violates the just and reasonable standard in
establishing appropriate rates (See MIT/Harvard Brief at 15; MIT/Harvard Reply
Brief at 6).
43. MIT/Harvard states that when the amortization of the non-cash portion of the
acquisition premium is excluded, the EPS is substantially higher (MIT/Harvard
Brief at 17).
44. AIM states that the Department has endorsed policies that allow utilities to
recover reasonable merger-related costs, as long as ratepayers are at least as
well off with the merger as they would be without it (AIM Brief at 7, citing
Eastern-Essex Acquisition). In this proceeding, since the proposed merger will
leave ratepayers in a better position absent the merger, AIM contends that the
Department should reject the Petitioners' proposal (AIM Brief at 7).
45. AIM notes that the Department will consider merger-related expenses on a
case-by-case basis. AIM states that in this case, preapproval of merger-related
costs without a showing of immediate and real customer benefits results in
substantial shareholder benefits (AIM Brief at 9; AIM Reply Brief at 2).
46. AIM contends that unless the Department requires guaranteed merger-related
savings in turn for the recovery of an acquisition premium, ratepayers absorb a
high level of risk. AIM asserts that this violates the Department's precedent
which requires a balancing of risk and rewards among shareholders and ratepayers
(AIM Brief at 11).
47. The "rate adder" proposed by MIT/Harvard's witness is a mechanism that would
identify, on an average basis over the four-year Rate Plan, the merger-related
costs and savings projected by the Joint Petitioners (Exh. LAC at 29). The rate
adder will cease to apply at the end of the Rate Plan, at which time the Joint
Petitioners would be permitted to file a rate case to adjust their rates to
include additional savings, or reasonable merger-related costs as may be
recognized in a test year (id. at 29-30). Under this mechanism, merger-related
costs would be recoverable to the extent justified by clearly-identified
merger-related savings (id. at 30).
48. The Joint Petitioners calculate that the savings over the first 10 years
result in a benefit-cost ratio for ratepayers of almost two-to-one, over $600
million in merger-related savings vs. $340 million amortization (Joint
Petitioners Brief at 17). Over the next 30 years, the Joint Petitioners state
that the benefit-cost ratio expands to six-to-one as the remainder of the $4-$5
billion in savings for the next 40 years is offset by the $20.6 million per year
amortization of the remaining acquisition premium. Thereafter, the Joint
Petitioners assert that ratepayers receive all of the savings "in perpetuity"
(id.).
49. This requirement is consistent with the legitimate expectation of
shareholders that common stock earnings will not be diluted as a result of the
merger. Because the costs described above will have a significant and direct
effect on earnings, a portion of the synergies that will be achieved by the
merger that are sufficient to recover the merger-related investment must be
retained" (Exh. JJJ-3, at 10).
50. In approving that petition, the Department cautioned that petitioners who in
the future sought to rely on future filings to demonstrate the presence of
merger-related benefits would not have met their burden to justify approval of
merger-related costs under G.L. c. 164, ss. 96. NIPSCO/Bay State Acquisition,
D.T.E. 98-31, at 68 (1998).
51. $500 million in recoverable acquisition premiums multiplied by combined
federal-state tax rate of 39.225 percent, and divided by 40 years.
52. The Department considers the acquisition premium, if recovery is sought, to
be one of the costs that must be examined in evaluating the costs and benefits
of a proposed merger. Mergers and Acquisitions, D.P.U. 93-167-A at 18-19.
53. The Department has noted that a finding that a proposed merger or
acquisition would probably yield a net benefit does not mean that such a
transaction must yield a net benefit to satisfy D.P.U. 850. Eastern-Essex
Acquisition, D.T.E. 98-27, at 8 (1998).
54. This calculation uses a return on equity that corresponds to those returns
recently granted by the Department. Eastern-Colonial Acquisition, D.T.E. 98-128,
at 52-53 (1999).
55. PV30 = (20.6/(1+.11)) + (20.6/(1+.11)2) + ... + (20.6/(1+.11)30)
56. $308.7 million in costs over ten years, plus $179.0 million present value
costs after year ten.
