October 16, 2014
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 2015 Capital Budget and Revised Tariff Sheets for Recovery of 2015 Administrative Costs; Docket No. ER15-______
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 2015 (the “2015 Capital Budget”) and a revised Section IV.A of the Tariff to reflect the collection of its administrative costs for calendar year 2015 (the “2015 Administrative Expenses Tariff”). The ISO requests that the Commission accept the 2015 Capital Budget and the 2015 Administrative Expenses Tariff as filed, effective January 1, 2015.
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 2015 Capital Budget or the 2015 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 2015 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, 2014 Page 2 of 32
that the Commission accept the 2015 Capital Budget and the 2015 Administrative Expenses Tariff without suspension and not subject to refund.3
Should the Commission have any questions regarding the 2015 Capital Budget or the 2015 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, 2015. 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 2015 REVENUE REQUIREMENT AND REVISED SHEETS
A. Overview
This filing presents the 2015 Revenue Requirement4 for operating the ISO. Before incorporating the true-up for actual expenses and collections in 2013, the 2015 Revenue Requirement is $178.3 million, which is $9 million more than in 2014. After the over-collection for 2013 is incorporated, the total 2015 Revenue Requirement decreases to $168.5 million. In comparison, the 2014 total was $171.2 million. Using another metric, if the ISO’s Revenue Requirement was fully passed through to end-use customers, their cost would average 90 cents per month, down from 2014 levels of 92 cents.5
For 2015, the ISO is anticipating increased costs both to maintain the status quo and to fund established initiatives. To maintain the status quo, the ISO must fund the higher costs of existing software licenses, pension and medical benefits, fees for the Northeast Power Coordinating Council (“NPCC”) and North American Electric Reliability Corporation (“NERC”), and competitive compensation. The ISO’s established initiatives, which also require funding, include implementation of Coordinated Transaction Scheduling, Energy Market Offer Flexibility, and efforts to prudently address heightened cyber security risks.
The ISO was able to offset many of these costs with savings, automation and efficiencies totaling $4.3 million. In sum, the 2015 Revenue Requirement is 5.3% higher than in 2014
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 under- collection in revenues versus expenses. Generally, numbers used herein are rounded for ease of reference and, accordingly, may not sum. 5 See slide 12 of the ISO’s annual budget presentation to stakeholders (the “Budget Presentation”) for detail on this calculation, at http://www.iso-ne.com/static-assets/documents/2014/09/2_2015_operat_cap_budget_update_v2.pdf. October 16, 2014 Page 3 of 32
(before true-up). With credit for the overcollection in 2013, the 2015 Revenue Requirement is 1.6% lower than the 2014 Revenue Requirement.
The remainder of this Section I describes:
• the 2015 budget development process (Section B); • components of the 2015 Revenue Requirement (Section C); • the three services provided by the ISO and funded by the 2015 Revenue Requirement (Section D); and • the allocation of costs among the three primary schedules and the development of the rates reflected in the 2015 Administrative Expenses Tariff (Section E).
B. 2015 Budget Development Process
The ISO has always operated in a climate of cost accountability and transparency.6 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 can 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 2015 Core Operating Budget. The full seven-step process, throughout which stakeholder input was sought, requires the ISO to:
• define objectives, activities, and goals; • identify efficiencies for each department; • determine resource requirements; • develop budget estimates for each department;
6 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, 2014 Page 4 of 32
• 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 17, 2014 meeting with the New England Conference of Public Utilities Commissioners. The ISO then developed its 2015 Revenue Requirement proposal, which was ultimately lower than the preliminary estimate, given negotiation of lower costs for medical benefits and a cut to the proposed budget for promotional increases.
Next, the ISO posted the detailed Budget Presentation, which includes more than 120 slides regarding the 2015 Capital Budget and the 2015 Revenue Requirement,7 and reviewed the Budget Presentation at the NEPOOL Budget and Finance Subcommittee’s August 27, 2014 meeting and at a meeting for state agencies on August 28, 2014. Following the August 28 meeting, a number of the state agencies submitted written questions regarding the budgets on the topics of headcount, compensation, capital spending and depreciation. ISO-NE provided answers within a week, following which the state agencies provided written comments regarding headcount, the sufficiency of the Board’s budget review, and consumer costs. Those comments and the ISO’s response are located at Exhibits 10 and 11 to this filing letter.8
The ISO reviewed the 2015 Capital Budget and the 2015 Revenue Requirement at the NEPOOL Participants Committee’s meetings on September 12 and October 3, 2014. At the October 3 meeting, the two budgets were supported unanimously by the Participants Committee (with abstentions).9
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.
7 See footnote 5. 8 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. 9 The vote was conducted by show of hands. Although a formal roll call vote was not requested or taken, members and alternates were provided with an opportunity to register oppositions and abstentions, with those not registering an opposition or abstention deemed to support the budgets. Abstentions were noted by the Massachusetts Municipal Wholesale Electric Company and each of the Publicly Owned Entities that it represents, Littleton (NH) Water & Light Department, Vermont Electric Cooperative, and Vermont Public Power Supply Authority. October 16, 2014 Page 5 of 32
The full Board is also involved. 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 in-depth review of the budgets at its September meeting. Last, after receiving final feedback from stakeholders, the Board votes on the budgets.10 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 2015 budgets effective October 16, 2014.
C. The 2015 Revenue Requirement
This section provides an overview of the 2015 Revenue Requirement and detail regarding its significant components. As noted above and shown in more detail in Exhibit 3, the 2015 Revenue Requirement, after the true-up for 2013, is $168.5 million.11 It includes the following components:
• the 2015 Core Operating Budget ($146.6 million); • depreciation and amortization of regulatory assets ($31.7 million); and • a true-up for 2013 that reduces the 2015 Revenue Requirement by $9.8 million as a result of over-collection of ISO rates in 2013. Each of these components is discussed below, with further details supporting the ISO’s costs provided in the testimony of Robert C. Ludlow, the ISO’s Chief Financial Officer, and the exhibits thereto. Mr. Ludlow’s testimony is attached at Exhibit 3.
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 2015 that exceed the allocated amounts and contingencies. Specific potential risks include unforeseeable litigation, imposition of new requirements by policymakers, and interest rate changes.
In general, the demands Market Participants and regulators place on the ISO 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 by a net amount of approximately $5.7 million from 2014 levels to: (i) maintain competitive compensation and
10 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 11 See the Budget Presentation for a breakdown of the Revenue Requirement by functional area (slides 22-43) and category (slides 62-66). October 16, 2014 Page 6 of 32
benefits, existing financing, and NERC and NPCC membership ($5.4 million); (ii) fund established initiatives, including Energy Market Offer Flexibility and Coordinated Transaction Scheduling ($2.1 million); and (iii) support both current initiatives and previously-implemented initiatives by funding increases in computer services, systems maintenance and cyber security, and other support services ($2.5 million). Below, the ISO discusses the costs in each of these categories, including the addition of 9.5 employees,12 and then reviews the savings, efficiencies, and non-recurring work that offset these increases by the amount of $4.3 million.13
a. Increases to Maintain Competitive Compensation and Benefits and NERC and NPCC Membership
The cost increases in this category are needed to maintain the status quo. For example, to maintain its membership in NERC and NPCC, the ISO must pay an additional $400,000 in fees, and the ISO’s existing financing is anticipated to be more expensive (by $100,000) given increased debt service costs and bank fees and reduced interest income. Similarly, to maintain medical benefits for its employees and to fund its pension plans, the ISO will incur an additional $2.1 million in costs. In the case of the pension plans, changes in the discount rate and new mortality tables contribute to the rising costs; the medical costs are influenced in part by the ISO’s claims history.
This category also includes the budget for merit and promotional increases. The ISO uses these funds to keep its 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, eight candidates have declined the ISO’s job offers in 2014 because, in their estimation, the compensation was insufficient. In addition, nine employees have left the ISO for higher-paying jobs this year. With this turnover comes inefficiency; for example, it takes more than six months to fill a transmission engineer vacancy, followed by an inevitable learning curve.
The ISO has budgeted the sum of $2.8 million for a 3.0% increase in salaries for merit and a .5% increase for promotions. To establish these amounts, the ISO reviewed 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 2015 Revenue Requirement recommendations collectively polled thousands of employers and include both all-industry and utility-specific data.14
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
12 See slide 21 of the Budget Presentation for a breakdown of the new additions. 13 See the Budget Presentation for more information on all of these year-over-year budget changes. 14 The surveys used by the ISO were conducted by Buck Consultants, Mercer, WorldatWork, the Conference Board, Towers Watson and Aon Hewitt. October 16, 2014 Page 7 of 32
similarly-situated organizations, both taxable and tax-exempt, for functionally comparable positions.15
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 similarly- situated entities. The Commission has found that this process results in just and reasonable compensation.16
The testimony of Janice S. Dickstein, the ISO’s Vice President, Human Resources, provides more detail on the ISO’s compensation practices, as does the Budget Presentation (at slides 44-61).
b. Funding for Established Initiatives
The cost increase of $2.1 million in this category results from ISO-NE’s established commitments to implement programs and practices, including Energy Market Offer Flexibility ($600,000), Coordinated Transaction Scheduling ($500,000) and changes to the Forward Capacity Market (with funding for other priorities, $1,000,000). While these costs reflect the use of existing employees and consulting services to the greatest extent possible to perform the work, given that the capacity to take on new work is limited, the ISO is adding limited personnel to implement these new programs and practices where needed.
The Energy Market Offer Flexibility project responds to strategic risks, including those related to gas dependency. The project will allow generators increased flexibility to change their bids, which will allow generators to respond to and recoup variable fuel costs and will encourage improved generator performance. The costs for this project include .75 of a full-time employee to support the dramatically increased data flows, additional software licenses for real-time data applications, and consulting support for energy management systems and network modeling.
Coordinated Transaction Scheduling will improve market efficiency (and lower costs) across New England and New York. The costs fund an increase of 1.25 employees, as well as staff augmentation through consultants, to handle the increased frequency of data between the control areas and to support more than fifty new data bridges and additional user interfaces. The work of other employees in Market Operations Support and Market Settlements is being reallocated in order to accommodate increased workload in those areas.
15 See Internal Revenue Code § 4958. 16 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, 2014 Page 8 of 32
Finally, this category includes the reallocation of internal resources to 2015 priorities, including work by the System Planning Department on Forward Capacity Market (“FCM”) initiatives, including new capacity zone evaluation and reconfiguration, development and implementation of zonal demand curves, and evaluation of natural gas availability as part of resource qualification. This category also includes the reallocation of Market Operations and Settlements personnel to the new divisional accounting functionality, sub-hourly settlements, third-party administration of Financial Transmission Rights, Customer and Asset Management System improvements, and Oracle Business Intelligence Report Integration. Finally, System Operations will reallocate personnel to develop a training program for non-operations staff in compliance with NERC standards.
c. Support for Initiatives By Funding Increases in Computer Services, Systems Maintenance, Cyber Security and Other Inflationary Increases
The costs in this category include $600,000 for cyber security initiatives. The ISO’s increased work in this area reflects its uniquely vulnerable position, as the ISO maintains a trifecta of sensitive information regarding the financial settlement of billions of dollars per year, the topology of the grid, and the protected information of Market Participants and employees. As a result, ISO-NE plans to add 2.5 employees in the Information Technology Department to support the increased cyber security needs, and to fund computer service costs, including for Distributed Denial of Service mitigation software.
This category also includes $1.5 million to perform additional work to support current initiatives as well as implemented initiatives. These costs reflect 3.5 new employees in Information Technology and Program Management to support FCM, software testing, power system modeling, financial systems/database support and increased consulting costs for desktop support and other applications. This category also includes computer service licenses and maintenance for new and enhanced systems, including FCM, asset and license management, the redesigned website, the project to integrate variable resources, storage sub-systems, virtual PC environments required by the Business Continuity Project, and network modeling.
Finally, there are miscellaneous costs amounting to $400,000 for the addition of a Payroll Supervisor in the Finance Department and to make a part-time Business Analyst full-time. The latter results in consultant savings above the staffing costs. This category also includes increased costs of employee training, oil and coal price monitoring subscriptions, telecommunications, leased computer equipment, and Back-up Control Center operating costs.
d. Offsetting Deferrals and Eliminations; Direct Charge Activities
The ISO works to offset increased costs through cost-cutting and reallocation of resources to emerging initiatives. For 2015, the ISO has realized $4.3 million by reallocating resources, automating work, identifying efficiencies, and eliminating discontinued or non- repetitive work.
In particular, the ISO has eliminated funding for non-recurring 2014 work (e.g., Net Commitment Period Compensation), and has absorbed some consultant work. The ISO also October 16, 2014 Page 9 of 32
expects to reduce salaries as a result of staff turnover, and reduce building services fees as a result of contract negotiation. Finally, system automation will result in reduced data gathering or processing time.
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,17 information requests,18 non-standard contract provisions,19 and non-standard billing.20 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 2015 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 2015, the ISO’s depreciation and amortization costs are $31.7 million, which is $3.3 more than in 2015. The increased costs are largely attributable to a number of significant capital projects expected to go into service in the second half of 2014 or the first half of 2015, including Energy Market Offer Flexibility, Simultaneous Feasibility Test and Market System Upgrade, Web Enhancements Phase II, NX9/NX12 Data Integration and Automation Phase II, and Generation Control Application Production Part 1. In addition, the ISO will also bear the costs of the first full year of depreciation on the new Back-up Control Center.
The ISO’s depreciation rates remain unchanged from those previously accepted by the Commission.21 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 appropriate. The service lives are:
• Computer hardware, software and accessories: 3 to 5 years
17 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. 18 Tariff § IV.A.6.2 (Information Requests). 19 Tariff § IV.A.6.3 (Non-Standard Provisions). 20 Tariff § IV.A.6.4 (Non-Standard Billing Service). 21 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). October 16, 2014 Page 10 of 32
• 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 2015 Revenue Requirement includes an adjustment for deviations between actual collections and expenses for calendar year 2013. 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 2013 true-up, the ISO collected $9.8 million more than it needed to pay its expenses.22 This sum will be subtracted from the 2015 Revenue Requirement.
With respect to Schedule 1, the ISO had expenses of $36.7 million, and collected revenues of $41.1 million, resulting in an over-collection for Schedule 1 (i.e., the decrease to the 2015 Revenue Requirement for Schedule 1) of about $4.4 million.23 With respect to Schedule 2, the ISO had expenses of $71.6 million and collected revenues of $74.6 million, resulting in an over-collection for Schedule 2 (i.e., the decrease to the 2015 Revenue Requirement for Schedule 2) of approximately $3 million.24 Finally, with respect to Schedule 3, the ISO had expenses of $48.5 million and collected revenues of $50.8 million, resulting in a net over-collection for Schedule 3 (i.e., the reduction to the 2015 Revenue Requirement for Schedule 3) of approximately $2.3 million.25
22 See Exhibit 3, RCL-2, Schedule 2, page 1 of 2. 23 See Exhibit 3, RCL-2, Schedule 2, page 2 of 2. 24 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. 25 See Exhibit 3, RCL-2, Schedule, 2 page 2 of 2. October 16, 2014 Page 11 of 32
D. Services Funded by the 2015 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)
Schedule 1 of the Tariff provides the terms, conditions and rates for the ISO’s provision of Scheduling Service, which includes the transmission-related Ancillary Services identified in Schedule 1 of Section II of the Tariff. The 2015 Revenue Requirement for Schedule 1 (including true-ups) is $37.9 million.
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.
Functions performed by the ISO in connection with this Service include:
• 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.
2. Energy Administration Service (Schedule 2)
Energy Administration Service is the service provided by the ISO to administer the Energy Market. The 2015 Revenue Requirement for Schedule 2 (including true-ups) is $78 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; October 16, 2014 Page 12 of 32
• 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 transmission and Energy 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 2015 Revenue Requirement for Schedule 3 (including true-ups) is $52.6 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; • preparation of regional reports and load forecasts and profiles (Capacity, Energy, Load and Transmission 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 October 16, 2014 Page 13 of 32
determinants used by each schedule; (iii) explaining how the ISO adjusted the billing determinants for 2015; (iv) describing the rates ultimately derived for 2015 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.26 The ISO established the core rate design for its first three schedules through an uncontested settlement approved by the Commission in 2001,27 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 2015 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 non- labor-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 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.
26 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”). 27 See Settlement Agreement in Docket No. ER01-316-000 (filed June 1, 2001). October 16, 2014 Page 14 of 32
a. Schedule 1
The billing determinants for Schedule 1 are Monthly Regional Network Load and Reserved Capacity. 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 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 Financial Transmission Right (“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 Block- Hours, 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 three- tiered 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%.
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. October 16, 2014 Page 15 of 32
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 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.
c. Schedule 3
Schedule 3 allocates internal load activity based on Real-Time NCP (Non-Coincident Peak) Load Obligation measured in kilowatts. Additionally, for Exports, Schedule 3 assesses a volumetric (per MWh) charge. Specifically, the ISO divides the Schedule 3 Revenue Requirement by the Real-Time Load Obligation forecasted for the upcoming year in the most recent Capacity, Energy, Loads and Transmission (“CELT”) Report. 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 kilowatt-month.28
3. Adjusting Billing Determinants for 2015
The data used in designing the proposed rates in the 2015 Administrative Expenses Tariff was taken from the ISO markets system for the 12-month period ending July 2014. Consistent with the practice reflected in the ISO’s Tariff filings for 1999 through 2014, the ISO also relied upon information contained in the annual CELT Report.29 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 2014 suggests that the estimated data for August 2014 through December 2014 should be based, without change, on 2013 data. The ISO’s analysis of the data also led to an increase of 1.5% in the projected data for 2015 (over 2014 levels) for the Schedule 1 (i.e., Regional Network Load) billing determinant, the load-related (volumetric) measures in Schedule 2, and the Schedule 3 billing determinant related to Real-Time NCP Load Obligation.
The Schedule 2 transaction unit determinants for Energy TUs, virtual transactions and FTRs were left flat for 2015. The decision regarding Energy TUs was based on a review of the volume of transactions, which has been consistent for several years. 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.
Finally, ISO-NE reduced, by 15%, the Schedule 3 volumetric charge for Exports. The decision was made because, although the determinants had been left flat for a number of years,
28 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. 29 ISO New England Inc., 2014-2023 Forecast Report of Capacity, Energy, Loads and Transmission (May 2014). See http://www.iso-ne.com/static-assets/documents/trans/celt/report/2014/2014_celt_report_rev.pdf. October 16, 2014 Page 16 of 32
the actual MWh have been less than the projected sums in the years 2011 through 2014 to date. Moreover, ISO-NE’s analysis concluded that the trend is not likely to reverse in 2015. Accordingly, the ISO reduced this determinant by 15%, which is the average amount of the under-projection.
4. Deriving the 2015 Rates
a. Rate Development for Scheduling Service (Schedule 1)
The ISO’s Revenue Requirement for Schedule 1 totals $37.9 million. The total underlying annual billing determinants for Schedule 1 are 243,679,448 kilowatt-months,30 reflecting the escalation factor as discussed above, based on actual plus forecasted activity in 2014. The resulting rate is $0.15570 per kilowatt-month, which is billed as $0.00021 per kilowatt-hour. 31
b. Rate Development for Energy Administration Service (Schedule 2)
In determining the ISO’s Revenue Requirement for 2015, the ISO includes a true-up for 2013 based on both the TU and VM portions of Schedule 2.32 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 over- recovery) 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 2015 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.
The TU recovery for 2013 was an over-collection of TU revenue in the amount of $944,459. 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.33
30 Exhibit 3, RCL-7, Schedule 3, Line 2. 31 Exhibit 3, RCL-7, Schedule 3, Lines 2-3. 32 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. 33 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 over-collection of $3 million. October 16, 2014 Page 17 of 32
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 2015 budget costs assigned to Schedule 2 total approximately $78 million after true-up.34 Of this total cost, $11.7 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. Included in this amount is $11.1 million of costs incurred under a declining block rate, billed as follows: $0.65101 per TU for Block 1; $0.59182 per TU for Block 2; and $0.53264 per TU for Block 3.35 Total projected Energy TUs for 2015 are 17,628,151.36 In addition, $599,982 has been budgeted for operating the FTR auction, and will be recovered through the following rates: $.85853 per FTR bid submitted; and $1.21377 per FTR bid that clears the auction.37 Finally, the TU Revenue Requirement includes $33,409 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.38
The remainder of the total Schedule 2 cost for 2015, approximately $66.3 million39 (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: $0.25517 per VM for Block 1; $0.23197 per VM for Block 2; and $0.20877 per VM for Block 3.40 Total projected Schedule 2 VMs for 2015 are 272,019,810.41
c. Rate Development for Reliability Administration Service (Schedule 3)
The ISO’s 2015 Revenue Requirement for Reliability Administration Service consists of its expenses for the functions required to provide the Service, as described above. These expenses, totaling $52.6 million after true-up, are detailed in Exhibit 3, RCL-3, Schedule 1 to 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 towards internal load); and (ii) a per-MWh rate for Exports. The total underlying Real-Time NCP Load Obligation is 272,169,942 kilowatt-months.42 The resulting rate is $0.18763 per kilowatt- month.43 The Export rate is $0.37 per MWh.44
34 Exhibit 3, RCL-3, Schedule 1. 35 Exhibit 3, RCL-7, Schedule 3, Line 6 and Lines 16-19. 36 Exhibit 3, RCL-7, Schedule 3, Line 20. 37 Exhibit 3, RCL-7, Schedule 3, Lines 12-13. 38 Exhibit 3, RCL-7, Schedule 3, Lines 8-9. 39 Exhibit 3, RCL-7, Schedule 3, Line 22. 40 Exhibit 3, RCL-7, Schedule 3, Lines 23-25. 41 Exhibit 3, RCL-7, Schedule 3, Line 26. 42 Exhibit 3, RCL-7, Schedule 3, Line 31. 43 Id. October 16, 2014 Page 18 of 32
Schedule 3 also includes Reliability Administration Service fees applicable to Non- Market 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 2015 Revenue Requirement to the Schedule 3 forecasted Revenue Requirement for 2002 to the 2002 Reliability Administration Service Fee, to obtain a monthly Fee of $2,202.27, or an hourly rate of $3.02. See Mr. Ludlow’s testimony at Exhibit 3 (pages 39-40) 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 $3,871,739 (from $38,455,349 to $42,327,088), an increase in Schedule 2 of $2,266,756 (from $78,752,397 to $81,019,153), and an increase in Schedule 3 of $2,852,221 (from $52,116,450 to $54,968,671). Several factors contributed to this result.
Schedule 1. The increase in the Revenue Requirement for Schedule 1 results from 2015 cost increases and changes that impact all three schedules, including the costs to maintain the status quo for benefits and compensation, the costs of cyber security improvements, computer service licensing and maintenance and the Energy Market Offer Flexibility project, along with depreciation expenses for projects including Energy Market Offer Flexibility, Business Continuity Planning Phase III, and a full year of the new Backup Control Center. The remainder of the Schedule 1 increase is due to projects that are predominantly or entirely allocated to Schedule 1, including Coordinated Transaction Scheduling and depreciation expense therefor, as well as depreciation expense for the Voltage Stability and Control Room Visualization projects. 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. This increase was offset by a reduction in depreciation expense due to the full depreciation of a number of projects, including Standard Market Design Upgrade Phase III, Automated Market Mitigation, and Generation Control Application Phase I.
Schedule 3. The increase in the Schedule 3 Revenue Requirement is due to the increased costs allocated to all three schedules (see above), increased NPCC and NERC dues, and depreciation expense for projects allocated entirely to Schedule 3, including Forward Capacity Auction 9, Alternative Technologies and Regulation Market, and FCM Terminations and Retirements. These costs were partially offset by a reduction in costs related to Order 1000.
II. ISO-NE’S 2015 CAPITAL BUDGET
The 2015 Capital Budget is a list of the ISO’s planned capital expenditures in 2015. The ISO does not make any collections through its capital budget; rather, the capital projects reflected therein are funded through private placement financing. The only collections the ISO ______(...continued) 44 Exhibit 3, RCL-7, Schedule 3, Line 32. October 16, 2014 Page 19 of 32 will make for 2015, including for debt service, are through the 2015 Administrative Expenses Tariff discussed in Section I above.
Before describing the projects that comprise the 2015 Capital Budget in Section II.C, the ISO provides context for the Capital Budget in Sections II.A and B.
A. The 2015 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
(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.45 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 ….”46
After the ISO commenced operations in 1997, it spent several years trying to obtain third- party private financing consistent with the Commission’s directive to maintain independence
45 New England Power Pool, 79 FERC ¶ 61,374 at p. 62,590 (1997). 46 Id. October 16, 2014 Page 20 of 32
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 2015 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 2015 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 2015. As a result, the ISO does not anticipate assessing charges to Market Participants under the Capital Funding Arrangements in calendar year 2015.
