DECISION
NSUARB-NSPI-P-875
2002 NSUARB 59
NOVA SCOTIA UTILITY AND REVIEW BOARD
IN THE MATTER OF THE PUBLIC UTILITIES ACT
- and IN THE MATTER OF AN APPLICATION by Nova Scotia Power Incorporated for
approval of certain Revisions to its Rates, Charges and Regulations
BEFORE:
John A. Morash, C.A., Chair
Margaret A. M. Shears, Vice-Chair
John L. Harris, Q.C., Member
COUNSEL:
NOVA SCOTIA POWER INCORPORATED
Peter W. Gurnham, Q.C.
Daniel M. Campbell, Q. C.
ANNAPOLIS GROUP et al.
Robert G. Grant, Q.C.
Nancy G. Rubin
DALHOUSIE LEGAL AID SERVICE
Claire McNeil
ELECTRICITY CONSUMERS ALLIANCE
OF NOVA SCOTIA
John Woods, P. Eng.
HALIFAX REGIONAL MUNICIPALITY
Mary Ellen Donovan
MUNICIPAL ELECTRIC UTILITIES
OF NOVA SCOTIA CO-OPERATIVE
Donald Regan
Albert Dominie
PROVINCE OF NOVA SCOTIA
Jeannine Lagassé
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STORA ENSO PORT HAWKESBURY LIMITED and
BOWATER MERSEY PAPER COMPANY LIMITED
George T. H. Cooper, Q.C.
David S. MacDougall
TRENTONWORKS LIMITED et al.
A. William Moreira, Q. C.
Ben R. Durnford
HEARING DATES
April 22-26 and 29-30,
May 1-3, 13-17, 21-24 and
June 3-4, 2002
FINAL SUBMISSIONS
June 24, 2002
LIST OF WITNESSES
APPENDIX - A
LIST OF INTERVENORS
APPENDIX - B
BOARD COUNSEL:
S. Bruce Outhouse, Q.C.
BOARD COUNSEL’S
CONSULTANTS:
Dr. John Stutz,
Tellus Institute
James A. Rothschild
Rothschild Financial Consulting
DECISION DATE:
October 23, 2002
DECISION:
Requested Revenue Requirement increase of $67.1
million reduced to approximately $24.7 million;
Proposed average rate increase across all classes of
8.9% reduced to approximately 3.3%.
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TABLE OF CONTENTS
1.0
INTRODUCTION .................................................................................................. 1
2.0
BACKGROUND .................................................................................................... 6
3.0
TEST YEAR REVENUE AND LOAD FORECAST.............................................. 16
3.1
Load Forecast and Revenues .................................................................. 16
3.1.1 Submission - NSPI ........................................................................ 16
3.1.2 Submissions - Intervenors ............................................................. 18
3.1.3 Findings......................................................................................... 18
4.0
TEST YEAR EXPENSES.................................................................................... 20
4.1
Fuel Costs ................................................................................................ 20
4.1.1 Submission - NSPI ........................................................................ 20
4.1.2 Submissions - Intervenors ............................................................. 24
4.1.3 Findings......................................................................................... 27
4.2
CBDC Buyout.......................................................................................... 30
4.2.1 Submission - NSPI ........................................................................ 30
4.2.2 Submissions - Intervenors ............................................................. 34
4.2.3 Findings......................................................................................... 37
4.3
January Adjustment ................................................................................. 38
4.3.1 Submission - NSPI ........................................................................ 38
4.3.2 Submissions - Intervenors ............................................................. 41
4.3.3 Findings......................................................................................... 43
4.4
Hydro........................................................................................................ 44
4.4.1 Submission - NSPI ........................................................................ 44
4.4.2 Submissions - Intervenors ............................................................. 44
4.4.3 Findings......................................................................................... 46
4.5
Compensation .......................................................................................... 47
4.5.1 Submission - NSPI ........................................................................ 47
4.5.2 Submissions - Intervenors ............................................................. 48
4.5.3 Findings......................................................................................... 52
4.5.3.1 Executive Compensation............................................... 52
4.5.3.2 Incentive Compensation................................................ 56
4.6
Operating, Maintenance and General Expenses (OM&G) ....................... 58
4.6.1 Submission - NSPI ........................................................................ 58
4.6.2 Submissions - Intervenors ............................................................. 60
4.6.3 Findings......................................................................................... 63
4.7
Depreciation Expense .............................................................................. 67
4.7.1 Findings......................................................................................... 67
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5.0
CAPITAL STRUCTURE AND RATE OF RETURN............................................. 68
5.1
Capital Structure ...................................................................................... 68
5.1.1 Submission - NSPI ........................................................................ 68
5.1.2 Submissions - Intervenors ............................................................. 70
5.1.3 Findings - Capital Structure ........................................................... 72
5.2 Rate of Return on Equity ............................................................................. 73
5.2.1 Submission - NSPI ........................................................................ 73
5.2.2 Submissions - Intervenors ............................................................. 75
5.2.3 Findings - Rate of Return on Equity .............................................. 78
5.3
Return on Rate Base................................................................................ 78
5.3.1 Findings......................................................................................... 78
6.0
AFFILIATE ACTIVITY......................................................................................... 81
6.1
Code of Conduct - PricewaterhouseCoopers Report ............................... 81
6.1.1 Submissions .................................................................................. 81
6.1.2 Findings......................................................................................... 85
6.2
Emera Energy - Agency Agreement......................................................... 87
6.2.1 Submission - NSPI ........................................................................ 87
6.2.2 Submissions - Intervenors ............................................................. 90
6.2.3 Findings......................................................................................... 95
6.3
Shared Services Allocation .................................................................... 101
6.3.1 Submission - NSPI ...................................................................... 101
6.3.2 Submissions - Intervenors ........................................................... 102
6.3.3 Findings....................................................................................... 104
6.4 Coal Transportation Costs ..................................................................... 106
6.4.1 Submission - NSPI ...................................................................... 106
6.4.2 Submissions - Intervenors ........................................................... 108
6.4.3 Findings....................................................................................... 109
6.5
Independence and Insulation ................................................................. 111
7.0
COST OF SERVICE, RATE DESIGN AND OTHER RATE-MAKING ISSUES. 116
7.1
Overview - Rate-making Issues ............................................................. 116
7.2
Cost of Service Study............................................................................. 117
7.2.1 Submissions - NSPI .................................................................... 117
7.2.2 Submissions - Intervenors ........................................................... 118
7.2.3 Findings....................................................................................... 119
7.3
Revenue/Cost Ratios and Rate Shock................................................... 119
7.3.1 Submissions - NSPI .................................................................... 119
7.3.2 Submissions - Intervenors ........................................................... 120
7.3.3 Findings....................................................................................... 123
7.4
Annually Adjusted Rates ........................................................................ 124
7.4.1 Submission - NSPI ...................................................................... 124
7.4.2 Submissions - Intervenors ........................................................... 124
7.4.3 Findings....................................................................................... 125
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7.5
7.6
7.7
7.8
Rate Design ........................................................................................... 126
7.5.1 Submissions - NSPI .................................................................... 126
7.5.2 Submissions - Intervenors ........................................................... 126
7.5.3 Findings....................................................................................... 127
Future Rate Design Proceeding............................................................. 130
7.6.1 Board Directives .......................................................................... 130
Municipal/Large Industrial Rate Relationship ......................................... 131
Green Rider Rate ................................................................................... 132
7.8.1 Submission - NSPI ...................................................................... 132
7.8.2 Submissions - Intervenors ........................................................... 132
7.8.3 Findings....................................................................................... 133
8.0
RULES AND REGULATIONS........................................................................... 134
8.1
Submission - NSPI ................................................................................. 134
8.2
Submissions - Intervenors...................................................................... 135
8.3
Findings.................................................................................................. 135
9.0
OTHER ISSUES ............................................................................................... 136
9.1
Regulatory Process - Timing .................................................................. 136
9.2
Disclosure .............................................................................................. 138
9.3
Process Improvements .......................................................................... 140
9.4
Dalhousie Legal Aid Service .................................................................. 142
10.0
SUMMARY OF DISALLOWANCES AND ADJUSTMENTS.............................. 145
11.0
SUMMARY OF BOARD FINDINGS.................................................................. 147
11.1 Revenue Requirement/Rate Increase .................................................... 147
11.2 Capital Structure .................................................................................... 147
11.3 Rate of Return on Equity........................................................................ 148
11.4 January Adjustment ............................................................................... 148
11.5 Coal Costs.............................................................................................. 149
11.6 CBDC Buyout......................................................................................... 149
11.7 Hydro Generation................................................................................... 150
11.8 Executive Compensation ....................................................................... 150
11.9 Incentive Compensation......................................................................... 151
11.10 Operating, Maintenance and General Expenses ................................... 152
11.11 Sponsorships and Donations ................................................................. 153
11.12 Affiliate Activity ....................................................................................... 153
(A)
Code of Conduct ......................................................................... 153
(B)
Agency Agreement ...................................................................... 154
(C)
Shared Services Allocation.......................................................... 157
(D)
Coal Transportation Contract ...................................................... 158
(E)
Independence and Insulation ...................................................... 159
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11.13 Cost of Service, Rate Design and Other Rate-Making Issues .............. 160
(A)
Compliance Filing........................................................................ 160
(B)
Cost of Service Methodology....................................................... 161
(C)
Revenue/Cost Ratios and Rate Shock ........................................ 161
(D)
Annually Adjusted Rates ............................................................. 162
(E)
Rate Design................................................................................. 163
(F)
Future Rate Design Proceeding .................................................. 163
11.14 Municipal/Large Industrial Rate Relationship ......................................... 164
11.15 Green Rider Rate ................................................................................... 164
11.16 Depreciation Expense ............................................................................ 164
11.17 Load Forecasting ................................................................................... 165
11.18 Dalhousie Legal Aid Service .................................................................. 165
11.19 Regulatory Process................................................................................ 166
APPENDIX - A
Lists of Witnesses ....................................................................... 168
APPENDIX - B
List of Intervenors........................................................................ 170
APPENDIX - C
Interim Code of Conduct ............................................................. 172
APPENDIX - D
Board Disclosure Order ............................................................... 180
APPENDIX - E
Board Letter of Clarification......................................................... 187
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1
1.0
INTRODUCTION
[1]
This decision is further to a public hearing conducted by the Nova Scotia
Utility and Review Board (the Board) over 21 days between April 22, 2002 and June 4, 2002 in the
matter of an application by Nova Scotia Power Incorporated (NSPI, the Company, the Utility) for
approval of revisions to its Rates, Charges and Regulations.
[2]
NSPI is a regulated public utility and is the successor to Nova Scotia Power
Corporation, a crown corporation which was privatized in 1992. As of January 1, 1999, NSPI
became the principal subsidiary of Nova Scotia Power Holdings Incorporated, now known as Emera
Incorporated (Emera).
[3]
NSPI is engaged in the production and supply of electrical energy. It
distributes electricity through a province-wide system and, as at December 31, 2001, served
approximately 445,000 customers including six municipal electric utilities. Its revenues for the year
2001 were $838.6 million and its total assets as at December 31, 2001 were $2.9 billion.
[4]
In this application NSPI is requesting an increase in rates to meet its proposed
revenue requirement. Its proposed rate increases will result in an average increase of 8.9% across all
classes. Certain customers will receive rate increases considerably in excess of this amount. In its
application as originally filed, NSPI also requests approval of a return on rate base of 10.25%, a
return on common equity of 11% and an increase in the common equity component of its capital
structure from 35% to a range of 40% - 45%. NSPI also requests final approval of the Code of
Conduct which governs the relationship between NSPI and its affiliates. It was approved by the
Board on an interim basis on March 16, 2001 and has been in effect since September 16, 2001.
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2
[5]
The hearing was duly advertised in accordance with Sections 64 and 86 of the
Public Utilities Act (“the Act”) R.S.N.S., 1989, c.380, as amended, which read as follows:
Approval of schedule of rates and charges of utility
64 (1) No public utility shall charge, demand, collect or receive any compensation for any
service performed by it until such public utility has first submitted for the approval of
the Board a schedule of rates, tolls and charges and has obtained the approval of
the Board thereof.
Filing with Board
(2) The schedule of rates, tolls and charges so approved shall be filed with the Board
and shall be the only lawful rates, tolls and charges of such public utility until altered,
reduced or modified as provided in this Act. R.S., c. 380, s. 64.
Notice of hearing of application for rate changes
86
Notice of the hearing of any application, for the approval of or providing for an
increase or decrease in the rates, tolls and charges of any public utility, shall be
given by advertisement in one or more newspapers published or circulating in the
cities, towns or municipalities where such changes are sought, for three consecutive
weekly insertions preceding the date of said hearing, unless otherwise ordered by
the Board. R.S., c. 380, s. 86.
[6]
There were 64 formal intervenors who entered appearances or notices of
intervention opposing NSPI’s application. A number of these parties, (identified in Appendix B,
attached) were represented at the hearing by Counsel. The Province of Nova Scotia (“the Province”);
Annapolis Group et al. (“Annapolis”) whose Counsel represented approximately 32 intervenors;
Stora Enso Port Hawkesbury Limited and Bowater Mersey Paper Company Limited (“SEB”);
TrentonWorks Limited et al. (“TrentonWorks”), whose Counsel also represented several industrial
customers; Halifax Regional Municipality (“HRM”); Dalhousie Legal Aid Service (“DLAS”); the
Electricity Consumers Alliance of Nova Scotia (“ECANS”) and the Municipal Electric Utilities of
Nova Scotia Cooperative (“MEUNSC”) all participated in the hearing. The Board also received 107
letters and e-mails opposing NSPI’s application.
[7]
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The application for a rate increase was filed by NSPI on December 18, 2001.
3
By Order dated December 20, 2001, the Board set down a public hearing on the application to
commence on March 4, 2002 and established a timetable for filings and information requests and
responses (“IRs”) that covered the period from January 7, 2002 to February 28, 2002. Following
public notice of the hearing schedule, a number of intervenors including the Province, SEB,
Annapolis, ECANS and MUENSC filed submissions with the Board requesting an adjournment of
the proceeding. The intervenors cited the magnitude of the proposed increases; the timing of the
application and notice which ran over the Christmas holidays; the time required to engage expert
witnesses; and the time necessary for intervenors to adequately prepare their case, as grounds for the
requested adjournment. By Order dated January 22, 2002 the Board agreed, over NSPI’s objections,
to an adjournment and set out a revised timetable which provided additional time for IRs to be issued
and responses filed. The revised date for the commencement of the hearing was April 22, 2002.
[8]
On March 8, 2002 an application was filed with the Board by SEB and
Annapolis “...to compel NSPI to provide better and fuller responses” to certain IRs. A hearing on the
application was held on March 11, 2002 and, in an Order dated March 12, 2002, (Appendix D,
attached) the Board rejected NSPI’s argument that the information sought should not be disclosed,
even on a confidential basis. The Board ordered that certain designated confidential information
(DCI) be made available for inspection at NSPI’s offices to those parties who participated in the
disclosure hearing and who signed confidentiality undertakings in a form approved by the Board.
The DCI related to:
(a)
(b)
(c)
(d)
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fuel supply contracts;
fuel transportation contracts;
tender documentation related to (a) and (b) above;
correspondence and documents relating to negotiation of termination of the
long-term CBDC coal supply contract, (sometimes referred to as the
4
(e)
(f)
[9]
contract “buyout”) including original coal contract and amendments,
termination agreement and arbitration agreement;
generating unit-specific production and cost information, on a monthly
basis, including but not limited to heat rates, monthly forecast MWh of
supply, cost of each fuel source, and quantities and qualities of fuel to be
used by fuel source;
an explanation of the assumptions and calculations underlying the
information provided above.
(Board Order on Disclosure Application, March 12, 2002)
As a result of the Board’s Order, (and subsequent letter dated March 22, 2002
which resolved a dispute between NSPI and Annapolis as to the scope of the March 12, 2002 Order,
attached as Appendix E), those intervenors who signed confidentiality undertakings reviewed the
DCI at NSPI’s offices. Certain intervenors presented evidence and made submissions based on the
information reviewed and this evidence was filed with the Board on a confidential basis. To the
extent that any submission includes references to DCI, portions of the evidence available to the
Board do not form part of the public record of the hearing. Similarly, when confidential information
was the subject of testimony of witnesses at the hearing, the Board conducted those parts of the
hearing on an in camera basis.
Accordingly, certain testimony, undertakings, exhibits and
transcripts relating to confidential information were (and continue to be) available only to the Board
and those parties who signed confidentiality undertakings. Redacted versions of this evidence are a
matter of public record.
[10]
While conducting in camera sessions is an unusual occurrence for the Board,
it is not precluded by the Board’s regulatory rules. Indeed the rules contemplate information being
filed in confidence and also provide for other parties to request its disclosure. The Board believes
that its role as a regulator responsible for protecting the public interest requires it to issue a decision
that is, in all respects, accessible to the public. The Board considers that it is unacceptable to issue
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5
two versions of a decision - one public and one confidential. Therefore, although the Board has
carefully considered all of the evidence filed during this proceeding, including those parts which
involve confidential information, the Board has chosen, in this decision, to avoid direct reference to
confidential information.
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6
2.0
BACKGROUND
[11]
NSPI is a vertically integrated, investor-owned, regulated public utility with a
virtual monopoly on electricity service throughout the Province. In 2001, it supplied 97% of the
generation, 99% of the transmission and 95% of the distribution in the Province. The Board
regulates NSPI in the public interest on a cost of service basis. The Act gives the Board broad
regulatory oversight over public utilities and provides it with the authority to discharge its regulatory
responsibilities. Some of the relevant provisions are as follows:
Supervision of utility by Board
18
The Board shall have the general supervision of all public utilities, and may make all
necessary examinations and inquiries and keep itself informed as to the compliance
by the said public utilities with the provisions of law and shall have the right to obtain
from any public utility all information necessary to enable the Board to fulfil its duties.
R.S., c. 380, s. 18.
Form of books and records of utility
27
The Board may prescribe the forms of all books, accounts, papers and records
required to be kept by any public utility and every public utility is required to keep and
render its books, accounts, papers and records accurately and faithfully in the
manner and form prescribed by the Board and to comply with all directions of the
Board relating to such books, accounts, papers and records. R.S., c. 380, s. 27.
Examination and audit of accounts
29 (1) The Board may provide for the examination and audit of all accounts, and all items
shall be allocated to the accounts in the manner prescribed by the Board.
Authority to inspect books or records of utility
(2)
The agents, accountants or examiners employed by the Board shall have authority
under the direction of the Board to inspect all and any books, accounts, papers or
records and memoranda kept by any public utility. R.S., c. 380, s. 29.
Power to determine value of property of utility
30 (1)
The Board may at any time, with the assistance of such engineers, accountants,
valuators, counsel and others as it deems wise or advisable to employ, inquire into
and determine the extent, condition and value of the whole or any portion of the
property and assets of any public utility used and useful in furnishing, rendering or
supplying a particular service to or for the public, as of a date to be fixed by the
Board.
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7
Duty of utility to furnish information
33 (1)
Every public utility shall furnish to the Board from time to time, and as the Board may
require, maps, profiles, contracts, reports of engineers and other documents,
records and papers, or copies of any and all of the same in aid of any investigation
and to determine the value of the property of such public utility, and every public
utility shall co-operate with the Board in the work of the valuation of its property in
such further particulars and to such extent as the Board may direct.
Approval of improvement over $25,000
35
No public utility shall proceed with any new construction, improvements or
betterments in or extensions or additions to its property used or useful in furnishing,
rendering or supplying any service which requires the expenditure of more than
twenty-five thousand dollars without first securing the approval thereof by the Board.
R.S., c. 380, s. 35; 2001, c. 35, s. 30.
Separate rate base for each service supplied
42 (1)
The Board shall fix and determine a separate rate base for each type or kind of
service furnished, rendered or supplied to the public by a public utility.
Factors considered in establishing rate base
(2) In establishing a rate base the Board shall determine the value of the physical assets
of the public utility in accordance with the provisions of this Act, including in such
value the actual reasonable and necessary cost of labour and supervision up to and
including gang foreman, and the Board may, in its discretion, make allowances for
the following matters, and such other matters as the Board deems appropriate:
(a)
necessary working capital;
(b)
organization expenses to the extent of such sum as the public utility may
establish to the satisfaction of the Board to have been reasonably and
prudently expended out of capital account in respect of organization
expenses as defined by the regulations of the Board;
(c)
construction overheads to the extent of such sum as the public utility may
establish to the satisfaction of the Board to have been reasonably and
prudently expended out of capital account in respect of engineering,
superintendence, legal services, taxes and interest during construction, and
like matters not included in the valuation of the physical assets;
expenses of valuations to the extent of such sums as may have been
expended in respect of a valuation by the Board and, with the approval of
the Board, charged to capital account;
costs in whole or in part of land acquired
in
reasonable
anticipation of future
requirements.
(d)
(e)
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8
Amortization of organization and valuation expenses
(3)
The Board may direct that a public utility shall make such provision as to the Board
seems proper for the amortization of the sums allowed in a rate base for
organization expenses and expenses of valuations, and may direct that the sums
required annually for such amortization shall be charged as an operating expense.
Revision of rate base
(4)
The Board may from time to time revise any rate base making due allowance for
extensions and additions to, improvements or alterations in and withdrawals or
retirements from, the property and assets of the public utility.
Existing rate base
(5)
Until a rate base is determined by the Board for any public utility pursuant to this
Section, the present rate base for such public utility as from time to time revised or
accepted by the Board shall continue in effect and shall be the rate base for such
public utility, provided that the Board may direct that any such public utility shall
make such provision as to the Board seems proper for the amortization of the sums
allowed in such rate base for organization expenses, expenses of valuations or
allowances not mentioned in subsection (2) and may direct that the sums required
annually for such amortization shall be charged as an operating expense. R.S., c.
380, s. 42; 1992, c. 8. s. 35.
Amount utility entitled to earn annually
45 (1) Every public utility shall be entitled to earn annually such return as the Board deems
just and reasonable on the rate base as fixed and determined by the Board for each
type or kind of service furnished, rendered or supplied by such public utility, provided,
however, that where the Board by order requires a public utility to set aside annually
any sum for or towards an amortization fund or other special reserve in respect of
any service furnished, rendered or supplied, and does not in such order or in a
subsequent order authorize such sum or any part thereof to be charged as an
operating expense in connection with such service, such sum or part thereof shall be
deducted from the amount which otherwise under this Section such public utility
would be entitled to earn in respect of such service, and the net earnings from such
service shall be reduced accordingly.
Earnings are in addition to expenses and allowances
(2) Such return shall be in addition to such expenses as the Board may allow as
reasonable and prudent and properly chargeable to operating account, and to all just
allowances made by the Board according to this Act and the rules and regulations of
the Board. R.S., c. 380, s. 45.
Power to compel compliance by utility
46
The Board shall have power, after hearing and notice by order in writing, to require
and compel every public utility to comply with the provisions of this Act and any
municipal ordinance or regulation relating to said public utility, and to conform to the
duties imposed upon it thereby by the provisions of its own charter, if any charter has
or shall be granted it, provided, that nothing herein contained shall be held to relieve
any public utility or its officers, agents or servants, from any punishment, fine,
forfeiture or penalty for violation of any such law, ordinance, regulation or duty
imposed by its charter, nor to limit, take away or restrict the jurisdiction of any court
or other authority which now has or which may hereafter have power to impose any
such punishment, fine, forfeiture or penalty. R.S., c. 380, s. 46.
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Duty to furnish information
51 (1) Every public utility shall furnish to the Board all information required by it to carry into
effect the provisions of this Act, and shall make specific answers to all specific
questions submitted by the Board.
Duty to furnish safe and adequate service
52
Every public utility is required to furnish service and facilities reasonably safe and
adequate and in all respects just and reasonable. R.S., c. 380, s. 52.
Approval for transfer of undertaking
62
Notwithstanding the provisions of any Act of the Legislature, no public utility shall
sell, assign or transfer the whole of its undertaking or any part thereof to any person
or corporation except with the approval of the Board first had and obtained. R.S., c.
380, s. 62.
[12]
NSPI last filed an application for a general rate increase on August 17, 1995.
The Hearing was held in January of 1996 and the Board’s decision was rendered on March 4, 1996.
[13]
1.
The Board summarized its 1996 decision, in part, as follows:
SUMMARY OF DECISION
NSPI requested an increase in rates of $21.6 million which would have resulted in an
average increase of 3.0% over present revenue. The Company requested a return
on shareholder equity of 12.0%. The Board has reduced the requested increase by
approximately $11 million. This will result in an average rate increase of 1.85% but
vary by customer classes from a reduction of 8.0% to an increase of 5.0%. The
reduction in rates is the result of reducing the cost recovery ratio for certain classes
to 105. The Domestic class will continue to have the lowest revenue/cost ratio of any
of the customer classes at approximately 94%.
The reduction is attributable to a reduction in the shareholder return of 1.25%, the
allocation of some promotional and employee incentive expenses to shareholders
and a revised accounting treatment for the carrying costs of the Glace Bay
generating station.
Approximately $6 million of the reduction has been used to reduce the excess cost
recovery for the Small General, General and Small Industrial Rate customer classes.
The delay in the rate adjustment to March 1 amounts to a saving of $4.2 million to
all customers. The Domestic Rate block structure and base charge have been
adjusted to reduce the proposed impact on low-consumption customers.
2.
The Board is of the opinion that voluntary time-of-day rates are the most appropriate
form of cost reducing rate design at this time and that they are economic, necessary
and desirable. To ensure that there is an economic incentive for the Company, the
Board accepts electric thermal storage and hot water storage technologies as capital
expenditures within the regulated rate base providing that the equipment is handled
on a direct-to-customer basis and a lease-to-own basis.
3.
The Board is of the opinion that a considerable portion of the funds spent under the
DSM program should be consistent with the introduction of Time-of-Use Rates,
heat/hot water storage systems and other load shifting or consumption technologies.
The Board has, therefore, provided for an additional DSM budget of $500,000 in the
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10
revenue requirement for individually approved projects relating to these promotion
and demonstration activities.
4.
The Board determines that a return on equity in the range of 10.5% to 11.00% is just
and reasonable. Rates will be determined on the basis of a return on equity of
10.75%, which is 1.25% less than the requested return on shareholder equity. This
will result in a projected interest coverage of 1.70. The Board approves a return on
rate base of 11.09%.
5.
The Board continues to be of the opinion that a range of 8% to 10% for preferred
share capital and a range of 33% to 35% for common share capital is appropriate for
the capital structure of NSPI and has so approved.
6.
The Board approves a one year delay in the schedule for amortizing the deferral of
certain Point Aconi costs. The Board does not accept the Company proposal that
severance costs that exceed 0.25% of the revenue requirement should be deferred.
The modified plan will last approximately six months longer than the original plan and
will moderate the required 1996 rate increase.
7.
NSPI proposes to amortize the $27 million associated with the 1995 severance
separation and early retirement plan over a five year period. The Board approves
the deferral but directs that the deferral be over a three year period.
8.
In this decision the Board has made adjustments in the revenue requirement such
that the proposed cost recovery ratios of the Small General, General and Small
Industrial classes have been reduced. In future rate filings, should NSPI propose
rates such that the cost recovery ratio exceeds 1.05, the Board will revise the
proposed revenue requirement accordingly.
9.
By Order dated March 8, 1994, the Board directed NSPI to undertake an
investigation of rate designs that are consistent with cost reductions under the
Integrated Resource Plan. Rate alignment relates to the concept that future costs
should be reflected in the rate design so as to allow customers to make proper
investment decisions and that rates should be based on costs to the extent that
increased efficiency in the total utility system which will reduce costs to all
customers.
It is the Board’s opinion that rates should never be set below short-run marginal
costs. Long-run marginal costs should be used to temper the wide fluctuations that
can exist in the year-to-year levels of short run marginal costs.
10.
The Board has determined that it is appropriate to combine the Large Industrial and
the Interruptible Customer into a single class and offer interruptible customers a
demand credit. Limits of interruptibility will also be established. The Board
considers that transmission costs of $2.8 million dollars are properly attributed to the
class. Eligibility for the Large Industrial rate will be reduced to 2000 kVA as
requested by NSPI. Because there is a disproportionate impact on the low load
factor customer, the demand discount for certain customers will be phased in over
five years.
11.
The Board approves certain amendments to the regulations in regard to
underground electric wiring, billing adjustments, settlement agreements, deposits
and charges. The Board approves a revised pole attachment charge for cable
Document : 78377
11
television of $9.60 per pole per year.
(NSPI Decision, P-868, pp.96-102)
[14]
As noted above, in the six years since the last hearing, NSPI has become a
subsidiary of Emera, and other Emera subsidiaries are numerous and active in energy-related
business endeavours. A regulatory regime for natural gas distribution has been established in Nova
Scotia although at the present time natural gas is available only to a limited number of users from
laterals connecting to the Maritimes and Northeast Pipeline. The Province has adopted an energy
strategy which has the potential to impact NSPI’s monopoly status over time.
[15]
While capital expenditures by NSPI in excess of $25,000 require Board
approval, the Act was amended in 1992 to provide for a consolidated Annual Capital Expenditure
Plan (ACE Plan). Each year, the Board considers NSPI’s total proposed capital expenditures on
planned and routine items under $1,000,000 in one consolidated filing. Items over $1,000,000, or
those classified as Unknown and Unforeseen and not included in the ACE plan, are reviewed on an
individual basis by the Board.
[16]
NSPI’s operating expenses have not been subject to Board review since 1996
as its earnings on common equity did not materially exceed the 11.00% cap approved by the Board.
The setting of a range of permissible earnings on common equity (10.5% - 11.00% in the 1996
decision) is somewhat similar to performance-based regulation which is generally considered to be a
more light-handed form of regulation than traditional cost of service regulation. It gives the utility an
incentive to effect cost savings in order to earn above the return approved for rate making purposes
(10.75% in 1996) and enables it to avoid frequent rate reviews as long as it maintains its earnings
within the permitted range.
Document : 78377
12
[17]
In its current application NSPI has chosen 2002 as its test year. It estimates
substantially higher expenses in 2002 over 2001. The increase is principally caused by higher fuel
costs (particularly coal) including associated increased foreign exchange costs. Unlike its experience
in 2001, NSPI does not foresee the possibility of offsetting coal price increases with profits from
natural gas sales. As summarized in the direct evidence of Dr. John Stutz, a principal of the Tellus
Institute and consultant to Board Counsel, the requested increase in rates is due primarily to an
increase of $35.5 million in coal costs and a decrease in natural gas sale revenues of $32 million. In
addition, NSPI considers that the earnings range on common equity approved by the Board in 1996 is
no longer adequate. Other issues cited by NSPI as factors in its decision to apply for a rate increase
are environmental concerns, increased business risk and competition, and NSPI’s future income tax
liabilities. NSPI has concluded that the existing rates no longer permit it to both cover its operating
costs and earn an acceptable return. In its original application, it requested approval of rates which,
if effective on January 1, 2002, would result in a revenue increase of $67.1 million.
[18]
In using a test year ending December 31, 2002, NSPI necessarily used forecast
data for the full test period. In its initial filing, NSPI advised that:
Because of the volatility of certain costs for the test year, NSPI will provide an updated 2002
forecast by January 28, 2002, even if no change to the revenue requirement is warranted.
(Exhibit N-1, p.16)
[19]
NSPI did, in fact, file an updated financial forecast for 2002 on January 28,
2002. It contained a number of adjustments to revenues and expenses, the net effect of which was
that no change in revenue requirement was indicated. Much time was spent at the hearing debating
the implications of the various adjustment items included in the January 28, 2002 revision.
[20]
Document : 78377
The Board has considered what use it should make of the information
13
contained in the January 28, 2002 letter and in the tables filed in conjunction with the letter. For
many years the Board has permitted applicants seeking rate increases to use a forward-looking test
year using projected data for that purpose. On occasion, applicants may have used a combination of
actual and projected data for test year purposes. In the present instance, where the January 28, 2002
data makes no difference to the Company’s ultimate revenue requirement and only one month of
actual data is included in any event, and for reasons which are set out in Section 4 of this decision,
the Board is of the opinion that it would be appropriate for it to disregard the January 28, 2002 filing
and to use projected data only for the full 2002 test year.
[21]
In utility regulation, there are generally accepted principles which govern the
rate-making exercise. The object of rate-making under a cost-of-service-based model is that, to the
extent reasonably possible, rates should reflect the cost to the utility of providing electric service to
each distinct customer class. In regulating NSPI, the Board is guided by these generally accepted
principles as well as by case law.
[22]
A widely-accepted publication written by Dr. James Bonbright entitled
Principles of Public Utility Rates, sets out the following guidelines for determining appropriate
rates:
CRITERIA OF A SOUND RATE STRUCTURE
1.
2.
3.
4.
5.
6.
7.
The related, "practical" attributes of simplicity, understandability, public acceptability, and
feasibility of application.
Freedom from controversies as to proper interpretation.
Effectiveness in yielding total revenue requirements under the fair-return standard.
Revenue stability from year to year.
Stability of the rates themselves, with a minimum of unexpected changes seriously
adverse to existing customers. (Compare "The best tax is an old tax.")
Fairness of the specific rates in the apportionment of total costs of service among
the different consumers.
Avoidance of "undue discrimination" in rate relationships.
Document : 78377
14
8.
Efficiency of the rate classes and rate blocks in discouraging wasteful use of service
while promoting all justified types and amounts of use:
(a)
in the control of the total amounts of service supplied by the company;
(b)
in the control of the relative uses of alternative types of service (onpeak versus off-peak electricity, Pullman travel versus coach travel,
single-party telephone service versus service from a multi-party
line, etc.).
(Exhibit N-92)
(James Bonbright, Principles of Public Utility
Rates, Columbia University Press, 1961, p. 291)
[23]
These principles are well established and form the background against which
the current application must be assessed.
Document : 78377
15
3.0
TEST YEAR REVENUE AND LOAD FORECAST
3.1
Load Forecast and Revenues
3.1.1 Submission - NSPI
[24]
NSPI’s estimate of revenue from the sale of electricity is based on its forecast
of electric energy and peak demand requirements to be met in the forecast period. Estimates are
developed using econometric and end-use models and large customer energy surveys. In its load
forecast, NSPI summarizes the resulting sales, losses and total energy requirement for the years
1995-2002, including the energy required by the six municipal electric utilities.
[25]
NSPI filed a load forecast with its original application as follows:
Table 4.1
LOAD Forecast (GWh) - 1996-2000 Actual and 2001-2002 Forecast
Year
Residential
GWh
%
Commercial
GWh
%
2686
Industrial
GWh
%
2862
Exports
GWh
%
1
Losses
Requirement
GWh
GWh
656
9675
%
1995
3470
1996
3568
2.8
2714
1.0
2774
-3.1
73
NA
696
9825
1.6
1997
3598
0.8
2720
0.2
2863
3.2
319
337.3
803
10303
4.9
1998
3467
-3.6
2688
-1.2
3442
20.2
160
-49.8
749
10506
2.0
1999
3559
2.6
2752
2.4
3848
11.8
197
22.6
723
11079
5.4
2000
3697
3.9
2837
3.1
3931
2.1
181
-8.1
786
11432
3.2
2001
3826
3.5
2881
1.6
3907
-0.6
297
64.1
802
11713
2.5
2002
3904
2.0
2982
3.5
4008
2.6
295
-0.7
819
12008
2.5
(Exhibit N-1, Table 4.1)
[26]
Based on these forecasts, NSPI developed its revenue estimate for 2002 as
follows:
Nova Scotia
Power
Inc.Table
3.6
Detail
of Electric
Revenue
Years
December
31st
MillionsEnded
of Dollars
Document : 78377
16
RESIDENTIAL
GENERAL
Small
General
General
Demand
Large General
(1)
(2)
Actual
2000
Forecast
2001
(3)
Present
Rates
Forecast
2002
(4)
Proposed
Rates
Test
Year
Forecast
2002
(5)
Proposed
Rates
(May
1st)
Forecast
2002
$351.6
12.4
192.4
22.6
$361.6
8.7
200.1
22.8
$367.6
8.9
206.0
23.2
$400.4
9.7
216.4
27.0
$387.5
9.4
212.6
25.8
227.4
231.7
238.1
253.0
247.9
16.6
32.8
81.8
14.5
6.1
43.4
2.1-
16.3
33.7
72.0
17.8
6.5
49.0
5.0-
16.9
34.9
71.8
17.8
6.7
54.7
9.1-
18.5
39.3
83.6
18.5
6.7
57.2
9.4-
18.0
37.9
79.7
18.5
6.7
57.2
9.4-
197.3
200.4
212.0
233.2
227.5
10.4
17.7
1.7
10.7
17.2
(1.1)
11.1
18.5-
12.9
18.5-
12.2
18.5
0
29.8
26.9
29.6
31.4
30.8
806.1
820.5
847.3
918.0
893.6
EXPORT
CONTRACT
SALES
OTHER EXPORT
SALES
7.2-
1.7
11.1
13.5
2.9
13.5
2.9
13.5
2.9
TOTAL ELECTRIC REVENUE
$813.3
$833.3
$863.7
$934.3
$910.0
Total General
INDUSTRIAL
Small
Industrial
Medium
Industrial
Large
Industrial
Generation
Replacement
&
Load
Following
Mersey
Industrial
Expansion
Surplus
Power
Interruptible
Real Time
Pricing
Total Industrial
OTHER
Municipal
Unmetered
Other Electric
Total Other
TOTAL
IN-PROVINCE
ELECTRIC
REVENUE
(Exhibit N-1, Table 3.6)
[27]
It is of interest that, in recent years, gas sales have also formed part of NSPI’s
revenues. However, NSPI states that:
Natural gas prices have declined markedly from their levels in 2000 and 2001. During that
period NSPI has been able to sell gas which it acquires under firm contracts while burning
lower-cost oil, thus reducing the net cost of its fuel. This effect was sufficient to avoid the
necessity of rate increases in 2000 and 2001. This option is not expected to be available in
2002. Ironically, this decline in the price of gas has resulted in an increase in the net cost of
fuel to NSPI.
(Exhibit N-1, pp.37-38)
[28]
It should also be noted that NSPI receives revenue as a result of export sales of
electricity.
3.1.2 Submissions - Intervenors
[29]
While NSPI’s load forecast methodology was not disputed by the intervenors,
there were a number of issues relating to the forecast itself which were contested.
[30]
Document : 78377
One major issue is that in its January 28, 2002 update NSPI adjusted its load
17
data based on a warmer than normal January in 2002. Intervenors believe that adjusting test year
data by introducing “actual” temperature information erodes the value of using forecasted test year
data.
3.1.3 Findings
[31]
While not a significant issue at this hearing, the Board is cognizant of the fact
that the electricity load forecast forms the foundation upon which the application is based. The
Board notes that a large number of information requests were issued by both Board Staff and some
of the intervenors for evidence supporting NSPI’s load forecast. The Board is of the opinion that this
supporting data should have been filed as part of the original application. As part of any future rate
applications, the Board directs NSPI to file all supporting evidence pertaining to the development of
its energy and peak demand forecasts. This evidence should include discussions of all econometric
models considered and either rejected or chosen.
