October 16, 2016 VIA ELECTRONIC FILING Honorable Kimberly D

Transcription

October 16, 2016
VIA ELECTRONIC FILING
Honorable Kimberly D. Bose, Secretary
Federal Energy Regulatory Commission
888 First Street, NE
Washington, D.C. 20426
Re:
ISO New England Inc., Filing of 2016 Capital Budget and Revised Tariff
Sheets for Recovery of 2016 Administrative Costs;
Docket No. ER16-_______________________
Dear Secretary Bose:
Pursuant to Section 205 of the Federal Power Act, Part 35 of the Rules and Regulations
of the Federal Energy Regulatory Commission (the “Commission”), Section 12 of the
Participants Agreement among ISO New England Inc., the New England Power Pool and any
Individual Participants, 1 and Section IV.B.6.1 of the ISO New England Inc. Transmission,
Markets and Services Tariff (the “Tariff”), 2 ISO New England Inc. (the “ISO” or “ISO-NE”)
hereby submits its capital budget for calendar year 2016 (the “2016 Capital Budget”) and a
revised Section IV.A of the Tariff to reflect the collection of its administrative costs for calendar
year 2016 (the “2016 Administrative Expenses Tariff”). The ISO requests that the Commission
accept the 2016 Capital Budget and the 2016 Administrative Expenses Tariff as filed, effective
January 1, 2016.
Because the ISO is a non-profit entity without equity, it relies totally on collections under
its Tariff to fund its operational expenses, including through depreciation. For this reason, the
ISO is not in a position to make refunds should the Commission accept the 2016 Capital Budget
or the 2016 Administrative Expenses Tariff for filing but set them for hearing subject to refund.
That is, the only “refunds” that can be paid to ISO Customers during 2016 would have to be
funded by additional charges to other Customers. For this reason, the ISO respectfully requests
1
The Participants Agreement is available at http://www.iso-ne.com/static-assets/documents/regulatory/part_agree/
part_agree_1_15_11.pdf.
2
Capitalized terms used but not otherwise defined in this filing have the meanings given them in the Tariff.
October 16, 2015
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that the Commission accept the 2016 Capital Budget and the 2016 Administrative Expenses
Tariff without suspension and not subject to refund. 3
Should the Commission have any questions regarding the 2016 Capital Budget or the
2016 Administrative Expenses Tariff, the ISO respectfully requests that such concerns be
resolved in an accelerated fashion and addressed in the Commission’s Order issued prior to
January 1, 2016. If the Commission decides to set any issues for hearing, the ISO requests that
the Commission set the scope of any such hearing as specifically and narrowly as is feasible, and
require a paper hearing process, to ensure conservation of ISO, stakeholder, and Commission
staff resources.
I.
ISO-NE’S 2016 REVENUE REQUIREMENT AND REVISED SHEETS
A.
Overview
This filing presents the 2016 Revenue Requirement 4 for operating the ISO. Before
incorporating the true-up for 2014’s actual expenses and collections, the 2016 Revenue
Requirement is $185.2 million, which is $6.8 million more than in 2015. After the overcollection for 2014 is subtracted, the total 2016 Revenue Requirement decreases to $184.5
million. In comparison, the 2015 total – which was reduced by a much larger over-collection of
nearly $10 million – was $168.5 million.
In sum, the 2016 Revenue Requirement is 3.8% higher than in 2015 before the prior
years’ true-ups. When the two years’ operating budgets are compared with inclusion of the trueups (including the nearly $10 million true-up for 2013), the 2016 Revenue Requirement is 9.6%
higher than the 2015 Revenue Requirement.
For 2016, more than half of the increase in the Core Operating Budget is necessary to
maintain the ISO’s current operations, by funding competitive compensation, software licenses
and maintenance, and retirement and medical benefits. Most of the remaining increased costs are
attributable to: cyber security enhancements, including the establishment of a 24/7 cyber
security operations center, as directed by the ISO’s Board of Directors; meeting the Internal
Market Monitor’s resource needs; and implementing Commission-approved changes to the
Forward Capacity Market (“FCM”). Each of these initiatives is discussed in more detail in
Section I.C, below.
3
This approach is consistent with NEPOOL’s recommendation to the Commission that “contested budget increases
should not be implemented subject to ‘refunds’” because of the ISO’s non-profit status, which means that any
money already spent “can only be reallocated among the stakeholders, negating any true refund.” Comments of the
New England Power Pool Participants Committee at 3, Docket No. RM04-12-000 (Nov. 9, 2004) (“NEPOOL RTO
Cost Comments”).
4
As used in this filing, “Revenue Requirement” refers to the combination of: the administrative costs of running the
ISO (the “Core Operating Budget”); depreciation and amortization; and the true-up for past over-collection or undercollection in revenues versus expenses. Generally, numbers used herein are rounded for ease of reference and,
accordingly, may not sum.
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The ISO seeks to add 8.5 full-time employees in 2016, largely to staff the cyber security
operations center and to meet the Internal Market Monitor’s personnel requirements. The ISO is
meeting other staffing needs by reassigning existing employees. Barring unforeseen
circumstances, the ISO intends to fulfill all of its obligations with existing employees in the next
budget cycle.
The remainder of this Section I describes:
•
the 2016 budget development process (Section B);
•
components of the 2016 Revenue Requirement (Section C);
•
the three services provided by the ISO and funded by the 2016 Revenue
Requirement (Section D); and
•
the allocation of costs among the three primary schedules and the development of
the rates reflected in the 2016 Administrative Expenses Tariff (Section E).
B.
2016 Budget Development Process
The ISO has always operated in a climate of cost accountability and transparency. 5 The
ISO annually files with the Commission updated specific dollar-value, non-formula rates to
collect the ISO’s Revenue Requirement for each upcoming calendar year. Instead of using a
formula rate allowing the automatic collection of every expense as incurred, the ISO revises its
specific rates each year from a proposed annual Revenue Requirement that has been reviewed
through a multi-stage stakeholder process, voted on by participants, approved by the ISO’s
independent Board of Directors, and ultimately filed with the Commission for approval in an
open process in which any interested party may participate.
As in past years, the ISO’s budgeting process was driven by the business planning
process led by the ISO’s Board of Directors. The business plan’s timeline is five years and, for
that period, contains the following overarching objectives: New England’s bulk power system is
reliable in both the short- and long-term and the wholesale electricity markets are competitive
and efficient; and business operations are well-managed, cost effective, and responsive to New
England’s Market Participants, state officials, and other electricity stakeholders.
These objectives formed the foundation for development of the ISO’s 2016 Core
Operating Budget. The full seven-step process, throughout which stakeholder input was sought,
requires the ISO to:
5
•
define objectives, activities, and goals;
•
identify efficiencies for each department;
The NEPOOL Participants Committee, the ISO’s primary stakeholder body, has lauded the ISO’s budget process,
stating that it “works, not only because NEPOOL provides input, but also because ISO-NE is responsive to that
input.” NEPOOL RTO Cost Comments at 6.
October 16, 2015
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•
determine resource requirements;
•
develop budget estimates for each department;
•
adjust budgets to ensure that staff resources and activities are aligned with the
business plan;
•
conduct senior staff review to ensure alignment of the budget with the business
plan and overall fiscal constraint; and
•
develop priorities.
ISO-NE reviews the budgets with both the New England Power Pool (“NEPOOL”) and
the states. To kick off this year’s process, the ISO presented proposed budgets at the June 7,
2015 meeting with the New England Conference of Public Utilities Commissioners and the June
22, 2015 meeting of the NEPOOL Participants Committee.
The ISO then developed its 2016 Revenue Requirement proposal and posted a detailed
budget presentation, which includes more than 120 slides regarding the 2016 Capital Budget and
the 2016 Revenue Requirement (the “Budget Presentation”). 6 The ISO reviewed the Budget
Presentation at the NEPOOL Budget and Finance Subcommittee’s August 26, 2015 meeting and
at a meeting for state agencies on August 27, 2015.
Following the August 27 meeting, a number of the state agencies submitted written
questions regarding the budgets. ISO-NE provided answers, following which the state agencies
submitted written comments regarding the budget review process and the ISO’s headcount.
Those comments and the ISO’s response are located at Exhibits 10 and 11 to this filing letter. 7
The ISO reviewed the 2016 Capital Budget and the 2016 Revenue Requirement at the
NEPOOL Participants Committee’s meetings on September 11 and October 2, 2015. At the
October 2 meeting, the two budgets were supported unanimously by the Participants Committee
(with abstentions).
Contemporaneously with the stakeholder processes, the Board of Directors undertakes its
review of the budget. The Board process includes review of particular elements of the budgets
by Board committees with responsibility in a defined area. For example, compensation matters
are reviewed by the Compensation and Human Resources Committee and projects with
reliability implications are reviewed by the System Planning and Reliability Committee. The
Audit and Finance Committee advises management throughout the development of the budgets
and engages in a detailed review of the budgets in both May and August.
In addition to receiving updates throughout the process from management regarding the
stakeholder process and from the Audit and Finance Committee, the Board engages in an in6
The Budget Presentation is available at http://www.iso-ne.com/static-assets/documents/2015/09/2_2016_operat_
capital_budget_update_09_23_2015.pdf.
7
Pursuant to a settlement agreement entered into among certain state agencies and the ISO regarding the 2013
budgets, ISO-NE is required to include these comments and its response in its budget filing.
October 16, 2015
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depth review of the budgets at its September meeting. Last, after receiving final feedback from
stakeholders in the form of the Participants Committee’s vote and the comments of the
participating state agencies, the Board votes on the budgets. 8 In the instant case, after reviewing
all input from stakeholders, including the vote of the Participants Committee, the ISO’s Board of
Directors approved the 2016 budgets effective October 15, 2015.
C.
The 2016 Revenue Requirement
This section provides an overview of the 2016 Revenue Requirement and detail regarding
its significant components. Additional detail can be found at Exhibit 3 in the testimony of
Robert C. Ludlow, the ISO’s Chief Financial Officer, and the exhibits thereto.
As noted above, the 2016 Revenue Requirement, after the true-up for 2014, is $184.5
million.9 It includes the following components, each of which is discussed below.
•
the 2016 Core Operating Budget ($152.2 million);
•
depreciation and amortization of regulatory assets ($33 million); and
•
a true-up for 2014 that reduces the 2016 Revenue Requirement by $600,000 as a
result of over-collection of ISO rates in 2014.
While the ISO has amassed a consistent track record of spending integrity – since the
inception of its self-funding tariff for calendar year 1998, the ISO’s annual spending has never
exceeded its budget – the risk exists that the ISO may have to incur additional expenditures
during 2016 that exceed the allocated amounts and contingencies. Specific potential risks
include unforeseeable litigation, costs of complying with Order 1000 that exceed estimates,
cyber security threats, imposition of new requirements by policymakers, and interest rate
changes.
In general, the demands placed on the ISO by Market Participants and regulators will
determine the extent of additional work and the resources the ISO will require. In any case,
should the need ever arise for the ISO to spend more than a given year’s Revenue Requirement,
the ISO will first seek stakeholder support and then file a rate increase with the Commission,
thus allowing stakeholder and Commission review before approving such increases.
1.
Components of the Core Operating Budget Increase
The ISO proposes to increase its Core Operating Budget from 2015 levels to:
(i) maintain competitive compensation and benefits ($3.8 million); (ii) maintain existing software
licenses and maintenance ($1.3 million); (iii) fund cyber security initiatives ($1.3 million),
including the institution of a 24/7 cyber security operations center which accounts for
8
The ISO must report the results of all Participants Committee votes on the budgets to the Board of Directors and to
the Commission. Participants Agreement at §§ 12.3, 12.5
9
See the Budget Presentation for a breakdown of the Revenue Requirement by functional area (slides 24-45) and
category (slides 64-77).
October 16, 2015
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approximately half of the increase; (iv) meet the Internal Market Monitor’s resource needs,
including two new headcount ($1.0 million); (v) implement changes to FCM ($800,000); and
(vi) miscellaneous increases, including increased costs for hardware leasing, maintenance,
information technology consulting, and training. Below, the ISO discusses the costs in each of
these categories, including the addition of 8.5 employees, 10 and then reviews the savings,
efficiencies, and non-recurring work that offset these increases by $3.8 million. 11
a.
Increases to Maintain Competitive Compensation and Benefits
To maintain medical benefits and life and disability insurance for its employees and to
fund its defined contribution pension plan, 12 the ISO will incur an additional $700,000 in costs.
This category also includes the ISO’s $3.1 million budget for a 2.75% increase in salaries based
on merit and a .75% increase for promotions.
The merit and promotional increases are used to keep the ISO’s salaries competitive,
thereby attracting and retaining the high-quality employees crucial to the ISO’s operations. This
goal remains relevant, as more candidates are declining the ISO’s job offers, and many are citing
compensation as the reason; specifically, thirteen candidates declined the ISO’s job offers in
2014 and to this point in 2015 because, in their estimation, the compensation was insufficient. 13
In addition, the ISO has lost eighteen employees in 2014 and to date in 2015 to higher-paying
jobs. 14 With this turnover comes inefficiency; for example, it takes months to fill a transmission
engineer vacancy, followed by an inevitable learning curve.
To establish the amounts of the merit and promotional increases, the ISO reviews survey
data from several national compensation consultants on expected merit and promotional pool
increases, as well as expected salary range adjustments for the coming year. The surveys the
ISO used to develop its 2016 Revenue Requirement recommendations collectively polled
thousands of employers and include both all-industry and utility-specific data. 15
The ISO also complies with the standards of the Internal Revenue Service when
determining executive compensation. These standards encompass all aspects of compensation,
including base salary and all bonuses, and require that the ISO’s executive and Board
compensation fall within a range of competitive practices for total compensation paid by
10
See slide 23 of the Budget Presentation for a breakdown of the new additions.
11
See the Budget Presentation for more information on all of these year-over-year budget changes.
12
As of January 1, 2014, the ISO closed its defined benefit plan to new entrants and offered new employees an
enhanced defined contribution plan.
13
See Exhibit 4 at p. 7 and ISO New England Inc., Filing of 2015 Capital Budget and Revised Tariff Sheets for
Recovery of 2015 Administrative Costs, Docket No. ER15-112-000 at pp. 6-7 of Exhibit 4 (October 16, 2014).
14
15
Id.
The surveys used by the ISO were conducted by Buck Consultants, Mercer, WorldatWork, the Conference Board,
Towers Watson and Aon Hewitt.
October 16, 2015
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similarly-situated organizations, both taxable and tax-exempt, for functionally comparable
positions. 16
To ensure compliance, the ISO has engaged a nationally recognized, independent
consulting firm, which evaluates the compensation offered by similarly-situated entities. This
evaluation includes other system operators and select for-profit “peer” utility organizations
(chosen for organizational size, complexity, and scope of responsibilities). It also incorporates a
broader comparison across all industries for positions not unique to utilities (again, comparators
are selected for organizational size, complexity, and scope of responsibilities). The resulting
opinion each year has been that the ISO’s executive and Board compensation is within a
reasonable range of competitive practice for functionally comparable positions among similarlysituated entities. The Commission has found that this process results in just and reasonable
compensation. 17
The testimony of Janice S. Dickstein, the ISO’s Vice President, Human Resources
(located at Exhibit 4), provides more detail on the ISO’s compensation practices, as does the
Budget Presentation (at slides 46-61).
b.
Increases in Computer Licensing and Maintenance Costs
The cost increase of $1.3 million in this category represents increased costs for on-going
support, systems backup software, and support for new hardware and software. Most
significantly, the costs stem from Microsoft’s determination that independent system operators
and regional transmission organizations no longer qualify for pricing as charitable organizations.
c.
Cyber Security Costs
Costs in the area of cyber security reflect the growing risk in this area, and the ISO’s
vulnerability, given its control of sensitive information about the financial settlement of billions
of dollars per year, the topology of the grid, and the protected information of Market Participants
and employees.
More than half of the cost increase of $1.3 million in this category is to fund six full-time
employees who will provide around-the-clock surveillance of systems and networks in a cyber
security operations center. The ISO’s Board of Directors proposed this center after convening an
ad hoc Cyber Security Committee to assess and address the cyber security risks to the ISO. The
remainder of the cost increase is for new or enhanced monitoring software and for cyber security
insurance, a relatively new product that provides protection against the costs of a cyber security
event.
16
See Internal Revenue Code § 4958.
17
ISO New England Inc., 117 FERC ¶ 61,310 at P 18 (2006); Order on paper hearing and finding rehearing to be
moot, 119 FERC ¶ 61,178 (2007).
October 16, 2015
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d.
Costs to Meet the Internal Market Monitor’s Resource Needs
The ISO’s Internal Market Monitor has identified resources that are required to allow his
department to perform their monitoring and mitigation functions. These resources include two
new full-time employees and consulting support to address workload created by new features of
FCM, including de-list reviews, non-price retirements, Pay For Performance, and an update to
the Offer Review Trigger Price. Other portions of the cost increase will fund enhanced
monitoring capabilities through improvements in processes, data gathering, and analysis for
systems enhancements. Finally, funds have been allocated for information technology support of
market monitoring systems.
e.
Implementation of Changes to FCM
As noted in the preceding paragraph, there have been a number of changes to FCM that
have increased the ISO’s workload. More specifically, the cost increase in this category results
from the need for additional consulting and staff time in Market Development to design sloped
demand curves, qualification process changes, and auction pricing rules and associated
reconfiguration auctions. Other increased costs include consultant funding in System Planning
to update the calculation of the Cost of New Entry.
f.
Miscellaneous Increases
The cost increase in this category is attributable to increased hardware leasing costs,
maintenance of new control room communication systems, consulting services in Information
Technology to support Model-On-Demand, support for enhancements to the Energy
Management System, training on reliability standards for System Operations, and integration of
market enhancements in Settlements and Market Operations. These enhancements include SubHourly Settlements, Divisional Accounting and Oracle Business Intelligence. Finally, this
category includes increased dues owed to the North American Electric Reliability Corporation
(“NERC”) and the Northeast Power Coordinating Council and fees for the Eastern Interconnect
Data Sharing Network.
g.
Offsetting Savings; Direct Charge Activities
The ISO works to offset increased costs through cost-cutting and reallocation of
resources to emerging initiatives. For 2016, the ISO has realized $3.8 million by reallocating
resources, automating work, identifying efficiencies, and eliminating discontinued or nonrepetitive work.
To meet 2016 priorities, the ISO will reallocate the responsibilities of six employees in
Market Operations and two in System Planning. Additionally, internal ISO employees will
assume work previously performed by contractors, under both the operating and capital budgets,
including in Market Operations (operating and capital), Legal (operating), and System Planning
(operating).
The ISO also expects to reduce salaries as a result of staff turnover. Finally, automation
of functions in Market Operations and Settlements, including improvements in data querying and
October 16, 2015
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validation, resettlement processing and certain reporting tools, will result in reduced data
gathering and processing time.
The $3.8 million also includes a small amount of savings in year-over-year contributions
to the ISO’s defined benefit pension plan, which was closed to new entrants as of January 1,
2014, but which must still be funded to meet the ISO’s obligations to employees who were
enrolled before that cut-off date.
For 2016 and future years, the ISO has changed its funding methodology for the defined
benefit pension plan by adopting a “level funding” approach. After consulting with its actuaries
and investment consultants, the ISO decided on a flat $10 million contribution to the plans for
each of the next ten years (barring unforeseen circumstances). This level funding approach
should decrease the volatility of the expense while still maintaining reasonable levels of funding.
If the ISO had not adopted this approach, the 2016 contribution would have been $11.05
million.18
The ISO will also offset its costs through certain direct charges. Section IV.A of the
Tariff includes provisions for the ISO to assess direct charges to collect reasonable
administrative costs for performing certain discrete functions, including transmission studies,19
information requests, 20 non-standard contract provisions, 21 and non-standard billing. 22 Expected
revenues to reimburse ISO staff efforts for studies (as opposed to revenues that are flowed
through to contractors actually performing the studies) have been used to reduce the relevant
schedule’s 2016 Revenue Requirement.
2.
Depreciation
As a non-profit entity without equity, the ISO must recover revenues consistent with its
obligation to repay the loans funding its projects. In fact, the ability to obtain and maintain
independent financing is dependent upon the ISO’s being able to recover the principal portion of
debt service through depreciation and amortization.
For 2016, the ISO’s depreciation and amortization costs are $33 million, which is $1.3
more than in 2015. The increased costs are largely attributable to a number of significant capital
projects expected to go into service at the end of 2015 or the beginning of 2016, including the
Coordinated Transaction Scheduling project, Part 1 of the Generation Control Application
project, phase 3 of the Business Continuity Planning project, the project to comply with version
18
See the Budget Presentation at slides 57-58 and Exhibit 3 at p. 15.
19
Tariff § IV.A.6.1 (Transmission Studies). This provision permits, for example, charging for the performance of
System Impact Studies, Facilities Studies and FCM qualification studies.
20
Tariff § IV.A.6.2 (Information Requests).
21
Tariff § IV.A.6.3 (Non-Standard Provisions).
22
Tariff § IV.A.6.4 (Non-Standard Billing Service).
October 16, 2015
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5 of NERC’s Critical Infrastructure Protection standards, and phase 2 of the Wind Integration/Do
Not Exceed Dispatch project. 23
The ISO’s depreciation rates remain unchanged from those previously accepted by the
Commission.24 The ISO uses the straight-line depreciation methodology based on no net salvage
value and the various average service lives described below. These service lives reflect the
ISO’s historical experience and forecasted expectations for capital projects placed into service,
are necessary to comply with the ISO’s funding mechanisms, are consistent with the ISO’s
historical experience, and have been repeatedly determined by independent auditors to be
reasonable. The service lives are:
•
Computer hardware, software and accessories: 3 to 5 years
•
Software development costs: 3 to 5 years
•
Furniture and fixtures: 7 years
•
Machinery and equipment: 7 years
•
Building: average of 25 years (based on the opinion of independent bond counsel
and analysis of the service lives of the different aspects of the building (e.g., the
building’s steel and concrete at 40 years, mechanical and electrical work at 25
years, and high wear-and-tear elements at 15 years))
•
Leasehold/Building Improvements: lesser of 1 to 25 years or remaining life of the
lease or building, as determined at the time of the purchase based on the nature of
each such improvement (e.g., rooftop railing at twenty-five years, air conditioning
unit at fifteen years, capacitor bank at ten years)
•
Vehicles: 3-7 years
3.
True-Up Mechanism
As set forth in Section IV.A.2.2 of the Tariff, the 2016 Revenue Requirement includes an
adjustment for deviations between actual collections and expenses for calendar year 2014. In
general, the amount of the true-up is added to (in the case of a revenue shortfall) or subtracted
from (in the case of a revenue over-recovery) the ISO’s total estimated budgeted amounts for the
upcoming budget year. In the case of the 2014 true-up, the ISO collected $600,000 more than it
needed to pay its expenses. 25 This sum will be subtracted from the 2016 Revenue Requirement.
With respect to Schedule 1, the ISO had expenses of $38 million, and collected revenues
of $36.3 million, resulting in an under-collection for Schedule 1 (i.e., the increase to the 2016
23
See Exhibit 3, RCL-5, Schedule 4, page 2 of 2.
24
In 2006, the Commission examined and accepted the ISO’s depreciation rates after holding a paper hearing. ISO
New England Inc., 117 FERC ¶ 61,310 at P 18 (2006), Order on paper hearing and finding rehearing to be moot,
119 FERC ¶ 61,178 (2007).
25
October 16, 2015
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Revenue Requirement for Schedule 1) of about $1.7 million.26 With respect to Schedule 2, the
ISO had expenses of $75.2 million and collected revenues of $77.5 million, resulting in an overcollection for Schedule 2 (i.e., the decrease to the 2016 Revenue Requirement for Schedule 2) of
approximately $2.35 million. 27 Finally, with respect to Schedule 3, the ISO had expenses of
$49.55 million and collected revenues of $49.51 million, resulting in an under-collection for
Schedule 3 (i.e., the increase to the 2016 Revenue Requirement for Schedule 3) of approximately
$40,000. 28
D.
Services Funded by the 2016 Revenue Requirement
This section discusses the three services the ISO provides, which correspond to the rate
schedules through which the ISO recovers its Revenue Requirement: Schedule 1 - Scheduling,
System Control and Dispatch Service (“Scheduling Service”); Schedule 2 - Energy
Administration Service; and Schedule 3 - Reliability Administration Service.
1.
Scheduling Service (Schedule 1)
Scheduling Service includes the transmission-related service required to schedule at the
pool level the movement of power through, out of, within, or into the New England Control
Area. It does not cover expenses of dispatching Energy, which are collected as part of the
charges in Schedule 2. Scheduling Service can be provided only by the ISO, and all
Transmission Customers must purchase this Service from the ISO. The 2016 Revenue
Requirement for Schedule 1 (including true-ups) is $46 million.
Functions performed by the ISO in connection with this Service include:
26
•
processing and implementation of requests for Regional Transmission Service,
including support of the Open Access Same-Time Information System node;
•
coordination of transmission system operation (including administration of
reactive power requirements under Schedule 2 of Section II of the Tariff) and
implementation of necessary control actions by the ISO and support for these
functions;
•
billing associated with regional transmission services provided under the Tariff;
•
transmission system planning that supports this Service; and
•
administrative costs associated with the aforementioned functions.
27
See Exhibit 3, RCL-2, Schedule 2, page 2 of 2. Pursuant to Section IV.A.2.2 of the Tariff, the true-up is
calculated separately for Schedule 2. See also Section I.E.4.b of this transmittal letter.
28
See Exhibit 3, RCL-2, Schedule, 2 page 2 of 2.
October 16, 2015
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2.
Energy Administration Service (Schedule 2)
Energy Administration Service is the service provided by the ISO to administer the
Energy Market. The 2016 Revenue Requirement for Schedule 2 (including true-ups) is $82.4
million.
The ISO’s functions that comprise Energy Administration Service include:
•
core operation of the Energy Market;
•
generation and demand dispatch related to the Energy Market;
•
energy accounting;
•
loss determination and allocation;
•
billing preparation;
•
market power monitoring and mitigation for the Energy Market;
•
sanctions activities;
•
operation of Financial Transmission Rights auctions;
•
market assessment and reports; and
•
formulation of additional market rules and proposals to modify existing rules.
3.
Reliability Administration Service (Schedule 3)
The ISO provides Reliability Administration Service to administer the Reliability
Markets, including FCM, in accordance with Market Rule 1 and to provide other reliability and
informational services. These services are of a type not directly related to the services provided
under Schedules 1 and 2, and are expenses of operating the New England Control Area
generally, rather than expenses attributable to serving a particular Customer. The 2016 Revenue
Requirement for Schedule 3 (including true-ups) is $56.1 million.
Examples of the functions performed (in addition to the core operation of the Reliability
Markets) include:
•
generation and demand dispatch associated with Reliability Markets;
•
Reliability Markets accounting;
•
billing preparation;
•
generation emissions analysis;
•
risk profile updates;
•
triennial review of resource adequacy;
•
studies and qualification of resources under FCM;
October 16, 2015
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•
preparation of regional reports and load forecasts and profiles (Capacity, Energy,
Load and Transmission (“CELT”) Reports; reports to the Energy Information
Administration of the United States Department of Energy; reports to NERC;
Regional System Plan);
•
support of power supply, environmental and market reliability planning activities;
•
market power monitoring, mitigation and assessment for the Reliability Markets;
and
•
formulation of additional market rules and proposals to modify existing rules.
E.
Cost Allocation and Rate Development
This section describes the new rates proposed herein by: (i) detailing how the ISO
generally allocates its costs among the three core rate schedules; (ii) explaining the billing
determinants used by each schedule; (iii) explaining how the ISO adjusted the billing
determinants for 2016; (iv) describing the rates ultimately derived for 2016 for each schedule;
and (v) explaining how and why the Revenue Requirement for each schedule shifted.
1.
Cost Allocation Among the ISO’s Services
Most of the ISO’s operating costs are fixed and do not vary based on the volume of a
Customer’s activity—a fact recognized by the Commission itself. 29 The ISO established the core
rate design for its first three schedules through an uncontested settlement approved by the
Commission in 2001, 30 with additional modifications reflecting necessary changes upon the
commencement of Standard Market Design in New England. Although the 2001 settlement is no
longer binding, the ISO followed the same cost allocation among the three primary schedules
when establishing the rates proposed herein.
The Tariff structure relies upon the activity-based allocation of the ISO’s costs to its three
rate schedules, namely Scheduling Service, Energy Administration Service, and Reliability
Administration Service. These rate schedules coincide with the main “service categories” of the
ISO. Exhibit 3, RCL-3, Schedule 1 contains a Test Year 2016 cost of service for the three rate
schedules. This exhibit lays out in detail how the ISO’s costs were assigned to the schedules.
In assessing how costs should be assigned to the various categories of service that the
ISO provides to its Customers, the objective is to reflect cost causation principles as much as
possible. All costs that could be assigned to the three rate schedules using direct allocators were
so allocated. Most activity costs consist of direct labor costs, employee benefits, and other nonlabor-related costs (i.e., office supplies, software, hardware, depreciation, interest, etc.). For
each activity code, both the labor-related and non labor-related costs are assigned to the rate
29
ISO New England Inc., 89 FERC ¶ 61,339 at p. 62,019 (1999), reh’g denied, 91 FERC ¶ 61,016 (2000) (finding
that the ISO’s expenses “are essentially fixed” and that the issue of rate design involves “not so much cost causation,
as it does the equitable allocation of an essentially fixed amount of expenses among many users of the grid”).
30
See Settlement Agreement in Docket No. ER01-316-000 (filed June 1, 2001).
October 16, 2015
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schedule using the same allocator. Within a given department, known allocators (Alloc-Fixed)
for specific cost categories or activities were used to allocate those labor costs that were
specifically attributable to a schedule. All remaining labor costs within that department were
allocated in proportion to the distribution of the summed Alloc-Fixed labor costs among the three
schedules. Labor costs within all departments were allocated in this manner and summed for the
entire company.
2.
Rate Design and Billing Determinants
As discussed below, each Schedule utilizes different billing determinants and attempts to
reflect cost causation principles, to the extent possible. The ISO is not proposing any changes to
the design of the billing determinants for 2016; however, as part of its filing of the Coordinated
Transaction Scheduling (“CTS”) project with the New York ISO, ISO-NE filed changes to
Schedules 1, 2 and 3 of Section IV.A of the Tariff on September 10, 2015. 31 Those changes are
still pending before the Commission.
CTS is intended to enhance the market efficiency of external transactions (i.e., energy
imports and exports) between the two regions through economic clearing of external
transactions. As part of that effort, ISO-NE has proposed that certain charges in Schedules 1, 2
and 3 be eliminated, effective on or after December 1, 2015. If the Commission approves the
changes, they will affect collections under Schedules 1, 2 and 3. The ISO has estimated the
impact of this change using historical monthly average volumes for external transactions and
total pool charges, and, based on the analysis performed, has concluded that the eliminated
charges make up 1.1% of Schedule 1 total charges, 2.8% of Schedule 2 charges, and 1.4% of
Schedule 3 charges. Their elimination will raise the affected billing determinants. 32
In its development of rates for 2016, ISO-NE has presumed Commission approval of the
pending CTS filing; accordingly, any effects have been incorporated into the 2016 rates that are
described herein. Below, ISO-NE highlights the sections of the Schedules where CTS changes
have been proposed.
a.
Schedule 1
The billing determinants for Schedule 1 are Monthly Regional Network Load and
Reserved Capacity; changes are pending before the Commission to exclude Coordinated
External Transactions, which are defined in Section I of the Tariff as transactions at external
interfaces to which the enhanced scheduling procedures in the CTS rules (located in Tariff
Section III.1.10.7.A) apply.
31
ISO New England Inc. and New England Power Pool, Coordination Agreement, Market Rule 1, OATT
Conforming Revisions Relating to Coordinated Transaction Scheduling; Docket No. ER15-2641-000 (September
10, 2015).
32
Slides 5-7 of “Coordinated Transaction Scheduling: Self and Capital Funding Tariff,” a presentation to the
NEPOOL Budget & Finance Subcommittee that was made in May 2015. The presentation can be found at
http://www.iso-ne.com/static-assets/documents/2015/05/5a_coordinated_transaction_sch_self_cap_cft.pdf.
October 16, 2015
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Monthly Regional Network Load is measured in kilowatts. The determinant based on
Reserved Capacity uses the highest amount of Reserved Capacity for an hour for each
transaction scheduled to occur during the month as Through or Out Service. Schedule 1
revenues collected from Through or Out Service Customers are credited to each Network
Customer that month in proportion to each Network Customer’s Monthly Regional Network
Load. Revenues from the Non-Participant Financial Transmission Rights (“FTR”) fee described
in Market Rule 1 and non-refundable Long Lead Facility deposits will be credited to the
Schedule 1 Revenue Requirement through future true-ups.
b.
Schedule 2
The Schedule 2 Revenue Requirement is allocated 15% to Transaction Units (“TUs”) and
85% to Volumetric Measures (“VMs”), subject to the special true-up described below. TUs
measure the frequency and duration of activity and are indifferent to the size (e.g., capacity) of
any particular transaction. Conversely, VMs seek to capture a Customer’s “physical” reliance on
the system administered by the ISO and thus the benefit received.
Schedule 2 utilizes three types of TUs: (i) those associated with Real-Time Energy
Market transactions (“Energy TU Based Charges”), (ii) those associated with Increment Offers
and Decrement Bids, and (iii) those associated with FTR auction bids.
Energy TU Based Charges: These charges equal the sum per month of a Customer’s
Bilateral Contract Block-Hours, Demand Bid Block-Hours, Asset Related Demand Bid BlockHours, Supply Offer Block-Hours and Energy Non-Zero Spot Market Settlement Hours. Under
the ISO’s current rate design, a Customer’s total monthly Energy TUs are priced under a threetiered declining block rate structure. Under this regime, the highest unit rate applies to the first
12,500 Energy TUs incurred in a month. The Customer’s next 27,000 Energy TUs are priced
approximately 10% lower, with the balance of monthly Energy TUs (i.e., those in excess of
39,500) priced at an additional savings of approximately 10%. If the Commission approves the
pending CTS rules, Energy TUs will be calculated without reference to contributions from
Coordinated External Transactions.
TU Charges Based on Increment Offers and Decrement Bids: These charges are
based on both of the following: (i) a charge multiplied by the total number of Increment Offers
and Decrement Bids submitted; plus (ii) a charge multiplied by the total number of Increment
Offers and Decrement Bids that clear the Day-Ahead Energy Market. This category is
sometimes referred to as “virtual activity.”
TU Charges Based on FTR Auction Bids Submitted and Cleared: These charges are
intended to recover all costs for operating the monthly, multi-month and annual FTR auctions.
The charges consist of: (i) a unitized charge multiplied by the total number of bids submitted to
the FTR auctions; plus (ii) a unitized charge multiplied by the total number of bids that clear the
FTR auctions.
Schedule 2 Volumetric Measures consist of the sum of a Customer’s Monthly Real-Time
Load Obligation and Monthly Real-Time Generation Obligation (measured in megawatt hours
(MWh)). Under the ISO’s current rate regime, Schedule 2 VMs are priced under a three-tiered
October 16, 2015
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declining block wherein the highest unitized rate is assessed to the first 250,000 MWh each
month. The Customer’s next 1,250,000 MWh are priced at a discount of approximately 10%
from the tier-1 unitized rate, and VMs in excess of 1,500,000 MWh incur the lowest unitized
monthly rate. If the Commission approves the pending CTS rules, Volumetric Measures will
exclude the Monthly Real-Time Generation Obligation associated with Coordinated External
Transactions.
c.
Schedule 3
Schedule 3 allocates internal load activity based on Real-Time NCP [Non-Coincident
Peak] Load Obligation. For Exports, Schedule 3 assesses a volumetric (per MWh) charge. 33
Specifically, the ISO divides the Schedule 3 Revenue Requirement by the real-time load
obligation forecasted for the upcoming year in the most recent CELT Report to yield the unitized
rate per kW-month. 34 The remaining revenue requirement for Schedule 3 (i.e., net of that
allocated to Exports) is then divided by the total Real-Time NCP Load Obligation forecast to
yield the unitized rate per kW-month. If the CTS rules are approved by the Commission,
Coordinated External Transactions will be exempt from Schedule 3 Export charges..
3.
Adjusting Billing Determinants for 2016
The data used in designing the proposed rates in the 2016 Administrative Expenses Tariff
was taken from the ISO markets system for the 12-month period ending July 2015. Consistent
with the practice reflected in the ISO’s Tariff filings for 1999 through 2015, the ISO also relied
on information contained in the annual CELT Report. The development of the escalation factors
is shown in Exhibit 3, RCL-7, Schedules 1 and 2.
In sum, the ISO’s analysis of CELT Report data, other load data, and transaction data
through July 2015 suggests that the estimated data for August 2015 through December 2015
should be based, without change, on 2014 data. The ISO’s analysis of the data also led to an
increase of 1.0% in the projected data for 2016 (over 2015 levels) for the Schedule 1 (i.e.,
Regional Network Load) billing determinant. However, this increase is offset by a 1.1%
reduction attributable to CTS. The net escalation factor is .999.
The Schedule 2 transaction unit determinants for virtual transactions and FTRs were left
flat for 2016, as the numbers of virtual transactions and FTRs have fluctuated in recent years but
have not substantially changed overall. Data regarding these calculations appears in Exhibit 3,
RCL-7.
The Schedule 2 transaction unit determinants for Energy TUs decrease as a result of CTS
by an escalation factor of .967. The volumetric measures in Schedule 2 decrease by a factor of
33
The Commission accepted the current form of the Schedule 3 rate design that distinguishes Exports from internal
activity in a June 2, 2006 Letter Order issued in Docket No. ER06-926-000.
34
ISO New England Inc., 2015-2024 Forecast Report of Capacity, Energy, Loads and Transmission (May 1, 2015).
See http://www.iso-ne.com/static-assets/documents/2015/05/2015_celt_report.pdf.
October 16, 2015
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.985, after netting a load increase of 1.0% against a 2.5% reduction based on CTS
implementation. See column (i) of RCL-7, Schedule 2.
Finally, the Schedule 3 billing determinant based on export volumes is decreased most
dramatically as a result of CTS implementation, by an escalation factor of .655, as shown in
RCL-7, Schedule 2, column (k). The remainder of the Schedule 3 revenue requirement is
assessed via a billing determinant related to NCP Load Obligation. This billing determinant, like
the Schedule 2 volumetric measures and the Schedule 1 billing determinants, is increased by
1.0% based on CELT Report load data, as shown in column (j) of RCL-7, Schedule 2. Although
the NCP Load Obligation billing determinant is not directly impacted by CTS implementation,
under CTS the rate will increase due to lower estimated volume for Schedule 3 exports since the
NCP Load Obligation absorbs the remaining Schedule 3 revenue requirement.
4.
Deriving the 2016 Rates
a.
Rate Development for Scheduling Service (Schedule 1)
The ISO’s Revenue Requirement for Schedule 1 totals $46 million. The total underlying
annual billing determinants for Schedule 1 are 238,898,663 kilowatt-months, 35 reflecting the
escalation factor discussed above, based on actual plus forecasted activity in 2015. The resulting
rate is $0.19275 per kilowatt-month, which is billed as $0.00026 per kilowatt-hour. 36
b.
Rate Development for Energy Administration Service (Schedule 2)
In determining the ISO’s Revenue Requirement for 2016, the ISO includes a true-up for
2014 based on both the TU and VM portions of Schedule 2. 37 In implementing the true-up
adjustment for revenue differences in the VM portion of Schedule 2, the differences will be
added to (in the case of a revenue shortfall) or subtracted from (in the case of a revenue overrecovery) the ISO’s total estimated budgeted amounts for Schedule 2 for the coming year.
Revenue over-recoveries attributable to the TUs in Schedule 2 are treated in the same
manner. However, if there is a revenue shortfall attributable to the TUs in Schedule 2, half of the
shortfall will be subtracted from the 2016 Revenue Requirement for Schedule 2. An additional
percentage of the shortfall will be added to the ISO’s projected revenue requirement for the
Schedule 2 VMs for each percentage decrease that was deemed to have occurred between the
number of TUs used in the true-up and the number of TUs that the ISO had used in the original
projection of the rates for that year. The maximum percentage of the shortfall that will be added
to the VMs is 100%, which would result if the percentage difference between the actual and
forecasted TUs was 50% or greater. Any remaining revenue shortfalls will be added to the ISO’s
projected revenue requirement for the Schedule 2 TUs.
35
Exhibit 3, RCL-7, Schedule 3, Line 2.
36
Exhibit 3, RCL-7, Schedule 3, Lines 2-3.
37
Consistent with the 2001 Settlement, injections associated with energy imported into the New England Control
Area by Bangor Hydro-Electric Company (up to 300 MW) across the New Brunswick Tie are excluded for billing
and rate calculation purposes from Energy Administration Service VMs.
October 16, 2015
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The TU recovery for 2014 was an over-collection of TU revenue in the amount of $1.4
million. As a result of the TU over-collection, the allocation of Schedule 2 revenue will be 85%
to VMs and 15% to TUs, with no adjustment necessary. 38
The ISO’s Revenue Requirement for Energy Administration Service consists of its
expenses for the functions required to provide the Service, as described above. The year 2016
budget costs assigned to Schedule 2 total approximately $82.4 million after true-up. 39 Of this
total cost, $12.4 million (i.e., 15% of the Energy Administration Service Revenue Requirement)
is projected to be recovered pursuant to the rate design through user charges related to TUs. 40
Included in this amount is $11.3 million of costs assessed to Energy TUs under a declining block
rate, billed as follows: $0.66437 per TU for Block 1; $0.60397 per TU for Block 2; and
$0.54358 per TU for Block 3. 41 Total projected Energy TUs for 2016 are 17,783,524. 42 In
addition, $970,196 has been budgeted for operating the FTR auction, and will be recovered
through the following rates: $2.02863 per FTR bid submitted; and $2.62374 per FTR bid that
clears the auction. 43 Finally, the TU Revenue Requirement includes $42,793 for the submission
and clearing of Increment Offers and Decrement Bids, which is billed as $.00500 per submitted
offer or bid, and $.06000 per cleared offer or bid. 44
The remainder of the total Schedule 2 cost for 2016, approximately $70 million 45 (i.e.,
85% of the Energy Administration Service Revenue Requirement), is projected to be recovered
pursuant to the existing rate design through user charges related to VMs incurred under three
different declining block rates. The rates are as follows: $0.28296 per VM for Block 1;
$0.25723 per VM for Block 2; and $0.23151 per VM for Block 3. 46 Total projected Schedule 2
VMs for 2016 are 260,382,763. 47
c.
Rate Development for Reliability Administration Service
(Schedule 3)
The ISO’s 2016 Revenue Requirement for Reliability Administration Service consists of
its expenses for the functions required to provide the Service, as described above. These
expenses, totaling $56.1 million after true-up, are detailed in Exhibit 3, RCL-3, Schedule 1 to
38
Exhibit 3, RCL-7, Schedule 6. See also RCL-2, Schedule 2 and Section I.C.3. The overall Schedule 2 true-up is
an under-collection of $2.35 million.
39
Exhibit 3, RCL-3, Schedule 1.
40
41
42
43
44
45
46
47
October 16, 2015
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this filing. The ISO recovers its Schedule 3 Revenue Requirement from Market Participants
through two separate rates: (i) a Real-Time NCP Load Obligation charge (assessed to internal
load); and (ii) a per-MWh rate for Exports. The total underlying Real-Time NCP Load
Obligation is 270,740,473 kilowatt-months. 48 The resulting rate is $0.20313 per kilowattmonth. 49 The Export rate is $0.40 per MWh. 50
Schedule 3 also includes Reliability Administration Service fees applicable to NonMarket Participant Transmission Customers that take Through or Out Service under the OATT.
The proposed Reliability Administration Service fees were developed by applying a ratio of the
Schedule 3 forecasted 2016 Revenue Requirement to the Schedule 3 forecasted Revenue
Requirement for 2002 to the 2002 Reliability Administration Service Fee, to obtain a monthly
Fee of $2,347.77, or an hourly rate of $3.22. See Mr. Ludlow’s testimony at Exhibit 3 (pages
42-43) for more details on the calculation of this hourly rate.
5.
Analysis of Cost Shifts Across Schedules
Before true-up, the breakdown by schedule shows an increase in Schedule 1 of
$2,033,304 (from $42,327,088 to $44,360,392), an increase in Schedule 2 of $3,702,870 (from
$81,019,153 to $84,722,023), and an increase in Schedule 3 of $1,100,135 (from $54,968,671 to
$56,068,806). Several factors contributed to this result. 51
Schedule 1. The increase in the Revenue Requirement for Schedule 1 results from 2016
cost increases and changes that impact all three schedules, including the costs to maintain
benefits and compensation, the costs of cyber security improvements, computer service licensing
and maintenance, and depreciation expenses for in-service projects including Critical
Infrastructure Protection v. 5 and Business Continuity Planning Phase III – Remote Desktop.
The remainder of the Schedule 1 increase is depreciation expense for the Coordinated
Transaction Scheduling project (predominantly allocated to Schedule 1) and the Generation
Control Application Production Part 1 project (allocated evenly between Schedules 1 and 2). All
of these costs are discussed in Sections I.C.1 and I.C.2 above.
Schedule 2. The increase in the Schedule 2 Revenue Requirement is largely due to: the
increases that impact all three schedules, as discussed in the preceding paragraph; increased
funding for market monitoring, as discussed above; and depreciation for the Business Continuity
Planning Phase III – Markets Infrastructure project (largely allocated to Schedule 2), the
Generation Control Application Production Part 1 project (allocated evenly between Schedules 1
and 2), and the Wind Integration Phase II/Do Not Exceed Dispatch project (allocated evenly
between Schedules 2 and 3).
48
49
Id.
50
51
For more information on the factors discussed below, see memo to NEPOOL Budget & Finance Subcommittee
and Participants Committee from Bob Ludlow and Cheryl Arnold dated September 23, 2015. The memo is located
at http://www.iso-ne.com/static-assets/documents/2015/09/npc_20151002_supplemental_notice.pdf (item 5a).
October 16, 2015
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Schedule 3. The increase in the Schedule 3 Revenue Requirement is due to: the
increased costs allocated to all three schedules (see above); funding for the increased FCM costs
discussed above; the increased Market Monitoring costs related to FCM (also discussed above);
and depreciation expense for the FCA 10 project (entirely allocated to Schedule 3) and the Wind
Integration Phase II/Do Not Exceed Dispatch project (allocated evenly between Schedules 2 and
3). The increases were offset by an overall reduction in depreciation expense as a result of
previously-implemented projects becoming fully depreciated during 2016. These projects
include the Synchrophasor Infrastructure and Data Utilization project, the Energy Management
System Upgrade and Enhancements project, and the FCM Enhancements 2012 project.
II.
ISO-NE’S 2016 CAPITAL BUDGET
The 2016 Capital Budget is a list of the ISO’s planned capital expenditures in 2016. The
ISO does not make any collections through its capital budget; rather, the capital projects
reflected in the budget are funded through private placement financing. 52 The ISO funds the
capitalized portion of the interest on that financing through recovery of depreciation under its
annual operating budget, as discussed in Section I.C.2 above. In sum, the costs of these projects
are collected once only, through the depreciation recovery in the Revenue Requirement.
Before describing the projects that comprise the 2016 Capital Budget, the ISO provides
context for the Capital Budget in the following Sections II.A and B.
A.
The 2016 Capital Funding Arrangements
By way of review and introduction, Section IV.B of the Tariff (called the Capital Funding
Arrangements) permits the ISO to collect from Market Participants:
(1)
the costs of budgeted capital items, through a Capital Funding Charge, if
the costs are not financed by the ISO;
(2)
through an Early Amortization Charge, the remaining unamortized costs
of assets financed by the ISO in the event of termination, acceleration or
required repayment of private financing or, in the case of non-amortizing
private financing, payment at maturity if the ISO is unable to refinance
such financing;
(3)
the working capital amount required by the ISO, if financing arranged by
the ISO to meet working capital requirements is terminated early or
repayment is accelerated (and no replacement financing has been obtained
by the ISO), through an Early Amortization Working Capital Charge; and
52
The debt was approved by the Commission in Docket No. ES04-39-000, 109 FERC ¶ 62,195 (2004) and Docket
No. ES12-48-000, 140 FERC ¶ 62,173 (2012).
October 16, 2015
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(4)
the costs that would be required to be paid by the ISO in the event of
termination, acceleration or required prepayment of private financing
entered into by the ISO in support of weekly billing of a portion of the
market settlement system (and no replacement financing has been
obtained by the ISO), through an Early Payment Shortfall Funding
Charge.
The “backstopping” reflected in the foregoing Capital Funding Arrangements is
necessary to help the ISO obtain and/or maintain private financing. When approving the
establishment of an independent system operator in New England, the Commission expressed its
concern that financial arrangements directly relying on Market Participant support for capital
projects could compromise the ISO’s independence. 53 Although the Commission allowed the
ISO to initially rely on contractual provisions with the NEPOOL to fund then-existing capital
assets, the Commission made clear that, “[t]o the extent the ISO required additional, similar
facilities in the future, these facilities should be funded by the ISO, not NEPOOL ….” 54
After the ISO commenced operations in 1997, it spent several years trying to obtain thirdparty private financing consistent with the Commission’s directive to maintain independence
from NEPOOL participants. The ISO, however, faced a key problem: an inability to provide
banks the assurances they needed that the ISO would have the funds to repay a loan in the event
of its early termination or acceleration. As a non-profit, non-stock Delaware corporation that is
tax-exempt under Section 501(c)(3) of the Internal Revenue Code, the ISO has no equity capital
(or ability to raise capital) to fund capital expenditures or working capital. Substantially all of
the ISO’s revenues are derived from charges to Customers under Commission-approved
arrangements.
Ultimately, a bank expressed willingness to lend to the ISO based on the “backstopping”
provisions of the Tariff and the ability to recover debt service through depreciation and
amortization charges. Thus, the ISO funds its capital projects with third-party financing to
maintain independence from Market Participants, while banks rely on Sections IV.B and IV.A of
the Tariff to provide sufficient assurances to finance the ISO.
Given the structure and terms of the Capital Funding Arrangements (which remain
unchanged for calendar year 2016 from those on file with and accepted by the Commission), if
no termination or acceleration of that financing occurs, then none of the charges described above
will be collected for these purposes. The ISO currently has financing for all elements of the
2016 Capital Budget given the structure of its existing Capital Funding Arrangements, and, at
this time, the ISO does not foresee the need to obtain capital funds from Market Participants
pursuant to these arrangements in calendar year 2016. As a result, the ISO does not anticipate
assessing charges to Market Participants under the Capital Funding Arrangements in calendar
year 2016.
53
New England Power Pool, 79 FERC ¶ 61,374 at p. 62,590 (1997).
54
Id.
October 16, 2015
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B.
The Transparency of the 2016 Capital Budget
The ISO’s process outlined below makes the ISO’s capital budgeting process transparent
to stakeholders and the Commission and keeps them well informed of changes in forecasts or
actual expenditures. The process includes regular reviews with stakeholders, a vote on the
annual capital budget by the ISO’s independent Board of Directors, and quarterly and annual
filings with the Commission pursuant to Section 205 of the Federal Power Act.
The annual capital budgeting process includes review with the NEPOOL Budget and
Finance Subcommittee, the NEPOOL Participants Committee 55 and representatives of the New
England states’ public utilities commissions. 56 Following this review, the ISO Board of
Directors approves the annual capital budget. 57 These steps are precursors to a Section 205 filing
of the annual capital budget.