B. The Transparency of the 2015 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 Committee47 and representatives of the New England states’ public utilities commissions.48 Following this review, the ISO Board of Directors approves the annual capital budget.49 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
47 The process for Market Participant review of ISO budgets is specified in Section IV.B.6.1 of the Tariff. 48 See Section I.B above for a description of the 2015 process. 49 See Section IV.B.6.1 of the Tariff. October 16, 2014 Page 21 of 32
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 2014. The accounting is consistent for those capital projects that are reported both in the quarterly update and in the 2015 Capital Budget, although the focus of the two filings is different (i.e., 2014 versus 2015).
In sum, the ISO’s capital budgeting practices create a high degree of transparency and accountability that is unparalleled among other independent system operators (“ISOs”) and regional transmission organizations (“RTOs”)—and even among other public utilities.
C. Elements of the 2015 Capital Budget
The 2015 Capital Budget is $28 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 2015 Capital Budget projects is application software and requisite hardware needed to maintain and improve bulk-power system reliability and/or wholesale electric markets.50 Typically, most of the ISO’s capital projects stem from market initiatives identified in conjunction with stakeholders as priorities. The market enhancements are intended to improve Energy Markets, Ancillary Services Markets and FCM. The ISO believes that these improvements will ultimately assure Market Participants that they will continue to receive reliable electricity at efficient prices, which will engender increased confidence in the 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 believes its capital projects will benefit the region’s stakeholders by improving the ISO’s ability to maintain bulk-power system reliability, administer fair and efficient markets, and provide information to stakeholders to increase transparency and facilitate decision-making.
50 Capital projects also include design work. If a project’s design is approved and built, it 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 design work and recovers it in full in the year of abandonment. October 16, 2014 Page 22 of 32
The ISO’s 2015 Capital Budget is funded by private placement debt.51 The ISO funds the capitalized portion of the interest on that debt through recovery of depreciation under its annual operating budgets collected through the rates specified in Section IV.A. of the Tariff.52 The costs of these projects are collected once only, through the depreciation recovery in the Revenue Requirement.53
The following are the specific projects that are anticipated to comprise the 2015 Capital Budget. The projects listed in Sections 1 through 7 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. Coordinated Transaction Scheduling ($4,170,500)
In July 2010, ISO-NE and the New York Independent System Operator commenced this project to improve the operational and economic efficiency of the two ISOs by coordinating the scheduling of wholesale electricity sales between the two regions and reducing the costs for consumers in New York and New England. The target completion date for this project is November 2015.
The project, strongly recommended by ISO-NE’s External Market Monitor, will provide the capability to submit interface bids with fifteen minute granularity, eliminate price disparity, and move to fifteen minute scheduling (from hourly today). Specific enhancements include increasing the frequency of scheduling energy transactions over the transmission network between regions, implementing software changes to enable the two ISOs to coordinate selection of the most economic transactions, and eliminating certain fees.
2. Generation Control Application Production Part 1 ($1,694,300)
This is a multi-phased project to develop a short-term look-ahead unit commitment and dispatch analysis application designed to provide dispatchers with the capability to manage changes in load, generation, interchange and transmission security constraints simultaneously on an intra-day and near real-time operational basis. This application will provide improved accuracy and optimality of the fast-start unit and pump Dispatchable Asset-Related Demand commitments and shutdowns. The application will also dispatch slow-moving units using ramping constraints to relieve future reserve or transmission constraints, better account for self- scheduled and pump units that are coming on-line or shutting down, provide automatic detection/prediction for minimum generation conditions, and improve external transaction scheduling by developing a next hour interchange predictor for the New York North Interface.
The application will optimize and minimize total production costs over the look-ahead period, and will also eliminate the need for out-of-merit manual commitment and dispatch of fast
51 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). 52 See Mr. Hameedy’s testimony at pp 23-25. 53 See the discussion of depreciation recovery in Section I.C.2 of this transmittal letter. October 16, 2014 Page 23 of 32 start units and slow-moving units to deal with future reserve or transmission constraints beyond the fifteen-minute look ahead interval of the real-time dispatch application. Reducing the out-of- merit manual commitment improves price formation in real-time, thereby strengthening incentives for resources to be available in real-time. This should further improve the reliability of the system, in addition to improving market efficiency.
The targeted completion date for this project is June 2015.
3. Divisional Accounting ($1,066,500)
In stakeholder outreach sessions and other meetings, Market Participants asked ISO-NE to add functionality to permit separation of settlement accounts by individual business units, thereby facilitating Customers’ divisional accounting and allowing ISO-NE Customers to easily evaluate their positions by business unit, division or generating facility.
The complexity of the implementation and the vast number of systems impacted resulted in five phased releases to occur in 2014 and 2015. The first two planned releases, which have been completed, allow Customers to create and maintain subaccounts, and include report modifications so Customers can receive reports for settlements for entity-based transactions by subaccounts.
Subsequent phases, which will be completed by November 2015, will include modifications to systems such as eMarket (a web based software application for use by Market Participants to submit supply offers and bids), eFTR (Financial Transmission Rights) and the Forward Capacity Tracking System to allow Customers to link transactions that are not associated with assets and resources to subaccounts, thereby allowing settlements for those transactions to be calculated and reported at the subaccount level.
4. Alternative Technologies and Regulation Market ($470,000)
The project will implement modifications to the regulation market resource selection process, Automatic Generation Control dispatch, and settlements to comply with the Commission’s Order No. 755. The design will fully integrate alternative technology regulation resources into the existing regulation market, provide hourly offer flexibility to allow regulation assets to change their offers as prices and conditions change, and allow the dispatch of regulation resources (both conventional and alternative technology) using continuous, energy neutral continuous and energy neutral trinary dispatch methods. Resources will be able to make separate bids for regulation capacity and regulation service (mileage), and will receive market-based compensation for actual capacity and mileage delivered. The target completion date is March 2015.
5. Forward Capacity Auction 9 ($230,000)
This project, chartered in May 2014 and scheduled for completion in February 2015, includes two primary efforts to be implemented before the ninth Forward Capacity Auction. The first effort is to implement a downward-sloping demand curve, which is a long-term solution to October 16, 2014 Page 24 of 32
the problems associated with the FCM administrative pricing provisions related to capacity carry forward, inadequate supply and insufficient competition.
The second effort involves improvements to the Financial Assurance provisions for Non- Commercial Capacity to improve the timing for Non-Commercial Capacity, strengthen incentives for Non-Commercial Capacity to achieve “commercial” status in a timely manner, reflect the capacity price in the calculation of Financial Assurance, and eliminate unnecessary Financial Assurance associated with obligations acquired through reconfiguration auctions or bilateral transactions.
6. Voltage Stability ($75,000)
This project will replace the existing voltage transfer limit calculator for the Connecticut and Southwest Connecticut regions and will implement a real-time voltage analysis tool and integrate it with the existing Energy Management System. The new analysis tool will be available for use in real-time, to conduct studies, and in the Testing and Training Simulation Environment.
New transmission facilities are being installed in Connecticut. The ISO’s past experience with large transmission expansions indicates that the manual process used to calculate voltage reduces the accuracy of the voltage limits, leading to a number of issues and inefficiencies in conducting day-ahead studies and in real-time operations. Moreover, the manual processes result in infrequent updates to voltage calculators, inconsistent results, and susceptibility to human error when creating formulas for voltage calculation.
The new software is expected to improve the efficiency of the voltage calculation process, the accuracy of the calculated voltage transfer limit results, and consistency with new automated technology for determining thermal limits. Ultimately, the project will enhance the reliability of grid operations. The software will be implemented in March 2015.
7. Control Room Visualization ($47,100)
The Control Room Visualization project, chartered in the third quarter 2013 and targeted for completion in February 2015, is an effort to improve the visualization of power system conditions by merging several hundred individual substation displays into a single display that will allow system operators a better viewpoint of interactions between substations. The combined system display will appear on the control room wallboard display and be available on each operator’s individual system.
By creating a single display for use on both the wallboard and operator consoles, the ISO reduces its support effort and the vendor-supplied software costs for maintaining separate displays. The same benefit will be realized in the Testing and Training Simulation Environment.
In addition, enhancements will be added to provide operators with context-sensitive access from the new display to Transmission Operating Guides and other documents stored on the Operations Document Management System. This will make these documents more easily accessible to the operators. October 16, 2014 Page 25 of 32
8. Business Continuity Plan Infrastructure Enhancements Phase III ($2,000,000)
The project is the third and final stage of an initiative that began in 2008 to update the ISO’s infrastructure to enhance business continuity. In continuation of the efforts initiated by the ISO in 2008 to enhance the Main Control Center and the Back-up Control Center, this project will implement the four-way Markets Database and expand the virtual environment to production. This virtual functionality will allow ISO personnel to conduct business remotely in the case of a pandemic or other unavailability of the Main Control Center, replicate virtual desktop capability to servers located at the Back-up Control Center, and gain the ability to transfer operations to or from market application servers at either control center in minutes. This includes critical operations such as the wholesale market, settlement, and financial applications. The targeted completion date for this project is fourth quarter of 2015. 9. Forward Capacity Auction 10 ($2,000,000)
In addition to the ISO’s project to implement a system-wide sloped demand curve to be effective for the ninth Forward Capacity Auction (as described in Section II.C.5, above), ISO-NE and stakeholders are working on sloped demand curves at the zonal level for the tenth Forward Capacity Auction. This project also includes work with stakeholders to address how reconfiguration auctions will work for Capacity Commitment Periods associated with the ninth Forward Capacity Auction and later auctions. The targeted completion date for this project is the first quarter of 2016.
10. Third Party Financial Transmission Rights Administration ($1,800,000)
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. Third-party clearing of FTRs addresses the primary deficiency related to the current FTR market design – the inability to properly collateralize against the risk of a Market Participant default. 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. This project will make the necessary Tariff language changes regarding third-party clearing and design and implement software to administer third-party clearing. The targeted completion date for this project is the third quarter of 2015. October 16, 2014 Page 26 of 32
11. Generation Control Application Production Part 2 ($1,500,000)
This is the second phase of the project described in Section II.C.2. During this phase of the project, targeted for completion in the fourth quarter of 2016, ISO-NE will address the inclusion in the look-ahead intervals of topology changes, especially those stemming from planned transmission line and transformer outages starting or ending in the look-ahead intervals. Topology changes affect the generator sensitivities to transmission constraints, and can affect the optimization of the commitment of fast-start units when the topology changes result in binding transmission constraints in congested areas of the power system. With its look-ahead functionality, the Generation Control Application can account for these potential future congestion conditions and dispatch the on-line generation and the commitment of fast-start units to prevent the congestion, or alert the operator of the system conditions that will exist if the planned outages are allowed to proceed.
12. VPN System Upgrade ($1,000,000)
The systems supporting Virtual Private Network (“VPN”) access to ISO-NE networks have been in place since 2006 and are in need of a technology update. Recent third party vulnerability assessments have consistently pointed out that the current technology requires updating to remain current and to reduce risk of an externally-initiated compromise of internal network access.
This project will undertake the replacement of network devices supporting the VPN endpoints and address the needs of client systems to update software and credentials. This will include replacements/updates as needed for current access, backend authentication, authorization and accounting database components, systems and supporting tracking of VPN access, and reporting on unused accounts. This upgrade will not only enhance the current value of remote access for ISO-NE staff and ongoing efforts to support business continuity and pandemic response efforts, but will also improve security associated with using VPN access.
The targeted completion date for this project is the third quarter of 2015.
13. Issue Resolution Project 2015 ($1,000,000)
The ISO uses a “Corrective Action/Preventative Action” approach to identify and track needed enhancements to existing systems and processes. This project continues 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 System 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 2015. October 16, 2014 Page 27 of 32
14. Simultaneous Feasibility Test Lite Production Version ($1,000,000)
The Day Ahead Performance Enhancement Prototype study evaluated a new product known as “SFT [Simultaneous Feasibility Test]-Lite” in 2014. The product is a direct current contingency analysis application designed to replace the current production alternating current contingency analysis application that is used in the clearing of the Day-Ahead Market and the Security Constrained Reliability Analysis process. The evaluation demonstrated that an appreciable reduction in the elapsed time to execute a Day-Ahead case could potentially be gained by switching to “SFT-Lite.”
This project proposes to further enhance the “SFT-Lite” product and improve the workflow between the various applications that are executed in the clearing of the Day-Ahead Market, with the goal of achieving a significant reduction in case execution elapsed time, which should benefit Market Participants by allowing more time to make fuel arrangements.
The targeted completion date for this project is the fourth quarter of 2015.
15. Power System Modeling ($1,000,000)
The Power System Modeling project proposes to implement enhancements to process, procedures and applications that will improve the power system network model used for the Energy Management System. Key areas of focus include: improving state estimation solution accuracy; introducing state estimation metrics to track performance; introducing methods for detecting parameter errors and developing an off-line tool that allows for on-going analysis of these functions to be performed with each major network model release; exploring the use of the Common Information Model in model management with a focus on reducing the network model release life cycle times; initiating the process for requirements gathering, and evaluating the purchase or development of tools to satisfy NERC standards that require entities to provide steady‐state, dynamics, and short circuit modeling data to its Transmission Planner(s) and Planning Coordinator(s); and evaluating tools and procedures to facilitate dynamic model validation per NERC standards. The targeted completion date for this project is the fourth quarter of 2015.
16. Quarterly Release Projects 2015 ($800,000)
In addition to major projects under consideration for 2015, 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 date for the first release is the second quarter of 2015, and the second release is targeted for completion in the fourth quarter of 2015.
17. Replacement of the Locational Marginal Price Calculator ($500,000)
The number of occurrences of price corrections has been increasing over the past year and, upon investigation, the software vendor has been able to identify issues contributing to the need for these price corrections. While fixes are scheduled to be implemented in production software effective December 3, 2014, the vendor cannot guarantee that these fixes will eliminate October 16, 2014 Page 28 of 32
the need to make price corrections, especially in the presence of binding transmission and binding reserve constraints; moreover, the introduction of Energy Market Offer Flexibility may further compound this issue. This project will include collaboration with the vendor to replace the current ex-post Locational Marginal Price Calculator to eliminate the need to make these price corrections. The targeted completion date for this project is the second quarter of 2015.
18. Wind Integration Phase II ($500,000)
The Wind Integration Phase II project is the second phase in the project to fully integrate wind power into the ISO-NE system. This project will design and implement functionality that will incorporate wind resources into Real-Time dispatch. This involves incorporating the wind forecasts to align with the Real-Time dispatch processes and issuance of dispatch signals. In addition, the project will incorporate wind power forecasts into the Reserves scheduling and procurement processes and will provide enhancements to the situational awareness tools for the control room. The targeted completion date for this project is the fourth quarter of 2015.
19. Web Enhancements ($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 2015, the ISO will evaluate the latest developments in web content and messaging and will develop a project scope to address any issues or concerns resulting from this evaluation. The target completion date for this project is the third quarter of 2015.
20. Phasor Measurement Unit Data Application ($500,000)
With the recent implementation of the Synchrophasor Infrastructure and Data Utilization project, ISO-NE will begin to work in 2015 toward completion of a multi-year plan to fully integrate Phasor Measurement Unit data into operations, thereby enhancing system reliability. The targeted completion date for this project is the fourth quarter of 2015.
This project proposes to acquire Phasor Measurement Unit data from neighboring ISOs and RTOs to enhance ISO-NE’s visibility into neighboring networks and wide area monitoring. The project will also enhance islanding, disturbance and oscillation detection and alarming in the PhasorPoint software. ISO-NE also plans to research a state estimator for Phasor Measurement Units in the 345 kV network and explore Area Control Error calculation and Automatic Generation Control based on Phasor Measurement Units. Throughout the project, ISO-NE will work with one Transmission Owner to establish a base (“golden”) Phasor Measurement Unit within New England that will provide a reference to calibrate other like data across New England.
21. Price Response Demand ($300,000)
To comply with FERC Order 745 (Demand Response Compensation in Organized Wholesale Energy Markets), ISO-NE proposed a two-step implementation. The first step was a transition period which primarily maintained the existing demand response programs and their participation in the Day-Ahead Energy Market, but incorporated the payment of Locational October 16, 2014 Page 29 of 32
Marginal Prices to active demand response in FCM when they were dispatched to reduce consumption. This step was implemented by the ISO in 2012.
This project, the second step, will implement the full integration of active demand response into the Capacity, Energy and Ancillary Service Markets. A common model will be created for a single representation of demand response that can either reduce consumption or provide supply. Modifications will be made to Capacity, Energy and Ancillary Service Markets to incorporate and effectively implement this model into the ISO-NE markets. This project will provide comparable treatment to other supply resources and allow demand response assets to directly impact the prices within the markets. The transition program will be terminated with the implementation of this project.
The targeted completion date for this project is the second quarter of 2018.
22. Software Testing Tool 2015 ($300,000)
During 2011, ISO-NE initiated a proof of concept to incorporate automated testing as part of new application design and testing. Since then, the ISO has expanded the creation of software testing tool scripts for various applications that have been implemented in previously-completed capital development projects. Given the success of these efforts in improving the quality and efficiency of testing, the ISO plans to continue its efforts and identify several other applications for which it will create automated test scripts in 2015. The targeted completion date for this project is the third quarter of 2015.
23. Non-Project Capital Expenditures ($3,400,000), Other Emerging Work ($1,646,600), and Capitalized Interest ($500,000)
The 2015 Capital Budget includes a total of $3,400,000 for non-project capital expenditures. Non-project capital expenditures fund external and internal capitalized labor necessary to program System Improvement Requests ($1,500,000), non-project related hardware purchases ($1,500,000), and furniture & fixtures ($400,000).
The “Other Emerging Work” category is primarily intended to address emerging work requests during 2015 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.
24. Caveats
The 2015 Capital Budget cannot accurately predict the ISO’s actual capital expenditures for 2015. 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 October 16, 2014 Page 30 of 32
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 2015 Capital Budget will 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:
• 2015 Administrative Expenses Tariff (Exhibit 1); • Blacklined version of 2015 Administrative Expenses Tariff (Exhibit 2); • Prepared testimony and exhibits of Robert C. Ludlow regarding the 2015 Administrative Expenses Tariff (Exhibit 3); • Prepared testimony of Janice S. Dickstein regarding the 2015 Administrative Expenses Tariff (Exhibit 4); • 2015 Capital Budget (Exhibit 5); • Prepared testimony of M. David Hameedy regarding the 2015 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 2013 (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 2015 Budgets (Exhibit 10); and
• ISO-NE response to Comments of state agencies on proposed 2015 Budgets (Exhibit 11).
As in the past, the ISO has included the cost-of-service data required by Statements AA- BM 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 not- for-profit RTO that does not own any generation or transmission assets. The Commission October 16, 2014 Page 31 of 32
repeatedly has accepted the ISO’s rates as supported in this manner, including an explicit acknowledgement that such data is sufficient.54
35.13(b)(2) – The ISO requests that the Commission accept the 2015 Capital Budget and the 2015 Administrative Expenses Tariff as filed, effective January 1, 2015.
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.iso- ne.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 2015 Capital Budget and the 2015 Administrative Expenses Tariff.
35.13(b)(6) –The ISO Board of Directors has approved the 2015 Capital Budget, the 2015 Revenue Requirement and resulting rates herein. The ISO also notes that the NEPOOL Participants Committee voted to support the 2015 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.
54 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, 2014 Page 32 of 32
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 2015 Capital Budget and the 2015 Administrative Expenses Tariff as filed, without suspension or hearing, with an effective date of January 1, 2015.
Respectfully submitted,
/s/ Maria A. Gulluni______Maria A. Gulluni Deputy General Counsel ISO New England Inc. 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 Purpose of Section IV.A; Adjustments to Rates
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 otherwise- projected 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 Billing and Payment
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.
IV.A.4 Regulatory Filings 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.
IV.A.5 Creditworthiness 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 Direct Billing; Sanctions
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 $0.15570 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 scheduled to occur during the month as Through or Out Service multiplied by $0.00021 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 Section 3.2.3.3(2) of Schedule 22 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: 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) $0.65101 times the Customer’s first 12,500 Energy TUs for that month; plus
(2) $0.59182 times the amount of Energy TUs that exceed 12,500 but are less than or equal to 39,500; plus
(3) $0.53264 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) $0.06000 times the number of Increment Offers and Decrement Bids submitted by the Customer 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) 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); 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.
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) $0.25517 per MWh for the first 250,000 MWh of EAS VM for that month; plus
(b) $0.23197 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) $0.20877 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) $.85853 times the number of bids submitted by the Customer into any FTR auctions held for that month; plus
(2) $.85853 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) $1.21377 times the number of bids submitted by the Customer during that month that clear any FTR auctions held for that month; plus
(4) $1.21377 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 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; • Reliability Markets accounting; • Billing preparation; • 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; Regional System Plan); • Support of power supply, environmental and market reliability planning activities; • Market power monitoring, mitigation and assessment for the Reliability Markets; • Formulation of additional market rules and proposals to modify existing rules.
(A) 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 $3.02 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 $0.18763 per kilowatt month times the Market Participant’s Real-Time NCP Load Obligation (measured in kilowatts) for that month.
(C) For Exports, each RAS Customer shall pay each month, in arrears, an amount equal to $0.37 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.
All general terms and conditions of the Tariff apply to this Service.
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 (“FERC- 582”), 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 megawatt- hours 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 2014, 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 $0.00553 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 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 Purpose of Section IV.A; Adjustments to Rates
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 otherwise- projected 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 Billing and Payment
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.
IV.A.4 Regulatory Filings 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.
IV.A.5 Creditworthiness 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 Direct Billing; Sanctions
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 $0.15640570 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 scheduled to occur during the month as Through or Out Service multiplied by $0.00021 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 Section 3.2.3.3(2) of Schedule 22 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: 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) $0.7316765101 times the Customer’s first 12,500 Energy TUs for that month; plus
(2) $0.6651559182 times the amount of Energy TUs that exceed 12,500 but are less than or equal to 39,500; plus
(3) $0.5986453264 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) $0.06000 times the number of Increment Offers and Decrement Bids submitted by the Customer 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) 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); 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.
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) $0.261495517 per MWh for the first 250,000 MWh of EAS VM for that month; plus
(b) $0.23772197 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) $0.213950877 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) $1.23712.85853 times the number of bids submitted by the Customer into any FTR auctions held for that month; plus
(2) $.858531.23712 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) $1.213771.76776 times the number of bids submitted by the Customer during that month that clear any FTR auctions held for that month; plus
(4) $1.2137776776 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 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; • Reliability Markets accounting; • Billing preparation; • 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; Regional System Plan); • Support of power supply, environmental and market reliability planning activities; • Market power monitoring, mitigation and assessment for the Reliability Markets; • Formulation of additional market rules and proposals to modify existing rules.
(A) 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 $2.943.02 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 $0.177908763 per kilowatt month times the Market Participant’s Real-Time NCP Load Obligation (measured in kilowatts) for that month.
(C) For Exports, each RAS Customer shall pay each month, in arrears, an amount equal to $0.37 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.
All general terms and conditions of the Tariff apply to this Service.
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 (“FERC- 582”), 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 megawatt- hours 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 2014, 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 $0.00553 per kilowatt times its Monthly Regional Network Load for that month.
EXHIBIT 3 ISO New England Inc. Exhibit 3 Recovery of 2015 Administrative Costs
UNITED STATES OF AMERICA
BEFORE THE
FEDERAL ENERGY REGULATORY COMMISSION
ISO New England Inc. ) Docket No. ER15-_____-000
DIRECT TESTIMONY
OF
ROBERT C. LUDLOW
Filed on: October 16, 2014
ISO New England Inc. Exhibit 3 Recovery of 2015 Administrative Costs
TABLE OF CONTENTS
PURPOSE OF TESTIMONY ...... 2
CURRENT OPERATIONS AND ORGANIZATIONAL STRUCTURE OF THE ISO ...... 4
THE BUDGET DEVELOPMENT PROCESS ...... 5
DESCRIPTION OF THE 2015 REVENUE REQUIREMENT ...... 7
ACTIVITY ACCOUNTING SYSTEM ...... 20
2015 COST ALLOCATION AMONG SCHEDULES 1, 2, AND 3 ...... 22
THE ISO RATE DESIGN AND BILLING DETERMINANTS ...... 34
RATE SUMMARY ...... 37
FIXED FEES ...... 39
CONCLUSION ...... 41
ISO New England Inc. Exhibit 3 Recovery of 2015 Administrative Costs
ATTACHMENTS TO THIS TESTIMONY
RCL-1: Organization Chart (CEO direct reports)
RCL-2: Revenue Requirement and True-Up
Schedule 1: [reserved] Schedule 2: 2015 Revenue Requirement and 2013 True-Up
RCL-3: Test Year 2015 Cost Allocations
Schedule 1: Total Cost Allocation to Schedules by Department Schedule 2: Total Direct Labor Allocation to Schedules by Department Schedule 3: Total Cost Allocations to Schedules by Cost Category Schedule 4: Direct Labor Cost Allocations to Schedules by Cost Category Schedule 5: Allocation Factors by Cost Category Schedule 6: Allocation of Depreciation and Amortization Expense
RCL-4: [reserved]
RCL-5: 2015 Core Operating Budget
Schedule 1: Overview of Operating Expense Budget Schedule 2: Detail of Components of 2015 Operating Expense Budget Schedule 3: Variance Summary (vs. 2014) Schedule 4: Detailed Change in Budget (vs. 2014) Schedule 5: Staffing Projections Schedule 6: 2015 Capital Budget
RCL-6: [reserved]
RCL-7: Escalation Factors and Billing Determinants
Schedule 1: Development of Escalation Factors Schedule 2: Billing Determinants for Calendar Year 2014 and Test Year 2015 Schedule 3: Rate Design Summary Schedule 4: Annual Revenue Comparison at Present and Proposed Rates Schedule 5: Comparison of Schedule 2 Revenues from Transaction Units for 2013 Schedule 6: Schedule 2 TU True-Up Summary
RCL-8: NEPOOL Resolution
ISO New England Inc. Exhibit 3 Recovery of 2015 Administrative Costs Page 1
1 UNITED STATES OF AMERICA 2 BEFORE THE 3 FEDERAL ENERGY REGULATORY COMMISSION
4 ISO NEW ENGLAND INC. ) Docket No. ER15-_____-000
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”).