57. The point was raised by AIM that the incentive for savings is strongest
during the rate freeze. The reporting requirement described here addresses AIM's
concern.
58. APB 16 is a subsection of GAAP that specifies the rules to follow when
entering into a business combination (Exhs. DTE 1-33; MIT/Harvard 1-36; Tr. 5,
at 479). APB 16 prescribes the allocation of costs of an acquiring company to
the assets acquired in a business combination recorded under purchase accounting
(Exhs. DTE 1-13; MIT/Harvard 1-36).
59. The Joint Petitioners claimed that, as a practical matter, the fair market
value of the unregulated affiliates was not likely to be significantly above
book value. This correspondence is because approximately 80 percent of the book
value of its nonregulated assets are represented by (1) the MATEP cogeneration
facilities, which were only recently acquired by Advanced Energy Systems, a
subsidiary of ComEnergy System, and (2) several real estate operations for which
the related land is in the process of being sold off (RR-DTE-6; Tr. 5, at
487-488).
60. By way of example, assuming for purposes of illustration that the fair
market value of ComEnergy System's unregulated subsidiaries with a book value of
approximately $50 million is equal to 110 percent of their book value, or $55
million, the Joint Petitioners explained that $55 million would be deducted from
the total purchase price of approximately $950 million, leaving a net
acquisition premium of approximately $895 associated with regulated operations
(RR-DTE-6). The difference between this $895 million and ComEnergy System's book
value of approximately $400 million, or $495 million, would be allocated among
the regulated subsidiaries of ComEnergy System and BEC Energy (id.).
61. As an example of traditional allocation methods, the Joint Petitioners
provided the allocation study reviewed by the Department in Cambridge Electric
Light Company, D.P.U. 92-250 (1993) (Exh. RDW-5).
62. Merger-related costs and savings are estimated by the Joint Petitioners for
the entire corporate organization combining BEC Energy and ComEnergy System
without any distinction between regulated and unregulated affiliates nor among
the four regulated companies (Exhs. AG 3-1; AG 3-2; Tr. 3, at 244-245; Tr. 4, at
398, 439). However, the Joint Petitioners claim that approximately five percent
or less of each individual category of cost savings can be attributed to the
unregulated businesses (Tr. 4, at 398).
63. The specified time for this performance measure is 30 seconds for Cambridge
Electric and ComElectric, and both 20 and 30 seconds for Boston Edison.
64. The specified time for this performance measure is 5 days for Cambridge
Electric and ComElectric, and 2 days for Boston Edison.
65. The Joint Petitioners add that the exclusion of the complaint statistics is
not meant as a criticism of either the quality of the statistics or the
important role that the Consumer Division plays in dealing with consumer
inquiries (Joint Petitioners Reply Brief at 27).
66. The Joint Petitioners state that the proposed Rate Plan is not a PBR
proposal, noting that, in Eastern-Essex Acquisition, D.T.E. 98-27, at 16 (1998),
the Department determined that a multi-year freeze proposed in the context of a
merger-related rate plan does not constitute a PBR proposal (Joint Petitioners
Reply Brief at 26).
67. Only the last three categories would apply to ComGas.
68. As indicated in Eastern-Colonial Acquisition, D.T.E. 98-128 (1999), the
Department will open a generic proceeding to exercise the discretionary
authority granted by G.L. c. 164, ss. 1E regarding PBR, by Order of Notice
issued on or about October 1, 1999. Id. at 16, n.20.
69. During 1996, BECo personnel answered 52.7 percent of telephone calls within
20 seconds, and 55.9 percent of telephone calls within 30 seconds. The
corresponding numbers for 1997 are 81.9 percent of calls answered calls within
20 seconds, and 84 percent of calls within 30 seconds; for 1998, BECo personnel
answered 75.2 percent of telephone calls within 20 seconds, and 77.3 percent of
telephone calls within 30 seconds. The proposed benchmarks of 70 percent of
telephone calls answered within 20 seconds, and 72 percent of telephone calls
within 30 seconds were calculated as the average of the value for the years
1996-1998 (Exh. JJJ-3, Att. B).