In addition, on a quarterly basis, the ISO reviews updates to the capital budget at
meetings of the NEPOOL Budget and Finance Subcommittee and then files these updates with
the Commission under Section 205. These updates are described in Section IV.B.6.2 of the
Tariff, which requires the ISO to file with the Commission under Section 205 on a quarterly
basis: (i) a report specifying by project prior-year spending on multi-year projects, year to date
spending, and a forecast of the spending to complete the project in each future calendar year; and
(ii) a schedule of the unamortized costs of the ISO’s funded capital expenditures at the end of the
quarter and the allocation of those costs to the ISO’s rates (i.e., Schedules 1, 2, and 3 to Section
IV.A of the Tariff).
Roughly contemporaneously with the instant filing, the ISO will make a separate
quarterly filing for the third quarter of 2015. The accounting is consistent for those capital
projects that are reported both in the quarterly update and in the 2016 Capital Budget, although
the focus of the two filings is different (i.e., 2015 versus 2016).
In sum, the ISO’s capital budgeting practices create a high degree of transparency and
accountability that is unparalleled among other independent system operators and regional
transmission organizations—and even among other public utilities.
C.
Elements of the 2016 Capital Budget
The 2016 Capital Budget is $27 million. Its primary elements are anticipated to be those
projects outlined below and further detailed in the attached prepared testimony of M. David
Hameedy, Director of the Program Management Office at the ISO.
The primary deliverable for a majority of the 2016 Capital Budget projects is application
software and requisite hardware needed to maintain and improve bulk-power system reliability
55
The process for Market Participant review of ISO budgets is specified in Section IV.B.6.1 of the Tariff.
56
See Section I.B above for a description of the 2016 process.
57
See Section IV.B.6.1 of the Tariff.
October 16, 2015
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and/or wholesale electric markets. 58 Typically, the ISO’s capital projects stem from market
initiatives, identified in conjunction with stakeholders, to improve the energy, ancillary services
and capacity markets. Other capital projects are driven by the need for increased reliability and
information, Operational Excellence activities that aim to improve the efficiency of the
organization through measures such as automation of manual business processes, or regulatory
requirements imposed by the Commission. In each case, the ISO has determined that the capital
project will benefit the region’s stakeholders by improving the ISO’s ability to maintain bulkpower system reliability, administer fair and efficient markets, and provide information to
stakeholders to increase transparency and facilitate decision-making.
The following are the material projects that are anticipated to comprise the 2016 Capital
Budget. The projects listed in Sections 1 through 6 are well-defined and have had charters
approved by management; the remainder are still in the planning stages or are subject to further
Commission action.
1.
Wind Integration Phase II / Do Not Exceed Dispatch ($2,472,000)
This is the second phase in the project to fully integrate wind power into the ISO-NE
system. Phase I of the project established a centralized wind power forecast system for ISO-NE,
putting the forecast into use by wind plant operators and ISO-NE. The wind power forecast was
a direct recommendation from the New England Wind Integration Study and the first step
towards the full integration of wind into ISO-NE systems. The Phase I project implemented an
infrastructure that can be used to extend the usage of the wind power forecasts into other ISO-NE
processes.
Phase II builds on Phase I by adding both improvements and new functionality.
Significantly, Phase II will employ the wind power forecast to facilitate the inclusion of wind
resources in the real-time dispatch. Allowing real-time dispatch will alleviate issues with
curtailment priorities, allow wind resources to set price, and provide the proper market signals
for new capacity. Phase II also includes: short-term wind power forecast improvements;
publishing medium-term and long-term forecasts; adding a new wind power forecast analysis
archive; improving real-time wind dashboard displays; and adding Do Not Exceed dispatch for
intermittent resources.
The target completion date for this project is May 2016.
2.
Forward Capacity Auction (“FCA”) 10 ($590,000)
The FCA 10 project will implement Tariff revisions that were filed with the Commission
on May 1, 2015 to address the potential exercise of market power. The changes include:
increasing the Dynamic De-List Bid Threshold; mitigating New Import Resources that function
58
Capital projects also include project management and design work. If a project’s design is approved and built,
this work becomes part of the asset on which the ISO collects depreciation when the asset is placed in service and in
future years via the operating budget. On the other hand, if the capital project is abandoned, the ISO writes off the
project management and design work and recovers it in full in the year of abandonment.
October 16, 2015
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more like existing resources than new resources; and establishing a single pivotal supplier test
that applies to both capacity imports and existing resources. Other changes include the
implementation of a system-wide demand curve in the Annual Reconfiguration Auctions and
functionality to support Renewable Technology Resources.
In addition to the market changes discussed above, the FCA-10 project will include
upgrades for the software used to support the qualification process. Oracle and Microsoft have
announced that the current versions of Oracle (11g) and Internet Explorer (v.8) in use by the ISO
have reached their end of life and will not be supported effective January 2016. Accordingly, the
existing software will be upgraded to Oracle version 12c and Internet Explorer version 11.
The targeted completion date for this project is May 2016.
3.
Divisional Accounting ($496,800)
The Divisional Accounting project is a multi-phased project, implemented at the request
of Market Participants, to add software functionality to permit separation of settlement accounts
by individual business unit. This capability will facilitate customers’ divisional accounting,
allowing customers to easily evaluate their positions by business unit, division or generating
facility.
Due to the complexity of the implementation and the vast number of systems impacted
(e.g., eMarket, eFTR, Forward Capacity Tracking System), the project was designed with five
phased releases originally scheduled to occur in 2014 and 2015. The first four phases of the
project are complete. However, due to resource conflicts, specifically with the Coordinated
Transaction Scheduling project, the fifth and final phase of the project, which focuses
specifically on external transactions and their respective settlements, has been delayed.
Re-planning analysis is underway for the Phase 5 release and initial estimates indicate
completion during 2016.
4.
Zonal Load Forecast ($225,000)
On May 29, 2012, temperatures in Connecticut were much higher than those in coastal
Massachusetts. The load forecast at that time was based on a weighted average of the weather
forecasts for various New England locations, an approach that works well when weather follows
normal seasonal patterns. However, when very hot and humid conditions occur inland and the
coastal regions experience a cooling sea breeze as they did on May 29, 2012, the load forecast is
no longer accurate. On that date, the result was unexpectedly high loads in Connecticut and very
tight capacity conditions in the inland regions of Massachusetts.
In response to this situation, ISO-NE developed a zonal load forecast prototype which
addresses the problem by creating a load forecast for each load zone. This project will build on
the successful prototype by incorporating zonal load forecast functionality into the existing load
forecast application, and adjusting downstream systems using load forecast data accordingly.
With this project, the overall load forecast for the region will improve.
October 16, 2015
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The targeted completion date for this project is March 2016.
5.
Power System Modeling Management Initiatives ($145,000)
The Power System Modeling Management Initiatives project proposes to implement
enhancements to processes, procedures, and applications that will improve the power system
network model used for the Energy Management System.
The ISO will work with Northeastern University to perform an analysis of the ISO-NE
network model to identify: the type and location of all “critical” measurements identified in the
ISO-NE measurement configuration; the observable islands identified by the set of buses
belonging to each island; and all unobservable branches separating the identified observable
islands. In addition, Northeastern University will develop software that will allow for off-line
detection and identification of analog measurements and state estimator parameters with
significant errors that impact the state estimator solution. Using this software, ISO-NE will work
with transmission owners to correct these errors. The goal is to create a more robust and
accurate state estimator solution, which in turn will benefit other critical Energy Management
System functions and market applications.
The targeted completion date for this project is August 2017.
6.
NX9/NX12D – Generator Voltage Data ($50,000)
The NX9/NX12D application, implemented in the fall of 2013, is an externally-facing
application that manages the data and certifications provided by ISO-NE customers for specific
equipment. Currently, the NX12D section of the application is used to collect information on
generators, including reactive data. The NX9 section of the application collects specific
nameplate and characteristic data for transmission equipment.
The NX9/NX12D project will update the software associated with these systems to align
with ISO-NE Operating Procedure No. 12 (“Voltage & Reactive Control”), which was recently
updated in compliance with NERC’s Reliability Standard VAR-001-4.
The targeted completion date for this project is February 2016.
7.
FCA 11 ($3,000,000)
This project is dedicated to the design and implementation of zonal sloped demand
curves that successfully balance the factors involved in designing capacity market demand curves:
reliability, price volatility, market power, and robust performance. The project is intended to be
completed with the eleventh FCA, which will be held in February 2017.
8.
Sub-Hourly Settlements ($2,500,000)
The real-time markets (energy, reserve, and regulation) are settled hourly, even though
the ISO calculates real-time locational marginal prices every five minutes. Existing settlement
rules tend to undercompensate certain resources, particularly more flexible generation and
storage assets that respond quickly in tight operating conditions, when there are significant mid-
October 16, 2015
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hour price changes. Compensating resources at the more granular, five-minute price would help
improve price formation by ensuring that the price that suppliers are paid for real-time
performance is a more accurate signal of the power system’s current operating conditions. In the
future, this change may also provide an additional revenue source for wholesale electricity
storage resources.
The target completion date for this project is the fourth quarter of 2016.
9.
Fast-Start Pricing ($2,500,000)
In practice, fast-start units, even when deployed in economic merit order, often do not set
the real-time price given their operating characteristics. This is due to the limitations of ISONE’s existing fast-start pricing logic, which was designed fifteen years ago to work with the
software and hardware that was available at the time.
The proposed changes will increase the accuracy and efficiency of dispatch, pricing, and
compensation when fast-start units are deployed. Price formation will be improved by fast-start
resources’ ability to set price more frequently, and prices will reflect the cost of fast-start
deployments through transparent market price signals. The result will be improved performance
incentives for all resources during tight system conditions.
The targeted completion date for this project is the first quarter of 2017.
10.
Submission of FTRs for Clearing ($1,800,000)
The objective of this project, currently in planning, is to institute third-party clearing in
order to address the inability to properly collateralize against the risk of a participant default.
Currently, ISO-NE holds Financial Assurance that may not be adequate to cover the potential
losses of a Market Participant’s default on its FTRs. Specifically, there is no way for ISO-NE to
unwind a defaulted FTR position. If a participant acquires a large position in an annual FTR
auction, and the amount of negative target allocations exceeds its Financial Assurance, the losses
on this position, and the losses to all ISO-NE participants in the event of a default, can continue
to accumulate. Under a third-party clearing design, if a Market Participant defaults, its clearing
member will liquidate the defaulted portfolio in the secondary market, and if the combined
margin held against the portfolio is not adequate to cover the liquidation losses, the clearing
member holds the financial responsibility to cover the excess losses.
Regulatory and jurisdictional questions surrounding the project have resulted in major
delays. Minimal work on the project will continue in 2015, with the majority of development
work anticipated to occur in 2016.
The targeted completion date for this project is the fourth quarter of 2016.
October 16, 2015
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11.
2016 Issues Resolution Project ($1,500,000)
The ISO uses a “Corrective Action/Preventative Action” approach to identify and track
needed enhancements to existing systems and processes. This project is anticipated to occur in
two phases and will continue efforts to resolve as many current outstanding issues that have a
software impact as possible. These issues include automation of manual functions, addition of
functionality in support of market activities, miscellaneous application improvements, internal
and external report updates, and technology improvements. The ISO Information Technology
and Systems groups will review the list of issues related to the systems and applications for
which they provide support and identify those that can be implemented during the year. The
targeted completion date for this project is the fourth quarter of 2016.
12.
Expand Energy Offers for Pumps ($900,000)
The ISO does not currently allow Dispatchable Asset Related Demands (“DARDs”) to
have inter-temporal constraints (start-up, notification, minimum run and down times, and
maximum number of starts per day). In response to the Commission’s Order No. 719, ISO-NE
agreed to modify this practice. Specifically, through this project, the ISO will enable DARDs to
have maximum demand-dispatch duration, maximum dispatch frequency, and a minimum downtime. In addition, the ISO will expand the rules for Net Commitment Period Compensation and
define cost allocation rules for DARDs.
13.
Quarterly Release Projects 2016 ($800,000)
In addition to major projects under consideration for 2016, the ISO expects to address a
number of minor enhancements requested by stakeholders. These minor enhancements are
bundled into two quarterly releases. The targeted completion dates are the second quarter of
2016 for the first release, and the fourth quarter of 2016 for the second release.
14.
Asset Characteristics Database & User Interface Redesign ($700,000)
The Asset Characteristics Database User Interface Redesign project will provide
participants and ISO-NE Internal Market Monitoring staff enhanced functionality to track
generator characteristics for reference level calculations. This project will build upon
functionality delivered as part of the Energy Market Offer Flexibility (Hourly Markets) project.
The targeted completion date for this project is the third quarter of 2016.
15.
Energy Management Platform Customs Elimination ($600,000)
ISO-NE’s Energy Management System is based on Alstom Grid’s suite of Energy
Management Platform applications. When absolutely necessary, the Information Services
department customizes Alstom’s software to suit the business needs of ISO-NE. Accordingly,
when Alstom upgrades its software, a significant effort is needed to port the customized ISO-NE
October 16, 2015
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software to the upgraded software. This project involves work with Alstom Grid to eliminate
some of the ISO-NE customs, with the goal of simplifying the next software upgrade.
16.
Operations Document Management System (“ODMS”) ($600,000)
The ODMS has proven to be a stable and effective tool for managing System Operations
Documents. System Operations is currently using ODMS as the sole system for managing the
edit, review and sign-off for all transmission operating guides, operating procedures, master local
control center procedures, and system operating procedures. ODMS also provides operational
functionality, including searching and decision making. Since ISO-NE is phasing out
SharePoint- based applications such as ODMS, the project will migrate ODMS to a new software
platform.
17.
Transmart Rewrite ($500,000)
Transmart is a software application that is used by ISO-NE System Operations staff to
support external transactions. The Transmart application has been in existence prior to the
implementation of Standard Market Design in 2003. The Transmart Rewrite project upgrades
the remaining functionality that still exists in the original Transmart application.
The targeted completion date for this project is the fourth quarter 2016.
18.
Web Enhancements 2016 ($500,000)
ISO-NE completed a redesigned website in 2014 that greatly improved ease of use of,
and access to, market and power system information for Market Participants, public officials, and
other key stakeholders. In an effort to continue to improve the ISO New England web presence,
the Web Enhancements 2016 project will improve the usability and technical support of the
internal and external websites by implementing stakeholders’ most requested improvements and
the highest priority enhancements. The project is targeted for completion in 2016.
19.
Asset Registration Automation ($500,000)
The current asset registration process relies on participant submittal of scanned, emailed,
or faxed asset registration forms or spreadsheets. This project aims to improve the asset
registration process by providing a secure digital format for submission and retrieval of asset
registration forms, in addition to requested asset data changes and transfers. The repository
would include the required controls for this data and ensure that all customers and business users
would have access to timely and accurate asset data without the need to maintain separate
databases, spreadsheets, binders, or duplicate forms. This project would also provide a workflow
to manage the necessary participant and ISO approvals required for asset registration and
changes to existing asset data.
October 16, 2015
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The targeted completion date for this project is the third quarter of 2016.
20.
Dynamic Interchange Adjustment Tool ($300,000)
Currently, ISO-NE sets hourly interchange schedules with neighboring control areas in
New York, Quebec and New Brunswick. The schedules all change concurrently once per hour
and are primarily ramped over a ten-minute period beginning five minutes before the top of each
hour. System Operating Procedures apply uniform ramp limits to all hours without regard to
actual system conditions or system ramping capability. The use of a uniform ramp limit can
result in unnecessary curtailment of transactions, or may occasionally fail to account for a
shortage of ramping capability. The purpose of the Dynamic Interchange Adjustment Tool
project is to predict secure ranges of system ramping capabilities for intra-hour interchange
adjustments, and to address the additional layer of complexity created by the advent of intra-hour
scheduling with New York.
The target completion date for this project is the fourth quarter of 2016.
21.
Oracle 12c Upgrade ($100,000)
Many ISO-NE business applications rely on an Oracle database. To obtain the level of
support needed from Oracle to meet the ISO’s availability goals, the ISO must run on the current
Oracle database version for each application. This project will ensure all systems are upgraded
from Oracle version 11g to Oracle version 12c. Because upgrades are also occurring in the
context of current and upcoming projects, this project’s scope will specifically address only
database upgrades and performance testing for those systems not covered under a current or
upcoming project.
The targeted completion date for this project is the second quarter of 2016.
22.
Case Snapshot Enhancements for Market Operator Interface
($100,000)
On July 3, 2013, the Commission approved ISO-NE’s proposal to use the $1 million in
funds provided to ISO-NE under the Stipulation and Consent Agreement between Constellation
Energy Commodities Group and the Office of Enforcement. That proposal involved the
development of new software to allow increased surveillance and oversight of the Day-Ahead
Energy Market. The new software (called Case Snapshot) allows the re-execution of the DayAhead Energy Market’s Reserve Adequacy Assessment and Security Constrained Reliability
Assessment cases using the same market data that existed when the original case was executed
and approved.
The initial development and implementation of Case Snapshot occurred at the end of
October 2013. Enhancements to augment the data captured in the snapshot tables and the data
retention period were subsequently made. On December 22, 2014, ISO-NE reported that the
initial implementation was complete at a total project cost of $672,500.
October 16, 2015
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ISO-NE is now proposing to use the remaining funds to develop a suite of user interface
displays that will provide visibility of the snapshot data when re-running a case and allow the
ability to modify this data, including participant offers, before executing the case. In addition,
this functionality will facilitate the execution of “what-if” scenarios. Currently, for much of the
snapshot data, this can only be achieved using database queries and manual database edits. It is
ISO-NE’s expectation that the remaining funding from the settlement will cover most but not all
of the costs of developing and implementing the enhancements.
23.
Price Responsive Demand ($100,000)
The Price Responsive Demand Project aims to fully integrate demand response into the
wholesale markets. The project will create a dispatchable capacity product for demand response,
including the application of Peak Energy Rents and performance penalties to demand response,
thereby creating disincentives for economic and physical withholding of capacity. In addition,
the project will provide a mechanism for capacity replacement for resources that are not able to
demonstrate their obligated capacity. Due to the uncertainty surrounding the Commission’s
Order No. 745, the ISO has allocated a limited sum for work in 2016, and currently anticipates a
completion date for this project is the third quarter of 2018.
24.
Non-Project Capital Expenditures ($3,700,000), Other Emerging
Work ($1,809,200), and Capitalized Interest ($500,000)
The 2016 Capital Budget includes a total of $3,700,000 for non-project capital
expenditures. Non-project capital expenditures fund external and internal capitalized labor
necessary to program System Improvement Requests ($2,000,000), non-project related hardware
purchases ($1,500,000), and furniture & fixtures ($200,000).
The “Other Emerging Work” category is primarily intended to address emerging work
requests during 2016 that result from operational needs, compliance obligations or
regulatory/stakeholder feedback.
Last, $500,000 is allocated to capitalized interest. Accounting conventions require that
interest be capitalized for capital projects that cross years. In addition, loan fees associated with
borrowings to fund capital assets are also capitalized.
D.
Caveats
The 2016 Capital Budget cannot accurately predict the ISO’s actual capital expenditures
for 2016. For example, protracted stakeholder review of a proposal or extensive litigation
contesting a proposal can delay implementation of market improvements, thereby affecting when
the ISO might incur a capital expenditure and the amount of that expenditure, as well as the
ISO’s cost recovery and ability to fund future projects due to constraints on available lines of
credit. It is also likely that the ISO’s capital project priorities will change during the course of
the year. Emerging needs that are difficult to anticipate in advance will likely require a shift in
priorities. In such situations, it is likely that the distribution of the 2016 Capital Budget will
October 16, 2015
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change. The quarterly filings under Section IV.B.6.2 of the Tariff will keep stakeholders and the
Commission apprised of necessary adjustments.
III.
ADDITIONAL SUPPORTING INFORMATION
The ISO submits the following additional information pursuant to Sections 205 of the
FPA and 35.13 of the Code of Federal Regulations:
35.13(b)(1) – In addition to this transmittal letter, the ISO provides the following
materials:
•
Section IV.A of the Tariff (Exhibit 1);
•
Blacklined version of Section IV.A of the Tariff (Exhibit 2);
•
Prepared testimony and exhibits of Robert C. Ludlow regarding the 2016
Administrative Expenses Tariff (Exhibit 3);
•
Prepared testimony of Janice S. Dickstein regarding the 2016 Administrative
Expenses Tariff (Exhibit 4);
•
2016 Capital Budget (Exhibit 5);
•
Prepared testimony of M. David Hameedy regarding the 2016 Capital Budget
(Exhibit 6);
•
Table showing cross-references for Statement AA-BM data (Exhibit 7);
•
Excerpts (income statement, balance sheet, cash flow, notes to the financial
statements) from the ISO’s Form 1 for 2014 (Exhibit 8);
•
Lists of the governors and electric utility regulatory agencies for the six New England
states to which the ISO has sent electronic copies of this filing (Exhibit 9);
•
Comments of state agencies on proposed 2016 Budgets (Exhibit 10); and
•
ISO-NE response to comments of state agencies on proposed 2016 Budgets (Exhibit
11).
As in the past, the ISO has included the cost-of-service data required by Statements AABM and relevant to the ISO through these exhibits, with Exhibit 7 showing the location in each
exhibit by statement. Exhibit 7 also identifies those statements requiring data that are not
relevant to the ISO’s development of a Revenue Requirement, due to the ISO’s nature as a notfor-profit RTO that does not own any generation or transmission assets. The Commission
repeatedly has accepted the ISO’s rates as supported in this manner, including an explicit
acknowledgement that such data is sufficient. 59
59
ISO New England Inc., 85 FERC ¶ 61,453 at p. 62,680 (1998) (rejecting a protestor’s request to require the ISO to
file the cost-of-service statements set forth in Section 35.13(h) of the Commission’s Rules and Regulations,
“find[ing] that the ISO has provided sufficient information to meet the minimum filing requirements”).
October 16, 2015
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35.13(b)(2) – The ISO requests that the Commission accept the 2016 Capital Budget and
the 2016 Administrative Expenses Tariff as filed, effective January 1, 2016.
35.13(b)(3) – Pursuant to Section 17.11(e) of the Participants Agreement, Governance
Participants will be served electronically. The names and addresses of the Governance
Participants are available through the ISO’s website at http://www.isone.com/participate/participant-asset-listings/directory. A copy of this transmittal letter and the
accompanying materials have also been e-mailed to the governors and electric utility regulatory
agencies for the six New England states and to the New England Conference of Public Utilities
Commissioners and the New England States Committee on Electricity. The names and e-mail
addresses of these governors and regulatory agencies are shown in Exhibit 9. In accordance with
Commission rules and practice, there is no need for the Governance Participants or the entities
identified on Exhibit 9 to be included on the Commission’s official service list in the captioned
proceeding unless such entities become intervenors in this proceeding.
35.13(b)(4) – A description of the materials submitted pursuant to this filing is contained
in this transmittal letter.
35.13(b)(5) – This transmittal letter and supporting materials provide a statement of the
reasons the Commission should accept the 2016 Capital Budget and the 2016 Administrative
Expenses Tariff.
35.13(b)(6) –The ISO Board of Directors has approved the 2016 Capital Budget, the
2016 Revenue Requirement and resulting rates herein. The ISO also notes that the NEPOOL
Participants Committee voted to support the 2016 Capital Budget and the Revenue Requirement.
35.13(b)(7) – The ISO does not have any knowledge of any relevant expenses or costs of
service that have been alleged or judged in any administrative or judicial proceeding to be illegal,
duplicative, or unnecessary costs that are demonstrably the product of discriminatory
employment practices.
35.13(c)(1) – See Exhibit 3 for a comparison of the sales, services and revenues from the
rate schedule to be superseded and under the rate schedule change.
35.13(c)(2) – The ISO has no other rates for similar services.
35.13(c)(3) – No specifically assignable facilities have been or will be installed or
modified in order for the Commission to accept this filing.
October 16, 2015
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IV.
COMMUNICATIONS
Correspondence and communications regarding this filing should be addressed to the
undersigned for the ISO as follows:
Maria A. Gulluni
Deputy General Counsel
ISO New England Inc.
One Sullivan Road
Holyoke, MA 01040-2841
Tel: (413) 540-4473
Fax: (413) 535-4379
E-mail: [email protected]
V.
CONCLUSION
For the reasons stated herein, the ISO requests that the Commission accept the 2016
Capital Budget and the 2016 Administrative Expenses Tariff as filed, without suspension or
hearing, with an effective date of January 1, 2016.
Respectfully submitted,
/s/ Maria A. Gulluni___________________
Maria A. Gulluni
Deputy General Counsel
Enclosures
EXHIBIT 1
SECTION IV.A
RECOVERY OF ISO ADMINISTRATIVE EXPENSES
TABLE OF CONTENTS
IV.A.1 Definitions
IV.A.2 Purpose of Section IV.A; Adjustments to Rates
IV.A.2.1
Purpose of Section
IV.A.2.2
True-Ups
IV.A.3 Billing and Payment
IV.A.3.1
Billing Procedure
IV.A.3.2
Working Capital Advances
IV.A.4 Regulatory Filings
IV.A.5 Creditworthiness
IV.A.6 Direct Billing; Sanctions
IV.A.6.1
Transmission Studies
IV.A.6.2
Information Requests
IV.A.6.3
Non-Standard Provisions
IV.A.6.4
Non-Standard Billing Service
IV.A.6.5
Imposition of Monetary Sanctions by the ISO
IV.A.6.6
Re-billing Requests
IV.A.7 Metering
IV.A.7.1
Customer Obligations
IV.A.7.2
RTO Access to Metering Data
IV.A.8 Collection of Commission Annual Charges
Schedule 1 Scheduling, System Control and Dispatch Service
Schedule 2 Energy Administration Service
Schedule 3 Reliability Administration Service
Schedule 4 Collection of Commission Annual Charges
Schedule 5 Collection of NESCOE Budget
IV.A.1 Definitions:
Whenever used in this Section IV.A, in either the singular or plural number, capitalized terms shall have
the meanings specified in Section I.
IV.A.2.1 Purpose of Section IV.A
Section IV.A of the Tariff is the means by which the ISO collects the revenues necessary to carry out its
administrative functions in each calendar year, and contains rates, charges, terms and conditions for the
following Services, which together encompass the functions carried out by the ISO:
(1)
Scheduling, System Control and Dispatch Service (Schedule 1 hereto);
(2)
Energy Administration Service (Schedule 2 hereto); and
(3)
Reliability Administration Service (Schedule 3 hereto).
The rates and charges for each Service during a calendar year are based on the allocated portion of that
year’s Revenue Requirement. “Revenue Requirement” refers to the budgeted total expense for the year as
adjusted by true-ups described herein.
IV.A.2.2 True-Ups
(1) Schedule 2 True-Up
(i)
Each year (Year X), in determining the ISO’s Revenue Requirement for the subsequent
year (Year X+1), the ISO will make a true-up of the Schedule 2 portion of the Revenue
Requirement for the prior year (Year X-1). Any difference between the actual Year X-1 Schedule
2 revenues and amounts budgeted for Schedule 2 revenues in the Year X-1 Revenue Requirement
will be reflected in the projected Schedule 2 rates for Year X+1 as stated in paragraph (ii) below.
(ii)
In implementing the true-up adjustment for revenue differences in the volumetric portion
of Schedule 2, the differences will be added to (in the case of a revenue shortfall) or subtracted
from (in the case of a revenue over-recovery) the ISO’s total estimated budgeted amounts for
Schedule 2 for Year X+1. For revenue over-recoveries attributable to the TUs in Schedule 2, the
ISO will treat them in the same manner as revenue adjustments for the volumetric portion of
Schedule 2. For revenue shortfalls attributable to the TUs in Schedule 2, the ISO will allocate
them according to the following method:
(a)
50% of the shortfall will be added to the ISO’s projected Revenue Requirement
for the Schedule 2 volumetric component (85% of the projected Schedule 2 Revenue
Requirement prior to true-ups).
(b)
An additional percentage of the shortfall will be added to the ISO’s projected
Revenue Requirement for the Schedule 2 volumetric component for each percentage
decrease which was deemed to have occurred between the number of TUs used in the
true-up and the number of TUs that the ISO had used in the original projection of the
rates for that year.
(c)
The maximum percentage of the shortfall to be added to the Schedule 2
volumetric component is 100%, which would result if the percentage difference between
the actual and forecasted TUs were 50% or greater.
(d)
Any remaining shortfall revenues after allocation of the shortfall to the Schedule
2 volumetric component will be added to the ISO’s projected Revenue Requirement for
the Schedule 2 TU component (15% of the projected Schedule 2 Revenue Requirements
prior to true-ups).
(iii)
True-Ups Collected in Future Rates. To the extent the ISO proposes to change its rate
design for Section IV.A, the ISO will continue to implement the true-up procedures stated in this
section to recover under- or over-collections of TUs for then-current and prior years. For
example, when, on a going-forward basis effective January 1, 2012, the ISO eliminated the
inclusion of an estimated true-up for the current year (Year X) in the Revenue Requirement for
the subsequent year (Year X+1), the ISO was still required to include in the Revenue
Requirement for 2013 the difference between the estimated 2011 true-up filed with the 2012
Revenue Requirement and the final 2011 true-up calculated based on historical data.
(2)
General True-Up
Each year (Year X), in determining its Revenue Requirement for Year X+1, the ISO will include in such
Revenue Requirement a true-up of Year X-1’s Revenue Requirement for Schedules 1, 3 and 5.
Specifically, the Revenue Requirement for Year X+1 will include deviations between collections under
this Section IV.A and the ISO’s actual expenses for Year X-1. For example, when filing the Revenue
Requirement for 2014, the ISO will compute the total actual expenses for Schedules 1, 3 and 5 in 2012
and will compare these totals with the total charges actually collected under the Tariff for each of these
Schedules during calendar year 2012. Based on these comparisons, the ISO will adjust the otherwiseprojected Revenue Requirement for calendar year 2014 for one or more of Schedules 1, 3 and 5, as
needed, downward or upward to reflect the actual calendar year 2012 surplus or deficit, respectively.
From these figures the ISO will calculate rates for calendar year 2014, and make a rate change filing for
calendar year 2014 and succeeding years, as required, to reflect the budget amount for the applicable
calendar year and the true-up calculated by means of the foregoing analysis and adjustments.
(3)
Indemnification
The Revenue Requirement does not reflect any amounts received by the ISO due to indemnification
payments.
IV.A.3.1 Billing Procedure:
With respect to charges under this Section IV.A., the ISO will apply the ISO Billing Policy as set forth in
Exhibit ID to Section I of the Tariff.
IV.A.3.2 Working Capital Advances:
In the event that working capital financing arranged by the ISO is terminated early or repayment is
accelerated (and no replacement funding has been obtained by the ISO) and Early Amortization Working
Capital Charges have been assessed to Market Participants by the ISO, each month, each Market
Participant shall be required to advance to the ISO an amount (each, an “Advance”) equal to the ISO’s
reasonable projection of such Market Participant’s charges under the Tariff for three succeeding months.
The Advances shall be held in an interest bearing account. In each succeeding month, the ISO shall
adjust each Market Participant’s Advance so that, in each calendar month, each Market Participant’s
Advance is equal to the ISO’s reasonable projection of such Market Participant’s charges under Section
IV.A of the Tariff for such month and the next two succeeding months. If, in the reasonable judgment of
the ISO, a cash deficiency is likely to occur at any time as a result of a depletion of the Advances (but not
as a result of the failure of any Market Participant to pay its Advance), the ISO shall, at its option, have
the right to require each Market Participant to pay the ISO its pro rata share (based on such Market
Participant’s projected charges under Section IV.A of the Tariff for the instant month and the next two
succeeding months compared to projected charges to all Market Participants under Section IV.A of the
Tariff for the instant month and the next two succeeding months) of any additional Advances required for
the ISO’s operations. If any Market Participant withdraws from the ISO or has its membership
terminated, its Advance will be returned to it at the end of the month in which its withdrawal or
termination is effective, provided that all of the departing Market Participant’s liabilities under the Tariff
have been satisfied, and all of the other Market Participants will have their Advances adjusted
accordingly.
Nothing contained in the Tariff or any Service Agreement thereunder shall be construed as affecting in
any way the right of the ISO to file with the Commission under Section 205 of the Federal Power Act and
pursuant to the Commission’s rules and regulations promulgated thereunder for a change in any rates,
terms and conditions, charges, classification of service, Service Agreement, rule or regulation.
Nothing contained in the Tariff or any Service Agreement shall be construed as affecting in any way the
ability of any Customer receiving a Service under the Tariff to exercise its rights under the Federal Power
Act and pursuant to the Commission’s rules and regulations promulgated thereunder.
For purposes of Section IV.A of the Tariff, the ISO will apply the ISO New England Financial Assurance
Policy attached to Section I of the Tariff. Each Customer shall comply with the requirements of this
policy, as applicable.
IV.A.6.1 Transmission Studies:
The ISO will conduct and coordinate certain System Impact Studies and Facilities Studies pursuant to,
and in accordance with, the Tariff. The costs of System Impact Studies and Facilities Studies will be
charged directly to the pertinent Eligible Customers or interconnection applicants. The ISO will also
conduct studies as part of the Forward Capacity Market qualification process and will charge those costs
directly through Qualification Process Cost Reimbursement Deposits.
IV.A.6.2 Information Requests:
In fulfilling information requests of a significant and non-routine nature, the ISO will charge its
associated direct and indirect costs to the requestor. Revenue from these charges will be credited to
Revenue Requirements for the Service to which the information request is most closely related.
IV.A.6.3 Non-Standard Provisions:
If there is a significant direct or indirect cost associated with the ISO’s implementation of non-standard
provisions for energy or other products in a bilateral contract, the ISO will charge those costs to the
contract submitter. Revenue from these charges will be credited to Revenue Requirements for the Service
to which the submitted contract is most closely related.
IV.A.6.4 Non-Standard Billing Service:
Market Participants and other Customers who require non-standard billing payment arrangements,
pursuant to the terms of the ISO New England Financial Assurance Policy shall be charged the ISO’s
associated direct and indirect costs for these arrangements. Fees collected will be credited to Revenue
Requirements for all three Services, in proportion to the relative Revenue Requirements for those
Services.
IV.A.6.5 Imposition of Monetary Sanctions by the ISO:
Amounts collected by the ISO during a month from Market Participants pursuant to Section III.B of the
Tariff shall be disbursed or credited by the ISO in accordance with the provisions of the Section III.B.5.5.
IV.A.6.6 Re-billing Requests:
In fulfilling re-billing requests of a significant and non-routine nature as a result of data revisions not
being received in a timely fashion from a Customer, the ISO will charge its associated direct and indirect
costs to that Customer. Revenue from these charges will be credited to Revenue Requirements for the
Service to which the information request is most closely related.
IV.A.7 Metering
IV.A.7.1 Customer Obligations:
The Customer shall be responsible for compliance with metering requirements under the Tariff and the
ISO New England Operating Documents and to communicate the metering information to the ISO.
IV.A.7.2 RTO Access to Metering Data:
The ISO will have access to such metering data as may reasonably be required to facilitate measurements
and billing under the ISO New England Operating Documents, the Tariff or any Service Agreement
thereunder.
IV.A.8 Collection of Commission Annual Charges:
The ISO’s collection of amounts necessary to pay annual charges to the Commission is addressed in
Schedule 4 hereof.
Schedule 1
Scheduling, System Control and Dispatch Service
Scheduling, System Control and Dispatch Service (“Scheduling Service”) is the service required to
schedule at the regional level the movement of power through, out of, within, or into the New England
Control Area. For regional transmission service under the Tariff, Scheduling Service is an Ancillary
Service that can be provided only by the ISO. All Transmission Customers must be Customers for
Scheduling Service under this Tariff and purchase this Service from the ISO. The ISO’s charges stated
herein for Scheduling Service are based on the expenses incurred by the ISO in providing this Service. In
addition, the ISO acts as a billing agent for the operators of the Local Control Centers and certain Market
Participants in order to collect expenses incurred in providing this Service pursuant to this Schedule 1.
The ISO’s expenses are based on the functions and activities required to provide this Service and include,
but are not limited to:
•
Processing and implementation of requests for regional transmission service, including support of
the OASIS node;
•
Coordination of transmission system operation (including administration of reactive power
requirements under Schedule 2 of Section II of the Tariff) and implementation of necessary
control actions by the ISO and support for these functions;
•
Billing associated with regional transmission services provided under the Tariff;
•
Transmission system planning which supports this Service; and
•
Administrative costs associated with the aforementioned functions.
For the ISO’s expenses in providing transmission-related Scheduling Service:
(A)
each Customer that is obligated to pay the Regional Network Service rate shall pay each month,
in arrears, an amount equal to the product of $0.19275 per kilowatt month times its Monthly Regional
Network Load for that month.
(B)
each Customer that is a Transmission Customer receiving Through or Out Service shall pay each
month, in arrears, an amount equal to the product of the Transmission Customer’s highest amount of
Reserved Capacity (expressed in kilowatts) for an hour for each transaction, other than a Coordinated
External Transaction, that is scheduled to occur during the month as Through or Out Service multiplied
by $0.00026 per kilowatt for each hour of service.
Schedule 1 revenues collected from Through or Out Service customers shall be credited to each Network
Customer receiving Regional Network Service that month in proportion to each Network Customer’s
Monthly Regional Network Load in that month.
Non-Market Participant FTR fees and any portions of Long Lead Facility deposits collected by the ISO
under Schedule 22 and Schedule 25 of Section II of the Tariff that become non-refundable will be
credited to Schedule 1 Revenue Requirements and will be included in the Schedule 1 true-up calculations.
All general terms and conditions of the Tariff apply to this Service.
Schedule 2
Energy Administration Service
Energy Administration Service (“EAS”) is the Service provided by the ISO to administer the Energy
Market.
The ISO’s expenses are based on the functions required to provide EAS and include, but are not limited
to:
•
Core operation of the Energy Market;
•
Generation and demand dispatch related to the Energy Market;
•
Energy accounting;
•
Loss determination and allocation;
•
Billing preparation;
•
Market power monitoring and mitigation for the Energy Market;
•
Sanctions activities;
•
Operation of FTR auctions;
•
Market assessment and reports; and
•
Formulation of additional market rules and proposals to modify existing rules.
Each Market Participant that has an account for Energy that is settled by the ISO for the current month
shall pay each month an amount based on Energy Transaction Units (Energy TUs), Increment Offers,
Decrement Bids, Volumetric Measures, submitted FTR auction bids, and cleared FTR auction bids.
Energy TU Based Charges: For purposes of this Schedule 2, Energy TUs shall be calculated without
reference to contributions from Coordinated External Transactions. Each Customer that has, during a
month, incurred Energy TUs exceeding zero shall pay an amount, in arrears, equal to the sum of the
products of:
(1)
$0.66437 times the Customer’s first 12,500 Energy TUs for that month; plus
(2)
$0.60397 times the amount of Energy TUs that exceed 12,500 but are less than or equal to
39,500; plus
(3)
$0.54358 times the amount of Energy TUs that exceed 39,500.
Charges Based on Increment Offers and Decrement Bids: Each Customer submitting Increment Offers
and/or Decrement Bids shall pay, in arrears, amounts equal to:
(1)
$0.00500 times the number of Increment Offers and Decrement Bids submitted by the Customer
for that month; plus
(2)
for that month that clear in the Day-Ahead Energy Market.
Volumetric Measure Based Charges: A Customer shall be considered an EAS VM Customer if the sum
of Monthly Real-Time Load Obligation and Monthly Real-Time Generation Obligation (measured in
megawatthours, MWh and excluding Coordinated External Transactions) assessed to that Customer
during the month exceeds zero (0), in which case, the total EAS VM charges for that Customer shall be
equal to the sum of:
(1)
Monthly Real-Time Load Obligation (MWh), excluding Monthly Real-Time Load Obligation
associated with Coordinated External Transactions; and
(2)
Monthly Real-Time Generation Obligation (MWh); provided, however, that Monthly Real-Time
Generation Obligation associated with energy imported into the New England Control Area by
Bangor Hydro-Electric Company across the New Brunswick ties shall be excluded (up to 300
MW) for billing and rate calculation purposes from EAS VMs, and provided further that Monthly
Real-Time Generation Obligation associated with Coordinated External Transactions shall be
excluded.
Subject to the foregoing, each Market Participant that is identified as an EAS VM Customer for that
month shall pay an amount, in arrears, based on total EAS VM, equal to:
(a)
$0.28296 per MWh for the first 250,000 MWh of EAS VM for that month; plus
(b)
$0.25723 per MWh for each VM that exceeds 250,000 EAS VM but is less than or equal to
1,500,000 MWh for that month; plus
(c)
$0.23151 per MWh for each EAS VM in excess of 1,500,000 MWh for that month.
Charges Based on Submitted and Cleared FTR Bids: Each Customer submitting FTR auction bids shall
pay, in arrears, amounts equal to:
(1)
$2.02863 times the number of bids submitted by the Customer into any FTR auctions held for
that month; plus
(2)
$2.02863 times the number of bids submitted by the Customer into any annual or multi-month
FTR auctions (billed with the invoice for the first month of the annual or multi-month FTR
auction); plus
(3)
$2.62374 times the number of bids submitted by the Customer during that month that clear any
FTR auctions held for that month; plus
(4)
$2.62374 times the number of bids submitted by the Customer that clear any annual or multimonth FTR auctions (billed with the invoice for the first month of the annual or multi-month FTR
auction).
Schedule 3
Reliability Administration Service
Reliability Administration Service (“RAS”) is the Service provided by the ISO to administer the
Reliability Markets (and facilitate reliability-associated transactions and arrangements) in accordance
with the Tariff and the corresponding rules promulgated thereunder, and to provide other reliability and
informational services. The Reliability Markets are also a means by which certain Ancillary Services are
obtained under Section II of the Tariff. Each Customer must enter into a Service Agreement.
The ISO’s administrative expenses are based on the functions required to provide this Service and
include, but are not limited to:
•
Generation and demand dispatch associated with Reliability Markets;
•
•
•
The ISO generation emissions analysis;
•
Risk profile updates;
•
Triennial review of resource adequacy;
•
Studies and qualification of resources under Forward Capacity Market;
•
Preparation of regional reports and load forecasts and profiles (Capacity, Energy, Load and
Transmission reports; reports to the Energy Information Administration (EIA) of the United
States Department of Energy; reports to the North American Electric Reliability Corporation;
(A)
•
Support of power supply, environmental and market reliability planning activities;
•
Market power monitoring, mitigation and assessment for the Reliability Markets;
•
Each Transmission Customer taking Through or Out Service that is not a Market Participant shall
be considered a RAS Customer and shall pay each month, in arrears, a RAS fee equal to the product of
$3.22 times the number of hourly Through or Out reservations made for that month.
(B)
Each Customer that is a Market Participant shall be considered a RAS Customer and shall pay
each month, in arrears, an amount equal to the product of $0.20313 per kilowatt month times the Market
Participant’s Real-Time NCP Load Obligation (measured in kilowatts) for that month.
(C)
For Exports other than Coordinated External Transactions, each RAS Customer shall pay each
month, in arrears, an amount equal to $0.40000 per MWh per Export, where MWh represents the hourly
scheduled MWs of associated Export.
In order to preserve the settlement approved in Docket No. ER01-316, Market Participants engaging in
“through” transactions using Through or Out Service will not be deemed to have a Real-Time Load
Obligation on account of those transactions.
Charges collected under Schedule 3 for RAS do not include any amounts paid by the ISO on behalf of the
Market Participants to purchase emergency power.
Charges collected under Schedule 3 for RAS do not include the recovery of costs associated with
disclosure or tracking obligations. If one or more states require Market Participants to undertake such
activity the ISO will separately charge the expenses associated with such obligations.
Schedule 4
Collection of Commission Annual Charges
Each Transmission Owner that is jurisdictional to the Commission shall provide to the ISO under oath,
sixty days in advance of the due date for the Commission’s Reporting Requirement No. 582 (“FERC582”), data for the pertinent period concerning the Transmission Owner’s megawatt-hours of all
unbundled transmission (including MWh delivered in wheeling transactions and MWh delivered in
exchange transactions) and the Transmission Owner’s megawatt-hours of all bundled wholesale power
sales (to the extent these latter MWh were not separately reported as unbundled transmission) for the
pertinent period, in the level of detail required by Commission regulations and necessary for the ISO to
make and support a FERC-582 report by the ISO for the New England Control Area. These amounts are
reported on the Commission’s Form 1 in connection with accounts 447, 456, and 555.
Upon the ISO’s receipt of the Commission’s bill for the annual charges for the New England Control
Area, the ISO will promptly calculate the allocable portion of that annual charge payable by each
Transmission Owner. To determine the amount payable by each Transmission Owner for the annual
charge for the then-current Commission fiscal year, the ISO will divide each Transmission Owner’s total
reported megawatt-hours of transmission of electric energy in interstate commerce by the total megawatthours of transmission of electric energy in interstate commerce reported for the prior calendar year by the
ISO in FERC-582 for the New England Control Area, and multiply the resulting figure by the
Commission’s annual charge to the New England Control Area for the then-current Commission fiscal
year. The allocation among Transmission Owners of any adjustments for the prior Commission fiscal
year reflected in the current-year Commission bill will be calculated by multiplying (x) each
Transmission Owner’s adjusted sales (i.e., megawatt-hours of transmission of electric energy in interstate
commerce) for the calendar year on which that prior Commission fiscal year’s annual charges were based
by (y) the final Commission charge factor for that prior fiscal year, as indicated in the Commission bill.
This amount will be compared with the amount originally paid by the corresponding Transmission Owner
for the prior fiscal year and any difference (positive or negative) will be an adjustment to the payment
required from that Transmission Owner for current-year Commission annual charges. The ISO will
promptly notify each Transmission Owner of the required payment, and each Transmission Owner shall
pay to the ISO, within fifteen (15) days of the Transmission Owner’s receipt of the notice, the amount
specified in the notice.
Each Transmission Owner will provide the ISO with assistance reasonably required in responding to
information requests and audits by the Commission in connection with the Form 582 Reporting
Requirement and payment of annual charges.
Schedule 5
Collection of NESCOE Budget
The ISO acts as the billing and collection agent for the New England States Committee on Electricity
(NESCOE) for recovery of amounts reflected in the annual NESCOE budget through the rates set forth
below. Each year, NESCOE will develop an annual budget, including supporting documentation and
justification and a collection schedule, and present it to the ISO in final form no later than October 20 for
the following calendar year, following the budget review process set forth in understandings among
NESCOE, the ISO, and NEPOOL, which process is anticipated to begin in June each year. NESCOE
shall not exceed its budget in any given calendar year. The “General True-Up Provision” in Section
IV.A.2.2.(2) of this Tariff shall apply to this Schedule 5.
The ISO will calculate the Schedule 5 rate based on the rate design specified below. The ISO will submit
the NESCOE-provided materials and any revised tariff sheets to the Commission separately but
contemporaneously with the ISO’s annual filing of rates to recover ISO’s other administrative expenses.
For the calendar year 2015, the six New England states shall bear NESCOE’s budgeted costs as follows.
Each Customer that is obligated to pay the Regional Network Service rate shall pay each month, in
arrears, an amount equal to the product of $0.00000 per kilowatt times its Monthly Regional Network
Load for that month.
EXHIBIT 2
SECTION IV.A
RECOVERY OF ISO ADMINISTRATIVE EXPENSES
TABLE OF CONTENTS
IV.A.1 Definitions
IV.A.2.1
Purpose of Section
IV.A.2.2
True-Ups
IV.A.3.1
Billing Procedure
IV.A.3.2
Working Capital Advances
IV.A.6.1
Transmission Studies
IV.A.6.2
Information Requests
IV.A.6.3
Non-Standard Provisions
IV.A.6.4
Non-Standard Billing Service
IV.A.6.5
Imposition of Monetary Sanctions by the ISO
IV.A.6.6
Re-billing Requests
IV.A.7 Metering
IV.A.7.1
Customer Obligations
IV.A.7.2
RTO Access to Metering Data
IV.A.8 Collection of Commission Annual Charges
Schedule 1 Scheduling, System Control and Dispatch Service
Schedule 2 Energy Administration Service
Schedule 3 Reliability Administration Service
Schedule 4 Collection of Commission Annual Charges
Schedule 5 Collection of NESCOE Budget
IV.A.1 Definitions:
Whenever used in this Section IV.A, in either the singular or plural number, capitalized terms shall have
the meanings specified in Section I.
IV.A.2.1 Purpose of Section IV.A
Section IV.A of the Tariff is the means by which the ISO collects the revenues necessary to carry out its
administrative functions in each calendar year, and contains rates, charges, terms and conditions for the
following Services, which together encompass the functions carried out by the ISO:
(1)
Scheduling, System Control and Dispatch Service (Schedule 1 hereto);
(2)
Energy Administration Service (Schedule 2 hereto); and
(3)
Reliability Administration Service (Schedule 3 hereto).
The rates and charges for each Service during a calendar year are based on the allocated portion of that
year’s Revenue Requirement. “Revenue Requirement” refers to the budgeted total expense for the year as
adjusted by true-ups described herein.
IV.A.2.2 True-Ups
(1) Schedule 2 True-Up
(i)
Each year (Year X), in determining the ISO’s Revenue Requirement for the subsequent
year (Year X+1), the ISO will make a true-up of the Schedule 2 portion of the Revenue
Requirement for the prior year (Year X-1). Any difference between the actual Year X-1 Schedule
2 revenues and amounts budgeted for Schedule 2 revenues in the Year X-1 Revenue Requirement
will be reflected in the projected Schedule 2 rates for Year X+1 as stated in paragraph (ii) below.
(ii)
In implementing the true-up adjustment for revenue differences in the volumetric portion
of Schedule 2, the differences will be added to (in the case of a revenue shortfall) or subtracted
from (in the case of a revenue over-recovery) the ISO’s total estimated budgeted amounts for
Schedule 2 for Year X+1. For revenue over-recoveries attributable to the TUs in Schedule 2, the
ISO will treat them in the same manner as revenue adjustments for the volumetric portion of
Schedule 2. For revenue shortfalls attributable to the TUs in Schedule 2, the ISO will allocate
them according to the following method:
(a)
50% of the shortfall will be added to the ISO’s projected Revenue Requirement
for the Schedule 2 volumetric component (85% of the projected Schedule 2 Revenue
Requirement prior to true-ups).
(b)
An additional percentage of the shortfall will be added to the ISO’s projected
Revenue Requirement for the Schedule 2 volumetric component for each percentage
decrease which was deemed to have occurred between the number of TUs used in the
true-up and the number of TUs that the ISO had used in the original projection of the
rates for that year.
(c)
The maximum percentage of the shortfall to be added to the Schedule 2
volumetric component is 100%, which would result if the percentage difference between
the actual and forecasted TUs were 50% or greater.
(d)
Any remaining shortfall revenues after allocation of the shortfall to the Schedule
2 volumetric component will be added to the ISO’s projected Revenue Requirement for
the Schedule 2 TU component (15% of the projected Schedule 2 Revenue Requirements
prior to true-ups).
(iii)
True-Ups Collected in Future Rates. To the extent the ISO proposes to change its rate
design for Section IV.A, the ISO will continue to implement the true-up procedures stated in this
section to recover under- or over-collections of TUs for then-current and prior years. For
example, when, on a going-forward basis effective January 1, 2012, the ISO eliminated the
inclusion of an estimated true-up for the current year (Year X) in the Revenue Requirement for
the subsequent year (Year X+1), the ISO was still required to include in the Revenue
Requirement for 2013 the difference between the estimated 2011 true-up filed with the 2012
Revenue Requirement and the final 2011 true-up calculated based on historical data.
(2)
General True-Up
Each year (Year X), in determining its Revenue Requirement for Year X+1, the ISO will include in such
Revenue Requirement a true-up of Year X-1’s Revenue Requirement for Schedules 1, 3 and 5.