[32]
The Board has reviewed NSPI’s electricity load forecast and supporting data
provided in response to information requests and concludes that the load forecast has been developed
in a reasonable manner. The Board’s comments on the proposed January adjustment are noted in
Section 4.3 of this decision.
Document : 78377
18
4.0
TEST YEAR EXPENSES
4.1
Fuel Costs
4.1.1 Submission - NSPI
[33]
In its application, NSPI stated that:
Approximately 90% of NSPI’s generated energy is produced from fuel-burning thermal plants.
In 2002 fuel costs will account for more than 50% of NSPI’s operating costs, and accordingly
changes in the delivered cost of fuel have a significant impact on NSPI’s total costs.
NSPI has avoided any general price increases since 1996 through a series of prudent
management initiatives. However, with the abrupt changes in our fuel markets in 2001, fuel
costs will increase dramatically in 2002, beyond the range which can be contained without
price increases.
(Ex. N-1, p.37)
[34]
NSPI witnesses reiterated at the hearing that fuel costs are the primary driver
of the application. NSPI’s ability to generate electricity is heavily dependent on solid fuel - i.e., coal
and petroleum coke (pet coke). This is illustrated by the following exchange between Counsel for
SEB and Christopher Huskilson, Chief Operating Officer of NSPI:
Q.
A.
And so it would be fair to characterize the application for a general increase in rates,
the one that we're dealing with right now, as driven -- to be driven primarily or maybe
even exclusively by the increase in fuel costs, including foreign exchange?
Yes, certainly those are the major components. As we've stated before, because of
the risk that the utility faces and the environment that both the bond rating agencies
and investors in general see, it's very important that the capital structure also be
addressed in this hearing and we believe that that's an urgent issue for the company,
but certainly fuel and foreign exchange is the primary driver to our costs for this year.
(Transcript, April 22/02, p.45-46)
[35]
NSPI is heavily dependent on coal for the generation of electricity as,
according to NSPI witnesses, approximately 80% of its generation is coal-fired.
[36]
Consequently, purchasing coal is the single largest expense for NSPI,
amounting to approximately $200 million in 2001. NSPI submits that the announced closure of the
Cape Breton coal mines in early 2001 by the Cape Breton Development Corporation (CBDC, Devco)
Document : 78377
19
forced NSPI to purchase coal in the international market at a time when coal prices were high. NSPI
tendered for coal supply in the spring and fall of 2001 when market circumstances (which have been
described by various witnesses as the “perfect storm” scenario) drove coal prices to very high levels.
According to NSPI, this sudden spike in coal prices was outside its control and, coupled with a low
Canadian dollar relative to the US dollar, resulted in cost increases which were beyond the ability of
the company to absorb. NSPI projects that profits from natural gas sales (natural gas being available
to NSPI under the Shell contract) will decline steeply in the test year and, as a result, NSPI will not
have this revenue to mitigate the increased cost of coal.
[37]
In 2001, NSPI was also in the process of altering its coal purchasing function.
NSPI entered into an arrangement with Emera Energy Inc., (Emera Energy) under which Emera
Energy acted as NSPI’s fuel acquisition agent. This arrangement, which is discussed more fully in
Section 6.2 of this decision, did not, according to NSPI, change the company’s basic coal
procurement strategy during this period. NSPI’s coal procurement strategy, as outlined in its
application, consisted of purchasing coal in the spring and fall for the following budget year. When
questioned by Counsel for Annapolis concerning NSPI’s strategy compared to that of other U.S.
utilities, Jeff Watkins, of Hill & Associates, NSPI’s coal expert, stated that:
A.
... I was talking there about domestic U.S. utilities that predominantly do not have
access to the seaborne market. I don't think it's a fair comparison to compare NSPI
to the domestic U.S. utilities. I was speaking about U.S. practices, not seaborne
practices. So I would suggest that NSPI does that by staying short in the market,
buying twice a year, therefore never getting too out of sync with the market, very
similar to what these U.S. utilities do with their short-term procurement strategy with
market price adjustments. So from a standpoint of staying close to the market,
they're very comparable. From a standpoint of the markets that they play in, they're
not comparable.
(Transcript, May 2/02, pp.1558-1559)
[38]
Document : 78377
NSPI witnesses, particularly Mr. Huskilson and James Taylor, Vice President
20
of Power and Production for NSPI, gave extensive evidence justifying the reasonableness and
prudence of NSPI’s coal procurement practices. Much of this testimony was given during in camera
sessions.
[39]
In its non-confidential post-hearing brief, NSPI defended its coal purchasing
strategy, arguing that:
Until the spring of 2001 NSPI was subject to a “requirements” coal supply contract with
CBDC. The history of that contract is dealt with elsewhere in this argument, but for the
purposes of this discussion it is important to understand that CBDC vigorously asserted its
right to import coal to supply NSPI’s needs, and an arbitrator had accepted this position
(although NSPI considered this finding to be obiter dicta). NSPI was therefore not in a
position
to
bind
itself
to
long-term
supply
contracts
with
others.
(NSPI, Post-Hearing Brief, p.8)
NSPI’s coal procurement strategy is designed for the market in which it participates. It has
adopted a purchase strategy under which it goes to market twice a year, and purchases coal
on contracts for delivery about a year in advance. Actual contracts are for delivery 8 to 18
months after contract date. Mr. Watkins explained that long-term (or even medium-term)
fixed price contracts are not readily available in the international seaborne market, and that if
such contracts are available at all, there would be a significant price premium or non-market
escalator. He indicated that the market indices are immature and not completely reliable
because there is no mandatory and reliable reporting of international sales data. He was of
the opinion that the program of twice-yearly marketing, with contracts for delivery between 8
and 18 months forward, was sound. By staying close to the market it minimized cost in the
long run, and minimized the risk that coal costs would ever be significantly above market
price.
(NSPI, Post-Hearing Brief, pp.10-11)
[40]
NSPI also vigorously disputes the allegations by the intervenors that its coal
purchasing strategy was imprudent. NSPI asserts that:
The intervenors’ consultants, Ms. Medine and Ms. Hennings, argue that, beginning in 1997,
NSPI should have signed long-term purchase agreements for approximately one third or one
quarter of its annual coal requirement, renewing expiring contracts as they mature. They
describe this as a “portfolio strategy”. They assert that if this had been done, the impact of
the “perfect storm” of 2001 would have been mitigated. Ms. Medine’s recommended strategy
assumed contractual options would have permitted the company to acquire coal at prior
years costs, thus further reducing the cost in the test year.
...
If the intervenors’ purchase strategies were applied consistently, and even assuming that
long term fixed price contracts were available without premium (and they are not), they lead
to exactly the same cost over time. If the 2001 prices are considered a short-term aberration,
these strategies would have NSPI paying them for one quarter of its fuel for four years - the
same amount. Ms. Hennings insisted that she would vary her purchase pattern, buying
heavily when prices are going up and buying short when prices are falling. This hope of
Document : 78377
21
consistently beating the market is the strategy of a speculator, not a prudent utility. Such a
strategy can result in prices being seriously out of line with market prices. Further, at the very
time that these consultants now suggest NSPI should have been buying long term, all
analysts, including Ms. Medine’s firm, were forecasting prices to be either flat or declining.
...
NSPI submits that the purchasing strategies of the intervenors’ consultants are unsound.
They lead to higher costs in the long term, and in most cases in the short term. Even if they
are accepted as “a “ prudent approach, they cannot be said to be uniquely prudent such that
any inconsistent strategy is to be penalized as “imprudent".
It must be remembered that NSPI was operating in a very challenging environment. It was
bound by a long term “requirements” contract with CBDC. It was in negotiations with CBDC
for the renewal of the price and volume terms of that contract, and with proponents who were
considering the takeover of the CBDC operations. Finally, it amended its agreement with
CBDC, only to learn that the mines were to close. And as this was happening, economic
forces converged in international coal markets causing prices to behave in a way that they
had never done before, and which was not foreseen by any of the analysts. This was
described by various witnesses, including Dr. Stutz, as the “perfect storm”. The intervenors
challenge the NSPI purchasing behavior in this challenging situation based on their strategies
which they hone with perfect hindsight - the perfect strategies for the perfect storm.
NSPI submits that the standard of “imprudence” must be a high one in order to justify
penalizing a utility. It must consist of a course of conduct which cannot be supported by a
body of reasonable opinion. In this case the practice of NSPI is not only supported, it is
actively recommended by Mr. Watkins, who has experience and expertise in this market. Dr.
Stutz fairly characterized the approach as a prudent one. It would be unfair and
unreasonable to penalize the utility because intervenors, with the benefit of perfect hindsight,
can concoct a scenario under which costs might have been reduced.
(NSPI, Post-Hearing Brief, pp.11-14)
4.1.2 Submissions - Intervenors
[41]
Two intervenors, SEB and Annapolis, retained experts to review NSPI’s fuel
costs. Sharon Hennings, a consultant with Brubaker and Associates, a U.S. based energy consulting
firm, and Emily Medine, Principal/Consultant with Energy Ventures Analysis, Inc., of Pittsburgh,
Pennsylvania, gave evidence for SEB and Annapolis respectively. Both experts stated that NSPI’s
coal procurement strategy was imprudent and each suggested that the Board significantly reduce
NSPI’s requested revenue requirement for fuel purchasing.
[42]
Document : 78377
Ms. Hennings, in her evidence (Exhibit N-30), asserted that NSPI was
22
imprudent by relying too heavily on the spot market for coal. As a result, NSPI had no protection, by
way of term contracts, when coal prices spiked dramatically. Ms. Hennings also took issue with
NSPI’s estimate of ground transportation costs for coal and for pet coke. She indicated in her direct
evidence, and under cross-examination, that these costs were excessive and not representative of a
valid forecast of reasonable costs, stating that:
The 2002 estimated cost of ground transportation in Nova Scotia is based on 2001 prices
charged by CBDC and other suppliers. NSPI represents these historical prices to be fair
market value prices and representative of the price that will be charged in the test year for the
transportation.
The ground transportation costs should be reduced to a reasonable level. The prices are
very high in comparison with other transportation costs. The cost to transport coal and
petroleum coke from Nova Scotia ports to NSPI’s generating plants is almost double the cost
to load and ship the coal from Baltimore. It is almost equivalent to the price of loading and
shipping coal from Columbia to Nova Scotia.
The price forecast being used for Nova Scotia ground transportation is not a valid forecast of
reasonable costs for the routes to the Lingan and Point Aconi plants.
(Exhibit N-30, p.6)
[43]
Ms. Hennings further suggested that downward adjustments should be made to
NSPI’s revenue requirement to account for forecasted coal purchases from distressed vessels,
increased pet coke usage, and increased hydro generation.
[44]
Ms. Medine also asserted that, in her view, NSPI was imprudent in its coal
procurement strategy. She noted in her direct evidence that:
Even though NSPI has reduced its forecast of 2002 solid fuel costs, these prices are
considerably higher than the solid fuel costs for earlier years and higher than they should be
in future years. Further, NSPI bears the responsibility for causing some of the additional cost
by not hedging import coal purchases in 1999 when the Phalen mine closed; by not hedging
coal purchases in 2000 when there were indications that the coal market was tightening and
the future of CBDC became very tenuous; and by not being more aggressive in 2001 when it
was clear that the market was tight and decisions needed to be made more quickly. Simply
put, NSPI’s stated costs for 2002 are inappropriate costs to be used for a test year.
(Exhibit N-39, pp.13-14)
[45]
Annapolis, in its closing submission, argues that:
As this is the first rate case in which NSPI has not secured all of its solid fuel requirements
from CBDC, this case is the first opportunity for the Board to inquire into the reasonableness
and the prudency of NSPI’s fuel procurement policy and fuel expenditures. The fact that
Document : 78377
23
NSPI has committed, by purchase order, to a certain percentage of import coal for the test
year, at a certain price, is not determinative of whether or not the Board should allow the
expenses. The Board’s regulatory duty is to scrutinize and disallow improper expenditures if
they are not necessary and reasonable.
The disallowance of improper expenditures which have been made imposes the burden on
investors in the form of lower profits and creates an incentive on the managers of the utility to
act appropriately, efficiently and with sophistication.
...
This coal procurement “strategy” is nothing more than a convenient process. No forwardlooking analysis was done at the time of its implementation; in reality NSPI admitted it “landed
on this strategy” (Transcript, Taylor, p. 891).
·
The “strategy” was developed without formal assistance from non-NSPI employees
or industry experts (Response to Grant IR-5; Transcript, Huskilson, p.525).
·
While Jeff Watkins of Hill & Associates was on retainer to provide forecasting
reports, he was not consulted in the development of the strategy (Transcript,
Huskilson, p.874).
·
There are no formal reports from third parties vetting the strategy (Transcript,
Huskilson, p.1095)
·
Despite being aware that it is common practice in the U.S. for fossil-fuel based
utilities to consult with the regulator on procurement strategy, NSPI did not seek
input from this Board (Transcript, Huskilson, p.1096).
(Annapolis, Closing Submission, pp.20-22)
[46]
In his direct evidence, Dr. Stutz did not suggest that NSPI’s coal purchasing
was imprudent but did recommend that NSPI’s fuel costs for the test year be reduced by 10%. Dr.
Stutz’s objection to NSPI’s estimated fuel costs is based on his view that the costs are anomalous
and are not representative of those that are likely to be incurred over the period in which the rates are
to be in effect and, therefore, should not be used for test year purposes. He differentiated this
suggestion from the recommendations of Ms. Medine and Ms. Hennings in response to questions
from the Board, indicating that:.
. . . They were really -- if I can just elaborate slightly, they were really suggesting three
different things. One thing was a very big adjustment, 40 million dollars I think was a figure
that appeared. This would be appropriate if you felt that the company's coal procurement
was imprudent. That's an open issue. A second thing that was suggested is that there were
various shortcomings in the company's justification of its costs. And you could make
adjustments of that sort, smaller amounts, generally in the 2 or 3 or 4 million dollar range. A
third thing that was suggested by Ms. Medine was that, in fact, even if you believe the
company acted in a generally prudent fashion, that because, as far as she could determine,
there was no systematic procedure for putting the bid data and the transport data together in
a consistent fashion, you simply couldn't determine whether they had succeeded in doing
what they set out to do, which was to minimize their costs. And I haven't heard the response
to that, but it did seem like a reasonable point. Now, what I've done is separate from all of
those I've simply said, even if you thought the approach was generally prudent, you didn't
agree with the company -- you didn't agree with the other intervenors that there were these
Document : 78377
24
other adjustments, and you thought somehow or other they'd gotten it right, even if you
accepted all of those points, and therefore rejected everything everyone else said, you still
might want to make my adjustment because you feel that the coal costs are unrepresentative
of what they'll face in 2003. Now, am I being generous to them as to what they'll face in
2003? I don't think so based on the evidence we've heard. Mr. Watkins was very clear that
the coal prices are not dropping back to their historic levels very rapidly, and so something
which brings you down from the current peak but doesn't, perhaps, take you all the way back
to where we've been historically, seems to me consistent. If they dropped faster then yes, I
would be overly generous.
(Transcript, June 4/02, pp.3980-3982)
[47]
Dr. Stutz also indicated that while he did not personally believe NSPI’s coal
procurement strategy was imprudent he agreed with Ms. Medine that their “strategy” was not
adequately implemented and, therefore, NSPI was unable to demonstrate that coal was obtained at
the lowest possible price.
[48]
A number of other intervenors (the Province, ECANS, HRM, MEUNSC and
TrentonWorks) support the proposition that NSPI’s estimate of coal prices for the test year were not
sufficiently representative of “normal” circumstances and should be reduced.
4.1.3 Findings
[49]
The Board has carefully considered all the evidence on the issue of fuel costs
including the evidence given during the in camera portion of the proceedings relating to coal costs
and purchasing.
[50]
In particular, the Board has considered the helpful evidence of Mr. Watkins,
Ms. Medine, Ms. Hennings and Dr. Stutz on the issue of imprudence and that of Dr. Alan Rosenberg,
of Brubaker and Associates, an expert retained by SEB, respecting the concept of “used and useful”
for the purpose of reviewing utility expenditures.
[51]
Document : 78377
After evaluating all the evidence concerning NSPI’s coal procurement
25
strategy, the Board finds that NSPI’s actions do not go so far as to constitute imprudence.
[52]
Although NSPI had contracted on the international market for some part of its
coal requirement in the late 1990’s, the bulk of its coal was supplied by CBDC pursuant to a longterm supply agreement dating back to 1978. NSPI’s coal supply situation changed drastically
between 1999 and 2001 with the decline in production at CBDC’s mines followed by the announced
closure of all of CBDC’s coal mines in the spring of 2001. Accordingly, NSPI has not had a lengthy
history of involvement in the international coal markets. The Board surmises that its learning curve
has been a steep one. While not imprudent, the Board considers that NSPI’s coal procurement
strategy has been lacking in sophistication. However, the Board is not prepared to find that NSPI’s
strategy of buying coal pursuant to short-term contracts on the international markets was
fundamentally flawed. The Board agrees with Ms. Medine, however, that stringent procedures
should be in place to govern coal procurement (i.e., practices and procedures setting out approved
methods for issuing bids for coal supply) as coal acquisition accounts for a huge portion of NSPI’s
total expenses. The records show considerable sloppiness on NSPI’s part in terms of its purchasing
practices, including the interchangeable and confusing use of Emera and NSPI as the contracting
party for coal. The Board will address this matter further in Section 6.2 of the decision.
[53]
Notwithstanding that the Board does not consider that the evidence supports a
finding of imprudence on the part of NSPI, the Board does believe that NSPI’s practices in this area
are sufficiently lax so as to undermine NSPI’s ability to ensure, and demonstrate to the Board, that
coal was obtained at the lowest possible price. NSPI’s argument that it had an “evolving”
relationship with Emera Energy does not justify the confusing document trail in terms of who was
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26
actually contracting for coal. In the Board’s view, there is too much at stake and, consequently, too
significant a potential impact on ratepayers, to accept anything less than the best possible business
practice.
[54]
The Board agrees with the intervenors that the fuel costs for the 2002 test year
are based on higher than normal coal costs. The expert witnesses all appear to agree that coal prices
have begun to decline and, while costs may remain relatively high, the abnormally high prices seen
during 2001 have dropped. Under these circumstances, the Board finds that the test year coal costs
used by NSPI are not suitable for rate-making purposes. In this case, NSPI applied for a rate increase
at the end of 2001 projecting coal costs which were higher than most experts anticipate to be the case
during 2002-03. NSPI is not entitled to recover past expenses caused by high coal prices. It is an
accepted principle, which the Board endorses, that rate-making should be prospective and not
retroactive. NSPI lost the opportunity to mitigate the high cost of coal for a good part of 2002 when
it waited to file an application until December of 2001. Accordingly, the Board finds that the cost of
fuel for the test year must be reduced in order to ensure that the costs are more representative of the
period during which the rates will be in place (i.e., late 2002 and into 2003).
[55]
As noted above, since the Board finds that NSPI’s projected fuel costs for the
test year are unusually high, it believes the fuel costs should be “normalized” by reducing the
amount estimated by NSPI. In determining an appropriate reduction the Board notes that Dr. Stutz’s
recommended 10% reduction in imported coal costs moves the price of coal closer to the historic
mean price as shown in Exhibit N-152, JS-5, while still acknowledging the increase in coal prices
which did occur. The Board finds that to normalize these coal costs on a go-forward basis for the
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27
balance of this year and into 2003, a 10% reduction in the test year costs for imported coal is
reasonable and balanced. The Board does note that, according to the information in the January 28,
2002 update, NSPI’s actual imported coal costs were less than those originally estimated. In the
Board’s view, a reasonable reduction in test year costs is the 10% suggested by Dr. Stutz. This will
result in a reduction of approximately $19.7 million in the test year revenue requirement.
4.2
CBDC Buyout
4.2.1 Submission - NSPI
[56]
NSPI has obtained coal for many years from CBDC. In April 2001, NSPI
entered into an "amending agreement" with CBDC to amend certain terms of the long-term coal
supply contract which had been in effect between the two parties since 1978. The amending
agreement was effective as of January 1, 2000. Among other things, the amending agreement
provided that the long-term coal purchase contract would terminate in 2005 rather than in 2010.
Pursuant to the amending agreement, NSPI incurred a $12.4 million buy-out fee, plus interest costs
of $1 million, in connection with the early termination of the long-term coal contract. NSPI proposes
that these costs be amortized over a five-year period beginning in 2002 with the amount to be
amortized in 2002 being $2.7 million.
[57]
NSPI described the long-term contract between it and CBDC as having the
following provisions among others:
... The agreement contained no guarantees of quality or quantity to be delivered, but gave
CBDC the right to supply up to the entire requirement of NSPI. CBDC took the position that it
had the right to import coal to meet NSPI’s requirements, and an arbitrator had accepted that
position. CBDC always vigorously asserted this right, although it did not at any time seek to
actually import coal on behalf of NSPI. The coal price was renegotiated every five years, and
Document : 78377
28
was subject to arbitration in accordance with the "four factor formula" in the agreement.
These factors included the (high) cost of production in the CBDC mines, and the cost of
supply of alternate energy sources.
(NSPI, Post-Hearing Brief, p. 14)
[58]
Again, much of the information pertaining to the coal supply contract was
provided on a confidential basis. However, a useful summary of the issue is available in the nonconfidential versions of post-hearing submissions. As noted above, NSPI asserts that it was subject
to a “requirements” coal supply contract with CBDC which commenced in 1978. NSPI explained
that the relationship was further complicated by CBDC’s claim that it had the right to import coal to
supply NSPI if necessary.
[59]
NSPI stated that:
The history of, and problems with, the CBDC contract are well known to the Board. CBDC
coal was of relatively poor quality. It was high in sulphur, and this became more problematic
as the environmental emissions limits, which were not an issue when the contract was
originally signed, were approached. The agreement contained no specifications for sulphur
content, and CBDC refused to agree to any such stipulations. As a partial response, NSPI
built the fluidized-bed combustor unit at Point Aconi, which could burn a high-sulphur fuel with
minimal emissions. Unfortunately, between the time of design and commissioning of the
Point Aconi generator, the quality of coal from the Prince Mine deteriorated (in that its level of
chlorine content increased) to the point that it could not be consumed in the Point Aconi
boiler.
Finally, supplies from CBDC were unreliable. Problems with geology (roof falls and floods)
and with organized labour led to supply interruptions from time to time. However,
investigations by NSPI and by proponents considering the purchase of the mines confirmed
that the mine could continue to produce at a rate of about 1,000,000 tonnes per year.
Throughout the life of the agreement, CBDC took the position that it had the right to import to
supply NSPI’s requirements, thereby continuing to employ some of their employees and to
use their surface assets (even if the mines were to close).
The relationship was a difficult one throughout its life, characterized by acrimonious
negotiations, action by unionized CBDC employees, litigation and arbitration.
(NSPI, Post-Hearing Brief, pp.14-15)
[60]
NSPI argues that it is reasonable to include the annualized cost of the buy-out
in the test year expenses for 2002 (and beyond) since ratepayers got the benefit of a retroactively
reduced coal cost which facilitated NSPI’s ability to continue to defer an application for a rate
increase until late 2001.
Document : 78377
29
[61]
Under cross-examination by Board Counsel, Mr. Huskilson elaborated on the
benefit to ratepayers of NSPI’s decision to terminate the contract:
Q.
A.
Q.
A.
Q.
A.
Q.
A.
I want to turn now to the Devco buyout. I realize it's fashionable now to refer to it as
CBDC, but it's been Devco for long enough in my mind anyway, that I'll refer to it as
such. It's established on the record that the agreement for the buyout of the Devco
agreement was made in April of 2001. Correct?
Yes, that's correct.
And as a result of that buyout and the renegotiation, the amending agreement, the
coal price that the company paid -- that is, NSPI paid -- was reduced? That's
correct? Over the previous level, over the contract ending 1999.
Yes, that's correct. At the end of 1999, we would have been paying about two
dollars and sixty-two cents a million BTU.
And those lower prices that were negotiated in April of 2001 resulted in retroactive
reductions in the costs associated with your coal purchases in 2000 and the first four
months of 2001. Correct?
Certainly they had retroactive effect, but certainly at the time, in the year 2000, we
wouldn't have known what we were paying. We would have made some
assumptions about what that was, but we wouldn't have known what we are paying
at that time. That's right.
If I interpret the response to Grant IR -- I guess it is 15.6 -- the savings in 2000 with
respect to the reduced coal cost was 14.3 million?
I think the way I'd characterize that is that the value created against what it otherwise
might have been in the year 2000 would have been that fourteen million dollars
($14,000,000). It wasn't actually a savings in that year, though, because of the fact
that we didn't know it until after that year ended up closing. So it's -- what the table
was doing was trying to represent the value created, but in fact that value was
created later rather than -- not in that year.
Q.
A.
And additional savings in 2001?
Again, that would be the value that's created from the analysis that we would have
done. I guess what I'd say is it's hard to characterize it as a savings because we
didn't know what otherwise it would have been, but it certainly is the value against
what it otherwise could have been. And you have to remember that what we were
testing it against was an arbitration that might occur which we believed would
probably occur in 2002 and which we believed would also probably set prices at or
near the higher end of the range as opposed to the lower end of the range. Going
into an arbitration where the two sixty-two was the starting point, our expectation
would be that we would have seen a higher price than two sixty-two rather than a
lower price.
Q.
Is it fair to say that the value you speak of was created when the agreement was
signed?
Yes, I would say that that would be fair to say.
A.
Q.
And to date, has the renegotiation of the Devco contract resulted in any change in
the price of electricity to NSPI customers?
Document : 78377
30
A.
I think what it did was it allowed us to not -- so I think if you looked at it another way,
you could have said that in the summer of 1999, we were facing a renegotiation with
CBDC for the five-year period. Had we believed at that time that in fact we were not
going to be in any way successful in anything other than an arbitration -- so in other
words, if we weren't working hard to ensure that we could reduce the cost for the
year 2000, we would have come to the Board then and said, "We expect coal prices
to be, I don't know, three dollars ($3) a million BTU or three dollars and fifty cents
($3.50) a million BTU and we need a rate increase for the year 2000." And so that
would have been the approach that we might have taken. So that I would say that in
the year 2000, the fact that we took the approach we took with CBDC saved a rate
increase in the year 2000 that we could have applied for in late 1999 had we taken a
less aggressive approach with the CBDC renegotiation. So that, yes, I would say
absolutely this has deferred a price increase to customers in the year 2000 that
would have otherwise been brought forward had we taken a different approach. But
it was the company's approach to that negotiation and it was the aggressive stance
that we took with CBDC that allowed us to ensure that we didn't have to come to the
Board and ask for a price increase for the year 2000. So that's a savings that the
customer has already seen.
Q.
But you'll agree with me, Mr. Huskilson, that customer[s] had no assurance of
receiving that saving, nor did NSPI until April 2001.
Well, the fact that we didn't come before the Board meant that the customer[s] did
receive theirs. Absolutely.
A.
Q.
A.
But the bottom line is, though, that you didn't know what the outcome of the
negotiations were until April 2001. Correct?
But we could have settled it in -- we could have settled it easily in the fall of 1999.
Without any doubt, had we just simply agreed to a high price, we could have settled
it, and that would have meant a price increase to customers.
Q.
A.
But the bottom line is the negotiation concluded in April of 2001. Correct?
Absolutely correct.
(Transcript, April 29/02, pp. 1097-1102)
[62]
In its post-hearing brief, NSPI provided the following justification for
inclusion of the buy-out fee in the test year expenses:
When, in the course of negotiations for the renewal of the price and quantity under the
agreement, it became possible to amend the agreement to shorten the term and eliminate
the issue about coal importation, NSPI decided to proceed. In return for a payment of $13.4
million, NSPI achieved a number of things:
a)
A price for the years 2000, 2001 and 2002 which was lower than the price which had
prevailed in the past. NSPI’s assessment was that this price was favourable in that it
was lower than the price that might be awarded by an arbitrator under the four factor
formula.
b)
A shortening of the term of the contract from 2010 to 2005. New environmental
limits coming into effect in 2005 would have made significant investment in
scrubbers necessary in order to continue burning Cape Breton coal, while use of
lower sulphur (or high sulphur/low chlorine) imported coal would be possible without
the cost.
c)
Elimination of the possibility of importation by CBDC to supply NSPI.
Document : 78377
31
d)
e)
Clarity as to volumes and quality of coal.
The right to acquire the surface transportation assets, including the international coal
pier in Sydney and the CBDC railway at fair market value.
Each of these provisions was of great value to NSPI and its utility customers, both at the time
and in the future. It cannot be seriously suggested that the buy-down of the agreement was
not reasonable and prudent, in the interest of NSPI and its customers, at the time it was
made.
(NSPI, Post-Hearing Brief, pp.15-16)[Emphasis in original]
4.2.2 Submissions - Intervenors
[63]
The intervenors generally agree that NSPI should not be permitted to recover
the cost of the CBDC buy-out. SEB and Annapolis, whose expert witnesses examined the
confidential documents including those pertaining to the CBDC buy-out, provided the most
extensive arguments against allowing NSPI to recover the costs.
As noted earlier, much of this
information has been filed in confidence. In the redacted version of her direct evidence, Ms. Medine
testified that NSPI should not be allowed to recover this cost, stating that:
1.
NSPI did not need to pay CBDC for an early termination of the Agreement because:
·
CBDC was not going to be around and CBDC did not have the right to
unilaterally assign the Agreement to a third party.
·
NSPI already had early termination rights under the Agreement that it could
have utilized.
2.
The NPV analysis was flawed and grossly overstated the potential savings tied to the
early termination payment.
·
Ratepayers did not derive any benefit from the retroactive establishment of
the C$2.11 per MMBtu price in 2000 and 2001.
·
The presumption that regardless of the import price, CBDC would be
C$0.28 per MMBtu higher is without analytical justification and was
inconsistent with actual prices in 2001.
·
CBDC coal could have burned in 2005 under the current environmental
requirements without scrubbing
and there is no guarantee that
Lingan will not have to be
scrubbed in any event.
3.
To the extent that NSPI realized lower prices in 2000 and 2001, as a result of the
payment, NSPI has already recovered the payment by virtue of the lower prices as
reflected in NSPI’s own net-present value analysis.
(Exhibit N-39, p.16)
[64]
Document : 78377
Ms. Medine elaborated on her reasons for this view during the in camera
32
session before the Board.
[65]
In the redacted version of her direct evidence, Ms. Hennings also indicated
that, in her opinion, NSPI should not be allowed to recover the buy-out costs. She stated that:
NSPI should not be allowed to recover the cost of the buyout in 2002 and later years. It
should be granted no regulatory asset for the buyout costs.
The cost of the buyout has already been recovered in the price reductions under the buyout
contract for NSPI’s coal purchases in 2000 and 2001. NSPI paid only part of the invoiced
price of its CBDC coal receipts, starting in 2000. NSPI made a lump sum payment of the
difference between its partial payments and the revised amounts due under the buyout as
part of the buyout settlement in late 2001. In effect, it received the cash from the price
reductions as the coal was delivered in 2000 and 2001.
By 2002, NSPI’s benefit from the buyout became a loss due to market price changes in other
coal transactions and a lack of term contracts. CBDC closed its mine and no longer supplied
the coal savings that supported the buyout price. NSPI’s actual coal prices for 2002 would be
higher than the 2002 CBDC coal price would have been without the buyout. If the buyout had
not already been recovered by 2002, the prudence of the buyout could have come into
question because NSPI did nothing to hedge the future market price used in its analysis.
8. Do you have any additional comments about the buyout analysis?
Yes, I think NSPI incorrectly included the avoided price of scrubbers for two units at the
Lingan plant in its analysis. These scrubbers and other capital equipment may still be
necessary to avail NSPI of the lowest coal prices. Capital equipment investments may allow
NSPI to burn a wider variety of coals, some of which are more competitive than coal from the
markets NSPI currently uses.
(Exhibit N-30, pp.3-4)
[66]
Annapolis takes issue with the inclusion of the buy-out fee, arguing that:
NSPI’s character is revealed in its requests to recover from the ratepayers the “termination
fee” paid by it as part of its settlement with Devco for its disputed values of delivered coal.
The evidence on record leads to the inevitable conclusion that the “termination fee” was a
device proposed by NSPI to enable it to support the $2.11 per MMBtu at which it booked
Devco coal in 2000. Based on this booked price, NSPI’s shareholders would enjoy dividends
and its executives their bonuses. From Devco’s perspective, it did not matter how this
payment was characterized as long as the cumulative payment under the Amending
Agreement gave it a fair price for the coal which was already delivered. The proximity of the
announcement of the closure of the Prince Mine to the conclusion of the Amending
Agreement and the absence of a covenant to continue to produce the coal can leave little
doubt that the negotiated price was never intended by Devco to have a prospective effect
apart from coal which it could “high grade” from the already developed face. The treatment
of interest under the Amending Agreement illustrates that the “termination fee” was made as
part of the compromise payment respecting the disputed invoices, the benefits of which NSPI
has already enjoyed.
NSPI’s attempts to withhold the contemporaneous analysis of the benefits of the Amending
Agreement to NSPI and to proffer instead an after-the fact analysis which includes different
calculations than presented to its Board of Directors does not reflect well upon NSPI and
illustrates the extent to which an attitude of “putting it to the ratepayers” has infused the
organization.
(Annapolis, Closing Brief, pp.4-5)
Document : 78377
33
[67]
SEB made similar arguments against NSPI including the buy-out cost in its
revenue requirement in its confidential closing submission to the Board on fuel costs. The Province
made the following objection to the inclusion of the buy-out fee:
NSPI are seeking approval of the Board to amortize the $13.4 million CBDC Contract
termination fee over a five year period beginning in 2002. In response to Grant IR 15.6, NSPI
provided a net present value calculation of the CBDC termination fee showing an
approximate net present value of $144.4 million. Ms. Hennings in Exhibit N-3 and Ms. Medine
in Exhibit N-39, both concur that the cost of the buyout has already been recovered in the
price reductions for NSPI’s coal purchases in 2000 and 2001 under the CBDC Amending
Agreement of April 2001. It is submitted that the termination fee paid by NSPI should have
been fully charged in 2001 when the company realized the fuel savings for both 2000 and
2001. The termination fee was simply a substitution for a decreased fuel cost in 2001.
(Province, Closing Submission, p.14)
[68]
ECANS and MEUNSC also indicated to the Board that, in their view, NSPI
should not be allowed to recover the cost of the CBDC buy-out.
4.2.3 Findings
[69]
The Board has reviewed the explanation offered by NSPI witnesses with
respect to the basis for inclusion of this expense and the reasoning and analysis that ultimately
persuaded the Board of Directors to approve the contract buy-out. There was considerable
discussion at the hearing regarding the nature of the long term CBDC contract, i.e., whether it
actually was a requirements contract. It is noteworthy that, despite NSPI’s characterization of the
contract as a “requirements” contract, and CBDC’s assertion that it could import to supply NSPI,
NSPI did acquire coal from sources other than CBDC while the contract was still in effect.
[70]
The Board notes that under cross-examination, Michael O’Neill, NSPI’s Vice
President of Finance and Administration, confirmed that the April 2001 buy-out established a coal
price of $2.11/MMBtu, which was the same amount recorded four months earlier, in December of
Document : 78377
34
2000, when NSPI booked its 2000 coal price in its year end accounting records.
[71]
With the exception of Mr. Watkins, all of the experts who reviewed this
matter - Ms. Medine, Ms. Hennings, Dr. Rosenberg and Dr. Stutz - agree that the expense associated
with the termination fee should be disallowed. In response to a question from the Board concerning
whether he agreed with Ms. Medine that the buy-out fee should be excluded, Dr. Stutz responded
that:
I do. And I'd just like to turn up something and then I'll answer. What I'm looking at is a table
that appears at the end of Grant 15.6. And there's no need to go rooting around for this
table, but if you look at Grant 15.6, there is a calculation which shows the costs and benefits
of termination. And on its face, what it shows is that there was a net benefit at the end of
2001. So one of the things that I believe Ms. Medine said was that the benefit was there
already and the costs had been effectively recovered. Then you went on to talk about intent.
I find it difficult to address intent. We have the product here of a settlement of some sort,
and knowing what went on in the settlement is very difficult. But we certainly can look at
effect, and what we know is that a relatively low price, two dollars and eleven cents ($2.11),
was imputed for 2000 and 2001. Certainly everything I've heard suggests that if this buyout
hadn't worked, we would have been paying more than that. So you got a relatively low
imputed price and you have a balloon payment. Now, as a matter of arithmetic, you could
increase the price and get rid of the balloon. There may be some reason why Devco would
prefer the balloon, but it's very hard for me to imagine it, and I certainly didn't hear it in the
time I was here. Now, during the years when we've imputed these prices, it also appears to
me from the indexed data that was used on cross-examination that appears in one of the IRs
that the company was earning at or a tiny bit above its allowed rate cap of 11 percent. So I
think her point that in fact the result was that the company had already been paid is
supported. Whether the company in fact organized its negotiations to prove that -- to provide
that result or whether it just fell out that way, I can't say.
(Transcript, June 4/02, pp. 3985-3986)
[72]
Notwithstanding the evidence of NSPI witnesses, the Board finds it difficult to
discern a future benefit to ratepayers as a result of a fee paid to terminate a coal supply contract
approximately one month before the announcement was made that coal mining by CBDC would
cease. In any event, the Board finds that, based on the evidence, it is reasonable to conclude that the
benefits of the $13.4 million paid to terminate the CBDC coal supply contract have already been
realized by shareholders. Under these circumstances, it is not appropriate to transfer the burden of
this fee to the ratepayers. Accordingly, the proposed expenses associated with this fee are
Document : 78377
35
disallowed. Test year expenses will be reduced by $2.7 million, which is the amortized value of the
fee for 2002.
4.3
January Adjustment
4.3.1 Submission - NSPI
[73]
As noted earlier, NSPI filed its application for a general rate increase on
December 18, 2001, using 2002 as the test year. In a letter dated January 28, 2002, NSPI updated
the December 18, 2001 filing.
[74]
NSPI’s January 28, 2002 letter reads as follows:
In its prefiled evidence of December 18, 2001, NSPI undertook to file updated 2002 financial
forecasts with the UARB on January 28, 2002, even if no change to revenue requirement is
warranted (page 16, lines 7-8).
NSPI has completed its update. A summary of revisions to the forecast is as follows:
Adjustments
1. Fuel (net of reduced export revenue)
6.1
3. January Revenue Deficiency
5.0
4. Interest Expense Increase
0.2
5. Revision of Revenue From Annually
Adjusted Rates
4.2
7. Test Year change in Earnings
Net Adjustment
2.
3.