70. BECo referred to the new system as a "one and done" focus, in which the
person answering the telephone call takes "ownership" of the caller's concerns
and issues (Tr. 7, at 919).
71. The Department notes that BECo's telephone answering performance during the
first four months of 1999 are consistent with its performance during the same
months of 1998 (see RR-DTE-12).
72. These values are 75.2 percent of telephone calls answered within 20 seconds,
and 77.3 percent of telephone calls within 30 seconds (Exh. JJJ-3, Att. B).
73. During 1996, 84.6 percent of customers' meters were read on-cycle. During
1997, 90.4 percent of customers' meters were read on-cycle. Finally, during
1998, 92.5 percent of customers' meters were read on-cycle (Exh. JJJ-3, Att. E).
Boston Edison's performance during the first three months of 1999 represents a
further improvement over the corresponding period in 1998 (RR-DTE-14).
74. During 1997, ComGas personnel answered 39 percent of telephone calls within
30 seconds. The corresponding numbers for 1998 are 31 percent of calls answered
calls within 30 seconds (Exh. RDW-6, Att. 8).
75. The penalty provision of this order is the subject of appeal in Boston Gas
Company v. Department of Public Utilities, SJC-07970.
76. As noted in Section III, above, BEC Energy and ComEnergy System are expected
to operate, at least temporarily, as subholding companies of Nstar.
Exhibit D-6
August 17, 1999
Nicholas T. Antoun, Esq.
Ropes & Gray
One International Place
Boston, MA 02110-2624
SUBJECT: PILGRIM NUCLEAR POWER STATION - WITHDRAWAL OF APPLICATION FOR THE
INDIRECT TRANSFER OF THE FACILITY OPERATING LICENSE (TAC NO. MA5333)
Dear Mr. Antoun:
By application dated February 3, 1999, as supplemented May 27, 1999, Boston
Edison Company sought approval of the indirect transfer of the Facility
Operating License for the Pilgrim Nuclear Power Station (Pilgrim) held by Boston
Edison Company. The indirect transfer would have resulted from the planned
formation of a new holding company, NSTAR, of which Commonwealth Energy System
and BEC Energy, the parent company of Boston Edison Company, are to become
wholly owned subsidiaries. Subsequently, by letter dated July 20, 1999, you
withdrew the request. You noted that the approval is no longer needed since
Boston Edison Company sold its interest in Pilgrim to Entergy Nuclear Generation
Company on July 13, 1999, and is no longer the licensee for Pilgrim.
The Commission has filed the enclosed Notice of Withdrawal of Application for
Approval of Indirect Transfer of the Facility Operating License for Pilgrim with
the Office of the Federal Register for publication.