Specifically, the Revenue Requirement for Year X+1 will include deviations between collections under
this Section IV.A and the ISO’s actual expenses for Year X-1. For example, when filing the Revenue
Requirement for 2014, the ISO will compute the total actual expenses for Schedules 1, 3 and 5 in 2012
and will compare these totals with the total charges actually collected under the Tariff for each of these
Schedules during calendar year 2012. Based on these comparisons, the ISO will adjust the otherwiseprojected Revenue Requirement for calendar year 2014 for one or more of Schedules 1, 3 and 5, as
needed, downward or upward to reflect the actual calendar year 2012 surplus or deficit, respectively.
From these figures the ISO will calculate rates for calendar year 2014, and make a rate change filing for
calendar year 2014 and succeeding years, as required, to reflect the budget amount for the applicable
calendar year and the true-up calculated by means of the foregoing analysis and adjustments.
(3)
Indemnification
The Revenue Requirement does not reflect any amounts received by the ISO due to indemnification
payments.
IV.A.3.1 Billing Procedure:
With respect to charges under this Section IV.A., the ISO will apply the ISO Billing Policy as set forth in
Exhibit ID to Section I of the Tariff.
IV.A.3.2 Working Capital Advances:
In the event that working capital financing arranged by the ISO is terminated early or repayment is
accelerated (and no replacement funding has been obtained by the ISO) and Early Amortization Working
Capital Charges have been assessed to Market Participants by the ISO, each month, each Market
Participant shall be required to advance to the ISO an amount (each, an “Advance”) equal to the ISO’s
reasonable projection of such Market Participant’s charges under the Tariff for three succeeding months.
The Advances shall be held in an interest bearing account. In each succeeding month, the ISO shall
adjust each Market Participant’s Advance so that, in each calendar month, each Market Participant’s
Advance is equal to the ISO’s reasonable projection of such Market Participant’s charges under Section
IV.A of the Tariff for such month and the next two succeeding months. If, in the reasonable judgment of
the ISO, a cash deficiency is likely to occur at any time as a result of a depletion of the Advances (but not
as a result of the failure of any Market Participant to pay its Advance), the ISO shall, at its option, have
the right to require each Market Participant to pay the ISO its pro rata share (based on such Market
Participant’s projected charges under Section IV.A of the Tariff for the instant month and the next two
succeeding months compared to projected charges to all Market Participants under Section IV.A of the
Tariff for the instant month and the next two succeeding months) of any additional Advances required for
the ISO’s operations. If any Market Participant withdraws from the ISO or has its membership
terminated, its Advance will be returned to it at the end of the month in which its withdrawal or
termination is effective, provided that all of the departing Market Participant’s liabilities under the Tariff
have been satisfied, and all of the other Market Participants will have their Advances adjusted
accordingly.
Nothing contained in the Tariff or any Service Agreement thereunder shall be construed as affecting in
any way the right of the ISO to file with the Commission under Section 205 of the Federal Power Act and
pursuant to the Commission’s rules and regulations promulgated thereunder for a change in any rates,
terms and conditions, charges, classification of service, Service Agreement, rule or regulation.
Nothing contained in the Tariff or any Service Agreement shall be construed as affecting in any way the
ability of any Customer receiving a Service under the Tariff to exercise its rights under the Federal Power
Act and pursuant to the Commission’s rules and regulations promulgated thereunder.
For purposes of Section IV.A of the Tariff, the ISO will apply the ISO New England Financial Assurance
Policy attached to Section I of the Tariff. Each Customer shall comply with the requirements of this
policy, as applicable.
IV.A.6.1 Transmission Studies:
The ISO will conduct and coordinate certain System Impact Studies and Facilities Studies pursuant to,
and in accordance with, the Tariff. The costs of System Impact Studies and Facilities Studies will be
charged directly to the pertinent Eligible Customers or interconnection applicants. The ISO will also
conduct studies as part of the Forward Capacity Market qualification process and will charge those costs
directly through Qualification Process Cost Reimbursement Deposits.
IV.A.6.2 Information Requests:
In fulfilling information requests of a significant and non-routine nature, the ISO will charge its
associated direct and indirect costs to the requestor. Revenue from these charges will be credited to
Revenue Requirements for the Service to which the information request is most closely related.
IV.A.6.3 Non-Standard Provisions:
If there is a significant direct or indirect cost associated with the ISO’s implementation of non-standard
provisions for energy or other products in a bilateral contract, the ISO will charge those costs to the
contract submitter. Revenue from these charges will be credited to Revenue Requirements for the Service
to which the submitted contract is most closely related.
IV.A.6.4 Non-Standard Billing Service:
Market Participants and other Customers who require non-standard billing payment arrangements,
pursuant to the terms of the ISO New England Financial Assurance Policy shall be charged the ISO’s
associated direct and indirect costs for these arrangements. Fees collected will be credited to Revenue
Requirements for all three Services, in proportion to the relative Revenue Requirements for those
Services.
IV.A.6.5 Imposition of Monetary Sanctions by the ISO:
Amounts collected by the ISO during a month from Market Participants pursuant to Section III.B of the
Tariff shall be disbursed or credited by the ISO in accordance with the provisions of the Section III.B.5.5.
IV.A.6.6 Re-billing Requests:
In fulfilling re-billing requests of a significant and non-routine nature as a result of data revisions not
being received in a timely fashion from a Customer, the ISO will charge its associated direct and indirect
costs to that Customer. Revenue from these charges will be credited to Revenue Requirements for the
Service to which the information request is most closely related.
IV.A.7 Metering
IV.A.7.1 Customer Obligations:
The Customer shall be responsible for compliance with metering requirements under the Tariff and the
ISO New England Operating Documents and to communicate the metering information to the ISO.
IV.A.7.2 RTO Access to Metering Data:
The ISO will have access to such metering data as may reasonably be required to facilitate measurements
and billing under the ISO New England Operating Documents, the Tariff or any Service Agreement
thereunder.
IV.A.8 Collection of Commission Annual Charges:
The ISO’s collection of amounts necessary to pay annual charges to the Commission is addressed in
Schedule 4 hereof.
Schedule 1
Scheduling, System Control and Dispatch Service
Scheduling, System Control and Dispatch Service (“Scheduling Service”) is the service required to
schedule at the regional level the movement of power through, out of, within, or into the New England
Control Area. For regional transmission service under the Tariff, Scheduling Service is an Ancillary
Service that can be provided only by the ISO. All Transmission Customers must be Customers for
Scheduling Service under this Tariff and purchase this Service from the ISO. The ISO’s charges stated
herein for Scheduling Service are based on the expenses incurred by the ISO in providing this Service. In
addition, the ISO acts as a billing agent for the operators of the Local Control Centers and certain Market
Participants in order to collect expenses incurred in providing this Service pursuant to this Schedule 1.
The ISO’s expenses are based on the functions and activities required to provide this Service and include,
but are not limited to:
•
Processing and implementation of requests for regional transmission service, including support of
the OASIS node;
•
Coordination of transmission system operation (including administration of reactive power
requirements under Schedule 2 of Section II of the Tariff) and implementation of necessary
control actions by the ISO and support for these functions;
•
Billing associated with regional transmission services provided under the Tariff;
•
Transmission system planning which supports this Service; and
•
Administrative costs associated with the aforementioned functions.
For the ISO’s expenses in providing transmission-related Scheduling Service:
(A)
each Customer that is obligated to pay the Regional Network Service rate shall pay each month,
in arrears, an amount equal to the product of $0.192755570 per kilowatt month times its Monthly
Regional Network Load for that month.
(B)
each Customer that is a Transmission Customer receiving Through or Out Service shall pay each
month, in arrears, an amount equal to the product of the Transmission Customer’s highest amount of
Reserved Capacity (expressed in kilowatts) for an hour for each transaction, other than a Coordinated
External Transaction, that is scheduled to occur during the month as Through or Out Service multiplied
by $0.000261 per kilowatt for each hour of service.
Schedule 1 revenues collected from Through or Out Service customers shall be credited to each Network
Customer receiving Regional Network Service that month in proportion to each Network Customer’s
Monthly Regional Network Load in that month.
Non-Market Participant FTR fees and any portions of Long Lead Facility deposits collected by the ISO
under Schedule 22 and Schedule 25 of Section II of the Tariff that become non-refundable will be
credited to Schedule 1 Revenue Requirements and will be included in the Schedule 1 true-up calculations.
Schedule 2
Energy Administration Service
Energy Administration Service (“EAS”) is the Service provided by the ISO to administer the Energy
Market.
The ISO’s expenses are based on the functions required to provide EAS and include, but are not limited
to:
•
Core operation of the Energy Market;
•
Generation and demand dispatch related to the Energy Market;
•
Energy accounting;
•
Loss determination and allocation;
•
•
Market power monitoring and mitigation for the Energy Market;
•
Sanctions activities;
•
Operation of FTR auctions;
•
Market assessment and reports; and
•
Each Market Participant that has an account for Energy that is settled by the ISO for the current month
shall pay each month an amount based on Energy Transaction Units (Energy TUs), Increment Offers,
Decrement Bids, Volumetric Measures, submitted FTR auction bids, and cleared FTR auction bids.
Energy TU Based Charges: For purposes of this Schedule 2, Energy TUs shall be calculated without
reference to contributions from Coordinated External Transactions. Each Customer that has, during a
month, incurred Energy TUs exceeding zero shall pay an amount, in arrears, equal to the sum of the
products of:
(1)
$0.6643765101 times the Customer’s first 12,500 Energy TUs for that month; plus
(2)
$0.6039759182 times the amount of Energy TUs that exceed 12,500 but are less than or equal to
39,500; plus
(3)
$0.5435853264 times the amount of Energy TUs that exceed 39,500.
Charges Based on Increment Offers and Decrement Bids: Each Customer submitting Increment Offers
and/or Decrement Bids shall pay, in arrears, amounts equal to:
(1)
(2)
for that month that clear in the Day-Ahead Energy Market.
Volumetric Measure Based Charges: A Customer shall be considered an EAS VM Customer if the sum
of Monthly Real-Time Load Obligation and Monthly Real-Time Generation Obligation (measured in
megawatthours, MWh and excluding Coordinated External Transactions) assessed to that Customer
during the month exceeds zero (0), in which case, the total EAS VM charges for that Customer shall be
equal to the sum of:
(1)
Monthly Real-Time Load Obligation (MWh), excluding Monthly Real-Time Load Obligation
associated with Coordinated External Transactions; and
(2)
Monthly Real-Time Generation Obligation (MWh); provided, however, that Monthly Real-Time
Generation Obligation associated with energy imported into the New England Control Area by
Bangor Hydro-Electric Company across the New Brunswick ties shall be excluded (up to 300
MW) for billing and rate calculation purposes from EAS VMs, and provided further that Monthly
Real-Time Generation Obligation associated with Coordinated External Transactions shall be
excluded.
Subject to the foregoing, each Market Participant that is identified as an EAS VM Customer for that
month shall pay an amount, in arrears, based on total EAS VM, equal to:
(a)
$0.2829625517 per MWh for the first 250,000 MWh of EAS VM for that month; plus
(b)
$0.2572323197 per MWh for each VM that exceeds 250,000 EAS VM but is less than or equal to
1,500,000 MWh for that month; plus
(c)
$0.2315120877 per MWh for each EAS VM in excess of 1,500,000 MWh for that month.
Charges Based on Submitted and Cleared FTR Bids: Each Customer submitting FTR auction bids shall
pay, in arrears, amounts equal to:
(1)
$2.02863.85853 times the number of bids submitted by the Customer into any FTR auctions held
(2)
$2.02863.85853 times the number of bids submitted by the Customer into any annual or multimonth FTR auctions (billed with the invoice for the first month of the annual or multi-month FTR
auction); plus
(3)
$2.623741.21377 times the number of bids submitted by the Customer during that month that
clear any FTR auctions held for that month; plus
(4)
$2.623741.21377 times the number of bids submitted by the Customer that clear any annual or
multi-month FTR auctions (billed with the invoice for the first month of the annual or multimonth FTR auction).
Schedule 3
Reliability Administration Service
Reliability Administration Service (“RAS”) is the Service provided by the ISO to administer the
Reliability Markets (and facilitate reliability-associated transactions and arrangements) in accordance
with the Tariff and the corresponding rules promulgated thereunder, and to provide other reliability and
informational services. The Reliability Markets are also a means by which certain Ancillary Services are
obtained under Section II of the Tariff. Each Customer must enter into a Service Agreement.
The ISO’s administrative expenses are based on the functions required to provide this Service and
include, but are not limited to:
•
Generation and demand dispatch associated with Reliability Markets;
•
•
•
The ISO generation emissions analysis;
•
Risk profile updates;
•
Triennial review of resource adequacy;
•
Studies and qualification of resources under Forward Capacity Market;
•
Preparation of regional reports and load forecasts and profiles (Capacity, Energy, Load and
Transmission reports; reports to the Energy Information Administration (EIA) of the United
States Department of Energy; reports to the North American Electric Reliability Corporation;
(A)
•
Support of power supply, environmental and market reliability planning activities;
•
Market power monitoring, mitigation and assessment for the Reliability Markets;
•
Each Transmission Customer taking Through or Out Service that is not a Market Participant shall
be considered a RAS Customer and shall pay each month, in arrears, a RAS fee equal to the product of
$3.022 times the number of hourly Through or Out reservations made for that month.
(B)
Each Customer that is a Market Participant shall be considered a RAS Customer and shall pay
each month, in arrears, an amount equal to the product of $0.1876320313 per kilowatt month times the
Market Participant’s Real-Time NCP Load Obligation (measured in kilowatts) for that month.
(C)
For Exports other than Coordinated External Transactions, each RAS Customer shall pay each
month, in arrears, an amount equal to $0.3740000 per MWh per Export, where MWh represents the
hourly scheduled MWs of associated Export.
In order to preserve the settlement approved in Docket No. ER01-316, Market Participants engaging in
“through” transactions using Through or Out Service will not be deemed to have a Real-Time Load
Obligation on account of those transactions.
Charges collected under Schedule 3 for RAS do not include any amounts paid by the ISO on behalf of the
Market Participants to purchase emergency power.
Charges collected under Schedule 3 for RAS do not include the recovery of costs associated with
disclosure or tracking obligations. If one or more states require Market Participants to undertake such
activity the ISO will separately charge the expenses associated with such obligations.
Schedule 4
Collection of Commission Annual Charges
Each Transmission Owner that is jurisdictional to the Commission shall provide to the ISO under oath,
sixty days in advance of the due date for the Commission’s Reporting Requirement No. 582 (“FERC582”), data for the pertinent period concerning the Transmission Owner’s megawatt-hours of all
unbundled transmission (including MWh delivered in wheeling transactions and MWh delivered in
exchange transactions) and the Transmission Owner’s megawatt-hours of all bundled wholesale power
sales (to the extent these latter MWh were not separately reported as unbundled transmission) for the
pertinent period, in the level of detail required by Commission regulations and necessary for the ISO to
make and support a FERC-582 report by the ISO for the New England Control Area. These amounts are
reported on the Commission’s Form 1 in connection with accounts 447, 456, and 555.
Upon the ISO’s receipt of the Commission’s bill for the annual charges for the New England Control
Area, the ISO will promptly calculate the allocable portion of that annual charge payable by each
Transmission Owner. To determine the amount payable by each Transmission Owner for the annual
charge for the then-current Commission fiscal year, the ISO will divide each Transmission Owner’s total
reported megawatt-hours of transmission of electric energy in interstate commerce by the total megawatthours of transmission of electric energy in interstate commerce reported for the prior calendar year by the
ISO in FERC-582 for the New England Control Area, and multiply the resulting figure by the
Commission’s annual charge to the New England Control Area for the then-current Commission fiscal
year. The allocation among Transmission Owners of any adjustments for the prior Commission fiscal
year reflected in the current-year Commission bill will be calculated by multiplying (x) each
Transmission Owner’s adjusted sales (i.e., megawatt-hours of transmission of electric energy in interstate
commerce) for the calendar year on which that prior Commission fiscal year’s annual charges were based
by (y) the final Commission charge factor for that prior fiscal year, as indicated in the Commission bill.
This amount will be compared with the amount originally paid by the corresponding Transmission Owner
for the prior fiscal year and any difference (positive or negative) will be an adjustment to the payment
required from that Transmission Owner for current-year Commission annual charges. The ISO will
promptly notify each Transmission Owner of the required payment, and each Transmission Owner shall
pay to the ISO, within fifteen (15) days of the Transmission Owner’s receipt of the notice, the amount
specified in the notice.
Each Transmission Owner will provide the ISO with assistance reasonably required in responding to
information requests and audits by the Commission in connection with the Form 582 Reporting
Requirement and payment of annual charges.
Schedule 5
Collection of NESCOE Budget
The ISO acts as the billing and collection agent for the New England States Committee on Electricity
(NESCOE) for recovery of amounts reflected in the annual NESCOE budget through the rates set forth
below. Each year, NESCOE will develop an annual budget, including supporting documentation and
justification and a collection schedule, and present it to the ISO in final form no later than October 20 for
the following calendar year, following the budget review process set forth in understandings among
NESCOE, the ISO, and NEPOOL, which process is anticipated to begin in June each year. NESCOE
shall not exceed its budget in any given calendar year. The “General True-Up Provision” in Section
IV.A.2.2.(2) of this Tariff shall apply to this Schedule 5.
The ISO will calculate the Schedule 5 rate based on the rate design specified below. The ISO will submit
the NESCOE-provided materials and any revised tariff sheets to the Commission separately but
contemporaneously with the ISO’s annual filing of rates to recover ISO’s other administrative expenses.
For the calendar year 2015, the six New England states shall bear NESCOE’s budgeted costs as follows.
Each Customer that is obligated to pay the Regional Network Service rate shall pay each month, in
arrears, an amount equal to the product of $0.00000 per kilowatt times its Monthly Regional Network
Load for that month.
EXHIBIT 3
Recovery of 2016 Administrative Costs
Exhibit 3
UNITED STATES OF AMERICA
BEFORE THE
FEDERAL ENERGY REGULATORY COMMISSION
)
Docket No. ER16-_____-000
DIRECT TESTIMONY
OF
ROBERT C. LUDLOW
Filed on:
October 16, 2015
Exhibit 3
TABLE OF CONTENTS
PURPOSE OF TESTIMONY ......................................................................................................... 2
CURRENT OPERATIONS AND ORGANIZATIONAL STRUCTURE OF THE ISO ............... 4
THE BUDGET DEVELOPMENT PROCESS ............................................................................... 5
DESCRIPTION OF THE 2016 REVENUE REQUIREMENT...................................................... 7
ACTIVITY ACCOUNTING SYSTEM ........................................................................................ 21
2016 COST ALLOCATION AMONG SCHEDULES 1, 2, AND 3 ............................................ 23
THE ISO RATE DESIGN AND ESCALATION FACTORS ...................................................... 29
THE 2016 BILLING DETERMINANTS ..................................................................................... 37
RATE SUMMARY ...................................................................................................................... 40
FIXED FEES................................................................................................................................. 42
CONCLUSION ............................................................................................................................. 44
Exhibit 3
ATTACHMENTS TO THIS TESTIMONY
RCL-1:
Organization Chart (CEO direct reports)
RCL-2:
Revenue Requirement and True-Up
Schedule 1: [reserved]
Schedule 2: 2016 Revenue Requirement and 2014 True-Up
RCL-3:
Test Year 2016 Cost Allocations
Schedule 1:
Schedule 2:
Schedule 3:
Schedule 4:
Schedule 5:
Schedule 6:
Total Cost Allocation to Schedules by Department
Total Direct Labor Allocation to Schedules by Department
Total Cost Allocations to Schedules by Cost Category
Direct Labor Cost Allocations to Schedules by Cost Category
Allocation Factors by Cost Category
Allocation on Depreciation and Amortization Expense
RCL-4:
[reserved]
RCL-5:
2016 Core Operating Budget
Schedule 1:
Schedule 2:
Schedule 3:
Schedule 4:
Schedule 5:
Schedule 6:
Overview of Operating Expense Budget
Detail of Components of 2016 Operating Expense Budget
Variance Summary (vs. 2015)
Detailed Change in Budget (vs. 2015)
Staffing Projections
2016 Capital Budget
RCL-6:
[reserved]
RCL-7:
Escalation Factors and Billing Determinants
Schedule 1:
Schedule 2:
Schedule 3:
Schedule 4:
Schedule 5:
Schedule 6:
Development of Escalation Factors
Billing Determinants for Calendar Year 2015 and Test Year 2016
Rate Design Summary
Annual Revenue Comparison at Present and Proposed Rates
Comparison of Schedule 2 Revenues from Transaction Units for 2014
Schedule 2 TU True-Up Summary
RCL-8: NEPOOL Resolution
1
2
3
4
Exhibit 3
Page 1
BEFORE THE
ISO NEW ENGLAND INC.
5
)
Direct Testimony of Robert C. Ludlow
6
Q.
PLEASE STATE YOUR NAME AND BUSINESS ADDRESS.
7
A.
My name is Robert C. Ludlow. My business address is One Sullivan Road,
8
Holyoke, Massachusetts 01040-2841.
9
Q.
WHAT IS YOUR OCCUPATION?
10
A.
I am a Vice President and the Chief Financial and Compliance Officer of ISO
11
New England Inc. (the “ISO”). I served in the role of Vice President and Chief
12
Financial Officer from the time the ISO commenced its operations on July 1, 1997
13
until September 2000. At that time, I began working as an outside consultant for
14
the ISO until August 2002, when I rejoined the ISO as Vice President and Chief
15
Financial Officer. In July of 2008 my title changed to reflect my expanded
16
responsibility for compliance. The compliance organization is responsible for
17
developing and maintaining the Company’s compliance management system.
18
This system captures the Company’s compliance obligations, including those of
19
the North American Electric Reliability Corporation (“NERC”), North American
20
Energy Standards Board, and the Northeast Power Coordinating Council
21
(“NPCC”).
1
Q.
2
3
Exhibit 3
Page 2
PLEASE DESCRIBE YOUR EDUCATIONAL BACKGROUND AND
PROFESSIONAL EXPERIENCE.
A.
I hold a B.B.A. in Accounting from St. Bonaventure University. Prior to joining
4
the ISO, I was a Partner at the accounting firm of Marden, Harrison & Kreuter,
5
CPAs. I also served as the Chief Financial Officer of Western Beef, Inc. I am a
6
Certified Public Accountant.
7
Q.
8
9
HAVE YOU PREVIOUSLY TESTIFIED BEFORE A REGULATORY
COMMISSION?
A.
Yes. I previously have testified before the Commission to support prior
10
administrative rate filings by the ISO in Docket Nos. ER15-112-000 (rates
11
proposed for 2015), ER14-90-000 (rates proposed for 2014), ER13-185-000 (rates
12
proposed for 2013), ER12-191-000 (rates proposed for 2012), ER11-1943-000
13
(rates proposed for 2011), ER10-154-000 (rates proposed for 2010), and others.
14
PURPOSE OF TESTIMONY
15
Q.
WHAT IS THE PURPOSE OF YOUR TESTIMONY?
16
A.
I am providing this testimony primarily to support the ISO’s proposed revenue
17
requirement for 2016 (“2016 Revenue Requirement”) and the updated rates to
18
collect it. My Direct Testimony presents the ISO’s 2016 Revenue Requirement as
19
reflected in the proposed revised tariff sheets attached as Exhibits 1 and 2 (clean
20
and blacklined versions, respectively) to the filing letter. Specifically, I will
21
describe the ISO’s budget process, summarize the elements of the ISO’s 2016
Exhibit 3
Page 3
1
Revenue Requirement (including the true-up mechanism), present the ISO’s 2016
2
Core Operating Budget, and describe the ISO’s activity accounting system. I will
3
also present the development of the Test Year 2016 cost of service study
4
associated with the ISO providing service under the three primary rate schedules
5
included in Section IV.A of the ISO’s Transmission, Markets and Services Tariff
6
(the “Tariff”). Section IV.A of the Tariff provides for recovery of the ISO’s
7
administrative expenses. The three primary rate schedules are: (1) Schedule 1 –
8
Scheduling, System Control and Dispatch Service (“Scheduling Service”); (2)
9
Schedule 2 – Energy Administration Service; and (3) Schedule 3 – Reliability
10
Administration Service. I will present proposed escalation factors to adjust actual
11
load data for the 12-month period ending July 2015 to the Test Year 2016 for the
12
purpose of rate design, discuss the rate design utilized, and the proposed rates,
13
including certain fixed fees.
14
Q.
HOW WILL YOUR TESTIMONY BE ORGANIZED?
15
A.
Before offering a conclusion, I will describe:
16
(i)
the current operations and organizational structure of the ISO;
17
(ii)
the budget development process;
18
(iii)
the various elements of the 2016 Revenue Requirement;
19
(iv)
the ISO’s activity accounting system;
20
(v)
how the ISO allocated its costs among the rates it proposes to charge in the
21
Tariff’s Schedules 1, 2, and 3;
1
(vi)
the 2016 rate design and escalation factors;
2
(vii)
the 2016 billing determinants;
3
(viii) a rate summary; and
4
(ix)
5
6
9
fixed fees.
CURRENT OPERATIONS AND ORGANIZATIONAL STRUCTURE OF THE ISO
Q.
7
8
Exhibit 3
Page 4
WHAT ARE THE CURRENT OPERATIONS AND ORGANIZATIONAL
STRUCTURE OF THE ISO?
A.
The ISO provides three basic services to its customers:
1.
Scheduling Service (Schedule 1): Through this service, the ISO schedules
10
at the pool level the movement of power through, out of, within, or into
11
the New England Control Area.
12
2.
Energy Administration Service (Schedule 2): Through this service, the
13
ISO administers the energy markets and facilitates generation and demand
14
dispatch, auctions for Financial Transmission Rights (“FTRs”), and other
15
services (i.e., under Section III of the Tariff).
16
3.
Reliability Administration Service (Schedule 3): Through this service, the
17
ISO administers the reliability markets (and facilitates reliability-related
18
transactions and arrangements) in accordance with Market Rule 1 and
19
provides other reliability and informational services.
Exhibit 3
Page 5
1
The ISO is governed by an independent Board of Directors with a cross-section of
2
skills and experience, including regulatory affairs, energy industry management,
3
corporate finance, bulk-power systems, public policy, and market development.
4
The ISO is overseen by a President and Chief Executive Officer (“CEO”) who has
5
seven direct reports. An Executive Vice President and Chief Operating Officer is
6
responsible for Market Operations, System Operations, System Planning, Market
7
Development, Program Management, Business Architecture, and Information
8
Technology. The other direct reports of the CEO are: Vice President and General
9
Counsel; Vice President of External Affairs and Corporate Communications; Vice
10
President, Chief Financial & Compliance Officer; Vice President, Human
11
Resources; Vice President, Market Monitoring; and Director, Internal Audit. The
12
latter two positions report to the CEO for administrative purposes only. See RCL-
13
1, attached to this testimony.
14
THE BUDGET DEVELOPMENT PROCESS
15
Q.
HOW WERE THE ISO’S BUDGETS DEVELOPED FOR 2016?
16
A.
The ISO prepares budgets in advance of each upcoming year using a seven-step
17
business planning process, throughout which stakeholder input is sought. The
18
seven-step process is:
19
1) define objectives, activities and goals;
20
2) identify efficiencies for each department;
21
3) determine resource requirements;
Exhibit 3
Page 6
1
4) develop budget estimates for each department;
2
5) adjust budgets to ensure that staff resources and activities are aligned with the
3
business plan;
4
6) conduct senior staff review to ensure alignment of budget with the ISO’s
5
business plan and overall fiscal constraint; and
6
7) develop priorities.
7
Q.
8
9
PLEASE SUMMARIZE THE STAKEHOLDER PROCESS USED TO
REVIEW THE 2016 BUDGET.
A.
After reviewing preliminary budgets with state agencies and NEPOOL at
10
meetings in June, the ISO presented the 2016 Revenue Requirement at the
11
NEPOOL Budget and Finance Subcommittee’s August 26, 2015 meeting and at a
12
meeting for state agencies on August 27, 2015. The ISO also presented the
13
budgets to the NEPOOL Participants Committee at the Committee’s meetings on
14
September 11 and October 2, 2015. At the October 2 meeting, the ISO’s 2016
15
Revenue Requirement was unanimously supported by the Participants Committee
16
(with abstentions). The terms of the NEPOOL Participants Committee’s action
17
are reflected in the resolution in RCL-8, attached to this testimony. In that same
18
resolution, the NEPOOL Participants Committee also supported the capital budget
19
for 2016. The ISO Board of Directors approved the budgets effective on October
20
15, 2015.
Exhibit 3
Page 7
1
Q.
DESCRIBE THE ISO’S HISTORY OF STAYING WITHIN ITS BUDGET.
2
A.
The ISO has amassed a consistent track record of spending integrity; since the
3
inception of its self-funding tariff for calendar year 1998, the ISO’s annual
4
spending has never exceeded the budget used to calculate the revenue requirement
5
accepted by the Commission that forms the basis for the rates for the year in
6
question. Should the need ever arise for the ISO to spend beyond a given year’s
7
budget (including contingencies), the ISO will first seek stakeholder support and
8
then file a rate increase with the Commission, thus allowing stakeholder and
9
Commission review before approving such increases.
10
DESCRIPTION OF THE 2016 REVENUE REQUIREMENT 1
11
Q.
12
WHAT IS THE 2016 REVENUE REQUIREMENT AND WHAT ARE ITS
ELEMENTS?
13
A.
As shown in RCL-2, Schedule 2, the 2016 Revenue Requirement is approximately
14
$184.5 million (after true-up). The 2016 Revenue Requirement contains the
15
following components, each of which is discussed below: (1) the 2016 operating
16
budget ($149.6 million) (i.e., the administrative costs of running the ISO);
17
(2) depreciation and amortization of regulatory assets ($33 million); (3) interest
18
expense of $2.5 million; and (iv) a final true-up adjustment for 2014 (the “2014
19
True-Up Amount”) calculated pursuant to Section IV.A.2.2 of the Tariff (a
1
Generally, numbers used herein are rounded for ease of reference and, accordingly, may not sum.
Exhibit 3
Page 8
1
decrease in the 2016 Revenue Requirement of approximately $600,000 resulting
2
from an over-collection in 2014).
3
Q.
4
5
WHAT IS THE IMPACT OF THE INCREASED REVENUE
REQUIREMENT ON CONSUMER COSTS?
A.
If the ISO’s Revenue Requirement were fully passed through to end-use
6
customers, their cost would average 99 cents per month, up from 2015 levels of
7
90 cents. This increase is largely due to the change in the true-up amounts year
8
over year. See slide 14 of the ISO’s annual budget presentation to stakeholders
9
(the “Budget Presentation”), which can be found at http://www.iso-ne.com/static-
10
assets /documents/2015/09/2_2016_operat_capital_budget_update_
11
09_23_2015.pdf.
12
Q.
WHAT ARE THE MOST SIGNIFICANT CHANGES IN THE 2016
13
OPERATING EXPENSE BUDGET COMPARED WITH THE 2015
14
OPERATING EXPENSE BUDGET?
15
A.
As described below, the ISO proposes to increase its Core Operating Budget (all
16
costs other than depreciation and the true-up) from 2015 levels to: (i) maintain
17
competitive compensation and benefits ($3.8 million); (ii) maintain existing
18
software licenses and maintenance ($1.3 million); (iii) cyber security initiatives,
19
including creation of a 24/7 cyber security operations center ($1.3 million); (iv)
20
meet the Internal Market Monitor’s resource needs, including two new headcount
21
($1.0 million); (v) implement changes to the Forward Capacity Market
Exhibit 3
Page 9
1
($800,000); and (vi) and miscellaneous increases, including increased NERC and
2
NPCC dues ($1.2 million). Because the ISO has also realized efficiencies and
3
savings of $3.8 million, the net increase has been reduced to approximately $5.6
4
million.
5
Q.
6
7
PLEASE DESCRIBE THE COSTS TO MAINTAIN COMPETITIVE
COMPENSATION AND BENEFITS.
A.
To maintain medical benefits and life and disability insurance for its employees
8
and to fund its defined contribution pension plan, the ISO will incur an additional
9
$700,000 in costs. This category also includes the ISO’s $3.1 million budget for a
10
2.75% increase in salaries based on merit and a .75% increase for promotions.
11
The budgeted amounts for merit and promotion are developed using data from
12
several national compensation consultants, and are within the ranges reported in
13
these surveys. Please see Ms. Dickstein’s testimony for detail on the development
14
of these allocations, compensation practices in general, and the ISO’s compliance
15
with the standards of the Internal Revenue Service regarding the reasonableness of
16
executive compensation.
17
Q.
18
19
PLEASE DESCRIBE THE INCREASES TO MAINTAIN COMPUTER
LICENSES AND MAINTENANCE.
A.
The cost increase of $1.3 million in this category represents increased costs for
20
on-going support, systems backup software, and support for new hardware and
21
software. Most significantly, the costs stem from Microsoft’s determination that
Exhibit 3
Page 10
1
independent system operators and regional transmission organizations no longer
2
qualify for pricing as charitable organizations.
3
Q.
PLEASE DESCRIBE THE INCREASES FOR CYBER SECURITY
4
INITIATIVES, INCLUDING A 24/7 CYBER SECURITY OPERATIONS
5
CENTER.
6
A.
More than half of the cost increase of $1.3 million in this category is to fund six
7
full-time employees who will provide around-the-clock surveillance of systems
8
and networks in a cyber security operations center. The ISO’s Board of Directors
9
proposed this center after forming an ad hoc Cyber Security Committee to assess
10
and address the ISO’s cyber security risks. The remainder of the cost increase is
11
for new or enhanced monitoring software and cyber security insurance, a
12
relatively new product that protects against the costs of a cyber security event.
13
Q.
14
15
PLEASE DESCRIBE THE INCREASES TO MEET THE INTERNAL
MARKET MONITOR’S RESOURCE NEEDS.
A.
The ISO’s internal market monitor has identified resources that are needed for his
16
department to perform its monitoring and mitigation functions. These resources
17
include two new full-time employees and consulting support to address workload
18
created by new features of the Forward Capacity Market, including de-list
19
reviews, non-price retirements, Pay For Performance, and an update to the Offer
20
Review Trigger Price ($300,000). Other portions of the cost increase will fund
21
enhanced monitoring capabilities through improvements in processes, data
Exhibit 3
Page 11
1
gathering, and analysis for systems enhancements ($500,000). Finally, $200,000
2
has been allocated to funding for information technology support of market
3
monitoring systems.
4
Q.
5
6
PLEASE DESCRIBE THE INCREASES TO IMPLEMENT CHANGES TO
THE FORWARD CAPACITY MARKET.
A.
As noted in the description of increased market monitoring costs, there have been
7
a number of changes to the Forward Capacity Market that have increased the
8
ISO’s workload. More specifically, the cost increase of $800,000 in this category
9
results from the need for additional consulting and staff time in Market
10
Development to design sloped demand curves, qualification process changes,
11
auction pricing rules and associated reconfiguration auctions, and to address
12
demand-side participation. Other increased costs include consultant funding in
13
System Planning to update the calculation of the Cost of New Entry.
14
Q.
PLEASE DESCRIBE THE MISCELLANEOUS INCREASES.
15
A.
The cost increase of $1.2 million in this category is attributable to increased
16
hardware leasing costs, maintenance of new control room communication
17
systems, consulting services in information technology to support Model-On-
18
Demand, support for enhancements to the Energy Management System, training
19
on NERC Standards for System Operations, and integration of market
20
enhancements in Settlements and Market Operations. These enhancements
21
include Sub-Hourly Settlements, Divisional Accounting and Oracle Business
Exhibit 3
Page 12
1
Intelligence. Finally, this category includes $100,000 to meet increased NERC
2
and NPCC dues and fees for the Eastern Interconnect Data Sharing Network.
3
Q.
4
5
PLEASE PROVIDE FURTHER INFORMATION ON INCREASED HEAD
COUNT FOR 2016.
A.
To determine its resource needs for 2016, the ISO looked at the work load to be
6
completed, including on-going work from 2015, non-repetitive work from 2015 to
7
2016, and new work for 2016. Each area of the Company then reviewed the
8
current resources available to complete this work, utilizing the current employee
9
complement to perform this work to the greatest extent possible. Accordingly, in
10
approaching the completion of the bottom-up budget, the ISO looked to add
11
positions only if (1) the position was needed for resource purposes or (2) the
12
position was cost beneficial to the overall budget.
13
The ISO is requesting a total of 8.5 additional positions in the 2016 budget. As
14
discussed above, the requested positions include six full-time employees to staff
15
the Cyber Security Operations Center and two full-time employees in Market
16
Monitoring. The remaining .5 is the net of two part-time employees moving to
17
full-time to support power system modeling improvements in Information
18
Technology Department and outage coordination in System Operations, and
19
another employee in a business analyst role is going from full-time to part-time.
Exhibit 3
Page 13
1
These additional positions relate to only a small portion of the additional work
2
being taken on for 2016. In fact, a number of resources are being reallocated to
3
2016 priorities. Specifically, approximately eight full-time employees will be
4
reallocated to new work, including six in Market Operations and two in System
5
Planning. This was accomplished through a combination of efficiencies gained or
6
the discontinuation of other work previously performed. Additionally, internal
7
ISO employees will assume work previously performed by contractors, under both
8
the operating and capital budgets, including in Market Operations (operating and
9
capital), Legal (operating), and System Planning (operating).
10
Q.
11
12
THERE HAS BEEN SIGNIFICANT ORGANIZATIONAL GROWTH IN
RECENT YEARS. CAN YOU EXPLAIN IT?
A.
The ISO will have added 52 full-time employees over the course of 2013, 2014,
13
2015 and 2016. This growth reflects the increase in the complexity of the ISO’s
14
operations. For example, compliance with new and emerging NERC and NPCC
15
standards has required a significant investment. The ISO has also provided
16
additional services, like doubling its billing obligations through twice-weekly
17
billing, which further mitigated market participants’ risk of significant payment
18
defaults, and adding transmission planning and economic studies. All of these
19
changes require personnel. Another area that has contributed to the addition of
20
employees is the replacement of long-term contractors with employees where the
21
responsible manager made a determination that the work being performed is
Exhibit 3
Page 14
1
permanent and that it was cost-advantageous to convert the position to that of a
2
full-time employee. These added positions had little or no impact on the budget.
3
Finally, certain departments have grown, including System Operations, in part due
4
to the need for employees to staff the Back-Up Control Center, which is more
5
robust as a result of compliance with more stringent requirements from the
6
Commission and NERC, and to provide training and backup for Control Room
7
Operators. Market Monitoring has grown as well, given the Commission’s
8
emphasis on this area and the evolution of the markets, including the Forward
9
Capacity Market. As noted above, two of the positions added for 2016 are for
10
Market Monitoring, with the rest of the full-time positions created to meet the
11
increasing cyber security risks through the staffing of a 24/7 Cyber Security
12
Operations Center.
13
Q.
HOW DOES ISO-NE’S SIZE COMPARE TO OTHER ISOS AND RTOS?
14
While the types and scopes of services vary widely among the ISOs and RTOs,
15
many costs are largely fixed, because all ISOs and RTOs must comply with the
16
Commission’s orders and mandatory reliability standards. ISO-NE does review
17
what others are spending. (See detail on comparisons in the ISO’s Budget
18
Presentation.) ISO-NE’s review indicates that its cost structure is reasonable.
1
Q.
2
3
Exhibit 3
Page 15
PLEASE DESCRIBE THE BUDGET CUTS AND DEFERRALS THAT
OFFSET THESE INCREASED COSTS.
A.
For 2016, the ISO has realized $3.8 million in savings by reallocating resources,
4
automating work, identifying efficiencies, and eliminating discontinued or non-
5
repetitive work. As discussed above, eight employees were reassigned internally
6
to save costs.
7
The $3.8 million also includes a small amount of savings in contributions to the
8
ISO’s defined benefit pension plan, which was closed to new entrants as of
9
January 1, 2014, but which must still be funded to meet the ISO’s obligations to
10
employees who were enrolled before that cut-off date.
11
For 2016 and future years, the ISO has changed its funding methodology for the
12
defined benefit pension plan, by adopting a “level funding” approach. After
13
consulting with its actuaries and investment consultants, the ISO decided on a flat
14
$10 million contribution to the plans for each of the next ten years (barring
15
unforeseen circumstances). This level funding approach should decrease the
16
volatility of the expense while still maintaining reasonable levels of funding. If
17
the ISO had not adopted this approach, the 2016 contribution would have been
18
$11.05 million.
1
Q.
Exhibit 3
Page 16
DOES THE REVENUE REQUIREMENT INCLUDE DEPRECIATION ON
2
ITEMS IN THE CAPITAL BUDGET THAT ARE PLACED IN SERVICE
3
IN 2016?
4
A.
Yes. The ISO’s depreciation rates remain unchanged from those accepted by the
5
Commission in the ISO’s 2015 Revenue Requirement. The ISO uses the straight-
6
line depreciation methodology based on no net salvage value and the various
7
average service lives described below. These service lives reflect the ISO’s
8
historical experience and forecasted expectations for capital projects placed into
9
service, are necessary to comply with the ISO’s funding mechanisms, are
10
consistent with the ISO’s historical experience, and have been repeatedly
11
determined by independent auditors to be reasonable. The service lives are:
12
•
Computer hardware, software and accessories: 3 to 5 years
13
•
Software development costs: 3 to 5 years
14
•
Furniture and fixtures: 7 years
15
•
Machinery and equipment: 7 years
16
•
Building: average of 25 years (based on the opinion of independent bond
17
counsel and analysis of the service lives of the different aspects of the
18
building (e.g., the building’s steel and concrete at 40 years, mechanical
19
and electrical work at 25 years, and high wear-and-tear elements at 15
20
years))
21
22
•
Leasehold/Building Improvements: lesser of 1 to 25 years or remaining
life of the lease or building, as determined at the time of the purchase
Exhibit 3
Page 17
1
based on the nature of each such improvement (e.g., rooftop railing at
2
twenty-five years, air conditioning unit at fifteen years, capacitor bank at
3
ten years)
4
•
5
The ISO uses private placement debt, issued pursuant to Commission
6
authorization under Section 204 of the Federal Power Act, to fund its capital
7
program. The ISO funds future capital expenditures by using amounts collected
8
for depreciation, with the notes covering the delay between project expenditures
9
and the collection of depreciation through rates. In addition, the ISO funds its
Vehicles: 3-7 years
10
working capital needs through a revolving line of credit.
11
The private placement notes are non-amortizing, with interest-only payments due
12
semi-annually throughout the life of the notes, and the principal due at the end of
13
the term. Revenue reserved for the depreciation of capital assets, as well as assets
14
placed in service in prior years and still depreciable, will be available to repay the
15
remaining principal amounts on outstanding debt.
16
Please note that capital projects include the cost of the necessary work performed
17
by the product manager, test coordinator and business analyst in the Program
18
Management Office and design work. If the design is approved and built, this
19
project management and design work is part of the asset on which depreciation is
20
collected when the asset is placed in service in future years via the Revenue
Exhibit 3
Page 18
1
Requirement. On the other hand, if the capital project is abandoned, the ISO
2
writes off the project management and design work and recovers it in full in the
3
year of abandonment. In addition, each capital project also includes the first
4
year’s maintenance cost and license fees for any newly capitalized software.
5
Q.
6
7
HOW DOES THE ISO ADDRESS UNEXPECTED COSTS THAT MIGHT
MATERIALIZE DURING 2016?
A.
The 2016 Core Operating Budget includes two line items to address unexpected
8
needs: (i) the CEO Emerging Work allowance of $1.1 million; and (ii) the
9
Operating Contingency of $700,000. Inclusion of these contingency amounts
10
recognizes that circumstances may arise that the ISO does not foresee in setting its
11
2016 Revenue Requirement for its various departments and programs.
12
The CEO Emerging Work Allowance covers new or deferred activities and
13
initiatives that emerge or become priorities during the year. Approval from both
14
the CEO and CFO is required before the ISO may draw upon these funds.
15
The Operating Contingency provides a funding source of last resort. ISO
16
management cannot access this fund without first obtaining approval from the
17
ISO’s independent Board of Directors.
1
Q.
2
3
Exhibit 3
Page 19
DO YOU FORESEE ANY PARTICULAR CONTINGENCIES THAT
WILL WARRANT THE ISO TAPPING INTO THESE FUNDS?
A.
I cannot say for sure what type of contingencies might arise. There are, however,
4
several ongoing issues that might require additional funds not included in the
5
2016 Core Operating Budget. The biggest issue is litigation that could be initiated
6
or accelerated in 2016. Additional risks include costs to comply with unforeseen
7
significant shifts in federal and state policy, costs of complying with Order 1000
8
that exceed estimates, interest rates, and additional cyber security work. In
9
general, states, Customers and the Commission will determine the extent of
10
11
additional work and resources required.
Q.
12
13
HAS THE ISO TAKEN ANY ACTION TO MITIGATE THE RISK OF A
CHANGING INTEREST RATE ENVIRONMENT?
A.
The ISO has purchased an interest rate cap for a portion of its tax-exempt bond
14
issuances. The tax-exempt bonds were issued in Massachusetts to fund the
15
refurbishing of the Main Control Center and in Connecticut to fund the
16
development of the Back-Up Control Center. Both sets of bonds are priced at a
17
weekly variable rate. By opting for variable rates on both sets of bonds, the ISO
18
has saved more than $12,100,000 since 2005 when the ISO first issued the
19
Massachusetts tax-exempt bonds (the Connecticut bonds were issued in 2012).
20
The ISO will protect that savings through the interest rate cap. The cap will
21
effectively serve as an insurance policy or “stop loss” mechanism in a changing
Exhibit 3
Page 20
1
interest rate environment, and is intended to cover the ISO’s interest rate exposure
2
through February 1, 2024 if rates rise significantly.
3
The cap covers only the unhedged portion of the variable rate debt. The ISO has
4
not purchased coverage for the portion of the debt that is hedged by the interest
5
earned on the settlement float that the ISO has through the normal course of
6
participant settlement, billing and payment. In other words, for a portion of the
7
ISO’s debt, the interest earned on the balance carried in the settlement account (as
8
amounts are due two days before they are paid out to customers) offsets the
9
interest due on the bonds. Because the projected average balance in the settlement
10
account does not provide complete cover for the floating rate tax-exempt debt, the
11
ISO purchased the 10-year interest rate cap to protect against a large uptick in the
12
variable tax-exempt interest rates for the uncovered portion.
13
Since the tax-exempt bonds are amortizing, the hedge is only in place until the
14
unamortized amount of the bonds drop below the projected average balance in the
15
settlement account. The cost of the cap is about $88,000 per year.
16
Q.
PLEASE DESCRIBE THE CALCULATION OF THE 2014 TRUE-UP.
17
A.
As set forth in Section IV.A.2.2 of the Tariff, the ISO has reconciled calendar year
18
2014’s actual expenses and collections under Schedules 1, 2 and 3 of the Tariff by
19
means of a true-up. The actual difference between 2014 expenses and collections
Exhibit 3
Page 21
1
is an over-collection of approximately $600,000, which decreases the 2016
2
Revenue Requirement by that amount. See RCL–2, Schedule 2.
3
Q.
4
5
THREE SCHEDULES?
A.
6
7
8
Schedule 1 increases by $1.69 million; Schedule 2 decreases by about $2.35
million; and Schedule 3 increases by $40,000. See RCL-2, Schedule 2.
ACTIVITY ACCOUNTING SYSTEM
Q.
9
DESCRIBE THE ISO’S ACTIVITY ACCOUNTING SYSTEM AND THE
EXTENT TO WHICH IT PROVIDES COST OF SERVICE
10
11
HOW IS THE 2014 TRUE-UP AMOUNT ALLOCATED AMONG THE
INFORMATION FOR EACH OF THE THREE PRIMARY SCHEDULES.
A.
The activity accounting system was implemented at the ISO’s inception in 1997
12
and refined in 1998. All operating charges recorded in the general ledger system
13
must be cross-referenced to an activity. Each department has identified its major
14
activities. Most activities are department-specific, but some activities may be
15
cross-charged if they are of a project nature. Activities within a department are
16
known as either “direct” activities or “indirect” activities. Direct activities are of
17
an operational nature and are allocated to one or more of the three schedules based
18
on a fixed percentage. This fixed allocation is provided by the department
19
manager annually in preparation for the next year’s budget and tariff filing.
20
Indirect activities are of an administrative nature and are allocated based on
21
current direct labor charges. In addition, the majority of activities for
Exhibit 3
Page 22
1
administrative departments (Finance, Human Resources, etc.) are allocated based
2
on the total labor charges within the Company.
3
The activity accounting system is largely manual, meaning that timesheets and
4
invoices are coded manually. The ISO found that it would not be prudent to
5
overly expand the system to require each employee to specify the schedule
6
serviced through the week. Further, the ISO does not pre-code employees’ time
7
because duties change often with seasonality or new projects. Therefore, the
8
allocation of activities to the schedules is made at the manager level.
9
The activity system is not designed to track costs to individual markets or
10
transaction units. An employee’s time is not driven by the number of transaction
11
units or markets, but by the number of tasks and projects.
12
If the activity accounting system were expanded to provide for accounting cost in
13
more detail, it would be more costly and difficult to manage without substantially
14
increasing its accuracy.
15
Q.
HOW WAS THE TARIFF SCHEDULE ALLOCATION VERIFIED?
16
A.
In developing the Revenue Requirement for each schedule, managers with cost
17
center responsibilities are required to review the allocation of each and every
18
activity under their control as to the appropriateness of the allocation. During this
19
lengthy evaluation process, all of the activities used by the ISO are reviewed. It is
Exhibit 3
Page 23
1
this activity allocation structure that formed the basis of the revenue requirements
2
for each of the three primary schedules.
3
2016 COST ALLOCATION AMONG SCHEDULES 1, 2, AND 3
4
Q.
5
6
HAVE YOU PREPARED AN EXHIBIT THAT SHOWS THE
DEVELOPMENT OF THE COST OF SERVICE (“COS”) ANALYSIS?
A.
Yes. The following schedules support the COS shown in RCL-3:
7
Schedule 1
Total Cost Allocation to Schedules by Department
8
Schedule 2
Total Direct Labor Allocation to Schedules by Department
9
Schedule 3
Total Cost Allocations to Schedules by Cost Category
10
11
Schedule 4
Direct Labor Cost Allocations to Schedules by Cost
Category
12
Schedule 5
Allocation Factors by Cost Category
13
Schedule 6
Allocation on Depreciation and Amortization Expense
14
Q.
WHAT IS THE ISO’S MAIN EXPENSE?
15
A.
As a non-profit entity that operates, but does not own, generation or transmission
16
assets, the ISO’s main expense in the Core Operating Budget is personnel. As
17
shown in RCL-5, Schedule 1, the ISO has budgeted $106.1 million of the ISO’s
18
2016 Core Operating Budget for salaries and overhead. This category includes
19
fees for the Board of Directors, as well.
Exhibit 3
Page 24
1
Q.
WOULD YOU PLEASE DESCRIBE YOUR RCL-3?
2
A.
RCL-3, Schedule 1 contains the Test Year 2016 COS for each of the three primary
3
rate schedules. The exhibit lays out in detail how ISO costs were assigned to the
4
three schedules.
5
Most activity costs consist of direct labor costs, employee benefits, and other non-
6
labor-related costs (e.g., office supplies, software, hardware, depreciation, interest,
7
consulting, etc.). For each Activity Code, both the labor-related and non-labor-
8
related costs are assigned to the rate schedule using the same allocator.
9
Q.
10
11
PLEASE EXPLAIN HOW LABOR RATIOS WERE DEVELOPED AND
USED TO ALLOCATE COSTS IN RCL-3.
A.