ISO New England Inc. Exhibit 3 Recovery of 2015 Administrative Costs Page 2
1 Q. PLEASE DESCRIBE YOUR EDUCATIONAL BACKGROUND AND
2 PROFESSIONAL EXPERIENCE.
3 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. HAVE YOU PREVIOUSLY TESTIFIED BEFORE A REGULATORY
8 COMMISSION?
9 A. Yes. I previously have testified before the Commission to support prior
10 administrative rate filings by the ISO in Docket Nos. ER14-90-000 (rates
11 proposed for 2014), ER13-185-000 (rates proposed for 2013), ER12-191-000
12 (rates proposed for 2012), ER11-1943-000 (rates proposed for 2011), ER10-154-
13 000 (rates proposed for 2010), ER09-197-000 (rates proposed for 2009), ER08-
14 189-000 (rates proposed for 2008), ER07-116-000 (rates proposed for 2007),
15 ER06-94-000 (rates proposed for 2006), ER00-395-000 (rates proposed for 2000),
16 and ER98-3554-000 (rates proposed for 1998).
17 PURPOSE OF TESTIMONY
18 Q. WHAT IS THE PURPOSE OF YOUR TESTIMONY?
19 A. I am providing this testimony primarily to support the ISO’s proposed revenue
20 requirement for 2015 (“2015 Revenue Requirement”) and the updated rates to
21 collect it. My Direct Testimony presents the ISO’s 2015 Revenue Requirement as
ISO New England Inc. Exhibit 3 Recovery of 2015 Administrative Costs Page 3
1 reflected in the proposed revised tariff sheets attached as Exhibits 1 and 2 (clean
2 and blacklined versions, respectively) to the filing letter. Specifically, I will
3 summarize the elements of the ISO’s 2015 Revenue Requirement (including the
4 true-up mechanism), describe the ISO’s budget process, present the ISO’s 2015
5 Core Operating Budget, and describe the ISO’s activity accounting system. I will
6 also present the development of the Test Year 2015 cost of service study
7 associated with the ISO providing service under the three primary rate schedules
8 included in Section IV.A of the ISO’s Transmission, Markets and Services Tariff
9 (the “Tariff”). Section IV.A of the Tariff provides for recovery of the ISO’s
10 administrative expenses. The three primary rate schedules are: (1) Schedule 1 –
11 Scheduling, System Control and Dispatch Service (“Scheduling Service”); (2)
12 Schedule 2 – Energy Administration Service; and (3) Schedule 3 – Reliability
13 Administration Service. I will present proposed escalation factors to adjust actual
14 load data for the 12-month period ending July 2014 to the Test Year 2015 for the
15 purpose of rate design, discuss the rate design utilized, and the proposed rates,
16 including certain fixed fees.
17 Q. HOW WILL YOUR TESTIMONY BE ORGANIZED?
18 A. Before offering a conclusion, I will describe:
19 (i) the current operations and organizational structure of the ISO;
20 (ii) the budget development process;
21 (iii) the various elements of the 2015 Revenue Requirement;
ISO New England Inc. Exhibit 3 Recovery of 2015 Administrative Costs Page 4
1 (iv) the ISO’s activity accounting system;
2 (v) how the ISO allocated its costs among the rates it proposes to charge in the
3 Tariff’s Schedules 1, 2, and 3;
4 (vi) the 2015 rate design and escalation factors;
5 (vii) the 2015 rate design and billing determinants;
6 (viii) a rate summary; and
7 (ix) fixed fees.
8 CURRENT OPERATIONS AND ORGANIZATIONAL STRUCTURE OF THE ISO
9 Q. WHAT ARE THE CURRENT OPERATIONS AND ORGANIZATIONAL
10 STRUCTURE OF THE ISO?
11 A. The ISO provides three basic services to its customers:
12 1. Scheduling Service (Schedule 1): Through this service, the ISO schedules
13 at the pool level the movement of power through, out of, within, or into
14 the New England Control Area.
15 2. Energy Administration Service (Schedule 2): Through this service, the
16 ISO administers the energy markets and facilitates generation and demand
17 dispatch, auctions for Financial Transmission Rights (“FTRs”), and other
18 services (i.e., under Section III of the Tariff).
19 3. Reliability Administration Service (Schedule 3): Through this service, the
20 ISO administers the reliability markets (and facilitates reliability-related
ISO New England Inc. Exhibit 3 Recovery of 2015 Administrative Costs Page 5
1 transactions and arrangements) in accordance with Market Rule 1 and
2 provides other reliability and informational services.
3 The ISO is governed by an independent Board of Directors with a cross-section of
4 skills and experience, including regulatory affairs, energy industry management,
5 corporate finance, bulk-power systems, public policy, and market development.
6 The ISO is overseen by a President and Chief Executive Officer (“CEO”) who has
7 seven direct reports. An Executive Vice President and Chief Operating Officer is
8 responsible for Market Operations, System Operations, System Planning, Market
9 Development, Program Management, Business Architecture, and Information
10 Technology. The other direct reports of the CEO are: Vice President and General
11 Counsel; Vice President of External Affairs and Corporate Communications; Vice
12 President, Chief Financial & Compliance Officer; Vice President, Human
13 Resources; Vice President, Market Monitoring; and Director, Internal Audit. The
14 latter two positions report to the CEO for administrative purposes only. See RCL-
15 1, attached to this testimony.
16 THE BUDGET DEVELOPMENT PROCESS
17 Q. HOW WERE THE ISO’S BUDGETS DEVELOPED FOR 2015?
18 A. The ISO prepares budgets in advance of each upcoming year using a seven-step
19 business planning process, throughout which stakeholder input is sought. The
20 seven-step process is:
ISO New England Inc. Exhibit 3 Recovery of 2015 Administrative Costs Page 6
1 1) define objectives, activities and goals;
2 2) identify efficiencies for each department;
3 3) determine resource requirements;
4 4) develop budget estimates for each department;
5 5) adjust budgets to ensure that staff resources and activities are aligned with the
6 business plan;
7 6) conduct senior staff review to ensure alignment of budget with the ISO’s
8 business plan and overall fiscal constraint; and
9 7) develop priorities.
10 Q. PLEASE SUMMARIZE THE STAKEHOLDER PROCESS USED TO
11 REVIEW THE 2015 BUDGET.
12 A. After reviewing budget scenarios with state agencies at a meeting in June, the ISO
13 presented the 2015 Revenue Requirement at the NEPOOL Budget and Finance
14 Subcommittee’s August 27, 2014 meeting and at a meeting for state agencies on
15 August 28, 2014. The ISO also presented the budgets to the NEPOOL
16 Participants Committee at the Committee’s meetings on September 12 and
17 October 3, 2014. At the October 3 meeting, the ISO’s 2015 Revenue
18 Requirement was unanimously supported by the Participants Committee (with
19 abstentions). The terms of the NEPOOL Participants Committee’s action are
20 reflected in the resolution in RCL-8, attached to this testimony. In that same
21 resolution, the NEPOOL Participants Committee also supported the capital budget
ISO New England Inc. Exhibit 3 Recovery of 2015 Administrative Costs Page 7
1 for 2015. The ISO Board of Directors approved the budgets effective on October
2 16, 2014.
3 Q. DESCRIBE THE ISO’S HISTORY OF STAYING WITHIN ITS BUDGET.
4 A. The ISO has amassed a consistent track record of spending integrity; since the
5 inception of its self-funding tariff for calendar year 1998, the ISO’s annual
6 spending has never exceeded the budget used to calculate the revenue requirement
7 accepted by the Commission that forms the basis for the rates for the year in
8 question. Should the need ever arise for the ISO to spend beyond a given year’s
9 budget (including contingencies), the ISO will first seek stakeholder support and
10 then file a rate increase with the Commission, thus allowing stakeholder and
11 Commission review before approving such increases.
12 DESCRIPTION OF THE 2015 REVENUE REQUIREMENT1
13 Q. WHAT IS THE 2015 REVENUE REQUIREMENT AND WHAT ARE ITS
14 ELEMENTS?
15 A. As shown in RCL-2, Schedule 2, the 2015 Revenue Requirement is approximately
16 $168.5 million. The 2015 Revenue Requirement contains the following
17 components, each of which is discussed below: (1) the 2015 operating budget
18 ($144.22 million) (i.e., the administrative costs of running the ISO); (2)
19 depreciation and amortization of regulatory assets ($31.77 million); (3) interest
1 Generally, numbers used herein are rounded for ease of reference and, accordingly, may not sum.
ISO New England Inc. Exhibit 3 Recovery of 2015 Administrative Costs Page 8
1 expense of $2.32 million; and (iv) a final true-up adjustment for 2013 (the “2013
2 True-Up Amount”) calculated pursuant to Section IV.A.2.2 of the Tariff (a
3 decrease in the 2015 Revenue Requirement of approximately $9.78 million
4 resulting from an over-collection in 2013).
5 Q. WHAT IS THE IMPACT OF THE INCREASED REVENUE
6 REQUIREMENT ON CONSUMER COSTS?
7 A. If the ISO’s Revenue Requirement was fully passed through to end-use customers,
8 their cost would average 90 cents per month, down from 2014 levels of 92 cents.
9 See slide 12 of the ISO’s annual budget presentation to stakeholders (the “Budget
10 Presentation”). The presentation is located at http://www.iso-ne.com/static-
11 assets/documents/2014/09/2_2015_operat_cap_budget_update_v2.pdf.
12 Q. WHAT ARE THE MOST SIGNIFICANT CHANGES IN THE 2015
13 OPERATING EXPENSE BUDGET COMPARED WITH THE 2014
14 OPERATING EXPENSE BUDGET?
15 A. As described below, the ISO proposes to increase its Core Operating Budget by
16 approximately $5.7 million from 2014 levels to: (i) maintain competitive
17 compensation and benefits, existing financing, and NERC and NPCC membership
18 ($5.4 million); (ii) fund established initiatives, including Energy Market Offer
19 Flexibility and Coordinated Transaction Scheduling ($2.1 million); and (iii)
20 support both current initiatives and previously-implemented initiatives by funding
ISO New England Inc. Exhibit 3 Recovery of 2015 Administrative Costs Page 9
1 increases in computer services, systems maintenance and cyber security, and other
2 support services ($2.5 million).
3 Q. PLEASE DESCRIBE THE COSTS TO MAINTAIN COMPETITIVE
4 COMPENSATION AND BENEFITS, EXISTING FINANCING, AND
5 NERC AND NPCC MEMBERSHIP.
6 A. The cost increases in this category are needed to maintain the status quo. For
7 example, to maintain its membership in NERC and NPCC, the ISO must pay an
8 additional $400,000 in fees. Similarly, to maintain medical benefits for its
9 employees and to fund its pension plans, the ISO will incur an additional $2.1
10 million in costs. In addition, the ISO’s existing financing is anticipated to be
11 more expensive (by $100,000).
12 This category also includes the ISO’s budget for a 3.0% increase in salaries for
13 merit and a .5% increase for promotions. The budgeted amounts for merit and
14 promotion are developed using data from several national compensation
15 consultants, and are within the ranges reported in these surveys. Please see Ms.
16 Dickstein’s testimony for detail on the development of these allocations,
17 compensation practices in general, and the ISO’s compliance with the standards of
18 the Internal Revenue Service regarding the reasonableness of executive
19 compensation.
ISO New England Inc. Exhibit 3 Recovery of 2015 Administrative Costs Page 10
1 Q. PLEASE DESCRIBE THE INCREASES TO FUND ESTABLISHED
2 INITIATIVES, INCLUDING ENERGY MARKET OFFER FLEXIBILITY
3 AND COORDINATED TRANSACTION SCHEDULING.
4 A. The cost increase of $2.1 million in this category results from ISO-NE’s
5 established commitments to implement programs and practices, including Energy
6 Market Offer Flexibility, Coordinated Transaction Scheduling and changes to the
7 Forward Capacity Market. While these costs reflect the use of existing employees
8 and consulting services to the greatest extent possible to perform the work, given
9 that the capacity to take on new work is limited, the ISO is adding limited
10 personnel to implement these new programs and practices where needed. For
11 example, the ISO is adding .75 of a full-time employee on the Energy Market
12 Offer Flexibility project to support the dramatically increased data flows, and 1.25
13 employees on Coordinated Transaction Scheduling to handle the increased
14 frequency of data between the control areas and to support more than fifty new
15 data bridges and additional user interfaces. This category also includes the
16 reallocation of internal resources to 2015 priorities.
17 Q. PLEASE DESCRIBE THE INCREASES TO SUPPORT CURRENT AND
18 PREVIOUSLY-IMPLEMENTED INITIATIVES BY FUNDING
19 INCREASES IN COMPUTER SERVICES, SYSTEMS MAINTENANCE
20 AND CYBER SECURITY, AND OTHER SUPPORT SERVICES.
21 A. The costs in this category include $600,000 for cyber security initiatives,
ISO New England Inc. Exhibit 3 Recovery of 2015 Administrative Costs Page 11
1 including 2.5 employees in the Information Technology Department. This
2 category also includes $1.5 million to support current initiatives as well as
3 implemented initiatives, including 3.5 new employees in Information Technology
4 and Program Management to support the Forward Capacity Market, software
5 testing, power system modeling, financial systems/database support and increased
6 consulting costs for desktop support and other applications. In the
7 “miscellaneous” category, there are costs for the addition of a Payroll Supervisor
8 in the Finance Department and to make a part-time Business Analyst full-time.
9 The latter results in consultant savings above the staffing costs.
10 Q. PLEASE PROVIDE FURTHER INFORMATION ON INCREASED HEAD
11 COUNT FOR 2015.
12 A. To determine its resource needs for 2015, the ISO looked at the work load to be
13 completed, including on-going work from 2014, non-repetitive work from 2014 to
14 2015, and new work for 2015. Each area of the Company then reviewed the
15 current resources available to complete this work, utilizing the current employee
16 complement to perform this work to the greatest extent possible. Accordingly, in
17 approaching the completion of the bottom-up budget, the ISO looked to add
18 positions only if (1) the position was needed for resource purposes or (2) the
19 position was cost beneficial to the overall budget.
20 The ISO is requesting a total of 9.5 additional positions in the 2015 budget. As
21 discussed above, the requested positions are: .75 of a full-time employee to be
ISO New England Inc. Exhibit 3 Recovery of 2015 Administrative Costs Page 12
1 dedicated to the Energy Market Offer Flexibility project; 1.25 employees to be
2 assigned to Coordinated Transaction Scheduling; 2.5 employees to be added in the
3 Information Technology Department to address increased cyber security risks; 3.5
4 new employees to join the Information Technology and Program Management
5 Departments to support the Forward Capacity Market, software testing, power
6 system modeling, financial systems/database support and increased consulting
7 costs for desktop support and other applications; a new Payroll Supervisor in the
8 Finance Department; and a part-time Business Analyst who will become full-time
9 (the costs of which are more than offset in foregone consulting costs).
10 These positions relate to only a small portion of the additional work being taken
11 on for 2015. In fact, a number of resources are being reallocated to 2015
12 priorities, including work by the System Planning Department on Forward
13 Capacity Market initiatives, including new capacity zone evaluation and
14 reconfiguration, development and implementation of zonal demand curves, and
15 evaluation of natural gas availability as part of resource qualification. In addition,
16 Market Operations and Settlements personnel are being reassigned to the new
17 divisional accounting functionality, sub-hourly settlements, third-party
18 administration of Financial Transmission Rights, Customer and Asset
19 Management System improvements, and Oracle Business Intelligence Report
20 Integration. Finally, System Operations will reallocate personnel to develop a
21 training program for non-operations staff in compliance with NERC standards.
ISO New England Inc. Exhibit 3 Recovery of 2015 Administrative Costs Page 13
1 Q. THERE HAS BEEN SIGNIFICANT ORGANIZATIONAL GROWTH IN
2 RECENT YEARS. CAN YOU EXPLAIN IT?
3 A. The ISO has grown significantly, adding more than 100 new employees since
4 2009. This growth reflects the increase in the complexity of the ISO’s operations.
5 For example, with the integration of demand resources into the Forward Capacity
6 Market, the number of registered and modeled assets has increased from a few
7 hundred to a few thousand. In addition, compliance with new and emerging
8 NERC and NPCC standards has required a significant investment. The ISO has
9 also provided additional services, like doubling its billing obligations through
10 twice-weekly billing, which further mitigated market participants’ risk of
11 significant payment defaults, and adding transmission planning and economic
12 studies. All of these changes require personnel.
13 Another area that has contributed to the addition of employees is the replacement
14 of long-term contractors with FTEs. At least a dozen employees have been added
15 to replace temporary help or contractors where the responsible manager made a
16 determination that the work being performed is permanent and that it was cost
17 advantageous to convert the position to a FTE. These added positions had little or
18 no impact on the budget.
19 Finally, certain departments have grown, including System Operations, in part due
20 to the need for employees to staff the Back-Up Control Center, which is more
21 robust as a result of compliance with more stringent requirements from the
ISO New England Inc. Exhibit 3 Recovery of 2015 Administrative Costs Page 14
1 Commission and NERC, and to provide training and backup for Control Room
2 Operators. Market Monitoring has grown as well, given the Commission’s
3 emphasis on this area and the evolution of the markets, including FCM.
4 Q. HOW DOES ISO-NE’S SIZE COMPARE TO OTHER ISOS AND RTOS?
5 While the types and scopes of services vary widely among the ISOs and RTOs,
6 many costs are largely fixed, because all ISOs and RTOs must comply with the
7 Commission’s orders and mandatory reliability standards. ISO-NE does review
8 what others are spending. (See detail on comparisons in the ISO’s Budget
9 Presentation.) ISO-NE’s review indicates that its cost structure is reasonable.
10 Q. PLEASE DESCRIBE THE BUDGET CUTS AND DEFERRALS THAT
11 OFFSET THESE INCREASED COSTS.
12 A. For 2015, the ISO has realized $4.3 million in savings by reallocating resources,
13 automating work, identifying efficiencies, and eliminating discontinued or non-
14 repetitive work.
15 Q. DOES THE REVENUE REQUIREMENT INCLUDE DEPRECIATION ON
16 ITEMS IN THE CAPITAL BUDGET THAT ARE PLACED IN SERVICE
17 IN 2015?
18 A. Yes. The ISO’s depreciation rates remain unchanged from those accepted by the
19 Commission in the ISO’s 2014 Revenue Requirement. The ISO uses the straight-
20 line depreciation methodology based on no net salvage value and the various
ISO New England Inc. Exhibit 3 Recovery of 2015 Administrative Costs Page 15
1 average service lives described below. These service lives reflect the ISO’s
2 historical experience and forecasted expectations for capital projects placed into
3 service, are necessary to comply with the ISO’s funding mechanisms, are
4 consistent with the ISO’s historical experience, and have been repeatedly
5 determined by independent auditors to be appropriate. The service lives are:
6 • Computer hardware, software and accessories: 3 to 5 years
7 • Software development costs: 3 to 5 years
8 • Furniture and fixtures: 7 years
9 • Machinery and equipment: 7 years
10 • Building: average of 25 years (based on the opinion of independent bond
11 counsel and analysis of the service lives of the different aspects of the
12 building (e.g., the building’s steel and concrete at 40 years, mechanical
13 and electrical work at 25 years, and high wear-and-tear elements at 15
14 years))
15 • Leasehold/Building Improvements: lesser of 1 to 25 years or remaining
16 life of the lease or building, as determined at the time of the purchase
17 based on the nature of each such improvement (e.g., rooftop railing at
18 twenty-five years, air conditioning unit at fifteen years, capacitor bank at
19 ten years)
20 • Vehicles: 3-7 years
ISO New England Inc. Exhibit 3 Recovery of 2015 Administrative Costs Page 16
1 The ISO uses private placement debt, issued pursuant to Commission
2 authorization under Section 204 of the Federal Power Act, to fund its capital
3 program. The private placement notes are non-amortizing, with interest-only
4 payments due semi-annually throughout the life of the notes, and the principal due
5 at the end of the term. Revenue reserved for the depreciation of capital assets, as
6 well as assets placed in service in prior years and still depreciable, may be
7 available to repay the remaining principal amounts on outstanding debt. Also, the
8 issuance of the notes will support future capital expenditures by allowing the ISO
9 to use amounts collected for residual depreciation and depreciation from future
10 capital items to fund those capital expenditures. The ISO’s working capital needs
11 have been funded through a revolving line of credit.
12 Please note that capital projects include design work and, if the design is approved
13 and built, the design work is part of the asset on which depreciation is collected
14 when the asset is placed in service in future years via the Revenue Requirement.
15 On the other hand, if the capital project is abandoned, the ISO writes off the
16 design work and recovers it in full in the year of abandonment. In addition, each
17 capital project also includes the first year maintenance cost and license fees for
18 any newly capitalized software.
ISO New England Inc. Exhibit 3 Recovery of 2015 Administrative Costs Page 17
1 Q. HOW DOES THE ISO ADDRESS UNEXPECTED COSTS THAT MIGHT
2 MATERIALIZE DURING 2015?
3 A. The 2015 Core Operating Budget includes two line items to address unexpected
4 needs: (i) the CEO Emerging Work allowance of $1.1 million; and (ii) the
5 Operating Contingency of $700,000. Inclusion of these contingency amounts
6 recognizes that circumstances may arise that the ISO does not foresee in setting its
7 2015 Revenue Requirement for its various departments and programs.
8 The CEO Emerging Work Allowance covers new or deferred activities and
9 initiatives that emerge or become priorities during the year. Approval from both
10 the CEO and CFO is required before the ISO may draw upon these funds.
11 The Operating Contingency provides a funding source of last resort. ISO
12 management cannot access this fund without first obtaining approval from the
13 ISO’s independent Board of Directors.
14 Q. DO YOU FORESEE ANY PARTICULAR CONTINGENCIES THAT
15 WILL WARRANT THE ISO TAPPING INTO THESE FUNDS?
16 A. I cannot say for sure what type of contingencies might arise. There are, however,
17 several ongoing issues that might require additional funds not included in the
18 2015 Core Operating Budget. The biggest issue is litigation that could be initiated
19 or accelerated in 2015. Additional risks include costs to comply with unforeseen
20 significant shifts in federal and state policy, costs of complying with Order 1000
ISO New England Inc. Exhibit 3 Recovery of 2015 Administrative Costs Page 18
1 that exceed estimates, interest rates, additional cyber security work, costs of
2 designing future winter programs, and request from the states to perform work
3 related to their infrastructure initiative. In general, states, Customers and the
4 Commission will determine the extent of additional work and resources required.
5 Q. HAS THE ISO TAKEN ANY ACTION TO MITIGATE THE RISK OF A
6 CHANGING INTEREST RATE ENVIRONMENT?
7 A. The ISO has purchased an interest rate cap for a portion of its tax-exempt bond
8 issuances. The tax-exempt bonds were issued in Massachusetts to fund the
9 refurbishing of the Main Control Center and in Connecticut to fund the
10 development of the new Back-Up Control Center. Both sets of bonds are priced
11 at a weekly variable rate. By opting for variable rates on both sets of bonds, the
12 ISO has saved more than $10,000,000 since 2005 when the ISO first issued the
13 Massachusetts tax-exempt bonds (the Connecticut bonds were issued in 2012).
14 The ISO will protect that savings through the interest rate cap. The cap will
15 effectively serve as an insurance policy or “stop loss” mechanism in a changing
16 interest rate environment, and is intended to cover the ISO’s interest rate exposure
17 through February 1, 2024 if rates rise significantly.