Sincerely,
/S/ ALAN WANG
Alan B. Wang, Project Manager, Section 2
Project Directorate I
Division of Licensing Project Management
Office of Nuclear Reactor Regulation
Docket No. 50-293
Enclosure: Notice of Withdrawal
<PAGE>
Nicholas T. Antoun, Esq. -2- August 20, 1999
cc: w/encl: See next page
<PAGE>
Boston Edison Company
cc:
Mr. Theodore A. Sullivan
Vice President Nuclear and Station
Director
Boston Edison Company
Pilgrim Nuclear Power Station
600 Rocky Hill Road
Plymouth, MA 02360-5599
Resident Inspector
U.S. Nuclear Regulatory Commission
Pilgrim Nuclear Power Station
Post Office Box 867
Plymouth, MA 02360-5599
Chairman, Board of Selectmen
11 Lincoln Street
Plymouth, MA 02360
Chairman, Board of Selectmen
Town Hall
878 Tremont Street
Duxbury, MA 02332
Office of the Commissioner
Massachusetts Department of
Environment Protection
One Winter Street
Boston, MA 02108
Office of the Attorney General
One Ashburton Place
20th Floor
Boston, MA 02108
Mr. Robert M. Hallisey, Director
Radiation Control Program
Massachusetts Department of
Public Health
305 South Street
Boston, MA 02130
Regional Administrator, Region I
U.S. Nuclear Regulatory Commission
475 Allendale Road
King of Prussia, PA 19406
Mr. C. Stephen Brennion
Regulatory Affairs Department Manager
Boston Edison Company
600 Rocky Hill Road
Plymouth, MA 02360-5599
Pilgrim Nuclear Power Station
Mr. Jack F. Alexander
Nuclear Assessment Group Manager
Pilgrim Nuclear Power Station
600 Rocky Hill Road
Plymouth, MA 02360-5599
Mr. David F. Tarantino
Nuclear Information Manager
Pilgrim Nucelar Power Station
600 Rocky Hill Road
Plymouth, MA 02360-5599
Ms. Kathleen M. O'Toole
Secretary of Public Safety
Executive Office of Public Safety
One Ashburton Place
Boston, MA 02108
Ms. Peter LaPorte, Director
Attn: James Muckerheide
Massachusetts Emergency Management
Agency
400 Worcester Road
P.O. Box 1496
Framingham, MA 01701-0317
Chairman, Citizens Urging
Responsible Energy
P.O. Box 2621
Duxbury, MA 02331
Citizens at Risk
P.O. Box 3803
Plymouth, MA 02361
John M. Fulton
Assistant General Counsel
800 Boylston St., P-361
Boston, MA 02199
Chairman
Nuclear Matters Committee
Town Hall
11 Lincoln Street
Plymouth, MA 02360
Mr. William D. Meinert
Nuclear Engineer
Massachusetts Municipal Wholesale
Electric Company
P.O. Box 426
Ludlow, MA 01056-0426
<PAGE>
Mr. Ron Ledgett
Executive Vice President
Boston Edison Co.
800 Boyleston Street
Boston, MA 02199
Ms. Mary Lampert, Director
Massachusetts Citizens for Safe Energy
148 Washington Street
Duxbury, MA 02332
<PAGE>
7590-01-P
UNITED STATES NUCLEAR REGULATORY COMMISSION
BOSTON EDISON COMPANY
DOCKET NO. 50-293
NOTICE OF WITHDRAWAL OF APPLICATION FOR APPROVAL OF
INDIRECT TRANSFER OF FACILITY OPERATING LICENSE
The U.S. Nuclear Regulatory Commission (the Commission) has granted the
request of Boston Edison Company (BECo) to withdraw its February 3, 1999,
application, as supplemented on May 27, 1999, by BECo for approval of the
indirect transfer of the Facility Operating License for the Pilgrim Nuclear
Power Station (Pilgrim).
The application was seeking approval of the indirect transfer of the
Facility Operating License for Pilgrim held by BECo. The indirect transfer would
have resulted from the planned formation of a new holding company, NSTAR, of
which Commonwealth Energy System and BEC Energy, the parent company of BECo, are
to become wholly owned subsidiaries. The approval is no longer needed since BECo
sold its interest in Pilgrim to Entergy Nuclear Generation Company on July 13,
1999, and no longer holds the license for Pilgrim.
The Commission had previously issued a Notice of Consideration of Approval
of Application Regarding Proposed Corporate Merger and Opportunity for Hearing
published in the FEDERAL REGISTER on June 17, 1999 (64 FR 32556). However, by
letter dated July 20, 1999, the applicant, through counsel, withdrew the
application.
For further details with respect to this action, see the application dated
February 3, 1999, as supplemented May 27, 1999, and the applicant's letter dated
July 20, 1999, which
1
<PAGE>
withdrew the application for approval of the indirect transfer. The above
documents are available for public inspection at the Commission's Public
Document Room, the Gelman Building, 2120 L. Street, NW., Washington, DC, and at
the local public document room located at the Plymouth Public Library, 132 South
Street, Plymouth, Massachusetts 02360.
Dated at Rockville, Maryland, this 17th day of August 1999.