Schedule 4 of RCL-3 shows an allocation to the three schedules of all ISO direct
12
labor costs as projected for Test Year 2016. Within a given department, known
13
allocators (“Alloc-Fixed”) for specific cost categories were used to allocate those
14
labor costs that were specifically attributable to a schedule. The Alloc-Fixed labor
15
costs were summed for that department and all remaining labor costs within that
16
department were allocated in proportion to the summed Alloc-Fixed costs. Labor
17
costs within all departments were allocated in this manner and summed for the
18
entire company. Schedule 5 of RCL-3 summarizes the labor allocation factors or
19
labor ratios for each Activity Code. These ratios were then used to allocate
20
various cost items in Schedules 3, 4, and 6 of RCL-3.
1
Q.
2
3
Exhibit 3
Page 25
PLEASE SUMMARIZE YOUR PROPOSED 2016 COS RESULTS FROM
RCL-3 FOR EACH OF THE THREE RATE SCHEDULES.
A.
Table 1 below summarizes the results of all the allocations contained in Schedule
4
1 of RCL-3, at Lines 47, 49 and 51. The totals demonstrate an initial 2016
5
Operating Expense Revenue Requirement (also provided on line 10 to RCL-2,
6
Schedule 2, page 1) decreased by the true-up amount (also provided on line 14 to
7
RCL-2, Schedule 2, page 1) to result in the total 2016 Revenue Requirement (also
8
provided on line 17 to RCL-2, Schedule 2, page 1).
Table 1
2016 Cost of Service Results (1)
Description
(a)
9
10
Test Year
(b)
Schedule 1, Scheduling, System Control and Dispatch Service
$
Schedule 2, Energy Administration Service
Schedule 3, Reliability Administration Service
Total
$
44,360,392 $
84,722,023
56,068,806
185,151,221 $
True-Up
(c)
1,688,404 $
(2,348,713)
38,565
(621,744) $
Total
(d)
46,048,796
82,373,310
56,107,371
184,529,477
(1) From Exhibit 3 (RCL-3), Schedule 1.0.
Q.
EXCLUDING TRUE-UP AMOUNTS, HOW DO THE COS RESULTS IN
11
SCHEDULE 1 OF RCL-3 COMPARE WITH THE TEST YEAR 2015 COS
12
RESULTS, ON WHICH THE CURRENT ISO RATES ARE BASED?
13
14
A.
Table 2 below compares, before taking into account any true-ups, the 2016 COS
results from Schedule 1 of RCL-3 to the 2015 COS results. Table 2 demonstrates
Exhibit 3
Page 26
1
how, excluding the true-up amounts, the 2016 COS constitutes a $6.8 million
2
increase from the 2015 COS accepted by the Commission last year.
Table 2
Comparison for Cost of Service Results
(Before True-Ups)
Description
(a)
Total
(b)
ISO Tariff Schedules
Schedule 1
Schedule 2
(c)
(d)
Schedule 3
(e)
2016 COS (1)
$185,151,221
$44,360,392
$84,722,023
$56,068,806
2015 COS (2)
$178,314,912
$42,327,088
$81,019,153
$54,968,671
Difference -$
-%
$6,836,309
3.8%
$2,033,304
4.8%
$3,702,870
4.6%
$1,100,135
2.0%
(1) From T able 1, Column (b).
3
(2) From Exhibit 3 (RCL-3), Sch. 1.0, Ln. 47, in FERC Dkt. No. ER15-112-000.
4
Q.
HAVE YOU IDENTIFIED SPECIFIC ACTIVITY ITEMS THAT GIVE
5
RISE TO THE INCREASES AND/OR DECREASES SHOWN ABOVE
6
FOR THE THREE SCHEDULES?
7
A.
Yes. Table 3 below highlights key activity items from Test Year 2016 allocated
8
among the three primary schedules by cost category (RCL-3, Schedule 3), along
9
with various depreciation/amortization items (RCL-3, Schedule 6), which changed
10
from 2015. The identified activity items account for the majority of the cost shifts
11
within each of the three schedules.
Exhibit 3
Page 27
Table 3
Examples of Differences in 2016 Operating Expenses
Activity
Code (a)
Various
6540
Various
12017
6512
6595
21604
21605
21804
21654
6541
6513
21707
3000
2033
21651
6615
Description
(b)
ISO Tariff Schedules
Schedule 1
Schedule 2
(d)
(e)
Test Year 2016
Total
(c)
Depreciation/Amortization
Security Compliance and Reporting
M arket M onitoring
Forward Capacity M arket (FCM ) Reforms
Host Computer - Hardware
IT WEB Application Support
DTS Support
DAM Support
Software Support - M itigation
NX9 Administration
Security SW Tools Program
Host Computer - Software
Application Analysis and Conceptual Design
Hourly Settlements Support
M arket Analysis
Power System M odeling
Host Computer M onitoring
$
32,882,654
2,169,684
4,665,011
810,821
1,146,315
722,943
1,544,494
1,000,980
451,110
481,016
333,579
1,763,842
1,074,003
263,183
184,563
861,609
1,254,513
-
Totals
$
51,610,318 $
8,659,550
467,524
155,780
1,235,595
200,196
192,406
71,880
344,643
-
11,327,574 $
Schedule 3
(f)
13,677,404
1,122,835
3,111,632
859,736
374,131
308,899
600,588
360,888
192,406
172,631
1,322,882
859,202
131,592
184,563
344,643
627,257
10,545,700
579,325
1,553,379
810,821
286,579
193,032
200,196
90,222
96,203
89,069
440,961
214,801
131,592
172,322
627,257
24,251,288 $
16,031,456
Test Year 2015
Various
6540
Various
12017
6512
6595
21604
21605
21804
21654
6541
6513
21707
3000
2033
21651
6615
M arket M onitoring
DTS Support
DAM Support
NX9 Administration
M arket Analysis
$
31,650,319
1,284,381
3,769,871
140,871
824,921
414,337
1,236,045
749,238
239,986
276,854
148,352
1,596,370
919,376
122,522
81,868
768,214
1,174,719
7,535,487
276,759
89,281
988,836
149,848
110,742
31,967
307,285
-
12,856,039
664,681
2,631,545
618,691
214,424
247,209
449,543
191,989
110,742
76,774
1,197,277
735,501
61,261
81,868
307,285
587,359
11,258,793
342,941
1,138,326
140,871
206,230
110,632
149,848
47,997
55,371
39,611
399,092
183,875
61,261
153,643
587,359
Totals
$
45,398,243 $
9,490,204 $
21,032,188 $
14,875,851
Test Year 2016 Costs Minus Test Year 2015 Costs
Various
6540
Various
12017
6512
6595
21604
21605
21804
21654
6541
6513
21707
3000
2033
21651
6615
1
M arket M onitoring
DTS Support
DAM Support
NX9 Administration
M arket Analysis
$
1,232,335
885,303
895,140
669,950
321,394
308,606
308,449
251,742
211,124
204,162
185,227
167,472
154,627
140,661
102,695
93,395
79,794
1,124,063
190,765
66,498
246,759
50,348
81,665
39,913
37,358
-
Totals
All Other Unidentified Changes
Total Change in Cost of Service
$
$
$
6,212,075 $
624,234 $
6,836,309 $
1,837,370 $
195,934 $
2,033,304 $
3,219,100 $
483,771 $
3,702,870 $
1,155,605
(55,471)
1,100,135
90.87%
90.36%
86.94%
105.04%
% of Difference shown on Table 2
821,365
458,154
480,087
241,045
159,707
61,690
151,045
168,899
81,665
95,857
125,604
123,701
70,331
102,695
37,358
39,897
(713,093)
236,384
415,053
669,950
80,348
82,400
50,348
42,225
40,832
49,457
41,868
30,925
70,331
18,679
39,897
1
Q.
Exhibit 3
Page 28
PLEASE EXPLAIN IN FURTHER DETAIL HOW THE REVENUE
2
REQUIREMENTS CHANGED FOR EACH SCHEDULE FROM THOSE
3
UTILIZED IN THE FILING SUPPORTING THE 2015 RATE TO THOSE
4
UTILIZED HERE FOR TEST YEAR 2016.
5
A.
Schedule 1: The increase in the Revenue Requirement for Schedule 1 results
6
from 2016 cost increases and changes that impact all three schedules, including
7
the costs to maintain the benefits and compensation, the costs of cyber security
8
improvements, computer service licensing and maintenance, and depreciation
9
expenses for in-service projects including Critical Infrastructure Protection v. 5
10
and Business Continuity Planning Phase III – Remote Desktop. The remainder of
11
the Schedule 1 increase is depreciation expense for the Coordinated Transaction
12
Scheduling project (predominantly allocated to Schedule 1) and the Generation
13
Control Application Production Part 1 project (allocated evenly between
14
Schedules 1 and 2).
15
Schedule 2: The increase in the Schedule 2 Revenue Requirement is due to:
16
increases that impact all three schedules, as discussed in the preceding paragraph;
17
increased funding for Market Monitoring, as discussed above; and depreciation
18
for the Business Continuity Planning Phase III – Markets Infrastructure project
19
(largely allocated to Schedule 2), the Generation Control Application Production
20
Part 1 project (allocated evenly between Schedules 1 and 2), and the Wind
Exhibit 3
Page 29
1
Integration Phase II/Do Not Exceed Dispatch project (allocated evenly between
2
Schedules 2 and 3).
3
Schedule 3: The increase in the Schedule 3 Revenue Requirement is due to: the
4
increased costs allocated to all three schedules (see above); funding for the
5
increased Forward Capacity Market costs discussed above; the increased Market
6
Monitoring costs related to Forward Capacity Market (also discussed above); and
7
depreciation expense for the Forward Capacity Auction 10 project and the Wind
8
Integration Phase II/Do Not Exceed Dispatch project (allocated evenly between
9
Schedules 2 and 3). The increases were offset by an overall reduction in
10
depreciation expense for Schedule 3 as a result of previously-implemented
11
projects becoming fully depreciated during 2016. These projects include the
12
Synchrophasor Infrastructure and Data Utilization project, the Energy
13
Management System Upgrade and Enhancements project, and the Forward
14
Capacity Market Enhancements 2012 project.
15
THE ISO RATE DESIGN AND ESCALATION FACTORS
16
Q.
HOW DID YOU DEVELOP THE ESCALATION FACTORS?
17
A.
Consistent with the practice reflected in the filings establishing the ISO’s rates to
18
collect its administrative costs for 1999-2015, escalation factors rely on
19
information contained in the 2015-2024 Forecast Report of Capacity, Energy,
20
Loads and Transmission (the “CELT Report”), dated May 1, 2015. The CELT
21
Report contains actual and estimated energy and peak loads for 2015-2024. The
Exhibit 3
Page 30
1
ISO also relied on information in the ISO markets system for the 12-month period
2
ending July 2015. The development of the escalation factors is shown in RCL-7,
3
Schedule 1.
4
Q.
ARE YOU PROPOSING ANY CHANGES TO THE RATE DESIGN?
5
A.
The ISO is not proposing any changes to the rate design from that in place in
6
2015. However, as part of its filing of the Coordinated Transaction Scheduling
7
(“CTS”) project with the New York ISO, ISO-NE filed changes to Schedules 1, 2
8
and 3 of Section IV.A of the Tariff on September 10, 2015. Those changes are
9
still pending before the Commission.
10
CTS is intended to enhance the market efficiency of external transactions (i.e.,
11
energy imports and exports) between the two regions through economic clearing
12
of external transactions. As part of that effort, ISO-NE has proposed that certain
13
charges in Schedules 1, 2 and 3 be eliminated, effective on or after December 1,
14
2015.
15
If the Commission approves the changes, they will affect collections under
16
Schedules 1, 2 and 3. The ISO has estimated the impact of this change using
17
historical monthly average volumes for external transactions and total pool
18
charges. The ISO has concluded that the eliminated charges make up 1.1% of
Exhibit 3
Page 31
1
Schedule 1 total charges; 2.8% of Schedule 2 charges; and 1.4% of Schedule 3
2
charges. Their elimination will raise the affected billing determinants. 2
3
In its development of rates for 2016, ISO-NE has presumed Commission
4
approval; accordingly, the projected effects of CTS have been incorporated into
5
the 2016 rates that are described below. Below, ISO-NE highlights the sections of
6
the Schedules where CTS changes have been proposed.
7
Q.
8
PLEASE OUTLINE THE CURRENT RATE DESIGN BEFORE
DESCRIBING THE VARIOUS ESCALATION FACTORS.
9
A.
As previously indicated, Section IV.A of the Tariff has three rate schedules to
10
cover the ISO’s expenses for providing its three services: Schedule 1 -
11
Scheduling Service; Schedule 2 – Energy Administration Service; and Schedule 3
12
– Reliability Administration Service.
•
13
Schedule 1
14
The Schedule 1 revenue requirement is allocated 100% to Monthly Regional
15
Network Load and the Reserved Capacity of Through and Out Service; changes
16
are pending before the Commission to exclude Coordinated External
17
Transactions, which are defined in Section I of the Tariff as transactions at
18
external interfaces to which the enhanced scheduling procedures in the CTS rules
2
Slides 5-7 of “Coordinated Transaction Scheduling: Self and Capital Funding Tariff,” a presentation to the
NEPOOL Budget & Finance Subcommittee that was made in May 2015. The presentation can be found at
http://www.iso-ne.com/static-assets/documents/2015/05/5a_coordinated_transaction_sch_self_cap_cft.pdf.
Exhibit 3
Page 32
1
(located in Tariff Section III.1.10.7.A) apply. Schedule 1 revenues collected from
2
Through and Out Service Customers are credited to each Network Customer that
3
month in proportion to each Network Customer’s Monthly Regional Network
4
Load.
5
•
Schedule 2
6
The Schedule 2 revenue requirement is allocated 15% to Transaction Units
7
(“TUs”) and 85% to Volumetric Measures (“VMs”), subject to the special true-up
8
described below. TUs measure the frequency and duration of activity and are
9
indifferent to the size (e.g., capacity) of any particular transaction. Conversely,
10
VMs seek to capture a customer’s “physical” reliance on the system administered
11
by the ISO and thus the benefit received.
12
A.
13
Schedule 2 currently utilizes three types of TUs: those associated with Real-Time
14
Energy Market transactions (Energy TU Based Charges), those associated with
15
Increment Offers and Decrement Bids, and those associated with FTR auction
16
submitted and cleared bids.
17
Energy TUs equal the sum per month of a Customer’s Bilateral Contract Block-
18
Hours, Demand Bid Block-Hours, Asset Related Demand Bid Block-Hours,
19
Supply Offer Block-Hours and Energy Non-Zero Spot Market Settlement Hours.
20
Under the ISO’s current rate design, a Customer’s total monthly Energy TUs are
21
priced under a three-tiered declining block rate structure. Under this regime, the
Transaction Units
Exhibit 3
Page 33
1
highest unit rate applies to the first 12,500 Energy TUs incurred in a month; the
2
Customer’s next 27,000 Energy TUs are priced approximately 10% lower; and the
3
balance of monthly Energy TUs, i.e., those in excess of 39,500, are priced at an
4
additional savings of approximately 10% on average. If the Commission
5
approves the pending CTS rules, Energy TUs will be calculated without reference
6
to contributions from Coordinated External Transactions.
7
TU Charges Based on Increment Offers and Decrement Bids are assessed based
8
on both of the following: (i) a charge multiplied by the total number of Increment
9
Offers and Decrement Bids submitted, plus (ii) a charge multiplied by the total
10
number of Increment Offers and Decrement Bids that clear the Day-Ahead Energy
11
Market. This category is sometimes referred to as “virtual activity,”
12
distinguishing it from physical activity.
13
TU Charges Based on FTR Auction Submitted and Cleared Bids are assessed
14
through both of the following: (i) a charge multiplied by the total number of FTR
15
auction bids submitted for that period, plus (ii) a charge multiplied by the total
16
number of FTR auction bids cleared for that period. The FTR charges are
17
designed to recoup the costs the ISO incurs for administering the FTR auctions.
18
The FTR revenue offsets other Schedule 2 TU charge revenues.
Exhibit 3
Page 34
1
B.
2
Schedule 2 Volumetric Measures consist of the sum of a Customer’s Monthly
3
Real-Time Load Obligation and Monthly Real-Time Generation Obligation
4
(measured in megawatt hours, MWh). Under the ISO’s current rate regime,
5
Schedule 2 VMs are priced under a three-tiered declining block rate structure
6
wherein the highest unitized rate is assessed to the first 250,000 MWh each
7
month; the Customer’s next 1,250,000 MWh are priced at a discount of
8
approximately 10% from the tier-1 unitized rate; and VMs in excess of 1,500,000
9
MWh incur the lowest unitized monthly rate. If the Commission approves the
10
pending CTS rules, Volumetric Measures will exclude the Monthly Real-Time
11
Generation Obligation associated with Coordinated External Transactions.
12
•
Volumetric Measures
Schedule 3
13
Schedule 3 allocates internal load activity based on Real-Time NCP [Non-
14
Coincident Peak] Load Obligation. For Exports, Schedule 3 assesses a volumetric
15
(per MWh) charge. Specifically, the ISO divides the Schedule 3 Revenue
16
Requirement by the real-time load obligation forecasted for the upcoming year in
17
the most recent CELT Report. The remaining revenue requirement for Schedule 3
18
(i.e., net of that allocated to Exports) is then divided by the total Real-Time NCP
19
Load Obligation forecast to yield the unitized rate per kW-month. If the CTS
20
rules are approved by the Commission, Coordinated External Transactions will be
21
exempt from Schedule 3 Export charges.
1
Q.
2
3
Exhibit 3
Page 35
PLEASE EXPLAIN THE ESCALATION FACTORS UTILIZED TO
DEVELOP THE BILLING DETERMINANTS FOR 2016.
A.
The Schedule 1 billing determinants for 2016 were decreased by a net escalation
4
factor of .999. This net is the sum of a 1.0% increase consistent with the
5
increased load projected in the CELT Report data and a 1.1% reduction given the
6
CTS project. See column (c) of RCL-7, Schedule 2.
7
The Schedule 2 transaction unit determinants for Energy TUs, shown in column
8
(d) of RCL-7, Schedule 2, also decrease as a result of CTS by an escalation factor
9
of .967.
10
The Schedule 2 virtual transactions and FTRs were left flat (see columns (e)
11
through (h) of RCL-7, Schedule 2). The numbers of virtual transactions and FTRs
12
have fluctuated in recent years but have not substantially changed overall. Tables
13
4 and 5 below provide, respectively, actual Virtual Energy TU data and actual
14
FTR data from January 2013 through July 2015.
1
Exhibit 3
Page 36
Table 4
Submitted and Cleared Virtual Energy TUs
450,000
50,000
400,000
45,000
350,000
40,000
35,000
30,000
250,000
25,000
200,000
20,000
150,000
15,000
100,000
10,000
Submitted
50,000
Cleared
Submitted
300,000
5,000
Cleared
0
0
2
3
Table 5
Submitted and Cleared FTR TUs (Bids)
120,000
100,000
49,000
Submitted
42,000
Cleared
28,000
60,000
21,000
40,000
20,000
0
4
35,000
14,000
7,000
0
Cleared
Submitted
80,000
Exhibit 3
Page 37
1
The volumetric measures in Schedule 2 decrease by a factor of .985, after netting
2
a load increase of 1.0% against a 2.5% reduction based on CTS implementation.
3
See column (i) of RCL-7, Schedule 2.
4
Finally, the Schedule 3 billing determinant based on export volumes decreases
5
most dramatically as a result of CTS implementation, by an escalation factor of
6
.655, as shown in RCL-7, Schedule 2, column (k). The remainder of the Schedule
7
3 revenue requirement is assessed via a billing determinant related to NCP Load
8
Obligation. This billing determinant, like the Schedule 2 volumetric measures
9
and the Schedule 1 billing determinants, is increased by 1.0% based on CELT
10
Report load data, as shown in column (j) of RCL-7, Schedule 2. Although the
11
NCP Load Obligation billing determinant is not directly impacted by CTS
12
implementation, under CTS the rate will increase due to the lower estimated
13
volume for Schedule 3 exports since the NCP Load Obligation absorbs the
14
remaining Schedule 3 revenue requirement.
15
THE 2016 BILLING DETERMINANTS
16
Q.
PLEASE DESCRIBE THE SCHEDULE 1 RATE CALCULATION.
17
A.
RCL-7, Schedule 3, lines 1 through 3 show the Schedule 1 Billing Determinants
18
and the Revenue Requirement allocated thereto. Dividing the Revenue
19
Requirement by the forecasted billing units yields the rate for 2016 of
20
$0.00026/kW-hour.
Exhibit 3
Page 38
1
Q.
2
A.
Schedule 2 employs a declining blocked rate structure for Energy TUs and VMs.
3
The three-tiered declining block structure is discussed earlier in my testimony.
4
Increment Offers and Decrement Bid TUs and FTR TUs incur unitized charges.
5
RCL-7 (Schedule 3) and Table 6 (below) provide the Schedule 2 rates proposed
6
for 2016.
TABLE 6
2
3
Description
(a)
Transaction Units
INC Offers/DEC Bids
Submitted
Cleared
TY 2016
(b)
$ 0.00500
$ 0.06000
/Offer or Bid
/Offer or Bid
$ 2.02863
$ 2.62374
/Bid
/Bid
12,500TUs
27,000TUs
39,500TUs
$ 0.66437
$ 0.60397
$ 0.54358
/TU-hour
/TU-hour
/TU-hour
250,000MWH
1,250,000MWH
1,500,000MWH
$ 0.28296
$ 0.25723
$ 0.23151
/MWh
/MWh
/MWh
Financial Transmission Rights
Submitted
Cleared
Energy Transaction Units
Block 1 - 1st
Block 2 – Next
Block 3 – Over
Volumetric Measures
Block 1 - 1st
Block 2 – Next
Block 3 – Over
1
Q.
2
3
Exhibit 3
Page 39
PLEASE EXPLAIN HOW THE RATES FOR EACH BLOCK ARE
CALCULATED.
A.
4
The rate components in all cases reflect an approximate 10% differential from the
average rate.
5
Q.
6
A.
RCL-7, Schedule 3 at lines 30 through 33 and Table 7 below list the billing rate
7
calculation. Exports are assessed a unitized charge per MWh based on the
8
Schedule 3 Revenue Requirement using the CELT Report’s real-time load
9
obligation forecast for 2016. The export rate is then applied to the total MWh of
10
Exports forecasted for the test year to determine the portion of the Schedule 3
11
Revenue Requirement assessed to exports. The remaining Revenue Requirement
12
for Schedule 3 (i.e., net of that allocated to exports) is then divided by the total
13
Real-Time NCP Load Obligation forecast to yield the unitized rate per kW-month.
Exhibit 3
Page 40
TABLE 7
TY 2016
Description
Amount
Revenue Requirement ($)
%
$ 56,107,371
100.0%
Real-Time NCP Load Obligation
$ 54,996,595
98.0%
Export Rate
$
1,110,776
2.0%
Billing Units
Export Rate
270,740,473 /kW-Mo.
2,776,941 /MWh
Rates
$ 0.20313 /kW-Mo.
Rate on Exports
$ 0.40 /MWh
1
2
3
RATE SUMMARY
Q.
4
5
WOULD YOU PLEASE SUMMARIZE THE RATES FOR 2016 THAT
YOU ARE SPONSORING?
A.
Yes. These rates are summarized in Table 8.
Exhibit 3
Page 41
Table 8
2016 Rate Components (1)
Tariff Schedule
Q.
3
4
Schedule 1
Network Load (per kW-hour)
$0.00026
Schedule 2
TU Bids (Virtual Inc/Dec)
Submitted
Cleared
$0.00500
$0.06000
FTR Bids
Submitted
Cleared
$2.02863
$2.62374
TU's
Block 1 - 1st 12,500
Block 2 - Next 27,000
Block 3 - Over 39,500
$0.66437
$0.60397
$0.54358
Volumetric
Block 1 - 1st 250,000
Block 2 - Next 1,250,000
Block 3 - Over 1,500,000
$0.28296
$0.25723
$0.23151
Schedule 3
R-T NCP Load Obligation
Export Rate
$0.20313
$0.40000
(1) From Exh 3, RCL-7, Sch. 3
1
2
Jan. 1, 2016
PLEASE EXPLAIN THE SPECIAL CALCULATION FOR A REVENUE
SHORTFALL ATTRIBUTABLE TO TUs USED IN SCHEDULE 2.
A.
In the event of a revenue shortfall attributable to TUs in the true-up year (in this
5
case, 2014), the shortfall allocation has two components. The first component
6
allocates the first 50% of the shortfall to Schedule 2 VMs rather than the usual
Exhibit 3
Page 42
1
15/85 allocation of Schedule 2 Revenue Requirements between TUs and VMs,
2
respectively. The second component increases the percentage of the shortfall
3
allocated to VMs by an additional percentage for each percentage decrease which
4
occurred between the number of TUs used in the current true-up (based on year-
5
to-date actual data through August of the current year) and the number of TUs that
6
the ISO had used in the original projection of the rates for that year.
7
As shown in RCL-7, Schedule 6, the final 2014 amount is an over-collection of
8
$1.4 million. Accordingly, there is no variation for 2016 to the 15/85 allocation
9
of the Schedule 2 revenue requirement between TUs and VMs.
10
11
FIXED FEES
Q.
12
13
DO YOU HAVE ANY OTHER COMMENTS REGARDING THE RATES
INCLUDED IN THE PROPOSED 2016 TARIFF?
A.
Yes. Schedule 3 includes certain RAS Fees that are applicable to Transmission
14
Customers who are non-Market Participants. This fee is currently $3.02 (hourly).
15
For 2016, I am proposing to increase this hourly fee to $3.22.
16
Q.
17
18
PLEASE EXPLAIN HOW YOU DERIVED THE PROPOSED HOURLY
RAS FEE.
A.
The proposed RAS Fee was developed by applying a ratio of the Schedule 3
19
forecasted revenue requirement for 2016 to the Schedule 3 forecasted revenue
20
requirement for 2002 to the 2002 RAS Monthly Fee ($671 x
Exhibit 3
Page 43
1
($56,107,371/$16,035,649) = $2,347.77), and breaking that down to an hourly
2
rate, which for 2016 is $3.22.
3
Q.
DID YOU DEVELOP THE APPROPRIATE RAS FEES FOR THOSE
4
CUSTOMERS WHO TAKE SERVICE FOR PERIODS OF LESS THAN
5
ONE MONTH?
6
A.
Yes. These charges are shown below in Table 9.
Table 9
RAS Fees
Line
No.
Item
(a)
1 Monthly Calculation $
2 Hourly Fee
Proposed
Jan. 1, 2016
(c)
Current
(b)
$
2,202.27
$
2,347.77
3.02
$
3.22
7
8
Q.
9
10
UNDER THE RATES PROPOSED IN THIS FILING, WHAT HAPPENS
TO THE REVENUE DERIVED FROM THESE RAS FEES?
A.
Any revenue derived from the RAS Fees will be credited back on a monthly basis
11
to all Market Participants who take service under Schedule 3 in proportion to the
12
total charges incurred by the Market Participants for that month.
1
Exhibit 3
RCL - 2
Schedule 2
Page 1 of 2
2016 REVENUE REQUIREMENT
(in thousands of dollars)
Line No.
Operating Expense Budget:
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
Operating Budget
Depreciation and interest expense
Depreciation
Interest
$ 149,620.2
32,997.1
2,533.9
35,531.0
Total 2016 Operating Expense Budget
$ 185,151.2
2016 Operating Expense Revenue Requirement
$ 185,151.2
True-Up Amount
2014 (Over)/ Under Collection
Total 2016 ISO Revenue Requirement
$
(621.7)
$ 184,529.5
Exhibit 3
RCL - 2
Schedule 2
Page 2 of 2
2014 True-Up Amount
Line No.
Total
1
2
3
4
2014 Total Operating Expense
2014 Total Collections
$
$
2014 Total (Over) / Under Collection
$
162,707,212
163,328,956
Schedule
2
1
3
$
$
37,981,328
36,292,924
$
$
75,179,339
77,528,052
$
$
49,546,545
49,507,980
(621,744) $
1,688,404
$
(2,348,713) $
38,565
Exhibit 3 (RCL-3)
Schedule 1.0
FERC DOCKET NO. ER16-___-000
TOTAL COST ALLOCATION TO SCHEDULES BY DEPARTMENT
TEST YEAR 2016
Line
No.
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47
48
49
50
51
Department
Description
(a)
Administration-CEO
Self-Funding Tariff
Schedule 1
Schedule 2
(c)
(d)
Total
(b)
$
Finance
9,135,171
$
1,968,449
$
4,727,551
Schedule 3
(e)
$
2,439,171
57,380,408
12,492,669
22,877,361
22,010,378
Building Services
3,109,354
670,004
1,609,125
830,225
Enterprise Risk Management
1,548,371
409,579
695,906
442,885
Human Resources
7,510,873
1,618,445
3,886,959
2,005,469
Legal Department
9,661,273
1,917,340
4,727,255
3,016,678
Internal Audit
1,827,115
298,649
1,172,931
355,535
1,545,526
414,226
12,209,722
984,821
1,267,021
5,547,323
773,699
1,035,587
4,665,011
2,248,016
2,609,034
1,039,110
2,159,294
900,242
1,228,630
4,458,046
5,326,697
1,798,076
2,295,384
3,252,636
740,862
288,706
4,323,391
11,656,862
8,584,936
1,888,404
5,736,905
3,228,782
2,771,706
94,978,655
383,618
143,074
3,910,611
365,320
526,673
3,298,538
90,858
5,578
387,294
54,218
276,455
809,204
550,337
5,001,206
444,030
494,610
540,396
26,178
23,468
1,019,439
1,614,419
1,300,255
3,960
2,089,517
695,739
930,264
24,985,258
686,372
192,284
6,291,578
197,826
420,110
497,765
393,637
720,187
3,111,632
1,988,000
1,197,248
792,726
1,689,884
466,975
288,168
811,628
810,455
1,187,887
1,875,478
372,558
200,199
2,158,705
6,687,166
5,163,349
1,460,272
2,742,072
1,670,930
949,844
45,024,934
475,537
78,869
2,007,533
421,675
320,239
1,751,020
289,204
309,822
1,553,379
260,016
1,024,492
192,165
192,955
433,267
131,258
3,096,081
325,490
543,591
612,888
836,763
342,126
65,039
1,145,247
3,355,277
2,121,333
424,173
905,316
862,113
891,598
24,968,464
56,068,806
38,565
38,565
56,107,371
ISO Operations
COO-Adm
System Operations - Administration
Operations
Reliability and Operations Services
Reliability and Operations Compliance
Operations Support Services
System Operations Support
Market Operations - Adm
Market Monitoring
Market Operations
Market Anaylsis & Settlements
Market Operations Support Services
Market Services
Market Training and Reliability Contracts
System Planning
Resource Adequacy
Transmission Planning
Program Management
Business Architecture and Technology
Market Development
Markets Committee Relations & Rule Integration
Demand Resource Strategy
IT Management
IT System/Network & Desktop
IT Enterprise Applications Support
IT Enterprise Applications Development
IT Energy Management Systems
IT Cyber Security
IT Power System Modeling Management
Total ISO Operations
Total ISO Revenue Requirement
True-up from 2014
Total True-up
ISO Net Revenue Requirement
$
$
185,151,221 $
(621,744)
(621,744) $
44,360,392
1,688,404
1,688,404
$
84,722,023 $
(2,348,713)
(2,348,713) $
$
184,529,477
46,048,796
$
82,373,310
$
$
$
Exhibit 3 (RCL-3)
Schedule 2.0
Page 1 of 1
TOTAL DIRECT LABOR ALLOCATION TO SCHEDULES BY DEPARTMENT
TEST YEAR 2016
Line
No.
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47
Department
Description
(a)
Administration-CEO
Self-Funding Tariff
Schedule 1
Schedule 2
(c)
(d)
Total
(b)
$
Finance
3,038,347
$
654,704
$
1,572,378
Schedule 3
(e)
$
811,265
14,062,314
2,855,435
6,857,793
4,349,086
585,812
126,231
303,164
156,417
1,484,538
393,470
666,569
424,499
Human Resources
4,283,799
923,074
2,216,913
1,143,812
Legal Department
6,073,496
1,224,400
2,789,332
2,059,765
Internal Audit
1,115,445
223,963
628,493
262,990
1,219,926
278,921
11,902,912
825,867
1,257,732
5,563,160
760,239
1,006,297
3,644,061
2,241,527
2,608,693
1,039,110
1,818,114
1,132,684
1,048,470
3,573,876
4,610,272
1,681,472
2,041,781
2,766,119
711,305
267,765
3,768,606
4,883,719
4,397,414
1,869,365
3,149,454
2,189,389
2,006,012
74,264,260
326,958
96,339
3,790,172
322,845
520,131
3,286,516
86,792
5,578
387,244
54,218
268,655
690,228
518,484
4,348,473
424,544
439,963
431,109
24,323
18,956
899,894
782,125
692,133
1,023,900
471,770
653,169
20,564,522
584,997
129,475
6,166,308
157,380
427,698
527,018
387,453
699,684
2,412,633
1,981,716
1,197,081
792,726
1,416,061
676,289
245,517
778,365
783,159
1,056,644
1,609,451
357,629
189,361
1,871,598
2,505,419
2,610,563
1,450,232
1,593,179
1,133,033
671,442
34,412,110
307,970
53,107
1,946,433
345,642
309,903
1,749,626
285,995
301,035
1,231,428
259,811
1,024,367
192,165
133,399
456,395
112,724
2,277,027
261,798
473,769
545,173
725,559
329,353
59,448
997,114
1,596,175
1,094,718
419,134
532,374
584,586
681,400
19,287,628
Building Services
ISO Operations
COO-Adm
Operations
Market Monitoring
Market Operations
Market Services
System Planning
Resource Adequacy
Program Management
Market Development
IT Management
IT Cyber Security
Total ISO Operations
Total ISO Direct Labor
$
104,908,012
$
26,965,798
$
49,446,752
$
28,495,462
Exhibit 3 (RCL-3)
Schedule 3.0
Page 1 of 7
TOTAL COST ALLOCATIONS TO SCHEDULES BY COST CATEGORY
TEST YEAR 2016
Line
No.
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47
48
49
50
51
52
53
54
55
56
57
58
59
60
61
62
63
64
65
66
67
68
Activity Code
Description
(b)
Allocation
Factor (1)
(c)
307
12651
12652
12654
12657
Administration-CEO
Indirect Administrative Support
NEPOOL Committee Support
National Committee Support
Indirect Administrative Support for BCC
Total
Total Dir Labor
Total Dir Labor
Total Dir Labor
Total Dir Labor
302
11601
11701
11702
11901
12001
12005
12017
12101
12201
92004
92005
92006
92007
92008
92009
92010
92011
92012
92013
92014
92015
92016
99707
99995
99996
99996
99998
Finance
Payroll Administration
Accounts Payable
Procurement
Billing for Transmission and Energy Settlements
Budgeting and Forecasting
Credit Admininstration
Forward Capacity Market (FCM) Reforms
Ledger Closing, Financial Statements and Tax Reporting
Treasury and Cash Management
Depreciation Expense 2004 Assets
Amortization of Land Recovery
NPCC/NERC Dues
Operating Contingency
Payroll & Other Accruals
Total
Total Dir Labor
Total Dir Labor
Total Dir Labor
Total Dir Labor
Total Dir Labor
Total Dir Labor
Alloc-Fixed
Total Dir Labor
Total Dir Labor
Alloc-Fixed
Alloc-Fixed
Total Dir Labor
Total Dir Labor
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
Total Dir Labor
Total Dir Labor
Total Dir Labor
366,853
199,569
479,629
68,142
498,264
333,866
810,821
589,983
2,539,144
43,160
802,617
570,733
162,196
15,026
11,454
103,190
619,573
2,372,346
8,434,369
8,246,713
10,260,470
1,240,806
54,396
5,892,615
700,000
1,100,000
10,864,472
57,380,408
79,050
43,003
103,351
14,683
107,366
71,941
127,130
547,135
8,988
169,813
122,993
34,953
6,888
5,155
24,473
151,324
573,449
1,703,917
2,117,577
3,506,762
233,257
10,516
150,836
237,028
2,341,079
12,492,669
189,850
103,279
248,213
35,264
257,857
172,779
305,323
1,314,035
22,535
417,365
295,354
83,937
5,368
4,155
51,323
216,674
878,234
3,679,657
2,905,411
4,551,536
565,856
19,353
362,258
569,262
5,622,484
22,877,361
97,953
53,287
128,065
18,195
133,041
89,145
810,821
157,531
677,974
11,637
215,439
152,386
43,306
2,770
2,144
27,395
251,575
920,664
3,050,794
3,223,724
2,202,173
441,693
24,527
5,892,615
186,906
293,710
2,900,909
22,010,378
108
12664
Building Services
Building Maintenance
Total
Total Dir Labor
3,109,354
3,109,354
670,004
670,004
1,609,125
1,609,125
830,225
830,225
310
22701
22703
22704
22705
22706
22708
22709
22710
22711
22712
22713
22714
22716
22719
22720
22721
22725
22727
23003
23006
25006
25011
25014
25015
25017
Enterprise Risk Mgmnt - Admin
Bus Cont Pl Prog Admin & Support
Record Retention Services
Corporate Scorecard
Document Management Services
Adminstration
Management
Employee Development
Forward Capacity Market (FCM) Cap Adjustments
Risk Policy Assessments
MEC/Financials
Analysis
Financial Assurance Management (FAM) Rebuild
Human Performance Improvement
Business Process Change Management
Corp Strategic Risk
OSHA procedures
ERM Business Analysis
Safety / Security / Facilities
Business Continuity Planning
Business Process Maintenance
Corrective Action/Preventive Action
EtQ Tools Dev & Support
Coord Tariff Change Committee (TCC)
Scorecard Operational Excellence Excercise -- I.3.9 Process
Total
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
Total Dir Labor
Total Dir Labor
Total Dir Labor
Total Dir Labor
Total Dir Labor
Total Dir Labor
Total Dir Labor
Total Dir Labor
Total Dir Labor
Total Dir Labor
Total Dir Labor
Total Dir Labor
Total Dir Labor
Total Dir Labor
Total Dir Labor
Alloc-Fixed
Alloc-Fixed
Total Dir Labor
Total Dir Labor
Total Dir Labor
2,282
141,205
80,512
31,379
109,826
15,689
94,137
15,689
21,509
15,689
31,379
125,515
109,826
9,894
125,515
23,534
15,689
62,758
78,447
47,068
19,625
179,175
106,530
54,117
31,379
1,548,371
760
47,021
26,810
10,449
43,930
3,381
20,285
3,381
4,635
3,381
6,762
27,046
23,665
2,132
27,046
5,071
3,381
13,523
16,904
10,142
8,831
59,665
22,955
11,661
6,762
409,579
760
47,021
26,810
10,449
32,948
8,119
48,717
8,119
11,131
8,119
16,239
64,956
56,836
5,120
64,956
12,179
8,119
32,478
40,597
24,358
8,831
59,665
55,131
28,006
16,239
695,906
762
47,162
26,891
10,481
32,948
4,189
25,135
4,189
5,743
4,189
8,378
33,514
29,325
2,642
33,514
6,284
4,189
16,757
20,946
12,568
1,963
59,845
28,444
14,450
8,378
442,885
No.
(a)
(2) Provided by ISO-NE.
Self-Funding Tariff
Schedule 1
Schedule 2
(e)
(f)
Total (2)
(d)
$
8,127,546
14,971
10,926
981,729
9,135,171
$
1,751,325
3,226
2,354
211,543
1,968,449
$
4,206,094
7,748
5,654
508,056
4,727,551
Schedule 3
(g)
$
2,170,126
3,997
2,917
262,130
2,439,171
Exhibit 3 (RCL-3)
Schedule 3.0
Page 2 of 7
TEST YEAR 2016
Line
No.
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47
48
49
50
51
52
53
54
55
56
57
58
59
60
61
62
63
64
65
66
67
68
69
70
71
72
73
74
75
76
Activity Code
Description
(b)
No.
(a)
Allocation
Factor (1)
(c)
Total (2)
(d)
Self-Funding Tariff
Schedule 1
Schedule 2
(e)
(f)
Schedule 3
(g)
301
12661
12701
12801
12901
12951
12961
12962
13410
13411
13412
13413
13414
Human Resources
Employee Affairs (Recreation Committee)
Recruiting/Interviewing
Employee Relations
Benefit Administration
Compensation
HR - General
HR - Training
Power Training & Development
Markets Training & Development
People Training & Development
Business Skills Trng & Dev
Technology Trng & Development
Total
Total Dir Labor
Total Dir Labor
Total Dir Labor
Total Dir Labor
Total Dir Labor
Total Dir Labor
Total Dir Labor
Total Dir Labor
Total Dir Labor
Total Dir Labor
Total Dir Labor
Total Dir Labor
21,821
553,457
8,943
1,139,839
501,581
1,124,146
1,049,652
1,176,010
375,057
580,066
167,452
812,849
7,510,873
4,702
119,259
1,927
245,613
108,081
242,231
226,179
253,407
80,817
124,993
36,083
175,153
1,618,445
11,292
286,420
4,628
589,879
259,574
581,758
543,206
608,598
194,096
300,191
86,658
420,658
3,886,959
5,826
147,778
2,388
304,347
133,927
300,157
280,266
314,005
100,144
154,883
44,711
217,038
2,005,469
306
8301
12426
12502
12504
12505
12508
12509
12512
12513
12514
12517
12520
12521
12523
12542
12543
12544
12552
12559
12563
12572
12573
12574
12587
12588
12594
12595
12609
12663
12669
Legal Department
Federal Regulatory
Interconnection Agreements
Board of Directors
ISO Tariff Litigation
Administration of OATT (Open Access Transmission Tariff)
Energy Markets / Complaints / Rule Changes
Market Monitoring and Sanctions
BSAI - General Corporate
Miscellaneous Labor Matters
NEPOOL Participants Committee
Administrative and Clerical Support
Market Monitoring Rules/Regulations
Billing Disputes
NEPOOL Information Policy
Transmission Upgrades CT
Independent Market Advisor
FERC Proceedings
S&G - General Corporate
General Corporate
Regulatory Matters
205 General Proceedings
Market Rule 1 Proceedings
Capacity Market Development
Web Content Management
Maine Transmission Siting
NEEWS Transmission Siting
FTR Clearing
Public Information
Government Affairs
Total
Total Dir Labor
Alloc-Fixed
Total Dir Labor
Total Dir Labor
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
Total Dir Labor
Total Dir Labor
Total Dir Labor
Total Dir Labor
Alloc-Fixed
Total Dir Labor
Total Dir Labor
Alloc-Fixed
Alloc-Fixed
Total Dir Labor
Total Dir Labor
Total Dir Labor
Total Dir Labor
Total Dir Labor
Total Dir Labor
Total Dir Labor
Alloc-Fixed
Total Dir Labor
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
Total Dir Labor
Total Dir Labor
265,674
29,038
448,228
72,595
339,894
58,076
87,114
80,002
120,003
100,674
450,091
290,381
126,291
36,298
29,992
900,000
209,877
234,992
901,039
49,992
29,992
29,992
479,994
509,797
571,803
35,005
1,370
60,002
1,393,147
1,719,920
9,661,273
57,247
96,584
15,643
339,894
17,239
25,858
21,693
96,986
27,213
7,821
45,224
50,636
194,156
10,772
6,463
6,463
103,429
123,212
300,196
370,609
1,917,340
137,489
14,519
231,963
37,569
58,076
43,557
41,402
62,103
52,100
232,927
116,152
65,357
18,784
20,994
630,000
108,614
121,611
466,298
25,872
15,521
15,521
248,402
295,914
24,504
959
30,001
720,969
890,078
4,727,255
70,937
14,519
119,681
19,384
43,557
21,361
32,042
26,881
120,178
174,229
33,721
9,692
8,998
270,000
56,039
62,745
240,585
13,348
8,008
8,008
128,163
509,797
152,676
10,502
411
30,001
371,983
459,234
3,016,678
305
15001
15002
15003
15004
15005
15006
15007
15008
15020
15021
15022
15023
15031
15040
15065
15085
15131
15133
15134
15161
15162
15166
15175
15186
25702
28160
Internal Audit
Indirect Management Duties
Personnel Management
Budget & Forecasting
Audit Follow-up Activities
Audit & Finance Committee
Internal Audit Business Process Update
Annual Audit Work Plan
Training
Internal Audit - Finance
Perfomance Measurements
Vendor Contracts
Wire Transfers
Employee Expense Reporting
Operations
Wind Integration Project
Information Technology
NAMS Support
Satellite Reviews
SCADA Operations Reviews
External Audit- Pension Audit
External Audit- Financial Audit
External Audit -Pricing Module Certification
External Audit - Info Technology
External Audit - SSAE 16 Direct Support
External Audit - SSAE 16
MS Universal Access Gateway Review
Total
Total Dir Labor
Total Dir Labor
Total Dir Labor
Total Dir Labor
Total Dir Labor
Total Dir Labor
Total Dir Labor
Total Dir Labor
Total Dir Labor
Total Dir Labor
Total Dir Labor
Total Dir Labor
Total Dir Labor
Total Dir Labor
Alloc-Fixed
Total Dir Labor
Total Dir Labor
Total Dir Labor
Total Dir Labor
Total Dir Labor
Total Dir Labor
Alloc-Fixed
Total Dir Labor
Total Dir Labor
Alloc-Fixed
Total Dir Labor
126,067
19,659
14,744
68,805
62,564
5,898
34,402
39,317
26,688
24,573
9,829
11,795
11,795
98,293
49,146
336,697
4,915
70,704
72,422
62,251
110,352
25,168
15,488
24,573
458,064
42,906
1,827,115
27,165
4,236
3,177
14,826
13,481
1,271
7,413
8,472
5,751
5,295
2,118
2,542
2,542
21,180
19,659
72,552
1,059
15,235
15,605
13,414
23,779
3,337
5,295
9,245
298,649
65,241
10,174
7,630
35,607
32,378
3,052
17,804
20,347
13,811
12,717
5,087
6,104
6,104
50,868
19,659
174,245
2,543
36,590
37,479
32,215
57,108
25,168
8,015
12,717
458,064
22,204
1,172,931
33,661
5,249
3,937
18,371
16,705
1,575
9,186
10,498
7,126
6,561
2,624
3,149
3,149
26,245
9,829
89,901
1,312
18,879
19,337
16,621
29,465
4,135
6,561
11,456
355,535
Exhibit 3 (RCL-3)
Schedule 3.0
Page 3 of 7
TEST YEAR 2016
Line
No.
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47
48
49
50
51
52
53
54
55
56
57
58
59
60
61
62
63
64
65
66
67
68
69
70
71
72
73
74
75
76
Activity Code
Description
(b)
No.
(a)
Allocation
Factor (1)
(c)
701
19001
19002
19003
19005
19009
COO-Adm
Regional Committee Support
Indirect Supervision/Clerical Support
Renewable Resource Integration
Total
Total OPS Labor
Total OPS Labor
Total OPS Labor
Total OPS Labor
Alloc-Fixed
105
14404
14405
14407
14408
Total
101
14001
14002
14304
14402
14413
14564
14702
Total (2)
(d)
Self-Funding Tariff
Schedule 1
Schedule 2
(e)
(f)
Schedule 3
(g)
57,751
31,400
57,656
1,284,522
114,197
1,545,526
15,478
8,416
15,453
344,271
383,618
27,693
15,057
27,648
615,973
686,372
14,579
7,927
14,555
324,278
114,197
475,537
SOA Labor
SOA Labor
SOA Labor
SOA Labor
12,256
350,021
12,256
39,692
414,226
4,233
120,897
4,233
13,710
143,074
5,689
162,480
5,689
18,425
192,284
2,334
66,644
2,334
7,557
78,869
Operations
Generation Dispatch
Transmission Operations
Advanced Scheduling and Forecasting
Operations Training
Operations Support Training & Development
Procedure Documentation
Total
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
OPS Labor
Alloc-Fixed
3,880,735
3,326,344
1,669,702
1,139,161
269,900
1,387,703
536,178
12,209,722
2,661,075
83,485
455,665
107,960
387,955
214,471
3,910,611
3,259,817
166,317
1,319,065
455,665
107,960
768,284
214,471
6,291,578
620,918
498,952
267,152
227,832
53,980
231,464
107,236
2,007,533
702
14703
14706
14711
14715
14813
ISO TMS Tariff - Section 2 - (OATT) and Agreements Support
Non DOE Funded/Unallowable
ICP Policy/Procedure
Total
OS Labor
OS Labor
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
440,571
21,933
207,354
216,552
98,411
984,821
244,723
12,183
69,049
39,364
365,320
85,173
4,240
69,049
39,364
197,826
110,675
5,510
69,256
216,552
19,682
421,675
703
14801
14803
14804
14806
14808
14809
14810
14812
14814
14815
Compliance Monitoring
Change Management
Tariff Compliance
NERC Self Certifications
NPCC MP Referral
Compliance Risk Assessment
Identifications and Description of Internal Controls
Total
Alloc-Fixed
OS Labor
OS Labor
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
Total Dir Labor
Total Dir Labor
659,625
18,140
146,408
9,841
49,205
49,205
98,411
19,682
19,682
196,822
1,267,021
263,850
9,070
73,204
5,466
22,142
14,762
83,649
7,873
4,242
42,415
526,673
263,850
1,903
4,921
29,523
7,873
10,186
101,855
420,110
131,925
9,070
73,204
2,472
22,142
4,921
14,762
3,936
5,255
52,551
320,239
103
14301
14452
14453
14454
14462
14476
18361
18381
18382
Contract Administration and Scheduling
General Systems Operations Support
Process Automation for On-Call Support of Control Room
Transmission Studies, Operations, OASIS Support
Transmission Outage Appl - Short Term
Trans Out Ap Lg Term
Total
Alloc-Fixed
TSO Labor
TSO Labor
TSO Labor
TSO Labor
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
(60,000)
9,665
127,286
493,763
134,044
270,626
2,400,403
1,082,505
1,089,030
5,547,323
(6,000)
3,129
41,208
159,852
43,396
270,626
1,920,323
866,004
3,298,538
(42,000)
4,621
60,853
236,061
64,085
120,020
54,125
497,765
(12,000)
1,915
25,224
97,850
26,564
360,060
162,376
1,089,030
1,751,020
C10/C30 Audits Resource Performance Monitoring NEPOOL Committee Support
Winter Reliability Project
Total
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
134,044
134,044
134,044
12,560
134,044
224,962
773,699
43,396
4,066
43,396
90,858
107,236
107,236
64,085
6,005
64,085
44,992
393,637
26,809
26,809
26,564
2,489
26,564
179,969
289,204
Settlements - Customer Service
CEII Requests
Total
MOA Labor
MOA Labor
MOA Labor
MOA Labor
MOA Labor
Total Dir Labor
33,475
14,021
937,732
6,471
18,003
25,885
1,035,587
5,578
5,578
23,433
9,815
656,412
4,530
12,602
13,396
720,187
10,043
4,206
281,319
1,941
5,401
6,911
309,822
14469
14470
14750
14751
14753
14757
415
19101
19103
19104
19105
19112
19120
Exhibit 3 (RCL-3)
Schedule 3.0
Page 4 of 7
TEST YEAR 2016
Line
No.
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47
48
49
50
51
52
53
54
55
56
57
58
59
60
61
62
63
64
65
66
67
68
69
70
Activity Code
Description
(b)
No.