-13.4
2. OMG
6. Income Tax Reduction
1.
$ millions
-3.1
1.0
0.0
Fuel costs have decreased from $372.0 million to $354.8 million. This is due to a
higher inventory of CBDC coal than expected at the end of 2001 and a modest
decline in world coal prices. It also reflects updated fuel prices. Export sales
revenue has been reduced by $3.8 million due to the lower fuel costs.
The operating, maintenance and general expense has increased by $6.1 million.
This includes a reduction in Power Production OM&G of $0.3 million and an increase
in pension expense of $6.4 million due to a change in actuarial assumptions
reflecting market conditions.
Sales and revenue have been updated to reflect January, 2002 estimated results
Document : 78377
36
4.
5.
6.
including warmer weather.
Interest expense has increased slightly due to timing changes in cash flows.
Annually adjusted rates for 2002, as submitted to the UARB on November 20, 2001,
are being revised to reflect the changes, since they are formula driven. These are
being submitted to the Board under separate cover. The impact of the annually
adjusted rate revenue is a function of when other proposed rates are approved. This
is because the Industrial Expansion rate is capped by the Interruptible rate. The
impact shown assumes the increases requested in the current application become
effective May 1, 2002.
Income tax has changed due to a revised 2001 closing taxable position.
The update confirms the 2002 forecast originally filed. We are, therefore, still seeking
approval of the rates as proposed in our December 18, 2001 filing.
Given the changes which have occurred, NSPI is hereby filing:
a)
Updated financial tables (Tables 3.1R to 3.13R) for 2002.
b)
An updated load forecast table (Table 4.1R) reflecting the January 2002 impact.
c)
Table A showing that the impacts of these changes on Revenue/Cost ratios are
minimal.
(Exhibit
N-160)
[75]
In response to questions from Counsel for SEB, Mr. Huskilson gave the
following explanation for the filing of the January adjustment:
Yes, we -- the primary concern that we had about our filing that we made on December 18
was that we -- it was going to be very hard for us to predict what our closing inventory levels
would be, and because we believed that we might still have some lower-cost coal on the
ground we believed that it would be very important to make sure that, that update be
reflected. And as I stated earlier, that was one of the corrections that we believed to be
important to make in order to ensure that we were asking for a revenue requirement that was
most appropriate and reflected all of the changes that we could envision in our fuel forecast.
(Transcript, April 22/02, p.47)
[76]
In its reply brief, NSPI points out a lack of consistency in intervenors’
arguments on this subject stating that:
NSPI has attempted to put forward the most accurate forecast of the test year of 2002
possible. In doing so it has incorporated actual data to the extent it is available. NSPI has
incorporated actual data which is favourable and unfavourable. The intervenors attempt to
rationalize their proposals to include the unfavourable data while excluding the favourable
data.
(NSPI, Reply Brief, p.1)
[77]
NSPI witnesses indicated that the purpose of the January 28, 2002 letter was
to provide to the Board information which might be of assistance in considering the rate application
in view of the timing of the hearing and “actual” data relating to the test year. Subsequent to filing
Document : 78377
37
the January 28, 2002 letter, NSPI filed amendments to its direct evidence, including revised financial
tables, which reflected the noted changes.
4.3.2 Submissions - Intervenors
[78]
Virtually all of the intervenors disagree with some component of the January
adjustments. In particular, the intervenors object to the weather adjustment, which is item 3 in the
January 28, 2002 letter. This change incorporates the inclusion of “actual” January 2002 weather
data in the test year. In his direct evidence, Dr. Rosenberg opposed NSPI’s adjustment to its revenue
requirement based on a warmer than normal January. Dr. Rosenberg asserts that:
. . . When NSPI made its initial filing it based its forecast on normal weather. This is as it
should be. When forecasts are based on normal weather the expected value of sales will be
equal to the forecast. While actual results will almost always differ from forecast, the forecast
is at least what a statistician would call “unbiased”. However, by taking a single month and
using abnormal weather, while at the same time using normal weather for the remaining 11
months, NSPI has biassed its forecast. Now if NSPI could present conclusive evidence that
the balance of the year will not be colder than normal (or that January 2003 will not be colder
than normal), it might have a point. Of course it is unable to present any evidence, so the
January adjustment must be rejected.
(Exhibit N-113, pp.27-28)
[79]
In his opening statement, Dr. Rosenberg again referred to NSPI’s January
adjustment stating that:
The last item concerning NSPI's revenue requirement that I address is the so-called January
adjustment. The net result of this adjustment, as Mr. Whalen concedes, would be to base
rates on a test year that was warmer than normal, contravening a fundamental precept of
regulation,
and
this
adjustment
should
be
summarily
rejected.
(Transcript, May 24/02, p. 3508)
Dr. Stutz, in his direct evidence, also opposed the use of “actual” weather
[80]
results stating that:
Actual January data are unrepresentative because the weather in January was much warmer
than normal. As stated in NSPI’s response to NSUARB-IR-342, heating degree days for
January 2002 were 628, while normal is 702. As noted in NSPI’s response to NSUARB-IR241, the warm weather in January reduced sales substantially. If test year data are to be
Document : 78377
38
representative, they should reflect normal weather for January. NSPI’s forecast data does
that.
(Exhibit N-152, p. 15)
[81]
Under cross-examination by NSPI Counsel, Dr. Stutz commented on the
question of adjusting test year data with actual data. The following exchange is illustrative:
Q.
A.
Q.
A.
Q.
A.
Q.
A.
Q.
A.
All right. Looking -- talking about other things that may or may not be ignored, and
that is the actual data for January.
Yes.
And you've offered the opinion that the actual data for January should not be relied
on.
That's correct.
Are you looking only at the weather data or are you looking more generally at actuals
of other things.
No, I don't think you should use the actuals at all, and the reason is basically that
you need a consistent test year, and you have a consistent test year based on
normal weather and all your other assumptions.
We know that the demand was down in January and that weather was just one factor
that contributed. Should we ignore all the other factors as well?
Yes, because again you're trying to set the rate -- well, let me say it a different way.
The rates you're setting will be used -- could be used for some January, but it's not
the January you have data for. It's the January in the future. And there's no
particular reason to think that this January would be similar to a future January, and
in fact, your own heating degree data suggests it won't be at least in that score.
So would you equally ignore actual cost impacts -- the cost impacts -- the costs to
the company should also be based on forecast rather than actuals?
I think you have to have a consistent set of data. Okay? And I think your January
adjustment makes your data inconsistent.
(Transcript, June 3/02, pp.3788-3789)
[82]
Dr. Stutz also gave the following response to a Board question:
It's still a future test year, right, because it doesn't have all historic data. You could call it a
mixed test year if you want to be precise. But I focused on the forecast information as the
one area in which I felt the update simply could not be accepted, and in my testimony I gave
one reason. I think this was brought out on cross-examination, perhaps by Mr. Cooper, but
the key point is that we're, in effect, forecasting warmer than normal weather if we average in
the January sales. And that just isn't reasonable. You're looking out prospectively. Januarys
are not always warmer than normal. If you look at the IR response that shows heating
degree data, you'll discover that January of 2001 was about spot-on for average weather.
So, it's simply not reasonable to use warmer than normal data. Moreover -- and this is
something I said to Mr. Campbell and I'm not sure I was completely clear about this -- putting
in a month of actual weather makes a shambles of the entire analytical framework, because
the way the analytical framework is constructed is there's an annual forecast of sales, that
forecast is then divided into monthly data and the monthly data is used in a variety of places
including the cost-of-service study. Now, you can't simply carve out a little piece of the
annual sales data, drop in January and have anything make sense. You're then -- when
Document : 78377
39
you're putting together your analysis, if you're taking annual data which includes the old
January and allocating it, the February data that you've got in there, in effect, reflects the
aggregate and so the old January but you've got it sitting next to the new January. Moreover,
everything you've done reflects normal weather except for the new January where the heating
degree days were more than 10 percent different from normal. It's chaos. You just can't do
that. So, for the two reasons, the representativeness and the chaos avoidance, if you will, I
think you have to reject the use of the January data. Now, does that mean you reject the
entire update?
No.
You simply use the update without the January data.
(Transcript, June 4/02, pp. 3935-36)
4.3.3 Findings
[83]
The Board agrees with the views of the intervenors with respect to the
problems which would occur if actual weather data for January 2002 was incorporated into the test
year calculations. The Board finds that mixing actual and projected weather data is not a sound basis
for rate-making. Indeed the Board finds that the January 28, 2002 update, with respect to all the
items, not just the weather adjustment, should be disregarded by the Board in determining the
appropriate revenue requirement for NSPI.
[84]
The Board believes that the December 18, 2001 filing by NSPI represented the
Utility’s best forward-looking estimate of the 2002 test year. The Board agrees with Dr. Stutz’s
point that incorporating "actual" January data may have the effect of lessening the consistency and
reliability of the test year data.
[85]
If the rate-making process were based on the most up-to-date numbers, as
opposed to forward-looking data derived from experience over the longer term, each month could
bring innumerable changes to the revenue requirement. On balance, it is the Board’s view that this is
not an appropriate methodology to employ for rate-making purposes. Therefore, despite the appeal
of "actual" results over projections and the arguments which have been made with respect to all or
Document : 78377
40
some of the adjustments, the Board has decided to disregard the January filing. Accordingly, the
Board will consider the test year data included in the original filing by NSPI dated December 18,
2001. The Board notes that, in any event, the net effect of the January adjustments on NSPI’s
projected revenue requirement is zero.
4.4
Hydro
4.4.1 Submission - NSPI
[86]
NSPI, using five year average rainfall data, projected a reduction in hydro
generation over previous years. Since there is little or no fuel required in hydraulic generation, a
decrease in this cheaper form of power production results in higher fuel costs. In previous filings
before the Board, NSPI used a twenty-three year average to predict rainfall with the result that hydro
generation was higher than is estimated in the current application.
4.4.2 Submissions - Intervenors
[87]
Ms. Hennings, in her direct evidence, made the following observation
concerning NSPI’s estimate of hydro generation:
My first adjustments, a fuel cost reduction of $[redacted] million, changes the plant dispatch
from what was forecast by NSPI. This reflects an increase of 80,500 MWh in the 2002
forecast of hydraulic generation. The revised hydro generation forecast is equivalent to a 23year average of the actual NSPI generation that was provided in response to SEB IR-15.
NSPI’s 2002 hydraulic generation estimate is based on a 5-year average, with the generation
effects of hurricanes removed. Removing the effects of hurricanes tends to understate the
resource. Using a long period of historical information can smooth out differences between
estimates and actual generation. Data from a long history should be adjusted for capacity
changes during the history. NSPI’s hydro capacity was not increased or decreased during
the 23 years given in NSPI’s response, so I used a simple average of the 23 years history. I
decreased the forecast generation from NSPI’s oil fired combustion turbines by 25,000 MWh.
According to SEB IR-10, the average increase for the last 3 years of combustion turbine
generation was 20,000 MWh per year. This year, the forecast increase over 2001 annualized
Document : 78377
41
information is an increase of 45,000 MWh from 2001 data. My adjustment brings the 2002
increase into line with prior years’ rate of change. It also reflects the replacement of marginal
system energy with part of the adjustment for increases in hydraulic power. When
combustion turbine generation runs, it is often on the margin. The remaining energy
reduction of 55,500 MWh is assumed to come from high cost coal generation.
These energy adjustments are calculated to decrease total fuel costs by $[redacted] million.
The assumptions used for average fuel costs of each of the sources of energy were that
hydro power is provided at no fuel cost, combustion turbine energy is assumed to average
$[redacted] per MWh, and Tuft’s Cove energy is assumed to average $[redacted] per
MWh, according to NSPI’s filing.
(Exhibit N-30, p.9)
[88]
Ms. Hennings was cross-examined by Counsel for NSPI on this issue during
an in camera session and, therefore, the Board is constrained from reproducing that exchange in this
decision. However, it can fairly be said that, while NSPI challenged Ms. Hennings’ assumptions
relating to marginal fuel costs, it did not directly contest her hydro generation based on a twentythree year average. In the confidential annex to its post- hearing brief, NSPI defends its estimate of
hydro based on rainfall averages of recent years as opposed to long-term rainfall averages. NSPI
further asserts that, even if the Board was inclined to adopt the long term data, Ms. Hennings’
adjustment would also change the dispatch model and should not be accepted without an off-setting
costing which would incorporate the impacts of dispatch changes.
[89]
SEB counters, in its confidential closing submission, that since there is no fuel
cost component to hydro generation, when hydro displaces fuel-driven generation, it follows that fuel
costs are reduced. SEB argues that this occurs regardless as to what dispatch model is used to run
numbers.
4.4.3 Findings
[90]
Document : 78377
The Board notes that this issue was canvassed in UARB IR-130(A). NSPI
42
was asked to estimate avoided fuel costs if assumed hydro generation in 2002 was at a higher level.
NSPI, in its response to UARB IR 130(A), stated that:
IR-130(A)
To estimate the impact of reducing hydro generation from 991 GWh to 917 GWh for the year,
the Proscreen model was re-run changing only the assumption about hydro production
volumes. The effect of increasing hydro generation was to decrease total fuel costs by
approximately C$3M.
(NSPI response to UARB IR-130(A))
[91]
It is reasonable, in the Board’s opinion, to use a twenty-three year average for
hydro generation rather than a five year average. The twenty-three year average is used by NSPI in
its weather data and has been used in its economic analysis methodology in other filings with the
Board. In any event, absent convincing evidence to the contrary, the Board believes longer term data
is preferable for purposes of estimating hydro generation.
[92]
Using the information provided in NSPI’s response to UARB IR-130(A), the
Board finds NSPI’s avoided fuel cost as a result of increased hydro generation to be $3 million.
NSPI’s test year expenses will be reduced accordingly.
4.5
Compensation
4.5.1 Submission - NSPI
[93]
NSPI, in its direct evidence, requested that the Board allow the inclusion of
100% of incentive compensation/bonus costs in the 2002 test year expenses. NSPI acknowledged
that this constitutes a change from the 1996 Board decision when only 50% of incentive
compensation was permitted to be included in the test year expenses.
[94]
NSPI asserts, notwithstanding the Board’s finding in its 1996 decision, that:
Performance based compensation is not an amount in addition to employee compensation it forms part of the fair and reasonable compensation of an increasingly large portion of
NSPI’s work force. NSPI’s employee compensation levels, including performance-based
compensation are “mid-market” as compared to levels for comparable staff in other large
Document : 78377
43
organizations. NSPI operates in a very competitive market for executive, managerial and
staff talent, and a compensation package incorporating an incentive element is considered a
requirement to attract, retain and motivate qualified employees. These amounts are
reasonably and necessarily expended in the operation of the utility and should form part of
the Company’s revenue requirement. The alternative would be to eliminate the incentive
program and adjust base compensation. This, however, would not be in the interest of either
customers or investors.
Payment of incentives is contingent on employees meeting objectives aligned with NSPI’s
corporate objectives. Evaluation is based on a Balanced Scorecard which recognizes the
interests of customers, employees and investors. This encourages innovation and
excellence and performance by plan employees, to the benefit of all stakeholders - payment
is neither automatic nor guaranteed; for 1998, no incentives were paid to any employees.
NSPI has included in its 2002 revenue requirement 100% of incentives totalling $3.5 million;
2001 projected results include one-half of the incentive at $1.6 million. Given the benefit of
the program, NSPI respectfully requests that the Board reconsider this issue and include
100%
of
the
incentive
as
part
of
the
revenue
requirement.
(Exhibit N-1, pp.18-19)
[95]
In Exhibit N-1, p.2 of Appendix 1, NSPI submits the following 2002
compensation cost for its Executive Management:
Thousands of $
Executive Management
Total Operating Labour
Actual
2000
Forecast
2001
Change
from
2000
Percentage
change
Forecast
2002
Change
from
2001
Percentage
Change
1,524.0
1,975.1
451.1
30%
2,081.3
106.2
5%
(Exhibit N-1, Appendix 1, p.2)
[96]
In Undertakings U-9 and U-10, NSPI provided information concerning the
process for determining appropriate levels of compensation for senior management and the benchmarking with comparable utilities and other companies that is done in setting compensation levels.
NSPI did not provide any specific support in its pre-filed evidence for the proposed expenses relating
to compensation for Executive Management.
Document : 78377
44
4.5.2 Submissions - Intervenors
[97]
Several intervenors, notably Annapolis, HRM, ECANS and the Province, took
issue with the level of compensation paid to Executive Management.
[98]
Counsel for Annapolis introduced Exhibit N-18, which reflects information
contained in management information circulars attached to NSPI’s responses to UARB IRs 215 and
166. The table compares compensation paid to senior NSPI management at the time of the last rate
hearing to present day compensation levels. (See the Table of Salaries on the following page).
Table of Salaries
President and Chief Executive Officer - Louis R. Comeau; David Mann (from 1996) * Annual base for 1996
1993
1994
%
1995
Change
%
1996
Change
%
1997
Change
%
1998
Change
Salary
157,212
165,621
185,287
325,000
335,521
Bonuses
40,640
43,890
42,185
25,000
65,000
197,852
209,511
%
1999
Change
346,535
%
Change
358,792
180,000
Other
Total
6%
227,472
8.5%
350,000
54%
400,521
14%
346,535
(-13%)
538,792
55.5%
%
1998
%
1999
%
Christopher G. Huskilson - Executive Vice-President Operations/Chief Operating Officer Nova Scotia Power Inc.
1993
1994
%
Change
Salary
1995
%
Change
1996
%
1997
Change
Change
111,547
Document : 78377
Change
140,077
Change
178,654
45
Bonuses
13,300
39,590
Other
Total
124,847
140,077
12%
218,244
NOTE: Correction - Transcript, April 23, p.317 which reads:
(Exhibit N-18)
“ . . . there's a small typo in the fifth column for 1995 for the President and CEO. It should read "227,472."
Document : 78377
56%
46
[99]
In its closing submission, Annapolis stated that:
It was clear from the evidence that there has been a substantial increase in executive
compensation between 1993 to 2002 with the President’s salary and bonus increasing from
about $200,000 to over $830,000. The Vice-President showed an increase of over 56% just
from last year (Exhibit N-18). NSPI has an executive compensation committee to set its
management compensation and, while the panel denied that there has been a change in
approach, it was apparent from the Management Information Circulars that the benchmarking of salaries to Atlantic Canadian companies has been eliminated in 2002 (Transcript,
pp. 322-325). NSPI offered up in response to Undertakings U-9 and U-10 a review of
executive compensation. It is significant that in the sample of nine electric utilities and energy
companies, when total compensation was divided by total revenue generated, Emera ranked
second.
While Emera purports to be global and diversified, NSPI remains a mid-size regulated Nova
Scotia utility. Its President was drawn from a local law firm and its Chief Operating Officer is
a Nova Scotian who worked his way up through the ranks of the utility. Should this Board
determine these compensation packages are not reasonable or fully used and useful, it may
disallow some portion of the executive compensation claimed. It is, of course, no concern to
the ratepayers or the Board how Emera wishes to compensate its executives.
(Annapolis, Closing Submission, pp.43-44)[Emphasis in original]
[100]
ECANS also took issue with executive management salaries pointing out that,
in its view, NSPI’s executive compensation is excessive given the size of NSPI. ECANS also made
the point that what is at issue is not the compensation level per se but the amount which is ultimately
recovered from utility ratepayers.
[101]
HRM registered its objection to the levels of compensation paid to executive
management noting that:
Mr. Huskilson in explaining the changed criterion stated that “Emera as an organization is
changing”. If the type of salaries needed to reflect the parent’s interest in growth and
acquisition is what is driving the common NSPI/Emera Board to so dramatically increase
executive salaries, rather than the business reality of NSPI, then only a just and reasonable
executive salary cost for the management of a regulated utility should be considered in
determining the NSPI revenue requirement.
It is submitted that the NSPI/Emera Board has not adopted an appropriate criteria for
determining NSPI executive salaries, and, as a result, only a portion of the current salary
base including bonus money and other benefits of its top 5 executives should be included in
the revenue requirement.
Document : 78377
47
As a percentage of revenue, both the salaries of the CEO and COO rank as No. 2 and are
thus leading salaries relative to revenues not only in Nova Scotia but also among Canadian
utility companies.
(HRM, Written submission, p. 21)
[102]
On the issue of incentive compensation, HRM argues that:
There is no evidence on the record from NSPI to support any change from an equal division
of corporate incentives as was ordered by the Board in its 1996 decision. Based on Chris
Huskilson’s testimony that there is a benefit to both shareholders and ratepayers which is
difficult to allocate between the two, and equal allocation of incentives between ratepayers
and
shareholders
would
appear
to
continue
to
be
appropriate.
(HRM, Written submission, p. 25)
[103]
In his direct evidence Dr. Stutz made the following comments on the issue of
incentive compensation:
In the past, the Board has allowed only 50 percent of these costs. NSPI states, in response
to NSUARB-IR-72, that its incentive plans align individual activities with corporate objectives.
As indicated in NSPI’s response to NSUARB-IR-73, these corporation objectives include
asset growth, which clearly benefits shareholders. As shown in the data provided in Exhibit
JS-6, incentives are a growing part of NSPI’s compensation to top management, which is
likely to be knowledgeable about, and concerned with, shareholder interests. Taking all of
these point into account, I recommend that the Board continue to allow only 50 percent of
incentive compensation costs in NSPI’s required revenues.
(Exhibit N-152, pp.15-16)
[104]
Under cross-examination by NSPI counsel, Dr. Stutz said:
I think where you have corporate goals that benefit both shareholders and rate payers and
where you have compensation tied to those goals and objectives, you have a situation where
the shareholders benefit directly and the rate payers benefit directly and it's up to the Board to
decide how much of that component of compensation ought to be borne by those who
benefit.
(Transcript, June 3/02, pp. 3794-3795)
[105]
When questioned by the Board, Dr. Stutz said:
The short answer is I'm where I started. Let me address the points that you've raised. Let
me begin with the second point. I don't understand anyone, including the Board in its past
decisions, to say that the company can't pay incentive compensation. I didn't see anything in
there that addressed whether that was -- whether the company could do it. I don't even recall
a comment about whether it was appropriate. The issue seemed to go to who benefitted
and, therefore, who should bear the cost, and that was the way I approached the issue. The
key new information that I heard in this hearing was, in fact, that it's impossible to determine
the proportion of benefits. I think that's what Mr. Huskilson said in his cross- examination,
that there was agreement that there were benefits to both shareholders and customers but
Document : 78377
48
that we couldn't determine the percentages, that it was kind of an inseparable cost, if you will.
So, we couldn't determine it was 60 percent to one and 40 percent to the other or vice versa.
So, 50/50 is a usual choice when you have a benefit that you can't divide, so I don't see any
reason for you to change that. As to the question of how many of the staff receive incentives
and what the incentives actually incent them to do, I don't see any basis for change there.
On the numbers, if you look at my Exhibit 6, you'll see that while larger numbers receive the
incentives, the incentive payments in dollar value do tend to be more at the top than uniformly
spread. So, there is some reason to believe that the big incentives, if you will, are going to
those who might have the interest of shareholders more clearly in mind. However, conscious
intent to help the shareholders is not really the issue. If you reduce costs between rate
cases, you help shareholders. That's the way regulation works. Because the rates are fixed,
if the costs go down, all else equal, the earnings go up. So, over the long haul, because
most years you're not setting rates, cost reductions most of the time benefit shareholders, not
ratepayers. Now, I think that's appropriate. I think it gives the company a real incentive to do
better. So, I don't object to that. I think it's a fine feature of regulation. But it does mean that
things you do, even customer service, for example -- suppose you keep a customer happy
and so he doesn't, in a fit of peak [pique], go out and buy his own generator. Between rate
cases that helps the company. So, I think all of these things that were said are true, but I
think they all, in many instances, help the shareholders. I think they also help the ratepayers
in the long run, because in the next rate case they have a bigger base over which to spread
their revenue. So, I'm not arguing one against the other, I'm simply supporting, I think, your
earlier finding that both benefit.
(Transcript, June 4/02, p. 3924-26)
4.5.3 Findings
4.5.3.1
Executive Compensation
[106]
The Board is concerned about the rapidly increasing compensation which is
being paid to the executive management of NSPI and which is included in costs to be recovered from
ratepayers. Other than providing information and assurances that compensation is “bench-marked”
against comparable positions, NSPI has not, in the Board’s view, adduced any justification for
ratepayers to bear these increased costs. In Exhibit N-18, it is clear that the compensation costs for
NSPI’s two most senior executives have increased dramatically over the past several years. The
Board has no information regarding the compensation of other senior executives of NSPI so its
comments in this regard refer to the individuals noted in Exhibit N-18.
[107]
The compensation paid to management is the prerogative of the Board of
Directors which is accountable to the shareholders of the Company. Obviously, the NSPI/Emera
Document : 78377
49
Board of Directors, acting on behalf of shareholders, believes these salaries are justifiable and
competitive.
[108]
The Board does not believe current compensation levels are acceptable to the
vast majority of ratepayers in this Province. This sentiment is clearly expressed in a number of the
comments made to the Board, particularly during the public evening session on April 25, 2002. The
issue of dramatically increasing compensation is exacerbated by the knowledge that these individuals
do not work exclusively for NSPI, as they also have responsibilities relating to other Emera corporate
activities. That being the case, the Board is of the view that it is appropriate for the shareholders to
bear a significant portion of the increased compensation costs.
[109]
It should be noted that in 1996 there was a different management structure in
place at NSPI. Today there is a President who is the Chief Executive Officer, and also a Chief
Operating Officer, a position that did not exist in 1996. It appears to the Board that Mr. Huskilson is
the individual in charge of NSPI operations on a day-to-day basis. He appears to be discharging
many of the duties previously performed by NSPI’s President. This is evidenced by his appearance
as the most senior executive of NSPI present during the hearing.
[110] The Board believes it is fair for ratepayers to bear compensation costs that
have increased at a reasonable rate from those paid at the time of the last rate hearing. Using the
President’s 1996 compensation as a base, the Board notes that Mr. Huskilson’s current compensation
of $483,669 represents approximately a 38% increase over that paid in 1996.
[111] The Board was impressed by Mr. Huskilson’s knowledge of NSPI affairs, as
he was questioned during the hearing about a wide range of NSPI matters. It is clear to the Board
that Mr. Huskilson devotes much of his time to NSPI activities. With respect to the compensation
Document : 78377
50
paid to Mr. Huskilson therefore, while the Board has some concerns about the magnitude of the
amount, as well as about the significant increase during the last few years, the Board is prepared to
accept it as a reasonable reflection of his contribution to NSPI. Accordingly, except for the incentive
compensation and corporate support allocation discussed below, the Board is prepared to include Mr.
Huskilson’s full compensation in the revenue requirement for the test year.
[112] The Board has some satisfaction that Mr. Huskilson’s salary is not completely
out of line compared to other Atlantic Canadian companies. The figures in Undertaking U-10 show
that for three Atlantic Canadian companies the average total compensation for the president is
approximately .06% of revenue. If this percentage is applied to NSPI’s revenue, the result
approximates the compensation Mr. Huskilson is receiving. The Board puts more weight on the
Atlantic Canadian companies primarily because they are in the same region as NSPI which provides
a more meaningful comparison, and also because the other companies listed in Undertaking U-10
are significantly larger than NSPI in terms of revenue. The Board recognizes that the figures used in
the calculation of the Atlantic Canadian percentages are primarily for the respective presidents.
However, the figures for the Vice-Presidents are not given in all cases, and further, the Board is of
the view that Mr. Huskilson appears to perform many of the duties of a president.
[113] Accordingly, for the purpose of test year expenses, the Board accepts the
compensation paid to Mr. Huskilson with the understanding that the allocation of the costs of his
compensation between NSPI and Emera (which will be discussed later in this decision) will be
applied to, and further reduce, the revenue required from ratepayers, as will the Board’s ruling on
incentive compensation.
[114]
Document : 78377
With respect to the compensation paid to David Mann, President of NSPI, the
51
Board has no evidence before it of Mr. Mann’s duties with NSPI. There were references at the
hearing to the fact that Mr. Mann did not give evidence during any of the proceedings. While his
absence is not unprecedented, it does leave the Board with no evidence on the record of Mr. Mann’s
day-to-day activities and, consequently, scant support for charging to ratepayers a 73% allocation of
his $832,000 annual compensation package. The evidence which is before the Board would seem to
indicate that many of Mr. Mann’s activities primarily relate to Emera. As President of Emera, Mr.
Mann heads some 15 of the 42 companies which fall under the Emera umbrella, including NSPI.
[115]
Without having any substantive evidence to support the reasonableness of Mr.
Mann’s current compensation level in relation to his duties and responsibilities with NSPI, the Board
can only conclude that the ratepayers are being asked to bear compensation costs, a significant
portion of which are primarily for the benefit of the shareholders of Emera. It is clear to the Board
that Mr. Mann, as President of NSPI, is ultimately responsible for the operations of the Company.
However, the Board is left with the impression that much of Mr. Mann’s time is spent on the
activities of Emera and its 42 affiliates. Accordingly, in the absence of any evidence to the contrary,
the Board will disallow one-half of the cost of Mr. Mann’s compensation which has been included
in NSPI’s revenue requirement.
[116]
The amount included by NSPI in the test year revenue requirement for Mr.
Mann’s compensation is $607,000 being 73% of $832,000. Reducing this by 50% represents a
disallowance of $303,500. In view of this disallowance, the Board will make no further adjustment
on account of Mr. Mann’s compensation as a result its findings with respect to incentive
compensation.
[117] The Board wishes to reiterate its earlier point that the Board of Directors of
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NSPI can pay whatever level of compensation it wishes to the employees of NSPI. This Board’s
only concern is the level of compensation which is reasonable to charge to the ratepayers of the
regulated Utility.
[118] When ratepayers are asked to bear the brunt of dramatically increased
compensation costs, as is the case in this proceeding, NSPI should be prepared to offer compelling
evidence that the amounts proposed are justified and it is reasonable to expect them to be recovered
from ratepayers. NSPI bears the burden of proof to demonstrate that costs are fair, reasonable and
justifiable in these and other areas. This burden has not been discharged with respect to executive
compensation.
4.5.3.2
Incentive Compensation
[119]
The Board has heard no evidence which persuades it that ratepayers should
bear 100% of the cost of incentive compensation. As Mr. Huskilson stated when questioned by
Counsel for the Province as to how customers benefit from incentive compensation paid to NSPI
employees:
A.
Well, I think, first of all, it's important to look at the efforts of employees as not just
being for shareholders, but as being for all of the stakeholders of the company. And
it's very, very hard to distinguish between stakeholders of an organization, so you
can't say that the success of the organization only goes to shareholders because a
lot of the success of the organization goes to customers as well. As an example, in
keeping rates the same between 1996 and today, that success of the organization
which, in part, was driven by incentives to employees to work hard at that activity
certainly was to the benefit of customers. And so from a conceptual perspective, we
have a hard time understanding how you separate the benefit that the different
stakeholders get from the company, so starting with that. The way that the bonus
programs, as they exist today, benefit all stakeholders of the organization are that it
causes employees to have a stake in the success of the organization, so employees
don't get, automatically, their total compensation. They only get the compensation
when they work hard, they meet goals and they meet objectives which work well for
all stakeholders. At the end of the day, if you're talking about an employee being
compensated, we're going to have to compensate that employee to the level that it
takes to retain that employee. And we believe that it's very important that a part of
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that compensation be at risk for that employee and that that employee have to meet
significant goals in order to be able to get those incentives. And so it's an important
part of our strategy to get employees pulling in the direction of all stakeholders,
which includes customers and shareholders and the general public.
Q.
A.
So you do not agree that shareholders are the primary beneficiary of these
incentives.
It's absolutely impossible to separate one stakeholder in the operation of a company
or an organization. If the company is successful, all stakeholders in that
organization benefit from that.
(Transcript, April 24/02, pp. 484-486)
[120]
The Board agrees that both shareholders and ratepayers benefit from a well-
run utility. The Board further agrees that it is difficult to quantify the benefit and, for that reason,
reaffirms its earlier decision that an equal division of incentive compensation is the most appropriate
method of allocating this cost. Accordingly, NSPI’s 2002 test year expenses are reduced by
approximately $1.58 million. This amount was determined by reducing the total incentive
compensation costs of $3.5 million by the amount of Mr. Mann’s incentive compensation and
applying a factor of 50% to the remainder.
4.6
Operating, Maintenance and General Expenses (OM&G)
4.6.1 Submission - NSPI
[121]
NSPI is projecting increases in its operating, maintenance and general
expenses (OM&G) budget as follows:
Operating, Maintenance and General (OM&G)
These expenditures cover labour and the various goods and services consumed in the
operation of the utility. Costs for 2002 of $166 million are expected, an increase of $2.1
million or 1.3% from 2001 estimated costs. Increases in projected OM&G for 2002, relate
primarily to increased labour and benefits costs. Detailed OM&G account analysis is
included
in
Appendix
1.
(Exhibit N-1, pp.16-17, original filing)
[122]
NSPI did not address specific cost cutting measures in its direct evidence. The
following cross-examination of Mr. Huskilson by Counsel for Annapolis is instructive:
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54
Q.
A.
Q.
A.
Q.
A.
Q.
A.
Q.
A.
But where you're seeking a high increase, do you not feel it's incumbent upon you to
be as rigorous as possible in curtailing your costs to the minimum?
Well, I think -- I mean, many people have asked the question as to why we are in -why we're in the middle of the test year with this application. One of the reasons is
the delay that's occurred. The other reason is that we were working very hard at the
end of last year in trying to find ways of not having to come forward with an increase.
But at the end of the day, the markets were such that we were unable to not have to
do that. But we have traditionally worked hard to make that happen, and we
continue to do that. I might just correct another point in that the 8.9 percent is not
unprecedented. Certainly in the history of this regulated utility, there have been
times when the price went up higher -- more than 8.9 percent.
But it is your position that in putting forward this application, NSPI has curtailed all
avenues -- or has explored all avenues available to it to curtail pending.
What I would say is that as a utility and as a supplier, we work hard to control our
costs and we have methods and mechanisms inside our organization that do that
and that have done that successfully through the years. We continue to work in the
same way.
Would you agree that you've exhausted your cost containment avenues?
As I said, at the end of last year, we were working hard to try not to come forward for
this filing, but we were unable to do that. We were overtaken by the coal markets,
foreign exchange situations.
So is that a yes, you have exhausted all your cost containment avenues?
Yes. We have worked hard on the costs and we have our costs -- we believe that
the costs we're putting forward as part of this revenue requirement are the proper
costs for this test year.
Mr. Huskilson, I detect you pulling your punches a little bit in the response. You're
not prepared to commit to having exhausted the cost containment avenues?
No. I would commit that we have in fact worked hard on our costs and we have our
costs in as good a shape as we can get them for this period.
(Transcript, April 23/02, pp.286-288)
[123]
Further explanation was provided in the following exchange between Mr.
Huskilson and the Board:
Q.
A.
When Mr. Grant was asking questions the other day he asked about whether or not
NSPI has explored all avenues to curtail expenditures, and I just would like to get -- I
realize some of these things have already been talked about, and I apologize for
that, but just going to Appendix 1, the OM&G section, and I'd just like to go to look at
page 12 of 49, for example. These are just examples. And we see on there line 13
"Contracts." Contracts up by two hundred and fifty-eight -- and I'm looking at
Forecast 2002 contracts is line 13 -- contracts up by two hundred and fifty-eight
thousand dollars ($258,000), 131 percent. And I was just wondering how do you -when you do these budgets, how do you ensure that expenditures are as low as they
possibly can be?
Well, the first thing we do is we benchmark ourselves against ourselves and against
others, and we -- and based on those bench-marks we set targets for each one of
the pieces of the business. And the way we judge whether or not someone who's
managing a budget has the budget in good shape and has done a lot of work to
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ensure that they've got their costs where they should be, and they've taken every
effort, we measure it against those targets that we set. And if they have a number
that's better than the target that we've set, based on bench-marking and various
different ways that we do that, then we say that they've done a good job and that they
have done everything they could do. And if they don't meet that target, then we work
on that budget and we help them to see lower costs. And so that's a very -- that's a
constant process inside our company. We've been doing it very aggressively in the
latter half of the '90s, and as has been seen in the documentation that's shown up.
And when we compare ourselves, big picture, with other utilities, we find that it is
true, we have a very good cost structure based on those kinds of costs. And so we
don't apologize at all for the costs that we have in those categories because they are
at the top of the heap in North America.
(Transcript, May 23/02, pp.3428 - 3430)
[124]
Mr. Huskilson was further questioned by the Board on the issue of reducing
expenditures as follows:
Q.
A.
So you don't really know, then, whether or not number by number it's possible to
achieve reductions or hold the line or lesser increases than are already showing
here?
I wouldn't say that. I would say we do know, based on our experience with this
business, based on the benchmarking we've done, and based on the work we've
done with people on cost conservation, we know that they have done a good job to
pull these together. Is every line analysed by a senior manager in the company?
No. That's not the way we run the business. But we do know that, over time, we
have achieved significant efficiency gains and those gains have been achieved by
this approach. And so we don't want to change that approach because that's -- we
will have different results then, and they probably won't be as good as the results
we've achieved.
(Transcript, May 23/02, pp. 3435-3436)
4.6.2 Submissions - Intervenors
[125]
Many of the intevenors and individuals who filed written comments with the
Board (and those who appeared at the evening session and at other times during the proceeding) take
issue with NSPI’s claim that it has exhausted all cost-cutting avenues in arriving at its test year
expenses. These customers argue that NSPI cannot simply pass along increased electricity costs in
the magnitude requested to its customers without clearly demonstrating that every reasonable costcutting measure has been exhausted.
[126]
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Annapolis, in its closing submission, argued:
56
The proposed rates do not meet the regulatory objectives of public acceptance and stability.
A substantial and important segment of the rate-paying public does not perceive the
proposed rates to be fair. Especially under these circumstances, it is submitted that NSPI
has an onus to demonstrate that the proposed rates are justified; that they will provide no
more than a fair return on the rate base after covering only those expenses which are
reasonable and prudent and properly chargeable.
(Annapolis, Closing Submission, p.3)
What is clear is that while NSPI asserts that all avenues to reduce costs have been pursued,
they do not do a line by line analysis of every expenditure, preferring instead to let
department managers determine how budgeted money is to be spent. (Transcript, Redden,
p. 296, Huskilson, p.3436).
On a line-by-line basis, NSPI would only examine variances of $200,000 or more pleading it
took too much effort to analyse at a greater level.
(Transcript, Redden, pp.297-298)
It is respectfully submitted that with the approach taken by NSPI, in the absence of a strict
critical analysis of the individual line items, neither the Board nor the ratepayers can
determine satisfactorily whether NSPI can reduce the total expenditures by a significant
amount.