18 The cap covers the unhedged portion of the variable rate debt. In other words, the
19 ISO has not purchased additional coverage for the portion of the debt that is
20 naturally hedged by the interest income earned on the settlement float that the ISO
ISO New England Inc. Exhibit 3 Recovery of 2015 Administrative Costs Page 19
1 has through the normal course of participant settlement billing and payment. In
2 other words, interest earned on the balance carried in the settlement account (as
3 amounts are due two days before they are paid out to customers) offsets the
4 interest due on the bonds. Because the projected average balance in the settlement
5 account does not provide complete cover for the floating rate tax-exempt debt, the
6 ISO purchased the 10-year interest rate cap, at a cost of about $88,000 per year, to
7 protect against a large uptick in the variable tax-exempt interest rates for the
8 uncovered portion. Since the tax-exempt bonds are amortizing, the hedge is only
9 in place until the unamortized amount of the bonds drop below the projected
10 average balance in the settlement account.
11 Q. PLEASE DESCRIBE THE CALCULATION OF THE 2013 TRUE-UP
12 AMOUNT.
13 A. As set forth in Section IV.A.2.2 of the Tariff, the ISO has reconciled calendar year
14 2013’s actual expenses and collections under Schedules 1, 2 and 3 of the Tariff by
15 means of a true-up. The actual difference between 2013 expenses and collections
16 is an over-collection of $9.8 million, which decreases the 2015 Revenue
17 Requirement by that amount. See RCL–2, Schedule 2.
18 Q. HOW IS THE 2013 TRUE-UP AMOUNT ALLOCATED AMONG THE
19 THREE SCHEDULES?
20 A. Schedule 1 has a decrease of $4.4 million; Schedule 2 has a decrease of about $3
21 million; and Schedule 3 has a decrease of $2.3 million. See RCL-2, Schedule 2.
ISO New England Inc. Exhibit 3 Recovery of 2015 Administrative Costs Page 20
1 ACTIVITY ACCOUNTING SYSTEM
2 Q. DESCRIBE THE ISO’S ACTIVITY ACCOUNTING SYSTEM AND THE
3 EXTENT TO WHICH IT PROVIDES COST OF SERVICE
4 INFORMATION FOR EACH OF THE THREE PRIMARY SCHEDULES.
5 A. The activity accounting system was implemented at the ISO’s inception in 1997
6 and refined in 1998. All operating charges recorded in the general ledger system
7 must be cross-referenced to an activity. Each department has identified its major
8 activities. Most activities are department-specific, but some activities may be
9 cross-charged if they are of a project nature. Activities within a department are
10 known as either “direct” activities or “indirect” activities. Direct activities are of
11 an operational nature and are allocated to one or more of the three schedules based
12 on a fixed percentage. This fixed allocation is provided by the department
13 manager annually in preparation for the next year’s budget and tariff filing.
14 Indirect activities are of an administrative nature and are allocated based on
15 current direct labor charges. In addition, the majority of activities for
16 administrative departments (Finance, Human Resources, etc.) are allocated based
17 on the total labor charges within the Company.
18 The activity accounting system is in large part a manual system, meaning that
19 timesheets and invoices are coded manually. The ISO found that it would not be
20 prudent to overly expand the system and require each employee to determine what
21 schedule they serviced through the week. Furthermore, the ISO does not pre-code
ISO New England Inc. Exhibit 3 Recovery of 2015 Administrative Costs Page 21
1 an employee’s time because duties may change often with seasonality or new
2 projects. Therefore, the allocation of activities to the three schedules is made at
3 the managerial level.
4 The activity system is not designed to track costs to individual markets or
5 transaction units. An employee’s time is not driven by the number of transaction
6 units or markets, but by the number of tasks and projects.
7 If the activity accounting system were expanded to provide for accounting cost in
8 more detail, it would be more costly and difficult to manage without substantially
9 increasing its accuracy.
10 Q. HOW WAS THE TARIFF SCHEDULE ALLOCATION VERIFIED?
11 A. In developing the Revenue Requirement for each schedule, managers with cost
12 center responsibilities are required to review the allocation of each and every
13 activity under their control as to the appropriateness of the allocation. During this
14 lengthy evaluation process, all of the activities used by the ISO are reviewed. It is
15 this activity allocation structure that formed the basis of the revenue requirements
16 for each of the three primary schedules.
ISO New England Inc. Exhibit 3 Recovery of 2015 Administrative Costs Page 22
1 2015 COST ALLOCATION AMONG SCHEDULES 1, 2, AND 3
2 Q. HAVE YOU PREPARED AND INCLUDED AN EXHIBIT THAT SHOWS
3 THE DEVELOPMENT OF THE COST OF SERVICE (“COS”)
4 ANALYSIS?
5 A. Yes. The following schedules support the COS shown in RCL-3:
6 Schedule 1 Total Cost Allocation to Schedules by Department
7 Schedule 2 Total Direct Labor Allocation to Schedules by Department
8 Schedule 3 Total Cost Allocations to Schedules by Cost Category
9 Schedule 4 Direct Labor Cost Allocations to Schedules by Cost 10 Category
11 Schedule 5 Allocation Factors by Cost Category
12 Schedule 6 Allocation of Depreciation and Amortization Expense
13 Q. WHAT IS THE ISO’S MAIN EXPENSE?
14 A. As a non-profit entity that operates, but does not own, generation or transmission
15 assets, the ISO’s main expense in the Core Operating Budget is personnel. As
16 shown in RCL-5, Schedule 1, the ISO has budgeted $102.3 million of the ISO’s
17 2015 Core Operating Budget for salaries and overhead. This category includes
18 fees for the Board of Directors, as well.
ISO New England Inc. Exhibit 3 Recovery of 2015 Administrative Costs Page 23
1 Q. WOULD YOU PLEASE DESCRIBE YOUR RCL-3?
2 A. RCL-3, Schedule 1 contains the Test Year 2015 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. PLEASE EXPLAIN HOW LABOR RATIOS WERE DEVELOPED AND
10 USED TO ALLOCATE COSTS IN RCL-3.
11 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 2015. 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.
ISO New England Inc. Exhibit 3 Recovery of 2015 Administrative Costs Page 24
1 Q. PLEASE SUMMARIZE YOUR PROPOSED 2015 COS RESULTS FROM
2 RCL-3 FOR EACH OF THE THREE RATE SCHEDULES.
3 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 2015
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 2015 Revenue Requirement (also
8 provided on line 17 to RCL-2, Schedule 2, page 1).
9
10 Q. EXCLUDING ANY TRUE-UP AMOUNTS, HOW DO THE COS RESULTS
11 SHOWN IN SCHEDULE 1 OF RCL-3 COMPARE WITH THE TEST
12 YEAR 2014 COS RESULTS, INCLUDED IN LAST YEAR’S FILING, ON
13 WHICH THE CURRENT ISO RATES ARE BASED?
14 A. Table 2 below compares, before taking into account any true-ups, the 2015 COS
15 results from Schedule 1 of RCL-3 to the 2014 COS results. Table 2 demonstrates
ISO New England Inc. Exhibit 3 Recovery of 2015 Administrative Costs Page 25
1 how, excluding the true-up amounts, the 2015 COS constitutes a $9 million
2 increase from the 2014 COS accepted by the Commission last year.
3
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 2015 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 2014. The identified activity items account for the majority of the cost shifts
11 within each of the three schedules.
ISO New England Inc. Exhibit 3 Recovery of 2015 Administrative Costs Page 26
Table 3 Examples of Differences in 2015 Operating Expenses
ISO Tariff Schedules Activity Description Total Schedule 1 Schedule 2 Schedule 3 Code (a) (b) (c) (d) (e) (f) Test Year 2015
Various Depreciation/Amortization $ 31,650,319 7,535,487 12,856,039 11,258,793 25902 Coordinated Transaction Scheduling - O&M 456,856 319,799 137,057 - 25926 Hourly Market 748,903 299,561 224,671 224,671 6552 IT - Security 648,132 139,660 335,416 173,057 6540 IT Security Compliance and Reporting 1,284,381 276,759 664,681 342,941 6620 IT - Systems Support - Security 241,437 52,025 124,946 64,466 21603 EMS - Applications Support 1,171,472 252,429 606,250 312,793 21606 EMS - Real-time Market Support 2,075,786 415,157 1,245,472 415,157 21651 PSMM- Power System Modeling 768,214 307,285 307,285 153,643 21707 Application Analysis and Conceptual Design 919,376 - 735,501 183,875 6510 Desktop Support - Hardware 452,893 97,589 234,377 120,926 6511 Desktop Support - Software 616,621 132,870 319,108 164,643 6602 Help Desk Support 349,611 75,334 180,927 93,349 6623 IT - Asset M anagement 534,717 115,221 276,722 142,774 21806 IT Markets Software Support - Enterprise 1,416,807 305,294 733,213 378,300 21821 Compliance M anagement 118,237 25,478 61,189 31,570 25953 ICCP and ED Network Upgrades 75,639 68,075 - 7,564 14402 Ops - Operations Training 2,123,325 849,330 849,330 424,665 99995 NPCC/NERC Dues 5,775,936 - - 5,775,936 18343 FERC Order 1000 959,012 - - 959,012 Totals $ 52,387,675 $ 11,267,353 $ 19,892,184 $ 21,228,137 Test Year 2014
Various Depreciation/Amortization $ 28,305,643 5,767,756 13,225,641 9,312,246 25902 Coordinated Transaction Scheduling - O&M - - - - 25926 Hourly Market 177,103 70,841 53,131 53,131 6552 IT - Security 595,388 128,294 308,120 158,974 6540 IT Security Compliance and Reporting 930,145 200,428 481,360 248,357 6620 IT - Systems Support - Security 83,049 17,895 42,979 22,175 21603 EMS - Applications Support 743,915 160,299 384,984 198,632 21606 EMS - Real-time Market Support 1,424,249 284,850 854,549 284,850 21651 PSMM- Power System Modeling 572,050 228,820 228,820 114,410 21707 Application Analysis and Conceptual Design 797,703 - 638,162 159,541 6510 Desktop Support - Hardware 212,085 45,700 109,756 56,629 6511 Desktop Support - Software 305,083 65,739 157,884 81,460 6602 Help Desk Support 201,355 43,388 104,203 53,764 6623 IT - Asset M anagement 399,966 86,185 206,987 106,794 21806 IT Markets Software Support - Enterprise 1,302,068 280,570 673,834 347,664 21821 Compliance M anagement 68,245 14,705 35,318 18,222 25953 ICCP and ED Network Upgrades - - - - 14402 Ops - Operations Training 1,783,990 713,596 713,596 356,798 99995 NPCC/NERC Dues 5,322,624 - - 5,322,624 18343 FERC Order 1000 1,304,576 - - 1,304,576 Totals $ 44,529,237 $ 8,109,066 $ 18,219,324 $ 18,200,847 Test Year 2015 Costs Minus Test Year 2014 Costs
Various Depreciation/Amortization $ 3,344,676 1,767,731 (369,602) 1,946,547 25902 Coordinated Transaction Scheduling - O&M 456,856 319,799 137,057 - 25926 Hourly Market 571,800 228,720 171,540 171,540 6552 IT - Security 52,744 11,366 27,296 14,083 6540 IT Security Compliance and Reporting 354,236 76,331 183,321 94,584 6620 IT - Systems Support - Security 158,388 34,130 81,967 42,291 21603 EMS - Applications Support 427,557 92,130 221,266 114,161 21606 EMS - Real-time Market Support 651,537 130,307 390,923 130,307 21651 PSMM- Power System Modeling 196,164 78,465 78,465 39,233 21707 Application Analysis and Conceptual Design 121,673 - 97,339 24,334 6510 Desktop Support - Hardware 240,808 51,889 124,621 64,297 6511 Desktop Support - Software 311,538 67,131 161,224 83,183 6602 Help Desk Support 148,256 31,946 76,724 39,585 6623 IT - Asset M anagement 134,751 29,036 69,735 35,980 21806 IT Markets Software Support - Enterprise 114,739 24,724 59,379 30,636 21821 Compliance M anagement 49,992 10,773 25,871 13,348 25953 ICCP and ED Network Upgrades 75,639 68,075 - 7,564 14402 Ops - Operations Training 339,335 135,734 135,734 67,867 99995 NPCC/NERC Dues 453,312 - - 453,312 18343 FERC Order 1000 (345,564) - - (345,564) Totals $ 7,858,438 $ 3,158,287 $ 1,672,860 $ 3,027,290 All Other Unidentified Changes $ 1,132,278 $ 713,452 $ 593,896 $ (175,069) Total Change in Cost of Service $ 8,990,716 $ 3,871,739 $ 2,266,756 $ 2,852,220
% of Difference shown on Table 2 87.41% 81.57% 73.80% 106.14% 1 ISO New England Inc. Exhibit 3 Recovery of 2015 Administrative Costs Page 27
1 Q. PLEASE EXPLAIN IN FURTHER DETAIL HOW THE REVENUE
2 REQUIREMENTS CHANGED FOR EACH SCHEDULE FROM THOSE
3 UTILIZED IN THE FILING SUPPORTING THE 2014 RATE TO THOSE
4 UTILIZED HERE FOR TEST YEAR 2015.
5 A. Schedule 1: The increase in the Revenue Requirement for Schedule 1 results
6 from 2015 cost increases and changes that impact all three schedules, including
7 the costs to maintain the status quo for benefits and compensation, the costs of
8 cyber security improvements, computer service licensing and maintenance, the
9 Energy Market Offer Flexibility project, and depreciation expenses for projects
10 including Energy Market Offer Flexibility, Business Continuity Planning Phase
11 III, and a full year of the new Backup Control Center. The remainder of the
12 Schedule 1 increase is due to work that is predominantly or entirely allocated to
13 Schedule 1, including Coordinated Transaction Scheduling and related
14 depreciation expense, as well as depreciation expense for the Voltage Stability
15 and Control Room Visualization projects.
16 Schedule 2: The increase in the Schedule 2 Revenue Requirement is largely due
17 to the increases that impact all three schedules, as discussed in the preceding
18 paragraph. This increase was offset by a reduction in depreciation expense due to
19 the full depreciation of a number of projects, including Standard Market Design
20 Upgrade Phase III, Automated Market Mitigation, and Generation Control
21 Application Phase I.
ISO New England Inc. Exhibit 3 Recovery of 2015 Administrative Costs Page 28
1 Schedule 3: The increase in the Schedule 3 Revenue Requirement is due to the
2 increased costs allocated to all three schedules (see above), increased NPCC and
3 NERC dues, and depreciation expense for projects allocated entirely to Schedule
4 3, including Forward Capacity Auction 9, Alternative Technologies and
5 Regulation Market, and FCM Terminations and Retirements. These costs were
6 partially offset by a reduction in costs related to Order 1000.
7 THE ISO RATE DESIGN AND ESCALATION FACTORS
8 Q. HOW DID YOU DEVELOP THE ESCALATION FACTORS?
9 A. Consistent with the practice reflected in the filings establishing the ISO’s rates to
10 collect its administrative costs for 1999-2014, escalation factors rely on
11 information contained in the 2014-2023 Forecast Report of Capacity, Energy,
12 Loads and Transmission (the “CELT Report”), dated May 2014. The CELT
13 Report contains actual and estimated energy and peak loads for 2014-2023. The
14 ISO also relied on information in the ISO markets system for the 12-month period
15 ending July 2014. The development of the escalation factors is shown in RCL-7,
16 Schedule 1.
17 Q. PLEASE OUTLINE THE CURRENT RATE DESIGN BEFORE
18 DESCRIBING THE VARIOUS ESCALATION FACTORS.
19 A. As previously indicated, Section IV.A of the Tariff has three rate schedules to
20 cover the ISO’s expenses for providing its three services: Schedule 1 -
ISO New England Inc. Exhibit 3 Recovery of 2015 Administrative Costs Page 29
1 Scheduling Service; Schedule 2 – Energy Administration Service; and Schedule 3
2 – Reliability Administration Service.
3 • Schedule 1
4 The Schedule 1 revenue requirement is allocated 100% to Monthly Regional
5 Network Load and the Reserved Capacity of Through and Out Service (including
6 Unauthorized Use). Schedule 1 revenues collected from Through and Out Service
7 Customers are credited to each Network Customer that month in proportion to
8 each Network Customer’s Monthly Regional Network Load in that month.
9 • Schedule 2
10 The Schedule 2 revenue requirement is allocated 15% to Transaction Units
11 (“TUs”) and 85% to Volumetric Measures (“VMs”), subject to the special true-up
12 described below. TUs measure the frequency and duration of activity and are
13 indifferent to the size (e.g., capacity) of any particular transaction. Conversely,
14 VMs seek to capture a customer’s “physical” reliance on the system administered
15 by the ISO and thus the benefit received.
16 A. Transaction Units
17 Schedule 2 currently utilizes three types of TUs: those associated with Real-Time
18 Energy Market transactions (Energy TU Based Charges), those associated with
19 Increment Offers and Decrement Bids, and those associated with FTR auction
20 submitted and cleared bids.
ISO New England Inc. Exhibit 3 Recovery of 2015 Administrative Costs Page 30
1 Energy TUs equal the sum per month of a Customer’s Bilateral Contract Block-
2 Hours, Demand Bid Block-Hours, Asset Related Demand Bid Block-Hours,
3 Supply Offer Block-Hours and Energy Non-Zero Spot Market Settlement Hours.
4 Under the ISO’s current rate design, a Customer’s total monthly Energy TUs are
5 priced under a three-tiered declining block rate structure. Under this regime, the
6 highest unit rate applies to the first 12,500 Energy TUs incurred in a month; the
7 Customer’s next 27,000 Energy TUs are priced approximately 10% lower; and the
8 balance of monthly Energy TUs, i.e., those in excess of 39,500, are priced at an
9 additional savings of approximately 10% on average.
10 TU Charges Based on Increment Offers and Decrement Bids are assessed based
11 on both of the following: (i) a charge multiplied by the total number of Increment
12 Offers and Decrement Bids submitted, plus (ii) a charge multiplied by the total
13 number of Increment Offers and Decrement Bids that clear the Day-Ahead Energy
14 Market. This category is sometimes referred to as “virtual activity,”
15 distinguishing it from physical activity.
16 TU Charges Based on FTR Auction Submitted and Cleared Bids are assessed on
17 both of the following: (i) a charge multiplied by the total number of FTR auction
18 bids submitted for that period, plus (ii) a charge multiplied by the total number of
19 FTR auction bids cleared for that period. The FTR charges are designed to recoup
20 the costs the ISO incurs for administering the FTR auctions. The FTR revenue
21 offsets other Schedule 2 TU charge revenues.
ISO New England Inc. Exhibit 3 Recovery of 2015 Administrative Costs Page 31
1 B. Volumetric Measures
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.
10 • Schedule 3
11 Schedule 3 allocates internal load activity based on Real-Time NCP [Non-
12 Coincident Peak] Load Obligation. For Exports, Schedule 3 assesses a volumetric
13 (per MWh) charge. Specifically, the ISO divides the Schedule 3 Revenue
14 Requirement by the real-time load obligation forecasted for the upcoming year in
15 the most recent CELT Report. The remaining revenue requirement for Schedule 3
16 (i.e., net of that allocated to Exports) is then divided by the total Real-Time NCP
17 Load Obligation forecast to yield the unitized rate per kW-month.
18 Q. PLEASE EXPLAIN THE ESCALATION FACTORS UTILIZED TO
19 DEVELOP THE BILLING DETERMINANTS FOR 2015.
20 A. The Schedule 1 billing determinants for August through December 2014 were left
21 flat and the determinants for 2015 were increased by 1.5%, consistent with the
ISO New England Inc. Exhibit 3 Recovery of 2015 Administrative Costs Page 32
1 CELT Report data, other load data, and transaction data through July 2014. See
2 column (c) of RCL-7, Schedule 2. The volumetric measures in Schedule 2 and
3 the Schedule 3 billing determinant related to NCP Load Obligation, both of which
4 (like the Schedule 1 billing determinants) are also based on load data, were treated
5 the same as the Schedule 1 determinants. These results are presented in columns
6 (i) and (j), respectively, of RCL-7, Schedule 2.
7 The Schedule 2 transaction unit determinants for Energy TUs, virtual transactions
8 and FTRs were left flat. The decision regarding Energy TUs was based on a
9 review of the volume of transactions, which has been consistent for several years
10 (see the data for 2014 in column (d) of RCL-7, Schedule 2).
11 The numbers of virtual transactions and FTRs have fluctuated in recent years but
12 have not substantially changed overall. Data regarding these calculations appears
13 in Exhibit 3, RCL-7. Tables 4 and 5 below provide, respectively, actual Virtual
14 Energy TU data and actual FTR data from January 2012 through July 2014. RCL-
15 7, Schedule 2, columns (g) and (h) also show data for 2014.
ISO New England Inc. Exhibit 3 Recovery of 2015 Administrative Costs Page 33
1 Table 4
Submitted and Cleared Virtual Energy TUs 350,000 45,000
40,000 300,000 35,000 250,000 30,000
200,000 25,000
20,000 Cleared
Submitted 150,000
15,000 100,000 10,000 Submitted 50,000 Cleared 5,000
0 0
2 3
4 Table 5
Submitted and Cleared FTR TUs (Bids) 120,000 49,000
Submitted 42,000 100,000 Cleared 35,000 80,000
28,000 60,000 Cleared
Submitted 21,000
40,000 14,000
20,000 7,000
0 0
5
ISO New England Inc. Exhibit 3 Recovery of 2015 Administrative Costs Page 34
1 Export activity has decreased in recent years, as shown in column (k) of RCL-7,
2 Schedule 2 and Table 5A, below. Moreover, the actual MWh have been less than
3 the projected sums in the years 2011 through 2014 to date by approximately 15%.
4 Therefore, the ISO has reduced the billing determinant in Schedule 3 for exports
5 by 15%.
6 Table 5A
Actual Schedule 3 Exports vs. Tariff Forecast 12,000,000
10,000,000
8,000,000
6,000,000 Forecast MWh Actual
4,000,000
2,000,000
0 2011 2012 2013 2014 (through July) 7
8 THE ISO RATE DESIGN AND BILLING DETERMINANTS
9 Q. DOES THE ISO PROPOSE ANY CHANGES TO THE EXISTING RATE
10 DESIGNS FOR SCHEDULES 1, 2, AND 3?
11 A. There are no changes to the rate design.
ISO New England Inc. Exhibit 3 Recovery of 2015 Administrative Costs Page 35
1 Q. PLEASE DESCRIBE THE SCHEDULE 1 RATE CALCULATION.
2 A. RCL-7, Schedule 3, lines 1 through 3 show the Schedule 1 Billing Determinants
3 and the Revenue Requirement allocated thereto. Dividing the Revenue
4 Requirement by the forecasted billing units yields the rate for 2015 of
5 $0.00021/kW-hour.
6 Q. PLEASE DESCRIBE THE SCHEDULE 2 RATE CALCULATION.
7 A. Schedule 2 employs a declining blocked rate structure that is applicable to both
8 Energy TUs and VMs. The three-tiered declining block structure is discussed
9 earlier in my testimony. Increment Offers and Decrement Bid TUs and FTR TUs
10 incur unitized charges. RCL-7 (Schedule 3) and Table 6 (below) provide the
11 Schedule 2 rates proposed for 2015.
ISO New England Inc. Exhibit 3 Recovery of 2015 Administrative Costs Page 36
TABLE 6
Description TY 2015 (a) (b) Transaction Units INC Offers/DEC Bids Submitted $ 0.00500 /Offer or Bid Cleared $ 0.06000 /Offer or Bid
Financial Transmission Rights Submitted $ 0.85853 /Bid Cleared $ 1.21377 /Bid
Energy Transaction Units Block 1 - 1st 12,500 TUs $ 0.65101 /TU-hour Block 2 – Next 27,000 TUs $ 0.59182 /TU-hour Block 3 – Over 39,500 TUs $ 0.53264 /TU-hour
Volumetric Measures Block 1 - 1st 250,000 MWH $ 0.25517 /MWh Block 2 – Next 1,250,000 MWH $ 0.23197 /MWh Block 3 – Over 1,500,000 MWH $ 0.20877 /MWh
1 Q. PLEASE EXPLAIN HOW THE RATES FOR EACH BLOCK ARE
2 CALCULATED.
3 A. The rate components in all cases reflect an approximate 10% differential from the
4 average rate.
5 Q. PLEASE DESCRIBE THE SCHEDULE 3 RATE CALCULATION.
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
ISO New England Inc. Exhibit 3 Recovery of 2015 Administrative Costs Page 37
1 obligation forecast for 2015. The export rate is then applied to the total MWh of
2 Exports forecasted for the test year to determine the portion of the Schedule 3
3 Revenue Requirement assessed to exports. The remaining Revenue Requirement
4 for Schedule 3 (i.e., net of that allocated to exports) is then divided by the total
5 Real-Time NCP Load Obligation forecast to yield the unitized rate per kW-month.
TABLE 7
Description TY 2015 Amount %
Revenue Requirement ($) $ 52,630,263 100.0%
Real-Time NCP Load Obligation $ 51,067,436 97.0%
Export Rate $ 1,562,827 3.0%
Billing Units
Real-Time NCP Load Obligation 272,169,942 /kW-Mo.
Export Rate 4,223,857 /MWh
Rates
Real-Time NCP Load Obligation $ 0.18763 /kW-Mo.