(a)
404
16101
16102
16111
16114
16115
16121
Market Monitoring
Market Power Monitoring and Mitigation
Regulatory Activities
Maintenance / Troubleshooting Software
Analysis & Internal Reports
FCM Market Monitoring
Total
416
21901
21902
21904
21907
21908
21913
21915
21916
21917
21951
21953
401
1701
1702
1713
1714
2039
2047
2048
2049
2051
2052
2054
2005
2007
2008
2009
2010
2013
2014
2020
2021
2022
2024
2025
2026
2030
2032
2033
3000
3002
3003
3004
3005
3006
3007
3008
3009
3010
3011
3012
3013
3014
3015
Allocation
Factor (1)
(c)
Total (2)
(d)
Self-Funding Tariff
Schedule 1
Schedule 2
(e)
(f)
Schedule 3
(g)
Alloc-Fixed
Alloc-Fixed
MMM Labor
MMM Labor
MMM Labor
Alloc-Fixed
3,591,744
365,402
254,824
761
232,458
219,822
4,665,011
-
2,514,220
255,781
178,377
533
162,720
3,111,632
1,077,523
109,621
76,447
228
69,737
219,822
1,553,379
Market Operations
Day Ahead Market Administration
Real Time Price Verification
Data Collection/Report Writing
FTR/Auction Administration
Forward Reserve Market - Administration
Real Time Price Finalization
FCM Annual Reconfiguration Auction Administration
FCM Monthly Administration
Total
Alloc-Fixed
Alloc-Fixed
MA Labor
MA Labor
MA Labor
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
345,499
345,499
4,551
456,984
33,707
337,072
303,365
33,707
176,963
33,707
176,963
2,248,016
-
345,499
345,499
4,407
442,553
32,643
337,072
303,365
176,963
1,988,000
144
14,431
1,064
33,707
33,707
176,963
260,016
Billing Statements - Energy
Billing Statements - Transmission
Billing Statements - ISO Tariff
Billable Tariff Re-billings
BITT and Business Tools
Score Card
FCM
Product Testing
Legal Support
FERC Data Request
MAS - Markets Development Support
Customer Service
Admin support - NEPOOL Committees
Admin support (ISO)
FTR Administration
Billing Statements - NCPC
Billing Disputes
Analysis & Reporting
Demand Response
ASM Regulation
ASM Locational Forward Reserve
Batch Processing
ARR Administration
Billing
Market Analysis
Total
Alloc-Fixed
Alloc-Fixed
Total Dir Labor
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
STLM Labor
STLM Labor
STLM Labor
STLM Labor
STLM Labor
Alloc-Fixed
Alloc-Fixed
Total Dir Labor
Total Dir Labor
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
Total Dir Labor
Alloc-Fixed
STLM Labor
Alloc-Fixed
87,109
72,682
23,955
72,410
2,178
10,616
211,240
21,777
23,138
544
2,994
119,775
16,877
77,966
790,516
107,798
24,772
258,878
12,522
241,728
7,078
31,577
111,881
32,122
2,450
59,888
184,563
2,609,034
72,682
5,162
72,410
327
1,570
17,712
2,496
11,530
116,902
15,941
2,698
52,088
6,922
8,856
387,294
87,109
12,397
1,307
5,171
17,422
11,569
272
1,497
58,347
8,222
37,980
385,090
52,512
24,772
129,439
6,480
125,097
16,623
2,205
29,173
184,563
1,197,248
6,396
544
3,875
211,240
4,355
11,569
272
1,497
43,716
6,160
28,456
288,525
39,344
129,439
3,343
64,544
7,078
31,577
111,881
8,577
245
21,858
1,024,492
Monthly Settlements Support
Market Analysis Support
Generation & Load Admin Support
Demand Resource Admin Support
Customer Service
NEPOOL Committees Support
Admin Support
Indirect Supervision (Principal Analysts only)
Release Checkout and Support
FERC Data Request
Tariff Change Coordination (TCC)
Markets Development Support
Market Administration Support
Total
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
Total Dir Labor
Alloc-Fixed
Alloc-Fixed
263,183
108,370
774
193,982
97,533
154,814
2,632
57,281
86,696
15,791
1,858
44,896
155
10,063
1,084
1,039,110
54,185
33
54,218
131,592
774
193,982
97,533
154,814
1,316
57,281
86,696
15,791
1,858
44,896
80
5,031
1,084
792,726
131,592
54,185
1,316
41
5,031
192,165
Exhibit 3 (RCL-3)
Schedule 3.0
Page 5 of 7
TEST YEAR 2016
Line
No.
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47
48
49
50
51
52
53
54
55
56
57
58
59
60
61
62
63
64
65
66
67
68
69
70
71
72
73
74
Activity Code
Description
(b)
No.
(a)
Allocation
Factor (1)
(c)
Total (2)
(d)
406
16001
16006
16404
16414
16419
16420
16422
16424
16425
16429
16434
16435
Market Services
Participant/membership support
Call Support (Ask ISO)
Direct Customer Contact
Asset Registration Implemented
Asset Registration Review
Claimed Capability Audits
Demand Resource Audits
DR Registration Implemented
Business Analysis - Process Improvement
QMS/CAPA Process and Procedure Updates
Resource Performance Monitoring
Total
410
16021
16024
16433
Training Development
Training Delivery
Passive Resource Performance and M&V Review
Total
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
203
14313
14315
17101
17131
17231
17241
17251
17331
17361
17401
17402
17403
17405
17406
17408
17501
17502
17503
17504
17505
17507
17508
18101
18121
18131
Resource Adequacy
Analysis
Calculate Objective Capability
Regulatory Filings
Transmission Plan Admin Support
Regional Bulk Power System Assessment
Indirect Supervisory Activities
Project Management
TCA Application Review
Energy Efficiency Forecast
North American Energy Standards Board (NAESB)
MA-EEAC
FCA - Evaluate Existing Resource De-list Bids
FCA - Preliminary Review of Show of Interest Applications
FCA - New Resource Qualification Support
FCA - Perform Transmission / Topology Assessments
FCA - Perform Existing Resource Qualification
FCA - Auctions & Filings
FCA - Annual Reconfiguration Auction Support/Reliability Reviews
Develop Load Forecast
Operations Forecast Support
Other Load Forecasting Activities
Total
PSR Labor
PSR Labor
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
PSR Labor
PSR Labor
PSR Labor
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
Total Dir Labor
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
41,007
139,271
709,940
317,359
33,807
33,807
304,260
105,953
35,140
169,953
236,647
70,857
67,613
36,873
36,873
73,097
140,710
295,797
101,420
208,323
809,626
73,097
315,198
67,613
33,807
4,458,046
204
18150
18152
18401
18501
18521
18531
System Planning
Regional Transmission Expansion Plan
States Requests
Regional Activities
Total
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
SP Labor
SP Labor
205
11201
18201
18261
18301
18331
18333
18334
18335
18336
18337
18338
18341
18343
18344
System Design Task Force
Transmission System Assessment
Transmission Tariff Information Requirements
NEPOOL Administrative Support - Schedule 1 Tariff
SIS Preparatory Arrangements
General SIS/FS
Regulatory Activities - NPCC
National Activities
NERC Compliance
FERC Order 1000
Transmission Planning Siting Support
Total
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
TP Labor
TP Labor
TP Labor
TP Labor
TP Labor
TP Labor
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
MS Labor
MS Labor
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
Total Dir Labor
Alloc-Fixed
65,096
853,752
86,134
159,795
244,377
210,670
33,707
185,390
33,707
155
252,804
33,707
2,159,294
Self-Funding Tariff
Schedule 1
Schedule 2
(e)
(f)
32,548
563,477
77,521
143,815
244,377
210,670
33,707
185,390
33,707
139
130,826
33,707
1,689,884
32,548
68,300
8,613
15,979
15
67,499
192,955
429,184
4,083
33,707
466,975
429,184
4,083
433,267
4,456
15,133
16,903
152,130
11,513
3,818
18,467
236,647
7,946
63,040
13,523
6,761
550,337
2,069
7,028
496,958
16,903
152,130
5,347
1,773
8,577
18,437
19,082
63,040
13,523
6,761
811,628
34,482
117,110
212,982
317,359
33,807
89,094
29,548
142,909
70,857
67,613
18,437
9,845
73,097
140,710
295,797
101,420
208,323
809,626
73,097
189,119
40,568
20,284
3,096,081
887,395
149,323
11,245
17,158
2,024
161,485
1,228,630
665,546
74,661
11,245
17,158
502
40,091
809,204
221,849
37,331
359
28,629
288,168
37,331
1,163
92,765
131,258
3,524
3,469,289
9,758
76,625
3,524
655,879
366,454
99,979
78,398
109,597
116,462
11,717
319,257
6,233
5,326,697
3,524
3,469,289
9,758
76,625
3,524
655,879
366,454
99,979
78,398
109,597
116,462
11,717
5,001,206
858,368
8,166
33,707
900,242
221,976
54,479
276,455
Schedule 3
(g)
-
-
319,257
6,233
325,490
Exhibit 3 (RCL-3)
Schedule 3.0
Page 6 of 7
TEST YEAR 2016
Line
No.
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47
48
49
50
51
52
53
54
55
56
57
58
59
60
61
62
63
64
65
66
67
68
Activity Code
Description
(b)
No.
(a)
Allocation
Factor (1)
(c)
Total (2)
(d)
Self-Funding Tariff
Schedule 1
Schedule 2
(e)
(f)
Schedule 3
(g)
304
801
1661
25002
25902
25914
25919
25926
25938
25940
25943
25953
Program Management
Program Management - Administration
ISO Program Management
PMO Support
Coordinated Transaction Scheduling - O&M
Divisional Accounting (for Market Participants)
Alternative Technologies & Regulation Market
Hourly Market
Asset Registration Automation
Non-Reimburseable Smart Grid SIDU Observation Period
Submission of FTRs for Clearing
ICCP and ED Network Upgrades
Total
Total Dir Labor
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
Total Dir Labor
Alloc-Fixed
Alloc-Fixed
Total Dir Labor
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
824,303
342,618
16,548
116,869
66,825
39,711
154,814
16,720
90,029
33,856
95,782
1,798,076
177,621
4,964
81,808
14,400
61,925
3,603
13,504
86,204
444,030
426,586
239,833
5,792
35,061
34,583
46,444
8,653
13,504
810,455
220,096
102,785
5,792
17,843
39,711
46,444
4,464
63,021
33,856
9,578
543,591
315
21201
21203
Total
Total Dir Labor
Total Dir Labor
2,246,284
49,100
2,295,384
484,030
10,580
494,610
1,162,477
25,410
1,187,887
599,778
13,110
612,888
408
21001
21002
21003
21007
21009
22656
Market Development
Market Development
Administration
Budget/Forecast Support
Increased Scope of Impact Analysis
Energy, Reserve, and Regulation Markets
Total
Total Dir Labor
Total Dir Labor
Total Dir Labor
Total Dir Labor
Alloc-Fixed
Alloc-Fixed
2,128,297
183,849
13,780
61,283
99,999
765,429
3,252,636
458,606
39,616
2,969
13,205
26,000
540,396
1,101,417
95,144
7,131
31,715
65,999
574,072
1,875,478
568,274
49,089
3,679
16,363
8,000
191,357
836,763
407
22602
22607
NEPOOL Committee Meetings & Support
NEPOOL Markets Committee Administration
Total
Alloc-Fixed
Total Dir Labor
619,376
121,485
740,862
26,178
26,178
309,688
62,870
372,558
309,688
32,438
342,126
409
22401
22402
22404
Administration
Working Group Meetings and Support
Price Responsive Demand
Total
Total Dir Labor
Total Dir Labor
Alloc-Fixed
87,011
21,899
179,796
288,706
18,749
4,719
23,468
45,029
11,333
143,837
200,199
23,233
5,847
35,959
65,039
210
6517
6519
6552
6556
6557
22501
22505
IT Management
Employee Development - Hardware/Software
Indirect Supervision and Clerical Support
Security
Budget Preparation, Tracking & Forecast
Information Technology Committee
Change Management Support
Administrative
Total
Total Dir Labor
Total Dir Labor
Total Dir Labor
Total Dir Labor
Total Dir Labor
Alloc-Fixed
Alloc-Fixed
95,555
3,118,865
405,253
145,731
18,277
187,538
352,172
4,323,391
20,590
672,054
87,324
31,402
3,938
84,392
119,738
1,019,439
49,451
1,614,047
209,723
75,417
9,459
84,392
116,217
2,158,705
25,514
832,764
108,206
38,911
4,880
18,754
116,217
1,145,247
Desktop Support - Hardware
Desktop Support - Software
Networking - Hardware
Communications
Data Communications Support
Help Desk Support
Host Computer Monitoring
Desktop Support
System Administration - Unix
System Administration - Windows
Systems Support Misc
Systems Support - Security
Network Support
Network/Systems Compliance
Asset Management
Total
Total Dir Labor
Total Dir Labor
Alloc-Fixed
Alloc-Fixed
Total Dir Labor
Total Dir Labor
Total Dir Labor
Total Dir Labor
Alloc-Fixed
Total Dir Labor
Total Dir Labor
Total Dir Labor
Total Dir Labor
Total Dir Labor
Total Dir Labor
Total Dir Labor
Total Dir Labor
399,247
796,785
1,146,315
1,763,842
816,849
1,678,847
270,398
335,290
1,254,513
499,800
678,400
838,710
85,170
245,577
415,081
11,019
421,020
11,656,862
86,030
171,691
176,015
361,758
58,265
72,248
107,697
146,182
180,725
18,352
52,917
89,442
2,374
90,721
1,614,419
206,615
412,345
859,736
1,322,882
422,728
868,822
139,934
173,516
627,257
258,652
351,079
434,042
44,076
127,089
214,809
5,703
217,882
6,687,166
106,602
212,749
286,579
440,961
218,106
448,267
72,199
89,525
627,257
133,451
181,139
223,943
22,741
65,571
110,830
2,942
112,416
3,355,277
201
6510
6511
6512
6513
6514
6516
6550
6602
6615
6616
6617
6618
6619
6620
6621
6622
6623
Exhibit 3 (RCL-3)
Schedule 3.0
Page 7 of 7
TEST YEAR 2016
Line
No.
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47
48
49
50
51
52
53
54
55
56
57
58
59
60
61
62
63
64
65
66
67
68
69
70
Activity Code
Description
(b)
No.
(a)
Allocation
Factor (1)
(c)
Self-Funding Tariff
Schedule 1
Schedule 2
(e)
(f)
Total (2)
(d)
Schedule 3
(g)
212
6539
6540
6540A
6540B
6540D
6540E
6541
6543
6544
6546
6547
6548
IT Cyber Security
Policy/Procedures Program
Controls Assessment
Virus/Malware Reporting and Response
Intrusion Monitoring and Response
System Compliance Enhancement
Critical Infrastructure Protection WG (NERC)
Infragrad (FBI)
Internal Audit Support
Security Training
CIP Compliance & Monitoring
Total
Total Dir Labor
Total Dir Labor
Total Dir Labor
Total Dir Labor
Total Dir Labor
Total Dir Labor
Total Dir Labor
Total Dir Labor
Total Dir Labor
Total Dir Labor
Total Dir Labor
Total Dir Labor
55,939
2,169,684
39,245
19,622
98,111
156,978
333,579
6,677
97,632
19,622
19,622
212,070
3,228,782
12,054
467,524
8,456
4,228
21,141
33,826
71,880
1,439
21,038
4,228
4,228
45,697
695,739
28,949
1,122,835
20,310
10,155
50,774
81,238
172,631
3,455
50,526
10,155
10,155
109,748
1,670,930
14,936
579,325
10,479
5,239
26,197
41,915
89,069
1,783
26,069
5,239
5,239
56,625
862,113
211
6571
6591
6594
6595
6596
21706
21801
21802
21803
21804
21805
21806
21807
21808
21809
21811
21816
21818
21819
21821
DBA Support - MOPS
Data Architect - MOPS
IT Data Analyst
IT Data Governance
IT Markets Software Development - Enterprise
Software Support - Settlements
Software Support - Publishing
Software Support - Finance
Software Support - Mitigation
Software Support - TSO
Software Support - Enterprise
Software Support - Planning
Training Delivery to NON-IT
Tools
Single Sign On Support
CMS Support
Discoverer Support
Ceridian Support
Compliance Management
Total
Total Dir Labor
Total Dir Labor
Total Dir Labor
Total Dir Labor
Total Dir Labor
Total Dir Labor
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
Total Dir Labor
Total Dir Labor
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
Total Dir Labor
Total Dir Labor
Total Dir Labor
Total Dir Labor
2,396,535
256,136
265,629
722,943
150,067
439,846
554,480
258,139
255,909
451,110
352,451
1,001,874
475,646
330,952
144,875
79,608
212,483
103,576
79,608
53,072
8,584,936
516,406
55,192
57,238
155,780
32,336
94,778
75,946
215,884
45,786
22,319
17,154
11,436
1,300,255
1,240,233
132,553
137,466
374,131
77,661
227,625
443,584
206,512
204,727
360,888
182,397
518,481
380,517
264,762
115,900
63,686
109,962
53,602
41,198
27,465
5,163,349
639,896
68,391
70,925
193,032
40,069
117,443
110,896
51,628
51,182
90,222
94,107
267,509
95,129
66,190
28,975
15,922
56,735
27,656
21,256
14,171
2,121,333
102
21600
21601
21603
21604
21605
21606
21607
Indirect Supervision and Administration
Power System Modeling
Applications Support
DTS Support
DAM Support
Real-time Market Support
Forecast Support
Total
Total Dir Labor
Total Dir Labor
Total Dir Labor
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
361,281
29,012
607,099
1,544,494
1,000,980
2,092,680
101,360
5,736,905
77,849
6,251
130,818
1,235,595
200,196
418,536
20,272
2,089,517
186,967
15,014
314,180
308,899
600,588
1,255,608
60,816
2,742,072
96,465
7,746
162,101
200,196
418,536
20,272
905,316
213
6518
21702
21707
21709
21710
21711
Employee Development - Software
IT Corporate Application Support
Technology Evaluation and Selection
EWR and CAPA Analysis
Total
Total Dir Labor
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
18,375
75,435
1,074,003
17,788
531,681
171,124
1,888,404
3,960
3,960
9,509
15,087
859,202
14,230
425,344
136,899
1,460,272
4,906
60,348
214,801
3,558
106,336
34,225
424,173
216
21650
21651
21652
21654
21655
21656
21657
21658
System Application Support
NX9 Administration
ICCP Support
Transmission Project Management
Model On Demand Admin
Model on Demand Case Requests
Total
Total Dir Labor
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
111,703
861,609
176,841
481,016
698,834
23,590
340,984
77,129
2,771,706
24,072
344,643
70,737
192,406
279,534
18,872
930,264
57,806
344,643
70,737
192,406
279,534
4,718
949,844
29,825
172,322
35,368
96,203
139,767
340,984
77,129
891,598
Total ISO
$ 185,151,221
$
44,360,392
$
84,722,023
$
56,068,806
Exhibit 3 (RCL-3)
Schedule 4.0
Page 1 of 9
DIRECT LABOR COST ALLOCATIONS TO SCHEDULES BY COST CATEGORY
TEST YEAR 2016
Line
No.
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47
48
49
50
51
52
53
54
55
56
57
58
59
60
Activity Code
Description
(b)
No.
(a)
Allocation
Factor (1)
(c)
Self-Funding Tariff
Schedule 1
Schedule 2
(e)
(f)
Total (2)
(d)
Schedule 3
(g)
307
12651
Administration-CEO
Total
302
11601
11701
11702
11901
12001
12005
12017
12101
12201
99998
Finance
Accounts Payable
Procurement
Total
Total Dir Labor
Total Dir Labor
Total Dir Labor
Total Dir Labor
Total Dir Labor
Total Dir Labor
Alloc-Fixed
Total Dir Labor
Total Dir Labor
Total Dir Labor
225,939
199,569
479,629
68,142
498,264
189,500
810,821
589,983
135,994
10,864,472
14,062,314
48,685
43,003
103,351
14,683
107,366
40,834
127,130
29,304
2,341,079
2,855,435
116,926
103,279
248,213
35,264
257,857
98,068
305,323
70,378
5,622,484
6,857,793
60,328
53,287
128,065
18,195
133,041
50,598
810,821
157,531
36,312
2,900,909
4,349,086
108
12664
Building Services
Total
Total Dir Labor
585,812
585,812
126,231
126,231
303,164
303,164
156,417
156,417
310
22703
22704
22705
22706
22708
22709
22710
22711
22712
22713
22714
22716
22720
22721
22725
22727
23003
23006
25006
25011
25014
25015
25017
Corporate Scorecard
Adminstration
Management
MEC/Financials
Analysis
Corp Strategic Risk
OSHA procedures
Total
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
Total Dir Labor
Total Dir Labor
Total Dir Labor
Total Dir Labor
Total Dir Labor
Total Dir Labor
Total Dir Labor
Total Dir Labor
Total Dir Labor
Total Dir Labor
Total Dir Labor
Total Dir Labor
Total Dir Labor
Total Dir Labor
Alloc-Fixed
Alloc-Fixed
Total Dir Labor
Total Dir Labor
Total Dir Labor
141,205
62,758
31,379
109,826
15,689
94,137
15,689
15,689
15,689
31,379
125,515
109,826
125,515
23,534
15,689
62,758
78,447
47,068
19,625
179,175
78,447
54,117
31,379
1,484,538
47,021
20,898
10,449
43,930
3,381
20,285
3,381
3,381
3,381
6,762
27,046
23,665
27,046
5,071
3,381
13,523
16,904
10,142
8,831
59,665
16,904
11,661
6,762
393,470
47,021
20,898
10,449
32,948
8,119
48,717
8,119
8,119
8,119
16,239
64,956
56,836
64,956
12,179
8,119
32,478
40,597
24,358
8,831
59,665
40,597
28,006
16,239
666,569
47,162
20,961
10,481
32,948
4,189
25,135
4,189
4,189
4,189
8,378
33,514
29,325
33,514
6,284
4,189
16,757
20,946
12,568
1,963
59,845
20,946
14,450
8,378
424,499
301
12661
12701
12901
12951
12961
12962
13410
13411
13412
13413
13414
Human Resources
Compensation
HR - General
HR - Training
Total
Total Dir Labor
Total Dir Labor
Total Dir Labor
Total Dir Labor
Total Dir Labor
Total Dir Labor
Total Dir Labor
Total Dir Labor
Total Dir Labor
Total Dir Labor
Total Dir Labor
5,713
181,609
207,553
389,163
985,879
778,326
772,560
257,445
234,464
81,731
389,357
4,283,799
1,231
39,133
44,724
83,857
212,437
167,714
166,471
55,474
50,522
17,611
83,899
923,074
2,956
93,985
107,411
201,396
510,203
402,792
399,808
133,230
121,338
42,297
201,496
2,216,913
1,525
48,491
55,419
103,910
263,238
207,820
206,280
68,740
62,604
21,823
103,962
1,143,812
Total Dir Labor
$
3,038,347
3,038,347
$
654,704
654,704
$
1,572,378
1,572,378
$
811,265
811,265
Exhibit 3 (RCL-3)
Schedule 4.0
Page 2 of 9
TEST YEAR 2016
Line
No.
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47
48
49
50
51
52
53
54
55
56
57
58
59
60
61
62
63
64
65
66
67
68
69
70
71
72
Activity Code
Description
(b)
No.
(a)
Allocation
Factor (1)
(c)
Total (2)
(d)
Self-Funding Tariff
Schedule 1
Schedule 2
(e)
(f)
Schedule 3
(g)
306
8301
12426
12502
12504
12505
12508
12509
12514
12517
12520
12521
12523
12544
12559
12587
12588
12663
12669
Legal Department
Federal Regulatory
Board of Directors
Billing Disputes
FERC Proceedings
General Corporate
Public Information
Government Affairs
Total
Total Dir Labor
Alloc-Fixed
Total Dir Labor
Total Dir Labor
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
Total Dir Labor
Total Dir Labor
Alloc-Fixed
Total Dir Labor
Total Dir Labor
Total Dir Labor
Total Dir Labor
Alloc-Fixed
Total Dir Labor
Total Dir Labor
Total Dir Labor
246,824
29,038
145,191
72,595
159,710
58,076
87,114
87,114
450,091
290,381
36,298
36,298
203,267
834,939
508,167
512,409
1,123,240
1,192,745
6,073,496
53,186
31,286
15,643
159,710
18,771
96,986
7,821
7,821
43,800
179,913
110,414
242,036
257,013
1,224,400
127,734
14,519
75,138
37,569
58,076
43,557
45,083
232,927
116,152
18,784
18,784
105,193
432,090
265,177
581,289
617,259
2,789,332
65,904
14,519
38,767
19,384
43,557
23,260
120,178
174,229
9,692
9,692
54,274
222,936
508,167
136,818
299,915
318,473
2,059,765
305
15001
15002
15003
15004
15005
15006
15007
15008
15021
15022
15023
15031
15065
15085
15040
15131
15133
15134
15161
15186
25702
28160
Internal Audit
Training
Vendor Contracts
Wire Transfers
Operations
NAMS Support
Satellite Reviews
Total
Total Dir Labor
Total Dir Labor
Total Dir Labor
Total Dir Labor
Total Dir Labor
Total Dir Labor
Total Dir Labor
Total Dir Labor
Total Dir Labor
Total Dir Labor
Total Dir Labor
Total Dir Labor
Alloc-Fixed
Total Dir Labor
Total Dir Labor
Total Dir Labor
Total Dir Labor
Total Dir Labor
Total Dir Labor
Total Dir Labor
Alloc-Fixed
Total Dir Labor
120,214
19,659
14,744
68,805
62,564
5,898
34,402
39,317
24,573
9,829
11,795
11,795
49,146
196,585
98,293
4,915
68,805
68,805
19,659
24,573
118,164
42,906
1,115,445
25,904
4,236
3,177
14,826
13,481
1,271
7,413
8,472
5,295
2,118
2,542
2,542
19,659
42,360
21,180
1,059
14,826
14,826
4,236
5,295
9,245
223,963
62,212
10,174
7,630
35,607
32,378
3,052
17,804
20,347
12,717
5,087
6,104
6,104
19,659
101,735
50,868
2,543
35,607
35,607
10,174
12,717
118,164
22,204
628,493
32,098
5,249
3,937
18,371
16,705
1,575
9,186
10,498
6,561
2,624
3,149
3,149
9,829
52,490
26,245
1,312
18,371
18,371
5,249
6,561
11,456
262,990
701
19001
19002
19003
19005
COO-Adm
Total
Total OPS Labor
Total OPS Labor
Total OPS Labor
Total OPS Labor
56,741
28,370
28,370
1,106,444
1,219,926
15,207
7,604
7,604
296,544
326,958
27,209
13,605
13,605
530,578
584,997
14,324
7,162
7,162
279,322
307,970
702
14703
14706
14711
14715
Total
OS Labor
OS Labor
Alloc-Fixed
Alloc-Fixed
434,972
21,933
207,354
161,608
825,867
241,613
12,183
69,049
322,845
84,090
4,240
69,049
157,380
109,268
5,510
69,256
161,608
345,642
703
14801
14804
14806
14808
14809
14810
14812
14813
14814
14815
Change Management
Tariff Compliance
NPCC MP Referral
Total
Alloc-Fixed
OS Labor
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
Total Dir Labor
Total Dir Labor
580,185
136,288
9,841
49,205
49,205
98,411
19,682
98,411
19,682
196,822
1,257,732
232,074
68,144
5,466
22,142
14,762
83,649
7,873
39,364
4,242
42,415
520,131
232,074
1,903
4,921
29,523
7,873
39,364
10,186
101,855
427,698
116,037
68,144
2,472
22,142
4,921
14,762
3,936
19,682
5,255
52,551
309,903
Exhibit 3 (RCL-3)
Schedule 4.0
Page 3 of 9
TEST YEAR 2016
Line
No.
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47
48
49
50
51
52
53
54
55
56
57
58
59
Activity Code
Description
(b)
No.
(a)
Allocation
Factor (1)
(c)
Total (2)
(d)
Self-Funding Tariff
Schedule 1
Schedule 2
(e)
(f)
Schedule 3
(g)
105
14405
Total
SOA Labor
278,921
278,921
96,339
96,339
129,475
129,475
53,107
53,107
101
14001
14002
14304
14402
14564
14702
Operations
Generation Dispatch
Operations Training
Total
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
OPS Labor
Alloc-Fixed
3,880,735
3,326,344
1,663,172
1,108,781
1,387,703
536,178
11,902,912
2,661,075
83,159
443,513
387,955
214,471
3,790,172
3,259,817
166,317
1,313,906
443,513
768,284
214,471
6,166,308
620,918
498,952
266,108
221,756
231,464
107,236
1,946,433
103
14453
14454
14462
14476
18361
18381
18382
Total
TSO Labor
TSO Labor
TSO Labor
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
111,569
493,763
134,044
270,626
2,388,147
1,082,505
1,082,505
5,563,160
36,120
159,852
43,396
270,626
1,910,518
866,004
3,286,516
53,339
236,061
64,085
119,407
54,125
527,018
22,110
97,850
26,564
358,222
162,376
1,082,505
1,749,626
Total
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
134,044
134,044
134,044
134,044
224,062
760,239
43,396
43,396
86,792
107,236
107,236
64,085
64,085
44,812
387,453
26,809
26,809
26,564
26,564
179,249
285,995
415
19101
19104
19105
19112
19120
CEII Requests
Total
MOA Labor
MOA Labor
MOA Labor
MOA Labor
Total Dir Labor
25,885
935,112
6,471
12,943
25,885
1,006,297
5,578
5,578
18,120
654,579
4,530
9,060
13,396
699,684
7,766
280,534
1,941
3,883
6,911
301,035
404
16101
16102
16111
16115
16121
Market Monitoring
Total
Alloc-Fixed
Alloc-Fixed
MMM Labor
MMM Labor
Alloc-Fixed
2,599,467
359,870
254,824
232,458
197,442
3,644,061
-
1,819,627
251,909
178,377
162,720
2,412,633
779,840
107,961
76,447
69,737
197,442
1,231,428
416
21901
21902
21907
21908
21913
21915
21916
21917
21951
21953
Market Operations
Total
Alloc-Fixed
Alloc-Fixed
MA Labor
MA Labor
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
345,499
345,499
455,046
33,707
337,072
303,365
33,707
176,963
33,707
176,963
2,241,527
-
345,499
345,499
440,676
32,643
337,072
303,365
176,963
1,981,716
14,370
1,064
33,707
33,707
176,963
259,811
14469
14470
14750
14753
14757
Exhibit 3 (RCL-3)
Schedule 4.0
Page 4 of 9
TEST YEAR 2016
Line
No.
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47
48
49
50
51
52
53
54
55
56
57
58
59
60
61
62
63
64
65
66
67
Activity Code
Description
(b)
No.
(a)
401
1701
1702
1713
1714
2005
2007
2008
2009
2010
2013
2014
2020
2021
2022
2024
2025
2026
2030
2032
2033
2039
2047
2048
2049
2051
2052
2054
Allocation
Factor (1)
(c)
Total (2)
(d)
Self-Funding Tariff
Schedule 1
Schedule 2
(e)
(f)
Schedule 3
(g)
Customer Service
Admin support (ISO)
FTR Administration
Billing Disputes
Demand Response
ASM Regulation
Batch Processing
ARR Administration
Billing
Market Analysis
Score Card
FCM
Product Testing
Legal Support
FERC Data Request
Total
Alloc-Fixed
Alloc-Fixed
Total Dir Labor
Alloc-Fixed
STLM Labor
STLM Labor
STLM Labor
STLM Labor
STLM Labor
Alloc-Fixed
Alloc-Fixed
Total Dir Labor
Total Dir Labor
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
Total Dir Labor
Alloc-Fixed
STLM Labor
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
87,109
72,682
23,955
72,410
119,775
16,877
77,625
790,516
107,798
24,772
258,878
12,522
241,728
7,078
31,577
111,881
32,122
2,450
59,888
184,563
2,178
10,616
211,240
21,777
23,138
544
2,994
2,608,693
72,682
5,162
72,410
17,712
2,496
11,479
116,902
15,941
2,698
52,088
6,922
8,856
327
1,570
387,244
87,109
12,397
58,347
8,222
37,814
385,090
52,512
24,772
129,439
6,480
125,097
16,623
2,205
29,173
184,563
1,307
5,171
17,422
11,569
272
1,497
1,197,081
6,396
43,716
6,160
28,332
288,525
39,344
129,439
3,343
64,544
7,078
31,577
111,881
8,577
245
21,858
544
3,875
211,240
4,355
11,569
272
1,497
1,024,367
Customer Service
Admin Support
FERC Data Request
Total
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
Total Dir Labor
Alloc-Fixed
Alloc-Fixed
263,183
108,370
774
193,982
97,533
154,814
2,632
57,281
86,696
15,791
1,858
44,896
155
10,063
1,084
1,039,110
54,185
33
54,218
131,592
774
193,982
97,533
154,814
1,316
57,281
86,696
15,791
1,858
44,896
80
5,031
1,084
792,726
131,592
54,185
1,316
41
5,031
192,165
406
16006
16419
16420
16422
16424
16425
16434
16435
Market Services
Total
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
Total Dir Labor
Alloc-Fixed
823,752
244,377
210,670
33,707
185,390
33,707
252,804
33,707
1,818,114
214,176
54,479
268,655
543,677
244,377
210,670
33,707
185,390
33,707
130,826
33,707
1,416,061
65,900
67,499
133,399
410
16021
16024
16433
16404
16414
16429
Training Delivery
Total
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
MS Labor
MS Labor
Alloc-Fixed
858,076
8,166
33,707
86,134
146,445
155
1,132,684
429,038
4,083
33,707
77,521
131,800
139
676,289
429,038
4,083
8,613
14,644
15
456,395
3000
3002
3003
3004
3005
3006
3007
3008
3009
3010
3011
3012
3013
3014
3015
-
Exhibit 3 (RCL-3)
Schedule 4.0
Page 5 of 9
TEST YEAR 2016
Line
No.
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47
48
49
50
51
52
53
54
55
56
57
58
59
60
61
62
63
64
65
66
67
68
69
70
71
72
73
74
75
76
77
78
Activity Code
Description
(b)
No.
(a)
Allocation
Factor (1)
(c)
Total (2)
(d)
Self-Funding Tariff
Schedule 1
Schedule 2
(e)
(f)
Schedule 3
(g)
203
14313
14315
18101
18121
18131
17101
17131
17231
17241
17251
17331
17361
17401
17402
17403
17405
17406
17408
17501
17502
17503
17504
17505
17507
17508
Resource Adequacy
Analysis
Regulatory Filings
Project Management
MA-EEAC
FCA - Annual Reconfiguration Auction Support/Reliability Revie
Total
PSR Labor
PSR Labor
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
PSR Labor
PSR Labor
PSR Labor
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
Total Dir Labor
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
33,807
135,227
169,033
67,613
33,807
709,940
169,033
33,807
33,807
304,260
101,420
33,807
169,033
236,647
70,489
67,613
33,807
33,807
73,097
140,710
208,323
101,420
208,323
331,951
73,097
3,573,876
3,673
14,694
33,807
13,523
6,761
16,903
152,130
11,020
3,673
18,367
236,647
7,285
518,484
1,706
6,824
33,807
13,523
6,761
496,958
16,903
152,130
5,118
1,706
8,530
16,903
17,495
778,365
28,427
113,709
101,420
40,568
20,284
212,982
169,033
33,807
85,281
28,427
142,136
70,489
67,613
16,903
9,026
73,097
140,710
208,323
101,420
208,323
331,951
73,097
2,277,027
204
18150
18152
18401
18501
18531
System Planning
States Requests
Regional Activities
Total
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
SP Labor
740,236
148,511
10,966
17,158
131,598
1,048,470
555,177
74,256
10,966
17,158
32,671
690,228
185,059
37,128
23,331
245,517
37,128
75,596
112,724
205
11201
18201
18261
18301
18331
18333
18334
18335
18336
18337
18338
18341
18343
18344
General SIS/FS
National Activities
NERC Compliance
FERC Order 1000
Total
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
TP Labor
TP Labor
TP Labor
TP Labor
TP Labor
TP Labor
Alloc-Fixed
Alloc-Fixed
3,524
3,066,230
9,758
69,447
3,524
435,079
366,454
90,732
72,061
108,205
111,741
11,717
255,565
6,233
4,610,272
3,524
3,066,230
9,758
69,447
3,524
435,079
366,454
90,732
72,061
108,205
111,741
11,717
4,348,473
304
801
1661
25002
25902
25914
25919
25926
25938
25943
25953
Program Management
PMO Support
Hourly Market
Total
Total Dir Labor
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
Total Dir Labor
Alloc-Fixed
Alloc-Fixed
Total Dir Labor
Alloc-Fixed
Alloc-Fixed
801,603
340,444
16,298
115,419
66,825
39,711
154,814
16,720
33,856
95,782
1,681,472
172,730
4,889
80,793
14,400
61,925
3,603
86,204
424,544
414,838
238,311
5,704
34,626
34,583
46,444
8,653
783,159
214,035
102,133
5,704
17,843
39,711
46,444
4,464
33,856
9,578
473,769
315
21201
21203
Total
Total Dir Labor
Total Dir Labor
2,005,775
36,006
2,041,781
432,205
7,759
439,963
1,038,011
18,634
1,056,644
535,559
9,614
545,173
408
21001
21002
21003
21007
22656
Market Development
Market Development
Administration
Total
Total Dir Labor
Total Dir Labor
Total Dir Labor
Total Dir Labor
Alloc-Fixed
1,751,638
183,849
3,920
61,283
765,429
2,766,119
377,443
39,616
845
13,205
431,109
906,492
95,144
2,029
31,715
574,072
1,609,451
467,703
49,089
1,047
16,363
191,357
725,559
-
255,565
6,233
261,798
Exhibit 3 (RCL-3)
Schedule 4.0
Page 6 of 9
TEST YEAR 2016
Line
No.
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47
48
49
50
51
52
53
54
55
56
57
58
59
60
61
62
63
64
Activity Code
Description
(b)
No.
(a)
Allocation
Factor (1)
(c)
Total (2)
(d)
Self-Funding Tariff
Schedule 1
Schedule 2
(e)
(f)
Schedule 3
(g)
407
22602
22607
Total
Alloc-Fixed
Total Dir Labor
598,427
112,878
711,305
24,323
24,323
299,213
58,416
357,629
299,213
30,139
329,353
409
22401
22402
22404
Administration
Total
Total Dir Labor
Total Dir Labor
Alloc-Fixed
66,070
21,899
179,796
267,765
14,237
4,719
18,956
34,192
11,333
143,837
189,361
17,641
5,847
35,959
59,448
210
6517
6519
6552
6556
6557
22501
22505
IT Management
Security
Administrative
Total
Total Dir Labor
Total Dir Labor
Total Dir Labor
Total Dir Labor
Total Dir Labor
Alloc-Fixed
Alloc-Fixed
74,438
2,988,976
7,024
145,731
12,727
187,538
352,172
3,768,606
16,040
644,065
1,514
31,402
2,743
84,392
119,738
899,894
38,522
1,546,828
3,635
75,417
6,587
84,392
116,217
1,871,598
19,876
798,083
1,875
38,911
3,398
18,754
116,217
997,114
Help Desk Support
Communications
Desktop Support
Network Support
Asset Management
Total
Total Dir Labor
Total Dir Labor
Alloc-Fixed
Total Dir Labor
Total Dir Labor
Total Dir Labor
Total Dir Labor
Total Dir Labor
Total Dir Labor
Total Dir Labor
Total Dir Labor
Total Dir Labor
270,398
334,649
1,254,035
19,345
499,125
678,400
838,453
85,170
245,577
413,609
11,019
233,940
4,883,719
58,265
72,110
4,168
107,552
146,182
180,670
18,352
52,917
89,125
2,374
50,409
782,125
139,934
173,184
627,017
10,011
258,303
351,079
433,909
44,076
127,089
214,047
5,703
121,067
2,505,419
72,199
89,354
627,017
5,165
133,271
181,139
223,874
22,741
65,571
110,437
2,942
62,464
1,596,175
Total Dir Labor
Total Dir Labor
Total Dir Labor
Total Dir Labor
Total Dir Labor
Total Dir Labor
Total Dir Labor
Total Dir Labor
Total Dir Labor
Total Dir Labor
19,622
39,245
19,622
98,111
156,978
1,336,004
333,579
19,622
19,622
146,982
2,189,389
4,228
8,456
4,228
21,141
33,826
287,883
71,880
4,228
4,228
31,672
471,770
10,155
20,310
10,155
50,774
81,238
691,397
172,631
10,155
10,155
76,065
1,133,033
5,239
10,479
5,239
26,197
41,915
356,725
89,069
5,239
5,239
39,245
584,586
Total Dir Labor
Total Dir Labor
Total Dir Labor
Total Dir Labor
Total Dir Labor
Total Dir Labor
Total Dir Labor
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
Total Dir Labor
Total Dir Labor
909,895
256,136
265,629
663,397
150,067
434,067
400,178
336,218
79,608
451,110
238,823
79,608
79,608
53,072
4,397,414
196,064
55,192
57,238
142,949
32,336
93,533
86,231
17,154
11,436
692,133
470,880
132,553
137,466
343,315
77,661
224,635
207,097
268,974
63,686
360,888
191,058
63,686
41,198
27,465
2,610,563
242,950
68,391
70,925
177,133
40,069
115,900
106,851
67,244
15,922
90,222
47,765
15,922
21,256
14,171
1,094,718
201
6550
6602
6615
6516
6616
6617
6618
6619
6620
6621
6622
6623
212
6539
6540A
6540B
6540D
6540E
6540
6541
6546
6547
6548
IT Cyber Security
Controls Assessment
Security Training
211
6571
6591
6594
6595
6596
21806
21706
21801
21803
21804
21802
21811
21819
21821
DBA Support - MOPS
IT Data Analyst
IT Data Governance
Ceridian Support
Total
Exhibit 3 (RCL-3)
Schedule 4.0
Page 7 of 9
TEST YEAR 2016
Line
No.
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
Activity Code
Description
(b)
No.
(a)
Allocation
Factor (1)
(c)
213
21702
21709
21707
21710
21711
Total
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
75,435
17,788
1,074,003
531,017
171,124
1,869,365
102
21600
21603
21604
21605
21606
DTS Support
DAM Support
Total
Total Dir Labor
Total Dir Labor
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
228,214
240,405
644,592
918,647
1,117,595
3,149,454
216
21650
21654
21651
21652
21655
21656
21657
21658
NX9 Administration
ICCP Support
Total
Total Dir Labor
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
107,374
149,822
720,224
176,841
481,009
23,590
272,624
74,528
2,006,012
Total ISO
$
104,908,012
100.0%
Self-Funding Tariff
Schedule 1
Schedule 2
(e)
(f)
Total (2)
(d)
-
$
Schedule 3
(g)
15,087
14,230
859,202
424,813
136,899
1,450,232
60,348
3,558
214,801
106,203
34,225
419,134
49,176
51,802
515,674
183,729
223,519
1,023,900
118,103
124,412
128,918
551,188
670,557
1,593,179
60,935
64,190
183,729
223,519
532,374
23,139
59,929
288,090
70,737
192,403
18,872
653,169
55,566
59,929
288,090
70,737
192,403
4,718
671,442
28,669
29,964
144,045
35,368
96,202
272,624
74,528
681,400
26,965,798
25.7%
$
49,446,752
47.1%
$
28,495,462
27.2%
Exhibit 3 (RCL-3)
Schedule 4.0
Page 8 of 9
TEST YEAR 2016
Line
No.
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47
48
49
50
51
52
53
54
55
56
57
58
59
No.
(a)
Activity Code
Description
(b)
Allocation
Factor (1)
(c)
Cost Ctr. Summary Of Departmental Labor Allocation Using "Alloc-Fixed" Allocators
307
Administration-CEO
Adm Labor
302
Finance
Fin Labor
108
Building Services
Bldg Labor
310
ERM Labor
301
Human Resources
HR Labor
306
Legal Department
Legal Labor
305
Internal Audit
IA Labor
701
COO-Adm
COO Labor
702
COO Labor
703
COO Labor
105
SYSOPS Labor
101
Operations
OPS Labor
103
TSO Labor
109
TSO Labor
415
MOA Labor
404
Market Monitoring
MMM Labor
416
Market Operations
MA Labor
401
STLM Labor
411
MOSS Labor
406
Market Services
MS Labor
410
MAR Labor
204
System Planning
SP Labor
203
Resource Adequacy
PSR Labor
205
TP Labor
304
Program Management
PMO Labor
315
BAT Labor
408
Market Development
MD Labor
407
MDES Labor
409
DR Labor
Self-Funding Tariff
Schedule 1
Schedule 2
(e)
(f)
Total (2)
(d)
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
0.00%
810,821
100.00%
0.00%
543,968
100.00%
0.00%
1,132,486
100.00%
167,311
100.00%
1,219,926
100.00%
825,867
100.00%
1,041,228
100.00%
278,921
100.00%
11,902,912
100.00%
5,563,160
100.00%
760,239
100.00%
980,412
100.00%
3,644,061
100.00%
2,241,527
100.00%
2,298,366
100.00%
1,038,955
100.00%
1,565,310
100.00%
1,132,684
100.00%
1,048,470
100.00%
3,540,070
100.00%
4,610,272
100.00%
796,324
100.00%
0.00%
765,429
100.00%
598,427
100.00%
179,796
100.00%
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
0.00%
0.00%
0.00%
190,796
35.07%
0.00%
159,710
14.10%
19,659
11.75%
326,958
26.80%
322,845
39.09%
473,475
45.47%
96,339
34.54%
3,790,172
31.84%
3,286,516
59.08%
86,792
11.42%
0.00%
0.00%
0.00%
320,375
13.94%
54,185
5.22%
214,176
13.68%
0.00%
690,228
65.83%
511,199
14.44%
4,348,473
94.32%
233,812
29.36%
0.00%
0.00%
0.00%
0.00%
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
0.00%
0.00%
0.00%
179,813
33.06%
0.00%
232,305
20.51%
137,823
82.38%
584,997
47.95%
157,380
19.06%
315,658
30.32%
129,475
46.42%
6,166,308
51.81%
527,018
9.47%
387,453
50.96%
686,288
70.00%
2,412,633
66.21%
1,981,716
88.41%
1,036,484
45.10%
792,646
76.29%
1,285,235
82.11%
676,289
59.71%
245,517
23.42%
760,870
21.49%
0.00%
325,085
40.82%
0.00%
574,072
75.00%
299,213
50.00%
143,837
80.00%
Schedule 3
(g)
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
0.00%
810,821
100.00%
0.00%
173,359
31.87%
0.00%
740,472
65.38%
9,829
5.87%
307,970
25.25%
345,642
41.85%
252,096
24.21%
53,107
19.04%
1,946,433
16.35%
1,749,626
31.45%
285,995
37.62%
294,124
30.00%
1,231,428
33.79%
259,811
11.59%
941,507
40.96%
192,124
18.49%
65,900
4.21%
456,395
40.29%
112,724
10.75%
2,268,001
64.07%
261,798
5.68%
237,427
29.82%
0.00%
191,357
25.00%
299,213
50.00%
35,959
20.00%
Exhibit 3 (RCL-3)
Schedule 4.0
Page 9 of 9
TEST YEAR 2016
Line
No.
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
Activity Code
Description
(b)
No.
(a)
Allocation
Factor (1)
(c)
Cost Ctr. Summary Of Departmental Labor Allocation Using "Alloc-Fixed" Allocators
210
IT Management
OTM Labor
201
ITO Labor
211
ITDG Labor
212
IT Cyber Security
ITCS
102
EMS Labor
213
ESD
216
ITPSM
Total Direct Labor
Self-Funding Tariff
Schedule 1
Schedule 2
(e)
(f)
Total (2)
(d)
$
$
$
$
$
$
$
$
539,710
100.00%
1,254,035
100.00%
1,185,366
100.00%
0.00%
2,680,834
100.00%
1,869,365
100.00%
1,898,637
100.00%
58,114,888
100.00%
$
$
$
$
$
$
$
$
Summary Of Allocations Of Labor Based On Fixed Allocators and Allocated Departmental Labor
Total Direct Labor
$
58,114,888 $
Dir Labor
100.00%
Total Indirect Labor Labor
$
46,793,124 $
InDir Labor
100.00%
Total Labor Expense
$
104,908,012 $
Total Dir Labor
100.00%
204,131
37.82%
0.00%
0.00%
0.00%
922,922
34.43%
0.00%
630,030
33.18%
16,882,792
29.05%
$
$
$
$
$
$
$
$
16,882,792 $
29.05%
10,083,006 $
21.55%
26,965,798 $
25.70%
200,609
37.17%
627,017
50.00%
948,293
80.00%
0.00%
1,350,664
50.38%
1,450,232
77.58%
615,876
32.44%
25,230,803
43.42%
Schedule 3
(g)
$
$
$
$
$
$
$
$
25,230,803 $
43.42%
24,215,949 $
51.75%
49,446,752 $
47.13%
134,971
25.01%
627,017
50.00%
237,073
20.00%
0.00%
407,248
15.19%
419,134
22.42%
652,731
34.38%
16,001,293
27.53%
16,001,293
27.53%
12,494,169
26.70%
28,495,462
27.16%
Exhibit 3 (RCL-3)
Schedule 5.0
Page 1 of 7
ALLOCATION FACTORS BY COST CATEGORY
TEST YEAR 2016
Line
No.
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47
48
49
50
51
52
53
54
55
56
57
58
59
60
61
62
63
64
65
66
67
68
69
70
71
72
73
74
75
76
77
No.