(Annapolis, Closing Submission, pp. 40-41)
[127]
HRM also objects to the level of expenses for NSPI, stating that:
At a point in time when power rates threaten industry, and when 51 linesmen are being laid
off which has to impact outage response times, and when customers are complaining about
service levels, it does not appear to be a just and reasonable expenditure in addition to
providing leading executive compensation, to be paying travel expenses in the amount of
$220,000 for the 6 executive team members together with training and development fees
annually averaging $10-15,000 each.
A further reduction of $100,000 reducing executive travel and conference expense from
$300,000 to $200,000 would appear to provide a just and reasonable level of expenditure for
this item.
(HRM, Written Submission, pp.23-24)
In its 1996 decision the Board held:
The Board considers that the considerations which persuaded it to disallow
the company’s charitable contributions from revenue requirement are
equally applicable to sponsorships and grants to universities in support of
scholarship programs.
NSPI has identified a total of $717,100 in Sponsorships & Donations in its revenue
requirement spread across various division. With its response to undertaking U-16 NSPI has
agreed that 73% of $120,000 budgeted for Sponsorships & Donations in Corporate Human
Resources should be deleted.
HRM submits that it appears the label employed by the accounts, contrary to the suggestion
of Chris Huskilson, correctly describes the application of the funds in this category. At a point
in time when NSPI’s application for rate increases seriously threatens the jobs of Stora
employees, the wisdom of “donating” money through sponsorships to the Homebuilders
Industry Partnership and TIANS, for example, has to be seriously questioned as to whether it
is just and reasonable. Particularly when one of the reasons given is that it provides
exposure to the organization, an organization that has all the exposure it requires as a
monopoly.
(HRM, Written submission, pp.30-31)
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ECANS, in its written submission, makes the following observation:
[128]
Page 2 of 49 of Appendix 1 provides contains[sic] other information that further paints a
disappointing and unsettling picture for Nova Scotia electricity ratepayers. In particular they
are:
Line item
Description
Amount
$
011
Travel Expenses
220,000
041
Meals & Entertainment
91,000
056
Training and Development
80,000
Total
391,000
During cross examination, NSPI panel members confirmed that, except for minor amounts
set aside for support staff, this money is meant for five (5) Executive Management
employees. On page 2704 of the transcript, Ms. Redden describes these items as being
below their $200,000 variance line and Undertaking U-69 simply confirms what was already
suspected. Simply put, these individuals are accustomed to a lavish and comfortable level of
self-treatment, well above what the vast majority of their customers can afford and what
should be considered as reasonable for these employees to do their jobs. These line items
amount to an additional $78,200 (i.e. $391,000 / 5) in annual discretionary spending for each
of these individuals. ECANS does not believe these spending habits would survive a ‘used
and useful’ test. If this type of thinking is pervasive at the top of the organization, it may
permeate elsewhere. One final comment on this subject is prompted by statements made by
Mssrs. Huskilson and Taylor (see page 2706 of the transcript) where they describe how the
costs of larger management meeting are included under these line items. If that were the
case, then Ms. Redden and her staff should have provided sufficient evidence to that effect.
(ECANS,Closing Submission, pp.25-26)
[129]
MEUNSC has recommended to the Board that the OM&G expense analysis
should be expanded “... to include common ground comparisons for the entire time frame between
rate applications.” MEUNSC also points out that NSPI has not had a depreciation review since the
time of the last rate filing. It argues that failure to do periodic reviews on a $100 million expense “. .
. is simply another example of NSPI’s arrogant approach to regulation and its customers, and another
example of mis-management.”
[130]
MEUNSC further comments that:
Every assurance must be obtained that the level of expense in this category is prudent,
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58
necessary and does not involve discretionary spending that sends the wrong message to rate
payers. Here again, an independent review rather than the trust-me approach adopted by
N.S.P. may be warranted. Changes in corporate structure and lack of data make an
inflationary type analysis over the time frame since the last rate application impossible.
Expansion of the line-by-line analysis to include comparisons, on a common ground, since
the last rate filing may be appropriate.
(MEUNSC, Final Brief, p.50)
[131]
SEB, in its closing argument, made the following recommendation:
The Board should undertake, in future, a continuous review of NSPI’s expenses with a view
to ensuring that NSPI pays adequate attention to cost reduction opportunities.
(SEB, Closing Submission, p.7)
[132]
SEB further comments that:
Stora Enso/Bowater did not take up the question of NSPI’s expenses in any detail, in contrast
to many of the intervenors. But that is not to say that we do not believe that a close
examination is essential, and indeed we support those intervenors in their efforts. The key
point from Stora Enso/Bowater’s point of view, is that NSPI has not succeeded in putting
forward a convincing case that it has paid adequate attention to cost reductions. In our view,
the Board must itself be vigilant in the matter of expenses, and Board staff must ensure at all
times that NSPI’s expenses are kept to the absolute minium. We therefore urge the Board to
adopt a proactive stance with respect to expenses, not only in the current hearings, but in
future months and years.
(SEB, Closing Submission, p.60)
4.6.3 Findings
[133]
The Board has significant concerns with respect to whether NSPI has reduced
corporate expenses to the fullest extent feasible and whether there are adequate controls on spending.
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[134]
The Board’s authority in this area is found in Sections 42(2) and 45(1) and
(2) of the Act which are set out earlier in this decision. The difficulty faced by the Board is that there
is simply insufficient information available to determine whether the expenses outlined in Appendix
1 of Exhibit N-1 are appropriate to be charged to ratepayers and are as low as prudently possible.
NSPI is requesting ratepayers to bear these and other costs through a significant increase in
electricity rates. It is, therefore, incumbent on the utility to satisfy the Board, through the public
hearing process, that ratepayers’ money is wisely and frugally spent. No such assurance is evident
from the information which has been filed.
[135]
Further, the Board is concerned that NSPI’s internal budgeting procedures are
not sufficiently thorough to ensure expenses are as low as possible. This is illustrated in the
following exchange between Counsel for Annapolis and the NSPI panel:
Q.
A.
Q.
A.
Q.
Can I go back to the question I asked a minute ago? When you prepare your
budgets on a group-by-group basis, is there any examination of the costs on a lineby-line basis to determine whether or not there can be savings effected, or do you
simply look at the bottom line on a group-by-group basis?
(Huskilson) And the answer would be that we do both. So for a group that would be
asking for more resources in a year, then we would be -- we would look at those
resources very carefully. In the case of this particular group you're talking about,
they're actually asking for less resources in this year, and so we probably would -from a corporate perspective, we would scrutinize their costs less, but we would
expect that the manager involved and that the people involved in those lines would
be scrutinizing those lines. But as Zeda said, on a line-by-line basis, we would be
looking to scrutinize costs at a two hundred thousand dollar level. That's the way
that we've looked at it from a corporate perspective. And also, if a group is going up
in costs, that's one thing. If they're going down in costs, then that's another. And so
those are parts of how we would look at it. But certainly every manager in the
business is responsible to manage their line by line.
I'm a little confused by the answer. Are you saying that for costs of two hundred
thousand dollars ($200,000) or less, you do not look to effect savings?
(Huskilson) No. I think what we said was that we have not explained in the
line-by-line variance costs that are under that threshold, and so that the level of
explanation that we've done, as you said, in the notes, is at that level. Inside the
business, however, each of the managers is responsible to manage their line items,
and they're responsible to manage those to the best of their ability.
Just to complete the line of thought, since line 26 of page 8 of Appendix 1 does not
give true comparables for previous years, can you provide the true comparables as
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A.
an undertaking?
(Redden) We could undertake to do that. I would note that that's a relatively small
amount,
a
hundred
and
eighty
thousand
dollars
($180,000).
(Transcript, April 23/02, pp.299-300)
[136]
The Board believes that it is incumbent on NSPI management to be able to
demonstrate that it has made every effort to operate on a cost efficient basis when it seeks to increase
electric rates in Nova Scotia. Intervenors have raised valid questions concerning certain expenses.
NSPI has not provided an adequate response. As a result, the Board is not satisfied that NSPI
management has made every reasonable effort to eliminate unnecessary expenses.
[137]
Further, the Board understands that a "benchmarking" process is utilized by
NSPI in setting overall spending levels. While this is a useful procedure, it should not be used to the
exclusion of other methods of determining the appropriate level of expenses, including a careful and
exhaustive review of NSPI’s operating expenses in an endeavour to ensure that it is operating as
efficiently as possible.
[138] With respect to NSPI’s inclusion of sponsorships and donations in its test year
expenses, the Board sees no reason to vary from its ruling in 1996 where the Board stated that:
. . . In its 1996 budget the Company proposes to spend a total of $158,000 on
“sponsorships” under its Public Affairs budget and $69,000 in support of scholarship
programs at Nova Scotia universities. The Company states that its sponsorships in the
Public Affairs area “support the corporate involvement at the community level, and are
designed to build a favorable corporate image”. Sponsorships in 1995 included various
Chambers of Commerce, the G-7 Conference, the Camp Hill Ski Challenge and the Art
Gallery of Nova Scotia. The Board considers these sponsorships and the general
scholarship program to be analogous to the corporate donation issue which the Board
addressed in its decision on the Company’s 1993 rate application. The Board said in that
decision:
“In the case of a monopoly utility the customer cannot go to another company if dissatisfied
with the utility’s spending decisions. Many regulators consider that there is no relationship
between a utility’s discretionary spending on donations and the level and quality of customer
service. The spending on donations in effect becomes an involuntary tax on the customers”.
The Board considers that the considerations which persuaded it to disallow the Company’s
charitable contributions from revenue requirement are equally applicable to sponsorships and
grants to universities in support of scholarship programs. While these programs may
enhance the Company’s corporate image, they do not directly benefit customers and the
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61
customers have no say in the choice of sponsorships. The Board will accordingly reduce the
Company’s revenue requirement by $227,000.
(NSPI Decision, P-868, pp.23-24)
[139]
Accordingly, NSPI’s test year expenses relating to sponsorships and donations
are disallowed. Exhibit N-21 lists the various items included in the "Sponsorships and other
Donations" category. The impact on the revenue requirement is $717,100 less the related amount
billed to affiliate entities. This reduces test year expenses by a further $635,800.
[140]
The Board’s concern in this regard goes beyond the present filing which
projects NSPI’s 2002 test year expenses. It appears from this rate proceeding that while overall
OM&G costs have not increased appreciably in the six years since the last rate hearing, certain
corporate expenses have increased significantly. The Board notes that there are no studies, evidence
of internal management reviews, or details of cutbacks on OM&G expenses on file with the Board.
The Board believes there is a pressing need to demonstrate that cost reductions at NSPI affect the
higher levels of the company as well as lower levels.
[141]
In view of the Board’s concerns in this regard, the Board has determined that
NSPI shall undertake a detailed review of the current level of OM&G expenses and submit a report
to the Board which demonstrates that NSPI is operating as cost-efficiently as possible. After
examining the report, the Board will determine if a further study is required. If further action is
required, the Board may appoint an independent consultant to perform the study.
[142] The Board also directs NSPI to provide, on an annual basis, a detailed
analysis showing executive management expenses, including compensation, expenses, memberships
and other personal benefits including loans. Only then can the Board be satisfied that expenses are
“...reasonable and prudent and properly chargeable...” in accordance with Section 45(2) of the Act.
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4.7
Depreciation Expense
4.7.1 Findings
[143] NSPI forecasts depreciation expense of $102.8 million for the 2002 test year,
an operating expense category exceeded in size only by fuel and purchased power and operating,
maintenance and general. NSPI last filed a depreciation study with the Board for approval in August,
1995. It was based on data as at December 31, 1994. In response to UARB IR-213, NSPI advised
that it normally undertakes depreciation studies as part of a general rate application. However,
“...due to the lead time required to complete the study, NSPI has not proposed any changes to its
depreciation rates as part of this application”. At the hearing, Ms. Redden advised that NSPI had
contacted a number of depreciation consultants and that they all indicated that a study would take
more than the two months available. The Board considers that NSPI’s depreciation rates should be
reviewed more frequently than once every seven years. NSPI is directed to retain an external
depreciation consultant and to file the consultant’s report with the Board for review not later than six
months from the date of this decision. The Board recognizes that NSPI predicts that its depreciation
expense is likely to increase as a result of the review and that NSPI’s current composite depreciation
rate (2.72%) is lower than the equivalent rate for most Canadian electric utilities (Undertaking U-71).
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5.0
CAPITAL STRUCTURE AND RATE OF RETURN
5.1
Capital Structure
5.1.1 Submission - NSPI
[144]
NSPI seeks to increase the common equity component of its capital structure
from 35% to 40% for the test year with the ability to increase this portion to 45% over time. In its
direct evidence NSPI states that:
... a higher equity ratio is required to ensure that the capital markets continue to exhibit the
confidence that they have demonstrated over the last several years. (Exhibit N-1, p.28)
[145]
NSPI’s expert witness, Richard Falconer of CIBC World Markets,
testified that:
The current capital structure, which allows for 33% to 35% common equity... is inappropriate
given the higher risks the Company is now facing. An increase in the common equity
component to a range of 40 to 45% and a subsequent decrease in the debt and preferred
share components would result in a capital structure more in line with NSPI’s “A” rated peer
group.
(Exhibit N-1, Falconer, Direct Evidence, p.15)
[146]
NSPI’s expert witness, Kathleen McShane of Foster and Associates, a U.S.
based consulting firm, stated in her direct evidence that:
NSPI’s proposal to increase its common equity ratio to 40% is consistent with its business
risks and the objective of maintaining debt ratings in the A category.
With a common equity ratio of 40-45% in the test year, NSPI would be considered by the
equity markets to be of average investment risk relative to its Canadian peers.
(Exhibit N-1,McShane, Direct Evidence, p.2)
[147]
In December, 2001, subsequent to the filing of direct evidence by NSPI, Mr.
Falconer and Ms. McShane, Standard & Poor’s lowered NSPI’s long-term corporate credit rating and
senior unsecured debt rating to "BBB+” from "A -". NSPI submits that the current capital structure
is inadequate to achieve an "A" credit rating and that a "BBB" rating is "neither optimal nor in the
long term desirable". It further submits, inter alia, that "BBB" rated companies may not be able to
raise debt with terms longer than 10 years and that the downgrade is likely to adversely affect both
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64
the "...availability of bank financing and its costs".
[148] The impact on revenue of the proposed changes to capital structure was
outlined in NSPI’s responses to Annapolis IR-23.1, MEUNSC IR-25 and Undertaking U-12. These
responses can be summarized as follows:
·
·
Increasing the equity component from 35% to 40% results in an increase in
the required revenue of $3.3 million.
Increasing the equity component from 35% to 45% results in an increase in
the required revenue of $11.6 million.
[149]
The Board questioned Ms. McShane as to whether arriving at the appropriate
capital structure involves a qualitative assessment as opposed to a quantitative one:
A.
I don't disagree with the comment that there is no formula for determining the
appropriate capital structure and it is in some measure a qualitative assessment. I
think that we are helped with the information that we do have provided by other
companies who have capital structures tested by the market in the sense that you
can look at different companies with different capital structures and other financial
parameters and see what bond ratings have been granted to those companies, so
you have a good sense of at what cost they can raise debt.
(Transcript, May 14/02 p.2175)
[150] Counsel for NSPI introduced a number of decisions which showed that certain
Canadian jurisdictions allowed higher equity ratios than those recommended by Drs. Roberts and
Kryzanowski, the Province’s expert witnesses. Exhibit N-62, a decision of the Newfoundland Board
of Commissioners of Public Utilities, allowed an equity component for rate making purposes of
45%. In addition, the legislated minimum ratio for Maritime Electric is 40%. Drs. Roberts and
Kryzanowski also confirmed that Exhibits N-65 and N-66 show business profiles, as measured by
Standard and Poor’s, for Consumers Gas and TransCanada Pipeline of 2 (out of 10 with 10 being the
most risky) as compared to 4 for NSPI, as shown in Exhibit N-47. NSPI’s Counsel also pointed out
that TransCanada Pipeline recently applied to the National Energy Board to increase its common
equity component to 40% from 30%. Drs. Roberts and Kryzanowski were asked whether by raising
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65
the equity component to 40% NSPI could expect to see a reduction in the cost of debt:
62.
Q.
A.
A.
63.
Q.
A.
5.1.2
Would you agree that if NSPI's capital structure is changed to allow a
40-percent common equity that there will be a reduction in the cost of debt
because of lower financial risk?
(Kryzanowski) Yes, that's right.
(Roberts) Yes, I would agree.
Okay. And would you agree, all things being equal, that a return on
common equity on a 40-percent capital structure would be slightly lower
than at 35 percent?
(Roberts) A return on common equity at a 40-percent capital structure
would be slightly lower, yes, I would agree.
(Transcript, May 15/02, pp.2268-2269)
Submissions - Intervenors
[151]
In their direct evidence, Drs. Roberts and Kryzanowski suggest that NSPI is
not facing any more risk than in 1996, when the Board approved a maximum common equity ratio of
35%. They conclude that:
Accordingly, that ratio will continue to serve NSPI well in the test period.
(Exhibit N-58,p.48)
Drs. Roberts and Kryzanowski further testified that an equity component of 35% is
reasonable compared to the actual and allowed ratios for other integrated electric utilities
and is reasonable in the light of past decisions of the Board. They further compared this
level with a number of gas utilities. In Schedule 5 of their direct evidence (Exhibit N-58),
the average common equity ratio for five gas utilities was calculated as 36.44%. In total,
six estimates of equity ratios were considered by Drs. Roberts and Kryzanowski with an
overall range of 33% to 37%, leading to their final recommendation of the continued
appropriateness of 35%.
[152]
During questioning by the Board, James Rothschild, a U.S. based financial
expert retained as a consultant to Board Counsel stated that, in his opinion, a 40% common equity
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66
ratio is desirable, but only if the parent company, Emera, has a similar ratio. Emera’s capital equity
ratio as at December 31, 2001 was 35.6%. It is Mr. Rothschild’s view that if NSPI increases its
common equity ratio, with no corresponding increase in the common equity ratio of Emera, there
will be no improvement in NSPI’s bond rating. This opinion is set out in his direct evidence as
follows:
... The higher common equity ratio of NSPI should only be used for ratemaking purposes if
the consolidated capital structure of Emera is increased to at least 40% as well. Until both
these changes occur, the proper capital structure to use for regulatory purposes is the actual
capital structure of NSPI as I have proposed. The extra cost associated with the higher
common equity ratio is only justifiable if that cost increase is offset by declines in both the
cost of equity and the cost of debt. The cost of debt only declines for NSPI if the common
equity ratio is actually increased to 40% by both NSPI and Emera.
(Exhibit N-73, pp. 7-8)
[153]
Mr. Rothschild indicated that with a lower debt rating, the next time that NSPI
goes to the market it will incur a somewhat higher interest cost. However, he indicated that:
... they're still investment grade, and I don't think there needs to be any undue concern about
the bond rating.
(Transcript, May 16/02, p. 2568)
[154]
When questioned by MEUNSC, Mr. Rothschild commented on the relative
importance of a deemed capital structure versus an actual capital structure from the viewpoint of
credit raters:
Q.
A.
Good morning, Mr. Rothschild. I, too, have only one question, and my question is -and it seems to be implied by what you've said this morning that if NSPI and, in your
argument, Emera, were to move to 40 percent equity rating by retaining earnings,
and were still receiving a regulated rate of return on the basis of a 35 percent
weighting, it's your belief that the bond markets would recognize the increased
portion of equity over time with a lower or better bond rating?
The actual capital structure of NSPI and Emera has a far greater influence on the
bond rating than what the Board allows. Said another way, if the Board were to set
rates based upon a 40 percent common equity ratio, and Emera and NSPI
maintained 35 percent, it would do very little to help the bond rating.
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Q.
A.
So the bond raters are looking at the real number, the actual —
They're looking -- yes, they're looking at not only what the real number is now, but
what they expect the real number to be. And that's not just capital structure. It's
covered ratios and so on. And I don't mean -- I don't want to mislead you in that, that
other things being equal the larger the profits the company earns, the higher the
coverage ratios will be. But, the impact on the coverage ratio from a somewhat
higher allowed return on equity is far less than the impact on the coverage ratio of an
increase in the equity ratio.
(Transcript, May 16/02, pp.2514-2515)
5.1.3 Findings - Capital Structure
[155]
After considering all the evidence and submissions respecting an appropriate
capital structure for NSPI, the Board finds that there is insufficient justification to increase the
common equity component from its present level of 35% to 40% at this time. The Board
understands the benefits which could flow from an increase in the common equity ratio. However,
the Board also accepts Mr. Rothschild’s view that without a corresponding increase in the common
equity ratio of NSPI’s parent company, Emera, there will likely be no overall benefit accruing from
an increase in the common equity level of NSPI. As noted above, Emera’s common equity ratio at
December 31, 2001, was 35.6%.
[156] The Board has seen no evidence to indicate that Emera is prepared to make a
similar increase in its common equity ratio. Accordingly, the Board directs that the common equity
level of NSPI remain at 35% for rate-making purposes. This will reduce the revenue requirement by
$3.3 million. The Board would indicate that it has no objection to NSPI increasing its actual equity
ratio in the future to 40%. However, at any future rate hearing, the Board will determine what equity
ratio is appropriate for rate-making purposes. At that time, among other things, the Board would
consider the level of equity in Emera.
5.2 Rate of Return on Equity
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5.2.1 Submission - NSPI
[157]
Based on the recommendation of its expert witness, Ms. McShane, NSPI
requests that the Board approve a return on common equity of 11.0% for the purpose of setting rates,
with the ability to earn up to 12.0%. This represents an increase from the current allowed return
range of 10.50% - 11.00% approved by the Board in its 1996 rate decision and an increase in the
earnings band to 100 basis points. Rates were set in 1996 on the basis of a return on common equity
of 10.75%.
[158]
In her direct evidence, Ms. McShane said that:
a 100 basis point range better recognizes the potential volatility of returns from year-to-year
and creates a more symmetric potential to earn above and below the allowed return.
(Exhibit N-1, McShane, Direct Evidence, p. 77)
[159]
She submitted that:
NSPI should have the same opportunities as other utilities to earn returns above the allowed
return. Most utilities in Canada subject to traditional rate of return regulation are not required
to refund earnings above the allowed return.
(Exhibit N-1, McShane, Direct Evidence, p.78)
[160]
The impact on revenue of the proposed changes to the allowed rate of return
on equity was set out in NSPI’s response to MEUNSC IR-25 and Undertaking U-12, and can be
summarized as follows:
·
Increasing the rate of return on equity from 10.75% to 11.0% results in an increase in
the required revenue of $2.0 million.
·
Increasing the rate of return on equity from 11.0% to 12.0% results in an increase in
the required revenue of $14.0 million.
[161] Ms. McShane used three tests to arrive at her recommended range: the equity
risk premium method, the discounted cash flow method (DCF) and the comparable earnings method.
In applying the risk premium method, she estimated the risk-free rate at 6% for the 2002 test year.
Using three separate risk premium approaches, she concluded that the risk premium analysis
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69
indicated a risk premium of 4.25%, for a cost of equity of 10.25% before any adjustment for
financing flexibility. Using the constant growth model, she applied the DCF test to a sample of U.S.
electric utilities and derived a cost of equity of 11.1% to 11.3%. She added a 50 basis point
financing flexibility adjustment to provide compensation for flotation costs. She applied the
comparable earnings test to samples of Canadian and U.S. low risk industrials and concluded that the
fair return based on the comparable earnings tests is in the range of 12.0% to 13.0%. After
considering the results of these three approaches, Ms. McShane recommended a rate of return on
equity of 11% to 12%.
[162]
In its post-hearing brief, NSPI addressed the following points concerning the
testimony of Drs. Roberts and Kryzanowski:
The CAPM results are subject to considerable variation, depending on the periods chosen for
estimation of the risk premium. It is submitted that Drs. Kryzanowski and Roberts were
selective with respect in their choice of time period to measure historic risk premiums. For
purposes of their evidence they concentrated on the 1957 to 2001 data because data prior to
1957 is not available for the TSE index.
(NSPI, Post-Hearing Brief, p.
33)
They do acknowledge that data for the Canadian equity market is available prior to 1957 and
at page 69 of their testimony calculate an equity risk premium of 5.5% for the period 1948 to
2001. However, they lower the risk premium they calculate by excluding the first 3 or 4 years
after the war, claiming that period was unusual.
NSPI believes the recommendation of these witnesses is unreasonable on its face and
should be disregarded. A return of just over 8% is equal to a risk premium of less than 1%
over NSPI’s cost of debt.
(NSPI, Post-Hearing Brief, p. 34)
NSPI would also reiterate the point made earlier that the Province’s witnesses did no kind of
evaluation to see if their recommendations were compatible with maintaining the company’s
financial integrity. Their recommendations would allow NSPI to achieve interest coverage
consistent with debt ratings in the junk bond category. In NSPI’s submission, acceptance of
these witnesses’ recommendations would be financially disastrous to the Company, its
bondholders and equity shareholders.
(NSPI, Post-Hearing Brief, pp. 35-36)
5.2.2 Submissions - Intervenors
[163]
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In their opening statement, Drs. Roberts and Kryzanowski recommended a
70
rate of return on common equity of 8.20% as opposed to the 8.02% they originally recommended in
their pre-filed evidence. Their recommendation is based upon their application of the equity risk
premium test. Drs. Roberts and Kryzanowski did not use the DCF method used by Mr. Rothschild
and Ms. McShane, or the comparable earnings test used by Ms. McShane.
[164] In his cross-examination of Drs. Roberts and Kryzanowski, Board Counsel
asked why they did not use the DCF method. They stated that, in their view, the DCF method has
two problems, that of circularity and obtaining an accurate growth forecast.
[165]
In his opening statement, Mr. Rothschild summarized his recommendation
that, assuming a 35% equity ratio, an appropriate rate of return on equity would be 10.15%. He
further stated that if NSPI’s equity ratio were to increase to 40%, his recommended rate of return
would drop to 9.95%. A further increase in the equity component would result in a further lowering
of the rate of return on equity. His recommended level of 10.15% was based on a recommended
equity cost of 9.75% and a capital structure risk adjustment of 0.40%.
[166]
Mr. Rothschild did not use the comparable earnings approach and he stated
that this approach is not valid since it does not address the cost of equity. Instead, it simply
considers the returns on book equity that were achieved without testing whether these returns were
higher or lower than necessary.
[167]
In his direct evidence Mr. Rothschild also addresses the methodology used by
Ms. McShane in her DCF analysis:
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Summarizing, the major problem with Ms. McShane’s Discounted Cash Flow (DCF) cost of
equity computation is that she applies the DCF Method as if investors not only expect shortterm analyst forecasts to be accurate in the short-term, but also somehow applicable in the
long-term. Ms. McShane’s analysis implies that investors believe the average return on book
equity (ROE) for her selected group of comparative electric companies will keep increasing
forever. Ignoring her inappropriate stretching of short-term forecasts to the horizon, her DCF
method is mathematically invalid because it is not indicative of the expected growth in
dividends, stock price, or book value even over the next five years. This large mathematical
error is repeated in the portion of Ms. McShane’s risk premium based methods that rely upon
her DCF method.
(Exhibit N-73, p.8)
[168]
Under cross-examination, Mr. Rothschild indicated that the DCF method is
the most common method used in the United States for calculating return on common equity:
Q.
A.
Would you agree -- even if others don't, but would you agree that the discounted
cash flow method is a method favoured in the United States in calculating return on
common equity?
That is very easy. Yes.
(Transcript, May 15/02, p.2414)
[169]
In responding to a question from the Board, Mr. Rothschild further discussed
the difference between his approach and that of Drs. Roberts and Kryzanowski:
Q.
A.
Okay. I think based on the evidence that we have an understanding why -- or first of
all, I guess I should say you're in the middle. Your recommendations are in the
middle between the Province's experts and Ms. McShane for the company. And I
think we have an idea why your recommendations are lower than Ms. McShane's. I
wonder if you could just summarize why your recommendations are higher than the
experts for the Province.
Yes, I can do that. I give primary weight to the DCF method. And that's not because
I haven't given significant weight to risk premiums in the past. My concern is that
right now, a risk premium method is understating the cost -- or let me say a properly
applied risk premium method. I've seen people even today who find ways to have
the risk premium approach come up with too high results by doing things like using
the arithmetic average. But a properly applied risk premium will understate the cost
of equity because of the flight to quality that is prevalent today with the combined
fears of heightened world tensions both relating to the terrorism and the ongoing
problems in the Middle East, and always uncertainty when there's a recession.
Things are starting to look better in terms of hopeful -- a recovery from recession,
but those things tend to create a flight to quality, and when that happens, you can get
a temporary distortion in risk premiums. When you implement a risk premium
method the way most people do it, and I believe the way all of the witnesses in this
case have done it, you're looking to historic relationships so that you can add a risk
premium to today's cost of debt, which is great and very helpful, but only work so
long as today is reasonably representative of what was the historic situation. And I
think it's just hopefully temporarily out of balance.
(Transcript, May 16/02, p.2553)
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5.2.3 Findings - Rate of Return on Equity
[170] The Board has considered the evidence of Ms. McShane, Drs. Roberts and
Kryzanowski and Mr. Rothschild. The Board believes that the rate of return on equity should be set
at a rate which fairly reflects the risk associated with an investment in NSPI. In the Board’s view,
the rate of return of 10.15%, as recommended by Mr. Rothschild, most fairly meets that test.
[171] The Board believes that the rate of return advocated by Drs. Roberts and
Kryzanowski is too low given the financial and business risks faced by NSPI and the current
economic environment. On the other hand, the level of return suggested by Ms. McShane is more
generous than warranted given the present economic environment.
[172] Accordingly, the Board sets the rate of return on equity at 10.15% for purposes
of setting rates. The Board continues to consider that it is useful to establish an earnings range,
which the Board sets at 9.90% to 10.40%. Setting the rate of return on equity at 10.15%, has the
effect of reducing NSPI’s revenue requirement by $8,500,000.
5.3
Return on Rate Base
5.3.1 Findings
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[173]
In Exhibit N-1, NSPI included Table 3.5 which sets out the calculation of its
rate base and rate of return on rate base. It shows a projected rate of return on average rate base of
10.25% for the 2002 test year. The rate of return on rate base is derived from the financial forecast
and for the test year assumes a rate of return on equity of 11.0% and a 40% equity component. NSPI
has not asked for approval of a specific rate of return on rate base. The supporting details of the
calculation of rate of return on rate base as presented in NSPI’s Table 3.5 are reproduced below.
Table 3.5
Nova Scotia Power Inc. - Rate of Return on Average Rate Base
Years Ended December 31st
Millions of Dollars
Actual
2000
Forecast
2001
Present Rates
Forecast 2002
Proposed
Rates Test
Year Forecast
2002
Proposed Rates
(May 1st) Forecast
2002
Net Plant in Service
Less: Non Utility Plant
$2,312.9
5.5
$2,332.2
5.2
$2,333.0
4.9
$2,333.0
4.9
$2,333.0
4.9
NET UTILITY PLANT IN SERVICE
$2,307.5
$2,327.1
$2,328.1
$2,328.1
$2,328.1
Add:
Allowance for Materials & Supplies
Allowance for Working capital
85.3
18.0
96.7
19.3
95.8
24.1
95.8
24.1
95.8
24.1
103.3
116
119.9
119.9
119.9
2410.7
2443.1
2448
2448
2448
2392
2426.9
2445.6
2445.6
2445.6
245
249.3
187.3
250.7
233.6
10.24%
10.27%
7.66%
10.25%
9.55%
Total Additions
Rate Base
Average Rate Base
Excess of Operating Revenue Over
Operating Expense
Rate of Return on Average Rate
Base
U-2 provides discussion by NSPI on ROR and difference between rate base and total
capital.
U-5 shows difference between rate base & capital in table format.
(Exhibit N-1, Table 3.5)
[174]
In its post-hearing brief, NSPI points out that it has presented its financial
tables consistent with its presentation in its 1993 and 1996 rate applications. This Board, in prior
NSPI rate decisions, has based the revenue requirement for the test year on an allowed return on
equity. The Board’s focus has been a return on equity, and not return on rate base. Once the rate of
return on common equity is determined, it is possible to calculate the return on average rate base.
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[175] The Board directs that NSPI, as part of the required Compliance Filing set out
in Section 7 of this decision, recalculate the return on average rate base taking into account the
adjustments made to test year revenues and expenses as a result of this decision. Following a review
by the Board, including any modifications which may be necessary, the Board will issue a final Order
which, among other things, will approve the rate of return on average rate base.
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6.0
AFFILIATE ACTIVITY
6.1
Code of Conduct - PricewaterhouseCoopers Report
6.1.1 Submissions
[176] In its direct evidence, NSPI states that:
On December 2, 1998, NSPI shareholders approved a proposal to reorganize NSPI to create
a holding Company structure. One month later, on January 1, 1999, all NSPI common
shareholders exchanged their shares for NS Power Holdings Inc. (“NSPHI”) common shares
on a one-for-one basis. In June 2000, NSPHI was renamed Emera Inc. (“Emera”). NSPI
continues as a wholly-owned subsidiary of Emera.
As a consequence of this new structure, the Board approved the NSPI Code of Conduct on
an interim basis on March 16, 2001, effective September 16, 2001. The Board ordered that
the Interim Code is to remain in force until a final Code of Conduct is approved by the Board
in a future general rate hearing.
The Code, provided at Appendix 5, provides an effective framework to govern utility/affiliate
activity. Key elements of the Code include the following:
...
Statement of Principles - 1) NSPI will neither subsidize, nor be subsidized by an affiliate’s
current or prospective activities and 2) Competition in markets where NSPI’s affiliates are
active will not be impaired by non-market behaviour by NSPI.
...
NSPI believes the Code as approved by the Board provides an effective balance between
appropriate regulatory oversight and pursuit of affiliate efficiencies and growth opportunities.
The reporting mechanisms in place will provide the Board with a thorough insight to NSPI
activity. We are not, at this time, seeking any modifications to the Code. As part of this
general rate application, we request the Board finalize its approval of the NSPI Code of
Conduct.
(Exhibit N-1, pp.64-65)
[177]
The development of a Code of Conduct was initiated between the Board and
NSPI in light of the increasing number of NSPI affiliates and the potential impact of their activities
on NSPI ratepayers. As noted above, the Interim Code, attached hereto as Appendix C, became
effective on September 16, 2001.
In preparation for the rate hearing, the Board engaged
PricewaterhouseCoopers (PWC) to review NSPI’s compliance with the Interim Code and, as well, to
recommend any changes which should be made to the Code before receiving final approval by the
Board. The PWC report drew the following conclusions:
1.
2.
The Code is generally effective in its primary purpose of ensuring that the customers
of NSPI are not harmed by transactions between NSPI and its affiliates.
There are two areas that we believe require refinement to be compliant with the
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3.
Code.
These are:
Establishment of a fair method for allocating corporate support services
costs; and
Establishment of fair market values for transactions with affiliates.
Management at NSPI is making significant efforts to comply with the spirit of the
Code although we note there are other minor areas in which compliance is not
absolute.
(Exhibit N-19, p.2)
[178]
PWC expanded upon its conclusions as follows:
Significant Findings and Recommendations
As noted, our major findings are around the allocation of corporate support services costs
and the fair market value of transactions with affiliates.
These findings and
recommendations are:
1.
We believe that the current method used by NSPI to allocate corporate shared
services costs does not appropriately measure the amount of specific services being
provided to or being used by its affiliates. We recommend that NSPI review
alternative methods of allocating its corporate shared services costs that directly
relate to the amount of the service utilized or the effort expended. We expect that
different allocation methods will be used for different types of costs. We do not know
if NSPI is in compliance with Section 6.11 of the Code as we do not know the
amount of the adjustment to the costs allocated to the affiliates that would be
required if these alternative measures were used.
2.
We believe that NSPI is in compliance with Section 6.8 of the Code with respect to
the sale of steam to Strait Energy as fully allocated cost is appropriate in the
circumstances. However, we believe that in keeping with the spirit of the Code, an
attempt to determine the fair market value of these transactions should have been
made.
3.
We do not have enough information to determine if NSPI is in compliance with
Section 6.8 of the Code in respect of its sale of energy to Emera Energy Inc. At
issue is the splitting of total margin on the resale of this energy of [redacted]. It is
currently split [redacted]. NSPI management has indicated that the agreement to
allocate the margin is temporary and that work on developing a pricing methodology
is ongoing.
4.
We recommend that, where the fair market value for affiliate transactions is not
readily determinable, NSPI introduce the transfer pricing methodologies
recommended by the Organization for Economic Co-operation and Development
(OECD) to determine fair market value for transactions with affiliates. This is of
particular concern in instances, such as those described in 2 and 3 above, where
NSPI produces the product that is delivered to the ultimate customer but where an
affiliate is between the customer and NSPI. Allocation of the earned margin between
NSPI and the affiliate should be based on established transfer pricing
methodologies.
[Exhibit N-19, p.5 (Deletions in original text)]
[179] During the hearing, NSPI vigorously disputed PWC’s findings concerning its
allocation process for purposes of sharing expenses with Emera.
[180] The following exchange with Board Counsel is illustrative:
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And there's a more elaborate discussion of that same point on pages 6 and 7. And I'm not
going to review that evidence, but my question to the panel is whether or not it is NSPI's
intention, in light of the PWC report, to change its method of allocating shared corporate
services costs.
(Huskilson) At this point the answer would be no.
(Transcript, May 22/02, p.3113)
(181) NSPI, in its post-hearing brief, states that:
While NSPI submits the Code is worthy of approval, if the Board is more comfortable
continuing interim approval pending further decision on affiliate transactions, NSPI would
accept that.
(NSPI, Post-Hearing Brief, p. 56)
[181]
During the hearing, NSPI advised that it was preparing a response to the PWC
report. NSPI filed its response as an attachment to its post-hearing brief. While NSPI stated its
fundamental agreement with the report, the following passages from its response are noteworthy:
In addition to the above, the Consultants’ report includes a number of finding[s] concerning
2002 transactions and process related recommendations upon which NSPI wishes to
comment. It is important to note that in discussing Code of Conduct processes within this
submission, NSPI has not changed its position that these are internal procedures directed
toward the achievement of Code compliance. As such they do not require or warrant UARB
approval. As affiliate relationships change over time, the Guidelines will be revised
accordingly. Consistent with this, where the recommendations of the Consultants concerning
Code processes are considered to contribute positively to Code of Conduct compliance,
these will be incorporated within the internal Guidelines.
The Board’s expectations concerning affiliate activity are clearly expressed within the terms
of the Code of Conduct. The scope of the Regulator’s oversight of this activity as outlined in
the Code’s provisions is broad and adequate to determine Code compliance. It must be left
to the Utility to develop the appropriate internal procedures to ensure the provisions of the
Code are met. NSPI management understands that should we fail to develop the necessary
internal processes to maintain compliance, the Regulator will respond.