FOR THE NUCLEAR REGULATORY COMMISSION
/S/ ALAN WANG
Alan B. Wang, Project Manager, Section 2
Project Directorate I
Division of Licensing Project Management
Office of Nuclear Reactor Regulation
2
Exhibit D-8
August 11, 1999
Mr. Ted C. Feigenbaum
Executive Vice President and
Chief Nuclear Officer
North Atlantic Energy Service Corporation
c/o Mr. James M. Peschel
P.O. Box 300
Seabrook, NH 03874
SUBJECT: ORDER APPROVING APPLICATION REGARDING CORPORATE MERGER (CANAL ELECTRIC
COMPANY) RELATING TO FACILITY OPERATING LICENSE FOR SEABROOK STATION,
UNIT NO. 1 (TAC NO. MA4754)
Dear Mr. Feigenbaum:
The enclosed Order is in response to Canal Electric Company's (Canal's)
application dated February 2, 1999, submitted under cover of your letter dated
February 11, 1999, as supplemented on February 23, March 5, and March 17, 1999.
The application requested approval of the indirect transfer of control of
Canal's interest in the facility operating license for Seabrook Station Unit 1.
The enclosed Order provides consent to the proposed indirect transfer, subject
to the conditions described therein.
The Order has been forwarded to the Office of the Federal Register for
publication.
Sincerely,
/s/ JOHN T. HARRISON
John T. Harrison, Project Manager, Section 2
Project Directorate I
Division of Licensing Project Management
Office of Nuclear Reactor Regulation
Docket No. 50-443
Enclosures: 1. Order
2. Safety Evaluation
cc w/encls; See next page
-1-
<PAGE>
Seabrook Station, Unit No. 1
cc:
Lillian M. Cuoco, Esq.
Senior Nuclear Counsel
Northeast Utilities Service Company
P.O. Box 270
Hartford, CT 06141-0270
Mr. Peter Bran
Assistant Attorney General
State House, Station #6
Augusta, ME 04333
Resident Inspector
U.S. Nuclear Regulatory Commission
Seabrook Nuclear Power Station
P.O. Box 1149
Seabrook, NH 03874
Jane Spector
Federal Energy Regulatory Commission
825 North Capital Street, N.E.
Room 8105
Washington, DC 20426
Town of Exeter
10 Front Street
Exeter, NH 03823
Regional Administrator, Region I
U.S. Nuclear Regulatory Commission
475 Allendale Road
King of Prussia, PA 19406
Office of the Attorney General
One Ashburton Place
20th Floor
Boston, MA 02108
Board of Selectmen
Town of Amesbury
Town Hall
Amesbury, MA 01913
Mr. Dan McElhinney
Federal Emergency Management Agency
Region I
J.W. McCormack P.O. &
Courthouse Building, Room 401
Boston, MA 02109
Mr. Peter LaPorte, Director
ATTN: James Muckerheide
Massachusetts Emergency Management
Agency
400 Worcester Road
P.O. Box 1496
Framingham, MA 01701-0317
Phillip T. McLaughlin, Attorney General
Steven M. Houran, Deputy Attorney General
33 Capitol Street
Concord, NH 03301
Mr. Woodbury Fogg, Director
New Hampshire Office of Emergency
Management
State Office Park South
107 Pleasant Street
Concord, NH 03301
Mr. Roy E. Hickok
Nuclear Training Manager
Seabrook Station
North Atlantic Energy Service Corp.
P.O. Box 300
Seabrook, NH 03874
Mr. James M. Peschel
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Manager of Regulatory Compliance
Seabrook Station
North Atlantic Energy Service Corp.
P.O. Box 300
Seabrook, NH 03874
Mr. W.A. DiProfio
Station Director
Seabrook Station
North Atlantic Energy Service Corporation
P.O. Box 300
Seabrook, NH 03874
Mr. Frank W. Getman, Jr.