(a)
Activity Code
Description
(b)
Allocation
Factor
(c)
Total
(d)
Self-Funding Tariff
Schedule 1 Schedule 2
(e)
(f)
Schedule 3
(g)
Reference
(h)
307
12651
12652
12654
12657
Administration-CEO
Indirect Administrative Support for BCC
Total Dir Labor
Total Dir Labor
Total Dir Labor
Total Dir Labor
100.00%
100.00%
100.00%
100.00%
21.55%
21.55%
21.55%
21.55%
51.75%
51.75%
51.75%
51.75%
26.70%
26.70%
26.70%
26.70%
Per ISO-NE Staff
302
11601
11701
11702
11901
12001
12005
12015
12017
12101
12201
92004
92005
92006
92007
92008
92009
92010
92011
92012
92013
92014
92015
92016
99707
99995
99996
99998
Finance
Accounts Payable
Procurement
Backup Control Center (BCC) Construction
Amortization of Land Recovery
NPCC/NERC Dues
Total Dir Labor
Total Dir Labor
Total Dir Labor
Total Dir Labor
Total Dir Labor
Total Dir Labor
Total Dir Labor
Alloc-Fixed
Total Dir Labor
Total Dir Labor
Alloc-Fixed
Alloc-Fixed
Total Dir Labor
Total Dir Labor
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
Total Dir Labor
Total Dir Labor
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
21.55%
21.55%
21.55%
21.55%
21.55%
21.55%
21.55%
0.00%
21.55%
21.55%
20.83%
21.16%
21.55%
21.55%
45.84%
45.01%
23.72%
24.42%
24.17%
20.20%
25.68%
34.18%
18.80%
19.33%
0.00%
21.55%
21.55%
51.75%
51.75%
51.75%
51.75%
51.75%
51.75%
51.75%
0.00%
51.75%
51.75%
52.21%
52.00%
51.75%
51.75%
35.73%
36.28%
49.74%
34.97%
37.02%
43.63%
35.23%
44.36%
45.60%
35.58%
0.00%
51.75%
51.75%
26.70%
26.70%
26.70%
26.70%
26.70%
26.70%
26.70%
100.00%
26.70%
26.70%
26.96%
26.84%
26.70%
26.70%
18.43%
18.72%
26.55%
40.60%
38.81%
36.17%
39.09%
21.46%
35.60%
45.09%
100.00%
26.70%
26.70%
Per ISO-NE Staff
108
12664
Building Services
Total Dir Labor
100.00%
21.55%
51.75%
26.70%
Per ISO-NE Staff
310
22701
22703
22704
22705
22706
22708
22709
22710
22711
22712
22713
22714
22716
22719
22720
22721
22725
22727
23003
23006
25006
25011
25014
25015
25017
301
12661
12701
12801
12901
12951
12961
12962
13410
13411
13412
13413
13414
Enterprise Risk Mgmnt - Admin
Corporate Scorecard
Adminstration
Management
MEC/Financials
Analysis
Human Performance Improvement
Corp Strategic Risk
OSHA procedures
Human Resources
Employee Relations
Compensation
HR - General
HR - Training
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
Total Dir Labor
Total Dir Labor
Total Dir Labor
Total Dir Labor
Total Dir Labor
Total Dir Labor
Total Dir Labor
Total Dir Labor
Total Dir Labor
Total Dir Labor
Total Dir Labor
Total Dir Labor
Total Dir Labor
Total Dir Labor
Total Dir Labor
Alloc-Fixed
Alloc-Fixed
Total Dir Labor
Total Dir Labor
Total Dir Labor
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
33.30%
33.30%
33.30%
33.30%
40.00%
21.55%
21.55%
21.55%
21.55%
21.55%
21.55%
21.55%
21.55%
21.55%
21.55%
21.55%
21.55%
21.55%
21.55%
21.55%
45.00%
33.30%
21.55%
21.55%
21.55%
33.30%
33.30%
33.30%
33.30%
30.00%
51.75%
51.75%
51.75%
51.75%
51.75%
51.75%
51.75%
51.75%
51.75%
51.75%
51.75%
51.75%
51.75%
51.75%
51.75%
45.00%
33.30%
51.75%
51.75%
51.75%
33.40%
33.40%
33.40%
33.40%
30.00%
26.70%
26.70%
26.70%
26.70%
26.70%
26.70%
26.70%
26.70%
26.70%
26.70%
26.70%
26.70%
26.70%
26.70%
26.70%
10.00%
33.40%
26.70%
26.70%
26.70%
Per ISO-NE Staff
Total Dir Labor
Total Dir Labor
Total Dir Labor
Total Dir Labor
Total Dir Labor
Total Dir Labor
Total Dir Labor
Total Dir Labor
Total Dir Labor
Total Dir Labor
Total Dir Labor
Total Dir Labor
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
21.55%
21.55%
21.55%
21.55%
21.55%
21.55%
21.55%
21.55%
21.55%
21.55%
21.55%
21.55%
51.75%
51.75%
51.75%
51.75%
51.75%
51.75%
51.75%
51.75%
51.75%
51.75%
51.75%
51.75%
26.70%
26.70%
26.70%
26.70%
26.70%
26.70%
26.70%
26.70%
26.70%
26.70%
26.70%
26.70%
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Exhibit 3 (RCL-3)
Schedule 5.0
Page 2 of 7
TEST YEAR 2016
Line
No.
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47
48
49
50
51
52
53
54
55
56
57
58
59
60
61
62
63
64
65
66
67
68
69
70
71
72
73
No.
(a)
Activity Code
Description
(b)
Allocation
Factor
(c)
Total
(d)
Self-Funding Tariff
(e)
(f)
Schedule 3
(g)
Reference
(h)
305
15001
15002
15003
15004
15005
15006
15007
15008
15020
15021
15022
15023
15031
15040
15065
15085
15131
15133
15134
15161
15162
15166
15175
15186
25702
28160
Internal Audit
Training
Internal Audit - Finance
Vendor Contracts
Wire Transfers
Operations
NAMS Support
Satellite Reviews
External Audit- Financial Audit
External Audit -Pricing Module Certification
External Audit - Info Technology
Total Dir Labor
Total Dir Labor
Total Dir Labor
Total Dir Labor
Total Dir Labor
Total Dir Labor
Total Dir Labor
Total Dir Labor
Total Dir Labor
Total Dir Labor
Total Dir Labor
Total Dir Labor
Total Dir Labor
Total Dir Labor
Alloc-Fixed
Total Dir Labor
Total Dir Labor
Total Dir Labor
Total Dir Labor
Total Dir Labor
Total Dir Labor
Alloc-Fixed
Total Dir Labor
Total Dir Labor
Alloc-Fixed
Total Dir Labor
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
21.55%
21.55%
21.55%
21.55%
21.55%
21.55%
21.55%
21.55%
21.55%
21.55%
21.55%
21.55%
21.55%
21.55%
40.00%
21.55%
21.55%
21.55%
21.55%
21.55%
21.55%
0.00%
21.55%
21.55%
0.00%
21.55%
51.75%
51.75%
51.75%
51.75%
51.75%
51.75%
51.75%
51.75%
51.75%
51.75%
51.75%
51.75%
51.75%
51.75%
40.00%
51.75%
51.75%
51.75%
51.75%
51.75%
51.75%
100.00%
51.75%
51.75%
100.00%
51.75%
26.70%
26.70%
26.70%
26.70%
26.70%
26.70%
26.70%
26.70%
26.70%
26.70%
26.70%
26.70%
26.70%
26.70%
20.00%
26.70%
26.70%
26.70%
26.70%
26.70%
26.70%
0.00%
26.70%
26.70%
0.00%
26.70%
Per ISO-NE Staff
306
8301
12426
12502
12504
12505
12508
12509
12512
12513
12514
12517
12520
12521
12523
12542
12543
12544
12552
12559
12563
12572
12573
12574
12587
12588
12594
12595
12609
12663
12669
Legal Department
Federal Regulatory
Board of Directors
BSAI - General Corporate
Miscellaneous Labor Matters
Billing Disputes
Transmission Upgrades CT
Independent Market Advisor
FERC Proceedings
S&G - General Corporate
General Corporate
Regulatory Matters
Market Rule 1 Proceedings
Maine Transmission Siting
NEEWS Transmission Siting
FTR Clearing
Public Information
Government Affairs
Total Dir Labor
Alloc-Fixed
Total Dir Labor
Total Dir Labor
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
Total Dir Labor
Total Dir Labor
Total Dir Labor
Total Dir Labor
Alloc-Fixed
Total Dir Labor
Total Dir Labor
Alloc-Fixed
Alloc-Fixed
Total Dir Labor
Total Dir Labor
Total Dir Labor
Total Dir Labor
Total Dir Labor
Total Dir Labor
Total Dir Labor
Alloc-Fixed
Total Dir Labor
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
Total Dir Labor
Total Dir Labor
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
21.55%
0.00%
21.55%
21.55%
100.00%
0.00%
0.00%
21.55%
21.55%
21.55%
21.55%
0.00%
21.55%
21.55%
0.00%
0.00%
21.55%
21.55%
21.55%
21.55%
21.55%
21.55%
21.55%
0.00%
21.55%
0.00%
0.00%
0.00%
21.55%
21.55%
51.75%
50.00%
51.75%
51.75%
0.00%
100.00%
50.00%
51.75%
51.75%
51.75%
51.75%
40.00%
51.75%
51.75%
70.00%
70.00%
51.75%
51.75%
51.75%
51.75%
51.75%
51.75%
51.75%
0.00%
51.75%
70.00%
70.00%
50.00%
51.75%
51.75%
26.70%
50.00%
26.70%
26.70%
0.00%
0.00%
50.00%
26.70%
26.70%
26.70%
26.70%
60.00%
26.70%
26.70%
30.00%
30.00%
26.70%
26.70%
26.70%
26.70%
26.70%
26.70%
26.70%
100.00%
26.70%
30.00%
30.00%
50.00%
26.70%
26.70%
Per ISO-NE Staff
701
19001
19002
19003
19005
19009
19012
COO-Adm
Renewable Resource Integration
Changes to the Forward Capacity Market
Total OPS Labor
Total OPS Labor
Total OPS Labor
Total OPS Labor
Alloc-Fixed
Alloc-Fixed
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
26.80%
26.80%
26.80%
26.80%
0.00%
0.00%
47.95%
47.95%
47.95%
47.95%
0.00%
0.00%
25.25%
25.25%
25.25%
25.25%
100.00%
100.00%
Per ISO-NE Staff
105
14404
14405
14407
14408
SOA Labor
SOA Labor
SOA Labor
SOA Labor
100.00%
100.00%
100.00%
100.00%
34.54%
34.54%
34.54%
34.54%
46.42%
46.42%
46.42%
46.42%
19.04%
19.04%
19.04%
19.04%
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Exhibit 3 (RCL-3)
Schedule 5.0
Page 3 of 7
TEST YEAR 2016
Line
No.
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47
48
49
50
51
52
53
54
55
56
57
58
59
60
61
62
No.
(a)
Activity Code
Description
(b)
Allocation
Factor
(c)
Total
(d)
Self-Funding Tariff
(e)
(f)
Schedule 3
(g)
Reference
(h)
101
14001
14002
14304
14402
14413
14564
14702
Operations
Generation Dispatch
Operations Training
Operations Support Training & Development
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
OPS Labor
Alloc-Fixed
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
0.00%
80.00%
5.00%
40.00%
40.00%
27.96%
40.00%
84.00%
5.00%
79.00%
40.00%
40.00%
55.36%
40.00%
16.00%
15.00%
16.00%
20.00%
20.00%
16.68%
20.00%
Per ISO-NE Staff
702
14703
14706
14711
14715
OS Labor
OS Labor
Alloc-Fixed
Alloc-Fixed
100.00%
100.00%
100.00%
100.00%
55.55%
55.55%
33.30%
0.00%
19.33%
19.33%
33.30%
0.00%
25.12%
25.12%
33.40%
100.00%
Per ISO-NE Staff
103
14301
14452
14453
14454
14462
14476
18361
18381
18382
Contract Administration and Scheduling
Alloc-Fixed
TSO Labor
TSO Labor
TSO Labor
TSO Labor
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
10.00%
32.37%
32.37%
32.37%
32.37%
100.00%
80.00%
80.00%
0.00%
70.00%
47.81%
47.81%
47.81%
47.81%
0.00%
5.00%
5.00%
0.00%
20.00%
19.82%
19.82%
19.82%
19.82%
0.00%
15.00%
15.00%
100.00%
Per ISO-NE Staff
315
14469
14470
14750
14751
14753
14757
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
0.00%
0.00%
32.37%
32.37%
32.37%
0.00%
80.00%
80.00%
47.81%
47.81%
47.81%
20.00%
20.00%
20.00%
19.82%
19.82%
19.82%
80.00%
Per ISO-NE Staff
415
19101
19103
19104
19105
19112
19120
CEII Requests
MOA Labor
MOA Labor
MOA Labor
MOA Labor
MOA Labor
Total Dir Labor
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
0.00%
0.00%
0.00%
0.00%
0.00%
21.55%
70.00%
70.00%
70.00%
70.00%
70.00%
51.75%
30.00%
30.00%
30.00%
30.00%
30.00%
26.70%
Per ISO-NE Staff
404
16101
16102
16111
16114
16115
16121
Market Monitoring
Maintenance / Troubleshooting Software
Alloc-Fixed
Alloc-Fixed
MMM Labor
MMM Labor
MMM Labor
Alloc-Fixed
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
70.00%
70.00%
70.00%
70.00%
70.00%
0.00%
30.00%
30.00%
30.00%
30.00%
30.00%
100.00%
Per ISO-NE Staff
416
21901
21902
21904
21907
21908
21913
21915
21916
21917
21951
21953
Market Operations
Alloc-Fixed
Alloc-Fixed
MA Labor
MA Labor
MA Labor
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
100.00%
100.00%
96.84%
96.84%
96.84%
100.00%
100.00%
0.00%
100.00%
0.00%
0.00%
0.00%
0.00%
3.16%
3.16%
3.16%
0.00%
0.00%
100.00%
0.00%
100.00%
100.00%
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Exhibit 3 (RCL-3)
Schedule 5.0
Page 4 of 7
TEST YEAR 2016
Line
No.
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47
48
49
50
51
52
53
54
55
56
57
58
59
60
61
62
63
64
65
66
67
68
69
70
71
72
No.
(a)
Activity Code
Description
(b)
Allocation
Factor
(c)
Total
(d)
Self-Funding Tariff
(e)
(f)
Schedule 3
(g)
Reference
(h)
401
1701
1702
1713
1714
2005
2007
2008
2009
2010
2013
2014
2020
2021
2022
2024
2025
2026
2030
2032
2033
2039
2047
2048
2049
2051
2052
2054
Customer Service
Admin support (ISO)
FTR Administration
Billing Disputes
Demand Response
ASM Regulation
Batch Processing
ARR Administration
Billing
Market Analysis
Score Card
FCM
Product Testing
Legal Support
FERC Data Request
Alloc-Fixed
Alloc-Fixed
Total Dir Labor
Alloc-Fixed
STLM Labor
STLM Labor
STLM Labor
STLM Labor
STLM Labor
Alloc-Fixed
Alloc-Fixed
Total Dir Labor
Total Dir Labor
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
Total Dir Labor
Alloc-Fixed
STLM Labor
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
0.00%
100.00%
21.55%
100.00%
14.79%
14.79%
14.79%
14.79%
14.79%
0.00%
0.00%
21.55%
21.55%
0.00%
0.00%
0.00%
21.55%
0.00%
14.79%
0.00%
15.00%
14.79%
0.00%
0.00%
0.00%
0.00%
0.00%
100.00%
0.00%
51.75%
0.00%
48.71%
48.71%
48.71%
48.71%
48.71%
100.00%
50.00%
51.75%
51.75%
0.00%
0.00%
0.00%
51.75%
90.00%
48.71%
100.00%
60.00%
48.71%
0.00%
80.00%
50.00%
50.00%
50.00%
0.00%
0.00%
26.70%
0.00%
36.50%
36.50%
36.50%
36.50%
36.50%
0.00%
50.00%
26.70%
26.70%
100.00%
100.00%
100.00%
26.70%
10.00%
36.50%
0.00%
25.00%
36.50%
100.00%
20.00%
50.00%
50.00%
50.00%
Per ISO-NE Staff
3000
3002
3003
3004
3005
3006
3007
3008
3009
3010
3011
3012
3013
3014
3015
Customer Service
Admin Support
FERC Data Request
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
Total Dir Labor
Alloc-Fixed
Alloc-Fixed
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
0.00%
50.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
21.55%
0.00%
0.00%
50.00%
0.00%
100.00%
100.00%
100.00%
100.00%
50.00%
100.00%
100.00%
100.00%
100.00%
100.00%
51.75%
50.00%
100.00%
50.00%
50.00%
0.00%
0.00%
0.00%
0.00%
50.00%
0.00%
0.00%
0.00%
0.00%
0.00%
26.70%
50.00%
0.00%
Per ISO-NE Staff
406
16001
16006
16404
16414
16419
16420
16422
16424
16425
16429
16434
16435
Market Services
Participant/membership support
Alloc-Fixed
Alloc-Fixed
MS Labor
MS Labor
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
Total Dir Labor
Alloc-Fixed
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
0.00%
26.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
21.55%
0.00%
50.00%
66.00%
90.00%
90.00%
100.00%
100.00%
100.00%
100.00%
100.00%
90.00%
51.75%
100.00%
50.00%
8.00%
10.00%
10.00%
0.00%
0.00%
0.00%
0.00%
0.00%
10.00%
26.70%
0.00%
Per ISO-NE Staff
410
16021
16024
16433
Training Delivery
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
100.00%
100.00%
100.00%
0.00%
0.00%
0.00%
50.00%
50.00%
100.00%
50.00%
50.00%
0.00%
Per ISO-NE Staff
204
18150
18152
18401
18501
18521
18531
System Planning
States Requests
Regional Activities
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
SP Labor
SP Labor
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
75.00%
50.00%
100.00%
100.00%
24.83%
24.83%
25.00%
25.00%
0.00%
0.00%
17.73%
17.73%
0.00%
25.00%
0.00%
0.00%
57.44%
57.44%
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Exhibit 3 (RCL-3)
Schedule 5.0
Page 5 of 7
TEST YEAR 2016
Line
No.
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47
48
49
50
51
52
53
54
55
56
57
58
59
60
61
62
63
64
65
66
67
No.
(a)
Activity Code
Description
(b)
Allocation
Factor
(c)
Total
(d)
Self-Funding Tariff
(e)
(f)
Schedule 3
(g)
Reference
(h)
203
18101
18121
18131
14313
14315
17101
17131
17231
17241
17251
17331
17361
17401
17402
17403
17405
17406
17408
17501
17502
17503
17504
17505
17507
17508
Resource Adequacy
Analysis
Regulatory Filings
Project Management
MA-EEAC
FCA - Annual Reconfiguration Auction Support/Reliability Reviews
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
PSR Labor
PSR Labor
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
PSR Labor
PSR Labor
PSR Labor
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
Total Dir Labor
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
20.00%
20.00%
20.00%
10.87%
10.87%
0.00%
0.00%
0.00%
50.00%
50.00%
10.87%
10.87%
10.87%
100.00%
0.00%
0.00%
0.00%
21.55%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
20.00%
20.00%
20.00%
5.05%
5.05%
70.00%
0.00%
0.00%
50.00%
50.00%
5.05%
5.05%
5.05%
0.00%
0.00%
0.00%
50.00%
51.75%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
60.00%
60.00%
60.00%
84.09%
84.09%
30.00%
100.00%
100.00%
0.00%
0.00%
84.09%
84.09%
84.09%
0.00%
100.00%
100.00%
50.00%
26.70%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
Per ISO-NE Staff
205
11201
18201
18261
18301
18331
18333
18334
18335
18336
18337
18338
18341
18343
18344
General SIS/FS
National Activities
NERC Compliance
FERC Order 1000
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
TP Labor
TP Labor
TP Labor
TP Labor
TP Labor
TP Labor
Alloc-Fixed
Alloc-Fixed
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
100.00%
100.00%
Per ISO-NE Staff
304
801
1661
25002
25902
25914
25919
25926
25938
25940
25943
25953
Program Management
PMO Support
Hourly Market
Non-Reimburseable Smart Grid SIDU Observation Period
Total Dir Labor
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
Total Dir Labor
Alloc-Fixed
Alloc-Fixed
Total Dir Labor
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
21.55%
0.00%
30.00%
70.00%
21.55%
0.00%
40.00%
21.55%
15.00%
0.00%
90.00%
51.75%
70.00%
35.00%
30.00%
51.75%
0.00%
30.00%
51.75%
15.00%
0.00%
0.00%
26.70%
30.00%
35.00%
0.00%
26.70%
100.00%
30.00%
26.70%
70.00%
100.00%
10.00%
Per ISO-NE Staff
315
21201
21203
Total Dir Labor
Total Dir Labor
100.00%
100.00%
21.55%
21.55%
51.75%
51.75%
26.70%
26.70%
Per ISO-NE Staff
408
21001
21002
21003
21007
21009
22656
Market Development
Market Development
Administration
Increased Scope of Impact Analysis
Total Dir Labor
Total Dir Labor
Total Dir Labor
Total Dir Labor
Alloc-Fixed
Alloc-Fixed
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
21.55%
21.55%
21.55%
21.55%
26.00%
0.00%
51.75%
51.75%
51.75%
51.75%
66.00%
75.00%
26.70%
26.70%
26.70%
26.70%
8.00%
25.00%
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Exhibit 3 (RCL-3)
Schedule 5.0
Page 6 of 7
TEST YEAR 2016
Line
No.
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47
48
49
50
51
52
53
54
55
56
57
58
59
60
61
62
63
64
65
66
67
68
69
70
71
72
73
74
75
76
77
78
79
No.
(a)
Activity Code
Description
(b)
Allocation
Factor
(c)
Total
(d)
Self-Funding Tariff
(e)
(f)
Schedule 3
(g)
Reference
(h)
407
22602
22607
Alloc-Fixed
Total Dir Labor
100.00%
100.00%
0.00%
21.55%
50.00%
51.75%
50.00%
26.70%
Per ISO-NE Staff
409
22401
22402
22404
Administration
Total Dir Labor
Total Dir Labor
Alloc-Fixed
100.00%
100.00%
100.00%
21.55%
21.55%
0.00%
51.75%
51.75%
80.00%
26.70%
26.70%
20.00%
Per ISO-NE Staff
210
6517
6519
6552
6556
6557
IT Management
Security
Total Dir Labor
Total Dir Labor
Total Dir Labor
Total Dir Labor
Total Dir Labor
100.00%
100.00%
100.00%
100.00%
100.00%
21.55%
21.55%
21.55%
21.55%
21.55%
51.75%
51.75%
51.75%
51.75%
51.75%
26.70%
26.70%
26.70%
26.70%
26.70%
Per ISO-NE Staff
201
6510
6511
6512
6513
6514
6516
6550
6602
6615
6616
6617
6618
6619
6620
6621
6622
6623
Desktop Support - Hardware
Desktop Support - Software
Networking - Hardware
Communications
Help Desk Support
Desktop Support
Network Support
Asset Management
Total Dir Labor
Total Dir Labor
Alloc-Fixed
Alloc-Fixed
Total Dir Labor
Total Dir Labor
Total Dir Labor
Total Dir Labor
Alloc-Fixed
Total Dir Labor
Total Dir Labor
Total Dir Labor
Total Dir Labor
Total Dir Labor
Total Dir Labor
Total Dir Labor
Total Dir Labor
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
21.55%
21.55%
0.00%
0.00%
21.55%
21.55%
21.55%
21.55%
0.00%
21.55%
21.55%
21.55%
21.55%
21.55%
21.55%
21.55%
21.55%
51.75%
51.75%
75.00%
75.00%
51.75%
51.75%
51.75%
51.75%
50.00%
51.75%
51.75%
51.75%
51.75%
51.75%
51.75%
51.75%
51.75%
26.70%
26.70%
25.00%
25.00%
26.70%
26.70%
26.70%
26.70%
50.00%
26.70%
26.70%
26.70%
26.70%
26.70%
26.70%
26.70%
26.70%
Per ISO-NE Staff
212
6539
6540
6540A
6540B
6540D
6540E
6541
6543
6544
6546
6547
6548
IT Cyber Security
Controls Assessment
Critical Infrastructure Protection WG (NERC)
Infragrad (FBI)
Security Training
Total Dir Labor
Total Dir Labor
Total Dir Labor
Total Dir Labor
Total Dir Labor
Total Dir Labor
Total Dir Labor
Total Dir Labor
Total Dir Labor
Total Dir Labor
Total Dir Labor
Total Dir Labor
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
21.55%
21.55%
21.55%
21.55%
21.55%
21.55%
21.55%
21.55%
21.55%
21.55%
21.55%
21.55%
51.75%
51.75%
51.75%
51.75%
51.75%
51.75%
51.75%
51.75%
51.75%
51.75%
51.75%
51.75%
26.70%
26.70%
26.70%
26.70%
26.70%
26.70%
26.70%
26.70%
26.70%
26.70%
26.70%
26.70%
Per ISO-NE Staff
211
21801
21802
21803
21804
21805
21806
21807
21808
21809
21811
21816
21818
21819
21821
6571
21706
6591
6594
6595
6596
Software Support - TSO
Software Support - Planning
Training Delivery to NON-IT
Tools
CMS Support
Discoverer Support
Ceridian Support
DBA Support - MOPS
IT Data Analyst
IT Data Governance
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
Total Dir Labor
Total Dir Labor
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
Total Dir Labor
Total Dir Labor
Total Dir Labor
Total Dir Labor
Total Dir Labor
Total Dir Labor
Total Dir Labor
Total Dir Labor
Total Dir Labor
Total Dir Labor
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
0.00%
0.00%
0.00%
0.00%
21.55%
21.55%
0.00%
0.00%
0.00%
0.00%
21.55%
21.55%
21.55%
21.55%
21.55%
21.55%
21.55%
21.55%
21.55%
21.55%
80.00%
80.00%
80.00%
80.00%
51.75%
51.75%
80.00%
80.00%
80.00%
80.00%
51.75%
51.75%
51.75%
51.75%
51.75%
51.75%
51.75%
51.75%
51.75%
51.75%
20.00%
20.00%
20.00%
20.00%
26.70%
26.70%
20.00%
20.00%
20.00%
20.00%
26.70%
26.70%
26.70%
26.70%
26.70%
26.70%
26.70%
26.70%
26.70%
26.70%
Per ISO-NE Staff
102
21600
21601
21603
21604
21605
21606
21607
DTS Support
DAM Support
Forecast Support
Total Dir Labor
Total Dir Labor
Total Dir Labor
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
21.55%
21.55%
21.55%
80.00%
20.00%
20.00%
20.00%
51.75%
51.75%
51.75%
20.00%
60.00%
60.00%
60.00%
26.70%
26.70%
26.70%
0.00%
20.00%
20.00%
20.00%
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Exhibit 3 (RCL-3)
Schedule 5.0
Page 7 of 7
TEST YEAR 2016
Line
No.
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
No.
(a)
Activity Code
Description
(b)
Allocation
Factor
(c)
Total
(d)
Self-Funding Tariff
(e)
(f)
Schedule 3
(g)
Reference
(h)
210
22501
22505
IT Change Management
Administrative
Alloc-Fixed
Alloc-Fixed
100.00%
100.00%
45.00%
34.00%
45.00%
33.00%
10.00%
33.00%
Per ISO-NE Staff
213
21702
21707
21709
21710
21711
6518
Employee Development - Software
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
Total Dir Labor
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
0.00%
0.00%
0.00%
0.00%
0.00%
21.55%
20.00%
80.00%
80.00%
80.00%
80.00%
51.75%
80.00%
20.00%
20.00%
20.00%
20.00%
26.70%
Per ISO-NE Staff
216
21650
21651
21652
21654
21655
21656
21657
21658
NX9 Administration
ICCP Support
Total Dir Labor
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
21.55%
40.00%
40.00%
40.00%
40.00%
80.00%
0.00%
0.00%
51.75%
40.00%
40.00%
40.00%
40.00%
20.00%
0.00%
0.00%
26.70%
20.00%
20.00%
20.00%
20.00%
0.00%
100.00%
100.00%
Per ISO-NE Staff
703
14801
14803
14804
14806
14808
14809
14810
14812
14813
14814
14815
Change Management
Tariff Compliance
NPCC MP Referral
Alloc-Fixed
OS Labor
OS Labor
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
Alloc-Fixed
Total Dir Labor
Total Dir Labor
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
40.00%
50.00%
50.00%
55.55%
45.00%
30.00%
85.00%
40.00%
40.00%
21.55%
21.55%
40.00%
0.00%
0.00%
19.33%
10.00%
60.00%
0.00%
40.00%
40.00%
51.75%
51.75%
20.00%
50.00%
50.00%
25.12%
45.00%
10.00%
15.00%
20.00%
20.00%
26.70%
26.70%
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Per ISO-NE Staff
Exhibit 3 (RCL-3)
Schedule 6.0
Page 1 of 2
FERC Docket No. ER16-____-000
ALLOCATION ON DEPRECIATION AND AMORTIZATION EXPENSE
TEST YEAR 2016
Line
No.
1
2
3
4
5
6
7
8
9
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47
48
49
50
51
52
53
54
55
56
57
58
59
60
61
62
63
64
Description
(a)
2016 Items:
Building Improvements
Back-up Control Center
Furniture, Fixtures, and Equipment
Non-Project Capital Spending (Hardware and Software)
Market Systems and Enhancement Projects
Non-Market Systems and Enhancement Projects
Total 2016 Items - $
Total 2016 Items - %
2015 Items:
2014 Items:
2013 Items:
2012 Items:
2011 Items:
Facilities Project
2010 Items:
Facilities Project
2009 Items:
Facilities Project
Total
(b)
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
250,000.00
455,472.23
535,334
1,240,806
4,895
29,237
621,694
8,105,314
1,499,330
10,260,470
18,243
234,329
71,660
1,480,659
5,536,872
904,949
8,246,713
21,402
935,877
148,566
1,183,562
4,357,464
1,787,497
8,434,369
20,450
159,069
1,629
35,392
1,409,941
745,866
2,372,346
40,667
4,031
155,689
419,185
619,573
7,715
1,537
2,508
91,430
103,190
7,100
616
313
3,425
11,454
Depreciation
Adjustments
(c)
$
Adj. Total
(d)
-
$
-
$
-
$
-
$
$
$
-
$
-
$
$
-
$
$
-
$
$
-
$
$
-
$
$
-
$
$
$
$
$
$
$
$
$
$
$
$
$
$
Total
(f)
(e)
250,000
455,472
535,334
1,240,806
$
4,895
29,237
621,694
8,105,314
1,499,330
10,260,470
$
18,243
234,329
71,660
1,480,659
5,536,872
904,949
8,246,713
$
21,402
935,877
148,566
1,183,562
4,357,464
1,787,497
8,434,369
$
20,450
159,069
1,629
35,392
1,409,941
745,866
2,372,346
$
40,667
4,031
155,689
419,185
619,573
$
7,715
1,537
2,508
91,430
103,190
$
7,100
616
313
3,425
11,454
$
$
$
$
$
$
$
$
$
$
250,000
455,472
535,334
1,240,806 $
100.00%
Self-Funding Tariff
Schedule 1
Schedule 2
(g)
(h)
$
53,875.00
98,154.26
81,228.17
233,257 $
18.80%
Schedule 3
(i)
$
129,375.00
66,750.00
235,706.88
121,611.08
200,774.13
253,331.92
565,856 $
441,693
45.60%
35.60%
4,895 $
1,055 $
2,533 $
1,307
29,237
6,300.61
15,130.25
7,806.33
621,694
133,975.00
321,726.50
165,992.22
8,105,314
2,822,043.91
3,490,220.03
1,793,049.69
1,499,330
543,387.71
721,925.46
234,017.30
10,260,470 $
3,506,762 $
4,551,536 $
2,202,173
100.00%
34.18%
44.36%
21.46%
18,243 $
234,329
71,660
1,480,659
5,536,872
904,949
8,246,713 $
100.00%
3,931 $
50,498
15,443
319,082
1,451,809
276,814
2,117,577 $
25.68%
9,441 $
121,265
37,084
766,241
1,729,241
242,139
2,905,411 $
35.23%
4,871
62,566
19,133
395,336
2,355,822
385,996
3,223,724
39.09%
21,402 $
935,877
148,566
1,183,562
4,357,464
1,787,497
8,434,369 $
100.00%
4,612 $
201,681
32,016
255,058
816,311
394,239
1,703,917 $
20.20%
11,076 $
484,316
76,883
612,493
1,934,893
559,996
3,679,657 $
43.63%
5,714
249,879
39,667
316,011
1,606,260
833,263
3,050,794
36.17%
20,450 $
159,069
1,629
35,392
1,409,941
745,866
2,372,346 $
100.00%
4,407 $
34,279
351
7,627
276,628
250,157
573,449 $
24.17%
10,583 $
82,318
843
18,315
589,505
176,670
878,234 $
37.02%
5,460
42,472
435
9,450
543,808
319,040
920,664
38.81%
40,667 $
4,031
155,689
419,185
619,573 $
100.00%
8,764 $
869
1,439
140,253
151,324 $
24.42%
21,045 $
2,086
67,415
126,127
216,674 $
34.97%
10,858
1,076
86,835
152,805
251,575
40.60%
7,715 $
1,537
2,508
91,430
103,190 $
100.00%
1,663 $
331
2,189
20,290
24,473 $
23.72%
3,993 $
796
287
46,248
51,323 $
49.74%
2,060
410
32
24,892
27,395
26.55%
7,100 $
616
313
3,425
11,454 $
100.00%
1,530 $
133
67
3,425
5,155 $
45.01%
3,674 $
319
162
4,155 $
36.28%
1,896
165
83
2,144
18.72%
Exhibit 3 (RCL-3)
Schedule 6.0
Page 2 of 2
FERC Docket No. ER16-____-000
ALLOCATION ON DEPRECIATION AND AMORTIZATION EXPENSE
TEST YEAR 2016
Line
No.
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47
48
49
Description
(a)
2008 Items:
Facilities Project
2007 Items:
Facilities Project
2006 Items:
Facilities Project
2005 Items:
Building/property improv. (Renov. workspace, network & voice rewiring)
Enhancements to Other Existing Market Systems
Hardware and Software Upgrades to existing Non Market Systems
Capital Interest/Fees
Internal Development Costs
Amortization of Reg Asset
2004 Items:
Building/property improv. (Renov. workspace, network & voice rewiring)
Enhancements to Other Existing Market Systems
Hardware and Software Upgrades to existing Non Market Systems
Internal Development Costs
Capital Interest/Fees
Total Budgeted Depreciation
-%
Total
(b)
$
$
$
$
$
$
10,373
4,652
15,026
162,196
162,196
570,733
570,733
Depreciation
Adjustments
(c)
Adj. Total
(d)
$
-
$
$
-
$
$
-
$
$
-
$
$
-
$
$
-
$
$
787,995
14,622
-
$
$
802,617
$
$
$
$
41,709
1,451
43,160
$
32,882,653
-
$
-
$
$
Total
(f)
(e)
10,373
4,652
15,026
$
162,196
162,196
$
570,733
570,733
$
787,995
14,622
802,617
$
$
$
$
-
$
41,709
1,451
43,160
$
-
$
32,882,653
$
$
$
$
$
Self-Funding Tariff
Schedule 1
Schedule 2
(g)
(h)
Schedule 3
(i)
10,373 $
4,652
15,026 $
100.00%
2,235 $
4,652
6,888 $
45.84%
5,368 $
5,368 $
35.73%
2,770
2,770
18.43%
162,196 $
162,196 $
100.00%
34,953 $
34,953 $
21.55%
83,936 $
83,936 $
51.75%
43,306
43,306
26.70%
570,733 $
570,733 $
100.00%
122,993 $
122,993 $
21.55%
295,355 $
295,355 $
51.75%
152,386
152,386
26.70%
787,995 $
14,622
802,617 $
100.00%
169,813 $
169,813 $
21.16%
407,787 $
9,577
417,365 $
52.00%
210,395
5,044
215,439
26.84%
41,709 $
1,451
43,160 $
100.00%
8,988 $
8,988 $
20.83%
21,585 $
950
22,535 $
52.21%
11,136
501
11,637
26.96%
32,882,653 $
100.00%
8,659,550 $
26.33%
13,677,404 $ 10,545,700
41.59%
32.07%
Exhibit 3
RCL-5
Schedule 1
2016 Operating Expense Budget
Line No.
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
Cost Category
(a)
Revenues and Other Income
Salaries and Overhead
Professional Fees & Consultants
Building Services
Rents/Leases
Communication Expenses
Computer Services
Data Services and Office Expenses
NPCC/NERC Dues
Insurance Expense
Meetings & Related Expenses
Education & Training
Regulatory Fees, Taxes, and Licenses
CEO Emerging Work Allowance
Net Expense before Depreciation and Debt Service
Amount
(b)
$
Depreciation and Debt Service
Total Operating Expense Budget
(440,506)
106,088,741
12,053,010
2,858,616
1,142,220
2,190,173
11,453,790
1,349,684
5,892,615
2,200,809
1,486,708
1,222,510
321,886
1,100,000
700,000
149,620,256
35,530,965
$
185,151,221
Exhibit 3
RCL - 5
Schedule 2
Page 1
Line No. Revenues and Other Income
Interest income
Includes fees for Participant training seminars and materials
Purchase Discounts
1
2
3
$
4
5
Salaries
Payroll Taxes and Employee Benefits
Board Fees and Expenses
6
7
8
9
10
11
(82,378)
(253,728)
(104,400)
(440,506)
78,266,951
26,651,380
1,170,410
106,088,741
Professional Fees and Consultants
Consulting
12
Information Technology support for market system and Energy Management
System daily operations, Network and Desktop Support, Architecture planning,
Cyber Security, IT Asset Management and Network Model Tools.
2,810,514
13
Market Advisor, Demand Resources, Market Development, Market Services,
Various R&D projects including special projects for Impact Analysis, and
Improved Tools & Optimization.
1,783,600
14
Resource Adequacy (including Forward Capacity Market Analytical & Auction
Work and Load Forecasting), Transmission Planning (including
OATT/Generation Interconnection Work & Project Planning, Elective
Transmission Upgrade Process, Short Circuit Analysis, and Bulk Power System
Testing & Investigation), Operations Project Support (including Integration of
Variable Resources), Operations, and Operations Planning.
1,886,636
15
Human Resource Consulting and Recruiting Services
1,462,260
16
Legal fees
1,810,000
Includes legal fees for OATT, regulatory filings, energy markets, market rules
and proceedings, Market Monitoring Support, Siting costs, billing disputes, new
initiatives/emerging issues funding, tariff and corporate matters, and
miscellaneous labor matters.
17
18
19
20
21
22
23
External Affairs
Corporate Communications Support
Market Monitoring
Auditors fees - SSAE Type 16 Audit, Network, Operations, Financial, Pension
Risk and Quality Management and Reliability and Operations Compliance
Finance Support and Payroll Service, Misc Other
24
25
26
27
426,898
205,110
746,000
700,300
58,200
163,492
12,053,010
Building Services
Repairs and maintenance
Utilities
318,066
1,456,500
Exhibit 3
RCL - 5
Schedule 2
Page 2
28
Miscellaneous (grounds keeping, supplies, building security)
1,084,050
2,858,616
Various office equipment leases
Auto leases and Auto Maintenance
1,082,577
59,643
1,142,220
Shared microwave
Network circuits and Internet circuits
Telephone and long distance lines
Miscellaneous maintenance and service items
228,600
883,528
775,664
302,381
2,190,173
29
30
Rents/Leases
31
32
33
34
Communications Expenses
35
36
37
38
39
40
Computer Services
Software and licensing costs
Maintenance contracts
Computer supplies
41
42
43
44
45
46
47
48
49
50
51
Data Services and Office expenses
Office supplies
Postage and courier
Printing Expense
Data Services, Dues, and subscriptions
Office equipment maintenance
Other Miscellaneous
52
53
54
1,641,550
9,646,040
166,200
11,453,790
113,429
41,000
118,425
951,965
100,000
24,865
1,349,684
NPCC/NERC Dues
55
56
Budget for NPCC and NERC Dues
Eastern Interconnect Data Sharing Network Allocation/Dues
5,822,615
70,000
5,892,615
Property and liability (including Cyber Security)
Directors and officers
1,862,925
337,884
2,200,809
57
58
59
Insurance Expense
60
61
62
63
64
65
1,486,708
Includes travel and related expenses for stakeholder meetings
throughout the region, for regulatory meetings and support including
FERC, NERC, NPCC, and state agencies, and for attendance at Industry
and Other Conference attendance, in addition to other miscellaneous
travel reimbursement and employee service recognition
Exhibit 3
RCL - 5
Schedule 2
Page 3
66
67
Includes funding for Enterprise wide training including Leadership and
Management Development, Cyber Security Degree Program, Technical
and NERC Certification Training, Communications and Presentation
Training, Management and General Training, and Education
Reimbursement
68
69
70
71
72
1,222,510
Regulatory Fees, Taxes and Licenses
Real estate tax
Business license and Bank Fees
240,000
81,886
321,886
73
74
75
New activities and initiatives that occur during the year.
76
1,100,000
77
78
79
Funding of last resort to cover unknown expenses.
700,000
80
81
82
83
Depreciation and Debt Service of Capitalized Costs
Depreciation and Amortization expense and Disposal
Interest expense
32,997,050
2,533,915
35,530,965
84
85
86
$
185,151,221
Exhibit 3
RCL-5
Schedule 3
Operating Expense Budget
Variance Summary
Proposed Year 2016 Budget vs 2015 Budget
(amounts in thousands)
Line No.
DESCRIPTION
Proposed
Annual Budget
2016
Original 2015
Budget
Variance 2016
Budget vs 2015
Budget
Inc/(Decrease)
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
Professional Fees & Consultants
Building Services
Rents/Leases
Computer Services
Data Services and Office Expenses
NPCC/NERC Dues
Insurance Expense
Regulatory Fees, Taxes, and Licenses
Net Expense before Depreciation and Debt Service
$
(440.5)
106,088.7
12,053.0
2,858.6
1,142.2
2,190.2
11,453.8
1,349.7
5,892.6
2,200.8
1,486.7
1,222.5
321.9
1,100.0
700.0
149,620.3
$
35,531.0
$
185,151.2
(445.8)
102,300.2
12,627.5
2,983.6
1,032.2
2,037.7
9,733.2
1,263.9
5,775.9
2,007.6
1,540.5
1,207.2
360.3
1,100.0
700.0
144,224.1
$
34,090.7
$
178,314.9
5.3
3,788.6
(574.5)
(125.0)
110.0
152.5
1,720.6
85.8
116.7
193.2
(53.8)
15.3
(38.4)
5,396.1
1,440.2
$
6,836.3
Change in Operating Expense Budgets
Proposed Year 2016 Budget vs. 2015 Budget
(Amounts in thousands)
Line No.
1
2
3
4
5
6
7
8
Exhibit 3
RCL-5
Schedule 4
Page 1
Interest Income
Participant Market Training Fees
Purchase Discounts
Total change in Revenues and Other Income
28.5
(23.3)
$
Merit and Promotion
3,186.0
9
Net Increase of 8.5 Additional Staff
1,060.0
10
Health Plan Rate Increase
Post Retirement Benefit and Pension Costs
11
12
13
14
Other (includes Increase in Internal Capital Development and Salary Rate Changes)
Total change in Salaries and Overhead
382.6
300.3
(1,140.3)
3,788.6
Professional Fees and Consultants
15
Legal - Reduction due to less reliance on external counsel and absorbtion of work by internal
counsel
(500.0)
16
Transmission Strategy & Services - FERC Order 1000 $(265)K, $(72.8) absorption by
internal staff.
(337.8)
17
Chief Operating Officer Admin - Impact Analysis $(100)K, Cyber Security $90K, and Other
Strategic Initiatives related funding $(200)K
(210.0)
18
Operations Support Services - Post-MPRP (Maine Power Reliability Program) out-study work
$(200)K
(200.0)
19
Market Operations Support Services - all consultant hours and fees absorbed by internal staff
(168.5)
20
Cyber Security - reduction in consulting for NERC CIP v5 Transition
(128.2)
21
Enterprise Risk Management - Information Governance Program Design completed by
internal staff in 2015
(61.0)
22
Market Monitoring - review of Offer Review Trigger Prices (ORTP) which is reuiqred once
each three years $250K, Internal Market Monitor (IMM) Data Infrastruture $150K, Other $46K
446.0
23
IT Power System Modeling Management - increase for Model On Demand consultant
$172.3K and NX9/NX12 Support $30K
202.3
24
Resource Adequacy - Calculation of CONE and Net CONE for FCA12
150.0
25
Market Development Admin - $75K for FCM Qualification Process Changes and $50K for
FCA Pricing Rules Analysis
125.0
26
Operations - increase in consulting related to NERC Std. PER-005-2 (training).
117.0
27
Other minor changes
28
29
30
5.3
Total change in Professional Fees and Consultants
Building Services
The primary change in the building services budget is a reduction in building security costs at
the Backup Control Center of $(185)K. The original plan was to utilize the local police force
but a private security firm was ultimately employed. Offsetting this reduction is increased
utility costs of $36.5K. Other miscellaneous repair and maintenance increases equal $23.5K.
Rents/Leases
The increase for 2016 is related to the expansion of the leasing program to replace old
laptops, desktops, and monitors.
(9.3)
(574.5)
(125.0)
31
32
33
110.0
Change in Operating Expense Budgets
Proposed Year 2016 Budget vs. 2015 Budget
(Amounts in thousands)
Exhibit 3
RCL-5
Schedule 4
Page 2
Line No.
34
Increases include $106K for maintenance and support on new Control Room phone systems
for both the Backup Control Center and Main Control Center, $33K for SIDU circuits for which
charge back to LCC's ended June 2015, and $12.6K for Shared Microwave.
Computer Services
The change in costs for Computer Services include inflationary increases and new software
maintenance as a result of software upgrades or enhancements completed, or will be
completed in 2015, of $599.4K (NetMRI/Infobox, Load Balancer, Smartnet Support, Citrix
Open Licenses, Net Scaler, EMC VPLEX (for BCP Phase III Markets), increased Microsoft
product pricing due to the elimination of "Charity Pricing" $530.7K, new IT Asset & License
Management software (Aspera) and consulting services to address Cyber Security initiatives
$347.6K, upgraded backup manager software $169.5K, licenses for intranet upgrade and
additional SAS licenses $124.5K. Other $(51.1)K
152.5
35
36
1,720.6
37
38
Increases in Dues & Subscriptions include $50K in Market Monitoring for FCM Capacity Price
Data Services and Office Expenses Forecast subscriptions, and $35.8K for various other small dollar increases and inflationary
items.
85.8
39
NPCC/NERC Dues
Primarliy due to pass through of increases in NPCC and NERC budgets of $112K plus a
small increase in Eastern Interconnect Data Sharing Network fees.
116.7
Insurance Expense
Funding for Cyber Insurance of $200K, Other $(6.8)K
193.2
Costs are essentially flat with minor decreases in travel in various departments
(53.8)
Costs are essentially flat with various adjustments in company training programs.
48
Regulatory Fees, Taxes, and
Licenses
Expected decrease in bank fees.
49
50
51
Total Change in Net Expense before Depreciation and Debt Service
40
41
42
43
44
45
46
47
52
Increases include Generation Control Application Phase I and Coordinated Transaction
Scheduling projects expected to be completed in the fourth quarter of 2015, Wind Integration
Phase II / Do Not Exceed (DNE) Dispatch project expected to go live in the first quarter of
2016, the Business Continuity Plan Infrastructure Enhancements Phase III – Markets
Infrastructure and Remote Desktop projects (Q4 2015), Critical Infrastructure Protection
(CIP) v5 project (Q4 2015), Forward Capacity Auction (FCA) 10 (Q1 2016), and other various
projects. These increases were partially offset by assets becoming fully depreciated in 2015
or 2016, and include the Energy Management System 2.6 Upgrade, Synchrophasor
Infrastructure and Data Utilization, Forward Capacity Market Enhancements 2012, Financial
Transmission Rights Multi-Round and Balancing Monthly Auctions, and other various projects
53
Interest Expense
Increase for fees and interest expense for the line of credit needed for clearing Financial
Transmission Rights through the clearinghouse; partially offset by a reduction in fees and
expense due to a lower outstanding amount of tax-exempt debt as principal payments are
made quarterly.
54
55
56
15.3
(38.4)
$
1,232.3
207.9
1,440.2
Total Depreciation and Debt Service
Total Change in Operating Expense Budget
5,396.2
$
6,836.3
Exhibit 3
RCL - 5
Schedule 5
Page 1
Line No.
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
Department
2015 Budget
Staff Level
2016 Budget
Staff Level
8.0
8.0
5.0
59.0
31.0
8.0
103.0
5.0
59.0
32.0
8.0
104.0
Resource Adequacy
Transmission Strategy & Services
System Planning
System Planning
24.0
19.0
9.0
8.0
3.0
63.0
23.0
17.0
11.0
10.0
2.0
63.0
Customer Service and Training
Markets Operations Administration
Settlements
Market Operations
Market Operations
14.0
6.0
13.0
20.0
25.0
78.0
13.0
6.0
14.0
20.0
25.0
78.0
Mkt Development Admin
Markets Development
Markets Development
5.0
3.0
11.0
2.0
21.0
5.0
3.0
11.0
2.0
21.0
27.0
20.0
7.0
15.0
37.0
6.0
2.0
12.0
21.0
4.0
3.0
1.0
155.0
27.0
20.0
13.0
15.0
37.0
6.0
2.0
13.0
21.0
4.0
3.0
1.0
162.0
10.0
10.0
COO - Administration
System Operations Management
Operations
System Operations
Energy Management Systems
Enterprise Applications Development
Cyber Security
Enterprise Applications Support
Systems/Network & Desktop
IT Management
IT System Testing
Power System Modeling Management
DB & Ent Support Services
Sftwr Dev & Pow Sys Supp Admin
Infra & Ent Supp Svs Admin
IT Asset & License Management
Exhibit 3
RCL - 5
Schedule 5
Page 2
Department
Line No.
44
45
46
47
48
49
50
51
52
53
54
55
56
57
58
59
60
61
62
63
64
65
66
67
68
69
70
71
72
73
74
2015 Budget
Staff Level
2016 Budget
Staff Level
21.0
20.0
459.0
466.0
9.0
9.0
Building Services
Reliability, Operations, and Compliance
Finance
Finance and Compliance
11.0
3.0
6.0
21.0
41.0
11.0
4.0
6.0
20.0
41.0
Legal Department
Corporate Communications & External Affairs
Legal and Public Affairs
14.0
17.0
31.0
14.0
17.0
31.0
Human Resources
13.0
13.0
5.0
4.0
13.0
16.0
5.0
5.0
Total Administration
117.0
119.0
Total FTE's
576.0
585.0
1.0
0.5
577.0
585.5
Program Management
Total COO
Chief Executive Officer - Administration
Market Monitoring and Mitigation
Market Monitoring Assessment and Investigation
Internal Audits
Total Part-timers (X @ 0.5)
Total Number of Employees
Note: Staffing levels are net of the estimated and budgeted vacancy.
Exhibit 3
RCL - 5
Schedule 6
2016 Capital Budget
Line No.
2016
Description
1
Capital Projects - Approved Charters
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
. Wind Integration Phase II / Do Not Exceed (DNE) Dispatch
. Divisional Accounting
. Forward Capacity Auction (FCA) 10
. Zonal Load Forecast
. Power System Modeling Management Initiatives
. NX9/NX12D - Generator Voltage Data
. Internet Explorer 11 Upgrade
Subtotal Projects with Approved Charters
Capital Projects in Conceptual Design
. Sub-hourly Settlements
. Fast-Start Pricing
. Submission of Financial Transmission Rights (FTR) for Clearing
. 2016 Issues Resolution Project
. Expand Energy Offers for Pumps
. Quarterly Release Projects 2016
. Asset Characteristic Database & User Interface Re-design
. Energy Management Platform Customs Elimination
. Operations Document Management System
. Transmart Rewrite
. Web Enhancements 2016
. Asset Registration Automation
. Dynamic Interchange Adjustment Tool
. Oracle 12c Upgrade
. Case Snapshot Enhancements for Market Operator Interface
. Price Responsive Demand
. Other Emerging Work Projects
Subtotal Conceptual Design
. Non-Project Capital Expenditures
. Capitalized Interest and loan fees
TOTAL Capital Projects (including Capitalized Interest)
$
2,472,000
496,800
590,000
225,000
145,000
50,000
12,000
3,990,800
3,000,000
2,500,000
2,500,000
1,800,000
1,500,000
900,000
800,000
700,000
600,000
600,000
500,000
500,000
500,000
300,000
100,000
100,000
100,000
1,809,200
18,809,200
3,700,000
500,000
$ 27,000,000
Exhibit 3
RCL-7
Schedule 1
FERC DOCKET NO. ER16
-000
Development of Escalation Factors
From CELT Report (As Published)
Month
Monthly Peak
Load
Monthly Net
Energy
(a)
(b)
(MW)
(c)
(GWH)
(d)
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
Aug-00
Sep-00
Oct-00
Nov-00
Dec-00
Jan-01
Feb-01
Mar-01
Apr-01
May-01
Jun-01
Jul-01
Aug-01
Sep-01
Oct-01
Nov-01
Dec-01
Jan-02
Feb-02
Mar-02
Apr-02
May-02
Jun-02
Jul-02
Aug-02
Sep-02
Oct-02
Nov-02
Dec-02
Jan-03
Feb-03
Mar-03
Apr-03
May-03
Jun-03
Jul-03
Aug-03
Sep-03
Oct-03
Data Source
From Monthly Market Reports
Monthly Peak Monthly Net
Load
Energy
Data Source
Line No.