Beyond these items, the Consultants also recommended a schedule of unadjusted
differences be appended to the Audit Report and management and post audit
correspondence involving the Code be filed with the UARB. NSPI believes these latter
recommendations to be inappropriate; in the case of the former, because it will tend to focus
compliance processes on relatedly immaterial areas and in the case of the latter because
expanding the audience of such correspondence beyond internal management may
negatively impact the value of the information in improving internal processes.
(NSPI, Post-Hearing Brief, Appendix B, pp.1-2)
[182] Intervenors, including HRM, MEUNSC, the Province and SEB, expressed
concern at the extent of NSPI affiliate activity and the potential for harm to NSPI and ratepayers
under the existing Interim Code. They urge the Board not to give final approval to the Code at this
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time.
[183] Annapolis, in its rebuttal submission, argued that:
In each of these transactions, there is a host of ways in which NSPI may be disadvantaged.
In many circumstances, the valuation placed upon services is subjective at best and involves
the application of a fair measure of judgement on the part of the individual assigning the
value. In view of the unlimited number of transactions in which NSPI may be involved with its
affiliates, the subjective nature of the valuations, and the effective inability or impracticality of
ratepayers challenging affiliated party transactions, we would submit that the Board refuse to
approve a Code of Conduct founded upon the principle that affiliated party transactions shall
cause no harm to the ratepayers. In our submission, the Board should direct NSPI to
prepare and submit to the Board a new Code of Conduct in which the principle is established
that NSPI shall not enter into an affiliated party transaction unless it is able to demonstrate
positively that the transaction will be of benefit to NSPI and its ratepayers.
(Annapolis, Rebuttal Submission, p.13)
6.1.2 Findings
[184] The Board notes that, according to Exhibit N-99, there are 42 companies
under the Emera corporate umbrella. These companies are affiliated with NSPI and, in some cases,
are involved in “shared services” with NSPI, (which will be discussed further in Section 6.3 of this
decision). According to the evidence, executives and other staff perform functions for NSPI and
affiliated companies.
[185] The Board is cognizant of the potential risk to ratepayers of unregulated
affiliate activities. The Interim Code was developed in order to institute a number of formalized
measures to protect NSPI ratepayers. The Board finds that the PWC report is helpful in that it
focusses attention on potential weak points in the existing Code. Likewise, the Board finds the
suggestion of Counsel for Annapolis, that the test for affiliate activity should be raised from “no
harm” to “demonstrate a benefit” to NSPI ratepayers, to have merit.
[186] NSPI witnesses acknowledged, when questioned by Counsel for Annapolis,
that transactions with affiliates are entered into on the basis that NSPI should realize a benefit, as
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indicated in the following passage:
Q.
A.
Do you think that any transaction between NSPI and Emera or an Emera affiliate
should contain a benefit to NSPI?
(Whalen) That's the general principle of the code, that there be a mutual sharing of
any benefits and there are guidelines in the code in terms of assessing that.
(Transcript, April 23/02, pp. 337-338)
[187] The Board finds that it is not appropriate, at this time, to give final approval to
the Interim Code of Conduct. There appears to be merit to the suggestion that Article 1.1 of the
Code be amended to require that affiliate transactions must demonstrate a benefit to NSPI ratepayers
as opposed to causing them no harm. The Board intends to retain independent consultants to review
the implications of such a change, and also to review the desirability of making further changes in
light of the recommendations contained in the PWC report, the evidence presented at the hearing,
and the findings of the Board in this decision.
[188]
The Board generally accepts the recommendations of the PWC report.
Additional Board comment on specific recommendations by PWC are set out later in this decision.
The Board agrees with PWC’s recommendation that NSPI’s external auditors should provide to the
Board a schedule of their unadjusted differences (i.e., a summary of immaterial errors or exceptions),
along with the annual audit report on compliance with the Code. In addition, the Board directs that
copies of management or post-audit letters issued by NSPI’s external auditors in connection with
their audit of NSPI’s compliance with the provisions of the Interim Code of Conduct be filed with
the Board by the external auditors. While the Board agrees with NSPI’s contention that individual
transactions may involve relatively small amounts, it believes that this issue goes beyond NSPI’s
materiality threshold. Disclosure of this information supports the fundamental principles of fairness
and accountability with respect to affiliate activities. The Board has no desire or intention to micromanage NSPI. However, at the present time, Emera appears to be in the process of transferring to
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various Emera affiliates a number of activities carried out by NSPI and the Board has concerns about
the fairness and efficacy of these transactions. Accordingly, the Board believes this reporting tool is
a helpful instrument in protecting the interests of NSPI ratepayers.
6.2
Emera Energy - Agency Agreement
6.2.1 Submission - NSPI
[189] During the course of the hearing, NSPI indicated that it intended to enter into
an Agency Agreement with its affiliate, Emera Energy, covering fuel procurement, export electricity
sales and gas sales. The transfer of these functions apparently took place in late 2001. In its
evidence, NSPI has identified $672,000 as the amount of fees to be paid by NSPI to Emera Energy
for the provision of fuel procurement services by Emera Energy during the test year.
[190] Mr. Huskilson advised that NSPI has engaged Dr. Jay Lukens, a Texas-based
consultant, to provide advice with respect to the Agency Agreement including its terms and
regulatory precedent for its implementation.
[191] Under cross-examination by Counsel for Annapolis, Mr. Huskilson described
how the agency agreement would work with respect to export energy sales:
Q.
A.
If more than 300GW of hours are generated, does NSPI participate in the excess
sales?
So I can't talk to you about the detail of that right now because it's not finalized, but,
in principle, NSPI will participate in any volume that gets sold. So if we sell at
traditional levels, so at what we call the five-year average, then NSPI will take in
about a million and a half dollars, which is what is in the current revenue
requirement. If we're able to exceed that, then the possibility exists that NSPI will
earn more than traditional levels. But, I might add that the one point five million
dollars ($1.5 million) is about three hundred thousand, three to four hundred
thousand dollars above what our traditional level of margin is on these sales.
(Transcript, April 24/02, p.415)
[192]
Under cross-examination by Counsel for Annapolis, the NSPI panel described
the status of the Agency Agreement at the time of the hearing as follows:
Q.
I want to turn to another topic. I understand that NSPI engages employees of
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A.
Emera to assist and advise in fuel purchasing.
(Taylor) The agency arrangement that we have with Emera Energy Services does
include advice on fuel purchasing.
Q.
A.
Okay. How long has that arrangement, agency arrangement, been in place?
(Taylor) The agency arrangement went into place in the fall of 2001.
Q.
A.
Is there an agreement documenting the terms of that agency agreement?
(Taylor) There is a -- there is an agency agreement, there is.
Q.
A.
Okay. Has that been filed with the Board?
(Taylor) Pardon me, Mr. Grant?
Q.
A.
Has that been filed with the Board?
(Taylor) Also it is a tentative draft agreement that is also part of the package that is
being reviewed internally subject to the consultant advice and is being built, so it's
not finalized yet.
Q.
A.
Okay. Is Emera Fuels --(Huskilson) The entire relationship, whether that be fuel procurement, export
energy, commodity trading, that whole relationship is all part of the agency
relationship. We've created -- as I said before, the process is we've created a
model, which is the one that Mr. Taylor was referring to. We've taken that through
an expert review. The expert review has made recommendations for some
changes, so we're making those changes. We now have this report, which is also
recommending some changes, so we're making those changes. And then that, the
output of all of those changes and the expert review, will be the final document. But
it's all one factor, whether it's fuel procurement, whether it's export sales, whether it's
-- or whether it's energy trading and financials that's all one relationship.
(Transcript, April 24/02, pp.417-419)
[193]
Mr. Taylor described Emera Energy’s activity in coal markets:
Q.
A.
How long has Emera been active in the coal market?
Emera Energy and Nova Scotia Power entered into a tentative agency agreement in
September of 2001. I believe that also -- though not certain because I don't know
the total dealings of Emera Energy -- that that would be when they started their coal
procurement activity.
(Transcript, April 29/02, p.1082)
[194]
While Mr. Huskilson and Mr. Taylor expressed the view that NSPI and the
ratepayers would derive a benefit through savings and expertise from using Emera Energy as an
agent for fuel procurement and to sell excess power, they also indicated a limited knowledge of
Emera Energy’s operations.
[195]
are informative:
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The following exchanges between Counsel for Annapolis and Mr. Huskilson
82
Q.
A.
Q.
A.
Q.
A.
Q.
A.
Well, let's come to that. On several occasions during the hearing, you've indicated
that you're not fully aware of what's going on inside Emera Energy. Correct?
Yes, that's correct.
And Emera Energy at the present time, although not under formal contract -- the
contract is being developed -- the agency agreement is being developed -- is NSPI's
fuel procurement agent.
Well again, we have to get into legal entities now. Emera Energy is the umbrella
company that holds all of those assets. It holds Emera Fuels, it holds Sable
Offshore, it holds Maritimes and Northeast. It is the development arm of the
business. And it holds Emera Energy Services.
(Transcript, May 23/02, pp.3196-3197)
And in part, that's what I was getting to, Mr. Huskilson. Fuel procurement -- we've
already been through this -- fuel costs is the driver in this application and certainly
fuel procurement has been made a key issue by a number of the intervenors. That's
correct?
It absolutely is, but as we've also said in the hearing, the strategy for fuel
procurement and the actual purchases of fuel are done by Nova Scotia Power.
Emera Energy Services acts as an agent, and that agency relationship is as we've
described it.
All right. But you -- let's be clear. You have touted Emera Energy -- and I'm just
using those two words now rather than Services or Inc. -- but Emera Energy as
having the expertise and having the ability to gather together that expertise to deliver
better fuel procurement service than NSPI could execute on its own. Having said
that, and given that fuel procurement is a key issue in this proceeding, we have
heard from no one who is intimately familiar with the details behind Emera Energy,
either Mr. Mann or anyone else. Isn't that correct?
Yes.
(Transcript, May 23/02, pp.3200-3201)
[196]
In the following response to questions from the Board, Mr. Huskilson
attempted to justify how NSPI, while retaining the final decision-making function relative to fuel
procurement, can realize cost savings by using Emera Energy as an agent.
A.
(Huskilson) The reason that it's less is because Emera Energy is doing it for less
than their cost. And the reason that they're willing to do that is because they have a
bigger business than our business, and that's [the] why. They can begin to employ
arms and legs of people where we could not. If we had a person, we had to have a
whole person. And so the cost efficiency of doing it for more people means that they
can do it for less money.
(Transcript, May 23/02, pp.3205-3206)
[197]
In its post-hearing brief, NSPI acknowledged that:
A number of questions about affiliate transactions were raised in the hearing. Because of the
evolving nature of the relationship between NSPI and, in particular, Emera Energy, NSPI was
not able to place before the Board a level of detail and precision about certain affiliate
transactions
which
the
Board
might
reasonably
expect.
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(NSPI Post-Hearing Brief, p.56)
[198]
NSPI further stated that:
With respect to the way forward on affiliate transactions and in particular the agency
agreement, NSPI has engaged expertise to advise on the appropriate structure for these
agreements. Clearly the matters noted above, among others need to be addressed. Also
NSPI will ensure that it can audit all transactions; that it obtains the market price for fuel and
that Emera Energy will have adequate risk management strategies in place.
Mr. Huskilson indicated that appropriate regulatory precedent and principle would be
identified and that those would be reflected in the agency agreement. Mr. Huskilson advised
that the agency agreement would be submitted to the Board. Preliminary research on behalf
of NSPI indicates that there are a number of instances among significant U.S. utilities of
regulated utilities having their acquisition of coal and other fuels managed by unregulated
affiliated trading companies, but this information is not on the record of this proceeding.
NSPI would propose to present it, together with information concerning any safeguards which
were considered appropriate in these situations, in connection with the filing of the agency
agreement. Mr. Huskilson made it clear that responsibility for the fuel procurement strategy
and final decision making on fuel purchases will stay with NSPI.
NSPI respectfully requests that the Board not take any final steps or make any final orders in
this proceeding that would have the effect of precluding potentially beneficial affiliate
transactions which are otherwise permitted by the Code. This would include delays in
establishing any principles such as those set out in Dr. Stutz’s additional evidence or making
final determinations on the appropriate fuel procurement configuration until the draft agency
agreement is completed and submitted to the Board.
(NSPI, Post-Hearing Brief, p.60-61)
6.2.2 Submissions - Intervenors
[199]
Of the intervenors who addressed the issue, all objected to NSPI’s proposed
Agency Agreement with Emera Energy.
[200]
Annapolis, through its expert witness, Ms. Medine, and in its written
submissions, challenged the notion that fuel procurement is not a core function of the Utility. It
further questions whether Emera Energy’s involvement in fuel procurement for NSPI is of value to
NSPI.
[201]
Annapolis asserts that:
Without question, fuel procurement is core to NSPI; it represents the single largest element
of NSPI’s variable costs. We learned through the hearing that not only is it being performed
by an affiliate, under an undefined relationship but that fees for services are being paid
without having established fair market value.
(Annapolis, Closing Submission, p.49)
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[202]
Further, in its rebuttal brief, Annapolis argues that:
The Board should recognize the potential as a consequence of the large number of affiliated
transactions proposed by NSPI, for it to lose regulatory control over a number of important
expenses incurred by NSPI.
No where is this more important than in the area of solid fuel procurement. This represents
the largest annual variable cost to NSPI and its ratepayers. As outlined in our post-hearing
submission, there are a number of reasons for which this function ought not to be outsourced to Emera fuels.
...
At this stage, outsourcing of coal procurement to Emera has not been proven to be
beneficial. NSPI has the sequence out of order. In our submission, it should have presented
a final Code of Conduct with the proposed nature of the transaction with Emera and
supporting evidence that it is of benefit to NSPI to the Board before embarking upon the
transaction. It is inappropriate, in our submission, for NSPI to urge the protection of the
status quo when the status quo has not yet received Board sanction.
In our submission, the significant risks and limited rewards associated with coal trading make
it unlikely for it to be beneficial to NSPI to enter into an affiliated party transaction with Emera
to undertake this work on its behalf. Footnote 85 at page 60 of NSPI’s post-hearing brief lists
a number of companies uncovered in "the preliminary research on behalf of NSPI" (which
was not in evidence before the hearing) of U.S. utilities having coal and other fuels acquisition
managed by unregulated affiliated trading companies. Even a cursory review of the lists
provided suggest that these companies are distinguishable from NSPI in size, diversification
and experience.
(Annapolis, Rebuttal Brief, pp.14-15)
[203]
ECANS, in its written submission, takes the following position:
One might argue that there is a silver lining in this matter - and it has to do with what agency
actually purchases fuel for the utility. During the Hearing, there were extended discussions
about affiliate relationships and why NSPI thought it best that Emera be contracted to take
over coal and other fuel purchases. ECANS could see a measured value in Mr. Huskilson’s
comments about Emera Energy having a ‘larger’ view of the North American energy
landscape and possessed a better overall understanding of the coal markets. However,
under later cross-examination by Mr. Outhouse, the question of risk associated with some
North American energy trading companies was explored. The Enron debacle, wash trades,
round trip trades and other undesirable activities alerted us to the fact that passing the job of
fuel procurement to Emera Energy brings with it a level of risk over which ratepayers would
have no influence. During this exchange of information, it became evident to ECANS that we
should express concern over who procures fuel for NSPI. We feel it will be in ratepayers’
interests if fuel procurement reverts back to an in-house activity, and with it a commitment by
the Company to fully train its fuel purchasing team.
ECANS recommends that:
1.
That as long as NSPI remains a regulated utility, coal procurement remain a direct
responsibility or business unit of NSPI
2.
The Board direct NSPI to develop a comprehensive coal procurement program to
ensure that solid fuel purchases are
optimized, minimizing risk to ratepayers
and shareholders.
(ECANS,
Closing
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Submission, p.9)
[204]
HRM reiterates this view, stating that:
HRM submits that given the risks associated with outsourcing fuel procurement, without
sufficient cost reduction benefits, it is in the public interest for the Board to take a
conservative approach and require NSPI to bring fuel procurement activities in-house.
(HRM, Written Submission, p.30)
[205]
SEB, whose closing arguments relating to coal procurement were filed in
confidence, also objected to the proposed Agency Agreement and the lack of stringent controls and
protocols surrounding multi-million dollar purchases.
[206]
Dr. Stutz filed supplementary evidence addressing the proposed Agency
Agreement between NSPI and Emera Energy. Dr. Stutz also referred to certain remarks by Mr.
Mann at the 2002 Emera Annual General Meeting.
[207]
Dr. Stutz’s supplementary evidence reads, in part, as follows:
Q.
A.
Q.
A.
-
Q.
A.
Has NSPI provided evidence justifying the development of an Agency Agreement
with Emera Energy?
No. In the course of cross Mr. Huskilson stated that Emera Energy has been able to
bring in expertise and build systems that could not be justified within NSPI.
However, there is no evidence concerning the incremental costs involved or the
specific type and value of the benefits Emera Energy will provide.
Do you have concerns about an Agency Agreement?
Yes, I do. There are limitations as well as potential conflicts and risks associated
with any such agreement. These include the following:
The Board’s ability to review all the activities of those involved in NSPI’s fuel
purchasing and gas and power sales will be limited.
After becoming a central part of NSPI’s operations, Emera Energy could develop
conflicts that preclude its continuation as NSPI’s agent.
Emera Energy’s unregulated activities could be quite risky. The Agency Agreement
will decrease NSPI’s insulation from these activities.
What sort of limitation might the Board face?
Mr. Huskilson’s lack of awareness of Emera Energy’s “internal workings” provides an
indication of the limitations the Board might face under an Agency Agreement. More
generally, as Ms. McShane indicated during her cross, regulators have less access
to unregulated affiliates then they do to regulated utilities.
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Q.
A.
What conflicts might arise?
As Mr. Mann stated in his remarks, [2002 Emera Annual General Meeting] Emera
Energy was formed to manage Emera’s non-utility investments and to lead Emera’s
business development. The activities might, for example, include use of the turbine
mentioned in the PWC report to generate electricity for sale to municipalities in direct
competition with NSPI, or the purchase and resale of gas in competition with sales
from which NSPI might benefit. The potential for conflict is broad because, as Mr.
Mann notes in his remarks, Emera Energy will offer all the services it provides to
NSPI to “other parties”.
Q.
A.
Please discuss the risks associated with Emera Energy’s activities.
As noted in Mr. Mann’s remarks, Emera Energy will include a “highly professional
trading entity which levers off our existing businesses”. In a recent article, Dr. Jay
Lukens, the expert selected by NSPI to help develop the Agency Agreement,
discusses such unregulated trading activities. He observes that large sums of
money are being made and lost trading energy assets and commodities. He also
notes that utility trading affiliates have grown very rapidly. Recently the methods by
which some such utility affiliates have achieved rapid growth have become a source
of serious concern.
(Exhibit N-154, pp.1-3)
[208]
Further, Dr. Stutz pointed out that:
The area covered by the Agency Agreement is central to NSPI’s operations. It accounts for
54% of NSPI’s cost of operations and 38% of its requested revenues in the test year. In light
of the area’s importance and the limitations, risks and potential conflicts associated with an
Agency Agreement, the Board should seriously consider requesting that NSPI not pursue the
development of such an agreement.
(Exhibit N-154, p.4)
[209]
Dr. Stutz also recommended that should NSPI continue to pursue an Agency
Agreement with Emera Energy, certain principles governing the agreement should be instituted by
the Board. These are as follows:
1.
An Agency Agreement could increase the cost of procuring fuel, purchasing and
selling power, or reselling gas. To avoid this, test year costs should be limited to
NSPI’s net savings in the provision of services due to the agreement. It should be
NSPI’s burden to quantify and document the savings in question, netting out any
additional “oversight costs” created by the agreement.
2.
Margin sharing could transfer to Emera Energy margins on power or sales that NSPI
could have made on its own. To avoid this, NSPI’s revenues should include all test
year margins on power and gas sales, except when NSPI can show to the Board’s
satisfaction that a specific margin could not have been earned without Emera
Energy’s services. Only such additional margins should be shared with Emera
Energy.
3.
As noted earlier, an Agency Agreement creates risks for NSPI ratepayers. As
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compensation for assuming these risks, any additional margins should be shared
with ratepayers based on a split determined by the Board.
(Exhibit N-154, p.5)
[210]
In response to questions from the Board, Dr. Stutz stated that:
. . . What is certainly true is that as near as I can determine, NSPI is outsourcing to Emera
and to others because it feels it can run the company in a more cost-effective way doing that.
So I take that as a given. What concerns me is that the outsourcing of the fuel function
creates limitations on your oversight, conflicts about which we won't know until it's too late to
really deal with them effectively, and risks which are very hard to anticipate. And I don't think
that those issues have been given due weight. Any of those issues could swamp the benefits
that we see in day-to-day efficiency. Let me give you my two examples of how things get
swamped. My first example is California. The thing that's forgotten about the California
regulatory experiment is that it worked splendidly for a number of years before it went directly
into the dumper. And so you could set up a system and run it and have it work efficiently. In
fact, there's an article which appeared contemporaneously with the incredible run-up of
California prices written by one of the officials who oversaw deregulation in California
extolling California as the model for the world of successful deregulation. They were just hit
by a train they didn't see coming. Now, let me give you the example that's perhaps a bit
closer to home. I'm sure when the CEO of Consumers Power was setting up their trading
subsidiary, he told people that it was going to be a boon to the company. Well, he resigned
over that. I mean, it was a disaster for the company. And it's that kind of very large risk that
you're creating that concerns me. I mean, just imagine the following scenario. We have
Emera Energy involved intimately in the middle of a fuel procurement, something goes
haywire in Emera Energy's other trading activities, there's a blowup similar to the wash
trading blowup that we just saw in the U.S., senior officials depart from Emera Energy, there's
some massive financial problem in Emera Energy. What kind of attention do you think your
fuel procurement is going to get? Those are the kind of concerns I have. And I just don't
think we can know how dangerous those risks are. You know, it's very well to say, "We'll
have good financial controls. We'll do this. We'll do that." You can always deal with the
problems you've seen in the past. The problem is we keep seeing new problems.
(Transcript, June 4/02, pp.3992-3994)
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6.2.3 Findings
[211]
The Board is troubled by the Agency Agreement between NSPI and Emera
Energy.
[212]
Fundamentally, the Board is concerned that a major portion of NSPI’s fuel
procurement activity, which the Board views as a core function of the Utility, representing a huge
portion of NSPI’s total costs, has been effectively transferred to an unregulated affiliate with no
notice, regulatory approval or formal documentation by way of contract. This is despite the fact that
in the Board’s opinion, fuel procurement, gas sales and export electricity sales could well be
considered as undertakings of NSPI. Section 62 of the Act reads as follows:
Approval for transfer of undertaking
62
Notwithstanding the provisions of any Act of the Legislature, no public utility shall
sell, assign or transfer the whole of its undertaking or any part thereof to any person
or corporation except with the approval of the Board first had and obtained.
[213]
The Board notes that in Undertaking U-102 NSPI has declined to provide its
legal opinion on a confidential basis in this matter, while indicating that further “information” will be
forthcoming.
[214]
The Board finds that the manner in which NSPI has conducted itself with
respect to the Agency Agreement is not in keeping with the spirit and intent of the utility regulatory
regime in this Province. The Board is of the view that the parent company of NSPI wishes to transfer
to Emera affiliates many functions and activities which are carried out by NSPI. The Board is
concerned that these activities could lead to a reduction in income to NSPI, thereby resulting in an
increased burden on its ratepayers.
[215]
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The Board’s concerns are heightened because it appears that NSPI is
89
embarking on a course of action without having fully considered its ramifications. An example is
NSPI’s request to transfer the Shell gas contract, at no value, to Emera Energy. The contract, along
with Dr. Lukens’ justification for its transfer, was provided to the Board some considerable time
after it was initially requested. When the Board issued formal information requests (which, among
other things, questioned how NSPI could justify transferring the contract to Emera Energy with no
value attributed), no response was forthcoming from NSPI. Instead, the Board learned for the first
time at the hearing that the request to transfer the Shell contract to Emera Energy had been
abandoned. The Board’s concerns are further exacerbated by the inability of the NSPI witnesses to
answer questions concerning the details surrounding the operations of Emera and its affiliate
companies.
[216] There are a number of reasons to have reservations about the Agency
Agreement. Since no document was available to the Board during the proceeding, the intended
terms of the agreement were unknown. Similarly, in the Board’s opinion, there is little or no
reliable evidence in this proceeding that NSPI would benefit as a result of the agreement. NSPI
justifies the estimated $672,000 in fees to be paid to Emera Energy in 2002 by submitting that,
because Emera Energy performs these services, NSPI’s costs are lower than they otherwise would
have been. The difficulty arises when one attempts to quantify this “benefit” without knowing
whether NSPI’s fuel procurement division was as efficient as possible prior to divestiture.
[217] NSPI’s suggestion that coal costs could be lowered through volume discounts
available to Emera, but not NSPI, was ably refuted by Ms. Medine. While clearly reluctant to
contradict his client, NSPI’s own coal expert, Mr. Watkins, was unable to fully endorse this
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90
proposition in his evidence before the Board.
[218]
Moreover, NSPI’s confidential Undertaking U-90, which lists the “other
customers” of Emera Energy, does not give the Board confidence that NSPI will benefit from
participating in Emera Energy’s purchasing pool.
[219]
Quite apart from NSPI’s inability to demonstrate cost savings as a result of the
Agency Agreement, there are valid concerns that the potential exists for Emera Energy and NSPI to
have conflicting interests. As pointed out by Dr. Stutz, the potential also exists for Emera Energy to
compete with NSPI:
As Mr. Mann stated in his remarks, Emera Energy was formed to manage Emera’s non-utility
investments and to lead Emera’s business development. The activities might, for example,
include use of the turbine mentioned in the PWC report to generate electricity for sale to
municipalities in direct competition with NSPI, or the purchase and resale of gas in
competition with sales from which NSPI might benefit. The potential for conflict is broad
because as Mr. Mann notes in his remarks, Emera Energy will offer all the services it
provides to NSPI to “other parties”.
(Exhibit N-154, pp.2-3)
[220]
The Agency Agreement seems to reflect a pattern of transactions whereby
activities previously performed by NSPI are transferred to affiliates. These transfers are not the
subject of competitive bids. It is unclear whether the affiliates can perform the tasks better than
NSPI since no evidence is forthcoming from the unregulated entities. This has been the case with the
sale of steam to Strait Energy; the aborted transfer of the Shell contract; the buy-back of refurbished
transformers; as well as the Agency Agreement with Emera Energy.
[221]
The Board also notes the qualifying comment made by NSPI’s auditors in
their report to the Board concerning their review of affiliate transactions:
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Significant Interpretations
We have audited the compliance of Nova Scotia Power Inc. (NSPI) for the period of
September 16, 2001 to December 31, 2001 with the criteria established and described in the
NSPI Interim Code of Conduct (the “Code of Conduct”) dated March 16, 2001 with the Nova
Scotia Utility and Review Board. Compliance was evaluated within the framework of
significant interpretations determined by NSPI’s management and summarized below.
Fair Market Value of Emera Energy Transactions
NSPI currently sells power to Emera Energy using a sharing mechanism that management
believes represents fair market value.
(Exhibit N-99, Ernst & Young Report)[Emphasis added]
[222]
In the Board’s view, fair market value cannot reasonably be established on
such a subjective basis. This arrangement is unsatisfactory as it is open to abuse.
[223] After considering all of the evidence concerning this matter, the Board is not
satisfied that, given the present structure of NSPI and Emera, ratepayers will be adequately protected
from Emera’s apparent intention of levering off NSPI for the benefit of Emera shareholders.
[224]
Accordingly, the Board disallows all fees paid by NSPI to Emera Energy in
the test year for fuel procurement services, export electricity sales and gas sales as being imprudent.
Furthermore, the Board directs that NSPI resume full responsibility for its own fuel procurement,
export electricity sales and gas sales which the Board considers to be core functions of NSPI and an
undertaking of the Utility pursuant to Section 62 of the Act. There may be some point in the future
when it would be prudent for these functions to be out-sourced, but this is neither an appropriate
time, nor are these appropriate circumstances to consider doing so. No information or evaluation of
Emera’s ability, performance and track record relative to other service providers is available to the
Board and there are valid concerns relating to risk, conflict and harm to ratepayers should these
functions be performed by an affiliate.
[225]
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To the extent that there are costs to NSPI associated with this directive, the
92
Board finds that such costs are as a result of the transfer of an undertaking of the utility without the
required approval of the Board. Under the circumstances, the Board does not believe it is reasonable
for the ratepayers to shoulder this expense.
[226]
The Board also directs NSPI to engage the services of experts in the area of
fuel procurement, especially coal, to develop in-house fuel procurement expertise, formalized
policies and procedures governing fuel purchases. The Board finds Ms. Medine’s evidence
particularly helpful in its deliberations in this matter. Although the Board will not quote directly
from evidence given during in camera sessions, suffice it to say that the Board shares Ms. Medine’s
view that neither NSPI nor Emera appear to have proper procedures or practices in place to control
and govern annual coal purchases of approximately $200 million. NSPI is further directed to report
to the Board on the status of its in-house fuel procurement division and policy and procedures
development within six months of the date of this decision, and to provide a follow-up report six
months later.
[227] The Board further directs that prior to the future transfer of functions which, in
the opinion of the Board, could constitute an undertaking of the utility, NSPI must receive the
approval of the Board.
[228] On October 8, 2002, NSPI filed, on a confidential basis, a copy of an executed
"Agency and Surplus Energy Purchase and Sale Agreement" between Emera Energy and NSPI.
NSPI has not requested approval of the Agreement and takes the position that none is required. As is
apparent from the foregoing, the Board disagrees. Further, the Board is not satisfied on the evidence
that any fees or commissions paid by NSPI to Emera Energy pursuant to the Agency Agreement are
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reasonable or prudent in the circumstances and, accordingly, such fees will not be chargeable against
ratepayers.
[229] Based on the information available to the Board this will result in a reduction
of at least $672,000 in the revenue requirement. The Board directs NSPI to provide, as part of its
Compliance Filing, all fees paid in the test year by NSPI to Emera Energy with respect to fuel
procurement services, export electricity sales and gas sales in order for the Board to determine the
precise amount to be disallowed as a result of this ruling.
6.3
Shared Services Allocation
6.3.1 Submission - NSPI
[230]
NSPI uses the “four-factor” allocation method to determine the portion of the
cost of services shared with its affiliates to be borne by NSPI. The method is described by NSPI’s
auditors in Exhibit N-99:
Management has adopted the four factor allocation method to allocate its Corporate costs to
all companies within the Emera consolidated group. The four factor allocation method uses
an average of the pro-rata percentage of Emera’s consolidated assets; revenues; operating,
maintenance and general expenses; and earnings before interest and taxes.
(Exhibit N-99, Ernst & Young Report)
[231]
In Exhibit N-1, NSPI states that:
... NSPI has adopted a simple, understandable and cost effective approach to cost allocation
in accordance with the Code of Conduct. The Company has used an allocation methodology
using an average of the pro-rata percentage of Emera’s consolidated assets, revenues,
OM&G and earnings before interest and taxes. Similar approaches have been used by other
utilities in North America.
The total pool of corporate costs that are projected to be allocated using this approach are
$16.0 million and $18.6 million in 2001 and 2002 respectively. The increase is driven
primarily by increased labour costs and the full year impact of filling positions vacant for a
portion of 2001.
Using this approach, NSPI will be charged 83% or $13.3 million of the corporate support
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costs in 2001. In 2002, this percentage will fall to 73% ($13.6 million) as more companies
join the Emera group (in particular Bangor-Hydro) and the cost of corporate support services
is shared across a broader base.
(Exhibit N-1, pp.20-21)
[232]
NSPI witnesses have argued that this formula is simple, effective and time-
saving as opposed to other methods such as time allocation. In its post-hearing brief, NSPI asserts
that:
While there are many different ways to allocate cost NSPI submits the current four factor
method is as good as any and is similar to that used elsewhere in North America and more
importantly results in a fair allocation of corporate costs. Indeed, this methodology is
frequently resisted by utilities on the grounds that it attributed too much cost to the non-utility
elements of the company.
Utilizing a differing allocation basis for various corporate support groups may result in a
different measure than currently identified, but this does not equate to a more “accurate”
allocation of costs. By definition, much of the time spent by senior executives are truly joint
or common costs of the whole enterprise. They are not uniquely attributable to any segment
of the business, and allocations are necessarily arbitrary. Further, executives are not
professionals or consultants who are compensated on the basis of hours spent. Rather, they
are compensated on the basis of the responsibilities which they bear, and the proposed
formula is a reasonable proxy for those responsibilities and a reasonable allocator of
executive cost.
The simplicity and transparency of the current method of cost allocation outweighs any
benefit NSPI believes which may be obtained from changing the costing methodology as
noted by Ms. Redden.
. . . It is submitted that one must step back from the issue and determine how much time,
effort and cost should be “allocated" to allocating $18,000,000 worth of corporate costs. Ms.
Redden specifically notes the impact of consultant’s recommendations with respect to human
resources and accounting. If the PwC recommendation were implemented more cost for
those
departments
would
be
allocated
to
NSPI.
(NSPI, Post-Hearing Brief, pp.43-44)
6.3.2 Submissions - Intervenors
[233]
Annapolis, in its closing submission to the Board, objects to the cost
allocation methodology used by NSPI, asserting that:
It is submitted that the allocation methodology should be of concern to the Board. While
NSPI trumpeted that the percentage of shared cost is declining for NSPI in relation to the
overall costs of Emera in 2002 from 2001, in fact the actual cost to NSPI is increasing by
approximately $300,000. It is however very difficult to track the increased costs due to
changes in structure of the entities, changes in responsibilities and movements of personnel.
It is submitted that the lack of transparency regarding shared services should be of concern
to the Board and, it is recommended that another “fair” allocation methodology be adopted to
track
actual
time
and
effort.
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(Annapolis, Closing Submission, p. 59)
[234]
HRM, ECANS and the Province also object to NSPI’s current cost allocation
methodology.
[235]
PWC, in its report, stated that it did not believe the “four factor” allocation
method was fair, noting that:
... We do not believe that the measurements used provide a fair basis for the allocations.
The following are examples of where the allocations may not be fair:
New and growing businesses (e.g., Emera Energy) typically require more
management time than mature businesses (e.g., NSPI). The formula’s focus on
revenues and income actually gives the reverse impact with relatively high
allocations to the mature businesses.
The formula does not deal with unusual transactions. For example, the acquisition
of Bangor Hydro and the investment in the Sable Offshore Energy Project in 2001
would undoubtedly have taken significant amounts of senior management, general
counsel and treasury/finance time. This is not reflected in the formula.
We would have anticipated that NSPI would have been allocated a relatively small
amount of Emera executive management costs as NSPI has its own executive team
in place. This does not appear to be reflected in the formula.
We understand that NSPI wants to implement a formula-driven approach as it believes that
the overall dollars to be allocated are relatively small and it wants a simple solution.
(Exhibit N-19, p.6)
[236] PWC recommended that:
... NSPI and Emera review and implement alternative methods of allocating its corporate
support service costs. We believe that the methods chosen should relate to the amount of
the specific service being provided to or being used by each entity. We believe that this will
result in different measures being used to allocate different costs.
(Exhibit N-19, p. 7)
[237]
Dr. Stutz said the following when asked by the Board to comment on NSPI’s
use of the “four-factor” methodology for cost allocation:
... I understand the convenience of the formula and I understand that it may be a
widely-accepted formula. I've spent 25 years in the accounting -- in the consulting business,
and during those 25 years I've accounted for my time hour-by-hour each week and I've never
found it burdensome, I've never found it to interfere with my business operations. I routinely
take recent college graduates and in the space of about a quarter of an hour explain to them
how to fill out the form required to do that. So, I don't see a direct assignment as
burdensome. Now, admittedly I'm not dealing with an organization which is at the scale of
Nova Scotia Power, so scale may be an issue to consider there, but my personal experience
is it's not a problem. My sense from talking to people who work in large law firms is they
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96
don't find it a problem either and they have software that makes it quite easy, as do we.
There is an issue of fairness, which I think is raised in the PricewaterhouseCoopers report. I
would think it would also be useful to the Board to have some clear understanding of who's
spending how much time doing what for whom, and direct assignment, were you to be able to
audit that at some point, would give you that kind of information. So, if that's of interest to
you, that might influence the methodology you choose as well.
(Transcript, June 4/02, pp.3921-3922)
6.3.3 Findings
[238]
There are two issues to be determined in reviewing NSPI’s cost allocation
model. Firstly, is the “four-factor” method the most fair and reasonable approach? Secondly, is it
fair to apportion 73% of 2002 corporate costs to NSPI?
[239]
With respect to the first point, the Board agrees with PWC that the current
method may result in unfairness. The ratepayers currently bear the risk of the potential for unfairness
as some senior management members are engaged in fostering new businesses on behalf of Emera
while NSPI ratepayers bear the lion’s share of corporate costs.
[240]
The Board is of the opinion that, with respect to senior management, properly
documented time allocation is the most appropriate method to determine how costs should be shared.
This is the best way to demonstrate that ratepayers are only charged for effort expended on their
behalf in respect of NSPI functions.
[241]
In reaching this conclusion, the Board recognizes NSPI’s comments regarding
the relative materiality of the amounts involved. Again, the Board is of the opinion that the
principle is more important than NSPI’s materiality threshold. NSPI ought to be able to demonstrate
fairness to the ratepayers in the manner in which it conducts its affairs. It may well be that
executives are inconvenienced in pursuit of fairness. In the Board’s view, the requirement for
fairness and accountability overrides any inconvenience.
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[242]
The Board expects that senior management of NSPI generally plan in advance
their daily activities, and the recording and allocating of such activities should merely be an
extension of their daily planning. Accordingly, the Board directs NSPI to proceed to implement a
cost allocation method, to be in place for the year 2003, based on well documented time keeping
records for those senior management employees having shared responsibilities for NSPI and any of
its affiliates.
[243]
For those costs which cannot properly be allocated on a "time allocation"
basis, the Board accepts the recommendation of PWC that NSPI review and implement alternative
methods of allocating its corporate support service costs. The specific methods chosen should be
based on measures that are specific to the particular units, such as space, number of employees, etc.
Prior to the implementation of the specific allocation methods, NSPI should prepare a report and
submit it to the Board for approval. This report should also include a list of those senior
management employees who will be accounting for their daily time and activities. In view of the
Board’s direction to NSPI to modify the four factor methodology on a go-forward basis, the Board,
despite some misgivings, will accept the 73% allocation of shared costs for 2002.
6.4
Coal Transportation Costs
6.4.1 Submission - NSPI
[244]
The surface assets of CBDC, which were used to transport coal for NSPI, have
been acquired by an NSPI affiliate. While the future ownership of these assets is in question, NSPI
has included CBDC’s charges to NSPI for coal transportation as a proxy for test year purposes.