Rate on Exports $ 0.37 /MWh 6
7 RATE SUMMARY
8 Q. WOULD YOU PLEASE SUMMARIZE THE RATES FOR 2015 THAT
9 YOU ARE SPONSORING?
10 A. Yes. These rates are summarized in Table 8.
ISO New England Inc. Exhibit 3 Recovery of 2015 Administrative Costs Page 38
Table 8 2015 Rate Components (1)
Tariff Schedule Jan. 1, 2015 (a) (b)
Schedule 1 Network Load (per kW-hour) $0.00021
Schedule 2 TU Bids (Virtual Inc/Dec) Submitted $0.00500 Cleared $0.06000
FTR Bids Submitted $0.85853 Cleared $1.21377
TU's Block 1 - 1st 12,500 $0.65101 Block 2 - Next 27,000 $0.59182 Block 3 - Over 39,500 $0.53264
Volumetric Block 1 - 1st 250,000 $0.25517 Block 2 - Next 1,250,000 $0.23197 Block 3 - Over 1,500,000 $0.20877
Schedule 3 R-T NCP Load Obligation $0.18763 Export Rate $0.37000
1 (1) From Exh 3, RCL-7, Sch 3.
2 Q. HAVE YOU TAKEN INTO ACCOUNT ANY REVENUE SHORTFALL
3 ATTRIBUTABLE TO TUs USED IN SCHEDULE 2?
4 A. Yes. In the event of a revenue shortfall attributable to TUs, the shortfall
5 allocation has two components. This first component allocates the first 50% of
6 the shortfall to Schedule 2 VMs rather than the usual 15/85 allocation of Schedule
ISO New England Inc. Exhibit 3 Recovery of 2015 Administrative Costs Page 39
1 2 Revenue Requirements between TUs and VMs, respectively. The second
2 component increases the percentage of the shortfall allocated to VMs by an
3 additional percentage for each percentage decrease which occurred between the
4 number of TUs used in the current true-up (based on year-to-date actual data
5 through August of the current year) and the number of TUs that the ISO had used
6 in the original projection of the rates for that year.
7 As shown in RCL-7, Schedule 6, the final 2013 amount is an over-collection of
8 $944,459. Accordingly, there is no variation for 2015 to the 15/85 allocation of
9 the Schedule 2 revenue requirement between TUs and VMs.
10 FIXED FEES
11 Q. DO YOU HAVE ANY OTHER COMMENTS REGARDING THE RATES
12 INCLUDED IN THE PROPOSED 2015 TARIFF?
13 A. Yes. Schedule 3 includes certain RAS Fees that are applicable to Transmission
14 Customers who are non-Market Participants. This fee is currently $2.94 (hourly).
15 For 2015, I am proposing to increase this hourly fee to $3.02.
16 Q. PLEASE EXPLAIN HOW YOU DERIVED THE PROPOSED HOURLY
17 RAS FEE.
18 A. The proposed RAS Fee was developed by applying a ratio of the Schedule 3
19 forecasted revenue requirement for 2015 to the Schedule 3 forecasted revenue
20 requirement for 2002 to the 2002 RAS Monthly Fee (($671 x
ISO New England Inc. Exhibit 3 Recovery of 2015 Administrative Costs Page 40
1 ($52,630,263/$16,035,649) = $2,202.27), and breaking that down to an hourly
2 rate, which for 2015 is $3.02.
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 Proposed No. Item Current Jan. 1, 2015 (a) (b) (c)
1 Monthly Calculation $ 2,149.01 $ 2,202.27
2 Hourly Fee $ 2.94 $ 3.02 7 8
9 Q. UNDER THE RATES PROPOSED IN THIS FILING, WHAT HAPPENS
10 TO THE REVENUE DERIVED FROM THESE RAS FEES?
11 A. Any revenue derived from the RAS Fees will be credited back on a monthly basis
12 to all Market Participants who take service under Schedule 3 in proportion to the
13 total charges incurred by the Market Participants for that month.
1 Exhibit 3 RCL - 2 Schedule 2 ISO NEW ENGLAND INC. Page 1 of 2 2015 REVENUE REQUIREMENT (in thousands of dollars)
Line No. Operating Expense Budget:
1 Operating Budget $144,224.2 2 3 Depreciation and interest expense 4 Depreciation 31,764.7 5 Interest 2,326.0 6 34,090.7 7 8 Total 2015 Operating Expense Budget $178,314.9 9 10 2015 Operating Expense Revenue Requirement $178,314.9 11 12 True-Up Amount 13 14 2013 (Over)/ Under Collection $ (9,777.9) 15 16 17 Total 2015 ISO Revenue Requirement $168,537.0 Exhibit 3 RCL - 2 Schedule 2 ISO New England Inc. Page 2 of 2 2013 True-Up Amount
Line No. Schedule Total 1 2 3
1 2013 Total Operating Expense $ 156,721,769 $ 36,722,955 $ 71,550,434 $ 48,448,380 2 2013 Total Collections $ 166,499,643 $ 41,109,301 $ 74,603,555 $ 50,786,788 3 4 2013 Total (Over) / Under Collection $ (9,777,874) $ (4,386,346) $ (3,053,121) $ (2,338,408) Exhibit 3 (RCL-3)
ISO NEW ENGLAND INC.
FERC DOCKET NO. ER15-___-000
COST ALLOCATIONS
TEST YEAR 2015
Exhibits For Robert C. Ludlow Exhibit 3 (RCL-3) Schedule 1.0
ISO NEW ENGLAND INC. FERC DOCKET NO. ER15-___-000 TOTAL COST ALLOCATION TO SCHEDULES BY DEPARTMENT TEST YEAR 2015
Line Department Self-Funding Tariff No. Description Total Schedule 1 Schedule 2 Schedule 3 (a) (b) (c) (d) (e)
1 Administration-CEO $ 8,460,763 $ 1,823,127 $ 4,378,538 $ 2,259,098 2 3 Finance 53,266,938 10,917,279 20,972,067 21,377,591 4 5 Building Services 3,546,150 764,125 1,835,172 946,853 6 7 Enterprise Risk Management 1,690,398 459,850 747,720 482,828 8 9 Human Resources 7,439,436 1,603,051 3,849,990 1,986,395 10 11 Legal Department 10,025,854 2,005,324 4,914,579 3,105,951 12 13 Internal Audit 1,675,620 264,947 1,086,726 323,947 14 15 ISO Operations 16 COO-Adm 1,815,643 456,214 816,261 543,167 17 System Operations - Administration 289,358 99,944 134,320 55,094 18 Operations 11,787,053 3,368,597 6,447,014 1,971,442 19 Reliability and Operations Services 819,683 307,886 173,465 338,333 20 Reliability and Operations Compliance 1,212,536 536,048 305,734 370,755 21 Operations Support Services 6,052,369 3,233,480 891,162 1,927,728 22 System Operations Support 336,867 2,033 69,120 265,714 23 Market Operations - Adm 1,228,918 1,373 859,080 368,465 24 Market Monitoring 3,769,871 - 2,631,545 1,138,326 25 Market Operations 2,536,928 9,233 2,159,697 367,998 26 Market Anaylsis & Settlements 2,513,702 368,906 1,161,745 983,050 27 Market Operations Support Services 605,717 47,498 443,903 114,316 28 Market Services 2,414,318 282,548 1,895,880 235,890 29 Market Training and Reliability Contracts 856,145 - 428,072 428,072 30 System Planning 1,437,600 965,795 288,405 183,401 31 Resource Adequacy 3,742,271 266,081 821,189 2,655,002 32 Transmission Planning 6,341,678 5,382,665 - 959,012 33 Program Management 2,532,237 877,125 922,595 732,517 34 Business Architecture and Technology 2,273,992 490,000 1,176,816 607,176 35 Market Development Administration 3,828,452 788,015 2,005,968 1,034,469 36 Market Design 902,601 162,167 448,208 292,225 37 Demand Resource Strategy 468,040 100,853 242,216 124,971 38 IT Management 3,929,424 910,653 1,962,706 1,056,066 39 IT System/Network & Desktop 10,436,097 1,473,904 5,943,148 3,019,046 40 IT Enterprise Applications Support 7,965,768 1,166,653 4,843,163 1,955,952 41 IT Enterprise Applications Development 1,718,340 - 1,374,672 343,668 42 IT Energy Management Systems 5,907,432 1,949,972 2,906,921 1,050,539 43 IT Cyber Security 2,041,727 439,952 1,056,616 545,159 44 IT Power System Modeling Management 2,444,985 801,788 824,741 818,455 45 Total ISO Operations 92,209,752 24,489,384 43,234,361 24,486,007 46 47 Total ISO Revenue Requirement $ 178,314,912 $ 42,327,088 $ 81,019,153 $ 54,968,671 48 True-up from 2013 (9,777,875) (4,386,346) (3,053,121) (2,338,408) 49 Total True-up $ (9,777,875) $ (4,386,346) $ (3,053,121) $ (2,338,408) 50 51 ISO Net Revenue Requirement $ 168,537,037 $ 37,940,742 $ 77,966,032 $ 52,630,263
(1) From Exhibit 3 (RCL-3), Schedule 3.0. Exhibit 3 (RCL-3) Schedule 2.0 Page 1 of 1 ISO NEW ENGLAND INC. FERC DOCKET NO. ER15-___-000 TOTAL DIRECT LABOR ALLOCATION TO SCHEDULES BY DEPARTMENT TEST YEAR 2015
Line Department Self-Funding Tariff No. Description Total Schedule 1 Schedule 2 Schedule 3 (a) (b) (c) (d) (e)
1 Administration-CEO $ 3,007,866 $ 648,136 $ 1,556,604 $ 803,127 2 3 Finance 11,419,899 2,430,407 5,837,021 3,152,471 4 5 Building Services 519,279 111,894 268,733 138,652 6 7 Enterprise Risk Management 1,577,553 427,292 702,262 447,999 8 9 Human Resources 4,072,577 877,560 2,107,604 1,087,414 10 11 Legal Department 6,080,995 1,269,026 2,793,972 2,017,997 12 13 Internal Audit 1,007,153 197,477 569,335 240,342 14 15 ISO Operations 16 COO-Adm 1,294,634 346,981 620,822 326,831 17 System Operations - Administration 219,249 75,729 101,775 41,745 18 Operations 11,644,238 3,319,859 6,379,764 1,944,616 19 Reliability and Operations Services 703,313 274,732 141,832 286,749 20 Reliability and Operations Compliance 1,259,266 551,692 336,436 371,137 21 Operations Support Services 5,863,910 3,165,855 854,737 1,843,319 22 System Operations Support 328,667 - 65,733 262,934 23 Market Operations - Adm 1,197,592 1,373 837,152 359,067 24 Market Monitoring 3,263,753 - 2,283,796 979,957 25 Market Operations 2,529,923 9,233 2,152,913 367,777 26 Market Anaylsis & Settlements 2,513,205 368,832 1,161,503 982,869 27 Market Operations Support Services 605,717 47,498 443,903 114,316 28 Market Services 2,136,283 274,228 1,682,140 179,915 29 Market Training and Reliability Contracts 855,866 - 427,933 427,933 30 System Planning 1,141,096 797,632 211,238 132,227 31 Resource Adequacy 3,054,594 235,456 785,813 2,033,325 32 Transmission Planning 5,162,034 4,693,029 - 469,006 33 Program Management 2,391,699 828,058 872,007 691,634 34 Business Architecture and Technology 2,028,147 437,026 1,049,588 541,533 35 Market Development Administration 3,530,924 719,585 1,830,440 980,899 36 Market Design 877,951 156,976 435,522 285,453 37 Demand Resource Strategy 328,031 70,684 169,759 87,587 38 IT Management 3,637,709 847,794 1,811,740 978,175 39 IT System/Network & Desktop 4,957,093 815,027 2,544,780 1,597,287 40 IT Enterprise Applications Support 3,898,855 565,758 2,377,390 955,707 41 IT Enterprise Applications Development 1,717,785 - 1,374,228 343,557 42 IT Energy Management Systems 3,143,894 1,064,714 1,560,190 518,990 43 IT Cyber Security 1,136,230 244,835 588,011 303,383 44 IT Power System Modeling Management 2,012,511 655,843 675,630 681,038 45 Total ISO Operations 73,434,171 20,568,429 33,776,777 19,088,965 46 47 Total ISO Direct Labor $ 101,119,493 $ 26,530,221 $ 47,612,306 $ 26,976,966
(1) From Exhibit 3 (RCL-3), Schedule 4.0. ISO NEW ENGLAND INC. Exhibit 3 (RCL-3) FERC DOCKET NO. ER15-___-000 Schedule 3.0 TOTAL COST ALLOCATIONS TO SCHEDULES BY COST CATEGORY Page 1 of 7 TEST YEAR 2015
Line Activity Code Allocation Self-Funding Tariff No. No. Description Factor (1) Total (2) Schedule 1 Schedule 2 Schedule 3 (a) (b) (c) (d) (e) (f) (g)
1 307 Administration-CEO 2 12651 Adm/Finance/HR - Indirect Administrative Support Total Dir Labor $ 7,783,348 $ 1,677,158 $ 4,027,968 $ 2,078,222 3 12652 Adm/Finance/HR - NEPOOL Committee Support Total Dir Labor 2,990 644 1,547 798 4 12654 Adm/Finance/HR - National Committee Support Total Dir Labor 13,679 2,947 7,079 3,652 5 12657 Adm/Finance/HR - Indirect Administrative Support for BCC Total Dir Labor 660,747 142,378 341,944 176,425 6 Total 8,460,764 1,823,127 4,378,538 2,259,098 7 8 302 Finance 9 11601 Payroll Administration Total Dir Labor 364,566 78,557 188,667 97,342 10 11701 Accounts Payable Total Dir Labor 207,225 44,653 107,241 55,331 11 11702 Procurement Total Dir Labor 498,029 107,315 257,735 132,978 12 11901 Billing for Transmission and Energy Settlements Total Dir Labor 70,756 15,247 36,617 18,893 13 12001 Budgeting and Forecasting Total Dir Labor 517,080 111,420 267,594 138,065 14 12005 Credit Admininstration Total Dir Labor 342,981 73,906 177,496 91,579 15 12015 BCC Construction Total Dir Labor 48,169 10,379 24,928 12,861 16 12017 Forward Capacity Market (FCM) Reforms Alloc-Fixed 140,871 - - 140,871 17 12101 Ledger Closing, Financial Statements and Tax Reporting Total Dir Labor 564,032 121,538 291,893 150,601 18 12201 Treasury and Cash Management Total Dir Labor 2,420,884 521,651 1,252,834 646,397 19 92004 Depreciation Expense 2004 Assets Alloc-Fixed 43,160 8,988 22,535 11,637 20 92005 Depreciation Expense 2005 Assets Alloc-Fixed 802,617 169,813 417,365 215,439 21 92006 Depreciation Expense 2006 Assets Total Dir Labor 570,895 123,028 295,438 152,429 22 92007 Depreciation Expense 2007 Assets Total Dir Labor 165,460 35,657 85,626 44,178 23 92008 Depreciation Expense 2008 Assets Alloc-Fixed 43,667 24,011 12,966 6,690 24 92009 Depreciation Expense 2009 Assets Alloc-Fixed 41,416 24,240 12,948 4,228 25 92010 Depreciation Expense 2010 Assets Alloc-Fixed 510,846 163,766 199,913 147,167 26 92011 Depreciation Expense 2011 Assets Alloc-Fixed 2,642,552 522,364 888,163 1,232,024 27 92012 Depreciation Expense 2012 Assets Alloc-Fixed 6,490,210 1,233,652 2,831,154 2,425,404 28 92013 Depreciation Expense 2013 Assets Alloc-Fixed 7,527,261 1,386,217 3,615,157 2,525,887 29 92014 Depreciation Expense 2014 Assets Alloc-Fixed 12,250,841 3,715,761 4,195,754 4,339,328 30 92015 Depreciation Expense 2015 Assets Alloc-Fixed 561,394 127,989 279,022 154,383 31 99707 Amortization of Land Recovery Alloc-Fixed 54,396 10,516 19,353 24,527 32 99995 NPCC/NERC Dues Alloc-Fixed 5,775,936 - - 5,775,936 33 99996 Operating Contingency Total Dir Labor 700,000 150,836 362,258 186,906 34 99996 Operating Contingency Total Dir Labor 1,100,000 237,028 569,262 293,710 35 99998 Payroll & Other Accruals Total Dir Labor 8,811,695 1,898,746 4,560,149 2,352,800 36 Total 53,266,938 10,917,279 20,972,067 21,377,591 37 38 108 Building Services 39 12664 Building Maintenance Total Dir Labor 3,546,150 764,125 1,835,172 946,853 40 12668 Building Maintenance - Offsite Temporary Offices Total Dir Labor - - - - 41 Total 3,546,150 764,125 1,835,172 946,853 42 43 310 Enterprise Risk Management 44 22701 ERM -Enterprise Risk Mgmnt - Admn Alloc-Fixed 7,619 2,537 2,537 2,545 45 22703 ERM-Bus Cont Pl Prog Admin & Support Alloc-Fixed 152,374 50,741 50,741 50,893 46 22704 ERM - Record Retention Services Alloc-Fixed 92,989 30,965 30,965 31,058 47 22705 ERM - Corporate Scorecard Alloc-Fixed 7,619 2,537 2,537 2,545 48 22706 ERM - Document Management Services Alloc-Fixed 99,043 39,617 29,713 29,713 49 22708 ERM Adminstration Total Dir Labor 7,619 1,642 3,943 2,034 50 22709 ERM Management Total Dir Labor 80,208 17,283 41,508 21,416 51 22710 Employee Development Total Dir Labor 22,856 4,925 11,828 6,103 52 22711 FAP Admin - FCM Cap Adjustments Total Dir Labor 26,773 5,769 13,855 7,149 53 22712 FAP Admin - Risk Policy Assessments Total Dir Labor 76,187 16,417 39,428 20,343 54 22713 FAP Admin - MEC/Financials Total Dir Labor 33,522 7,223 17,348 8,951 55 22714 FAP Analysis Total Dir Labor 121,899 26,267 63,084 32,548 56 22716 FAM Rebuild Total Dir Labor 30,475 6,567 15,771 8,137 57 22718 CAPA 2.0 Total Dir Labor 137,137 29,550 70,970 36,617 58 22719 Human Performance Improvement Total Dir Labor 1,524 328 789 407 59 22720 Business Process Change Management Total Dir Labor 144,755 31,192 74,912 38,651 60 22721 Corp Strategic Risk Total Dir Labor 38,093 8,208 19,714 10,171 61 22722 Corp Strategic Plan Total Dir Labor 7,619 1,642 3,943 2,034 62 22725 OSHA procedures Total Dir Labor 7,619 1,642 3,943 2,034 63 22726 Project Risk Management Meeting Total Dir Labor 2,724 587 1,410 727 64 22727 ERM Business Analysis Total Dir Labor 83,806 18,058 43,370 22,377 65 23003 CP - Safety / Security / Facilities Total Dir Labor 22,856 4,925 11,828 6,103 66 23006 Business Continuity Planning Total Dir Labor 38,093 8,208 19,714 10,171 67 25006 ERM - Business Process Maintenance Alloc-Fixed 52,780 23,751 23,751 5,278 68 25011 Corrective Action/Preventive Action Alloc-Fixed 290,544 96,751 96,751 97,042 69 25012 OE - Business Process Re-Engineering Alloc-Fixed 1,524 507 507 509 70 25014 EtQ Tools Dev & Support Total Dir Labor 102,143 22,010 52,860 27,273 71 Total 1,690,398 459,850 747,720 482,828
(1) From Exhibit 3 (RCL-3), Schedule 5.0. (2) Provided by ISO-NE. ISO NEW ENGLAND INC. Exhibit 3 (RCL-3) FERC DOCKET NO. ER15-___-000 Schedule 3.0 TOTAL COST ALLOCATIONS TO SCHEDULES BY COST CATEGORY Page 2 of 7 TEST YEAR 2015
Line Activity Code Allocation Self-Funding Tariff No. No. Description Factor (1) Total (2) Schedule 1 Schedule 2 Schedule 3 (a) (b) (c) (d) (e) (f) (g)
1 301 Human Resources 2 12661 Employee Affairs (Recreation Committee) Total Dir Labor 24,668 5,315 12,766 6,586 3 12701 Recruiting/Interviewing Total Dir Labor 458,427 98,782 237,241 122,404 4 12801 Employee Relations Total Dir Labor 154,957 33,390 80,192 41,375 5 12901 Benefit Administration Total Dir Labor 1,179,682 254,198 610,499 314,986 6 12951 Compensation Total Dir Labor 302,994 65,289 156,803 80,902 7 12961 HR - General Total Dir Labor 1,195,356 257,576 618,610 319,170 8 12962 HR - Training Total Dir Labor 1,150,437 247,897 595,364 307,177 9 13410 Power Training & Development Total Dir Labor 1,395,159 300,629 722,010 372,520 10 13411 Markets Training & Development Total Dir Labor 344,304 74,191 178,181 91,932 11 13412 People Training & Development Total Dir Labor 260,740 56,184 134,936 69,620 12 13413 Business Skills Trng & Dev Total Dir Labor 290,602 62,619 150,390 77,593 13 13414 Technology Trng & Development Total Dir Labor 682,111 146,981 353,000 182,130 14 Total 7,439,436 1,603,051 3,849,990 1,986,395 15 16 306 Legal Department 17 8301 GC - Federal Regulatory Total Dir Labor 298,729 64,370 154,596 79,763 18 12423 GC - Financial Assurance Policy (FAP) Total Dir Labor 12,007 2,587 6,214 3,206 19 12425 GC - Price Response Demand Total Dir Labor 40,001 8,619 20,701 10,681 20 12502 Board of Directors Total Dir Labor 148,039 31,899 76,612 39,528 21 12504 ISO Tariff Litigation Total Dir Labor 63,279 13,635 32,748 16,896 22 12505 Administration of OATT Alloc-Fixed 425,072 425,072 - - 23 12508 Energy Markets/Compliants/Rule Changes Alloc-Fixed 85,913 - 85,913 - 24 12509 Market Monitoring and Sanctions Alloc-Fixed 100,232 - 50,116 50,116 25 12512 GC - BSIA - General Corporate Total Dir Labor 59,990 12,927 31,046 16,018 26 12513 Miscellaneous Labor Matters Total Dir Labor 156,002 33,615 80,733 41,654 27 12514 NEPOOL Participants Committee Total Dir Labor 68,856 14,837 35,634 18,385 28 12517 Administrative and Clerical Support Total Dir Labor 458,205 98,734 237,126 122,345 29 12520 Market Monitoring Rules/Regulations Alloc-Fixed 315,016 - 126,006 189,010 30 12521 Billing Disputes Total Dir Labor 35,999 7,757 18,630 9,612 31 12523 NEPOOL Information Policy Total Dir Labor 42,957 9,256 22,231 11,470 32 12542 Transmission Upgrades CT Alloc-Fixed 62,410 - 43,687 18,723 33 12543 Independent Market Advisor Alloc-Fixed 883,000 - 618,100 264,900 34 12544 FERC Proceedings Total Dir Labor 193,436 41,682 100,105 51,649 35 12552 GC - S&G - General Corporate Total Dir Labor 235,586 50,764 121,918 62,903 36 12555 GC - Transmission Upgrades - VT Total Dir Labor 3,002 647 1,553 802 37 12556 GC - Patents Total Dir Labor 3,002 647 1,553 801 38 12559 General Corporate Total Dir Labor 937,926 202,104 485,387 250,434 39 12562 Transmission Upgrades VT Alloc-Fixed 13,194 - 9,236 3,958 40 12563 Regulatory Matters Total Dir Labor 384,002 82,745 198,725 102,532 41 12565 GC - Conn Regulatory Matters - WBAM Total Dir Labor 13,194 2,843 6,828 3,523 42 12569 NOPR / Rulemaking Comments Total Dir Labor 35,999 7,757 18,630 9,612 43 12570 Operations Total Dir Labor 12,007 2,587 6,214 3,206 44 12571 ISO Reporting Total Dir Labor 12,007 2,587 6,214 3,206 45 12572 GC - BSAI - 205 General Proceedings Total Dir Labor 35,999 7,757 18,630 9,612 46 12573 206 General Proceedings Total Dir Labor 120,003 25,858 62,103 32,042 47 12574 Market Rule 1 Proceedings Total Dir Labor 240,007 51,717 124,206 64,084 48 12575 Transmission Cost Allocation Alloc-Fixed 90,008 - 63,006 27,003 49 12587 Capacity Market Development Alloc-Fixed 474,684 - - 474,684 50 12588 Web Content Management Total Dir Labor 522, 230 