21,736
21,369
18,021
18,642
20,088
19,833
19,357
18,622
16,854
18,904
22,358
23,952
24,967
20,594
17,246
18,116
19,872
19,241
19,260
18,327
18,450
18,287
22,953
24,780
25,348
22,370
19,373
18,763
20,850
21,533
20,410
20,223
18,126
16,783
24,494
23,981
24,685
19,339
18,148
11,173
10,068
9,989
10,051
11,572
11,466
10,058
10,719
9,425
9,818
10,873
10,936
12,246
10,017
9,978
9,751
10,689
11,009
9,785
10,331
9,557
9,769
10,317
12,132
12,345
10,379
10,258
10,191
11,382
12,042
10,612
10,848
9,954
9,758
10,450
12,269
12,627
10,332
10,228
(e)
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
(MW)
(f)
21,736
21,369
18,021
18,642
20,088
19,833
19,357
18,622
16,854
18,904
22,358
23,952
24,967
20,594
17,246
18,116
19,872
19,241
19,260
18,327
18,450
18,287
22,953
24,780
25,348
22,370
19,373
18,763
20,850
21,533
20,410
20,223
18,126
16,783
24,494
23,981
24,685
19,339
18,148
(GWH)
(g)
11,173
10,068
9,989
10,051
11,572
11,466
10,058
10,719
9,425
9,818
10,873
10,936
12,246
10,017
9,978
9,751
10,689
11,009
9,785
10,331
9,557
9,769
10,317
12,132
12,345
10,379
10,258
10,191
11,382
12,042
10,612
10,848
9,954
9,758
10,450
12,269
12,627
10,331
10,228
(h)
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Month
Monthly Peak
Load
Monthly Net
Energy
(a)
(b)
(MW)
(c)
(GWH)
(d)
40
41
42
43
44
45
46
47
48
49
50
51
52
53
54
55
56
57
58
59
60
61
62
63
64
65
66
67
68
69
70
71
72
73
74
75
76
77
78
79
80
81
82
83
84
85
86
87
88
89
Nov-03
Dec-03
Jan-04
Feb-04
Mar-04
Apr-04
May-04
Jun-04
Jul-04
Aug-04
Sep-04
Oct-04
Nov-04
Dec-04
Jan-05
Feb-05
Mar-05
Apr-05
May-05
Jun-05
Jul-05
Aug-05
Sep-05
Oct-05
Nov-05
Dec-05
Jan-06
Feb-06
Mar-06
Apr-06
May-06
Jun-06
Jul-06
Aug-06
Sep-06
Oct-06
Nov-06
Dec-06
Jan-07
Feb-07
Mar-07
Apr-07
May-07
Jun-07
Jul-07
Aug-07
Sep-07
Oct-07
Nov-07
Dec-07
Data Source
Load
Energy
Data Source
Line No.
18,551
20,771
22,818
19,977
19,246
18,042
18,281
22,940
23,147
24,116
20,829
17,763
19,044
22,631
22,141
19,887
20,178
17,024
16,710
25,231
26,885
25,983
22,425
18,970
19,330
21,733
20,559
20,458
19,598
17,146
19,411
24,070
27,329
28,130
19,168
18,036
18,945
20,702
21,034
21,640
21,439
18,071
20,463
26,055
24,332
26,145
22,570
19,323
19,141
21,164
10,123
11,534
12,627
10,862
10,896
9,872
10,107
10,772
11,911
12,311
10,687
10,315
10,395
11,761
12,235
10,534
11,332
9,832
10,010
11,870
12,949
13,332
11,190
10,671
10,463
11,938
11,509
10,504
11,010
9,630
10,239
11,331
13,365
12,380
10,244
10,384
10,237
11,255
11,754
10,983
11,208
10,137
10,455
11,139
12,380
12,656
10,778
10,599
10,542
11,837
(e)
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
(MW)
(f)
18,551
20,771
22,818
19,977
19,246
18,042
18,281
22,940
23,147
24,116
20,829
17,763
19,044
22,631
22,141
19,887
20,178
17,024
16,710
25,231
26,885
25,983
22,425
18,972
19,331
21,768
20,559
20,469
19,598
17,146
19,411
24,070
27,329
28,130
19,168
18,036
18,938
20,701
21,034
21,640
21,439
18,071
20,463
26,055
24,332
26,145
22,570
19,323
19,129
21,305
(GWH)
(g)
10,123
11,534
12,627
10,861
10,896
9,872
10,107
10,772
11,911
12,311
10,687
10,315
10,395
11,761
12,235
10,534
11,332
9,832
10,010
11,870
12,949
13,332
11,190
10,671
10,463
11,938
11,509
10,504
11,010
9,630
10,239
11,331
13,364
12,380
10,244
10,384
10,237
11,255
11,754
10,983
11,208
10,137
10,455
11,139
12,380
12,656
10,778
10,599
10,542
11,837
(h)
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Month
Monthly Peak
Load
Monthly Net
Energy
(a)
(b)
(MW)
(c)
(GWH)
(d)
90
91
92
93
94
95
96
97
98
99
100
101
102
103
104
105
106
107
108
109
110
111
112
113
114
115
116
117
118
119
120
121
122
123
124
125
126
127
128
129
130
131
132
133
134
135
136
137
138
139
Jan-08
Feb-08
Mar-08
Apr-08
May-08
Jun-08
Jul-08
Aug-08
Sep-08
Oct-08
Nov-08
Dec-08
Jan-09
Feb-09
Mar-09
Apr-09
May-09
Jun-09
Jul-09
Aug-09
Sep-09
Oct-09
Nov-09
Dec-09
Jan-10
Feb-10
Mar-10
Apr-10
May-10
Jun-10
Jul-10
Aug-10
Sep-10
Oct-10
Nov-10
Dec-10
Jan-11
Feb-11
Mar-11
Apr-11
May-11
Jun-11
Jul-11
Aug-11
Sep-11
Oct-11
Nov-11
Dec-11
Jan-12
Feb-12
Data Source
Load
Energy
Data Source
Line No.
21,782
20,498
18,377
16,992
17,884
26,111
24,723
22,189
22,189
17,685
19,375
21,022
20,701
20,338
19,622
18,082
17,736
18,468
22,621
25,081
18,215
17,326
17,935
20,791
19,901
19,289
18,202
16,356
22,823
24,237
27,102
25,691
25,902
18,272
18,237
20,622
21,053
19,980
18,790
16,590
19,847
23,322
27,707
23,344
20,315
17,270
17,819
19,357
19,926
18,333
11,751
10,877
11,002
9,814
9,891
11,338
13,021
11,567
10,614
10,185
10,297
11,387
12,004
10,144
10,543
9,517
9,667
9,953
11,292
12,553
9,890
10,004
9,750
11,525
11,568
10,143
10,351
9,373
10,173
11,230
13,384
12,258
10,670
9,953
10,061
11,606
11,732
10,376
10,690
9,581
9,998
10,731
12,934
11,983
10,609
9,861
9,749
10,918
11,266
10,100
(e)
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
(MW)
(f)
21,774
20,489
18,369
16,972
17,884
26,138
24,733
22,195
22,204
17,685
19,362
21,022
20,701
20,338
19,622
18,082
17,736
18,468
22,621
25,081
18,215
17,326
17,935
20,791
19,902
19,289
18,202
16,356
22,823
24,237
27,102
25,691
25,902
18,272
18,237
20,622
21,053
19,980
18,790
16,590
19,847
23,322
27,707
23,344
20,315
17,270
17,819
19,357
19,926
18,333
(GWH)
(g)
11,751
10,877
11,002
9,814
9,896
11,338
13,021
11,569
10,616
10,185
10,297
11,388
12,005
10,144
10,540
9,515
9,663
9,960
11,291
12,557
9,885
10,002
9,750
11,527
11,569
10,143
10,351
9,373
10,173
11,230
13,384
12,258
10,670
9,953
10,061
11,606
11,732
10,376
10,690
9,581
9,998
10,731
12,934
11,983
10,609
9,861
9,749
10,918
11,266
10,100
(h)
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Month
Monthly Peak
Load
Monthly Net
Energy
(a)
(b)
(MW)
(c)
(GWH)
(d)
140
141
142
143
144
145
146
147
148
149
150
151
152
153
154
155
156
157
158
159
160
161
162
163
164
165
166
167
168
169
170
171
172
173
174
175
176
177
178
179
180
181
182
183
184
185
186
187
188
189
Mar-12
Apr-12
May-12
Jun-12
Jul-12
Aug-12
Sep-12
Oct-12
Nov-12
Dec-12
Jan-13
Feb-13
Mar-13
Apr-13
May-13
Jun-13
Jul-13
Aug-13
Sep-13
Oct-13
Nov-13
Dec-13
Jan-14
Feb-14
Mar-14
Apr-14
May-14
Jun-14
Jul-14
Aug-14
Sep-14
Oct-14
Nov-14
Dec-14
Jan-15
Feb-15
Mar-15
Apr-15
May-15
Jun-15
Jul-15
Aug-15
Sep-15
Oct-15
Nov-15
Dec-15
Jan-16
Feb-16
Mar-16
Apr-16
Data Source
Load
Energy
Data Source
Line No.
18,371
16,412
19,869
25,678
25,880
24,751
21,439
16,681
18,792
19,119
20,887
19,463
18,460
16,781
22,479
25,129
27,379
22,416
24,451
17,207
19,058
21,453
21,334
19,654
19,696
16,011
16,222
21,263
24,443
22,694
23,715
17,053
18,369
19,812
20,556
20,070
19,635
17,735
19,905
25,230
28,251
28,251
23,160
18,670
20,350
22,740
22,740
21,505
19,770
17,870
10,104
9,297
10,045
10,698
12,837
12,740
10,164
9,751
10,072
10,998
11,508
10,224
10,588
9,432
9,835
10,944
13,646
11,573
10,118
9,867
10,142
11,500
12,022
10,468
11,037
9,452
9,463
10,400
12,244
11,229
10,236
9,710
9,968
10,926
11,713
11,015
11,524
10,092
10,440
11,664
13,357
13,014
10,854
10,549
10,794
12,194
12,771
11,166
11,643
10,186
(e)
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Forecast
Forecast
Forecast
Forecast
Forecast
Forecast
Forecast
Forecast
Forecast
Forecast
Forecast
Forecast
Forecast
Forecast
(MW)
(f)
18,371
16,412
19,869
25,678
25,880
24,751
21,439
16,681
18,792
19,133
20,887
19,463
18,460
16,781
22,479
25,129
27,379
22,416
24,451
17,207
19,058
21,453
21,334
19,654
19,696
16,011
16,222
21,263
24,443
22,694
23,715
17,053
18,369
19,843
20,583
20,108
18,848
16,455
19,505
20,895
24,398
28,251
23,160
18,670
20,350
22,740
22,740
21,505
19,770
17,870
(GWH)
(g)
10,104
9,297
10,045
10,698
12,837
12,740
10,164
9,751
10,072
11,008
11,508
10,224
10,588
9,432
9,835
10,944
13,646
11,573
10,118
9,867
10,142
11,500
12,022
10,468
11,037
9,452
9,463
10,400
12,244
11,229
10,236
9,710
9,968
10,945
11,732
11,032
10,869
9,239
9,710
10,146
12,077
13,014
10,854
10,549
10,794
12,194
12,771
11,166
11,643
10,186
(h)
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Forecast
Forecast
Forecast
Forecast
Forecast
Forecast
Forecast
Forecast
Forecast
Month
Monthly Peak
Load
Monthly Net
Energy
(a)
(b)
(MW)
(c)
(GWH)
(d)
190
191
192
193
194
195
194
195
May-16
Jun-16
Jul-16
Aug-16
Sep-16
Oct-16
Nov-16
Dec-16
Data Source
Load
Energy
Data Source
Line No.
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
20,008
25,463
28,673
28,673
23,338
18,770
20,500
22,920
2001
2002
2003
2004
2005
2006
2007
2008
2009
2010
2011
2012
2013
2014
2015
2016
Average
20,056
20,667
20,587
20,736
21,375
21,129
21,781
20,736
19,743
21,386
20,450
20,438
21,264
20,022
22,046
22,519
2002
2003
2004
2005
2006
2007
2008
2009
2010
2011
2012
2013
2014
2015
2016
1.0304
0.9961
1.0072
1.0308
0.9885
1.0309
0.9520
0.9521
1.0832
0.9562
0.9994
1.0404
0.9416
1.1011
1.0215
Dec-00
Dec-01
Average
19,971
20,159
10,539
11,777
13,489
13,143
10,960
10,661
10,912
12,336
(e)
Forecast
Forecast
Forecast
Forecast
Forecast
Forecast
Forecast
Forecast
(MW)
(f)
20,008
25,463
28,673
28,673
23,338
18,770
20,500
22,920
Annualized Figures
Average
20,056
20,667
20,587
20,736
21,378
21,130
21,792
20,736
19,743
21,386
20,450
20,439
21,264
20,025
21,164
22,519
Annual Escalation
1.0117
1.0304
1.0261
0.9961
1.0133
1.0072
1.0290
1.0309
0.9687
0.9884
1.0180
1.0314
0.9797
0.9515
0.9628
0.9521
1.0310
1.0832
0.9877
0.9562
0.9916
0.9995
1.0102
1.0404
0.9828
0.9417
1.0791
1.0569
1.0173
1.0641
1.009
Last Five Months of Calendar Year
Total
Average
52,852
19,971
52,681
20,159
Total
125,976
127,455
130,776
132,517
136,355
132,087
134,468
131,743
126,842
130,770
129,162
128,072
129,377
127,155
137,210
139,583
(GWH)
(g)
10,539
11,777
13,489
13,143
10,960
10,661
10,912
12,336
(h)
Forecast
Forecast
Forecast
Forecast
Forecast
Forecast
Forecast
Forecast
Total
125,976
127,455
130,776
132,515
136,356
132,087
134,468
131,754
126,839
130,771
129,162
128,082
129,377
127,174
132,210
139,583
1.0117
1.0261
1.0133
1.0290
0.9687
1.0180
0.9798
0.9627
1.0310
0.9877
0.9916
1.0101
0.9830
1.0396
1.0558
1.007
NOT USED
Total
52,853 Actual
52,681 Actual
Month
Monthly Peak
Load
Monthly Net
Energy
(a)
(b)
(MW)
(c)
(GWH)
(d)
40
41
42
43
44
45
46
47
48
49
50
51
52
53
54
55
56
57
58
59
60
61
62
63
64
65
66
67
68
69
70
Dec-02
Dec-03
Dec-04
Dec-05
Dec-06
Dec-07
Dec-08
Dec-09
Dec-10
Dec-11
Dec-12
Dec-13
Dec-14
Dec-15
Data Source
Load
Energy
Data Source
Line No.
Dec-01
Dec-02
Dec-03
Dec-04
Dec-05
Dec-06
Dec-07
Dec-08
Dec-09
Dec-10
Dec-11
Dec-12
Dec-13
Dec-14
Dec-15
(e)
(MW)
(f)
(GWH)
(g)
21,341
54,554
21,341
54,555
20,299
54,844
20,299
54,843
20,877
55,469
20,877
55,469
21,688
57,593
21,696
57,594
20,996
54,499
20,995
54,500
21,669
56,412
21,694
56,412
20,492
54,050
20,494
54,055
19,870
53,722
19,870
53,721
21,745
54,548
21,745
54,548
19,621
53,120
19,621
53,120
20,156
53,725
20,159
53,735
20,917
53,200
20,917
53,200
20,329
52,069
20,335
52,088
22,634
57,405
22,634
57,405
Escalation Used for Last Five Months of Calendar Year
1.0094
0.9967
1.0586
1.0356
0.9512
1.0053
1.0285
1.0114
1.0392
1.0383
0.9677
0.9463
1.0333
1.0351
0.9446
0.9582
0.9696
0.9938
1.0944
1.0154
0.9023
0.9738
1.0274
1.0116
1.0376
0.9900
0.9722
0.9791
1.1131
1.1021
1.010
1.006
(h)
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Forecast
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Forecast
NOT USED
Exhibit 3
RCL-7
Schedule 2
-000
Billing Determinants for Calendar Year 2015 and Test Year 2016
TEST YEAR 2016
Schedule 2
Schedule 1
Transaction Units (TUs)
Network Load
Line
No.
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
Month
Data
Source
(kW)
Energy TUs
Submitted
Virtual Energy
(c)
(d)
(e)
(a)
(b)
Jan-15
Feb-15
Mar-15
Apr-15
May-15
Jun-15
Jul-15
Aug-15
Sep-15
Oct-15
Nov-15
Dec-15
Totals
Actual
Actual
Actual
Actual
Actual
Actual
Actual
Est.
Est.
Est.
Est.
Est.
20,287,685
19,910,998
18,580,936
16,133,097
19,305,827
20,826,343
24,144,201
22,211,418
23,367,341
16,828,635
18,043,001
19,498,319
239,137,801
Jan-16
Feb-16
Mar-16
Apr-16
May-16
Jun-16
Jul-16
Aug-16
Sep-16
Oct-16
Nov-16
Dec-16
Total
Est.
Est.
Est.
Est.
Est.
Est.
Est.
Est.
Est.
Est.
Est.
Est.
20,267,397
19,891,087
18,562,355
16,116,964
19,286,521
20,805,517
24,120,057
22,189,207
23,343,974
16,811,806
18,024,958
19,478,821
238,898,663
Escalation Factors
a
a
a
a
a
1,598,514
1,443,266
1,567,775
1,469,579
1,536,549
1,545,562
1,649,755
1,581,723
1,476,222
1,476,829
1,455,383
1,589,250
18,390,407
b
b
b
b
b
b
b
b
b
b
b
b
1,545,763
1,395,638
1,516,038
1,421,083
1,485,843
1,494,558
1,595,313
1,529,526
1,427,507
1,428,094
1,407,355
1,536,805
17,783,524
a
b
c
d
e
f
1.000
0.999
0.967
0.985
1.010
0.655
a
a
a
a
a
c
c
c
c
c
c
c
c
c
c
c
c
244,782
270,554
312,726
385,557
394,561
297,407
357,828
260,925
234,132
293,861
300,057
274,574
3,626,964
244,782
270,554
312,726
385,557
394,561
297,407
357,828
260,925
234,132
293,861
300,057
274,574
3,626,964
Cleared
Virtual
Energy
a
a
a
a
a
a
a
a
a
a
a
a
a
a
a
a
a
Schedule 3
(FTRs)
Submitted
FTR Bids
(f)
(g)
CALENDAR YEAR 2015
29,718
84,452
26,840
27,931
46,881
21,711
44,346
27,516
40,577
19,761
35,013
19,526
32,054
15,856
23,438 a
24,568
32,643 a
21,661
32,126 a
26,780
31,070 a
24,985
36,265 a
20,030
410,971
334,777
TEST YEAR 2016
29,718 a
26,840 a
46,881 a
44,346 a
40,577 a
35,013 a
32,054 a
23,438 a
32,643 a
32,126 a
31,070 a
36,265 a
410,971
84,452
27,931
21,711
27,516
19,761
19,526
15,856
24,568
21,661
26,780
24,985
20,030
334,777
a
a
a
a
a
a
a
a
a
a
a
a
a
a
a
a
a
Volumes
Cleared
FTR Bids
(GWH)
Peak Volumes
Electrical Load
(kW)
(h)
(i)
(j)
20,424
8,778
6,340
7,886
6,000
6,410
6,834
10,446
9,091
9,959
10,656
8,109
110,933
20,424
8,778
6,340
7,886
6,000
6,410
6,834
10,446
9,091
9,959
10,656
8,109
110,933
a
a
a
a
a
a
a
a
a
a
a
a
a
a
a
a
a
24,041,826
22,683,446
22,419,291
19,296,344
20,676,276
21,688,837
25,589,169
23,683,152
21,287,121
20,012,028
20,570,086
22,400,407
264,347,983
23,681,199
22,343,195
22,083,001
19,006,899
20,366,132
21,363,505
25,205,332
23,327,905
20,967,814
19,711,847
20,261,534
22,064,401
260,382,763
a
a
a
a
a
d
d
d
d
d
d
d
d
d
d
d
d
22,584,487
22,549,635
21,106,685
18,776,591
21,397,099
22,504,650
26,585,742
24,604,508
25,891,654
19,444,208
20,655,779
21,958,836
268,059,874
22,810,332
22,775,131
21,317,752
18,964,357
21,611,070
22,729,697
26,851,599
24,850,553
26,150,571
19,638,650
20,862,337
22,178,424
270,740,473
a
a
a
a
a
e
e
e
e
e
e
e
e
e
e
e
e
Export
Volumes
(MWh)
(k)
215,186
253,954
257,365
335,199
537,076
611,054
589,243
527,741
308,904
202,991
226,396
174,495
4,239,604
140,947
166,340
168,574
219,555
351,785
400,240
385,954
345,670
202,332
132,959
148,289
114,294
2,776,941
a
a
a
a
a
f
f
f
f
f
f
f
f
f
f
f
f
Exhibit 3
RCL-7
Schedule 3
Rate Design Summary
TEST YEAR 2016
Line
No.
Revenue
Requirement for
Test Year 2016
(b)
Tariff Schedule
(a)
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
Schedule 1
Network
Through or Out Service
$
Schedule 2
Transaction Units
INC Offers/DEC Bids
Submitted
Cleared
$
$
$
Submitted FTR Bids
Cleared FTR Bids
$
$
$
970,196
679,137
291,059
$
11,343,007
Energy TUs
Block 1
Block 2
Block 3
Volumetric Measures
Block 1
Block 2
Block 3
Billing Units
Blocks
(c)
Proposed Rates
Total
(d)
(e)
Calculated Revenue
(f)
(g)
(d) x (e)
46,048,796
Total
82,373,310
12,355,997
42,793
238,898,663
$
$
0.19275
0.00026
/kW-mo.
/kW-hour
$
46,048,796
$
$
0.00500
0.06000
/Offer or Bid
/Offer or Bid
Total
3,626,964
410,971
4,037,935
$
$
$
18,135
24,658
42,793
70%
30%
Total
334,777
110,933
445,710
$
$
2.02863
2.62374
/Bid
/Bid
$
$
$
679,137
291,059
970,196
12,500
27,000
39,500
12,158,008
3,438,723
2,186,793
17,783,524
$
$
$
0.66437
0.60397
0.54358
/TU-hour
/TU-hour
/TU-hour
$
$
$
$
8,077,423
2,076,896
1,188,688
11,343,007
250,000
1,250,000
1,500,000
133,352,189
111,785,794
15,244,780
260,382,763
$
$
$
0.28296
0.25723
0.23151
/mWh
/mWh
/mWh
$
$
$
$
37,732,929
28,755,062
3,529,323
70,017,314
$
82,373,310
$
$
$
54,996,595
1,110,776
56,107,371
$
184,529,477
15.00%
First
Next
Over
Total
$
-000
70,017,314
85.00%
First
Next
Over
Total
Total
Schedule 3
RT NCP Load Obligation
Exports
$
$
$
56,107,371
54,996,595
1,110,776
Totals
$
184,529,477
Total
Total
270,740,473
2,776,941
$
$
0.20313
0.40000
/kW-mo.
/mWh
Exhibit 3
RCL-7
Schedule 4
-000
Annual Revenue Comparison at Present and Proposed Rates
TEST YEAR 2016
Annual Revenue Analysis
Line
No.
Blocks
(b)
(a)
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
Schedule 1
Network
Total
Total
3,626,964
410,971
4,037,935
Total
334,777
110,933
445,710
Submitted FTR Bids
Cleared FTR Bids
Volumetric Measures
Block 1
Block 2
Block 3
Total
(c)
238,898,663
Schedule 2
Transaction Units
INC Offers/DEC Bids
Submitted
Cleared
Energy Transaction Units
Block 1
Block 2
Block 3
2015 Approved Rates
2016 Billing Units
Tariff Schedule
Effective Rates
(d)
$0.15570
Totals
(f)
(c) x (d)
$
37,196,522
$0.00500 /Offer or Bid
$0.06000 /Offer or Bid
$
$
$
18,135
24,658
42,793
$0.85853 /Bid
$1.21377 /Bid
$
$
$
287,416
134,647
422,063
Proposed Rates
(g)
$ 0.19275
Total Revenue (1)
(h)
/kW-mo.
Change
$
(j)
(i) - (f)
(i)
$
46,048,796
$ 0.00500 /Offer or Bid $
$ 0.06000 /Offer or Bid $
$
18,135
24,658
42,793
$ 2.02863 /Bid
$ 2.62374 /Bid
$
$
$
679,137
291,059
970,196
%
(k)
(j) / (f)
$
8,852,274
23.80%
First
Next
Over
Total
12,500
27,000
39,500
12,158,008
3,438,723
2,186,793
17,783,524
$0.65101
$0.59182
$0.53264
/TU-hour
/TU-hour
/TU-hour
$
$
$
$
7,914,985
2,035,105
1,164,773
11,114,863
$ 0.66437
$ 0.60397
$ 0.54358
/TU-hour
/TU-hour
/TU-hour
$
$
$
$
8,077,423
2,076,896
1,188,688
11,343,007
First
Next
Over
Total
250,000
1,250,000
1,500,000
133,352,189
111,785,794
15,244,780
260,382,763
$0.25517
$0.23197
$0.20877
/mWh
/mWh
/mWh
$
$
$
$
34,027,478
25,930,951
3,182,653
63,141,081
$ 0.28296
$ 0.25723
$ 0.23151
/mWh
/mWh
/mWh
$
$
$
$
37,732,929
28,755,062
3,529,323
70,017,314
$
74,720,801
$
82,373,310
$
7,652,509
10.24%
$
$
$
50,799,035
1,027,468
51,826,503
$
$
$
54,996,595
1,110,776
56,107,371
$
4,280,868
8.26%
$
163,743,826
$
184,529,477
$
20,785,651
12.69%
Total
Schedule 3
RT NCP Load Obligation
Exports
Calculated Revenue
(e)
/kW-mo.
2016 Proposed Rates
Total
Total
270,740,473
2,776,941
$0.18763
$0.37000
/kW-mo.
/mWh
$ 0.20313
$ 0.40000
/kW-mo.
/mWh
Exhibit 3
RCL-7
Schedule 5
-000
Comparison of Schedule 2 Revenues from Transaction Units (TUs) for 2014
TEST YEAR 2016
Comparison Of Monthly TU Data For CY 2014
TUs Per ISO Tariff Filing for TY 2014
Line
No.
Month
(a)
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
Jan-14
Feb-14
Mar-14
Apr-14
May-14
Jun-14
Jul-14
Aug-14
Sep-14
Oct-14
Nov-14
Dec-14
Totals
Source For TY
2014
(b)
1,379,716
1,259,732
1,364,713
1,282,913
1,373,080
1,404,103
1,465,640
1,401,678
1,337,862
1,335,119
1,277,896
1,364,206
16,246,658
Totals
2014 Approved Rates for
Schedule 2
16,246,658
Jan-13
Feb-13
Mar-13
Apr-13
May-13
Jun-13
Jul-13
Aug-12
Sep-12
Oct-12
Nov-12
Dec-12
Total Energy TU- Revenue
$
$
$
$
$
$
$
$
$
$
$
$
$
973,388
891,912
963,525
907,803
969,947
991,446
1,034,513
990,236
945,152
943,214
902,788
963,763
11,477,688
$
11,477,688
TUs Per ISO Tariff Filing for CY 2014
Source For
Over
Total TUs
TY 2016
39500
(f)
(g)
(h)
Billing Determinants - Energy TUs
135,309
Actual
1,530,445
99,170
Actual
1,399,304
127,446
Actual
1,495,523
106,321
Actual
1,409,469
126,020
Actual
1,463,493
137,309
Actual
1,483,121
148,305
Actual
1,583,869
129,415
Actual
1,581,723
123,523
Actual
1,476,222
123,269
Actual
1,476,829
117,986
Actual
1,455,383
125,955
Actual
1,589,250
1,500,028
17,944,631
Next
27000
(e)
972,182
910,954
966,058
925,210
977,522
1,001,793
1,044,898
999,955
954,429
952,472
911,649
973,223
11,590,346
272,225
249,608
271,209
251,382
269,538
265,001
272,437
272,308
259,910
259,377
248,260
265,028
3,156,284
$
$
$
$
$
$
$
$
$
$
$
$
$
711,316
666,518
706,836
676,948
715,224
732,982
764,521
731,637
698,327
696,895
667,027
712,078
8,480,309
$0.66515
$
$
$
$
$
$
$
$
$
$
$
$
$
181,070
166,027
180,395
167,207
179,283
176,265
181,211
181,126
172,879
172,525
165,130
176,283
2,099,402
$0.59864
Initial Estimate of Revenue From Energy TUs
$
81,001
Actual
$
1,078,664
$
59,367
Actual
$
988,546
$
76,294
Actual
$
1,054,512
$
63,648
Actual
$
995,448
$
75,441
Actual
$
1,032,619
$
82,199
Actual
$
1,045,556
$
88,781
Actual
$
1,114,675
$
77,473
Actual
$
1,113,182
$
73,946
Actual
$
1,042,191
$
73,794
Actual
$
1,042,680
$
70,631
Actual
$
1,027,480
$
75,402
Actual
$
1,118,015
$
897,977
$
12,653,569
$
Total
2,760,474
279,137
Rate
$0.00500
$0.06000
$
Total
Submitted FTR Bid TUs
Cleared FTR Bid TUs
331,175
99,327
Rate
$1.23712
$1.76776
$
$
12,093,526
True-Up - Over (Under) Recovery For Jan - Dec
First
12500
(i)
1,083,555
1,012,994
1,065,153
1,018,234
1,047,178
1,052,913
1,103,656
1,101,594
1,052,676
1,059,149
1,043,632
1,105,948
12,746,682
Next
27000
(j)
Over
39500
(k)
275,647
242,196
263,635
243,991
258,717
265,098
296,023
297,011
277,075
266,013
261,547
293,228
3,240,181
171,243
144,114
166,735
147,244
157,598
165,110
184,190
183,118
146,471
151,667
150,204
190,074
1,957,768
17,944,631
$0.73167
Submitted Virtual Energy Bids/Offers TUs
Cleared Virtual Energy Bids/Offers TUs
Total Schedule 2 TU- Revenue
44
45
(c)
Jan-13
Feb-13
Mar-13
Apr-13
May-13
Jun-13
Jul-13
Aug-12
Sep-12
Oct-12
Nov-12
Dec-12
Jan-14
Feb-14
Mar-14
Apr-14
May-14
Jun-14
Jul-14
Aug-14
Sep-14
Oct-14
Nov-14
Dec-14
Totals
First
12500
(d)
Total TUs
$0.73167
$0.66515
$
792,805
$
741,177
$
779,340
$
745,011
$
766,189
$
770,385
$
807,512
$
806,003
$
770,211
$
774,948
$
763,594
$
809,189
$ 9,326,365
$
183,347
$
161,097
$
175,357
$
162,291
$
172,086
$
176,330
$
196,900
$
197,557
$
184,296
$
176,939
$
173,968
$
195,041
$ 2,155,206
$0.59864
$
$
$
$
$
$
$
$
$
$
$
$
$
102,513
86,272
99,814
88,146
94,344
98,841
110,264
109,622
87,683
90,794
89,918
113,786
1,171,998
12,653,569
($)
13,802
16,748
30,551
($)
Total
2,896,433
335,394
409,701
175,586
585,288
449,377
144,431
Rate
$0.00500
$0.06000
$
Total
Rate
$1.23712
$1.76776
$
$
13,499,428
$
1,405,902
($)
14,482
20,124
34,606
($)
555,933
255,319
811,253
Exhibit 3
RCL-7
Schedule 6
FERC DOCKET NO. ER16-000
Schedule 2 TU True-Up Summary
TEST YEAR 2016
Line
No.
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
Total Schedule 2 TU
Revenues
Final 2014 True-Up
2014 Final TU Collections
Projected TU Collections in TY 2014 Filing
Final Schedule 2 TU Over/(Under) Collection
$
$
$
Initial Allocation to Volumetric 50%
2014 Final True-Up (as calculated above)
Total Projected Undercollection to Vol. Meas.
Schedule 2 Allocation before True-up
Allocated TU Under-recovery
16 Total Revenue Requirement After True-Up
17 % Allocation
13,499,428
12,093,526
1,405,902
% TU Difference
11.63%
N/A - Over Collected
Allocated to
$
$
$
Total
82,373,310 $
$
82,373,310 $
100.00%
TUs
12,355,997 $
$
12,355,997 $
15.00%
VMs
70,017,314
70,017,314
85.00%
Exhibit 3
RCL-8
NEW ENGLAND POWER POOL
PARTICIPANTS COMMITTEE MEETING
October 2, 2015
RESOLUTION REGARDING THE ISO 2016 BUDGET
RESOLVED, that the Participants Committee supports the Year 2016
operating budget and capital budget proposed by the ISO, as presented at
this meeting.
EXHIBIT 4
BEFORE THE
)
TESTIMONY
OF
JANICE S. DICKSTEIN
Filed on:
October 16, 2015
Docket No. ER16-___-000
1
2
3
4
5
6
7
8
Page 1
BEFORE THE
9
)
Docket No. ER16-___-000
Testimony of Janice S. Dickstein
10
Q:
PLEASE STATE YOUR NAME, TITLE AND BUSINESS ADDRESS.
11
A.
My name is Janice S. Dickstein. I am the Vice President of Human Resources
12
with the ISO. My business address is One Sullivan Road, Holyoke,
13
Massachusetts 01040.
14
Q:
PLEASE DESCRIBE, BRIEFLY, YOUR EDUCATIONAL AND
15
EMPLOYMENT BACKGROUND AND THE SCOPE OF YOUR
16
CURRENT POSITION AT ISO NEW ENGLAND.
17
A.
I am currently Vice President, Human Resources of ISO New England Inc. (the
18
“ISO” or “ISO-NE”) and have served in that role since joining the ISO in
19
September, 2004. In this role, my department and I provide compensation,
20
benefits, staffing, university recruiting, training, employee relations, and
21
talent/succession management support to the ISO. I also support the
22
Compensation and Human Resources Committee of the Board of Directors as
Page 2
1
well as the Joint Nominating Committee, which is responsible for nominating
2
directors to the Board.
3
I hold a B.S. in Psychology from Tufts University. I have worked for
4
Massachusetts Mutual Life Insurance Company and CIGNA in a variety of
5
functions, including technical training, university recruiting, and human
6
resources. When I left CIGNA for ISO New England I was CIGNA’s Vice
7
President, Human Resources: Sales, Marketing and Field Operations, and was
8
responsible for building human resources strategies to support business objectives
9
and was managing a large, multi-functional, geographically-dispersed staff.
10
Q:
11
A.
My testimony discusses the components of the proposed 2016 administrative
12
expenses related to compensation.
13
Q:
HOW IS YOUR TESTIMONY ORGANIZED?
14
A.
My testimony is organized as follows:
15
•
objective of compensation program
16
•
components of compensation
17
•
budget for merit and promotional salary increases
18
•
framework for determining executive compensation
1
OBJECTIVE OF COMPENSATION PROGRAM
2
Q.
3
4
Page 3
WHAT IS THE OBJECTIVE OF THE ISO’S COMPENSATION
PROGRAM?
A.
The objective of the compensation program is to offer competitive compensation
5
that enables the ISO to attract and retain the highly-skilled employees needed to
6
lead the ISO and meet its business goals for the New England region. We believe
7
that meeting this objective is ultimately less expensive than high levels of
8
turnover, considering the costs of recruiting, relocation, development time and the
9
disruption of workflow.
10
Q.
11
12
WHAT ARE THE CHALLENGES TO MEETING THE OBJECTIVE OF
THE ISO’S COMPENSATION PROGRAM?
A.
There are two primary challenges. The first is that there is a shortage of critical
13
talent in the utility industry. The second challenge is that the most critical
14
functions within our organization, IT and engineering, are also the most difficult
15
to recruit for and retain.
16
Q.
17
18
PLEASE DESCRIBE THE SHORTAGE OF CRITICAL TALENT IN THE
UTILITY INDUSTRY.
A.
As documented by numerous studies over the past several years, the electric
19
industry workforce is considered to be the oldest aged workforce in the United
20
States, with close to 50% of the workforce eligible to retire in the next several
21
years.
Page 4
1
In January of 2012, the National Regulatory Research Institute wrote that “[t]he
2
energy industry is facing an impending workforce shortage. The shortage reflects
3
an unprecedented number of retirements expected to occur in the next decade,
4
coupled with increasing energy demand...” The U.S. Department of Labor
5
predicts that 500,000 energy industry workers will retire in the next decade, a
6
turnover rate of 50 percent. These statistics have been confirmed in a number of
7
more recent writings.
8
A February 2014 Congressional Research Report entitled “The U.S. Science and
9
Engineering Workforce: Recent, Current, and Projected Employment, Wages,
10
and Unemployment,” which was prepared for Members and Committees of
11
Congress, reported that, between 2008 and 2012, the employment growth for
12
computer science professionals and electric engineers exceeded that of the general
13
population. The research paper also projected that employment growth for this
14
same technical sector would exceed that of the general population through 2022.
15
In May of 2014, Forbes.com reported on the lack of skilled workers. Quoting
16
Manpower Group, Forbes.com stated that “[t]his dichotomy exists in a world
17
where jobs in the energy industry are expected to nearly double to 3 million by
18
2020. But its research says that 72 percent of energy employers are having
19
difficulty finding quality candidates to fill their positions. The reason for that is
20
because the experts are getting on and getting ready to retire while rapid
21
evolutions in technology are altering the way business is done.”
1
Page 5
And, in February of 2015, a U.S. News & World Report article reported that:
2
3
4
5
6
7
8
9
10
11
12
13
About half of the workforce in engineering and advanced manufacturing is
approaching retirement, and the growth in the percentage of young
workers is not keeping pace… In fact, the number of young STEM
workers has actually declined since 2001, said Claus von Zastrow, chief
operating officer and director of research for Change the Equation. “Since
2001, the percentage of non-STEM workers under the age of 25 has
increased by 1 percent… Meanwhile, the percentages of engineering and
computing workers under 25 have decreased by 25 percent and 15
percent….This is not because these jobs aren't available. Every other
indicator we have shows there's actually robust demand here…We're
going to need all the talent we can get – we're going to need all hands on
deck.…”
14
15
16
17
18
19
According to the U.S. News/Raytheon STEM Index, high school student
interest in STEM fields reached a low point in 2004, dropping nearly 19
percent from the base-year calculations. Interest levels climbed steadily
until 2009, when they began to decline again. In spite of the intense drive
to encourage students to study science, interest levels fell between 2009
and 2013 and are now just slightly below where they were in 2000.
20
Q.
PLEASE DESCRIBE THE CHALLENGE IN RECRUITING FOR THE
21
MOST CRITICAL FUNCTIONS WITHIN THE ORGANIZATION (IT
22
AND ENGINEERING).
23
A.
This theme was highlighted in both Mercer’s 2015/2016 U.S. Compensation
24
Planning survey and Aon Hewitt’s 2015 U.S. Salary Increase survey. Mercer
25
survey respondents cited losing top performers and the ability to afford their
26
replacements as the most pressing issue facing their organizations. Aon Hewitt
27
survey respondents reported the highest use of sign-on and retention bonus
28
programs for their IT and engineering positions. In addition to attraction and
29
retention pressures, starting salaries of new graduates in IT and engineering
Page 6
1
positions in the energy industry continue to be strong, as evidenced in Towers
2
Watson’s 2015 General Industry Salary Budget Survey. This report shows that
3
starting salaries of engineers ranged from $72,000 - $85,000 and IT professionals
4
from $61,000 - $75,000.
5
Additionally, the February 2014 Congressional Research Report cited above
6
stated that “[i]n 2012, the mean annual wage for all scientists and engineers
7
[S&E] was $87,330; the mean annual wage for all occupations – professional and
8
non-professional – was $45,790. S&E managers had the highest mean annual
9
wage of all S&E occupational groups at $130,660 followed by engineers,
10
$90,960….” The National Academy of Sciences wrote about this in its 2013
11
paper entitled “Emerging Workforce Trends in the US Energy and Mining
12
Industries: A Call to Action,” when it noted that “[o]ptions for finding additional
13
workers are limited, especially as other countries face the same shortages and
14
attempt to attract U.S. workers with higher pay.”
15
Q.
HOW ARE THESE CHALLENGES MANIFESTING THEMSELVES?
16
A.
These challenges are manifested in turnover in the ISO industry. While industry
17
turnover was trending downward in 2008 - 2010, due to the depressed national
18
economy, it has increased as companies have begun hiring again and as
19
employees, who had deferred their retirements during the economic downturn,
20
now begin to exit the workforce. To date in 2015, the ISO’s turnover is running
21
at 5.8%. While on par with 2014 full year turnover, it is up from 2013 turnover,
Page 7
1
and significantly higher than the turnover seen prior to that. Individuals who have
2
departed this year were primarily in information technology, engineering and
3
economist positions, from System Operations, System Planning, Market
4
Operations and Market Development, all areas that are critical to operating the
5
grid and running our markets. In addition, to date in 2015, nine ISO employees
6
have resigned for similar but higher paying jobs at other employers; and, in 2015
7
thus far, five candidates have declined ISO-NE job offers, stating that the
8
compensation was not sufficient.
9
Q.
10
11
HOW DOES THE ISO MAINTAIN THE COMPETITIVENESS OF ITS
COMPENSATION?
A.
The ISO first identifies the industries with which it competes for talent – in other
12
words, the industries from which the ISO recruits, and to which the ISO loses
13
employees. These are other ISOs and RTOs, for-profit utility companies, energy-
14
related consulting firms, and the broader industry (for positions not specific to
15
utilities).
16
Next, the ISO defines target ranges of compensation within these markets. For
17
non-exempt, non-union employees, the target market range of compensation is the
18
50th percentile of the local market. For both executives and middle management
19
and professionals, this target is the 50th to 75th percentile of the national market.
20
For middle management and professionals, the following factors led to the
21
determination of this target: nation-wide recruitment; national shortages of
Page 8
1
qualified candidates; and difficulty in attracting candidates to the location. For
2
executives, we also considered: complexity of responsibilities; alignment with
3
higher salaries paid in the Northeast; and the limited promotional opportunities in
4
a smaller organization.
5
Last, as discussed in more detail below, the ISO regularly monitors job-specific
6
salary survey data to determine these targets.
7
COMPONENTS OF COMPENSATION
8
Q.
WHAT ARE THE COMPONENTS OF THE ISO’S COMPENSATION?
9
A.
The ISO has a “pay for performance” compensation program composed of two
10
components for all employees, and an additional long-term component for
11
executives and certain key employees.
12
The first component is annual base salary, which reflects external
13
competitiveness, the employee’s productivity and performance, the qualifications
14
for the position, and internal equity. An employee’s annual base salary evolves
15
based on his or her job performance, following the annual performance review
16
process. (These are the merit and promotional increases that will be discussed
17
below.) These changes to salary are one of the ways in which the ISO maintains
18
the competitiveness of its salaries within the target ranges previously discussed.
19
The second component of compensation is annual incentive compensation. This
20
program is intended to motivate employees to achieve superior performance on
Page 9
1
critical annual business and customer service objectives and goals. Subject to
2
eligibility criteria, employees may receive an annual award based on a formula
3
that includes company performance, individual performance, annual base salary
4
and a grade-related salary percentage. Company performance is determined using
5
goals that are set in advance by the Board. These goals are objective and
6
measurable and represent organizational goals for operational reliability, efficient
7
and competitive markets, budget performance and service excellence in
8
stakeholder processes. Performance against these goals is measured using a
9
corporate scorecard that is regularly published to all employees, and the
10
calculation of which is verified by the ISO’s internal auditors. The Board of
11
Directors then assigns a final score to the achievement of annual goals.
12
For executives and certain key employees, the third and final component of
13
compensation is a long-term incentive plan that is designed to encourage retention
14
by deferring payments for two and one-half years after they are declared. This
15
program is intended to provide compensation in lieu of the stock programs
16
provided by for-profit competitors. These awards are determined using a formula
17
of performance against specific corporate goals, individual performance and
18
annual base salary. Again, the goals and their performance are determined by the
19
Board. Additionally, before the payout, the Board conducts a retrospective
20
review of the quality and impact of the goal achievement supporting the award.
Page 10
1
Employees are not eligible for either type of award in a year in which they receive
2
a performance rating of “Clearly Below Expectations” or in the event of a major
3
collapse of the bulk electric power system. Similarly, if the ISO underperforms in
4
the management of the bulk electric power system or in its other functions in a
5
manner that is not captured in the goal performance score, the Board of Directors
6
can reduce or eliminate the payment of the awards. The Board has taken this step
7
in the past.
8
BUDGET FOR MERIT AND PROMOTIONAL SALARY INCREASES
9
Q:
10
11
PLEASE EXPLAIN THE MERIT AND PROMOTIONAL INCREASE
BUDGET.
A.
This is a budget that establishes annually the amount that management and the
12
Board can distribute to the entire employee base for salary increases following the
13
annual performance review process that occurs in the first quarter of each year, as
14
well as changes as a result of promotion. This is a critical component of our
15
ability to maintain competitive salaries, which, as discussed above, enables us to
16
retain our employees in a very competitive marketplace for their talent.
17
Q.
HOW IS THIS BUDGET DETERMINED?
18
A.
The Compensation and Human Resources Committee of the Board of Directors
19
determines this budget annually after reviewing national survey data that project
20
what other employers will do for these programs in the coming year. We
21
typically gather data from six surveys, prepared by Mercer, WorldatWork, the
Page 11
1
Conference Board, Buck Consultants, Aon Hewitt, and TowersWatson. The
2
surveys report the planned budget increases of several thousand employers,
3
including nearly 400 energy and utility companies. These surveys provide
4
information on all industries nationwide, as well as the utility industry separately,
5
and are used by most major companies to determine their compensation budgets.
6
The ISO utilizes nationwide benchmark data for both all-industry and utility-
7
specific employers, because it recruits a majority of its employees on a
8
nationwide basis given the unique skill sets required for many of its positions.
9
The ISO further assesses the data by employee group, reviewing data reported
10
specifically for executive, exempt employees, and non-union non-exempt
11
employees.
12
Q.
13
14
WHAT WERE THE SURVEY RESULTS REGARDING PROJECTED
INCREASES FOR 2016?
A.
For merit increase budgets, the surveys showed an average of slightly higher than
15
3.0% for all industries nationwide, and slightly lower than 3.0% for the utility
16
industry. For promotional increase budgets, the surveys showed a range of 0.5%
17
to 1.0% for all industries nationwide and 0.0% - 0.8% for the energy and utility
18
industry. Some of the energy and utility data is influenced by cut backs at oil and
19
gas companies, which have been affected by the decrease in oil and gas prices
20
nationwide.
Page 12
1
In 2008 and 2009, because employers were reducing their compensation budgets
2
given the economic downturn, the survey firms updated their data at year end.
3
The ISO reviewed this data in both years to ensure that the following year’s
4
budgeted increases remained within the survey ranges. In 2008, the ISO reduced
5
its 2009 compensation budget by $500,000 as a result. In 2010, only one of the
6
survey firms produced an update. There were no updates in 2011, and one update
7
in each of 2012, 2013 and 2014. We expect that one firm will issue an update in
8
2015, and we will review and consider that data, but expect that, consistent with
9
the last few years, it will not indicate any material changes in employers’
10
11
compensation budgets.
Q.
12
13
WHAT ARE THE ISO’S MERIT AND PROMOTIONAL INCREASE
BUDGETS FOR 2016?
A.
After reviewing the survey data, the Committee approved a merit increase budget
14
of 2.75% and a promotional increase budget of .75%. We chose to be on the
15
lower side of the survey data for the merit increase budget in order to move funds
16
into the promotional increase budget, where we are on the higher side of the
17
average survey data. This positioning will enable us to continue benchmarking
18
and adjusting compensation for engineers and informational technology
19
professionals, among others, when market data indicates that our salaries are not
20
competitive.
1
FRAMEWORK FOR DETERMINING EXECUTIVE COMPENSATION
2
Q.
3
4
Page 13
WHAT IS THE FRAMEWORK FOR THE ISO’S DETERMINATION OF
EXECUTIVE COMPENSATION?
A.
The ISO is a not-for-profit company under Section 501(c)(3) of the Internal
5
Revenue Code. The Internal Revenue Code and related Treasury regulations
6
require that the compensation paid to executive officers meet a standard of
7
“reasonableness.” Specifically, compensation must fall within a range of
8
competitive practices for total compensation paid by similarly-situated
9
organizations, both taxable and tax-exempt, for functionally comparable
10
positions.
11
The Internal Revenue Code allows a tax-exempt organization to establish a
12
“rebuttable presumption” of reasonableness. This places the onus on the Internal
13
Revenue Service to show that compensation is unreasonable. The rebuttable
14
presumption requires that the compensation arrangement be approved in advance
15
by independent individuals (e.g., the Board of Directors), that the Board has
16
obtained and relied upon appropriate data as to comparability (i.e., compensation
17
paid by similarly-situated entities – taxable and tax-exempt – for positions with a
18
similar scope of responsibility), and that the Board adequately documents the
19
basis for its determination.
1
Q.
2
3
Page 14
HOW HAS THE ISO ATTEMPTED TO SECURE THE BENEFIT OF THE
PRESUMPTION OF REASONABLENESS?
A.
The ISO’s Board of Directors approves all executive compensation, and
4
documents the basis for its determination. In order to ensure that the Board has
5
obtained and relied upon appropriate data as to comparability, the ISO retains an
6
outside compensation advisor, Mercer Consulting. Mercer prepares an opinion
7
annually on the reasonableness of the ISO’s executive compensation, using as
8
comparators other ISOs and RTOs, as well as for-profit utilities and other
9
companies, based on their organizational character/complexity, geographic
10
location, role of the incumbent and labor market for the executive team. The data
11
for these groups is then blended to create a composite market reference as an
12
overall benchmark. This composite reflects the fact that the ISO competes for
13
executive talent in the energy industry, as well as in the broader general industry
14
for positions in areas like Legal, Finance and Human Resources.
15
Q.
16
17
WHAT IS THE BOARD’S PROCESS FOR DETERMINING EXECUTIVE
COMPENSATION?
A.
This process occurs in the first quarter of each year. In determining executive
18
compensation, the Board first asks its Compensation and Human Resources
19
Committee to consider appropriate compensation. Both the Committee, and then
20
the Board, consider the CEO’s appraisal of each executive’s experience,
21
responsibilities, performance, specific skill set, and contribution to strategic goal
1
achievement (and, for the CEO, the Chair’s appraisal of the same factors as
2
related to the CEO), and the Company’s financial and operational achievement.
3
The Board then provides its compensation recommendations to Mercer for an
4
opinion on reasonableness, prior to implementation.
5
Q.
6
7
Page 15
WHAT WAS THE CONCLUSION OF MERCER’S MOST RECENT
REASONABLENESS OPINION?
A.
8
Mercer’s most recent reasonableness opinion concludes that the proposed 2015
total compensation for executives was reasonable.
9
Q.
HOW WILL 2016 EXECUTIVE COMPENSATION BE DETERMINED?
10
A.
The Board will use the same process described above, involving the
11
Compensation and Human Resources Committee’s review and approval followed
12
by full Board approval of executive compensation. Likewise, the Board will
13
employ Mercer to ensure the reasonableness of 2016 compensation. While 2016
14
compensation has not yet been determined, 2015 executive compensation will be
15
the base for 2016 compensation and the Board has not authorized any wholesale
16
changes to the compensation programs described above. Consequently, it is
17
reasonable to presume that the 2016 executive compensation will be similar to the
18
2015 compensation, with changes necessary to maintain its competitiveness.