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Under cross-examination by counsel for Annapolis, Mr. Huskilson gave the following explanation of
the sequence of events involving the acquisition of these assets:
I guess, first of all, it's important to note that that is very critical infrastructure to the security of
supply of the system at the Lingan and Point Aconi plants and so we -- when we understood
that CBDC was closing those facilities from May, 2000 to 2001, we began to work with CBDC
to try to deal with what that was going to mean and how it was going to work. We really were
only informed in the fall that, in fact, CBDC was going to stop operating those assets by
December the 15th and so from early in the fall until December the 15th we had to act quite
quickly in order to secure the ability to operate those assets. In fact, the -- from a timing
perspective, the assets were abandoned by CBDC on December the 15th and had to be
operational again on January the 2nd to move coal to the plants and also to -- ultimately to
allow us to receive a ship, I think, on something in around the January the 14th date. So
there was a lot of work that had to be done to make that happen, a lot of logistics that had to
be worked through. So since it was critical infrastructure and certainly not something that the
utility was core to its responsibility anyway, we engaged one of our affiliates to do the work
necessary to be able to pull this together and to make it work. And so we transferred the
responsibility to pull that together to our utility -- or sorry, Emera Utility Service. They were
able to get the assets working on the January time frame and started an evaluation as part of
the agreement with CBDC of the value of the assets because that was not known until an
evaluation was completed. And we're in the process -- we have just concluded the evaluation
process as we speak and so now we're currently looking to bring these assets forward before
the Board to have the Board understand from an overall perspective what the cost is of
supply was critical in that case, we had to act quickly and ensure that these assets were
operational.
(Transcript, April 26/02, pp.962-963)
[245]
Mr. Huskilson also testified that CBDC had in excess of 100 employees
engaged in operating these assets. The following exchange between Mr. Huskilson and Counsel for
Annapolis describes the current relationship between NSPI, Emera Utility Services and the
contractors:
Q.
A.
Q.
And as part of the transaction, has NSPI offered employment to any of these 100
employees?
My understanding is that about 43 of those employees have now been employed to
do work on those assets and, as well, we’ve employed a number of different
contractors to do work as well, so there is a combination of contract work and direct
employees that are engaged in this activity.
A.
From the sounds of your last answer, it would seem that the labour charges to be
incurred by NSPI in operating these ground transportation assets would differ
substantially than those of CBDC.
Yeah. At this point, none of the employees actually work for NSPI. They actually all
work for the contractors engaged in doing this work and the transfer of the collective
agreements and the negotiation of the collective agreements was all done by the
contractors so, in fact, NSPI's relationship right now is an agency relationship.
Q.
Are any of these contractors affiliates of NSPI?
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A.
Yes. At this point, Emera Utility Services is still performing the function of overall
management of the facility and, again, that's something that we need to sort out as
we go forward. We've really just concluded an understanding of the -- a complete
understanding of the assets and a complete understanding of the value of the
assets, so that's all still to be sorted out. The critical nature of the assets meant that
we had to act very quickly because ensuring security of supply was the most
important very similar to the Emera Utility -- the Emera Energy situation where we're
in an ongoing, evolving relationship. The same thing is true here. It's going to be
important that we develop a relationship that works for the utility, that meets the code
of conduct and that allows us to do this in the most efficient way possible.
Q.
A.
When were the assets operational under NSPI?
With the agency relationship in place the assets went operational January the 2nd.
The assets would have been transferred from CBDC on December the 15th, I
believe.
Q.
And at present, is NSPI paying Emera Utility Services for its services in connection
with these assets at the same rate that it was remunerating Devco in the past?
Again, I'd say that we're in about the same situation with this as we are with Emera
Energy in that we have an agency relationship but we're evolving the cost because
we haven't actually understood exactly what we can get a cost. A very significant
question is what is the [demurrage] charge that will actually occur as a function of the
operation of these assets. When CBDC was operating them, we were paying almost
two and a half million dollars ($2,500,000) a year in demerge [demurrage] charges.
Emera Utility Services believes that they can substantially improve that number. And
so we're in the process of really working through what kind of costs we're going to
incur here. At this point, we've said that the best we know about it is that for, I think,
a slightly increased tonnage, we believe that we can operate the facilities in and
around the cost that was there from last year, and so the revenue requirement
includes that cost. But as we go through the year and as we go through our
circumstance, we'll understand better the cost of operating.
Who's paying the workers right now?
The workers are actually being paid by Logistech, which is a third party agent
engaged in the activity.
A.
Q.
A.
Q.
A.
Who's paying Logistech?
Emera Utility Services.
Q.
A.
And who's paying Emera Utility Services?
Nova Scotia Power is paying through the agency relationship.
(Transcript, April 26/02, pp.965-968)
[246]
Mr. Huskilson indicated that a request for Board approval for NSPI to acquire
these assets would be forthcoming along with updated information with respect to NSPI’s costs of
coal transportation as compared to CBDC.
6.4.2 Submissions - Intervenors
[247]
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MEUNSC notes in its rebuttal brief that:
100
On page 18, lines 17 and 18 [of NSPI’s Post-Hearing Brief], NSPI states that it has proposed
to deem the price recently paid to CBDC for rail and truck freight within Nova Scotia as an
arms- length price, for the purpose of “the regulated revenue requirement”. Given that under
the Contract with CBDC the ground freight was included as part of a price for coal that NSPI
vigorously disputed, to the point of withholding payment, and given the testimony of NSPI
witnesses on Devco inefficiencies and the Confidential evidence in the J. T. Boyd analysis, it
is difficult to accept that this price is a reasonable surrogate for a market price. Or that it is a
price that NSPI would willingly pay to a non-affiliated firm. If NSPI believes that the CBDC
transport price is fair and reasonable, they stand alone in this belief. Expert testimony by
both Ms. Hennings and Ms. Medine held that this cost was too high.
(MEUNSC, Rebuttal Brief, p.2)
[248]
ECANS states that:
ECANS objects to the assumption that previous CBDC transportation rates are deemed to be
in the best interest of ratepayers. For years, NSPI complained about the expensive, noncompetitive costs CBDC inflicted upon electricity users in this Province. But when an
opportunity presents itself for NSPI to eliminate this decades-old practice, it chose to set a
legitimate concern aside in favour of furthering the financial well being of an affiliate. If NSPI
had acted with its ratepayers in mind, these services would have been tendered thus
ensuring
best
value
for
money
and
least
costs
to
consumers.
(ECANS, Response to Final Submissions, p.3)
[249]
While SEB’s comments on the CBDC transportation assets are part of its
confidential filing, it, too, asserts that given the uncertainty regarding the ownership of the assets,
NSPI shareholders, not ratepayers, should bear the responsibility for these costs. SEB further argues
that by simply adopting CBDC’s high prices, NSPI has made no effort to control transportation costs
itself despite now having an opportunity to do so.
[250]
SEB’s expert, Ms. Hennings, suggested that a significant reduction in NSPI’s
coal transportation costs are warranted. Also, PWC notes in its report that:
NSPI indicated that it transferred the option to its affiliate, Emera Utility Services, for $10
consideration. We now understand that NSPI will apply to the Board to acquire these rail
assets but that the intent is that Emera Utility Services will manage the railway for NSPI.
No pricing has yet been set for this latter contract. We believe that the pricing should follow
either Section 6.8 or Section 6.9 in the Code of Conduct. Transfer pricing methodologies
may be employed to ascertain fair market value of these services. Caution should be used
before assuming that transportation charges from Devco represent fair market value. The
Devco contract was for both the supply and delivery of coal. Often, in multiple-element
contracts, the buyer and seller both look at overall price and not at the individually quoted
prices.
The transfer of the assets to NSPI will transfer most of the risks associated with establishing
a rail transportation business to NSPI and the ratepayers. We believe that any management
contract pricing should reflect this risk transfer.
We also note that the purchase option transfer from NSPI to an affiliate was not on the list of
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101
affiliate transactions nor was there any indication that fair market value of this option was
assessed. While we understand NSPI’s position that unregulated activities should be carried
on outside of NSPI, where those opportunities arise within NSPI, the Code of Conduct applies
to their movement.
(Exhibit N-19, p.23)
6.4.3 Findings
[251]
The Board notes the objections of the intervenors to the use of CBDC prices to
support NSPI’s test year estimate for coal transportation costs. The Board further notes that no
request of the nature described by Mr. Huskilson, supra, has been filed with the Board to date.
[252] The Board considers that it is not reasonable to use CBDC’s charges to NSPI
as representative of the test year cost of the transportation work formerly performed by CBDC. In
the Board’s view, it is reasonable to expect that NSPI or its affiliate should operate the surface assets
during the test year at a lower cost than CBDC did. Having reviewed the evidence and bearing in
mind the comments of PWC with respect to the appropriate fair market value of CBDC’s
transportation charges, the Board will reduce NSPI’s deemed expense for the use of the CBDC
surface assets by $2 million. NSPI’s revenue requirement is reduced accordingly. Given its concerns
arising from Ms. Hennings’ evidence, the Board is of the view that this is a conservative adjustment.
The Board wishes to be satisfied that NSPI will be paying fair market value for the use of these
facilities in the future. NSPI is directed to file information supporting its transportation expenses
relating to these facilities within six months of the date of this decision. If the Board is not satisfied
with this information, it reserves the right to engage suitable consultants to advise it concerning the
fair market value of NSPI’s expenditures with respect to these facilities.
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6.5
Independence and Insulation
[253]
The Board became increasingly concerned during the hearing with respect to
the apparent lack of separation between NSPI and Emera and how this could negatively impact
ratepayers.
[254]
NSPI, as a corporate entity, has significant assets. Its monopoly status places
it in a powerful position. Over the years, ratepayers have paid for the construction and operation of
generating stations, transmission lines and distribution systems, indeed all of the plant required to
serve customers.
[255]
Emera is in the process of developing many affiliated unregulated businesses,
leveraging off its existing businesses. Its principal existing business is NSPI which accounts for in
excess of 80% of Emera’s revenue. While this may change in the future with the acquisition of
Bangor Hydro and other businesses, NSPI presently constitutes the predominant source of Emera’s
financial strength.
[256]
It is imperative, in the Board’s view, that NSPI and Emera avoid becoming so
integrated that senior management is conflicted between the interests of Emera’s shareholders and
the interests of NSPI ratepayers. It is clear to the Board that these interests can diverge from time to
time. What is unclear to the Board is whether NSPI has the appropriate management structure to
protect ratepayers in such circumstances.
[257]
According to Mr. Huskilson, and confirmed by Undertaking U-107, many of
NSPI’s personnel, including its most senior executives, also have responsibilities relating to Emera
or Emera affiliates. This fact, coupled with the apparent trend to spin off functions of NSPI to Emera
affiliates, reinforces the Board’s concern that some inherent separation is necessary.
[258]
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The Board does not wish to limit Emera’s legitimate business development
103
initiatives, nor does it wish to prevent NSPI from achieving worthwhile efficiencies. Neither does it
wish to impose impractical restrictions on the relationship between NSPI and Emera. However, the
Board must be satisfied that utility’s assets are not transferred to affiliates without appropriate
approval, regulatory oversight and objective arm’s length valuation.
[259]
The Board has carefully considered the evidence of Mr. Falconer, Dr.
Kryzanowski and Dr. Stutz on the issue of “insulation” - the degree to which the utility is separated,
or insulated, from its affiliates.
[260]
Mr. Falconer said the following in response to Board questions concerning
Exhibit N-47, a research report by Standard and Poor’s dated January 23, 2002, in which NSPI was
described as lacking sufficient regulatory insulation:
A.
As soon as I saw this document some weeks ago, I latched onto exactly the same
sentence and spent considerable time trying to analyze exactly what they were
looking at, and I think the concern here they're looking for is the degree to which you
can be assured that the activities of Nova Scotia Power are -- "ring-fenced" is a word
often used NSPI itself freestanding and itself controlled by the board and by the
actions of NSPI independent of Emera. I think that's what they're getting at and I
think that's a fair and valid point one always looks for in the evolution between a
holding company and a subsidiary. We face exactly the same issues as a bank
when we look to lending or look to do financing of any freestanding entities. So, this
is a fairly common phenomenon that we face all the time. Most financing, say, by a
bank to an entity that's held by somebody else is not -- they are not interlinked, and
so you're always questioning, "Well, how is that freestanding entity looked at and is it
fair, the relationships between that and the holding company, and in particular, is it
protected against any developments from the other entity?" So, as a lender we look
at exactly these same issues.
Q.
It appears that S&P have looked at this in coming to the conclusion that there is an
insufficient regulatory insulation in this case.
That's the way I read the sentence as well.
A.
Q.
A.
In your experience is it the norm or is it the usual that there would be an independent
board of directors in these types of circumstances?
Probably not at this stage of development. I would use the analogy of what has been
happening with the setting up of a lot of these trust units in the capital markets these
days. I'm sure you've all heard of these, where you do these -- carve out a piece of
the business and finance it separately as an income trust, and those are often very
much interlinked like this. They're often a fundamental part of the business that is
separately financed. And if they have a separate economic interest, then often you
do look at independent board members, although in those cases often it's relatively
few of the board members. Say, there might be five, seven board members, there
might only be two or three that are independent, but that is a factor that is looked at
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104
by other financial people in similar circumstances.
Q.
A.
Q.
A.
Do you think that would be a prudent move, that is at least a partially independent
board of directors if some of the activities, in fact, posed competition to the utility?
I would suspect that -- well, I find it extremely dangerous to speculate, especially in a
public forum, as to how a client should conduct its business. So, with that as a
preamble, my answer would still be yes. My partners at my firm may not appreciate
it.
And in terms of light-handed regulation -- and that's kind of a pleasant surprise
because in past proceedings, one, I think, anyway, the word "draconian" may have
been used. But light-handed regulation, I guess in this instance -- do you take that to
mean there is no requirement that the utility come before the Board on an annual or
twice-yearly basis to be reviewed?
To be honest, I had a little difficulty with that comment because it was the
circumstances that dictated that there was not a hearing on a regular basis. I took it
as a positive comment, or meant as a positive comment by this commentator. I
didn't see the justification for it, to be honest, but that's a personal view.
(Transcript, May 13/02, pp. 1999-2001)
[261] The comment in the Standard and Poor’s report which gave rise to the above
exchange read as follows:
The ratings on Nova Scotia Power reflect the company’s combined business and financial
risk profile and are determined in conjunction with the credit quality of parent Emera. The
parent and operating company credit profiles are further linked because ultimately Emera is
responsible for maintaining a common equity thickness at the regulated electricity utility
operations. Given a lack of sufficient regulatory insulation (light-handed, reactive regulation;
minimal restrictions on dividend payouts; and no independent board of directors), the ratings
on Nova Scotia Power are equalized with those on Emera.
(Exhibit N-47, p. 3)
[262]
Dr. Kryzanowski, in response to questions from Board Counsel, stated that:
In terms of making sure that transfer pricing is appropriate between the parent and the sub,
making sure that the profits are not transferred to the parent and the risks remain with the
sub, ensuring that the parent is a tower of strength for the sub. I mean, this is a major
problem in the banking area, and Gordon and I did a study for the government in terms of
that, and basically you want to make sure that NSPI is not affected adversely by actions at
the parent.
(Transcript, May 15/02, p. 2330)
[263]
Dr. Kryzanowski went on to say that:
I guess we could make a more general comment. There's a lot of discussion in Canada
about corporate governance, and corporate governance in Canada is a major problem. If
you look at Boards of Directors, there's been studies in terms of what should the Board of
Directors be. And the TSE hasn't gone that far, but they've gone part of the way and they
feel that the majority should be independent Directors. Now, when you start moving to parent
and subsidiaries, in some cases you don't even have a Board for the sub or the majority of
Directors are not independent.
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105
(Transcript, May 15/02, p. 2393)
[264]
Dr. Stutz also referred to the issue of insulation, commenting that:
I haven't looked to see whether there are separate Boards of Directors. I would think over
time that would be something that would be considered. Given the extent to which NSPI
makes up Emera at this time, I wouldn't have expected a separate board in the past. After
all, it was 90 odd percent. I can't see how you would in that situation go for it. Now, we've
heard many more Emera activities are coming on line. There's the gas storage. I don't know
what else might come in the future, but certainly as Emera gets larger and as the non-NSPI
portion of Emera grows larger, then there would be more of a case for it, I would think.
(Transcript, June 4/02, p. 4000)
[265]
The Board also notes the concerns of the intervenors, some of whom have
referenced the recent and well publicized problems experienced by investor-owned energy
companies as a result of affiliate activities.
[266]
NSPI, in defence of its affiliate activities, asserts that:
In the current open access market in North America there are enhanced risks associated with
exporting and trading in electrical energy. Companies conducting that activity have to
understand the business and have specialized skills to do the business. Having trading
activity within NSPI creates risk. Trading in both electricity and fuels has to occur.
The spectre of Enron and other companies hung over the hearing created by the introduction
of newspaper articles put to NSPI in cross-examination which frankly do not put those issues
in proper context and adequately explain them. NSPI’s is not a situation analogous to Enron.
The recent failure of Enron and the investigations into “wash trading” by many of the firms
trading power have painted a picture of reckless capitalism with collateral damage to
everyone involved when failures do occur. This picture is not accurate. History has shown
there obviously are risks in trading, but regulated utilities dealing with un-regulated trading
companies (affiliated or not) do not share in those risks to any significant extent.
(NSPI, Post-Hearing Brief, pp.58-59)
[267]
The Board does not view NSPI or Emera’s activities as being analogous to
those carried on by Enron or by other energy companies such as Dynegy and Williams. However,
these examples do give rise to legitimate concerns.
[268]
In view of Emera’s intention to engage in diverse businesses, it is incumbent
upon the Board to ensure ratepayers are shielded in the event that Emera is unsuccessful. While the
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Board does not believe it is necessary for each company to have a separate Board of Directors at this
time, it does believe certain changes in corporate governance would enhance the degree of insulation
between NSPI and Emera. Accordingly, the Board directs that effective for the year 2003:
1.
Emera and NSPI use different auditing firms; and
2.
NSPI’s audit committee shall have a different Chair than Emera’s audit
committee.
[269] The Board will continue to monitor this situation to determine what, if any,
further changes should be made in the future.
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7.0
COST OF SERVICE, RATE DESIGN AND OTHER RATE-MAKING ISSUES
7.1
Overview - Rate-making Issues
[270] This section deals with NSPI’s translation of the revised revenue requirement
into rates. The revenue requirement approved by the Board is substantially lower than the revenue
requirement requested by NSPI and, consequently, the resulting rates will also be lower than those
proposed by NSPI. However, because the changes from NSPI’s proposed revenue requirement are
numerous and substantial, it is impossible to foresee precisely what rates these changes will produce.
To avoid the introduction of anomalous or unintended effects, NSPI is directed to submit a
Compliance Filing, providing the information identified in the following three sections.
Implementation of rates pursuant to this decision will only take place after the Compliance Filing has
been reviewed by the Board, any requested modifications have been made, and the Board has issued
a final Order approving the rates. Sections 7.2, 7.3, 7.4 and 7.5 set out the principles, methods and
data choices that will determine the rates NSPI is directed to develop in the Compliance Filing.
[271] As noted above, the Compliance Filing will incorporate the adjustments and
directives which are set out in this decision. The issues giving rise to the Board’s adjustments and
directives have already been the subject of a lengthy public proceeding as have the Company’s
proposed changes in rate structure. Intervenors have had a full and fair opportunity to challenge
NSPI’s application and present their own positions through evidence and argument. Accordingly,
the Compliance Filing will be reviewed by the Board alone prior to the issuance of a final Order in
this matter. In the Board’s view, no purpose would be served by prolonging this proceeding by
permitting further representations from intervenors.
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7.2
Cost of Service Study
7.2.1 Submissions - NSPI
[272] As part of its evidence in this proceeding, NSPI filed a Cost of Service Study
(COSS). NSPI’s study is described briefly in the text to Exhibit N-1, with supporting detail in
Appendix 2. In NSPI’s evidence and also in its response to UARB-IR-92, NSPI indicated that it had
relied upon the COSS methodology previously approved by the Board.
In its response, NSPI stated:
The cost of service study filed with our application on December 18, 2001 employed the
same methodology as was approved by the Board in their Generic Hearing Decision dated
September 20 [22], 1995. In that decision, the Board ordered that NS Power employ the 3
Coincident Peak Demand responsibility and to use the System Load Factor to allocate
generation and transmission fixed costs to energy.
The only change in methodology is the allocation of Marketing and Sales costs. In 1995,
these were allocated based on the number of customers in each class. In this application
they are allocated based on resources dedicated to each rate class.
(NSPI’s response to UARB IR-92)
[273] The current approved methodology was adopted as the result of a Generic
Hearing, which led to an Order dated September 29, 1995. The Board reaffirmed its support of that
methodology in its Order in NSPI’s last rate case, dated March 4, 1996.
7.2.2 Submissions - Intervenors
[274] Two witnesses —Dr. Rosenberg and Dr. Stutz— addressed NSPI’s choice of
methodology for its COSS. Dr. Rosenberg summarized two changes in his opening statement which
he characterized as “improvements” to the methodology for allocating generation and transmissionrelated costs. He said the following:
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However, I do put forward two changes to the Company allocations that I believe improve the
accuracy of the study, but are nevertheless within the confines of the 1995 Decision. The
first such change deals with the allocation of fuel cost. As the Company noted on several
occasions, perhaps most recently in its September 30, 2001report to the Board on its Fuel
Hedging Program, fuel costs are measurably higher in the high load or on-peak hours than
during the low load or off peak periods. Unfortunately, not only does the Company fuel
allocation fail to capture that important factor in cost causation, it even leads to
counterintuitive results, such as classes with more off-peak usage being assigned higher fuel
costs per kWh of generation than classes with more on-peak usage. To resolve this
problem, I projected monthly on-peak and monthly off-peak marginal fuel costs to shape a
class fuel allocator in the cost of service study. If we confine ourselves to fuel costs, this
would be equivalent to performing a marginal cost of service study, and then reconciling the
result to the embedded revenue requirement by a uniform pro-rata reduction. In other words,
if a class is found responsible for X% of the marginal fuel cost, it is also held responsible for
the same X% of the embedded or average fuel cost. I explain in my testimony why this
method is more reflective of cost causation, and sends more accurate price signals, than
does the Company method.
The second change I made to the methodology is to use this fuel allocator that I have just
described, to allocate the deemed energy related portion of the generation and transmission
fixed costs. In other words, the energy related portion of the fixed generation and
transmission costs are allocated in a manner that exactly parallels how the paragon of energy
related costs - fuel costs - are allocated.
I believe that the two changes described are completely in accord with both the letter and
spirit of the 1995 generic decision. More importantly, however, they represent a very modest
step toward making the cost of service study more reflective of actual cost causation, and
sending a more accurate price signal to customers in terms of the link between consumption
patterns and consequences to the cost of service.
(Exhibit N-117, pp. 16-17)
[275] Dr. Stutz suggested the possibility of a change in the classification and
allocation of certain distribution system costs which, he acknowledged, would be a change from the
Board’s previously approved methodology for dealing with these costs.
[276] In addition to methodology, the results of a COSS depend on the data,
particularly the costs and revenues assumed for the 2002 test year. Dr. Rosenberg was the only
witness to suggest changes to the data used in NSPI’s COSS. However, NSPI also made changes to
the data used in its study. These were reflected in the “updated” COSS filed with Mr. Whalen’s
letter of January 28, 2002.
7.2.3 Findings
[277] The Board reaffirms the findings in its Cost of Service Decision dated
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September 22, 1995. NSPI’s use of the Board’s approved methodology is accepted. Accordingly,
for the purposes of setting rates, the Board will rely upon a COSS which begins with the study
originally filed by NSPI, and reflects only the changes required to make the resulting study consistent
with the findings made elsewhere in this decision. Such a study will ensure that the rates set reflect
the Board’s decisions on key issues such as fuel costs. As part of the Compliance Filing, NSPI is
directed to provide a COSS in the same format and detail as that provided in Appendix 2 of NSPI ’s
original filing. With that study, NSPI is required to submit a brief statement identifying each change
made from the original study, and explain how each change was required by, and conforms to, this
decision.
7.3
Revenue/Cost Ratios and Rate Shock
7.3.1 Submissions - NSPI
[278] In its direct evidence, NSPI indicated that the following considerations can
influence rate design:
(a)
(b)
(c)
The principles of fairness, understandability, ease of administration, etc.
Customer impacts that are created in moving from existing rates to new rates
Price signals that are sent to customers
(Exhibit N-1, p. 53)
[279] NSPI stated that its proposed rates attempt to balance these considerations and
that all revenue/cost (R/C) ratios were adjusted to conform to the 0.95 - 1.05 range effectively
ordered by the Board in its 1996 rate decision. Rate shock is not specifically alluded to in the above
considerations.
[280] While the proposed rate increase averages 8.9% across all rate classes, some
customers will experience considerably higher increases. NSPI describes the impact of the increases
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on customer strata as follows:
The increases [in the Residential and Small General classes] were limited such that no
customer stratum experiences increases greater than 175% of the class average or no less
than 25% of the class average. Energy charges were adjusted to recover the remaining
revenue requirement.
In the remaining classes, the energy charges were set to be no lower than the average
marginal cost of energy in the test year, and demand and first block energy charges were
adjusted to recover the remaining revenue requirement. Increases to individual customer
stratum were limited to 50% to 150% of the class average.
(Exhibit N-1, p. 54)
7.3.2 Submissions - Intervenors
[281] Dr. Rosenberg urged the Board to temper its application of the 95% to 105%
range in order to avoid rate shock:
While the Company did bring revenue-to-cost ratios within the 95% to 105% bandwidth as
Board guidelines suggest, they violated another regulatory principle that, in my opinion, ought
to be complied with. I am referring to the principle of rate moderation or gradualism so as to
ameliorate "rate shock".
(Ex. N-113, P.58)
[282] He suggested that rate shock can be avoided by ensuring that no customer
class increase (including customers on annually adjusted rates) exceed 10 percent "on an annual
basis".
[283] Dr. Rosenberg’s testimony included the following:
Q.
A.
Dr. Rosenberg, how would [you] define rate shock?
I think you have to put that in the context of the inflation rate. You know, if you had
inflation at 7 to 8 percent, then, you know, rate shock might be 15 or 20 percent, but
if you have inflation going at 2 to 3 percent, then in my view anything above 10
percent is rate shock. So, you have to do it in the context of what the general rate of
inflation is.
Q.
So, with respect to the application that's before us, would you -- how would you
characterize the proposed rates vis-a-vis whether or not there's rate shock?
I think by the tenor of some of the comments that you've received, I think a lot of
people will consider it rate shock.
A.
Q.
A.
And is that one of the reasons that you have proposed a cap on the rate of increase
-- on the increases?
That is correct.
( Transcript, May 24/02, p. 3643)
[284] Dr. Stutz defined rate shock in answer to questions from the Board as "a large
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increase in rates over a short period of time". He went on to say that rate shock must be related to
the underlying rate increase. He also expressed the opinion that rate shock refers to the above-theline rates and not to the formula rates such as the annually adjusted rates. He said that customers on
the formula driven rates are pursuing a benefit and, as such, are bound by the formula. Dr. Stutz
noted that adherence to the R/C ratio range of .95 to 1.05 can conflict with the application of any sort
of rule pertaining to rate shock:
Q.
A.
Q.
A.
I see what you’re saying, yes. It’s too narrow a spread.
Yes.
Yes. Now, if you were to limit it to a percentage increase, can you adopt that -- or
adapt that increase so that it would apply to all the customers in the classes or do
you have to -- I guess my question is can you do that.
It's very hard, particularly if you're pursuing other goals. But can you articulate a
rule? I think I just did. So if the increase is 8.3 and we're limiting it to 150 percent,
then we're going to limit it to 12.5 on a class and if we're limiting it to 200 percent for
customers, we're going to limit it to 16.6 per customer. It's easy to write down
numbers. There are two problems. One problem is that you have other goals and,
in particular, you'd like to move into that 95 to 105 band width, which is also perfectly
reasonable, also expresses equity in a certain sense. So you don't want to
completely give that up and there's probably a conflict there. The other thing is that
within rate classes customers differ widely, particularly in rate classes that have
demand charges. Just based on load factor you can get all kinds of results. It's
probably very hard to get as narrow a spread as I've described intra-class without
changing the rate design significantly. And I haven't tried to do that, but I suspect it's
going to be a problem. Like I say, my own slightly canned way of handling it is just to
increase the kW and kWh charges proportionately. That'll limit those intra-class
effects.
(Transcript, June 4/02, p. 4019)
[285] Unlike Dr. Rosenberg, who described rate shock as an increase of over 10%,
Dr. Stutz described it in relation to the average, utility-wide increase. He submitted that increases of
150% of the average for class revenue requirements and of over 200% of the average for individual
customers would be indicators of rate shock. However, he noted that these percentages need to be
considered in light of the size of the average increase. The lower the average increase, the higher the
increases in class revenue requirement might be before rate shock occurs. He addressed this point in
the following extract from his testimony at the hearing:
A.
... rate shock is usually thought of in the context of a rate case of the type we're in
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now, and operationally, the way it gets thought about is to think about the level of
increase and the ranges that customer classes or individual customers might see.
So if there was a -- if you think of it in sort of an indexed way or a percentage way, if
the increase is a hundred, then you would want to limit the rate classes, say, to
increases of between 50 and 150. So in other words, you link the rate increase for
the classes or bracket the rate increase for the classes based on how big the
increase is for the company as a whole. Similarly, for customers, you might go out
another 50 points. You might say, okay, if the individual rate class sees 150, an
individual customer at the extreme might see 200.
Now, the numbers are a matter of judgement, but the basic idea that it's related to
the underlying rate increase is essential. It makes no sense to talk about a level of
rate shock in the absolute sense. Is five percent a shocking increase? Well, it is if
everybody's getting a 10-percent decrease and you're the one getting a five-percent
increase. It's shocking. Why were you singled out?
(Transcript, June 4, 2002, pp. 4015 - 4016)
7.3.3 Findings
[286] For over 15 years, the Board has indicated that customer class R/C ratios
should be in the range of 95% to 105%. Dr. Rosenberg and Dr. Stutz were the only two witnesses to
address the R/C ratios. Both generally supported the 95% to 105% range adopted historically by the
Board. Based on the evidence in this proceeding, the Board affirms its long-standing use of the 95%
to 105% range for R/C ratios. While the Board affirms the commitment in its decision in NSPI’s
last rate case to limit the class revenue requirements so that no class has an R/C ratio of below 95%
or above 105%, it also believes that, depending on the scale of a proposed rate increase, there may be
justification for the Board to exercise some flexibility in the application of this general rule.
Judgement must be exercised in balancing the R/C ratio objective with the desire to avoid rate shock.
[287] The Board finds that, to be reasonably applicable in a range of circumstances,
the notion of rate shock must take into account the underlying average level of increase. Thus, in
considering rate shock in this proceeding, the Board will rely on the approach proposed by Dr. Stutz.
Generally speaking, in considering the issue of rate shock, the Board will continue to strive towards
its stated objective of keeping R/C ratios in the 95% to 105% range, subject to the foregoing caveat.
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The Board will apply these principles in its review of NSPI’s Compliance Filing.
7.4
Annually Adjusted Rates
7.4.1 Submission - NSPI
[288] The Annually Adjusted Rates (AARs) are described on pages 50 to 52 of
NSPI’s evidence (Exhibit N-1). NSPI explained that it has five rates that are adjusted on an annual
basis, based on methodologies approved by the Board: the Generation Replacement and Load
Following (GRLF) rate; the Industrial Expansion Interruptible rate; and the three Real Time Pricing
(RTP) rates. In addition, the Mersey System rate is also determined annually on the basis of a
formula approved by the Board.
[289] Revenues and costs associated with all of these rates are treated as “below-theline” items in the COSS. Revenue requirements that are offset by revenues from the annually
adjusted rates are deducted from total revenue requirements and only the remaining revenue
requirements are allocated to the “above the line” rate classes, using the cost of service methodology.
NSPI submitted proposals for the AARs and the Mersey rate for 2002 as part of its original
evidence. A revised proposal for each of the AARs for 2002 was submitted to the Board in
conjunction with the updated financial forecast of January 28, 2002.
7.4.2 Submissions - Intervenors
[290] Drs. Rosenberg and Stutz were the only witnesses to address the AARs. Dr.
Rosenberg proposed a number of specific changes in the methodology and data used by NSPI to
develop the AARs proposed for 2002. Dr. Stutz took a different approach. He discussed a number
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of general concerns, but not specific points of data and methodology. In its post-hearing brief, NSPI
chose to respond to Dr. Rosenberg, but not Dr. Stutz.
7.4.3 Findings
[291] In addressing the AARs, the Board will deal separately with the methodology
and data. Turning first to methodology, it is important to note that no witness, including Dr.
Rosenberg, claimed that NSPI applied the “formulas”, which define the charges included in the
AARs, in a fashion significantly different from, or inconsistent with, the application of those
formulas approved by the Board in the past. In this proceeding, the Board directs that AARs for
2002 be developed using the formulas approved in the past. Changes in the formulas for the AARs
will be discussed in a separate proceeding.
[292] Turning to the issue of data, the Board takes the same position it took with
respect to the COSS. Development of the AARs for 2002 should begin with the data used in
preparing the AARs included in NSPI’s initial evidence. However, that data should be modified to
take into account all of the changes required elsewhere in this decision. Similar changes, as required,
should be made to the Mersey rate.
[293] As with the COSS, NSPI shall submit compliance versions of the AARs and
the Mersey rate for Board review. The Compliance Filing shall include a statement, identifying each
data change made for each rate, as well as a brief explanation of how each change conforms with the
findings and directives made in this decision. The revised AARs will be implemented after the
Compliance Filing has been reviewed by the Board, the changes, if any, required by the Board have
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been made, and the Board has issued a final Order approving the new rates. Once approved,
however, the new rates will be effective as at January 1, 2002.
7.5
Rate Design
7.5.1 Submissions - NSPI
[294] On pages 52 to 62 of Exhibit N-1, NSPI addresses its proposed designs for the
Interruptible Credit and the rates for Domestic, General, Industrial, Municipal and Unmetered
service. The proposed new rates are set out in Appendix 3 of NSPI’s application. There was no
change in those rate designs due to the revised data and COSS that accompanied Mr. Whalen’s letter
of January 28, 2002. As shown in Table A attached to Mr. Whalen’s letter, NSPI in fact proposed
class revenue requirements that resulted in R/C ratios in the 95% to 105% range. However, as
shown in Exhibit N-1, Table 6.1, NSPI’s proposed class revenue requirements in some cases exceed
150% of the average increase. In addition, as shown in Exhibit N-1, Table 6.2, the proposed
increases applicable to individual customers with low energy consumption often far exceed 200% of
the average increase.
7.5.2 Submissions - Intervenors
[295] Drs. Rosenberg and Stutz offered evidence concerning NSPI’s rate design.
MEUNSC also made a number of submissions with respect to rate design. The range of issues
addressed, particularly by Drs. Rosenberg and Stutz, and the breadth of opinion offered on specific
issues, is quite wide. The size of the Interruptible Credit is a specific example. NSPI, at page 50 of
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its evidence, suggests a credit of $3.08 per kVA. Dr. Rosenberg calls for an increase to no less than
$4.00 (N-117, page 20). At page 66 of his evidence, Dr. Rosenberg argues that, if one uses “more
realistic” assumptions than those selected by NSPI, a figure of $7.33 per kW could be justified. On
the other hand, at pages 28 to 30 of his evidence, Dr. Stutz cites a number of factors which together
suggest that a credit less than $3.08 may be justified. In light of the breadth of the issues raised, as
well as the extent of the disagreements on specific items, it appears that a separate rate design
hearing is appropriate.
7.5.3 Findings
[296] The Board has determined that it will not address the rate design issues raised
at this time. Instead, it will simply require a rate design which furthers the Board’s goal of having
R/C ratios in the 95% to 105% range, and which minimizes rate shock to the extent possible in
accordance with the Board’s earlier comments. The rate design issues not addressed in this decision
will be the subject of a separate, subsequent rate design proceeding.
[297] The Board finds that, for purposes of setting rates in this proceeding, the
general rate design approach described on pages 53 and 54 of NSPI’s evidence should be followed.
NSPI’s procedures (a), (b) and (c) provide a general methodology for setting class revenue
requirements. They are as follows:
a)
b)
c)
All revenue/cost ratios were adjusted to conform to the 0.95 - 1.05 range ordered by
the Board.
Any revenue deficiencies resulting from a) were allocated to those classes that had
the lowest R/C ratios. However, Large Industrials who were already receiving the
largest price increases, were held at 0.95.
The revenue increases or decreases resulting from a) and b) were added to the
average increase required to allow NSPI to meet its proposed revenue requirement,
to calculate average increases required by class.
(Exhibit N-1, p. 53)
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[298] Accordingly, NSPI is directed to set class revenue requirements following
these general principles. In doing so, NSPI shall rely on the COSS to be developed and provided as
part of the Compliance Filing as specified in this decision and the existing Interruptible Credit of
$3.43 per kVA per month.
[299]
Application of the above principles involves some judgment. In exercising
that judgment, NSPI shall, to the extent possible, limit increases to 150% of the average increase in
revenues required from the existing rates as a whole given the revenue requirement allowed in this
decision. The Board also notes that rates should be developed on the basis that the transformer credit
and the interruptible credit remain at the present approved levels.
[300] In order to create the specific rates required for each class, NSPI shall increase
all the rate components currently applicable to each class by the percentage increase in the revenue
requirement for that class. This “across-the-board” rate design procedure is similar, but broader in
scope than that recommended by Dr. Stutz. By broadening Dr. Stutz’ procedure, the Board removes,
as fully as possible, any differences between changes in class revenue requirements and customer bill
impacts. This should avoid the dramatic variation in bill increases shown in NSPI’s Table 6.2 noted
above.
[301] The Board directs NSPI to develop and submit, as part of its Compliance
Filing, rates which meet all of the requirements described above to the fullest extent possible. As
part of the Compliance Filing, NSPI should, at a minimum, provide the following:
·
a set of revised rate sheets similar to those in Appendix 3 of the filing,
showing proposed charges;
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·
a table similar to Table 3.6 in its application, showing revenues under current
and proposed rates;
·
a table similar to Table 6.1 in the application, showing changes in class
revenues;
·
a table showing R/C ratios by class before and after the increases;
·
a table similar to Exhibit 10 in Appendix 2 to the application supporting the
“before” and “after” R/C ratios;
·
a table similar to that provided in response to SEB-IR-125, showing a proof
of revenue.
These tables shall be accompanied by a statement explaining how NSPI applied principles
(a), (b), and (c), taking into account the requirement to avoid increases over 150%.