112,530 270,260 139,440 51 12592 GC - State Proceedings Alloc-Fixed 240,007 - 120,003 120,003 52 12594 Maine Transmission Siting Alloc-Fixed 30,577 - 21,404 9,173 53 12595 NEEWS Transmission Siting Alloc-Fixed 2,940 - 2,058 882 54 12598 GC - ERO Alloc-Fixed 35,999 14,399 14,399 7,200 55 12663 Public Information Total Dir Labor 1,429,324 307,991 739,691 381,642 56 12669 Government Affairs Total Dir Labor 1,704,015 367,182 881,847 454,987 57 12673 Market Conference Total Dir Labor 999 215 517 267 58 Total 10,025,854 2,005,324 4,914,579 3,105,951 59 60 305 Internal Audit 61 15001 Audit - Indirect Mgmnt Duties Total Dir Labor 73,469 15,831 38,021 19,617 62 15002 Audit- Personnel Management Total Dir Labor 17,112 3,687 8,856 4,569 63 15003 Audit- Budget & Forecasting Total Dir Labor 8,556 1,844 4,428 2,285 64 15004 Audit- Audit Followup Activities Total Dir Labor 8,556 1,844 4,428 2,285 65 15005 Audit - Audit & Finance Committee Total Dir Labor 85,071 18,331 44,025 22,715 66 15006 Audit- Internal Audit Business Process Update Total Dir Labor 8,556 1,844 4,428 2,285 67 15007 Audit- Annual Audit Work Plan Total Dir Labor 43,194 9,307 22,353 11,533 68 15008 Audit-Training Total Dir Labor 71,963 15,507 37,241 19,215 69 15020 Internal Audit - Finance Total Dir Labor 42,781 9,218 22,140 11,423 70 15021 Audit- Perfomance Measurements Total Dir Labor 25,669 5,531 13,284 6,854 71 15022 Audit- Vendor Contracts Total Dir Labor 12,834 2,766 6,642 3,427 72 15023 Audit- Wire Transfers Total Dir Labor 8,556 1,844 4,428 2,285 73 15040 Audit-Operations Total Dir Labor 200,518 43,208 103,770 53,540 74 15065 Audit - Wind Integration Project Alloc-Fixed 42,781 17,112 17,112 8,556 75 15068 Audit - FCM Settlements Audit Alloc-Fixed 8,290 - - 8,290 76 15085 Audit - Information Technology Total Dir Labor 152,018 32,757 78,671 40,590 77 15090 Audit - Training Total Dir Labor 1,298 280 672 347 78 15110 External Audit - Operations Total Dir Labor 42,781 9,218 22,140 11,423 79 15133 Audit- Satellite Reviews Total Dir Labor 46,063 9,926 23,838 12,299 80 15134 Audit- SCADA Operations Reviews Total Dir Labor 1,651 356 854 441 81 15160 External Audit - Finance Total Dir Labor 15,336 3,305 7,937 4,095 82 15161 External Audit- Pension Audit Total Dir Labor 62,341 13,433 32,262 16,645 83 15162 Ext Audit- Financial Audit Total Dir Labor 101,400 21,850 52,476 27,075 84 15166 Ext Audit -Pricing Module Certification Alloc-Fixed 25,350 - 25,350 - 85 15175 Ext Audit - Info Technology Total Dir Labor 15,600 3,361 8,073 4,165 86 15186 Ext Audit - SSAE 16 Direct Support Total Dir Labor 34,225 7,375 17,712 9,138 87 15190 Int Audit Special Projects Total Dir Labor 11,700 2,521 6,055 3,124 88 15192 IA Special Projects - Data Mining - Audit Command Language Impl Total Dir Labor 16,614 3,580 8,598 4,436 89 25702 External Audit - SSAE 16 Alloc-Fixed 449,048 - 449,048 - 90 28160 Audit - MS Universal Access Gateway Review Total Dir Labor 42,290 9,113 21,885 11,292 91 Total 1,675,620 264,947 1,086,726 323,947 (1) From Exhibit 3 (RCL-3), Schedule 5.0. (2) Provided by ISO-NE. ISO NEW ENGLAND INC. Exhibit 3 (RCL-3) FERC DOCKET NO. ER15-___-000 Schedule 3.0 TOTAL COST ALLOCATIONS TO SCHEDULES BY COST CATEGORY Page 3 of 7 TEST YEAR 2015
Line Activity Code Allocation Self-Funding Tariff No. No. Description Factor (1) Total (2) Schedule 1 Schedule 2 Schedule 3 (a) (b) (c) (d) (e) (f) (g)
1 701 COO-Adm 2 19001 COO - NEPOOL Committee Support Total OPS Labor 59,321 15,899 28,446 14,976 3 19002 COO - Regional Committee Support Total OPS Labor 58,310 15,628 27,962 14,720 4 19003 COO - National Committee Support Total OPS Labor 89,924 24,101 43,122 22,701 5 19005 COO - Indirect Supervision/Clerical Support Total OPS Labor 1,144,639 306,781 548,894 288,964 6 19007 COO - Operational Excellence Total OPS Labor 250,000 67,004 119,884 63,113 7 19009 COO - Renewable Resource Integration Alloc-Fixed 113,448 - - 113,448 8 19010 COO - Quality Improvement Total OPS Labor 100,000 26,802 47,953 25,245 9 Total 1,815,643 456,214 816,261 543,167 10 11 12 105 System Operations - Administration 13 14404 System Ops Mgt & Adm - NEPOOL Committee Support SOA Labor 9,005 3,110 4,180 1,714 14 14405 System Ops Mgt & Adm - Indirect Supervision/Clerical Support SOA Labor 271,349 93,724 125,960 51,665 15 14407 System Ops Mgt & Adm - Regional Committee Support SOA Labor 9,005 3,110 4,180 1,714 16 Total 289,358 99,944 134,320 55,094 17 18 101 Operations 19 14001 Ops - Generation Dispatch Alloc-Fixed 3,727,871 - 3,131,411 596,459 20 14002 Ops - Transmission Operations Alloc-Fixed 2,351,539 1,881,231 117,577 352,731 21 14304 Ops - Advanced Scheduling and Forecasting Alloc-Fixed 1,771,745 88,587 1,399,678 283,479 22 14402 Ops - Operations Training Alloc-Fixed 2,123,325 849,330 849,330 424,665 23 14561 Ops - NEPOOL Committee Support OPS Labor 10,190 2,849 5,642 1,700 24 14563 Ops - National Committee Support OPS Labor 10,190 2,849 5,642 1,700 25 14564 Ops - Indirect Supervision/Clerical Support OPS Labor 1,417,869 396,388 784,985 236,496 26 14565 Ops - Employee Development OPS Labor 19,650 5,493 10,879 3,278 27 14702 TPC - Procedure Documentation Alloc-Fixed 354,675 141,870 141,870 70,935 28 Total 11,787,053 3,368,597 6,447,014 1,971,442 29 30 702 Reliability and Operations Services 31 14703 TPC - NEPOOL Committee Support OS Labor 330,858 183,782 63,963 83,114 32 14704 TPC - Regional Committee Support OS Labor 14,241 7,910 2,753 3,577 33 14706 TPC - Indirect Supervision/Clerical Support OS Labor 26,081 14,487 5,042 6,552 34 14711 ISO TMS Tariff-Section 2 - (OATT) and Agreements Support Alloc-Fixed 212,871 70,886 70,886 71,099 35 14715 EIPC - Non DOE Funded/Unallowable Alloc-Fixed 158,580 - - 158,580 36 14813 ROC - ICP Policy/Procedure Alloc-Fixed 77,052 30,821 30,821 15,410 37 Total 819,683 307,886 173,465 338,333 38 39 703 Reliability and Operations Compliance 40 14801 ROC - Compliance Monitoring Alloc-Fixed 675,357 270,143 270,143 135,071 41 14803 ROC - Regional Committee Support OS Labor 11,906 5,953 - 5,953 42 14804 ROC - National Committee Support OS Labor 166,801 83,400 - 83,400 43 14806 ROC - Employee Development Alloc-Fixed 19,693 10,939 3,807 4,947 44 14807 ROC - Compliance Audit OS Labor 240,873 120,437 - 120,437 45 14808 ROC - Change Management Alloc-Fixed 28,894 13,002 2,889 13,002 46 14809 ROC - Tariff Compliance Alloc-Fixed 48,157 14,447 28,894 4,816 47 14810 ROC - NERC Self Certifications Alloc-Fixed 20,855 17,726 - 3,128 48 Total 1,212,536 536,048 305,734 370,755 49 50 103 Operations Support Services 51 14451 TSO - NEPOOL Committee Support TSO Labor 15,280 4,947 7,305 3,028 52 14452 TSO - Regional Committee Support TSO Labor 15,532 5,028 7,426 3,078 53 14453 TSO - National Committee Support TSO Labor 139,858 45,278 66,864 27,716 54 14454 TSO - Indirect Supervision/Clerical Support TSO Labor 494,653 160,140 236,486 98,026 55 14462 OSS - General Systems Operations Support TSO Labor 839,684 271,842 401,440 166,402 56 18361 OSS - Transmission Studies, Operations, OASIS Support Alloc-Fixed 2,318,249 1,854,599 115,912 347,737 57 18381 OSS - Transmission Outage Appl - Short Term Alloc-Fixed 1,114,557 891,646 55,728 167,184 58 18382 OSS - Trans Out Ap Lg Term Alloc-Fixed 1,114,557 - - 1,114,557 59 Total 6,052,369 3,233,480 891,162 1,927,728 60 61 System Operations Support 62 14752 SOS - National Committee Support Alloc-Fixed 6,280 2,033 3,002 1,245 63 14757 Winter 2014/15 Reliability Project Alloc-Fixed 330,587 - 66,117 264,470 64 336,867 2,033 69,120 265,714 65 66 415 Market Operations - Adm 67 19101 MO - NEPOOL Committee Support MOA Labor 19,948 - 13,964 5,985 68 19103 MO - National Committee Support MOA Labor 14,071 - 9,850 4,221 69 19104 MO - Indirect Supervision/Clerical Support MOA Labor 1,178,014 - 824,610 353,404 70 19105 Employee Development MOA Labor 6,370 - 4,459 1,911 71 19112 Settlements - Customer Service MOA Labor 4,145 - 2,901 1,243 72 19120 CEII Requests Total Dir Labor 6,370 1,373 3,297 1,701 73 Total 1,228,918 1,373 859,080 368,465
(1) From Exhibit 3 (RCL-3), Schedule 5.0. (2) Provided by ISO-NE. ISO NEW ENGLAND INC. Exhibit 3 (RCL-3) FERC DOCKET NO. ER15-___-000 Schedule 3.0 TOTAL COST ALLOCATIONS TO SCHEDULES BY COST CATEGORY Page 4 of 7 TEST YEAR 2015
Line Activity Code Allocation Self-Funding Tariff No. No. Description Factor (1) Total (2) Schedule 1 Schedule 2 Schedule 3 (a) (b) (c) (d) (e) (f) (g)
1 404 Market Monitoring 2 16101 Market Power Monitoring and Mitigation Alloc-Fixed 3,292,039 - 2,304,427 987,612 3 16102 Regulatory Activities Alloc-Fixed 10,913 - 7,639 3,274 4 16111 Employee Development MMM Labor 7,312 - 5,118 2,194 5 16115 Analysis & Internal Reports MMM Labor 449,087 - 314,361 134,726 6 16121 FCM Market Monitoring Alloc-Fixed 10,521 - - 10,521 7 Total 3,769,871 - 2,631,545 1,138,326 8 9 416 Market Operations 10 21901 Day Ahead Market Administration Alloc-Fixed 553,998 - 553,998 - 11 21902 Real Time Price Verification Alloc-Fixed 443,198 - 443,198 - 12 21903 FTR/ARR Administration Alloc-Fixed 18,467 9,233 9,233 - 13 21904 MA - NEPOOL Committee Support MA Labor 39,903 - 38,643 1,260 14 21907 MA - Indirect Supervision/Clerical Support MA Labor 447,233 - 433,110 14,123 15 21908 Employee Development MA Labor 36,933 - 35,767 1,166 16 21909 Customer Support MA Labor 18,467 - 17,883 583 17 21913 MA-Data Collection/Report Writing Alloc-Fixed 295,465 - 295,465 - 18 21915 FTR/Auction Administration Alloc-Fixed 295,465 - 295,465 - 19 21916 Forward Reserve Market - Administration Alloc-Fixed 18,467 - - 18,467 20 21917 Real Time Price Finalization Alloc-Fixed 36,933 - 36,933 - 21 21951 FCM Annual Reconfiguration Auction Administration Alloc-Fixed 18,467 - - 18,467 22 21952 FCM Annual CSO Bilaterals Administration Alloc-Fixed 18,467 - - 18,467 23 21953 FCM Monthly Administration Alloc-Fixed 295,465 - - 295,465 24 Total 2,536,928 9,233 2,159,697 367,998 25 26 401 Market Anaylsis & Settlements 27 1701 Billing Statements - Energy Alloc-Fixed 63,711 - 63,711 - 28 1702 Billing Statements - Transmission Alloc-Fixed 68,024 68,024 - - 29 1713 Billing Statements - ISO Tariff Total Dir Labor 14,816 3,193 7,667 3,956 30 2036 MAS - Market Analysis - Projects Alloc-Fixed 273 - 273 - 31 2037 MAS - Bill Job Aid Alloc-Fixed 819 123 491 205 32 2039 MAS - BITT and Business Tools Alloc-Fixed 4,492 674 2,695 1,123 33 2043 MAS - Release Checkout and Support Alloc-Fixed 35,322 5,298 21,193 8,830 34 2044 MAS - EQR Reporting Alloc-Fixed 537 81 322 134 35 2047 MAS - Score Card Alloc-Fixed 6,800 1,006 3,312 2,482 36 2048 MAS - FCM Alloc-Fixed 145,011 - - 145,011 37 2049 MAS - Product Testing Alloc-Fixed 7,420 - 5,936 1,484 38 2051 MAS - Legal Support Alloc-Fixed 8,585 - 4,293 4,293 39 2052 MAS - FERC Data Request Alloc-Fixed 10,536 - 5,268 5,268 40 2053 MAS - Tariff Change Coordination (TCC) Total Dir Labor 167,134 36,017 86,492 44,625 41 2054 MAS - Markets Development Support Alloc-Fixed 19,411 - 9,705 9,705 42 2005 Settlements - Customer Service STLM Labor 140,285 20,745 68,338 51,201 43 2007 Settlements - Admin support - NEPOOL Committees STLM Labor 29,557 4,371 14,398 10,788 44 2008 Settlements - Admin support (ISO) STLM Labor 128,263 18,968 62,482 46,814 45 2009 Settlements - Indirect Supervision/Clerical Support STLM Labor 826,643 122,244 402,689 301,710 46 2010 Settlements - Employee Development STLM Labor 22,889 3,385 11,150 8,354 47 2013 Settlements - FTR Administration Alloc-Fixed 17,517 - 17,517 - 48 2014 Billing Statements - NCPC Alloc-Fixed 160,100 - 80,050 80,050 49 2020 Settlements-Billing Disputes Total Dir Labor 3,400 733 1,760 908 50 2021 Settlements-Analysis & Reporting Total Dir Labor 276,617 59,605 143,152 73,859 51 2022 Settlements-Demand Response Alloc-Fixed 12,111 - - 12,111 52 2024 Settlements - ASM Regulation Alloc-Fixed 18,535 - - 18,535 53 2025 Settlements - ASM Locational Forward Reserve Alloc-Fixed 91,080 - - 91,080 54 2026 Settlements-Batch Processing Total Dir Labor 26,323 5,672 13,622 7,028 55 2032 Settlements - Billing STLM Labor 35,705 5,280 17,393 13,032 56 2033 Settlements - Market Analysis Alloc-Fixed 81,868 - 81,868 - 57 2034 Settlements - COPQ Alloc-Fixed 89,920 13,488 35,968 40,464 58 Total 2,513,702 368,906 1,161,745 983,050 59 60 Market Operations Support Services 61 3000 MOSS - Hourly Settlements Support Alloc-Fixed 122,522 - 61,261 61,261 62 3002 MOSS - Monthly Settlements Support Alloc-Fixed 93,874 46,937 - 46,937 63 3003 MOSS - Market Analysis Support Alloc-Fixed 1,524 - 1,524 - 64 3004 MOSS - Generation & Load Admin Support Alloc-Fixed 124,015 - 124,015 - 65 3005 MOSS - Demand Resource Admin Support Alloc-Fixed 133,542 - 133,542 - 66 3006 MOSS - Customer Service Alloc-Fixed 20,636 - 20,636 - 67 3007 MOSS - NEPOOL Committees Support Alloc-Fixed 10,017 - 5,009 5,009 68 3008 MOSS - Admin Support Alloc-Fixed 15,215 - 15,215 - 69 3009 MOSS - Indirect Supervision (Principal Analysts only) Alloc-Fixed 20,480 - 20,480 - 70 3010 MOSS - Employee Development Alloc-Fixed 44,643 - 44,643 - 71 3011 MOSS - Release Checkout and Support Alloc-Fixed 9,705 - 9,705 - 72 3012 MOSS - FERC Data Request Alloc-Fixed 6,114 - 6,114 - 73 3013 MOSS - Tariff Change Coordination (TCC) Total Dir Labor 2,602 561 1,346 695 74 3014 MOSS - Markets Development Support Alloc-Fixed 829 - 415 415 75 Total 605,717 47,498 443,903 114,316
(1) From Exhibit 3 (RCL-3), Schedule 5.0. (2) Provided by ISO-NE. ISO NEW ENGLAND INC. Exhibit 3 (RCL-3) FERC DOCKET NO. ER15-___-000 Schedule 3.0 TOTAL COST ALLOCATIONS TO SCHEDULES BY COST CATEGORY Page 5 of 7 TEST YEAR 2015
Line Activity Code Allocation Self-Funding Tariff No. No. Description Factor (1) Total (2) Schedule 1 Schedule 2 Schedule 3 (a) (b) (c) (d) (e) (f) (g)
1 406 Market Services 2 16001 Participant/membership support Alloc-Fixed 144,160 - 72,080 72,080 3 16006 Call Support (HEAT) Alloc-Fixed 933,663 242,752 616,218 74,693 4 16403 MSS NEPOOL Market Committee MS Labor 23,561 - 21,205 2,356 5 16419 Asset Registration Implemented Alloc-Fixed 184,666 - 184,666 - 6 16420 Asset Registration Reivew Alloc-Fixed 184,666 - 184,666 - 7 16421 C10/C30 Audits Alloc-Fixed 128,791 - 108,184 20,607 8 16422 Claimed Capability Audits Alloc-Fixed 36,933 - 36,933 - 9 16424 Demand Resource Audits Alloc-Fixed 295,465 - 295,465 - 10 16425 DR Registration Implemented Alloc-Fixed 36,933 - 36,933 - 11 16426 DR Registration Review Alloc-Fixed 36,933 - 36,933 - 12 16429 MSS Business Analysis - Process Improvement Alloc-Fixed 168,480 - 151,632 16,848 13 16432 New Generation Coordination and Registration Alloc-Fixed 18,467 - 18,467 - 14 16434 QMS/CAPA Process and Procedure Updates Total Dir Labor 184,666 39,796 95,565 49,306 15 16435 Resource Performance Monitoring Alloc-Fixed 36,933 - 36,933 - 16 Total 2,414,318 282,548 1,895,880 235,890 17 18 410 Market Training and Reliability Contracts 19 16021 Training Development Alloc-Fixed 849,890 - 424,945 424,945 20 16024 Training Delivery Alloc-Fixed 6,255 - 3,127 3,127 21 Total 856,145 - 428,072 428,072 22 23 203 Resource Adequacy 24 14315 PSR - Employee Development PSR Labor 92,570 10,059 4,672 77,839 25 17101 PSR Analysis Alloc-Fixed 739,574 - 517,702 221,872 26 17131 PSR - Calculate Objective Capability Alloc-Fixed 140,871 - - 140,871 27 17201 PSR Regulatory Liaison Alloc-Fixed 43,737 - 13,121 30,616 28 17231 PSR Regulatory Filings Alloc-Fixed 17,609 - - 17,609 29 17241 PSR-Transmission Plan Admin Support Alloc-Fixed 35,218 17,609 17,609 - 30 17251 PSR-Regional Bulk Power System Assessment Alloc-Fixed 246,525 123,262 123,262 - 31 17331 PSR NEPOOL Committee Support PSR Labor 91,696 9,964 4,627 77,105 32 17361 PSR Regional Committee Support PSR Labor 35,218 3,827 1,777 29,614 33 17401 PSR Indirect Supervisory Activities PSR Labor 105,834 11,500 5,341 88,994 34 17403 TCA Application Review Alloc-Fixed 67,724 - - 67,724 35 17404 Non-Transmission Alternative Analyses Alloc-Fixed 35,218 - 17,609 17,609 36 17405 Energy Efficiency Forecast Alloc-Fixed 35,218 - - 35,218 37 17406 SP - North American Energy Standards Board (NAESB) Alloc-Fixed 20,652 - 10,326 10,326 38 17407 SP - National Standards Work Alloc-Fixed 18,826 - 9,413 9,413 39 17408 MA-EEAC Total Dir Labor 19,435 4,188 10,057 5,189 40 17501 FCA - Evaluate Existing Resource De-list Bids Alloc-Fixed 146,110 - - 146,110 41 17502 FCA - Preliminary Review of Show of Interest Applications Alloc-Fixed 70,436 - - 70,436 42 17503 FCA - New Resource Qualification Support Alloc-Fixed 271,860 - - 271,860 43 17504 FCA - Perform Transmission / Topology Assessments Alloc-Fixed 52,827 - - 52,827 44 17505 FCA - Perform Existing Resource Qualification Alloc-Fixed 70,436 - - 70,436 45 17507 FCA - Auctions & Filings Alloc-Fixed 868,274 - - 868,274 46 17508 FCA - Annual Reconfiguration Auction Support/Reliability Reviews Alloc-Fixed 88,045 - - 88,045 47 18101 LF - Develop Load Forecast Alloc-Fixed 305,098 61,020 61,020 183,059 48 18121 SP - Operations Forecast Support Alloc-Fixed 88,045 17,609 17,609 52,827 49 18131 LF - Other Load Forecasting Activities Alloc-Fixed 35,218 7,044 7,044 21,131 50 Total 3,742,271 266,081 821,189 2,655,002 51 52 204 System Planning 53 18148 SP - NEPOOL Committee Support Alloc-Fixed 43,851 - 43,851 - 54 18150 SP - Regional Transmission Expansion Plan Alloc-Fixed 585,693 439,270 146,423 - 55 18152 States Requests Alloc-Fixed 240,265 120,132 60,066 60,066 56 18401 SP - Regional Activities Alloc-Fixed 278,199 278,199 - - 57 18501 SP - Regulatory Activities Alloc-Fixed 4,456 4,456 - - 58 18521 SP - Employee Development SP Labor 28,471 7,068 5,048 16,355 59 18531 SP - Indirect Supervision/Clerical Support SP Labor 186,230 46,234 33,016 106,980 60 18562 SP - Project Management Alloc-Fixed 70,436 70,436 - - 61 Total 1,437,600 965,795 288,405 183,401 62 63 205 Transmission Planning 64 11201 System Design Task Force Alloc-Fixed 26,945 26,945 - - 65 18201 TR - Transmission System Assessment Alloc-Fixed 3,191,325 3,191,325 - - 66 18261 TR - Transmission Tariff Information Requirements Alloc-Fixed 13,487 13,487 - - 67 18301 TR - NEPOOL Administrative Support - Schedule 1 Tariff Alloc-Fixed 104,379 104,379 - - 68 18333 TR - General SIS/FS Alloc-Fixed 980,048 980,048 - - 69 18334 TR - Indirect Supervision/Clerical Support TP Labor 604,639 604,639 - - 70 18335 TR - Regulatory Activities - NPCC TP Labor 154,233 154,233 - - 71 18336 TR - National Activities TP Labor 50,679 50,679 - - 72 18337 TR - Regulatory Activities TP Labor 134,204 134,204 - - 73 18338 TR - Employee Development TP Labor 87,057 87,057 - - 74 18341 TR – NERC Compliance TP Labor 35,668 35,668 - - 75 18343 FERC Order 1000 Alloc-Fixed 959,012 - - 959,012 76 Total 6,341,678 5,382,665 - 959,012
(1) From Exhibit 3 (RCL-3), Schedule 5.0. (2) Provided by ISO-NE. ISO NEW ENGLAND INC. Exhibit 3 (RCL-3) FERC DOCKET NO. ER15-___-000 Schedule 3.0 TOTAL COST ALLOCATIONS TO SCHEDULES BY COST CATEGORY Page 6 of 7 TEST YEAR 2015
Line Activity Code Allocation Self-Funding Tariff No. No. Description Factor (1) Total (2) Schedule 1 Schedule 2 Schedule 3 (a) (b) (c) (d) (e) (f) (g)