20 International Drive
Suite 301
Portsmouth, NH 03801-6809
Mr. B. D. Kenyon
President - Nuclear Group
Northeast Utilities Service Group
P.O. Box 128
Waterford, CT 06385
Mr. David E. Carriere
Director, Production Services
Canal Electric Company
2421 Cranberry Highway
Wareham, MA 02571
Mr. David A. Lochbum
Nuclear Safety Engineer
Union of Concerned Scientists
1616 P Street, NW, Suite 310
Washington, DC 20036-1495
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UNITED STATES OF AMERICA
NUCLEAR REGULATORY COMMISSION
In the Matter of )
)
NORTH ATLANTIC ENERGY SERVICE ) Docket No. 50-443
CORPORATION, et al., )
)
(Seabrook Station Unit No. 1) )
ORDER APPROVING APPLICATION REGARDING
CORPORATION MERGER (CANAL ELECTRIC COMPANY)
I.
North Atlantic Energy Service Corporation (North Atlantic) is authorized to
act as agent for the joint owners of the Seabrook Station Unit No. 1 (Seabrook)
and has exclusive responsibility and control over the physical construction,
operation, and maintenance of the facility as reflected in Facility Operating
License NPF-86. Canal Electric Company (Canal), one of the joint owners, holds a
3.52317-percent possessory interest in Seabrook. The Nuclear Regulatory
Commission (NRC) issued Facility Operating License NPF-86 on March 15, 1990,
pursuant to Part 50 of Title 10 of the Code of Federal Regulations (10 CFR Part
50). The facility is located in Seabrook Township, Rockingham County, on the
southeast coast of the State of New Hampshire.
II.
Under cover of a letter dated February 11, 1999, North Atlantic forwarded
an application by Canal requesting approval of the indirect transfer of control
of Canal's interest in the operating
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license (OL) for Seabrook. The application was supplemented on February 23,
March 5, and March 17, 1999 (collectively referred to hereinafter as the
application).
According to the application, Canal is a wholly owned subsidiary of
Commonwealth Energy System (CES). On December 5, 1998, CES and BEC Energy (BEC)
entered into an Agreement and Plan of Merger under which those entities will
merge into a new surviving Massachusetts corporation (the "New Company"). Upon
consummation of the merger, Canal will become a wholly owned subsidiary of the
New Company, thereby effecting an indirect transfer of Canal's interest in
Seabrook's OL. North Atlantic, the sole license operator of the facility, would
remain as the managing agent for the 11 joint owners of the facility and would
continue to have exclusive responsibility for the management, operation, and
maintenance of Seabrook. The application does not propose a change in the
rights, obligations, or interests of the other joint owners of Seabrook. In
addition, no physical changes to Seabrook or operational changes are being
proposed. No direct transfer of the license will result from the proposed
merger.
Approval of the indirect transfer was requested pursuant to 10 CFR 50.80.
Notice of the application for approval and an opportunity for a hearing was
published in the Federal Register on April 27, 1999 (64 FR 22657). No hearing
requests were filed.
Under 10 CFR 50.80, no license, or any right thereunder, shall be
transferred, directly or indirectly, through transfer of control of the license,
unless the Commission shall give its consent in writing. Upon review of the
information in the application, and other information before the Commission, the
NRC staff has determined that the proposed merger will not affect the
qualifications of Canal as a holder of the Seabrook license, and that the
transfer of control of the license, to the extent effect by the proposed merger,
is otherwise consistent with applicable
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provisions of law, regulations, and orders issued by the Commission subject to
the conditions set forth herein. The foregoing findings are supported by a
safety evaluation dated August 11, 1999.
Accordingly, pursuant to Sections 161b, 161i, 161o, and 184 of the Atomic
Energy Act of 1964, as amended; 42 USC ss.ss. 2201(b), 2201(i), 2201(o), and
2234; and 10 CFR 50.80. IT IS HEREBY ORDERED that the indirect license transfer
referenced above is approved, subject to the following conditions:
1. Canal shall provide the Director of the Office of Nuclear Reactor
Regulation a copy of any application, at the time it is filed, to
transfer (excluding grants of security interests or liens) from Canal
to its proposed parent, or to any other affiliated company, facilities
for the production, transmission, or distribution of electric energy
having a depreciated book value exceeding ten percent (10%) of Canal's
consolidated net utility plant as recorded on Canal's books of
accounts.