[302] The Board approves NSPI’s request to delete the following two expired rates:
·
·
7.6
Time of Day Expansion Interruptible Rate; and
Surplus Power Interruptible Rate
(Exhibit N-1, pp.51-52)
Future Rate Design Proceeding
7.6.1 Board Directives
[303] In light of the large number of issues raised concerning the AARs, the
Interruptible Credit and the other rates, the Board has decided to conduct a separate rate design
proceeding, to be held in 2003. The "ground rules" for the proceeding will include the following:
·
The current Cost of Service methodology will be accepted and NSPI’s COSS
model will be used. Data inputs can be adjusted, but not methodology.
·
Each party proposing rate design changes for the existing rates will submit
two Summary Exhibits, similar to Exhibit N-152, JS-10 which was filed in this
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proceeding by Dr. Stutz, showing the specific charges proposed compared to
the charges approved in this proceeding. One exhibit will be based on
NSPI’s current class revenue requirements, the other on the party’s preferred
class revenue targets.
·
NSPI will provide standard billing determinants, similar to those in SEB-IR125. Each party will use those determinants to show the revenues produced
by the rates presented in the Summary Exhibit.
[304]
Similar ground rules will be developed to govern the examination of the
AARs.
[305] Within the framework established by the ground rules, the parties will have
the opportunity to propose changes in rate design, including those proposed by Drs. Rosenberg, Stutz
and MEUNSC in this proceeding. In order to minimize effort, parties will be allowed to enter
testimony, exhibits and responses to information requests from the present proceeding into evidence
in the rate design proceeding.
7.7
Municipal/Large Industrial Rate Relationship
[307] For the first time in more than 25 years NSPI has proposed in this application
to "decouple" the Municipal rate from the Large Industrial rate. Over this considerable period of
time, the demand and energy charges in the Municipal rate have always been the same as the
demand and energy charges in the Large Industrial rate. NSPI now proposes to increase the demand
charge in the Municipal rate to $9.81 per month per kilovolt ampere of maximum demand and to
increase the demand charge in the Large Industrial rate to $9.35. The energy charge in the Municipal
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rate would increase to 4.70 cents per kilowatt hour compared to a proposed Large Industrial energy
charge of 4.64 cents per kilowatt hour.
[308] The Board has considered the arguments put forward by NSPI in favour of
making this change and the arguments by MEUNSC in favour of retaining the status quo. The Board
is not persuaded that the arguments in favour of decoupling the rate are so compelling that any
change in the longstanding practice needs to be made in advance of the rate design proceeding to be
held pursuant to this decision. Accordingly, the Board directs that NSPI, in revising its rates in
accordance with the directions set out above, shall maintain the Municipal and Large Industrial rate
components at the same levels.
7.8
Green Rider Rate
7.8.1 Submission - NSPI
[309] By letter dated December 12, 2001, NSPI requested interim Board approval
for a new rate which, it states, will allow:
... customers who are so inclined to voluntarily contribute $5.00 per month in support of
NSPI’s efforts to develop green energy supplies in Nova Scotia. In return for each $5.00
subscription, NSPI will commit to producing or purchasing 125kWh per month from green
sources, thus displacing fossil fuels. The proposed contribution of $5.00 to support 125kWh
is equivalent to a contribution of 4 cents per kWh.
(NSPI letter dated December 12, 2001)
[310] NSPI’s proposal involves the establishment of a voluntary rate under which
customers could pay a premium for electric service, in $5 increments, to promote the use of
electricity generated from environmentally-friendly renewable sources such as wind power. NSPI
states that the premium is designed to cover the incremental cost of providing power and energy
from "green sources" and was developed on the basis of the cost of two wind turbines. NSPI has
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already canvassed the acceptability of the concept with certain customers, including the federal
government, and is satisfied that some customers will pay a premium to promote electricity
generated from green sources.
[311] The Board determined that the green rider rate should form part of the general
rate hearing and deferred consideration of the rate until that time.
7.8.2 Submissions - Intervenors
[312]
The Board received a number of submissions on the green rider rate from
intervenors, including the NDP and ECANS. ECANS, in particular, believes that aspects of NSPI’s
proposal would benefit from additional scrutiny. The NDP opposed the structure of the green rider
as presented, arguing that customers should not have to pay a premium to encourage the generation
of electricity from more environmentally-friendly sources.
7.8.3 Findings
[313] The Board appreciates the helpful suggestions of all the parties with respect to
this issue. The Board is cognizant of the fact that details of the proposed green rider rate were not
included in the notice of the rate application published by the Board. It agrees with ECANS that
parties ought to have an additional opportunity to review this rate. The Board is also aware that the
lack of notice to the public of the proposed green rider rate was not as a result of any oversight on the
part of NSPI. In order to balance the interests of both sides on this issue, the Board will not give
final approval of the green rider rate at this time. It will, however, approve the green rider rate on an
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interim basis to be reviewed in detail during the next general rate proceeding.
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8.0
RULES AND REGULATIONS
8.1
Submission - NSPI
[314] In its application, NSPI requested that the Board approve amendments to
NSPI’s Rules and Regulations to provide for: 1) a change in the requirement governing notification
of disconnection; and 2) a change in the interest rate paid on deposits from 8% to the prevailing
Royal Bank of Canada lending rate less 1%. NSPI notes that, as at the time of filing, this would
result in interest on deposits of approximately 3%. At present, the regulations are as follows:
6.2
7.1
MANNER OF DISCONNECTION
Prior to the proposed date of disconnection the Company shall make
reasonable efforts to contact the customer, to determine whether the
customer has satisfied the outstanding account or is willing to make
satisfactory arrangements to settle the outstanding account. If such contact
is made and payment is not or has not been made and satisfactory
arrangements for payment have not been made, the Company may
disconnect the electric service. If such contact cannot be made the
Company shall attempt to contact the customer or other responsible adult
upon the premises served by the electric service account. If the Company is
unable to contact such persons upon the premises, a written notice shall be
left in a conspicuous location stating the date and time after which electric
service will be disconnected unless the amount specified for the outstanding
account is satisfied or satisfactory arrangements made to settle the
outstanding account and thereafter the Company may disconnect the
existing electric service.
SCHEDULE OF CHARGES
The following charges shall apply:
(a)
Connection or reconnection of electric service, ....
(i)
Interest on Deposits
8% per annum (simple interest)
[315]
With respect to Regulation 6.2, NSPI wishes to add a provision, as an
alternative to leaving a “doorknob” notice in circumstances where customers cannot be contacted,
allowing customers to be notified by priority mail which requires a signature. The proposed
regulation reads as follows:
B)
MANNER OF DISCONNECTION
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Prior to the proposed date of disconnection the Company shall make
reasonable efforts to contact the customer, to determine whether the
customer has satisfied the outstanding account or is willing to make
satisfactory arrangements to settle the outstanding account. If such contact
is made and payment is not or has not been made and satisfactory
arrangement for payment have not been made, the Company may
disconnect the electric service. If such contact cannot be made the
Company shall attempt to contact the customer or other responsible adult
upon the premises served by the electric service account. If the Company is
unable to contact such persons upon the premises, a written notice shall be
left in a conspicuous location or the written notice shall be delivered by
priority mail requiring signature. Either notice shall state the date and time
after which electric service will be disconnected unless the amount,
specified for the outstanding account is satisfied or satisfactory arrangement
made to settle the outstanding account and thereafter the Company may
disconnect the exiting electric service.
(Exhibit N-1, Appendix 4, Reg. 6.2(b))
[316] With respect to the proposed change in the interest rate paid on deposits, NSPI
indicates that the change will result in an:
st
Interest rate based on Royal Bank prime rate minus 1%; set January 1 of each year.
(Exhibit N-1, Proposed Reg. 7.1(i))
8.2
Submissions - Intervenors
[317] No objections were noted to these requests.
8.3
Findings
[318] The Board approves the regulations as proposed.
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9.0
OTHER ISSUES
9.1
Regulatory Process - Timing
[319] There was comment on the record in this proceeding of NSPI’s desire for
changes in the existing regulatory process. This is highlighted in the following exchange between
Board Counsel and Mr. Huskilson:
Q.
A.
Mr. Huskilson, just turn to page 6 of Mr. Mann's remarks, and at the -- the very first
paragraph begins, "We are striving at all times to do better," since there's no page
references on this. And the part of that page that I wanted to direct your attention to
begins at the fourth paragraph from the bottom where it says: "However, we need
more than strong management. We need timely rate action and a commitment to
regulatory reform. At the moment, we are engaged in two very different regulatory
proceedings here and in Maine. Our experience in Maine with negotiated
performance-based rate making suggests that there may be better and more flexible
and less divisive ways of establishing our prices. Instead of an expensive and
lengthy hearing, we participated in a collaborative process for a defined 90-day
period." And on the top of the next page, he says:
"The successful conclusion of these negotiations with the regulator, the public
advocate and key stakeholders has led to a recommendation for a six-year alternate
rate plan being sent to the commissioners for their approval."
Has that approval, by the way, been granted yet?
I'm not aware of the answer to that, but I believe not.
(Transcript, May 23/02, pp. 3206-3208)
[320] Under cross-examination by Counsel for Annapolis, Mr. Huskilson said:
Well, I think -- I mean, many people have asked the question as to why we are in -- why we're
in the middle of the test year with this application. One of the reasons is the delay that's
occurred. The other reason is that we were working very hard at the end of last year in trying
to find ways of not having to come forward with an increase. But at the end of the day, the
markets were such that we were unable to not have to do that. But we have traditionally
worked hard to make that happen, and we continue to do that.
(Transcript, April 23/02, pp. 286-287)
[321] Annapolis points out in its closing submission that:
NSPI has not demonstrated that it is entitled to the rates it seeks. A rate proceeding is
intrinsically an asymmetrical affair; the utility possesses all the evidence relevant to its
revenue requests and the intervenors possess nothing more than what the utility is inclined to
provide to them or what the Board orders. It is unseemly for the utility to complain about the
length and cost of such proceedings when its costs will all be recovered from the ratepayers
and its inaccurate, unresponsive and misleading information (whether inadvertent or
otherwise) has been a principal cause of the prolixity of the proceedings. The result and
costs to the intervenors are by and large not recoverable and pose a test to their endurance
and resolve.
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(Annapolis, Closing Submission, p.3)
[322] MEUNSC stated in its final brief that:
N.S.P.I. was aware by at least May of 2001 that coal prices were rising. This was
dramatically confirmed by September 4, 2001. We hope that someone, in N.S.P.I. or Emera,
whichever was then in charge of procurement, was doing market research in the interim. Mr.
O’Neill stated under cross “Speaking from a financial point of view, if I had my way we would
have been filing last August.” . . . N.S.P.I. has staff knowledgeable in rate design and
regulatory affairs, indeed charged with those responsibilities and presumably accounting staff
have the capacity to generate financials. They should have had an application prepared and
ready to print, subject to updates. It is difficult to imagine why the company filed a rate case
requesting large and controversial increases, using 2002 as the test year, on December 18,
2001. Unless having seen the “perfect storm” in coal prices, they sought the perfect window
in presenting an application. At the time of their filing, CBDC was in fact closed and no
operators were available. (See Medine, Confidential N-37, pages 9 and 10). CBDC coal at
$2.11/mmbtu was not in the future equation. There was no contract with Nova, so no need to
consider that price. The N.S.P.I. panel denies the connection, but absent some compelling
motive, waiting until December 2001 to file was imprudent even if the coal procurement was
not.
(MEUNSC, Final Brief, p.26)
[323] The Province in its final submission states that:
NSPI’s general rate application was filed on December 18, 2001. After a lengthy pre-hearing
discovery process, including a preliminary motion for production of documents, the hearing
commenced on April 22, 2002 and finished on June 4, 2002. The Province submits that
alternative procedures to the hearing process should be canvassed to determine if
efficiencies can be gained in the process and if there is an appropriate mechanism for
settling some of the regulatory issues outside of the costly hearing process.
(Province, Final Submission, p.19)
[324] As noted earlier in this decision, the initial hearing on NSPI’s December 18,
2001 application was scheduled for March of 2002. It was only after the majority of intervenors
requested an adjournment that the hearing was postponed until April 22, 2002. The Board believed
at the time (and continues to be of the view) that the adjournment request was reasonable given the
complexity of the material; the lengthy interval between rate cases; the scope of the issues; and the
magnitude and potential impact of the proposed increases.
[325] The Board further notes Dr. Stutz’s comments on the process in Nova Scotia
as compared to other North American regulatory jurisdictions:
Yes, my view is that you're doing pretty well with the methods you have. I think that there
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probably are administrative changes such as the conference I mentioned earlier which might
make rate cases proceed more smoothly. But I don't believe that you need to make systemic
changes. Performance based regulation would be one such systemic change that might be
suggested. My feeling is that you have a very good form of performance based regulation
built into your current arrangements. Normal test year regulation without a fuel adjustment
clause is, in my view, a very effective form of performance based regulation. And, in fact, I
think you have evidence that it works. If you look, the company stayed out for a long time,
managed its costs, produced an acceptable rate of return, and was only forced in by a truly
extraordinary change in its fuel prices. But that's precisely what performance based
regulation is supposed to do. So I would recommend on that front you simply declare a
victory.
(Transcript, June 4/02, pp.3977-3978)
[326] The Board agrees with the comments made by MEUNSC that NSPI should
have anticipated that an application for such a significant increase would attract considerable
attention and scrutiny. It is inappropriate in the Board’s view, to suggest that opportunities for a
thorough scrutiny of NSPI’s case should be short-circuited in order to accommodate a compressed
time frame of NSPI’s own making.
9.2
Disclosure
[327] A number of intervenors have suggested that a lack of timely disclosure on the
part of NSPI resulted in a lengthier than necessary process. For example, SEB, in its reply argument,
stated that:
Stora Enso/Bowater take exception with NSPI’s description at line 26 of page 4 of their
Argument that there was an “extraordinary discovery process authorized by the Board in this
case”. NSPI seems not to understand that it has been granted the privilege of a monopoly,
and that the regulatory process is designed to ensure that monopoly power is not abused.
Intervenors have every right to access information of the type sought by them in this
proceeding. The record is clear that information of the type sought by Stora Enso/Bowater in
this proceeding is normally available in other North American jurisdictions, and available
without the intervenors having to go to the considerable time and expense expended in this
Hearing to achieve access to that information. [See for example Transcript, pages 17741775,
questions
72-76
and
Exhibit
N-117,
page
3,
line
3]
(SEB, Reply Argument, p.3)
[328]
disclosure:
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Annapolis, in its closing submission, also reiterates concerns with respect to
129
Ms. Medine was frustrated in her review as she explained in her report that “the information
provided by NSPI through its filing, the IR responses and, and confidentially at its offices was
disjointed and, at times, inaccurate and incomplete” (Exhibit N-37,p.1). These complaints
were echoed by Ms. Sharon Hennings and Dr. Rosenberg, the experts retained on behalf of
Stora/Bowater (Transcript, Hennings, P. 1671; Rosenberg, pp.3516-3517).
(Annapolis, Closing Submission, P. 19)
[329] In Exhibit N-117, Dr. Rosenberg quoted the following excerpt from Mr.
Huskilson’s testimony:
(Huskilson) Mr. Cooper, in this province we have an open and transparent process where
customers can review our information and ultimately the Board makes a decision based on
that. We just want to be in a position where we are sharing the information with our
customers and with the Board that we have, and we don’t want to be in a position where
we’re withholding information. (Emphasis added)
[330] Dr. Rosenberg then continued as follows:
While those were admirable sentiments expressed by Mr. Huskilson, in my view there was a
serious gulf between this aspiration and the actual process. It was frustratingly difficult to
extract even what I would consider to be the most elemental amount of data and documents
during the discovery phase in this case. For example, in the first round of discovery, Stora
Enso/Bowater could not get access to:
The cost date for export sales;
Full details supporting the fuel cost data in Table 3.8:
Fuel cost contracts;
The model used to develop the Company cost of service study;
Input and Output of Production cost simulation models:
Certain class load shapes;
Details of cost allocations to below the line classes;
Workpapers supporting many calculations.
In fact, despite the voluminous responses to the first round of discovery, Stora Enso/Bowater
did not receive a single computer spreadsheet in electronic format. In this day and age,
when computer spreadsheet models are indispensable in preparing a rate application, this is
inexcusable. Moreover, it is not at all the practice followed by applicants in regulatory
proceedings in the vast majority of states and provinces with which I have had experience.
Eventually we did gain access to some of that data, and to some spread sheets in electronic
form. However, other items were never disclosed, or disclosed in such a fashion that it made
independent analysis and corroboration tedious and time consuming.
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The rate hearing procedure is of necessity, and by design, an adversarial process. It is only
by parties with different interests and constituencies presenting alternative viewpoints that the
regulator can arrive at an informed decision. In fact, in Alberta, the Board so values these
different opinions that participant[s] often get a significant portion of their costs back,
depending upon the contribution to the hearing process that the Board perceives. But this
adversarial process can only function efficaciously when there is in fact an “open and
transparent” flow of information. Now I appreciate the commercial sensitivity of some of this
information. Nevertheless, there are ways to give parties with legitimate interests sufficient
access to models, documents and workpapers, while still providing NSPI with adequate
safeguards for its concerns. I urge the Board to facilitate the discovery process in the future in other words to make NSPI practice the “openness and transparency” it preaches. For this
hearing, my recommendation is that the Board take notice of this unnecessary problem when
weighing the evidence.
(Exhibit N-117, pp.2-3)
9.3
Process Improvements
[331] The Board is in favour of implementing techniques which could improve the
efficiency of proceedings.
Dr. Stutz, in response to Board questions concerning possible
improvements stated that:
. . . One thing would be simply to make it clear that having the intervenors understand these
things at the level -- at whatever level the Board
believes is appropriate, whether it's the almost
audit level one would say of the coal witnesses, or
whether it's at a higher level, but whatever level is
appropriate to make it clear that the requirement
for having a successful rate case is that you make
that information easily available. That would be a
help, because then the company would, of course,
understand what it needs to do, and I presume
would try to do it. Let me say I personally didn't
feel frustrated in obtaining information from the
company, but I did not attempt to perform the audit
level review that Ms. Medine and others may have
tried to perform. A second thing that could be
done would be to have some sort of a conference
between the first set of IR’s and the second, and
the purpose of these conferences is simply to
provide technical information quickly and easily.
This is done routinely in other jurisdictions. I don't
know what constraints there may be on doing it
here.
(Transcript, June 4/02, pp. 3973-3974)
[332] The Board does not agree with NSPI’s position that it was subjected to an “. .
. extraordinary ‘discovery’ process authorized by the Board in this case”. The Board believes that
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the intervenors were entitled to examine and challenge NSPI on these issues and they could not fairly
do so without the data that was sought. NSPI is a monopoly utility whose revenue requirement must
be subject to thorough public scrutiny. It is NSPI, not the intervenors, which bears the burden of
proof in establishing that a rate increase is warranted.
[333] NSPI has pointed out during this proceeding that circumstances have changed
since the last rate filing in 1995 - i.e., competitive pressures, foreign exchange, increased costs,
environmental considerations, etc. Ironically, it is clear from the many submissions received by the
Board that the intervenors in this proceeding face many of these same pressures. Many argue that
they, unlike NSPI, operate in a truly competitive environment. Based on the application as filed,
some were facing rate increases in excess of 25%. It should not be surprising that NSPI has been
confronted by ratepayers who demand to be thoroughly informed and who challenge NSPI in terms
of the efficiency and competency of its operation and the validity and reasonableness of its proposed
rates. The Board does not expect this trend to diminish over time.
[334] Accordingly, the Board will facilitate a technical conference, in advance of the
next hearing, between NSPI and intervenors for the purpose of streamlining the information request
and response process. The Board hopes that this will result in a shorter hearing and less acrimony
between the parties. This conference will occur following the filing of NSPI’s application and prior
to the issuing of IRs.
[335] Further, the Board notes that it does not object in principle to a settlement
process in advance of the hearing provided that all classes of ratepayers are represented in these
discussions. To this end, should NSPI wish to pursue a settlement process with intervenors, the
Board will appoint a consultant, at NSPI’s expense, to act as a consumer advocate for otherwise
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under-represented groups of customers (i.e., domestic, small commercial). The Board may also
determine that it would be in the public interest to ensure that these customers are represented by a
consumer advocate at the technical conference referred to above. It goes without saying, of course,
that any settlement agreement reached by the parties would be subject to scrutiny at a public hearing
by the Board.
9.4
Dalhousie Legal Aid Service
[336] In a well-documented and carefully argued submission to the Board,
Dalhousie Legal Aid Service (DLAS) addressed the effect of electric rate increases on low income
residential customers. Drawing upon a comparison of electricity rates in North American cities
undertaken by Hydro Quebec, and based on a monthly consumption of 1,000 kWh, DLAS points out
that of the Canadian cities surveyed, residents of Halifax pay the third highest residential rates in
Canada.
[337] DLAS states that the application as filed would result in disproportionate rate
increases for residential customers who use very little electricity. NSPI indicated in its direct
evidence that customers using less than 2,000 kWh per year would face a 15.3% increase in their
bills compared to the average proposed increase of 8.9%. DLAS notes, however, that low income
customers are not always low users of electricity.
[338] DLAS states that Nova Scotians in receipt of social assistance spend 10.8% of
their incomes on electricity compared to 5% for the consumer of average income. If the rate
application were to be granted in full, Nova Scotian recipients of social assistance would apply
12.2% of their incomes to the purchase of electricity, which would represent the highest such
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proportion in Canada.
[339] DLAS goes on to point out that since 1995, the year before the Board last
authorized NSPI to increase its rates, power increases have not resulted in corresponding increases in
shelter benefits to low income consumers. Nova Scotia “total annual welfare incomes”, measured on
the basis of the maximum shelter rates available, have in fact declined from $12,271 in 1995 to
$12,250 in 2001. DLAS further states that there has been a “dramatic” increase in the number of
service disconnections and use of security deposits since 1996.
[340] DLAS’ principal recommendation to the Board is that it introduce a “rate
subsidy program” under which low income residential customers would be subsidized by other
customers of the utility. DLAS does not explain how such a program should be implemented.
[341] The Board has in the past rejected the principle of rate subsidies based on
income disparity. For example, in its 1992 decision on a rate application by NSPI, the Board said
this:
It was suggested that the Corporation be required to report on the affordability of domestic
rates for seniors, people with disabilities and other individuals or families who are living on a
fixed income. Changes to rate structures to provide subsidized rates to such persons would
be discriminatory and thus contrary to the basic thrust of regulation, which is to ensure
customers pay rates that are justified by the cost of serving them. The government might be
interested in such a study from the social assistance viewpoint, but it is not within the
regulatory mandate.
Section 67(1) of the Act is pertinent to any discussion of rate subsidies:
67(1) All tolls, rates and charges shall always, under substantially similar circumstances and
conditions in respect of service of the same description, be charged equally to all persons
and at the same rate, and the Board may by regulation declare what shall constitute
substantially similar circumstances and conditions.
[342] The Board recognizes DLAS’ argument that, in the context of human rights
legislation, the courts might well hold that differences in treatment based on differences in income
level might be justified as being differences in circumstances and would not constitute
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discrimination. The Board has given renewed consideration to the issue of rate subsidization based
on income in light of the arguments put forward by DLAS. However, it continues to hold the view
that the implementation of such rate subsidy programs is neither contemplated by s. 67(1) nor
appropriate in the context of the regulation of public utilities.
[343] The Board would note that the reduction in the revenue requirement ordered in
this decision and the Board’s direction that the components of the domestic and other rates shall
increase by the same percentage will alleviate the disproportionate effect of NSPI’s proposed rate
increase on residential customers who consume low amounts of electricity.
10.0
SUMMARY OF DISALLOWANCES AND ADJUSTMENTS
[344]
NSPI, in its direct evidence, submitted that an additional $67.1 million was
required from “above-the-line” customers (i.e., not LRR, GRLF or IE customers). This is illustrated
in the following table.
Table 6.1
ABOVE-THE-LINE-CLASSES
Changes in Class Revenues
(millions of dollars)
REVENUE UNDER
CURRENT RATES
ADDITIONAL REVENUE
REQUIRED
PROPOSED
REVENUE
% INCREASE
$363.0
$4.7
$367.6
$32.3
$0.4
$32.7
$395.3
$5.1
$400.4
8.9%
8.9%
8.9%
Small General
General Demand
Large General
Total Commercial
$8.9
$206.0
$23
$238
$0.8
$10.3
$3.8
$15
$9.7
$216.3
$27
$253
8.8%
5.0%
16.2%
6.2%
Residential & Commercial
$605.8
$47.6
$653.4
7.9%
$16.9
$34.9
$1.6
$4.4
$18.5
$39.3
9.2%
12.5%
Residential
Residential non ETS
Residential ETS
Total Residential
Commercial
Industrial
Small Industrial
Medium Industrial
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Large Industrial
Total Industrial
$71.8
$123.6
$11.8
$17.7
$83.6
$141.3
16.4%
14.3%
$11.1
$18.5
$29.6
$1.8
$0.0
$1.8
$12.9
$18.5
$31.4
16.4%
0.0%
6.1%
$759.0
$67.1
$826.1
8.9%
$0.0
$17.8
$6.7
$54.7
$9.1
$88.3
$0.0
$0.7
$0.0
$2.5
$0.3
$3.5
$0.0
$18.5
$6.7
$57.2
$9.4
$91.9
0.0%
3.9%
0.0%
4.6%
3.3%
4.1%
$847.3
$70.6
$918.0
8.3%
Other before Export Sales
Municipal
Unmetered
Other before Export Sales
Total Above-the-line Classes
BELOW-THE-LINE CLASSES
Other Electric Revenue
Gen. Repl. & Load Follow
Bowater Mersey
Industrial Exp. (Stora)
RTP
Total Below-the-line Classes
In-Province Total
(Exhibit N-1, Table 6.1)
[345]
For the reasons given in the preceding sections of this decision NSPI’s
proposed revenue requirement has been reduced as set out in the following table:
Test Year Expenses
Reductions to NSPI’s Requested Revenue Requirement
ITEM
AMOUNT OF REDUCTION
10% Imported Coal cost adjustment
$19,700,000
Disallowed CBDC buyout
$ 2,700,000
Disallowed Compensation - Executive
$
Disallowed Compensation - Incentive
$ 1,580,000
Reduced Other expenses (Sponsorship & Donations)
$
Reduced Return on Equity (based on R.O.E. of 10.15%)
$ 8,500,000
Reduced Capital Structure
$ 3,300,000
Coal Transportation Costs
$ 2,000,000
Emera Energy Agency Fee
$
Adjusted Additional Hydro generation
$ 3,000,000
Total disallowances and adjustments
303,500
635,800
672,000
$42,391,300
[346] The Board notes that the reductions shown in the Table above are estimates
based on the information available to it. The actual amount of the reduction may change somewhat
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136
and will be reflected in NSPI’s Compliance Filing. In particular, NSPI must verify in its Compliance
Filing the reductions in the revenue requirement due to decreasing the Common Equity component
from 40% to 35% and decreasing the Return on Equity from 11% to 10.15%.
[347] The additional revenue requirement of $67.1 million requested by NSPI in its
application resulted in an overall rate increase of 8.9%. The reductions in the revenue requirement of
$42.4 million set out above, reduce the overall rate increase from 8.9% to 3.3%.
11.0
SUMMARY OF BOARD FINDINGS
11.1
Revenue Requirement/Rate Increase
[348] NSPI, in its application to the Board, requested an increase in its revenue
requirement from general rates of $67.1 million for the test year 2002. Such an increase, according
to NSPI, would result in an average rate increase of 8.9% in general rates across all customer classes,
with some customers experiencing considerably higher increases. The Board, after reviewing NSPI’s
projections, has reduced the revenue requirement by $42.4 million (see Table on page 146). This
results in a reduction in the average rate increase across all classes from NSPI’s proposed 8.9% to
3.3%.
11.2
Capital Structure
[349] NSPI requested Board approval to increase the common equity component of
its capital structure from 35% to 40% for the test year with the ability to increase this to 45% over
time.
[350] The Board finds that there is insufficient justification to increase the common
equity component from its present level of 35% to 40% at this time. The Board believes that without
a corresponding increase in the common equity ratio of NSPI’s parent company, Emera, there will
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likely be no overall benefit accruing from an increase in the common equity level of NSPI.
[351] The Board directs that the common equity level of NSPI remain at 35% for
rate-making purposes, but has no objection to NSPI increasing its actual equity ratio to 40% in the
future. However, at any subsequent rate hearing, the Board will determine what equity ratio is
appropriate for rate-making purposes. This finding reduces NSPI’s revenue requirement by
$3,300,000.
11.3
Rate of Return on Equity
[352]
NSPI requested approval of rates which would result in a return on common
equity of 11.0%. It further requested approval of an allowed earnings range on common equity of
11.0% to 12.0%. Rates were last set in 1996 on the basis of a return on common equity of 10.75%
with an allowed range of 10.5% to 11.0%. The Board believes that the rate of return on equity should
be set at a rate which fairly reflects the risk associated with an investment in NSPI. The Board
considers that a rate of return of 10.15% most fairly reflects this risk. Accordingly, the Board fixes
the rate of return on common equity at 10.15%. The Board continues to consider that it is useful to
establish an earnings range, which it sets at 9.90% to 10.40%. As a result, NSPI’s revenue
requirement is reduced by $8,500,000.
11.4
January Adjustment
[353] The Board considers that the data filed by NSPI with its original application
on December 18, 2001 represented the Utility’s best forward-looking estimate of the 2002 test year.
The Board determined that NSPI’s January 28, 2002 letter, which updated the December 18, 2001
filing, should be disregarded. The Board believes that incorporating actual data with test year
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projections may have the effect of lessening the consistency and reliability of the test year data.
11.5
Coal Costs
[354] The Board finds that NSPI’s estimated fuel costs for the 2002 test year are
based on higher than normal coal costs and, consequently, are not suitable for rate-making purposes.
Accordingly, the Board finds that the cost of fuel for the test year must be reduced in order to ensure
that the costs are more representative of the period during which the rates will be in place (i.e., late
2002 and into 2003). The Board finds that to normalize these coal costs on a go-forward basis for
the remainder of this year and into 2003, a 10% reduction in test year costs for imported coal is
reasonable.
This will result in a reduction of approximately $19.7 million in the revenue
requirement.
11.6
CBDC Buyout
[355] In April of 2001, NSPI entered into an amending agreement with CBDC
which resulted in the early termination of a long term coal supply contract. The effective date of the
amending agreement was January 1, 2000. The cost of the contract buy-out was $13.4 million.
NSPI requested Board approval to include this cost ($2.7 million per year for five years beginning in
2002) as an expense to be borne by ratepayers.
[356] The Board finds it difficult to discern a future benefit to ratepayers as a result
of a fee paid to terminate a coal supply contract approximately one month before the announcement
was made that coal mining by CBDC would cease. The Board finds that, based on the evidence, it is
reasonable to conclude that the benefits of the $13.4 million paid to terminate the CBDC coal supply
contract have already been realized by shareholders. Under these circumstances, the Board finds that
it is not appropriate to transfer the burden of this fee to the ratepayers and, accordingly, the expenses
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associated with this fee are disallowed and test year expenses are reduced by $2.7 million.
11.7
Hydro Generation
[357] NSPI, using five year average rainfall data, projected a reduction in hydro
generation over previous years. Since there is little or no fuel required in hydraulic generation, a
decrease in this cheaper form of power production results in higher fuel costs. It is reasonable, in the
Board’s opinion, to use a twenty-three year average for hydro generation rather than a five year
average. Using NSPI’s calculations, the Board finds NSPI’s avoided fuel cost as a result of increased
hydro generation to be $3 million. NSPI’s test year expenses will be reduced accordingly.
11.8
Executive Compensation
[358] The Board is concerned about the rapidly increasing compensation which is
being paid to the executive management of NSPI and which is included in costs to be recovered from
ratepayers. It is clear that the compensation costs for NSPI’s two most senior executives have
increased dramatically over the past several years. The Board does not believe current compensation
levels are acceptable to the vast majority of ratepayers in this Province. The Board is of the view that
it is appropriate for the shareholders to bear a significant portion of the increased compensation
costs. The Board believes it is fair for ratepayers to bear compensation costs that have increased at a
reasonable rate from those paid at the time of the last rate hearing.
[359] With respect to the compensation paid to Mr. Huskilson, NSPI’s Chief
Operating Officer, while the Board has some concerns about the magnitude of the amount ($335,769
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in salary and $147,900 in bonuses in 2001), as well as the significant increase during the last few
years, the Board is prepared to accept it as a reasonable reflection of his contribution to NSPI subject
to reductions in incentive compensation and corporate support allocation reductions.
[360] With respect to the compensation paid to Mr. Mann, President of NSPI, the
Board has no evidence before it of Mr. Mann’s duties with NSPI and, consequently, there is scant
support for charging to ratepayers a 73% allocation of his $832,000 annual compensation package.
The Board is left with the impression that much of Mr. Mann’s time is spent on activities of Emera,
and its 42 affiliates. Accordingly, in the absence of any evidence to the contrary, the Board disallows
one-half of the cost of Mr. Mann’s compensation which has been included in NSPI’s revenue
requirement. This represents a disallowance of $303,500.
11.9
Incentive Compensation
[361] NSPI requested that the Board approve 100% of incentive compensation
(bonuses) as a charge against ratepayers. The Board has heard no evidence which persuades it that
ratepayers should bear 100% of the cost of incentive compensation. The Board believes that both
shareholders and ratepayers benefit from a well run-utility. The Board reaffirms its earlier decision
that an equal division of incentive compensation is the most appropriate method of allocating this
cost. Accordingly, NSPI’s 2002 test year expenses are reduced by approximately $1.58 million.
11.10 Operating, Maintenance and General Expenses
[362] The Board believes that it is incumbent on NSPI management to be able to
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demonstrate that it has made every effort to operate on a cost efficient basis when it seeks to increase
electric rates in Nova Scotia. The Board is not satisfied that NSPI management has made every
reasonable effort to eliminate unnecessary expenses.
[363] The Board’s concern in this regard goes beyond the present filing which
projects NSPI’s 2002 test year expenses. It appears from the evidence that, while overall OM&G
costs have not increased appreciably in the six years since the last rate hearing, certain corporate
expenses have increased significantly. The Board believes there is a pressing need to demonstrate
that cost reductions at NSPI affect the higher levels of the company as well as lower levels.
[364]
The Board has determined that NSPI shall undertake a review of the current
level of OM&G expenses and submit a report to the Board which demonstrates that NSPI is
operating as cost-efficiently as possible. After examining the report, the Board will determine if a
further study is required. If further action is required, the Board may appoint an independent
consultant to perform the study.
[365] The Board also directs NSPI to provide, on an annual basis, a detailed
analysis showing executive management expenses, including compensation, expenses, memberships
and other personal benefits including loans. Only then can the Board be satisfied that expenses are
“reasonable and prudent and properly chargeable...” in accordance with Section 45(2) of the Act.
11.11 Sponsorships and Donations
[366] NSPI’s test year expenses relating to sponsorships and donations are
disallowed. The Board reaffirms its 1996 ruling in this regard. The impact on the revenue
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requirement is a reduction of $635,800, which is the total proposed amount of $717,000 less the
amount billed to affiliate entities.
11.12 Affiliate Activity
(A)
Code of Conduct
[367] The Board is cognizant of the potential risk to ratepayers of unregulated
affiliate activities. The Interim Code of Conduct was developed in order to institute a number of
formalized measures to protect NSPI ratepayers. The Board finds that it is not appropriate, at this
time, to give final approval to the Interim Code of Conduct. There appears to be considerable merit
to the suggestion that Article 1.1 of the Code be amended to require that affiliate transactions must
demonstrate a benefit to NSPI customers as opposed to causing them no harm. The Board intends to
retain independent consultants to review the implications of such a change, and also to review the
desirability of making further changes in light of the recommendations contained in the PWC report,
the evidence presented at the hearing, and the findings of the Board in this decision.
[368]
The Board directs that NSPI’s external auditors shall provide to the Board a
schedule of their unadjusted differences (i.e., a summary of immaterial errors or exceptions), along
with the annual audit report on compliance with the Code. In addition, the Board directs that copies
of management or post-audit letters issued by NSPI’s external auditors in connection with their audit
of NSPI’s compliance with the provisions of the Interim Code of Conduct be filed with the Board by
the external auditors. Disclosure of this information supports the fundamental principles of fairness
and accountability with respect to affiliate activities. At the present time, Emera appears to be in the
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process of transferring to various affiliates a number of activities previously carried out by NSPI.
The Board has concerns about the fairness of these transactions and, accordingly, the Board believes
this reporting tool is a helpful instrument in protecting the interests of NSPI ratepayers.
(B)
Agency Agreement
[369] During the course of the hearing, NSPI indicated that it intended to enter into
an Agency Agreement with its affiliate, Emera Energy, covering fuel procurement, export electricity
sales and gas sales. The transfer of these functions apparently took place in late 2001. In its
evidence, NSPI has identified $672,000 as the amount of fees to be paid by NSPI to Emera Energy
for the provision of fuel procurement services by Emera Energy during the test year.
[370] The Board is concerned that a major portion of NSPI’s fuel procurement
activity, which the Board views as a core function of the Utility, representing a huge portion of
NSPI’s total costs, has been effectively transferred to an unregulated affiliate with no notice,
regulatory approval or formal documentation by way of contract.
[371] The Board finds that the manner in which NSPI has conducted itself with
respect to the Agency Agreement is not in keeping with the spirit and intent of the public utility
regulatory regime in this Province. The Board is of the view that Emera wishes to transfer to
affiliates many functions and activities which are carried out by NSPI. The Board is concerned that
these activities could lead to a reduction in income to NSPI, thereby resulting in an increased burden
on the ratepayers of NSPI. The Board’s concerns are exacerbated due to the inability of the NSPI
witnesses to answer questions concerning the details surrounding the operations of Emera and its
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affiliate companies.
[372] Since no document was available to the Board during the proceeding, the
intended terms of the agreement were unknown. The Board is not satisfied that, given the present
structure of NSPI and Emera, ratepayers will be adequately protected from Emera’s apparent
intention of levering off NSPI for the benefit of Emera shareholders.
[373] The Board disallows all fees paid by NSPI to Emera Energy in the test year for
fuel procurement services, export electricity sales and gas sales as being imprudent. Moreover, the
Board directs that NSPI resume full responsibility for its own fuel procurement, export electricity
sales and gas sales which the Board considers to be core functions of NSPI and an undertaking of the
Utility pursuant to Section 62 of the Act. There may be some point in the future when it would be
prudent for these functions to be out-sourced, but this is neither an appropriate time, nor are these
appropriate circumstances to consider doing so. No information or evaluation of Emera’s ability,
performance and track record relative to other service providers is available to the Board and there
are valid concerns relating to risk, conflict and harm to ratepayers should these functions be
performed by an affiliate.
[374] On October 8, 2002, NSPI filed, on a confidential basis, a copy of an executed
“Agency and Surplus Energy Purchase and Sale Agreement” between Emera Energy and NSPI.