1 304 Program Management 2 801 Program Management - Administration Total Dir Labor 510,402 109,982 264,139 136,282 3 1661 ISO Program Management Alloc-Fixed 337,731 - 236,411 101,319 4 25002 PMO Support Alloc-Fixed 55,929 16,779 19,575 19,575 5 25822 System Restoration and Blackstart Resource Resource Mgmnt Alloc-Fixed 50,400 50,400 - - 6 25902 Coordinated Transaction Scheduling - O&M Alloc-Fixed 456,856 319,799 137,057 - 7 25912 Generation Auditing - Claim 10/30 Alloc-Fixed 9,883 - - 9,883 8 25914 Divisional Accounting (for Market Participants) Total Dir Labor 58,143 12,529 30,090 15,525 9 25919 Alternative Technologies & Regulation Market Alloc-Fixed 171,828 - - 171,828 10 25926 Hourly Market Alloc-Fixed 748,903 299,561 224,671 224,671 11 25948 FCA 9 Alloc-Fixed 35,218 - - 35,218 12 25953 ICCP and ED Network Upgrades Alloc-Fixed 75,639 68,075 - 7,564 13 25955 Financial Assurance BI Integration Alloc-Fixed 21,304 - 10,652 10,652 14 Total 2,532,237 877,125 922,595 732,517 15 16 315 Business Architecture and Technology 17 21201 Business Architecture and Technology Total Dir Labor 2,261,344 487,275 1,170,270 603,799 18 21203 BAT - Employee Development Total Dir Labor 12,648 2,725 6,546 3,377 19 Total 2,273,992 490,000 1,176,816 607,176 20 21 408 Market Development Administration 22 21001 Markets Development Total Dir Labor 2,954,384 636,611 1,528,926 788,846 23 21002 MD - Indirect Supervision/Clerical Support Total Dir Labor 75,854 16,345 39,255 20,254 24 21003 MD - Employee Development Total Dir Labor 125,240 26,987 64,813 33,440 25 21005 MD - ICAP Total Dir Labor 296,027 63,788 153,197 79,042 26 21007 MD - Budget/Forecast Support Total Dir Labor 18,734 4,037 9,695 5,002 27 21009 Increased Scope of Impact Analysis Alloc-Fixed 150,000 39,000 99,000 12,000 28 16607 National Committee Support MD Labor 208,214 1,248 111,081 95,885 29 Total 3,828,452 788,015 2,005,968 1,034,469 30 31 407 Market Design 32 22601 MDes-Direct Supervision&Clerical Total Dir Labor 47,069 10,143 24,359 12,568 33 22602 MDes-Committee Meetings Total Dir Labor 288,938 62,260 149,529 77,149 34 22603 MDes-Employee Development Total Dir Labor 5,352 1,153 2,770 1,429 35 22606 MDes-Market Analysis/Governing Documents Total Dir Labor 281,321 60,619 145,587 75,115 36 22607 MDes - NEPOOL Markets Committee Administration Alloc-Fixed 279,920 27,992 125,964 125,964 37 Total 902,601 162,167 448,208 292,225 38 39 409 Demand Resource Strategy 40 22401 Demand Response Total Dir Labor 96,332 20,758 49,853 25,721 41 22402 DR-Regulatory Ccmmittees and Working Groups Total Dir Labor 43,931 9,466 22,735 11,730 42 22404 RFP Linkages Total Dir Labor 327,198 70,505 169,328 87,365 43 22409 DR - Winter Supplemental Program Total Dir Labor 579 125 300 155 44 Total 468,040 100,853 242,216 124,971 45 46 210 IT Management 47 6517 Employee Development - Hardware/Software Total Dir Labor 48,101 10,365 24,893 12,843 48 6519 Indirect Supervision and Clerical Support Total Dir Labor 2,602,208 560,724 1,346,671 694,812 49 6552 IT - Security Total Dir Labor 648,132 139,660 335,416 173,057 50 6556 IT - Budget Preparation, Tracking & Forecast Total Dir Labor 174,075 37,510 90,086 46,480 51 6557 IT - Information Technology Committee Total Dir Labor 22,187 4,781 11,482 5,924 52 22501 IT CM/QA - Change Management Support Alloc-Fixed 89,168 40,126 40,126 8,917 53 22505 IT CM/QA - Administrative Alloc-Fixed 345,553 117,488 114,032 114,032 54 Total 3,929,424 910,653 1,962,706 1,056,066 55 56 201 IT System/Network & Desktop 57 6510 Desktop Support - Hardware Total Dir Labor 452,893 97,589 234,377 120,926 58 6511 Desktop Support - Software Total Dir Labor 616,621 132,870 319,108 164,643 59 6512 Host Computer - Hardware Alloc-Fixed 824,921 - 618,691 206,230 60 6513 Host Computer - Software Alloc-Fixed 1,596,370 - 1,197,277 399,092 61 6514 Networking - Hardware Total Dir Labor 359,607 77,488 186,101 96,018 62 6516 Communications Total Dir Labor 1,511,307 325,657 782,118 403,532 63 6550 IT - Data Communications Support Total Dir Labor 190,349 41,017 98,508 50,825 64 6602 Help Desk Support Total Dir Labor 349,611 75,334 180,927 93,349 65 6615 IT - Host Computer Monitoring Alloc-Fixed 1,174,719 - 587,359 587,359 66 6616 IT - Desktop Support Total Dir Labor 528,569 113,896 273,540 141,132 67 6617 IT - System Administration - Unix Total Dir Labor 675,155 145,483 349,400 180,272 68 6618 IT - System Administration - Windows Total Dir Labor 877,775 189,143 454,258 234,374 69 6619 IT - Systems Support Misc Total Dir Labor 103,248 22,248 53,432 27,568 70 6620 IT - Systems Support - Security Total Dir Labor 241,436 52,025 124,946 64,466 71 6621 IT - Network Support Total Dir Labor 377,835 81,416 195,534 100,885 72 6622 IT - Network/Systems Compliance 2009 Initiative Total Dir Labor 6,637 1,430 3,435 1,772 73 6623 IT - Asset Management Total Dir Labor 549,043 118,308 284,136 146,599 74 Total 10,436,097 1,473,904 5,943,148 3,019,046
(1) From Exhibit 3 (RCL-3), Schedule 5.0. (2) Provided by ISO-NE. ISO NEW ENGLAND INC. Exhibit 3 (RCL-3) FERC DOCKET NO. ER15-___-000 Schedule 3.0 TOTAL COST ALLOCATIONS TO SCHEDULES BY COST CATEGORY Page 7 of 7 TEST YEAR 2015
Line Activity Code Allocation Self-Funding Tariff No. No. Description Factor (1) Total (2) Schedule 1 Schedule 2 Schedule 3 (a) (b) (c) (d) (e) (f) (g)
1 212 IT Cyber Security 2 6539 IT Policy/Procedures Program Total Dir Labor 59,480 12,817 30,782 15,882 3 6540 IT Security Compliance and Reporting Total Dir Labor 1,284,381 276,759 664,681 342,941 4 6540A IT Controls Assessment Total Dir Labor 32,238 6,947 16,683 8,608 5 6540B IT Virus/Malware Reporting and Response Total Dir Labor 10,746 2,316 5,561 2,869 6 6540D IT Intrusion Monitoring and Response Total Dir Labor 118,205 25,471 61,172 31,562 7 6540E IT System Compliance Enhancement Total Dir Labor 96,713 20,840 50,050 25,823 8 6541 IT Security SW Tools Program Total Dir Labor 148,352 31,967 76,774 39,611 9 6543 Critical Infrastructure Protection WG (NERC) Total Dir Labor 33,930 7,311 17,559 9,060 10 6544 Infragrad (FBI) Total Dir Labor 98,010 21,119 50,721 26,170 11 6546 IT Internal Audit Support Total Dir Labor 23,184 4,996 11,998 6,190 12 6547 IT - Security Training Total Dir Labor 1,488 321 770 397 13 6548 CIP Compliance & Monitoring Total Dir Labor 134,999 29,090 69,864 36,046 14 Total 2,041,727 439,952 1,056,616 545,159 15 16 211 IT Enterprise Applications Support 17 6571 DBA Support - MOPS Total Dir Labor 1,741,165 375,187 901,072 464,906 18 6591 Data Architect - MOPS Total Dir Labor 255,323 55,017 132,133 68,174 19 6594 IT Data Analyst Total Dir Labor 344,381 74,207 178,221 91,953 20 6595 IT WEB Application Support Total Dir Labor 414,337 89,281 214,424 110,632 21 6596 IT Data Governance Total Dir Labor 172,190 37,104 89,110 45,976 22 21706 IT Markets Software Development - Enterprise Total Dir Labor 368,980 79,508 190,951 98,521 23 21801 IT Markets Software Support - Settlements Alloc-Fixed 649,981 - 519,985 129,996 24 21802 IT Markets Software Support - Publishing Alloc-Fixed 258,961 - 207,168 51,792 25 21803 IT Markets Software Support - Finance Alloc-Fixed 547,544 - 438,035 109,509 26 21804 IT Markets Software Support - Mitigation Alloc-Fixed 239,986 - 191,989 47,997 27 21805 IT Markets Software Support - TSO Total Dir Labor 341,464 73,579 176,711 91,174 28 21806 IT Markets Software Support - Enterprise Total Dir Labor 1,416,807 305,294 733,213 378,300 29 21807 IT Markets Software Support - Planning Alloc-Fixed 290,013 - 232,010 58,003 30 21808 IT CM/QA - Training Delivery to NON-IT Alloc-Fixed 294,605 - 235,684 58,921 31 21809 IT CM/QA - Tools Alloc-Fixed 40,549 - 32,439 8,110 32 21811 FSIT - Single Sign On Support Alloc-Fixed 229,931 - 183,945 45,986 33 21818 Discoverer Support Total Dir Labor 189,522 40,838 98,080 50,604 34 21819 Ceridian Support Total Dir Labor 51,792 11,160 26,803 13,829 35 21821 Compliance Management Total Dir Labor 118,237 25,478 61,189 31,570 36 Total 7,965,768 1,166,653 4,843,163 1,955,952 37 38 102 IT Energy Management Systems 39 21600 EMS - Indirect Supervision and Administration Total Dir Labor 495,352 106,739 256,350 132,263 40 21601 EMS - Power System Modeling Total Dir Labor 68,201 14,696 35,295 18,210 41 21603 EMS - Applications Support Total Dir Labor 1,171,472 252,429 606,250 312,793 42 21604 EMS/DTS Support Alloc-Fixed 1,236,045 988,836 247,209 - 43 21605 EMS - DAM Support Alloc-Fixed 749,238 149,848 449,543 149,848 44 21606 EMS - Real-time Market Support Alloc-Fixed 2,075,786 415,157 1,245,472 415,157 45 21607 EMS - Forecast Support Alloc-Fixed 111,339 22,268 66,803 22,268 46 Total 5,907,432 1,949,972 2,906,921 1,050,539 47 48 213 IT Enterprise Applications Development 49 21707 Application Analysis and Conceptual Design Alloc-Fixed 919,376 - 735,501 183,875 50 21710 ESD - Indirect Supervision and Administration Alloc-Fixed 651,207 - 520,965 130,241 51 21711 EWR and CAPA Analysis Alloc-Fixed 147,757 - 118,206 29,551 52 Total 1,718,340 - 1,374,672 343,668 53 54 216 IT Power System Modeling Management 55 21650 PSMM- Indirect Supervision and Administration Total Dir Labor 121,999 26,291 63,135 32,574 56 21651 PSMM- Power System Modeling Alloc-Fixed 768,214 307,285 307,285 153,643 57 21652 PSMM- System Application Support Alloc-Fixed 176,500 70,600 70,600 35,300 58 21654 PSMM- NX9 Administration Alloc-Fixed 276,854 110,742 110,742 55,371 59 21655 PSMM- ICCP Support Alloc-Fixed 670,873 268,349 268,349 134,175 60 21656 PSMM- Transmission Project Management Alloc-Fixed 23,152 18,521 4,630 - 61 21657 PSMM- Model On Demand Admin Alloc-Fixed 342,861 - - 342,861 62 21658 PSMM- Model on Demand Case Requests Alloc-Fixed 64,532 - - 64,532 63 Total 2,444,985 801,788 824,741 818,455 64 65 66 Total ISO $ 178,314,912 $ 42,327,088 $ 81,019,153 $ 54,968,671
(1) From Exhibit 3 (RCL-3), Schedule 5.0. (2) Provided by ISO-NE. Exhibit 3 (RCL-3) Schedule 4.0 Page 1 of 9
ISO NEW ENGLAND INC. FERC DOCKET NO. ER15-___-000 DIRECT LABOR COST ALLOCATIONS TO SCHEDULES BY COST CATEGORY TEST YEAR 2015
Line Activity Code Allocation Self-Funding Tariff No. No. Description Factor (1) Total (2) Schedule 1 Schedule 2 Schedule 3 (a) (b) (c) (d) (e) (f) (g)
1 307 Administration-CEO 2 12651 Adm/Finance/HR - Indirect Administrative Support Total Dir Labor $ 3,007,866 $ 648,136 $ 1,556,604 $ 803,127 3 Total 3,007,866 648,136 1,556,604 803,127 4 5 302 Finance 6 11601 Payroll Administration Total Dir Labor 234,607 50,553 121,412 62,642 7 11701 Accounts Payable Total Dir Labor 207,225 44,653 107,241 55,331 8 11702 Procurement Total Dir Labor 498,029 107,315 257,735 132,978 9 11901 Billing for Transmission and Energy Settlements Total Dir Labor 70,756 15,247 36,617 18,893 10 12001 Budgeting and Forecasting Total Dir Labor 517,080 111,420 267,594 138,065 11 12005 Credit Admininstration Total Dir Labor 186,230 40,129 96,376 49,725 12 12015 BCC Construction Total Dir Labor 48,169 10,379 24,928 12,861 13 12017 Forward Capacity Market (FCM) Reforms Alloc-Fixed 140,871 - - 140,871 14 12101 Ledger Closing, Financial Statements and Tax Reporting Total Dir Labor 564,032 121,538 291,893 150,601 15 12201 Treasury and Cash Management Total Dir Labor 141,205 30,427 73,075 37,703 16 99998 Payroll & Other Accruals Total Dir Labor 8,811,695 1,898,746 4,560,149 2,352,800 17 Total 11,419,899 2,430,407 5,837,021 3,152,471 18 19 108 Building Services 20 12664 Building Maintenance Total Dir Labor 519,279 111,894 268,733 138,652 21 Total 519,279 111,894 268,733 138,652 22 23 310 Enterprise Risk Management 24 22701 ERM -Enterprise Risk Mgmnt - Admn Alloc-Fixed 7,619 2,537 2,537 2,545 25 22703 ERM-Bus Cont Pl Prog Admin & Support Alloc-Fixed 152,374 50,741 50,741 50,893 26 22704 ERM - Record Retention Services Alloc-Fixed 22,856 7,611 7,611 7,634 27 22705 ERM - Corporate Scorecard Alloc-Fixed 7,619 2,537 2,537 2,545 28 22706 ERM - Document Management Services Alloc-Fixed 99,043 39,617 29,713 29,713 29 22708 ERM Adminstration Total Dir Labor 7,619 1,642 3,943 2,034 30 22709 ERM Management Total Dir Labor 76,187 16,417 39,428 20,343 31 22710 Employee Development Total Dir Labor 22,856 4,925 11,828 6,103 32 22711 FAP Admin - FCM Cap Adjustments Total Dir Labor 15,237 3,283 7,886 4,069 33 22712 FAP Admin - Risk Policy Assessments Total Dir Labor 76,187 16,417 39,428 20,343 34 22713 FAP Admin - MEC/Financials Total Dir Labor 33,522 7,223 17,348 8,951 35 22714 FAP Analysis Total Dir Labor 121,899 26,267 63,084 32,548 36 22716 FAM Rebuild Total Dir Labor 30,475 6,567 15,771 8,137 37 22718 CAPA 2.0 Total Dir Labor 137,137 29,550 70,970 36,617 38 22719 Human Performance Improvement Total Dir Labor 1,524 328 789 407 39 22720 Business Process Change Management Total Dir Labor 144,755 31,192 74,912 38,651 40 22721 Corp Strategic Risk Total Dir Labor 38,093 8,208 19,714 10,171 41 22722 Corp Strategic Plan Total Dir Labor 7,619 1,642 3,943 2,034 42 22725 OSHA procedures Total Dir Labor 7,619 1,642 3,943 2,034 43 22726 Project Risk Management Meeting Total Dir Labor 1,524 328 789 407 44 22727 ERM Business Analysis Total Dir Labor 83,806 18,058 43,370 22,377 45 23003 CP - Safety / Security / Facilities Total Dir Labor 22,856 4,925 11,828 6,103 46 23006 Business Continuity Planning Total Dir Labor 38,093 8,208 19,714 10,171 47 25006 ERM - Business Process Maintenance Alloc-Fixed 52,780 23,751 23,751 5,278 48 25011 Corrective Action/Preventive Action Alloc-Fixed 290,544 96,751 96,751 97,042 49 25012 OE - Business Process Re-Engineering Alloc-Fixed 1,524 507 507 509 50 25014 EtQ Tools Dev & Support Total Dir Labor 76,187 16,417 39,428 20,343 51 Total 1,577,553 427,292 702,262 447,999 52 53 301 Human Resources 54 12661 Employee Affairs (Recreation Committee) Total Dir Labor 9,311 2,006 4,818 2,486 55 12701 Recruiting/Interviewing Total Dir Labor 200,402 43,183 103,710 53,509 56 12901 Benefit Administration Total Dir Labor 275,553 59,376 142,602 73,575 57 12951 Compensation Total Dir Labor 225,453 48,581 116,674 60,198 58 12961 HR - General Total Dir Labor 1,052,112 226,709 544,480 280,923 59 12962 HR - Training Total Dir Labor 751,509 161,935 388,914 200,659 60 13410 Power Training & Development Total Dir Labor 701,976 151,262 363,280 187,434 61 13411 Markets Training & Development Total Dir Labor 291,607 62,836 150,910 77,862 62 13412 People Training & Development Total Dir Labor 125,507 27,044 64,951 33,511 63 13413 Business Skills Trng & Dev Total Dir Labor 99,301 21,397 51,389 26,514 64 13414 Technology Trng & Development Total Dir Labor 339,846 73,230 175,874 90,742 65 Total 4,072,577 877,560 2,107,604 1,087,414
(1) From Exhibit 3 (RCL-3), Schedule 5.0. (2) Provided by ISO-NE. Exhibit 3 (RCL-3) Schedule 4.0 Page 2 of 9
ISO NEW ENGLAND INC. FERC DOCKET NO. ER15-___-000 DIRECT LABOR COST ALLOCATIONS TO SCHEDULES BY COST CATEGORY TEST YEAR 2015
Line Activity Code Allocation Self-Funding Tariff No. No. Description Factor (1) Total (2) Schedule 1 Schedule 2 Schedule 3 (a) (b) (c) (d) (e) (f) (g)
1 306 Legal Department 2 8301 GC - Federal Regulatory Total Dir Labor 272,059 58,623 140,794 72,642 3 12502 Board of Directors Total Dir Labor 143,989 31,027 74,516 38,446 4 12504 ISO Tariff Litigation Total Dir Labor 57,276 12,342 29,641 15,293 5 12505 Administration of OATT Alloc-Fixed 214,784 214,784 - - 6 12508 Energy Markets/Compliants/Rule Changes Alloc-Fixed 85,913 - 85,913 - 7 12509 Market Monitoring and Sanctions Alloc-Fixed 100,232 - 50,116 50,116 8 12514 NEPOOL Participants Committee Total Dir Labor 57,276 12,342 29,641 15,293 9 12517 Administrative and Clerical Support Total Dir Labor 458,205 98,734 237,126 122,345 10 12520 Market Monitoring Rules/Regulations Alloc-Fixed 315,016 - 126,006 189,010 11 12523 NEPOOL Information Policy Total Dir Labor 42,957 9,256 22,231 11,470 12 12544 FERC Proceedings Total Dir Labor 186,146 40,111 96,332 49,703 13 12559 General Corporate Total Dir Labor 879,766 189,572 455,288 234,905 14 12587 Capacity Market Development Alloc-Fixed 472,524 - - 472,524 15 12588 Web Content Management Total Dir Labor 435,929 93,934 225,598 116,397 16 12663 Public Information Total Dir Labor 1,186,325 255,630 613,936 316,759 17 12669 Government Affairs Total Dir Labor 1,172,600 252,672 606,834 313,095 18 Total 6,080,995 1,269,026 2,793,972 2,017,997 19 20 305 Internal Audit 21 15001 Audit - Indirect Mgmnt Duties Total Dir Labor 67,958 14,644 35,169 18,145 22 15002 Audit- Personnel Management Total Dir Labor 17,112 3,687 8,856 4,569 23 15003 Audit- Budget & Forecasting Total Dir Labor 8,556 1,844 4,428 2,285 24 15004 Audit- Audit Followup Activities Total Dir Labor 8,556 1,844 4,428 2,285 25 15005 Audit - Audit & Finance Committee Total Dir Labor 85,071 18,331 44,025 22,715 26 15006 Audit- Internal Audit Business Process Update Total Dir Labor 8,556 1,844 4,428 2,285 27 15007 Audit- Annual Audit Work Plan Total Dir Labor 42,781 9,218 22,140 11,423 28 15008 Audit-Training Total Dir Labor 68,450 14,750 35,423 18,277 29 15020 Internal Audit - Finance Total Dir Labor 42,781 9,218 22,140 11,423 30 15021 Audit- Perfomance Measurements Total Dir Labor 25,669 5,531 13,284 6,854 31 15022 Audit- Vendor Contracts Total Dir Labor 12,834 2,766 6,642 3,427 32 15023 Audit- Wire Transfers Total Dir Labor 8,556 1,844 4,428 2,285 33 15065 Audit - Wind Integration Project Alloc-Fixed 42,781 17,112 17,112 8,556 34 15068 Audit - FCM Settlements Audit Alloc-Fixed 8,290 - - 8,290 35 15085 Audit - Information Technology Total Dir Labor 85,562 18,437 44,279 22,846 36 15040 Audit-Operations Total Dir Labor 171,124 36,874 88,559 45,692 37 15110 External Audit - Operations Total Dir Labor 42,781 9,218 22,140 11,423 38 15133 Audit- Satellite Reviews Total Dir Labor 42,781 9,218 22,140 11,423 39 15161 External Audit- Pension Audit Total Dir Labor 21,391 4,609 11,070 5,711 40 15186 Ext Audit - SSAE 16 Direct Support Total Dir Labor 34,225 7,375 17,712 9,138 41 25702 External Audit - SSAE 16 Alloc-Fixed 119,048 - 119,048 - 42 28160 Audit - MS Universal Access Gateway Review Total Dir Labor 42,290 9,113 21,885 11,292 43 Total 1,007,153 197,477 569,335 240,342 44 45 701 COO-Adm 46 19001 COO - NEPOOL Committee Support Total OPS Labor 56,288 15,086 26,992 14,210 47 19002 COO - Regional Committee Support Total OPS Labor 56,288 15,086 26,992 14,210 48 19003 COO - National Committee Support Total OPS Labor 56,288 15,086 26,992 14,210 49 19005 COO - Indirect Supervision/Clerical Support Total OPS Labor 1,125,769 301,723 539,845 284,201 50 Total 1,294,634 346,981 620,822 326,831 51 52 702 Reliability and Operations Services 53 14703 TPC - NEPOOL Committee Support OS Labor 330,858 183,782 63,963 83,114 54 14704 TPC - Regional Committee Support OS Labor 10,041 5,578 1,941 2,522 55 14706 TPC - Indirect Supervision/Clerical Support OS Labor 26,081 14,487 5,042 6,552 56 14711 ISO TMS Tariff-Section 2 - (OATT) and Agreements Support Alloc-Fixed 212,871 70,886 70,886 71,099 57 14715 EIPC - Non DOE Funded/Unallowable Alloc-Fixed 123,462 - - 123,462 58 Total 703,313 274,732 141,832 286,749 59 60 703 Reliability and Operations Compliance 61 14801 ROC - Compliance Monitoring Alloc-Fixed 675,270 270,108 270,108 135,054 62 14804 ROC - National Committee Support OS Labor 148,990 74,495 - 74,495 63 14806 ROC - Employee Development Alloc-Fixed 19,263 10,700 3,724 4,839 64 14807 ROC - Compliance Audit OS Labor 240,786 120,393 - 120,393 65 14808 ROC - Change Management Alloc-Fixed 28,894 13,002 2,889 13,002 66 14809 ROC - Tariff Compliance Alloc-Fixed 48,157 14,447 28,894 4,816 67 14810 ROC - NERC Self Certifications Alloc-Fixed 20,855 17,726 - 3,128 68 14813 ROC - ICP Policy/Procedure Alloc-Fixed 77,052 30,821 30,821 15,410 69 Total 1,259,266 551,692 336,436 371,137
(1) From Exhibit 3 (RCL-3), Schedule 5.0. (2) Provided by ISO-NE. Exhibit 3 (RCL-3) Schedule 4.0 Page 3 of 9
ISO NEW ENGLAND INC. FERC DOCKET NO. ER15-___-000 DIRECT LABOR COST ALLOCATIONS TO SCHEDULES BY COST CATEGORY TEST YEAR 2015