2. Should the transfer not be completed by August 1, 2000, this Order
shall become null and void, provided, however, on application and for
good cause shown, such date may be extended.
This Order is effective upon issuance.
For further details with respect to this Order, see the initial application
dated February 2, 1999, and supplements dated February 23, March 5, and March
17, 1999, which are available for public inspection at the Commission's Public
Document Room, the Gelman Building, 2120 L Street, N.W., Washington, DC and at
the local public document room located at the Exeter Public Library, Founders
Park, Exeter, NH 03833.
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Dated at Rockville, Maryland, this 11th day of August, 1999
FOR THE NUCLEAR REGULATORY COMMISSION
/S/ WILLIAM F. KANE
William F. Kane, Acting Director
Office of Nuclear Reactor Regulation
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SAFETY EVALUATION BY THE OFFICE OF NUCLEAR REACTOR REGULATION
RELATED TO CORPORATE MERGER (CANAL ELECTRIC COMPANY)
NORTH ATLANTIC ENERGY SERVICE CORPORATION
DOCKET NO. 50-443
SEABROOK STATION, UNIT NO. 1
1.0 BACKGROUND
By application dated February 2, 1999, Canal Electric Company (Canal) requested
that the U.S. Nuclear Regulatory Commission (NRC) consent to the indirect
transfer of control of Canal's interest in the operating license (OL) for
Seabrook Station Unit No. 1 (Seabrook). Canal is a 3.52-percent owner of
Seabrook. The remained 96.48 percent is owned by a consortium of 10 other
companies. North Atlantic Energy Service Corporation (North Atlantic) is the
exclusive licensed operator of Seabrook and is authorized to act as agent for
the 11 owners of the facility. The application was supplemented on February 23,
March 5, and March 17, 1999.
Canal is a wholly owned subsidiary of Commonwealth Energy System (CES). CES is a
Massachusetts Business Trust organized under the laws of Massachusetts and an
exempt public utility holding company under Section 3(a)(1) of the Public
Utility Holding Company Act (PUHCA). On December 5, 1998, CES and BEC Energy
Company (BEC) entered into an Agreement and Plan of Merger pursuant to which
these entities will merge into a new surviving Massachusetts corporation yet to
be named. For the purposes of this safety evaluation, the surviving corporation
is designation "New Company." BEC is an exempt public utility holding company
under Section 3(a)(1) of the PUHCA and is regulated as a public utility in the
Commonwealth of Massachusetts. Upon consummation of the merger, the stockholders
of CES and BEC will become the stockholders of New Company. BEC stockholders
will own approximately 68 percent of New Company and CES stockholders will own
approximately 32 percent. The assets (including their respective subsidiaries)
and liability of BEC and CES will become the assets and liabilities of New
Company. Therefore, Canal will become a wholly owned subsidiary of New Company,
and the merger will effect an indirect change of control of Canal's interest in
the Seabrook OL.
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Seabrook is a 1,158-MW pressurized-water reactor generating facility that is
owned by the 11 Seabrook joint owners pursuant to an agreement for joint
Ownership, Construction, and Operation of New Hampshire Nuclear Units, dated May
1, 1973, as amended (Joint Ownership Agreement). In accordance with the Joint
Ownership Agreement and the Managing Agent Operating Agreement dated June 29,
1992, as amended, (the "MAOA"), North Atlantic is the Managing Agent for the 11
Seabrook joint owners and, as such, has responsibility for the management,
operating, and maintenance of Seabrook. North Atlantic's position as Managing
Agent and operator was approved by issuance of Amendment No. 10, dated May 29,
1992, to the Seabrook OL.