NSPI has not requested approval of the Agreement and takes the position that none is required. The
Board disagrees with this view. Further, the Board is not satisfied on the evidence that any fees or
commissions paid by NSPI to Emergy Energy pursuant to the Agency Agreement are reasonable or
prudent in the circumstances and, accordingly, such fees will not be chargeable against ratepayers.
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[375] Based on the information available to the Board this will result in a reduction
of at least $672,000 in the revenue requirement. The Board directs NSPI to provide as part of its
Compliance Filing all fees paid in the test year to Emera Energy with respect to fuel procurement
services, export electricity sales and gas sales in order for the Board to determine the precise amount
to be disallowed as a result of this ruling.
[376]
The Board also directs NSPI to engage the services of experts in the area of
fuel procurement, especially coal, to develop in-house fuel procurement expertise as well as
formalized policies and procedures governing fuel purchases. The Board is concerned that neither
NSPI nor Emera Energy appear to have proper procedures or practices in place to control and govern
annual coal purchases of approximately $200 million. NSPI is further directed to report to the Board
on the status of its in-house fuel procurement division and policy and procedure development within
six months of the date of this decision, and to provide a follow-up report six months later.
[377] The Board further directs that prior to the future transfer of functions which, in
the opinion of the Board, could constitute an undertaking of the utility, NSPI must receive the
approval of the Board.
(C)
Shared Services Allocation
[378] NSPI has identified that it uses the "four-factor" formula in determining what
portion of the cost of services shared with its affiliates should be borne by NSPI. According to
NSPI’s auditors, the four-factor allocation method uses an average of the pro-rata percentage of
Emera’s consolidated assets; revenues; operating, maintenance and general expenses; and earnings
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before interest and taxes.
[379] The Board finds that the current method may result in unfairness. The
ratepayers currently bear the risk of the potential for unfairness as some senior management members
are engaged in fostering new businesses on behalf of Emera while NSPI ratepayers bear the lion’s
share of corporate costs.
[380] The Board is of the opinion that, with respect to senior management, welldocumented time allocation is the most appropriate method to determine how costs should be shared.
This is the best way to demonstrate that ratepayers are only charged for effort expended on their
behalf in respect of NSPI functions.
[381]
Accordingly, the Board directs NSPI to proceed to implement a cost
allocation method, to be in place for the year 2003, based on well-documented time keeping records
for those senior management employees having responsibilities for NSPI and any of its affiliates.
[382]
For those costs not allocated on a "time allocation" basis, the Board directs
that NSPI review and implement alternative methods of allocating its corporate support service costs.
The specific methods chosen should be based on measures that are specific to the particular units,
such as space, number of employees, etc. Prior to the implementation of the specific allocation
methods NSPI should prepare a report and submit it to the Board for approval. This report should
also include a list of those senior management employees who will be accounting for their daily time
and activities.
(D)
Coal Transportation Contract
[383] The surface assets of CBDC, which were used to transport coal for NSPI, have
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been acquired by an NSPI affiliate and NSPI has included this component of its coal transportation
costs in its revenue requirement, using CBDC’s contract price as a proxy for test year purposes. The
Board does not believe it is reasonable to use the CBDC price as representative of test year costs. In
the Board’s view, it is reasonable to expect that NSPI, or its affiliate, will operate the surface assets
at a lower cost than CBDC.
[384]
Having reviewed the evidence and bearing in mind the comments of PWC
with respect to the appropriate fair market value of CBDC’s transportation charges, the Board will
reduce NSPI’s deemed expense for the use of the CBDC surface assets by $2 million. NSPI’s
revenue requirement is reduced accordingly. Given its concerns arising from Ms. Hennings’
evidence, the Board is of the view that this is a conservative adjustment. The Board wishes to be
satisfied that NSPI will be paying fair market value for the use of these facilities in the future. NSPI
shall file information supporting its transportation expenses relating to these facilities within six
months of the date of this decision. If the Board is not satisfied with this information, it reserves the
right to engage suitable consultants to advise it concerning the fair market value of NSPI’s
expenditures with respect to these facilities.
(E)
Independence and Insulation
[385] The Board became increasingly concerned during the hearing with respect to
the apparent lack of separation between NSPI and Emera and how this could negatively impact
ratepayers. It is imperative, in the Board’s view, that NSPI and Emera avoid becoming so integrated
that senior management is conflicted between the interests of Emera shareholders and the interests of
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NSPI ratepayers. It is clear to the Board that these interests can diverge from time to time.
[386] The Board does not wish to limit Emera’s legitimate business development
initiatives, nor does it wish to prevent NSPI from achieving worthwhile efficiencies. Neither does it
wish to impose impractical restrictions on the relationship between NSPI and Emera. However, the
Board must be satisfied that the utility’s assets are not transferred to affiliates without appropriate
approval, regulatory oversight and objective arm’s length valuation. While the Board does not
consider it is necessary for NSPI to have a separate Board of Directors at this time, it does believe
certain changes in corporate governance would enhance the degree of insulation between NSPI and
Emera. Accordingly, the Board directs that effective for the year 2003:
1.
Emera and NSPI use different auditing firms; and
2.
NSPI’s audit committee shall have a different Chair than Emera’s audit
committee.
[387] The Board will continue to monitor this situation to determine what, if any,
further changes should be made in the future.
11.13 Cost of Service, Rate Design and Other Rate-Making Issues
(A)
Compliance Filing
[388] The revenue requirement approved by the Board is substantially lower than the
revenue requirement requested by NSPI and, consequently, the resulting rates will also be lower than
those proposed by NSPI. NSPI is directed to submit a Compliance Filing which will incorporate the
adjustments and directives set out in this decision. The issues giving rise to the Board’s adjustments
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and directives have already been the subject of a lengthy public proceeding as have the Company’s
proposed changes in rate structure. Intervenors have had a full and fair opportunity to challenge
NSPI’s application and present their respective positions through evidence and argument.
Accordingly, the Compliance Filing will be reviewed by the Board alone prior to the issuance of a
final Order in this matter.
(B)
Cost of Service Methodology
[389] The Board reaffirms the findings in its Cost of Service Decision dated
September 22, 1995. NSPI’s use of the Board’s approved methodology is accepted. Accordingly,
for the purposes of setting rates, the Board will rely upon a COSS which begins with the study
originally filed by NSPI, and reflects only the changes required to make the resulting study consistent
with the findings made elsewhere in this decision.
[390] As part of the Compliance Filing, NSPI is directed to provide a COSS in the
same format and detail as that provided in Appendix 2 of NSPI’s original filing. With that study,
NSPI is required to submit a brief statement identifying each change made from the original study,
and explain how each change was required by, and conforms to, the Board’s decision in this
proceeding.
(C)
Revenue/Cost Ratios and Rate Shock
[391] While the Board affirms the commitment in its decision in NSPI’s last rate
case to limit the class revenue requirements so that no class has an R/C ratio below 95% or above
105%, it also believes that, depending on the scale of a proposed rate increase, there may be
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justification for the Board to exercise some flexibility in the application of this general rule.
Judgement must be exercised in balancing the R/C ratio objective with the desire to avoid rate shock.
The Board finds that, to be reasonably applicable in a range of circumstances, the notion of rate
shock must take into account the underlying average level of increase. Generally speaking, in
considering the issue of rate shock, the Board will continue to strive towards its stated objective of
keeping R/C ratios in the 95% to 105%, subject to the foregoing caveat. The Board will apply these
principles in its review of NSPI’s Compliance Filing.
(D)
Annually Adjusted Rates
[392] With respect to Annually Adjusted Rates, the Board directs that AARs for
2002 be developed using the formulas approved in the past. Development of the AARs for 2002
should begin with the data used in preparing the AARs included in NSPI’s initial evidence.
However, that data should be modified to take into account all of the changes required elsewhere in
this decision. Similar changes, as required, should be made to the Mersey rate.
[393] As with the COSS, NSPI shall submit compliance versions of the AARs and
the Mersey rate for Board review. The Compliance Filing shall include a statement, identifying each
data change made for each rate, as well as a brief explanation of how each change conforms with the
filings and directives made in this decision. The AARs will be implemented after the Compliance
Filing has been reviewed by the Board, the changes, if any, required by the Board have been made
and the Board has issued a final Order approving the new rates. Once approved, however, the new
rates will be effective as at January 1, 2002.
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(E)
Rate Design
[394] The Board has determined that it will not address rate design issues at this
time. Instead, it will simply require a rate design which furthers the Board’s goal of having R/C
ratios in the 95% to 105% range, and which will minimize rate shock to the extent possible. The
Board finds that, for purposes of setting rates in this proceeding, the general rate design approach
described on pages 53 and 54 of NSPI’s evidence should be followed. NSPI is directed to set class
revenue requirements on the basis set out in Section 7.5 of this decision.
[395] The Board directs NSPI to develop and submit, as part of its Compliance
Filing, rates which meet all of the requirements prescribed by the Board to the fullest extent possible.
(F)
Future Rate Design Proceeding
[396] The Board has decided to conduct a separate rate design proceeding to be held
in 2003. Within the framework established by the ground rules set out in this decision, the parties
will have the opportunity to propose changes in rate design. In order to minimize effort, parties will
be allowed to enter testimony, exhibits and responses to information requests from the present
proceeding into evidence in the rate design proceeding.
11.14 Municipal/Large Industrial Rate Relationship
[397] For the first time in more than 25 years NSPI has proposed in this application
to "decouple" the Municipal rate from the Large Industrial rate. The Board is not persuaded that the
arguments in favour of decoupling the rate are so compelling that any change in the longstanding
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practice needs to be made in advance of the rate design proceeding to be held pursuant to this
decision. Accordingly, the Board directs that NSPI, in revising its rates in accordance with the
directions set out above, shall maintain the Municipal and Large Industrial rate components at the
same levels.
11.15 Green Rider Rate
[398] NSPI requested interim Board approval for a new rate which involves the
establishment of a voluntary rate under which customers could pay a premium for electric service, in
$5 increments, to promote the use of electricity generated from environmentally-friendly renewable
sources such as wind power. The Board has determined that while it will not give final approval for
the green rider rate at this time, it will, however, approve the rate on an interim basis to be reviewed
in detail during the next general rate proceeding.
11.16 Depreciation Expense
[399] NSPI forecasts depreciation expense of $102.8 million for the test year. The
last depreciation study filed by NSPI was based on 1994 data. The Board considers that NSPI’s
depreciation rates should be reviewed more frequently than once every seven years. NSPI is directed
to retain an external depreciation consultant and to file a report with the Board for review not later
than six months from the date of this decision.
11.17 Load Forecasting
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[400] The Board notes that Board staff and intervenors issued a number of IRs to
NSPI requesting evidence to support NSPI’s load forecast. While the Board finds that NSPI’s load
forecast has been developed in a reasonable manner, it directs NSPI to file, as part of any future rate
application, all supporting evidence pertaining to the development of its energy and peak demand
forecasts.
11.18 Dalhousie Legal Aid Service
[401] DLAS’ principal recommendation to the Board is that it introduce a “rate
subsidy program” under which low income residential customers would be subsidized by other
customers of the utility. DLAS does not explain how such a program should be implemented.
[402] The Board has in the past rejected the principle of rate subsidies based on
income disparity. The Board has given renewed consideration to the issue of rate subsidization
based on income in light of the arguments put forward by Dalhousie Legal Aid Service. However,
the Board continues to hold the view that the explanation of such rate subsidy programs is neither
contemplated by S. 67(1) nor appropriate in the context of the regulation of public utilities.
Section 67(1) of the Act is pertinent to any discussion of rate subsidies:
67(1) All tolls, rates and charges shall always, under substantially similar circumstances and
conditions in respect of service of the same description, be charged equally to all persons
and at the same rate, and the Board may by regulation declare what shall constitute
substantially similar circumstances and conditions.
11.19 Regulatory Process
[403]
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The Board is aware of NSPI’s complaint with respect to the length of time
154
involved in completing this proceeding. The Board is of the view that, relative to other North
American regulatory jurisdictions, the length of this proceeding was not unreasonable given the
complexity of the material; the lengthy interval between rate cases; the scope of the issues; the
magnitude and potential impact of the proposed increases; and the difficulties between the parties
relating to the availability of information.
[404] The Board does not agree with NSPI’s position that it was subjected to an
"...extraordinary ‘discovery’ process authorized by the Board in this case." NSPI is a monopoly
utility with a revenue requirement that is subject to public scrutiny. It is NSPI, not the intervenors,
which has the burden of proof in establishing that a rate increase is warranted.
[405] The Board will facilitate a technical conference, in advance of the next
hearing, between NSPI and intervenors for the purpose of streamlining the information request and
response process. The Board hopes that this will result in a shorter hearing and less acrimony
between the parties. This conference will occur following the filing of NSPI’s application and prior
to the issue of IRs.
[406] The Board does not object in principle to a settlement process in advance of
the hearing provided that all classes of ratepayers are represented in these discussions. To this end,
should NSPI wish to pursue a settlement process with intervenors, the Board will appoint a
consultant, at NSPI’s expense, to act as a consumer advocate for otherwise under-represented groups
of customers (i.e., domestic, small commercial). The Board may also determine that it would be in
the public interest to ensure that these customers are represented by a consumer advocate at the
technical conference referred to above. It goes without saying, of course, that any settlement
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agreement reached by the parties would be subject to scrutiny at a public hearing by the Board.
An Order will issue accordingly.
DATED at Halifax, Nova Scotia, this 23rd day of October, 2002.
___________________________
John A. Morash, Chair
___________________________
Margaret A.M. Shears, Vice-chair
___________________________
John L. Harris, Member
APPENDIX - A
List of Witnesses
On behalf of:
Witness
NSPI
Christopher Huskilson
James Taylor
Melvin Whalen
Michael O’Neil
Zeda Redden
Mary Lambert
J. A. Watkins
Richard D. Falconer
Kathleen C. McShane
ANNAPOLIS GROUP
Emily S. Medine
NSUARB
James A. Rothschild
Dr. John Stutz
ECANS
James R. Carpenter
Norman Pearce
Richard Gerrior
Marc D. LeClerc
William St. Leger
PROVINCE OF NOVA SCOTIA
Dr. Lawrence Kryzanowski
Dr. Gordon S. Roberts
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STORA ENSO
& BOWATER MERSEY
Sharon Hennings
Dr. Alan Rosenberg
Fred Hussey
EVENING SESSION
Dick Smyth, Vice-pres. - Canadian Manufacturers & Exporters
Eric Twohig - Renewable Energy Services Limited
Richard Freeman & Doug Ledwidge-Forest Products Assoc. of NS
Patricia Pilkington - residential customers
Mayor C. Cotter and Deputy Mayor Jim Fraser - Town of Trenton
Joey O’Brien - Ski Martock
Councillor Peter Newton - Municipality of Annapolis Co.
Paul O’Hara - Northend Community Health Centre
Bill Cruickshank, Recreation Facility Assoc. of NS
Alasdair Sinclair and Hilary Fraser - Face of Poverty Consultation
Warden Richard Cotton - Municipality of the County of Richmond
Mayor Billy Joe MacLean - Town of Port Hawkesbury
Warden Herbert DeLorey - Municipality of the Co. of Antigonish
Warden A. J. McDougall - Municipality of the Co. of Inverness
Perry Chandler - Strait Area Chamber of Commerce
Duncan Cross, Atlantic Region - Canadian Plastics Industry Assoc.
Manning MacDonald, MLA Cape Breton South
Michel Samson, MLA Richmond
Jerry Ackerman
OTHERS
W. A. (Bill) Macneil, P.Eng. on behalf O&Y Enterprise Purdy’s Wharf
Jo Sheppard, Lunenburg Co., NS
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APPENDIX - B
List of Formal Intervenors
Annapolis Group Inc.
Robert G. Grant, Q.C. and
Atlantic Shopping Centres Ltd.
Nancy G. Rubin
Avon Valley Greenhouses Ltd.
Ben’s Limited
Canadian Salt Company Limited
Capital District Health Authority
Cerescorp Company
CKF Inc.
Council of Nova Scotia University Presidents
Crown Fibre Tube Inc.
EastLink Limited
(Bragg Communications Inc.)
(Bay Communications Inc.)
(Halifax Cablevision Limited)
(K-Right Communications Limited)
(Access Communications Inc.)
(Access Bedford Sackville Cablevision Limited)
(Kings Cable Limited)
Envirosystems Inc.
Halifax Grain Elevator Limited
Halifax International Airport Authority
Halterm Limited
High Liner Foods Inc.
Irving Oil Limited
Irving Shipbuilding Inc.
Izaak Walton Killam Health Centre
J. D. Irving Ltd., Sawmill Division
Mactara Limited
Maritime Paper Products Ltd.
Michelin North America (Canada) Inc.
Minas Basin Pulp & Paper Company Ltd.
Mount Saint Vincent University
Nova Scotia School Boards Association
Oxford Frozen Foods Limited
PolyCello
Sable Offshore Energy Inc.
Scotia Investments Ltd.
Sifto Canada Inc
Sobeys Group Inc.
Sobey Leased Properties Ltd.
Statia Terminals Canada Incorporated
Antigonish, Town of
Brian R. MacNeil
Bowater Mersey Paper Company Limited
George Cooper, Q.C.
and Stora Enso Port Hawkesbury Limited
David MacDougall
Canadian Oil Heat Association - Nova Scotia Chapter
Debbie Jamieson, VP
Canadian Plastics Industry Association
Duncan Cross, Exec. Director
Canso, Town of
T. Troy Jenkins, CAO
Cape Breton Regional Municipality
John Whalley
Dalhousie Legal Aid Service
Claire McNeil, Staff Lawyer
Dalhousie University
Peter Howitt, MBA, P. Eng.
Donkin Resources Limited
Stephen Farrell, P. Eng., Pres.
Electricity Consumers Alliance of Nova Scotia (ECANS)
John Woods, P. Eng., Exec. Dir.
Forest Products Association of Nova Scotia
Steve D. Talbot, Exec. Director
GasWorks Installations Inc.
John H. Reynolds, P. Eng and
Dwight E. Jeans
Halifax Port Authority
Dennis W. Creamer
Halifax Regional Municipality
Mary Ellen Donovan, HRM
Liberal Caucus
Wayne Gaudet, Interim Leader
Lighthouse Energy Inc.
Ray Ritcey
Lunenburg, Town of
Bea Renton
and Lunenburg Electric Utility
Municipal Electric Utilities of Nova Scotia Co-operative
Don Regan, Berwick Electric
NB Power
Rick Mitton
NDP Caucus
Shawn Fuller, Mgr., Research
Nova Construction Company Limited
Mark MacDonald, Q.C.
Province of Nova Scotia
Jeannine Lagasse
Renewable Energy Services Limited
D. R. Harper, Eric Twohig and
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TrentonWorks Limited
ACA Cooperative Ltd. &
Eastern Protein Foods
Cherubini Metal Works Limited
Maritime Steel and Foundries Limited
United Steel Workers of America - Dist. 6
Wentworth Valley Developments Ltd.
Brian Wattling
A. William Moreira, Q. C. and
Ben Durnford
John Kingston
Steven Wilson
Informal Intervenor
Kimberly-Clark Nova Scotia
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Jack Blakeney
159
APPENDIX - C
INTERIM CODE OF CONDUCT
ORDER
NSUARB - NSPI-P-167
IN THE MATTER OF THE PUBLIC UTILITIES ACT
-andIN THE MATTER OF AN INTERIM CODE OF CONDUCT to govern the relations
between NOVA SCOTIA POWER INC. and its AFFILIATES
BEFORE:
John A. Morash, C.A., Chair
Margaret A.M. Shears, Vice-chair
John L. Harris, Q.C., Member
ORDER
WHEREAS Nova Scotia Power Inc. (NSPI) is a body corporate incorporated
pursuant to the Companies Act and is engaged in the production and supply of electrical
energy in Nova Scotia;
AND WHEREAS NSPI is a public utility and its business activities are
regulated by the Nova Scotia Utility and Review Board (Board) pursuant to the Public
Utilities Act;
AND WHEREAS NSPI is the principal operating subsidiary of, and is wholly
owned by, Emera Inc. (Emera), formerly known as NS Power Holdings Incorporated, a
body corporate incorporated pursuant to the Companies Act on July 23, 1998;
AND WHEREAS Emera, by itself and through subsidiaries other than NSPI,
has a number of business interests and engages in a number of business activities which
are not subject to regulation under the Public Utilities Act;
AND WHEREAS the Board stated the following in its decision dated March 4,
1996, on an application by NSPI for a general rate increase: “The Board will review the
issues involved in ensuring that unregulated subsidiaries are not cross-subsidized by the
customers of the utility and may at a later date prescribe additional cost separation
procedures to be followed by NSPI”;
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AND WHEREAS NSPI recognizes that the ratepayers of NSPI should not be
harmed by transactions between NSPI and its affiliates;
AND WHEREAS the Board has engaged Consultants to assist it in
developing a Code of Conduct which would apply to the business activities of NSPI and its
affiliates;
AND WHEREAS the Consultants have engaged in extensive discussions with
NSPI with regard to the form and content of a Code of Conduct;
AND WHEREAS the Board has reviewed the Code of Conduct developed by
its Consultants and NSPI, and is prepared to approve it on an interim basis;
AND WHEREAS the Code of Conduct is a public document which shall be
subject to review at a future general rate hearing or, in the discretion of the Board, at an
earlier public hearing;
IT IS ORDERED AND DECLARED THAT:
1. The NSPI Interim Code of Conduct attached hereto as Schedule “A” is hereby
approved;
2.
The Interim Code of Conduct shall come into force on September 16, 2001;
3. The Interim Code of Conduct shall remain in force until a final Code of Conduct
is approved by the Board pursuant to a future general rate hearing or pursuant to an earlier
public hearing at the discretion of the Board;
4. Notwithstanding that the Interim Code of Conduct does not formally come into
force until September 16, 2001, NSPI and its affiliates shall, to the extent feasible, conduct
their business activities in accordance with the provisions of the Interim Code of Conduct,
effective immediately.
DATED at Halifax, Nova Scotia, this 16th day of March, 2001.
_________________________
Clerk of the Board
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DECISION N.S. BOARD - 5 FÉV. 03.DOC
161
Schedule “A” to Board Order dated March 16, 2001
NOVA SCOTIA POWER INC.
INTERIM CODE OF CONDUCT
Effective September 16, 2001
1.0
PURPOSE
1.1
The primary purpose of this Code of Conduct is to ensure
that the customers of Nova Scotia Power Inc. (NSPI) are not
harmed by transactions between NSPI and its affiliates1.
2.0
STATEMENT OF PRINCIPLES
2.1
NSPI will neither subsidize, nor be subsidized by an
affiliate’s current or prospective activities. This means
that, among other things, NSPI’s customers will not bear the
risks nor share the rewards of an affiliate’s activities.
2.2
Competition in markets where NSPI’s affiliates are active
will not be impaired by non-market behaviour by NSPI.
3.0
CORPORATE STRUCTURE
Objectives
To separate regulated electric and other utility services2
from affiliate activities.
1
For the purposes of this Code of Conduct, the term “affiliate” shall be interpreted
in accordance with Sections 2(2), 2(3), and 2(4) of the Nova Scotia Companies Act.
2
Regulated electric and other utility services are those covered by the Public
Utilities Act.
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DECISION N.S. BOARD - 5 FÉV. 03.DOC
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Protocols
3.1
EMERA, the parent company of NSPI, will create and maintain
a corporate organizational structure which ensures that
regulated electric and other utility services are provided
solely by NSPI and by no other affiliate.
3.2
NSPI will maintain a complete list of all of its
affiliates. The list will include the name and address of
each affiliate, a brief description of its activities and
the names, addresses and telephone numbers of all of its
officers. The list will be kept on open file with the Nova
Scotia Utility and Review Board (Board).
4.0
UTILITY MANAGEMENT
Objectives
To dedicate to the provision of regulated services, in
terms of quality and numbers, a management team capable of
maintaining a superior level of performance, at the same
time as NSPI affiliates are expanding into other business
activities.
Protocols
4.1 NSPI will maintain a management team capable of delivering a
superior level of performance.
4.2
NSPI will prepare and submit to the Board an annual report
which summarizes utility results. The report format, and
contents thereof, shall be agreed upon in advance between
NSPI and the Board.
5.0
UTILITY
FINANCING
Objectives
To maintain a capital structure
for NSPI which is in accordance with applicable Board
decisions.
Protocols
5.1 NSPI’s capital structure will reflect the Board approved
capital structure.
5.2 NSPI’s
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DECISION N.S. BOARD - 5 FÉV. 03.DOC
will
not
be
used
to
subsidize
163
affiliate activities. Affiliate risks or losses will not be
borne by NSPI’s customers.
5.3 NSPI shall not, without the prior approval of the Board,
provide loans to, guarantee the indebtedness of, or invest in
securities of an affiliate.
6.0 FAIR DEALING
Objectives
To avoid discrimination in the matter of pricing or in any
other manner against non-affiliated buyers of regulated
electric utility services.
To avoid NSPI subsidizing
activities of affiliates.
or
being
subsidized
by
the
Protocols
6.1
NSPI will provide access to regulated utility services on a
non-discriminatory basis.
6.2
The financial records of NSPI, as well as NSPI’s information
systems, will be kept separate from those of its
affiliates.
6.3
NSPI will not directly or indirectly state, imply or offer
any preference or favoured treatment to NSPI’s affiliates or
persons using affiliate services.
6.4
NSPI will not provide confidential customer information to
affiliates or other persons without prior customer consent.
6.5
NSPI will provide customer information to NSPI affiliates
and non-affiliates in a non-discriminatory manner.
6.6
NSPI will charge Board approved rates for all regulated
electric and other utility services provided to affiliates.
6.7
NSPI will charge and be charged a market rate of return for
any assistance it provides to or receives from affiliates
by way of a guarantee or loan.
6.8
NSPI will charge and be charged prices which reflect fair
market value for all non-regulated utility goods and
services provided to affiliates or purchased from
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164
affiliates, provided that in no case shall NSPI supply such
goods and services at a loss.
Where prices based on market value cannot be established,
NSPI will charge prices which reflect the utility’s fullyallocated costs for the goods and services provided.
6.9
6.10
Where a capital asset is transferred from NSPI to an
affiliate or from an affiliate to NSPI, that asset will be
transferred at a price to be approved by the Board in
advance.
6.11
The costs of corporate support services3 will be fairly
allocated between NSPI and its affiliates. The allocation
factor employed will depend on the nature of the corporate
support services.
7.0
ACCOUNTING COMPLIANCE
Objectives
To separately and fully account for the value of goods,
services, financial and other support delivered to or from
NSPI and its affiliates.
Protocols
7.1
NSPI shall report annually to the Board the following
information:
(a)
(b)
A detailed listing of all assets, services and
products provided to and from NSPI and each of its
affiliated companies.
Each item on the listing should indicate the price
3
Corporate support services are those Management and Administrative services which
are provided to affiliates by NSPI. Examples include Board of Directors’ costs, Public
and Regulatory Affairs, Finance and Administration, Corporate Services, Legal, Human
Resources and Information Technology.
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(c)
(d)
(e)
received or paid and, as appropriate, the relevant
fully allocated costs or market values.
Where fair market value is used, an explanation should
be provided as to how the value was determined,
including the comparative source for the value.
Where cost allocations are involved, a description of
the cost allocators and methods used to make the
allocations should be included.
A summary of corporate services and the methodology
for ensuring fair allocations of these costs.
7.2
NSPI shall submit an annual report to the Board by its
external auditors, in a form satisfactory to the Board,
which indicates whether the company is in compliance with
the provisions of this Code of Conduct.
7.3
In order to monitor compliance, the Board at any time may
review the records of NSPI and, so far as is required for
this sole purpose, the records of NSPI affiliates.
8.0
EMPLOYEE COMPLIANCE
Objectives
To ensure understanding of and compliance with this Code of
Conduct.
Protocols
8.1
9.0
NSPI will inform all its managers and employees directly
involved in affiliate activities of their expected
behaviour relative to the Code of Conduct and will
undertake annual management reviews to ensure compliance.
GENERAL
9.1
All reports referred to in this document shall be provided
by April 30 in respect of each preceding year.
9.2
This Code of Conduct shall become effective six (6) months
following approval by the Board.
APPENDIX - D
BOARD ORDER ON DISCLOSURE
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166
ORDER
NSPI-P-875
(Preliminary Motion)
NOVA SCOTIA UTILITY AND REVIEW BOARD
IN THE MATTER OF THE PUBLIC UTILITIES ACT
- and -
IN THE MATTER OF an Application by Stora Enso Port Hawkesbury Limited, Bowater
Mersey Paper Company Limited and Annapolis Group et al to compel Nova Scotia Power
Incorporated to Provide Better and Fuller Responses to certain Information Requests filed by
the Applicants as a result of a request by Nova Scotia Power Incorporated for approval of
Changes to its Rates, Charges and Regulations
BEFORE:
John A. Morash, C.A., Chair
Margaret A. M. Shears, Vice-chair
John L. Harris, Q.C., Member
ORDER
WHEREAS the Applicants, Stora Enso Port Hawkesbury Limited, Bowater Mersey
Paper Company Limited (SEB) and the Annapolis Group et al (Annapolis) are formal Intervenors in
the application by Nova Scotia Power Incorporated (NSPI) for changes to its Rates, Charges and
Regulations, and have requested information from NSPI in accordance with the Hearing Order
issued by the Board;
AND WHEREAS in submissions dated March 8, 2002, SEB and Annapolis
requested that the Board compel NSPI to provide better and fuller responses to certain information
requests which the Applicants state are required in order to facilitate a satisfactory level of review of
fuel costs by experts retained by the Applicants in preparation for the upcoming rate hearing; and
which have been categorized by SEB as tender information; contracts (fuel and transportation); the
Cape Breton Development Corporation (CBDC) contract and information concerning the buyout;
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unit figures for individual plants including heat rates, generation, etc.; and the assumptions and
calculations used by NSPI to produce the summary information which has been provided;
AND WHEREAS after having invited submissions on the matter from all
Intervenors, the Board held a hearing on the application on March 11, 2002 at which time NSPI
argued that it should not be compelled to disclose the information sought as it is confidential and, if
disclosed, could result in commercial harm to NSPI, and that NSPI was not satisfied that such harm
could be mitigated by limiting access to such information to certain parties on a confidential basis;
AND WHEREAS the following persons participated in the said hearing:
George T. H. Cooper, Q.C., David S. MacDougall and Sharon Hennings for SEB
Nancy G. Rubin and Emily Medine for Annapolis
Benjamin R. Durnford for Trentonworks et al
Jeannine A. Lagassé for the Province of Nova Scotia
Karen L. Brown for Halifax Regional Municipality
John P. Woods for Electricity Consumers Alliance of Nova Scotia
Daniel M. Campbell, Q.C., for NSPI
S. Bruce Outhouse, Q.C., Board Counsel
AND WHEREAS pursuant to Board Regulatory Rule 7(9) the Board has the
discretion to determine whether and on what terms information, in respect of which a claim of
confidentiality has been made, should be disclosed;
AND WHEREAS in a decision of the Board dated June 19, 1990 in the matter of an
application for information by Scotia Biomass Power Incorporated, the Board made the following
statement explaining its decision to permit access to the information in question on a confidential
basis:
It has been argued by the respondents that even though the
information is relevant, Scotia Biomass has no real need for it
because (1) the Board’s staff and consultants have the information
and Scotia Biomass and the other intervenors can rely on the Board
to correctly analyze and evaluate this information... The Board does
not agree with these arguments. The Board’s experts are, in its
opinion, very competent in their field. However, they are not
infallible. The Board will benefit from having not only the
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Corporation’s testimony but also the testimony of its own experts
tested by well prepared intervenors... In a matter of such evident
importance to the intervenors it is essential that they not only be
able to test the evidence of other witnesses but they have access to
all information which may be necessary to build their own case.
[Board Decision, June 19, 1990, pp. 6 & 7]
AND WHEREAS after carefully reviewing the submissions of the participants, the
Board has determined that the findings of the Board as quoted above are applicable to the present
circumstances and that the public interest is best served in these circumstances by directing the
release of the information, as described in summary form above, on a limited and confidential basis
in accordance with the process set out in this Order;
AND WHEREAS the Board further notes that it retains the right to assess costs
and/or pursue appropriate action against any individual who violates the undertaking to maintain the
confidentiality of this information;
IT IS HEREBY ORDERED THAT:
1.
NSPI shall provide Designated Confidential Information, as
defined herein, to the Designated Recipients set out below.
2.
Designated Confidential Information shall consist of
following:
(a) fuel supply contracts;
(b) fuel transportation contracts;
(c) tender documentation related to (a) and
(b) above;
(d) correspondence and documents relating to
negotiation of termination of the long-term
CBDC coal supply contract, (sometimes referred
to as the contract “buyout”) including original
coal contract and amendments, termination
agreement and arbitration agreement;
(e) generating unit-specific production and cost
information, on a
monthly basis, including
but not limited to heat rates, monthly
forecast MWh of supply, cost of each fuel
source, and quantities and qualities of fuel
to be used by fuel source;
(f) an
explanation
of
the
assumptions
and
calculations
underlying
the
information
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provided above.
3.
Access to Designated Confidential Information shall be
restricted to the following Designated Recipients:
David S. MacDougall and Sharon Hennings;
Robert G. Grant, Q.C., Nancy G. Rubin and Emily Medine
A. William Moreira, Q.C. and Benjamin R. Durnford
Jeannine A. Lagassé
Mary Ellen Donovan and Karen L. Brown
Donald Regan and John P. Woods
4.
As a condition precedent to receiving Designated Confidential
Information, the Designated Recipients shall sign the form of
undertaking attached as Schedule “A” to this Order.
5.
No Designated Confidential Information furnished by NSPI shall
be given or communicated to persons other than the Designated
Recipients authorized under this Order. For greater certainty,
no Designated Confidential Information shall be provided to
the clients of Designated Recipients, to Intervenors or to
employees, officers or members of Intervenors.
6.
NSPI shall make the Designated Confidential Information
(including copies if necessary) available to the Designated
Recipients for review at its head office. No documentation
provided under this Order shall be removed from NSPI’s
premises without the consent of NSPI. Designated Recipients
may take such notes as may be necessary solely for the
purposes of this proceeding. Such notes shall be treated as
Designated Confidential Information.
7.
Where a reference to Designated Confidential Information is
required in pre-filed testimony, briefs, other legal documents
or arguments, such reference shall be by citation of title or
exhibit number only or by some other non-confidential
description which protects the confidentiality of the
information. In such circumstances, counsel and those persons
bound by this Order shall make every reasonable effort to
preserve the confidentiality of the information provided by
NSPI. The Board may draw upon all Designated Confidential
Information in the record in the deliberation of any decision
or order it may issue, but the Board will avoid the
reproduction in its decision of any Designated Confidential
Information.
8.
Where an Intervenor files testimony which contains Designated
Confidential Information, the testimony must be filed on a
confidential basis and the Designated Confidential Information
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170
must be specifically identified as such. In addition, the
Board will sit in camera to hear such evidence if requested by
NSPI.
9.
Should any appeal or challenge to the Board’s decision in this
proceeding be taken, any portions of the record which have
been designated confidential in accordance with this Order
shall be forwarded to the court in accordance with applicable
laws
and
procedures
but
under
seal
and
designated
confidential.
10.
Within 30 days after the Board has reached a final decision in
this proceeding, each person to whom Designated Confidential
Information has been provided shall return to NSPI such
Designated Confidential Information and shall destroy all
documents, notes and other materials containing or reflecting,
directly or indirectly, Designated Confidential Information,
and shall provide an affidavit of compliance to NSPI
respecting same.
11.
The date for filing intervenor evidence is extended until the
later of March 25, 2002 and twelve (12) calendar days from the
receipt of the information provided by NSPI to the Designated
Recipients pursuant to this Order.
DATED at Halifax, Nova Scotia, this 12th day of March,
2002.
_____________________________________
_
Clerk of the Board
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171
SCHEDULE “A”
NOVA SCOTIA UTILITY AND REVIEW BOARD
IN THE MATTER OF THE PUBLIC UTILITIES ACT
- and IN THE MATTER OF an Application by Stora Enso Port Hawkesbury Limited, Bowater
Mersey Paper Company Limited and Annapolis Group et al to compel Nova Scotia Power
Incorporated to Provide Better and Fuller Responses to certain Information Requests filed by
the Applicants as a result of a request by Nova Scotia Power Incorporated for approval of
Changes to its Rates, Charges and Regulations
UNDERTAKING
I,
, of
having read the Order of the Nova Scotia Utility and Review Board
dated the 12th day of March, 2002 concerning the provision to me of
designated confidential information, hereby undertake and agree to
abide by all the terms thereof.
DATED
at
, this
day of
March, 2002.
_________________________________
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172
APPENDIX - E
TEXT OF BOARD LETTER OF CLARIFICATION
March 22, 2002
By Fax: 420-1417
Ms. Nancy G. Rubin
Stewart McKelvey Stirling Scales
900-1959 Upper Water St
P. O. Box 997
Halifax, NS B3J 2X2
Dear Ms. Rubin :
Nova Scotia Power Inc. - Application for approval of certain revisions to
its Rates, Charges and Regulations -Application by Stora Enso Port Hawkesbury
Limited, Bowater Mersey Paper Company Limited and Annapolis Group et al to compel Nova Scotia
Power Incorporated to Provide Better and Fuller Responses to certain Information Requests Preliminary Hearing - P-875
This letter is further to your request, dated March 21, 2002, for
clarification as to whether Section 2(d) of the Order of the Board dated
March 12, 2002, which required Nova Scotia Power Incorporated (NSPI) to
provide better and fuller responses to certain information requests on a
limited and confidential basis, can be interpreted to include the
memorandum from NSPI management to the Board of Directors concerning the
costs incurred in the termination of the long term contract with Cape
Breton Development Corporation (CBDC).
The Board has received a submission from Counsel for NSPI objecting to
the disclosure of this document on the basis that documents provided to
the Board of Directors of NSPI are particularly sensitive and are not
included in the wording of the Board’s March 12, 2002 Order. Further, NSPI
states that disclosure of the information to your firm, which evidently
also represents CBDC, is “particularly inappropriate”.
The Board has reviewed the submissions in this matter and has determined
that Section 2(d) of the Order dated March 12, 2002 can reasonably be
interpreted to include the memorandum which is the subject of this
dispute.
Further, with respect to the issue of your firm acting for
CBDC, in the Board’s view, the confidentiality order signed by yourself
and Mr. Grant should adequately address this matter. The Board further
understands that neither you nor Mr. Grant represent CBDC.
Yours truly,
Nancy McNeil
Regulatory Affairs Officers/Clerk
c.c. Mr. Bruce Outhouse, Q.C., Board Counsel
Mr. Peter Gurnham, Q.C.
Mr. David MacDougall
Formal Intervenors
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DECISION N.S. BOARD - 5 FÉV. 03.DOC
Fax: 429-7347
Fax: 421-3130
Fax: 425-6350