EXHIBIT 5
Exhibit 5
2016 Capital Projects Schedule
Description
Current Year
Project-To- (2015) Cost to
Date
Complete [1]
2016 Cost to
Complete
$
$
Total Project
Costs
Estimated
Complete Date
Capital Projects - Approved Charters
. Wind Integration Phase II / Do Not Exceed (DNE) Dispatch
1,308.8
$
1,359.9
2,472.0
$
5/2016
5,140.7
2,232.0
72.0
496.8
2,800.8
2016
758.5
1,366.5
590.0
2,715.0
5/2016
. Zonal Load Forecast
48.2
406.8
225.0
680.0
. Power System Modeling Management Initiatives
12.5
97.5
145.0
420.0
112.6
192.4
50.0
355.0
2/2016
89.1
200.9
12.0
302.0
12/2015
4,561.7
3,696.0
3,990.8
12,413.5
. Divisional Accounting
. NX9/NX12D - Generator Voltage Data
. Internet Explorer 11 Upgrade
Sub Total Projects with Approved Charters
3/2016
[2]
8/2017
Planning/Conceptual Design [3]
-
100.0
3,000.0
3,100.0
TBD
. Sub-hourly Settlements
-
85.0
2,500.0
2,585.0
TBD
. Fast-Start Pricing
-
-
2,500.0
2,500.0
TBD
88.9
21.2
1,800.0
1,910.1
TBD
-
1,500.0
1,500.0
. Submission of Financial Transmission Rights (FTR) for Clearing
. 2016 Issues Resolution Project
-
. Long-term FTRs
907.5
. Expand Energy Offers for Pumps
-
-
. Quarterly Release Projects 2016
. Asset Characteristic Database & User Interface Re-design
-
-
907.5
900.0
TBD
[4]
900.0
TBD
TBD
-
-
800.0
800.0
TBD
1.0
39.0
700.0
740.0
TBD
. Energy Management Platform Customs Elimination
-
-
600.0
600.0
TBD
. Operations Document Management System
-
-
600.0
600.0
TBD
TBD
. Asset Registration Automation
30.2
27.5
500.0
557.7
. Transmart Rewrite
-
-
500.0
500.0
TBD
. Web Enhancements 2016
-
-
500.0
500.0
TBD
. Dynamic Interchange Adjustment Tool
. Oracle 12c Upgrade
-
-
300.0
300.0
TBD
17.4
32.6
100.0
150.0
TBD
. Case Snapshot Enhancements for Market Operator Interface
-
-
100.0
100.0
TBD
. Price Responsive Demand
-
-
100.0
100.0
TBD
TBD
. Other Emerging Work Projects
-
Sub Total Conceptual Design
-
1,045.0
305.3
1,809.2
1,809.2
18,809.2
20,159.5
3,700.0
. Non-Project Capital Expenditures
-
-
3,700.0
. Capitalized Interest and Loan Fees
-
-
500.0
Total Capital Projects (Including Capitalized Interest)
$
5,606.7
$
4,001.3
$
27,000.0
500.0
$
36,773.0
[1] The amounts under the "Current Year (2015) Cost to Complete" list only includes those projects with budgeted costs in 2016 and beyond.
[2] Total Project Costs for the Power System Modeling Management Initiatives project includes 2017 estimated expense of $165,000.
[3] The 2016 Budget for Projects in Planning and Conceptual Design is not final. Once the project scope and timeline have been determined the budget will
be finalized.
[4] The Long-term FTRs project has been indefinitely deferred pending the development of appropriate credit requirements.
EXHIBIT 6
2016 Capital Budget
BEFORE THE
)
DIRECT TESTIMONY
OF
M. DAVID HAMEEDY
Filed on: October 16, 2015
2016 Capital Budget
Page 1
1
2
BEFORE THE FEDERAL ENERGY REGULATORY COMMISSION
3
4
)
5
Direct Testimony of M. David Hameedy
6
7
Q.
PLEASE STATE YOUR NAME AND BUSINESS ADDRESS.
8
A.
My name is M. David Hameedy. My business address is One Sullivan Road,
Holyoke, Massachusetts 01040-2841.
9
10
Q.
WHAT IS YOUR OCCUPATION?
11
A.
I am the Director of the Program Management Office of ISO New England Inc.
12
(the “ISO” or “ISO-NE”). My primary responsibilities include managing the
13
portfolio of capital projects at the ISO from inception to completion. I have
14
served in this role since January of 2005. Prior to that date, I served as the Project
15
Manager for the Standard Market Design project and then the Development
16
Manager in the Information Technology Department.
2016 Capital Budget
1
Q.
PLEASE DESCRIBE YOUR EDUCATIONAL BACKGROUND AND
PROFESSIONAL EXPERIENCE.
2
3
Page 2
A.
I received my BS in Nuclear Engineering from the University of Arizona in 1981,
4
my MS degree in Nuclear Engineering from the University of Arizona in 1983,
5
and my MBA from Rensselaer Polytechnic Institute (RPI) in 1988. Before joining
6
the ISO, I worked for the New York Power Authority, Westinghouse Electric
7
Corporation, and ABB in several engineering and marketing positions.
8
PURPOSE OF TESTIMONY
9
Q.
10
A.
I am providing this testimony in support of the filing of the ISO’s capital budget
11
for 2016 (“2016 Capital Budget”).
12
My Direct Testimony describes:
13
(i)
the Capital Budget development process;
14
(ii)
elements of the 2016 Capital Budget; and
15
(iii)
funding of the 2016 Capital Budget.
16
THE CAPITAL BUDGET DEVELOPMENT PROCESS
17
Q.
WHAT BUDGETS DOES THE ISO DEVELOP FOR EACH YEAR?
18
A.
The ISO develops an operating budget and a capital budget. The capital budget
19
supports important capital needs for New England.
2016 Capital Budget
Page 3
1
Q.
HOW WERE THE ISO’S BUDGETS DEVELOPED FOR 2016?
2
A.
The ISO prepares budgets in advance of each upcoming year, including a capital
3
budget. To develop these budgets for 2016, the CEO held meetings with the
4
Chief Financial and Compliance Officer, members of the ISO Board, officers and
5
certain key managers to discuss the existing and changing responsibilities of the
6
organization. Based on the results of these meetings and the priorities established
7
with stakeholders, estimates of the resources necessary to carry out the ISO’s
8
responsibilities were submitted by each of the responsible directors and managers.
9
Following these efforts, the ISO develops a project charter for each capital project.
10
All projects with completed charters were reviewed to ensure that the estimates
11
were reasonable and that no costs were double-counted. The ISO management
12
team meets once a month to discuss the project charters. An approval by the ISO
13
management team is essential prior to the authorization of budgets and the start of
14
project work.
15
16
ELEMENTS OF THE 2016 CAPITAL BUDGET
Q.
FOR THE CAPITAL PROJECTS DISCUSSED ABOVE?
17
18
IN GENERAL, HOW WILL THE ISO SPEND THE MONEY REQUIRED
A.
The primary deliverable for a majority of the projects listed in the 2016 Capital
19
Budget is application software and requisite hardware needed to maintain and
20
improve bulk-power system reliability and/or wholesale electric markets.
2016 Capital Budget
Page 4
1
Q.
HAS THE 2016 CAPITAL BUDGET CHANGED FROM 2015 LEVELS?
2
A.
The 2016 Capital Budget is $27 million, which is $1 million less than the 2015
budget.
3
4
Q.
PLEASE DESCRIBE THE ELEMENTS OF THE CAPITAL BUDGET.
5
A.
The 2016 Capital Budget contains the following projects: Wind Integration Phase
6
II / Do Not Exceed Dispatch; Forward Capacity Auction 10; Divisional
7
Accounting; Zonal Load Forecast; Power System Modeling Management
8
Initiatives; NX9/NX12D – Generator Voltage Data; Forward Capacity Auction
9
(“FCA”) 11; Sub-Hourly Settlements; Fast-Start Pricing; Submission of Financial
10
Transmission Rights for Clearing; 2016 Issues Resolution Project; Expand Energy
11
Offers for Pumps; Quarterly Release Projects 2016; Asset Characteristics
12
Database & User Interface Redesign; Energy Management Platform Customs
13
Elimination; Operations Document Management System; Transmart Rewrite;
14
Web Enhancements 2016; Asset Registration Automation; Dynamic Interchange
15
Adjustment Tool; Oracle 12c Upgrade; Case Snapshot Enhancements for Market
16
Operator Interface; Price Responsive Demand; Non-Project Capital Expenditures;
17
and Other Emerging Work. The 2016 Capital Budget also includes $500,000 to
18
pay for capitalized interest and loan fees.
2016 Capital Budget
1
Q.
PLEASE DESCRIBE THE WIND INTEGRATION PHASE II / DO NOT
EXCEED DISPATCH PROJECT.
2
3
Page 5
A.
The ISO has budgeted $2,472,000 in 2016 for this effort, which is expected to be
4
complete in May 2016. This is the second phase in the project to fully integrate
5
wind power into the ISO-NE system. Phase I of the project established a
6
centralized wind power forecast system for ISO-NE, putting the forecast into use
7
by wind plant operators and ISO-NE. The wind power forecast was a direct
8
recommendation from the New England Wind Integration Study and the first step
9
towards the full integration of wind into ISO-NE systems. The Phase I project
10
implemented an infrastructure that can be used to extend the usage of the wind
11
power forecasts into other ISO-NE processes.
12
Phase II builds on Phase I by adding both improvements and new functionality.
13
Significantly, Phase II will employ the wind power forecast to facilitate the
14
inclusion of wind resources in the real-time dispatch. Allowing real-time dispatch
15
will alleviate issues with curtailment priorities, allow wind resources to set price,
16
and provide the proper market signals for new capacity. Phase II also includes:
17
short-term wind power forecast improvements; publishing medium-term and long-
18
term forecasts; adding a new wind power forecast analysis archive; improving
19
real-time wind dashboard displays; and adding Do Not Exceed dispatch for
20
intermittent resources.
2016 Capital Budget
1
Q.
PLEASE DESCRIBE THE FORWARD CAPACITY AUCTION 10
PROJECT.
2
3
Page 6
A.
The FCA 10 project will implement Tariff revisions that were filed with the
4
Commission on May 1, 2015 to address the potential exercise of market power.
5
The changes include: increasing the Dynamic De-List Bid Threshold; mitigating
6
New Import Resources that function more like existing resources than new
7
resources; and establishing a single pivotal supplier test that applies to both
8
capacity imports and existing resources. Other changes include the
9
implementation of a system-wide demand curve in the Annual Reconfiguration
10
Auctions and functionality to support Renewable Technology Resources.
11
In addition to the market changes discussed above, the FCA 10 project will
12
include upgrades for the software used to support the qualification process.
13
Oracle and Microsoft have announced that the current versions of Oracle (11g)
14
and Internet Explorer (v.8) in use by the ISO have reached their end of life and
15
will not be supported effective January 2016. Accordingly, the existing software
16
will be upgraded to Oracle version 12c and Internet Explorer version 11.
17
The targeted completion date for this project is May 2016 and it is expected to
18
cost $590,000 in 2016.
2016 Capital Budget
1
Q.
PLEASE DESCRIBE THE DIVISIONAL ACCOUNTING PROJECT.
2
A.
Market Participants with business interests in different aspects of the New
Page 7
3
England electricity markets have requested separate settlement accounts for their
4
individual business units, allowing them to evaluate their positions by business
5
unit, division or generating facility. This project will implement changes, in
6
phases, to various ISO-NE systems to allow Market Participants to create and
7
maintain subaccounts and associate their resources and transactions to these
8
subaccounts.
9
The complexity of the implementation and the vast number of systems impacted
10
resulted in five phased releases to occur in 2014 and 2015. The first four planned
11
phases have been completed, and allow Customers to create and maintain
12
subaccounts and receive reports for settlements for entity-based transactions by
13
subaccounts. In addition, the ISO has completed the necessary modifications to
14
eMarket (a web based software application for use by Market Participants to
15
submit supply offers and bids), eFTR (Financial Transmission Rights) and the
16
Forward Capacity Tracking System to allow Customers to link transactions that
17
are not associated with assets and resources to subaccounts, thereby allowing
18
settlements for those transactions to be calculated and reported at the subaccount
19
level.
2016 Capital Budget
Page 8
1
The fifth and final phase of the project has been delayed due to resource conflicts,
2
specifically with the Coordinated Transaction Scheduling project. The final phase
3
is focused specifically on external transactions and their respective settlements.
4
Re-planning analysis is underway, and initial estimates indicate completion during
5
2016 at a cost of $496,800.
6
Q.
PLEASE DESCRIBE THE ZONAL LOAD FORECAST PROJECT.
7
A.
This project, for which $225,000 is budgeted in 2016, addresses a load forecasting
8
need related to weather events in which hot and humid conditions occur inland
9
and the coastal regions experience a cooling sea breeze. In response to this
10
situation, ISO-NE developed a zonal load forecast prototype which addresses the
11
problem by creating a load forecast for each load zone. This project will build on
12
the successful prototype by incorporating zonal load forecast functionality into the
13
existing load forecast application, and adjusting downstream systems using load
14
forecast data accordingly. With this project, the overall load forecast for the
15
region will improve. The targeted completion date for this project is March 2016.
16
Q.
MANAGEMENT INITIATIVES PROJECT.
17
18
PLEASE DESCRIBE THE POWER SYSTEM MODELING
A.
The ISO has budgeted $145,000 for this project, which is intended to implement
19
enhancements to processes, procedures, and applications that will improve the
20
power system network model used for the Energy Management System. The ISO
2016 Capital Budget
Page 9
1
will work with Northeastern University to perform an analysis of the ISO-NE
2
network model to identify: the type and location of all “critical” measurements
3
identified in the measurement configuration; the observable islands identified by
4
the set of buses belonging to each island; and all unobservable branches
5
separating the identified observable islands. In addition, Northeastern University
6
will develop software that will allow for off-line detection and identification of
7
analog measurements and state estimator parameters with significant errors that
8
impact the state estimator solution. Using this software, ISO-NE will work with
9
transmission owners to correct these errors. The goal is to create a more robust
10
and accurate state estimator solution, which in turn will benefit other critical
11
energy management system functions and market applications. The targeted
12
completion date for this project is August 2017.
13
Q.
DATA PROJECT.
14
15
PLEASE DESCRIBE THE NX9/NX12D – GENERATOR VOLTAGE
A.
The NX9/NX12D application, implemented in the fall of 2013, is an externally-
16
facing application that manages the data and certifications provided by ISO-NE
17
customers for specific equipment. Currently, the NX12D section of the
18
application is used to collect information on generators, including reactive
19
data. The NX9 section of the application collects specific nameplate and
20
characteristic data for transmission equipment. At a 2016 cost to complete of
2016 Capital Budget
Page 10
1
$50,000, the NX9/NX12D project will update the software associated with these
2
systems to align with ISO-NE Operating Procedure No. 12 (“Voltage & Reactive
3
Control”), which was recently updated in compliance with the North American
4
Electric Reliability Corporation’s Reliability Standard VAR-001-4. The targeted
5
completion date for this project is February 2016.
6
Q.
PLEASE DESCRIBE THE FCA 11 PROJECT.
7
A.
This project is dedicated to the design and implementation of zonal sloped
8
demand curves that balance the factors involved in designing capacity market
9
demand curves: reliability, price volatility, market power, and robust
10
performance. The project is intended to be completed with the eleventh FCA,
11
which will be held in February 2017. The 2016 Capital Budget includes
12
$3,000,000 for this project.
13
Q.
PLEASE DESCRIBE THE SUB-HOURLY SETTLEMENTS PROJECT.
14
A.
The real-time markets (energy, reserve, and regulation) are settled hourly, even
15
though the ISO calculates real-time locational marginal prices every five minutes.
16
Existing settlement rules tend to undercompensate certain resources, particularly
17
more flexible generation and storage assets that respond quickly in tight operating
18
conditions, when there are significant mid-hour price changes. Compensating
19
resources at the more granular, five-minute price would help improve price
20
formation by ensuring that the price that suppliers are paid for real-time
2016 Capital Budget
Page 11
1
performance is a more accurate signal of the power system’s current operating
2
conditions. In the future, this change may also provide an additional revenue
3
source for wholesale electricity storage resources. The target completion date for
4
this project is the fourth quarter of 2016, and the 2016 Capital Budget includes
5
$2,500,000 for its completion.
6
Q.
PLEASE DESCRIBE THE FAST-START PRICING PROJECT.
7
A.
In practice, fast-start units, even when deployed in economic merit order, often do
8
not set the real-time price given their operating characteristics. This is due to the
9
limitations of ISO-NE’s existing fast-start pricing logic, which was designed
10
fifteen years ago to work with the software and hardware that was available at the
11
time. The proposed changes will increase the accuracy and efficiency of dispatch,
12
pricing, and compensation when fast-start units are deployed. Price formation
13
will be improved by fast-start resources’ ability to set price more frequently, and
14
prices will reflect the cost of fast-start deployments through transparent market
15
price signals. The result will be improved performance incentives for all
16
resources during tight system conditions. The targeted completion date for this
17
project is the first quarter of 2017. The 2016 Capital Budget includes $2,500,000
18
for this project.
2016 Capital Budget
1
Q.
PLEASE DESCRIBE THE SUBMISSION OF FINANCIAL
TRANSMISSION RIGHTS FOR CLEARING PROJECT.
2
3
Page 12
A.
The objective of this project, currently in planning, is to institute third-party
4
clearing in order to address the inability to properly collateralize against the risk
5
of a participant default. Currently, ISO-NE holds Financial Assurance that may
6
not be adequate to cover the potential losses of a Market Participant’s default on
7
its FTRs. Specifically, there is no way for ISO-NE to unwind a defaulted FTR
8
position. If a participant acquires a large position in an annual FTR auction, and
9
the amount of negative target allocations exceeds its Financial Assurance, the
10
losses on this position, and the losses to all ISO-NE participants in the event of a
11
default, can continue to accumulate. Under a third-party clearing design, if a
12
Market Participant defaults, its clearing member will liquidate the defaulted
13
portfolio in the secondary market, and if the combined margin held against the
14
portfolio is not adequate to cover the liquidation losses, the clearing member
15
holds the financial responsibility to cover the excess losses.
16
Regulatory and jurisdictional questions surrounding the project have resulted in
17
major delays. Minimal work on the project will continue in 2015, with the
18
majority of development work anticipated to occur in 2016 at a cost of
19
$1,800,000. The targeted completion date for this project is the fourth quarter of
20
2016.
2016 Capital Budget
Page 13
1
Q.
PLEASE DESCRIBE THE ISSUE RESOLUTION PROJECT 2016.
2
A.
The ISO uses a “Corrective Action/Preventative Action” approach to identify and
3
track needed enhancements to existing systems and processes. This project
4
continues efforts to resolve as many current outstanding issues that have a
5
software impact as possible. These issues include automation of manual
6
functions, addition of functionality in support of market activities, miscellaneous
7
application improvements, internal and external report updates, and technology
8
improvements. The ISO Information Technology and System groups will review
9
the list of issues related to the systems and applications for which they provide
10
support and identify those that can be implemented during the year. The targeted
11
completion date for this project is the fourth quarter of 2016 and the anticipated
12
cost is $1,500,000.
13
Q.
PROJECT.
14
15
PLEASE DESCRIBE THE EXPAND ENERGY OFFERS FOR PUMPS
A.
The ISO does not currently allow Dispatchable Asset Related Demands
16
(“DARDs”) to have inter-temporal constraints (start-up, notification, minimum
17
run and down times, and maximum number of starts per day). In response to the
18
Commission’s Order No. 719, ISO-NE agreed to modify this practice.
19
Specifically, through this project, the ISO will enable DARDs to have maximum
20
demand-dispatch duration, maximum dispatch frequency, and a minimum down-
2016 Capital Budget
Page 14
1
time. In addition, the ISO will expand the rules for Net Commitment Period
2
Compensation and define cost allocation rules for DARDs. The targeted
3
completion date for this project is the fourth quarter of 2016. The Capital Budget
4
includes $900,000 for this project in 2016.
5
Q.
PROJECT.
6
7
PLEASE DESCRIBE THE QUARTERLY RELEASE PROJECTS 2016
A.
In addition to major projects under consideration for 2016, the ISO expects to
8
address a number of minor enhancements requested by stakeholders at a cost of
9
$800,000. These enhancements are bundled into two quarterly releases. The
10
targeted completion dates are the second quarter of 2016 for the first release, and
11
the fourth quarter of 2016 for the second release.
12
Q.
USER INTERFACE REDESIGN PROJECT.
13
14
PLEASE DESCRIBE THE ASSET CHARACTERISTICS DATABASE &
A.
This project will provide participants and ISO-NE Internal Market Monitoring
15
staff with enhanced functionality to track generator characteristics for reference
16
level calculations. This project will build upon functionality delivered as part of
17
the Energy Market Offer Flexibility (Hourly Markets) project. The targeted
18
completion date for this project is the third quarter of 2016 and the Capital Budget
19
includes $700,000 for its completion.
2016 Capital Budget
1
Q.
PLEASE DESCRIBE THE ENERGY MANAGEMENT PLATFORM
CUSTOMS ELIMINATION PROJECT.
2
3
Page 15
A.
ISO-NE’s Energy Management System is based on Alstom Grid’s suite of Energy
4
Management Platform applications. When absolutely necessary, the Information
5
Services department customizes Alstom’s software to meet the business needs of
6
ISO-NE. Accordingly, when Alstom upgrades its software, a significant effort is
7
needed to port the customized ISO-NE software to the upgraded software. This
8
project involves work with Alstom Grid to eliminate some of the ISO-NE
9
customs, with the goal of simplifying the next software upgrade. The targeted
10
completion date for this project is the fourth quarter of 2017, and $600,000 has
11
been included for it in the 2016 Capital Budget.
12
Q.
SYSTEM PROJECT.
13
14
PLEASE DESCRIBE THE OPERATIONS DOCUMENT MANAGEMENT
A.
System Operations is currently using the Operations Document Management
15
System (“ODMS”) as the sole system for managing the edit, review and sign-off
16
for all transmission operating guides, operating procedures, master local control
17
center procedures, and system operating procedures. ODMS also provides
18
operational functionality, including searching and decision making. Since ISO-
19
NE is phasing out SharePoint-based applications such as ODMS, the project will
2016 Capital Budget
Page 16
1
migrate ODMS to a new software platform. The targeted completion date for this
2
project is the fourth quarter of 2016 at a cost of $600,000 in 2016.
3
Q.
PLEASE DESCRIBE THE TRANSMART REWRITE PROJECT.
4
A.
Transmart is a software application that is used by ISO-NE System Operations
5
staff to support external transactions. The Transmart application has been in
6
existence since before the implementation of Standard Market Design in 2003.
7
The Transmart Rewrite project upgrades the remaining functionality that still
8
exists in the original Transmart application. The targeted completion date for this
9
project is the fourth quarter 2016 and the Capital Budget includes $500,000 for
this project.
10
11
Q.
PLEASE DESCRIBE THE WEB ENHANCEMENTS 2016 PROJECT.
12
A.
ISO-NE completed a redesigned website in 2014 that greatly improved ease of use
13
of, and access to, market and power system information for Market Participants,
14
public officials, and other key stakeholders. In an effort to continue to improve
15
the ISO New England web presence, the Web Enhancements 2016 project, at a
16
cost of $500,000, will improve the usability and technical support of the internal
17
and external websites by implementing stakeholders’ most requested
18
improvements and the highest priority enhancements. The project is targeted for
19
completion in 2016.
2016 Capital Budget
Page 17
1
Q.
PLEASE DESCRIBE THE ASSET REGISTRATION PROJECT.
2
A.
The current asset registration process relies on participant submittal of scanned,
3
emailed, or faxed asset registration forms or spreadsheets. This project aims to
4
improve the asset registration process by providing a secure digital format for
5
submission and retrieval of asset registration forms, in addition to requested asset
6
data changes and transfers. The repository would include the required controls for
7
this data and ensure that all customers and business users would have access to
8
timely and accurate asset data without the need to maintain separate databases,
9
spreadsheets, binders, or duplicate forms. This project would also provide a
10
workflow to manage the necessary participant and ISO approvals required for
11
asset registration and changes to existing asset data. The targeted completion date
12
for this project is the third quarter of 2016 and the anticipated cost to complete the
13
work in 2016 is $500,000.
14
Q.
TOOL PROJECT.
15
16
PLEASE DESCRIBE THE DYNAMIC INTERCHANGE ADJUSTMENT
A.
Currently, ISO-NE sets hourly interchange schedules with neighboring control
17
areas in New York, Quebec and New Brunswick. The schedules all change
18
concurrently once per hour and are primarily ramped over a ten-minute period
19
beginning five minutes before the top of each hour. System Operating Procedures
20
apply uniform ramp limits to all hours without regard to actual system conditions
2016 Capital Budget
Page 18
1
or system ramping capability. As the use of a uniform ramp limit can result in
2
unnecessary curtailment of transactions, or may occasionally fail to account for a
3
shortage of ramping capability, the Dynamic Interchange Adjustment Tool project
4
will replace uniform ramp limits with secure ranges of system ramping
5
capabilities for intra-hour interchange adjustments. The project will also address
6
the additional layer of complexity created by the advent of intra-hour scheduling
7
with New York. The target completion date for this project is the fourth quarter
8
of 2016 at a cost of $300,000 in 2016.
9
Q.
PLEASE DESCRIBE THE ORACLE 12c UPGRADE PROJECT.
10
A.
Many ISO-NE business applications rely on an Oracle database. To obtain the
11
level of support needed from Oracle to meet the ISO’s availability goals, the ISO
12
must run on the current Oracle database version for each application. This project
13
will ensure all systems are upgraded from Oracle version 11g to Oracle version
14
12c. Because upgrades are also occurring in the context of current and upcoming
15
projects, this project’s scope will specifically address only database upgrades and
16
performance testing for those systems not covered under a current or upcoming
17
project. The targeted completion date for this project is the second quarter of 2016
18
and the Capital Budget includes $100,000 for this project.
2016 Capital Budget
1
Q.
PLEASE DESCRIBE THE CASE SNAPSHOT ENHANCEMENTS FOR
MARKET OPERATOR INTERFACE PROJECT.
2
3
Page 19
A.
On July 3, 2013, the Commission approved ISO-NE’s proposal to use the $1
4
million in funds provided to ISO-NE under the Stipulation and Consent
5
Agreement between Constellation Energy Commodities Group and the Office of
6
Enforcement. That proposal involved the development of new software to allow
7
increased surveillance and oversight of the Day-Ahead Energy Market. The new
8
software (called Case Snapshot) allows the re-execution of the Day-Ahead Energy
9
Market’s Reserve Adequacy Assessment and Security Constrained Reliability
10
Assessment cases using the same market data that existed when the original case
11
was executed and approved. The initial development and implementation of Case
12
Snapshot occurred at the end of October 2013. Enhancements to augment the data
13
captured in the snapshot tables and the data retention period were subsequently
14
made. On December 22, 2014, ISO-NE reported that the initial implementation
15
was complete at a total project cost of $672,500.
16
ISO-NE is now proposing to use the remaining funds to develop a suite of user
17
interface displays that will provide visibility of the snapshot data when re-running
18
a case and allow the ability to modify this data, including participant offers, before
19
executing the case. In addition, this functionality will facilitate the execution of
20
“what-if” scenarios. Currently, for much of the snapshot data, this can only be
2016 Capital Budget
Page 20
1
achieved using database queries and manual database edits. It is ISO-NE’s
2
expectation that the remaining funding from the settlement will cover most but
3
not all of the costs of developing and implementing the enhancements.
4
Accordingly, the 2016 Capital Budget includes $100,000 for this project. The
5
targeted completion date is the fourth quarter of 2016.
6
Q.
PLEASE DESCRIBE THE PRICE RESPONSIVE DEMAND PROJECT.
7
A.
This project aims to fully integrate demand response into the wholesale markets.
8
The project will create a dispatchable capacity product for demand response,
9
including the application of Peak Energy Rents and performance penalties to
10
demand response, thereby creating disincentives for economic and physical
11
withholding of capacity. In addition, the project will provide a mechanism for
12
capacity replacement for resources that are not able to demonstrate their obligated
13
capacity. Due to the uncertainty surrounding the Commission’s Order No. 745,
14
the ISO has allocated only $100,000 for work in 2016, and currently anticipates a
15
completion date for this project is the third quarter of 2018.
16
Q.
ITEM.
17
18
PLEASE DESCRIBE THE NON-PROJECT CAPITAL EXPENDITURES
A.
The 2016 Capital Budget includes $3.7 million for non-project capital
19
expenditures. Non-project capital expenditures fund external and internal
20
capitalized labor necessary to program System Improvement Requests
2016 Capital Budget
Page 21
1
($2,000,000), non-project related hardware purchases ($1,500,000), and furniture
2
& fixtures ($200,000).
3
Q.
PLEASE DESCRIBE THE “OTHER EMERGING WORK” PROJECTS.
4
A.
This category is primarily intended to deal with emerging work requests during
5
2016 that result from operational needs, compliance obligations or
6
regulatory/stakeholder feedback.
7
Q.
FOR THE PROJECTS INCLUDED IN THE 2016 CAPITAL BUDGET.
8
9
DESCRIBE THE ACCURACY OF THE EXPENDITURE ESTIMATES
A.
The 2016 Capital Budget includes six projects with approved charters: Wind
10
Integration Phase II / Do Not Exceed Dispatch; Forward Capacity Auction 10;
11
Divisional Accounting; Zonal Load Forecast; Power System Modeling
12
Management Initiatives; and NX9/NX12D – Generator Voltage Data. The ISO
13
has not finalized the design, scope, and charters for the remaining projects. As a
14
result, the cost estimates for such items are likely to change. Furthermore, the
15
capital budget is quite dynamic, and the ISO uses it to reflect any changing market
16
needs, when possible. To the extent new and urgent priorities arise, the ISO will
17
adjust accordingly and reflect these adjustments in its quarterly Section 205
18
filings.
2016 Capital Budget
1
2
CAPITAL BUDGET FUNDING
Q.
PLEASE DETAIL HOW THE EXPENDITURES CAPTURED IN THE
CAPITAL BUDGET ARE TYPICALLY FUNDED AND REPAID.
3
4
Page 22
A.
The ISO’s existing and future capital projects are financed by drawing upon the
5
private placement debt, issued with Commission authorization. (See orders in
6
Docket No. ES04-39-000, 109 FERC ¶ 62,195 (2004), and Docket No. ES12-48-
7
000, 140 FERC ¶ 62,173 (September 6, 2012).) The ISO funds the repayment of
8
this debt through recovery of depreciation under its annual operating budgets
9
collected through the rates specified in Section IV.A of the Tariff – Recovery of
10
ISO Administrative Expenses. The Customers that are repaying the charges under
11
the schedules in Section IV.A of the Tariff are receiving the benefits of the
12
services rendered under those schedules. In no case will the costs of items be
13
recovered twice.
14
If for some reason the ISO is unable to use private financing to cover its full
15
capital budget, Section IV.B of the Tariff (the “Capital Funding Arrangements”)
16
provides four different charges the ISO may use to recover such costs from
17
Market Participants. The Capital Funding Charge allows the ISO to collect from
18
Market Participants funds for the direct purchase of capital assets not previously
19
funded by Market Participants if the ISO does not enter into private financing to
20
fund these purchases or the ISO funds the purchases through interim financings
2016 Capital Budget
Page 23
1
and does not enter into private financing to provide long-term funding of these
2
purchases. In order to encourage banks to lend for the ISO’s capital and working
3
capital needs, Section IV.B of the Tariff includes an Early Amortization Capital
4
Charge and an Early Amortization Working Capital Charge. These charges
5
ensure that the ISO can recover its working capital and the unamortized costs of
6
the assets privately financed in the event of termination, acceleration or other
7
required repayment of the loans. Finally, the Early Payment Shortfall Funding
8
Charge allows the ISO to collect from Market Participants such funds as are
9
required for the repayment of the “Shortfall Funding Arrangement” financing
10
entered into by the ISO in support of weekly billing under the Billing Policy.
11
Q.
TO COVER THE 2016 CAPITAL BUDGET?
12
13
IS THE ISO’S CURRENT PRIVATE PLACEMENT DEBT SUFFICIENT
A.
Yes. At this time, the ISO does not foresee the need to recover any 2016 Capital
14
Budget expenditures from Market Participants pursuant to the charges provided in
15
the Capital Funding Arrangements of the Tariff. The ISO has sufficient financing
16
to cover its 2016 Capital Budget by drawing on its private placement debt.
EXHIBIT 7
Exhibit 7
Page 1 of 4
CROSS-REFERENCE TABLE
(showing location in the ISO’s filing of applicable items from
Statements AA - BM in Section 35.13(h))
Statement AA
Balance sheets: See balance sheets from ISO’s 2014 Form 1
(Exhibit 8).
Statement AB
Income statements: See income statements from ISO’s 2014
Form 1 (Exhibit 8 hereto). A comparison of budgeted net
operating expenses for 2016 with budgeted 2015 operating
expenses is contained in Exhibit 3, RCL-5, Schedules 3 and 4.
Statement AC
Retained earnings statement: Not applicable.
Statement AD
Cost of plant: The ISO’s “plant” consists of office furniture and
equipment (Account 391). The ISO does not own generation,
transmission or distribution equipment. See 2014 ISO Form 1
balance sheet (Exhibit 8) at page 110, lines 2 and 4. The three
“functions” of the ISO (and reflected in Section IV.A. of the ISO
New England Inc. Transmission, Markets and Services Tariff,
FERC Electric Tariff No. 3 (the “Tariff”)) are the three Services 1
provided by the ISO.
Statement AE
Accumulated depreciation and amortization: See 2014 ISO Form
1 balance sheet (Exhibit 8) at page 110, line 5.
Statement AF
Specified deferred credits: Not applicable
Statement AG
Specified plant accounts (other than plant in service): Not
applicable, because the ISO is not seeking a return on rate base.
Statement AH
Operation and maintenance expenses: These are functionalized
among the Services in Exhibit 3.
Statement AI
Wages and salaries: These are functionalized among the Services
in Exhibit 3, RCL-3, Schedules 2.0 and 4.0. A comparison of
staffing levels for 2015 and 2016 is contained in Exhibit 3, RCL-5,
Schedule 5.
Statement AJ
Depreciation and amortization (lease and sublease) expenses:
These are functionalized among the Services in Exhibit 3, RCL-3,
Schedule 3.0. Depreciation and amortization rates are discussed in
1
Capitalized terms not otherwise defined in this Exhibit have the meanings ascribed thereto in the Tariff.
Exhibit 7
Page 2 of 4
Section I.C.2 of the transmittal letter and in Mr. Ludlow’s
testimony (Exhibit 3).
Statement AK
Taxes other than income taxes: See Exhibit 3, RCL-5, Schedules 1
and 2.
Statement AL
Working capital: The Commission has authorized a revolving line
of credit of $20 million for the ISO’s working capital needs. See
151 FERC ¶ 62,185 (2015). Due to the nature of the limited plant
owned by the ISO, the concepts of supplies, fuel supplies, plant
materials and operating supplies are not applicable to the ISO.
Prepaid expenses for the ISO consist mainly of insurance costs.
Statement AM
Construction work in process: not applicable.
Statement AN
Notes payable: see description of notes authorized in 109 FERC
¶ 62,194 (2004); 140 FERC ¶ 62,172 (2012); 140 FERC ¶ 62,173
(2012); 144 FERC ¶ 62,087 (2013).
Statement AO
Rate for allowance for funds used during construction: not
applicable
Statement AP
Federal income tax deductions - interest: The ISO is exempt from
federal income taxation.
Statement AQ
Federal income tax deductions - other than interest: The ISO is
exempt from federal income taxation.
Statement AR
Federal tax adjustments: The ISO is exempt from federal income
taxation.
Statement AS
Additional state income tax deductions: The ISO pays no state
income taxes.
Statement AT
State tax adjustments: The ISO pays no state income taxes.
Statement AU
Revenue credits: Not applicable with respect to generation or
transmission. The 2016 Revenue Requirement reflects credits
from prior year true-up, as described in Section I.C.3 of the filing
letter, and Exhibit 3, RCL-2.
Statement AV
Rate of return: Not applicable because the ISO seeks no rate of
return.
Statement AW
Cost of short-term debt: No short-term debt.
Exhibit 7
Page 3 of 4
Statement AX
Other recent and pending rate changes: The ISO has no operating
revenues that are currently subject to refund.
Statement AY
Income and revenue tax rate data: Not applicable because the ISO
pays no federal or state income tax, and no revenue taxes.
Statement BA
Wholesale customer rate groups:
For each Service (i.e., each Rate Schedule), the cost of service
equals the revenues from the customer group, as ensured by the
true-up mechanism contained in Section IV.A.2.2 of the Tariff.
For Rate Schedule 1, all transmission customers under the Open
Access Transmission Tariff (Section II of the Tariff); for Rate
Schedule 2, all Market Participants that participate in the New
England Markets for energy; for Rate Schedule 3, all Market
Participants that have load, and non-Participant Point-to-Point
Transmission Service customers.
Statement BB
Allocation demand and capability data: Not applicable because the
ISO’s revenue requirement is not based on generation or
transmission expenses. The denominators used in the rate design
for each Service are explained in Section I.E of the transmittal
letter.
Statement BC
Reliability data: Not applicable because the ISO’s revenue
requirement is not based on generation or transmission expenses.
The denominators used in the rate design for each Service are
explained in Section I.E of the filing letter.
Statement BD
Allocation energy and supporting data: Not applicable because the
ISO’s revenue requirement is not based on generation expenses.
The denominators used in the rate design for each Service are
explained in Section I.E of the transmittal letter.
Statement BE
Specific assignment data: See Exhibit 3 for direct allocations to
the three rate schedules in Section IV.A of the Tariff.
Statement BF
Exclusive-use commitments of major power supply facilities: Not
applicable.
Statement BG
Revenue data to reflect changed rates: See Sections I.C and I.E of
the transmittal letter. The entire projected revenue requirement for
a Service (discussed in Exhibit 3) is paid for by the corresponding
customer group described in the Statement BA discussion, above.
Exhibit 7
Page 4 of 4
The billing determinants for each Service are discussed in Section
I.E of the filing letter. The ISO has no fuel clause.
Statement BH
Revenue data to reflect present rate: See Sections I.C. and I.E of
the filing letter.
Statement BI
Fuel cost adjustment factors: not applicable.
Statement BJ
Summary cost tables: See Exhibit 3.
Statement BK
Electric utility department cost of service: See Exhibit 3.
Statement BL
Rate design information: See Section I.E of the filing letter.
Statement BM
Construction program statement: Not applicable.
EXHIBIT 8
EXHIBIT 9
New England Governors, State Utility Regulators and Related Agencies*
Connecticut
The Honorable Dannel P. Malloy
Office of the Governor
State Capitol
210 Capitol Ave.
Hartford, CT 06106
[email protected]
[email protected]
Connecticut Public Utilities Regulatory
Authority
10 Franklin Square
New Britain, CT 06051-2605
[email protected]
[email protected]
[email protected]
Maine
The Honorable Paul LePage
One State House Station
Augusta, ME 04333-0001
[email protected]
Maine Public Utilities Commission
18 State House Station
Augusta, ME 04333-0018
[email protected]
Massachusetts
The Honorable Charles Baker
State House
Boston, MA 02133
Massachusetts Attorney General Office
One Ashburton Place
Boston, MA 02108
[email protected]
Massachusetts Department of Public Utilities
One South Station
Boston, MA 02110
[email protected]
[email protected]
New Hampshire
The Honorable Maggie Hassan
26 Capital Street
Concord NH 03301
[email protected]
[email protected]
New Hampshire Public Utilities Commission
21 South Fruit Street, Ste. 10
Concord, NH 03301-2429
[email protected]
[email protected]
[email protected]
[email protected]
[email protected]
[email protected]
Rhode Island
The Honorable Gina Raimondo
82 Smith Street
Providence, RI 02903
[email protected]
[email protected]
[email protected]
[email protected]
[email protected]
[email protected]
Rhode Island Public Utilities Commission
89 Jefferson Blvd.
Warwick, RI 02888
[email protected]
[email protected]
[email protected]
Vermont
5/1/2015
New England Governors, State Utility Regulators and Related Agencies*
The Honorable Peter Shumlin
109 State Street, Pavilion
Montpelier, VT 05609
[email protected]
[email protected]
Vermont Public Service Board
112 State Street
Montpelier, VT 05620-2701
[email protected]
[email protected]
New England Conference of Public Utilities
Commissioners
89 Jefferson Boulevard
Warwick, RI 02888
[email protected]
Harvey L. Reiter, Esq.
Counsel for New England Conference of Public
Utilities Commissioners, Inc.
c/o Stinson Morrison Hecker LLP
1150 18th Street, N.W., Ste. 800
Washington, DC 20036-3816
[email protected]
Vermont Department of Public Service
112 State Street, Drawer 20
Montpelier, VT 05620-2601
[email protected]
[email protected]
[email protected]
New England Governors, Utility Regulatory
and Related Agencies
Anne Stubbs
Coalition of Northeastern Governors
400 North Capitol Street, NW
Washington, DC 20001
[email protected]
Heather Hunt, Executive Director
New England States Committee on Electricity
655 Longmeadow Street
Longmeadow, MA 01106
[email protected]
[email protected]
Rachel Goldwasser, Executive Director
New England Conference of Public Utilities
Commissioners
Concord, NH 03301
[email protected]
Margaret “Meg” Curran, President
5/1/2015
EXHIBIT 10
September 29, 2015
David J. Vitale
Chairman
ISO New England
One Sullivan Road
Holyoke, MA 01040
Re:
Comments on proposed 2016 ISO New England Budget
Dear Chairman Vitale:
On behalf of the undersigned New England state agencies, we hereby offer
comments regarding the ISO New England (“ISO-NE or “ISO”) proposed 2016
administrative and capital budgets. We welcome this opportunity to provide direct
feedback to you regarding the budgets.
We deeply appreciated the ISO-NE Board of Directors’ (“Board”) Board's
attendance at the budget briefing in June, and commend you and your fellow Board
members for your efforts to keep cost increases within reasonable limits. We
appreciate that the overall cost increase was restricted to 3.9% for the operating budget.
We also appreciate the change to a level funding approach for the defined benefit
pension liability, as it will ease the volatility of the expense.
The processes that have been developed to date, and the efforts of all parties
involved, have helped to limit our comments to two areas. First, we wish to propose a
timing change in the states' review of ISO's budget, to accommodate the Board's
calendar and better align the purpose of the process. Second, we wish to express our
repeated, and continuing concerns about the sustained, rapid growth in staffing levels.
I.
The Budget Review Process Should Occur Sooner in Order to
Provide the Board with the States' Position When the Board
Discusses the Budget.
We believe the new budget review procedure has resulted in a much more
cooperative and productive process. However, we propose that this review process be
modified to occur earlier, so that the States' comments are submitted to the Board prior
to the Board's in-person meeting on the budget. We realize that the Board met and
reviewed the budget on September 17, more than a week before the States' comments
were due. We also understand that the Board will receive the States' comments,
management's response and the results of the NEPOOL Participants' Committee vote
prior to acting on the budget by written consent (electronically) in mid-October. We
Daniel J. Vitale
Chairman, ISO New England
September 29, 2015
Page 2
would like to modify this process so that the Board has the benefit of the States'
comments and ISO management's response when it meets and deliberates in person
on the budget.
The Settlement Agreement provides that the State Parties:
may submit comments regarding any proposed adjustments to the
proposed budget within five weeks after the August budget presentation
meeting but no later than September 25. ISO-NE shall respond in writing
to any written comments and proposed adjustments within two weeks of
receipt, but no later than five business days before the ISO-NE Board of
Directors votes on the proposed budgets.
The intent of providing written comments was to provide the ISO NE Board with
the opportunity to consider and discuss the States' concerns prior to voting on the
budget. Moreover, as last year's comments and this year's comments should
demonstrate, knowledge of the questions submitted is not dispositive of the States'
position on a budget. To comply with the intent of the Settlement Agreement, and to
provide the Board with the States' views during the Board's in-person review of the
budget, we request that the process be modified to ensure that the Board has the
States' comments prior to reviewing the budget in person.
II.
The Continuing Escalation of Staff
With this budget, ISO-NE will have added 52 full-time, funded employees since
FY 2013. 1 As the first substantive term in the 2013 Settlement Agreement, ISO-NE
agreed that it would rely:
to the greatest extent possible on its current employee complement to
perform all existing and proposed new projects, and shall document its
efforts to do so as set forth below.
Section II.A of the Settlement Agreement. An additional 52 full-time, funded positions
does not appear to comport with this obligation. Moreover, this continuing escalation of
staff is not sustainable.
1
As of December 31, 2012, ISO-NE had 539.5 FTEs. By the end of 2013, ISO-NE
employed 560 FTEs, and by the end of 2014, had 567.5 employees. Pursuant to last
year's budget, ISO has 577 funded FTE positions for this year, of which 576 were filed
by June 30, 2015. From FY2013 to FY2015, ISO-NE added 43.5 new funded FTE
positions in its budgets, and now seeks to add an additional 8.5 FTEs for FY 2016, for a
total of an additional 52 full-time, funded positions since FY2013.
Daniel J. Vitale
September 29, 2015
Page 3
As part of its oral presentation in June 2015, ISO management stated that it
would not seek additional FTE positions for its FY 2017 budget. When asked to confirm
this commitment, management responded "That is our current intention, but it is subject
to changes in workload brought about by regulatory and other exigent priorities." Every
state agency and most businesses have workload changes and exigent priorities, and
yet do not have the ability to add employees when a significant new directive arises.
Rather, as new directives are introduced, other priorities must make way or other
efficiencies must be explored.
We ask you to address this repeated, multi-year concern. The growth in full-time
employees served as one of the major drivers for the challenge to the budget that
resulted in the Settlement Agreement now governing this budget review process. We
are available to meet with management or the Board on this issue if it would assist in
resolving this continuing issue.
CONCLUSION
The undersigned New England State Agencies are heartened by the progress
made during this year’s budget review. However, we ask that the process for next
year's budget review be rescheduled so you have the benefit of our comments before
you deliberate and discuss the budget in person, and we look forward to discussing this
proposal with management. We also respectfully request that you consider and
address our continuing concern with the escalation of staffing levels at ISO NE.
Respectfully submitted,
_/s/ Arthur H. House_______
Arthur H. House
Chairman
Public Utilities Regulatory Authority
Ten Franklin Square
New Britain, CT 06051
_/s/ Elin Swanson Katz_________
Elin Swanson Katz
Consumer Counsel
Office of Consumer Counsel
Ten Franklin Square
New Britain, CT 06051
_/s/ George Jepsen_______
George Jepsen
Attorney General
Office of the Attorney General
55 Elm Street
Hartford, CT 06105
_/s/ Ed McNamara_________
Ed McNamara
Regional Policy Director
Vermont Department of Public Service
112 State Street
Montpelier, VT 05620
Daniel J. Vitale
September 29, 2015
Page 4
_/s/ Leo J. Wold_______
_/s/ Susan Chamberlin___________
Leo J. Wold, Assistant Attorney General
Susan Chamberlin
Rhode Island Department of Attorney General Consumer Advocate
150 South Main Street
Office of the Consumer Advocate
Providence, RI 02903
21 South Fruit Street
For Peter F. Kilmartin, Attorney General
Concord, NH 03301
of the State of Rhode Island and the
Rhode Island Division of Public Utilities and Carriers
EXHIBIT 11
Philip Shapiro
Chairman, Board of Directors
October 9, 2015 Susan W. Chamberlin, New Hampshire Consumer Advocate Arthur H. House, Chairman, Connecticut Public Utilities Regulatory Authority George Jepsen, Connecticut Attorney General Elin Swanson Katz, Connecticut Consumer Counsel Peter Kilmartin, Rhode Island Attorney General Ed McNamara, Vermont Department of Public Service Leo Wold, Rhode Island Division of Public Utilities and Carriers Dear State Officials: Thank you for your letter dated September 29, 2015 regarding ISO New England’s 2016 operating and capital budgets. I appreciate your comments and your involvement in ISO New England’s budget process. Below, I address your comments. Budget Review Process In your letter, you propose modifying the budget review process to ensure that the ISO Board of Directors receives the states’ comments before the Board’s September meeting, at which the Board reviews the budgets in detail. As you note, the states’ comments are due no later than September 25, and the Board typically meets in the middle of September. In 2016, the Board will meet on September 15. We would be very happy to have the benefit of the states’ formal comments for consideration at our Board meeting.1 If the states are able to offer their written comments before the Board meeting, I will ensure that they are distributed to the full Board. Currently, the budget review process entails a number of steps before the states submit their comments. These steps include: (i) the ISO’s preparation of the comprehensive budget presentation; (ii) a budget review meeting with the states within three days of the ISO’s meeting with the NEPOOL Budget & Finance Subcommittee; (iii) the ISO’s receipt of questions from the states within two weeks of the budget review meeting; and (iv) completion of the ISO’s responses to the questions within a week of their receipt. The timeline to complete these steps is constrained by the time required to prepare the budget presentation and the meeting date with NEPOOL. As you note in your letter that “knowledge of the questions submitted is not dispositive of the States’ position on a budget,” I am hopeful that the change required to meet your objective is as simple as the states submitting comments early in the 1
The Board also receives informal feedback from the states about the budget, including through Board attendance at the NECPUC annual symposium. ISO New England Inc. One Sullivan Road Holyoke, MA 01040‐2841 413‐535‐4000 iso‐ne.com
isonewswire.com
@isonewengland
iso‐ne.com/isotogo
iso‐ne.com/isoexpress
State Officials October 9, 2015 Page 2 of 2 process. In that case, we understand that you may reserve your rights to submit further comments pending the completion of the above‐referenced process. If you believe that further change to the process is required, I will ask the ISO’s staff to work with you and NEPOOL. Although, as noted above, the timeline is constrained, we believe that we can move the steps forward by approximately a week on our end. With the consent of you and NEPOOL, the revised process would require: our circulation of the budget presentation during the first week of August; holding the Budget & Finance Subcommittee and state meetings during the second week of August; the states’ submission of their questions within a week of their meeting; and the ISO’s submission of answers within the next week. This schedule should enable you to deliver your comments to the Board before the mid‐September meeting. Headcount In your letter, you note that the ISO will have added 52 full‐time employees over the course of 2013, 2014, 2015 and 2016. You also note our obligation to use existing employees to perform all work, to the greatest extent possible. We do not believe that these two facts are mutually exclusive. Simply put, our workload has grown beyond an amount that our existing employees can handle. In general, this is due to requirements imposed on us by the Federal Energy Regulatory Commission and priorities established by stakeholders and the states. For example, the growth of renewable and distributed energy as a result of state policies will increase the complexity of planning for and operation of the system – and additional resources may be required to maintain the reliability of the grid. The foregoing is just one example of a situation in which the Board, exercising its fiduciary duty, and management (joined, possibly, by stakeholders) may determine that there are unacceptable risks in not hiring. That was the case for 2016, when we directed management to establish a 24/7 cyber security control center. The center accounts for the bulk of the headcount additions in 2016. The remaining full‐time positions were identified as necessary by our internal market monitor. You note that ISO management has stated their intention to keep headcount flat in 2017. As this statement indicates, we are aware of the cost implications of increasing headcount. Accordingly, we plan to use consultants to manage the variability of our workload in 2017, but will continue to measure the costs of so doing against the costs of using full‐time employees. (As reported in past years, some of the 52 headcount that were added served to reduce our overall costs.) We will also balance our intention to keep headcount flat in 2017 against our recognition of the risks that are sometimes inherent in forgoing additional resources. Thank you again for your letter. We look forward to continuing to work together with you to ensure the continued reliable and efficient delivery of electricity to New England. Sincerely, Philip Shapiro Chairman of the Board of Directors ISO New England Inc. One Sullivan Road Holyoke, MA 01040‐2841 413‐535‐4000 iso‐ne.com
isonewswire.com
@isonewengland
iso‐ne.com/isotogo
iso‐ne.com/isoexpress

October 16, 2016 VIA ELECTRONIC FILING Honorable Kimberly D

Transcription

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