2.0 FINANCIAL QUALIFICATIONS
The financial qualifications analysis in based on the information provided in
the application and supplements thereto, referenced above (hereinafter
collectively "the application"). The applications states that, after the
proposed merger, the current regulatory mechanisms that affect Canals' revenues
and expenses for Seabrook's operation will remain in place and that the
decommissioning funding for Seabrook will not be affected. On the basis of the
information in the application, the staff finds that there will be no apparent
adverse effect on Canal's ability to contribute appropriately to the operations
and decommissioning of Seabrook as result of the proposed merger. Following the
merger, Canal will remain an electric utility as defined in 10 CFR 50.2. As an
electric utility, Canal is exempt from further financial qualifications review,
pursuant to 10 CFR 50.33(f).
However, in view of the NRC's concern that corporate restructurings involving
new parents or affiliates can lead to a diminution of assets necessary for the
safe operation and decommissioning of a licensee's nuclear power plant, the
NRC's practice has been to condition such license transfer approvals upon a
requirement that the licensee not transfer significant assets from the licensee
to an affiliate without first notifying the NRC. This requirement assists the
NRC in assuring that a licensee will continue to maintain adequate resources to
contribute to the safe operation and decommissioning of its facility. Thus, the
following should be made a condition of the order approving the application
regarding the proposed merger:
Canal shall provide the Director of the Office of Nuclear Reactor
Regulation a copy of any application, at the time it is filed, to transfer
(excluding grants of security interests or liens) from Canal to its
proposed parent, or to any other affiliated company, facilities for the
production, transmission, or distribution of electric energy having a
depreciated book value exceeding ten percent (10%) of Canal's consolidated
net utility plant as recorded on Canal's books of accounts.
3.0 TECHNICAL QUALIFICATIONS
After the merger, North Atlantic will remain as the sole licensed operator of
the facility and will continue to have exclusive responsibility for the
management, operation, and maintenance of
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Seabrook. The proposed merger will not affect North Atlantic's technical
qualifications or responsibilities with regard to Seabrook. Also, no changes are
proposed to the organization or personnel responsible for operation of Seabrook.
Based on the foregoing, the staff concludes that the proposed merger will not
affect North Atlantic's technical qualifications or responsibilities with regard
to Seabrook.
4.0 ANTITRUST REVIEW
The Atomic Energy Act does not require or authorize antitrust review of
post-operating license transfer applications. Kansas Gas and Electric Co., et
al. (Wolf Creek Generating Station, Unit 1), CLI-99-19, 49 NRC___, slip op.
(June 18, 1999). Therefore, since the transfer application postdated the
issuance of the Seabrook operating license, no antitrust review is required or
authorized.
5.0 FOREIGN OWNERSHIP, CONTROL, OR DOMINATION
Information in the application submitted to comply with 10 CFR 50.33(d) states
that Canal is a corporation organized under the laws of the Commonwealth of
Massachusetts with its principal place of business in Massachusetts and that all
of Canal's directors and principal officers are United States citizens.
Furthermore, the application states that "Canal is not now owned, controlled or
dominated by an alien, foreign corporation or foreign government." The staff
does not know or have reason to believe otherwise.
6.0 CONCLUSION
In view of the foregoing, the NRC staff concludes that the proposed merger of
CES and BEC, which will create a new parent company of Canal, will not adversely
affect the financial qualifications of Canal with respect to its ownership share
of Seabrook. Nor will this merger impact the technical qualifications of North
Atlantic as the licensed operator of Seabrook. Also, there do not appear to be
any problematic antitrust or foreign ownership considerations related to the
Seabrook license that would result from the proposed merger. Thus, the proposed
merger will not affect the qualifications of Canal as a holder of the license
for Seabrook, and the indirect transfer of control of the license, to the extent
effected by the proposed merger, is otherwise consistent with applicable
provisions of law, regulations, and orders issued by the Commission, subject to
the condition discussed above regarding the transfer of significant assets.
Accordingly, the application regarding the proposed merger should be approved
with the foregoing condition.
Principal Contributor: M.A. Dusanlwskyj
Alex McKaigney
Date: August 11, 1999
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