Line Activity Code Allocation Self-Funding Tariff No. No. Description Factor (1) Total (2) Schedule 1 Schedule 2 Schedule 3 (a) (b) (c) (d) (e) (f) (g)
1 105 System Operations - Administration 2 14405 System Ops Mgt & Adm - Indirect Supervision/Clerical Support SOA Labor 219,249 75,729 101,775 41,745 3 Total 219,249 75,729 101,775 41,745 4 5 101 Operations 6 14001 Ops - Generation Dispatch Alloc-Fixed 3,727,871 - 3,131,411 596,459 7 14002 Ops - Transmission Operations Alloc-Fixed 2,351,539 1,881,231 117,577 352,731 8 14304 Ops - Advanced Scheduling and Forecasting Alloc-Fixed 1,761,555 88,078 1,391,628 281,849 9 14402 Ops - Operations Training Alloc-Fixed 2,030,730 812,292 812,292 406,146 10 14564 Ops - Indirect Supervision/Clerical Support OPS Labor 1,417,869 396,388 784,985 236,496 11 14702 TPC - Procedure Documentation Alloc-Fixed 354,675 141,870 141,870 70,935 12 Total 11,644,238 3,319,859 6,379,764 1,944,616 13 14 103 Operations Support Services 15 14453 TSO - National Committee Support TSO Labor 109,624 35,490 52,410 21,724 16 14454 TSO - Indirect Supervision/Clerical Support TSO Labor 482,373 156,165 230,615 95,593 17 14462 OSS - General Systems Operations Support TSO Labor 842,684 272,813 402,875 166,996 18 18361 OSS - Transmission Studies, Operations, OASIS Support Alloc-Fixed 2,324,239 1,859,391 116,212 348,636 19 18381 OSS - Transmission Outage Appl - Short Term Alloc-Fixed 1,052,495 841,996 52,625 157,874 20 18382 OSS - Trans Out Ap Lg Term Alloc-Fixed 1,052,495 - - 1,052,495 21 Total 5,863,910 3,165,855 854,737 1,843,319 22 23 System Operations Support 24 14757 Winter 2014/15 Reliability Project Alloc-Fixed 328,667 - 65,733 262,934 25 Total 328,667 - 65,733 262,934 26 27 415 Market Operations - Adm 28 19101 MO - NEPOOL Committee Support MOA Labor 12,740 - 8,918 3,822 29 19104 MO - Indirect Supervision/Clerical Support MOA Labor 1,172,112 - 820,478 351,633 30 19105 Employee Development MOA Labor 6,370 - 4,459 1,911 31 19120 CEII Requests Total Dir Labor 6,370 1,373 3,297 1,701 32 Total 1,197,592 1,373 837,152 359,067 33 34 404 Market Monitoring 35 16101 Market Power Monitoring and Mitigation Alloc-Fixed 2,809,083 - 1,966,358 842,725 36 16111 Employee Development MMM Labor 7,312 - 5,118 2,194 37 16115 Analysis & Internal Reports MMM Labor 446,171 - 312,320 133,851 38 16121 FCM Market Monitoring Alloc-Fixed 1,187 - - 1,187 39 Total 3,263,753 - 2,283,796 979,957 40 41 416 Market Operations 42 21901 Day Ahead Market Administration Alloc-Fixed 553,998 - 553,998 - 43 21902 Real Time Price Verification Alloc-Fixed 443,198 - 443,198 - 44 21903 FTR/ARR Administration Alloc-Fixed 18,467 9,233 9,233 - 45 21904 MA - NEPOOL Committee Support MA Labor 36,933 - 35,767 1,166 46 21907 MA - Indirect Supervision/Clerical Support MA Labor 443,198 - 429,202 13,996 47 21908 Employee Development MA Labor 36,933 - 35,767 1,166 48 21909 Customer Support MA Labor 18,467 - 17,883 583 49 21913 MA-Data Collection/Report Writing Alloc-Fixed 295,465 - 295,465 - 50 21915 FTR/Auction Administration Alloc-Fixed 295,465 - 295,465 - 51 21916 Forward Reserve Market - Administration Alloc-Fixed 18,467 - - 18,467 52 21917 Real Time Price Finalization Alloc-Fixed 36,933 - 36,933 - 53 21951 FCM Annual Reconfiguration Auction Administration Alloc-Fixed 18,467 - - 18,467 54 21952 FCM Annual CSO Bilaterals Administration Alloc-Fixed 18,467 - - 18,467 55 21953 FCM Monthly Administration Alloc-Fixed 295,465 - - 295,465 56 Total 2,529,923 9,233 2,152,913 367,777
(1) From Exhibit 3 (RCL-3), Schedule 5.0. (2) Provided by ISO-NE. Exhibit 3 (RCL-3) Schedule 4.0 Page 4 of 9
ISO NEW ENGLAND INC. FERC DOCKET NO. ER15-___-000 DIRECT LABOR COST ALLOCATIONS TO SCHEDULES BY COST CATEGORY TEST YEAR 2015
Line Activity Code Allocation Self-Funding Tariff No. No. Description Factor (1) Total (2) Schedule 1 Schedule 2 Schedule 3 (a) (b) (c) (d) (e) (f) (g)
1 401 Market Anaylsis & Settlements 2 1701 Billing Statements - Energy Alloc-Fixed 63,711 - 63,711 - 3 1702 Billing Statements - Transmission Alloc-Fixed 68,024 68,024 - - 4 1713 Billing Statements - ISO Tariff Total Dir Labor 14,816 3,193 7,667 3,956 5 2005 Settlements - Customer Service STLM Labor 140,285 20,745 68,338 51,201 6 2007 Settlements - Admin support - NEPOOL Committees STLM Labor 29,557 4,371 14,398 10,788 7 2008 Settlements - Admin support (ISO) STLM Labor 127,766 18,894 62,240 46,632 8 2009 Settlements - Indirect Supervision/Clerical Support STLM Labor 826,643 122,244 402,689 301,710 9 2010 Settlements - Employee Development STLM Labor 22,889 3,385 11,150 8,354 10 2013 Settlements - FTR Administration Alloc-Fixed 17,517 - 17,517 - 11 2014 Billing Statements - NCPC Alloc-Fixed 160,100 - 80,050 80,050 12 2020 Settlements-Billing Disputes Total Dir Labor 3,400 733 1,760 908 13 2021 Settlements-Analysis & Reporting Total Dir Labor 276,617 59,605 143,152 73,859 14 2022 Settlements-Demand Response Alloc-Fixed 12,111 - - 12,111 15 2024 Settlements - ASM Regulation Alloc-Fixed 18,535 - - 18,535 16 2025 Settlements - ASM Locational Forward Reserve Alloc-Fixed 91,080 - - 91,080 17 2026 Settlements-Batch Processing Total Dir Labor 26,323 5,672 13,622 7,028 18 2032 Settlements - Billing STLM Labor 35,705 5,280 17,393 13,032 19 2033 Settlements - Market Analysis Alloc-Fixed 81,868 - 81,868 - 20 2034 Settlements - COPQ Alloc-Fixed 89,920 13,488 35,968 40,464 21 2036 MAS - Market Analysis - Projects Alloc-Fixed 273 - 273 - 22 2037 MAS - Bill Job Aid Alloc-Fixed 819 123 491 205 23 2039 MAS - BITT and Business Tools Alloc-Fixed 4,492 674 2,695 1,123 24 2043 MAS - Release Checkout and Support Alloc-Fixed 35,322 5,298 21,193 8,830 25 2044 MAS - EQR Reporting Alloc-Fixed 537 81 322 134 26 2047 MAS - Score Card Alloc-Fixed 6,800 1,006 3,312 2,482 27 2048 MAS - FCM Alloc-Fixed 145,011 - - 145,011 28 2049 MAS - Product Testing Alloc-Fixed 7,420 - 5,936 1,484 29 2051 MAS - Legal Support Alloc-Fixed 8,585 - 4,293 4,293 30 2052 MAS - FERC Data Request Alloc-Fixed 10,536 - 5,268 5,268 31 2053 MAS - Tariff Change Coordination (TCC) Total Dir Labor 167,134 36,017 86,492 44,625 32 2054 MAS - Markets Development Support Alloc-Fixed 19,411 - 9,705 9,705 33 Total 2,513,205 368,832 1,161,503 982,869 34 35 Market Operations Support Services 36 3000 MOSS - Hourly Settlements Support Alloc-Fixed 122,522 - 61,261 61,261 37 3002 MOSS - Monthly Settlements Support Alloc-Fixed 93,874 46,937 - 46,937 38 3003 MOSS - Market Analysis Support Alloc-Fixed 1,524 - 1,524 - 39 3004 MOSS - Generation & Load Admin Support Alloc-Fixed 124,015 - 124,015 - 40 3005 MOSS - Demand Resource Admin Support Alloc-Fixed 133,542 - 133,542 - 41 3006 MOSS - Customer Service Alloc-Fixed 20,636 - 20,636 - 42 3007 MOSS - NEPOOL Committees Support Alloc-Fixed 10,017 - 5,009 5,009 43 3008 MOSS - Admin Support Alloc-Fixed 15,215 - 15,215 - 44 3009 MOSS - Indirect Supervision (Principal Analysts only) Alloc-Fixed 20,480 - 20,480 - 45 3010 MOSS - Employee Development Alloc-Fixed 44,643 - 44,643 - 46 3011 MOSS - Release Checkout and Support Alloc-Fixed 9,705 - 9,705 - 47 3012 MOSS - FERC Data Request Alloc-Fixed 6,114 - 6,114 - 48 3013 MOSS - Tariff Change Coordination (TCC) Total Dir Labor 2,602 561 1,346 695 49 3014 MOSS - Markets Development Support Alloc-Fixed 829 - 415 415 50 Total 605,717 47,498 443,903 114,316 51 52 406 Market Services 53 16001 Participant/membership support Alloc-Fixed 72,133 - 36,067 36,067 54 16006 Call Support (HEAT) Alloc-Fixed 901,663 234,432 595,098 72,133 55 16403 MSS NEPOOL Market Committee MS Labor 18,033 - 16,230 1,803 56 16419 Asset Registration Implemented Alloc-Fixed 184,666 - 184,666 - 57 16420 Asset Registration Reivew Alloc-Fixed 184,666 - 184,666 - 58 16421 C10/C30 Audits Alloc-Fixed 128,791 - 108,184 20,607 59 16422 Claimed Capability Audits Alloc-Fixed 36,933 - 36,933 - 60 16424 Demand Resource Audits Alloc-Fixed 295,465 - 295,465 - 61 16425 DR Registration Implemented Alloc-Fixed 36,933 - 36,933 - 62 16426 DR Registration Review Alloc-Fixed 36,933 - 36,933 - 63 16432 New Generation Coordination and Registration Alloc-Fixed 18,467 - 18,467 - 64 16434 QMS/CAPA Process and Procedure Updates Total Dir Labor 184,666 39,796 95,565 49,306 65 16435 Resource Performance Monitoring Alloc-Fixed 36,933 - 36,933 - 66 Total 2,136,283 274,228 1,682,140 179,915 67 68 410 Market Training and Reliability Contracts 69 16021 Training Development Alloc-Fixed 849,611 - 424,806 424,806 70 16024 Training Delivery Alloc-Fixed 6,255 - 3,127 3,127 71 Total 855,866 - 427,933 427,933
(1) From Exhibit 3 (RCL-3), Schedule 5.0. (2) Provided by ISO-NE. Exhibit 3 (RCL-3) Schedule 4.0 Page 5 of 9
ISO NEW ENGLAND INC. FERC DOCKET NO. ER15-___-000 DIRECT LABOR COST ALLOCATIONS TO SCHEDULES BY COST CATEGORY TEST YEAR 2015
Line Activity Code Allocation Self-Funding Tariff No. No. Description Factor (1) Total (2) Schedule 1 Schedule 2 Schedule 3 (a) (b) (c) (d) (e) (f) (g)
1 204 System Planning 2 18148 SP - NEPOOL Committee Support Alloc-Fixed 35,218 - 35,218 - 3 18150 SP - Regional Transmission Expansion Plan Alloc-Fixed 465,561 349,171 116,390 - 4 18152 States Requests Alloc-Fixed 108,894 54,447 27,223 27,223 5 18401 SP - Regional Activities Alloc-Fixed 278,199 278,199 - - 6 18521 SP - Employee Development SP Labor 26,303 6,530 4,663 15,110 7 18531 SP - Indirect Supervision/Clerical Support SP Labor 156,487 38,850 27,743 89,894 8 18562 SP - Project Management Alloc-Fixed 70,436 70,436 - - 9 Total 1,141,096 797,632 211,238 132,227 10 11 203 Resource Adequacy 12 14315 PSR - Employee Development PSR Labor 88,045 9,567 4,443 74,034 13 18101 LF - Develop Load Forecast Alloc-Fixed 158,480 31,696 31,696 95,088 14 18121 SP - Operations Forecast Support Alloc-Fixed 88,045 17,609 17,609 52,827 15 18131 LF - Other Load Forecasting Activities Alloc-Fixed 35,218 7,044 7,044 21,131 16 17101 PSR Analysis Alloc-Fixed 739,574 - 517,702 221,872 17 17131 PSR - Calculate Objective Capability Alloc-Fixed 140,871 - - 140,871 18 17201 PSR Regulatory Liaison Alloc-Fixed 35,218 - 10,565 24,652 19 17231 PSR Regulatory Filings Alloc-Fixed 17,609 - - 17,609 20 17241 PSR-Transmission Plan Admin Support Alloc-Fixed 35,218 17,609 17,609 - 21 17251 PSR-Regional Bulk Power System Assessment Alloc-Fixed 246,525 123,262 123,262 - 22 17331 PSR NEPOOL Committee Support PSR Labor 88,045 9,567 4,443 74,034 23 17361 PSR Regional Committee Support PSR Labor 35,218 3,827 1,777 29,614 24 17401 PSR Indirect Supervisory Activities PSR Labor 105,653 11,480 5,332 88,841 25 17403 TCA Application Review Alloc-Fixed 67,362 - - 67,362 26 17404 Non-Transmission Alternative Analyses Alloc-Fixed 35,218 - 17,609 17,609 27 17405 Energy Efficiency Forecast Alloc-Fixed 35,218 - - 35,218 28 17406 SP - North American Energy Standards Board (NAESB) Alloc-Fixed 17,609 - 8,804 8,804 29 17407 SP - National Standards Work Alloc-Fixed 17,609 - 8,804 8,804 30 17408 MA-EEAC Total Dir Labor 17,609 3,795 9,113 4,702 31 17501 FCA - Evaluate Existing Resource De-list Bids Alloc-Fixed 83,923 - - 83,923 32 17502 FCA - Preliminary Review of Show of Interest Applications Alloc-Fixed 70,436 - - 70,436 33 17503 FCA - New Resource Qualification Support Alloc-Fixed 246,525 - - 246,525 34 17504 FCA - Perform Transmission / Topology Assessments Alloc-Fixed 52,827 - - 52,827 35 17505 FCA - Perform Existing Resource Qualification Alloc-Fixed 70,436 - - 70,436 36 17507 FCA - Auctions & Filings Alloc-Fixed 438,061 - - 438,061 37 17508 FCA - Annual Reconfiguration Auction Support/Reliability Revie Alloc-Fixed 88,045 - - 88,045 38 Total 3,054,594 235,456 785,813 2,033,325 39 40 205 Transmission Planning 41 11201 System Design Task Force Alloc-Fixed 26,945 26,945 - - 42 18201 TR - Transmission System Assessment Alloc-Fixed 2,904,811 2,904,811 - - 43 18261 TR - Transmission Tariff Information Requirements Alloc-Fixed 13,487 13,487 - - 44 18301 TR - NEPOOL Administrative Support - Schedule 1 Tariff Alloc-Fixed 96,324 96,324 - - 45 18333 TR - General SIS/FS Alloc-Fixed 670,019 670,019 - - 46 18334 TR - Indirect Supervision/Clerical Support TP Labor 604,639 604,639 - - 47 18335 TR - Regulatory Activities - NPCC TP Labor 140,716 140,716 - - 48 18336 TR - National Activities TP Labor 46,305 46,305 - - 49 18337 TR - Regulatory Activities TP Labor 71,277 71,277 - - 50 18338 TR - Employee Development TP Labor 82,837 82,837 - - 51 18341 TR – NERC Compliance TP Labor 35,668 35,668 - - 52 18343 FERC Order 1000 Alloc-Fixed 469,006 - - 469,006 53 Total 5,162,034 4,693,029 - 469,006 54 55 304 Program Management 56 801 Program Management - Administration Total Dir Labor 471,664 101,634 244,091 125,938 57 1661 ISO Program Management Alloc-Fixed 337,731 - 236,411 101,319 58 25002 PMO Support Alloc-Fixed 55,929 16,779 19,575 19,575 59 25822 System Restoration and Blackstart Resource Resource Mgmnt Alloc-Fixed 50,400 50,400 - - 60 25902 Coordinated Transaction Scheduling - O&M Alloc-Fixed 456,856 319,799 137,057 - 61 25912 Generation Auditing - Claim 10/30 Alloc-Fixed 9,883 - - 9,883 62 25914 Divisional Accounting (for Market Participants) Total Dir Labor 58,143 12,529 30,090 15,525 63 25919 Alternative Technologies & Regulation Market Alloc-Fixed 171,828 - - 171,828 64 25926 Hourly Market Alloc-Fixed 647,103 258,841 194,131 194,131 65 25948 FCA 9 Alloc-Fixed 35,218 - - 35,218 66 25953 ICCP and ED Network Upgrades Alloc-Fixed 75,639 68,075 - 7,564 67 25955 Financial Assurance BI Integration Alloc-Fixed 21,304 - 10,652 10,652 68 Total 2,391,699 828,058 872,007 691,634 69 70 315 Business Architecture and Technology 71 21201 Business Architecture and Technology Total Dir Labor 2,028,147 437,026 1,049,588 541,533 72 Total 2,028,147 437,026 1,049,588 541,533 73 74 408 Market Development Administration 75 21001 Markets Development Total Dir Labor 2,828,509 609,488 1,463,785 755,237 76 21002 MD - Indirect Supervision/Clerical Support Total Dir Labor 75,854 16,345 39,255 20,254 77 21003 MD - Employee Development Total Dir Labor 114,846 24,747 59,434 30,665 78 21005 MD - ICAP Total Dir Labor 296,027 63,788 153,197 79,042 79 21007 MD - Budget/Forecast Support Total Dir Labor 18,734 4,037 9,695 5,002 80 16607 National Committee Support MD Labor 196,955 1,180 105,075 90,700 81 Total 3,530,924 719,585 1,830,440 980,899
(1) From Exhibit 3 (RCL-3), Schedule 5.0. (2) Provided by ISO-NE. Exhibit 3 (RCL-3) Schedule 4.0 Page 6 of 9
ISO NEW ENGLAND INC. FERC DOCKET NO. ER15-___-000 DIRECT LABOR COST ALLOCATIONS TO SCHEDULES BY COST CATEGORY TEST YEAR 2015
Line Activity Code Allocation Self-Funding Tariff No. No. Description Factor (1) Total (2) Schedule 1 Schedule 2 Schedule 3 (a) (b) (c) (d) (e) (f) (g)
1 407 Market Design 2 22601 MDes-Direct Supervision&Clerical Total Dir Labor 46,994 10,126 24,320 12,548 3 22602 MDes-Committee Meetings Total Dir Labor 268,406 57,836 138,903 71,667 4 22603 MDes-Employee Development Total Dir Labor 2,352 507 1,217 628 5 22606 MDes-Market Analysis/Governing Documents Total Dir Labor 281,321 60,619 145,587 75,115 6 22607 MDes - NEPOOL Markets Committee Administration Alloc-Fixed 278,878 27,888 125,495 125,495 7 Total 877,951 156,976 435,522 285,453 8 9 409 Demand Resource Strategy 10 22401 Demand Response Total Dir Labor 75,649 16,301 39,149 20,199 11 22402 DR-Regulatory Ccmmittees and Working Groups Total Dir Labor 43,931 9,466 22,735 11,730 12 22404 RFP Linkages Total Dir Labor 207,871 44,792 107,576 55,503 13 22409 DR - Winter Supplemental Program Total Dir Labor 579 125 300 155 14 Total 328,031 70,684 169,759 87,587 15 16 210 IT Management 17 6517 Employee Development - Hardware/Software Total Dir Labor 48,101 10,365 24,893 12,843 18 6519 Indirect Supervision and Clerical Support Total Dir Labor 2,504,878 539,752 1,296,302 668,824 19 6552 IT - Security Total Dir Labor 463,497 99,874 239,865 123,758 20 6556 IT - Budget Preparation, Tracking & Forecast Total Dir Labor 174,075 37,510 90,086 46,480 21 6557 IT - Information Technology Committee Total Dir Labor 12,439 2,680 6,437 3,321 22 22501 IT CM/QA - Change Management Support Alloc-Fixed 89,168 40,126 40,126 8,917 23 22505 IT CM/QA - Administrative Alloc-Fixed 345,553 117,488 114,032 114,032 24 Total 3,637,709 847,794 1,811,740 978,175 25 26 201 IT System/Network & Desktop 27 6550 IT - Data Communications Support Total Dir Labor 190,349 41,017 98,508 50,825 28 6602 Help Desk Support Total Dir Labor 349,611 75,334 180,927 93,349 29 6615 IT - Host Computer Monitoring Alloc-Fixed 1,174,719 - 587,359 587,359 30 6516 Communications Total Dir Labor 36,039 7,766 18,650 9,623 31 6616 IT - Desktop Support Total Dir Labor 528,569 113,896 273,540 141,132 32 6617 IT - System Administration - Unix Total Dir Labor 675,155 145,483 349,400 180,272 33 6618 IT - System Administration - Windows Total Dir Labor 877,775 189,143 454,258 234,374 34 6619 IT - Systems Support Misc Total Dir Labor 103,248 22,248 53,432 27,568 35 6620 IT - Systems Support - Security Total Dir Labor 241,436 52,025 124,946 64,466 36 6621 IT - Network Support Total Dir Labor 377,835 81,416 195,534 100,885 37 6622 IT - Network/Systems Compliance 2009 Initiative Total Dir Labor 6,637 1,430 3,435 1,772 38 6623 IT - Asset Management Total Dir Labor 395,720 85,270 204,789 105,661 39 Total 4,957,093 815,027 2,544,780 1,597,287 40 41 212 IT Cyber Security 42 6539 IT Policy/Procedures Program Total Dir Labor 33,930 7,311 17,559 9,060 43 6540 IT Security Compliance and Reporting Total Dir Labor 577,063 124,346 298,636 154,081 44 6540A IT Controls Assessment Total Dir Labor 32,238 6,947 16,683 8,608 45 6540B IT Virus/Malware Reporting and Response Total Dir Labor 10,746 2,316 5,561 2,869 46 6540D IT Intrusion Monitoring and Response Total Dir Labor 118,205 25,471 61,172 31,562 47 6540E IT System Compliance Enhancement Total Dir Labor 96,713 20,840 50,050 25,823 48 6541 IT Security SW Tools Program Total Dir Labor 64,475 13,893 33,367 17,215 49 6543 Critical Infrastructure Protection WG (NERC) Total Dir Labor 33,930 7,311 17,559 9,060 50 6544 Infragrad (FBI) Total Dir Labor 10,746 2,316 5,561 2,869 51 6546 IT Internal Audit Support Total Dir Labor 23,184 4,996 11,998 6,190 52 6548 CIP Compliance & Monitoring Total Dir Labor 134,999 29,090 69,864 36,046 53 1,136,230 244,835 588,011 303,383 54 211 IT Enterprise Applications Support 55 6571 DBA Support - MOPS Total Dir Labor 287,613 61,975 148,843 76,795 56 6591 Data Architect - MOPS Total Dir Labor 255,323 55,017 132,133 68,174 57 6594 IT Data Analyst Total Dir Labor 344,381 74,207 178,221 91,953 58 6595 IT WEB Application Support Total Dir Labor 414,337 89,281 214,424 110,632 59 6596 IT Data Governance Total Dir Labor 172,190 37,104 89,110 45,976 60 21806 IT Markets Software Support - Enterprise Total Dir Labor 653,263 140,765 338,071 174,427 61 21706 IT Markets Software Development - Enterprise Total Dir Labor 368,980 79,508 190,951 98,521 62 21801 IT Markets Software Support - Settlements Alloc-Fixed 411,797 - 329,438 82,359 63 21803 IT Markets Software Support - Finance Alloc-Fixed 181,272 - 145,018 36,254 64 21804 IT Markets Software Support - Mitigation Alloc-Fixed 239,986 - 191,989 47,997 65 21802 IT Markets Software Support - Publishing Alloc-Fixed 258,961 - 207,168 51,792 66 21811 FSIT - Single Sign On Support Alloc-Fixed 181,272 - 145,018 36,254 67 21819 Ceridian Support Total Dir Labor 51,792 11,160 26,803 13,829 68 21821 Compliance Management Total Dir Labor 77,688 16,740 40,204 20,743 69 Total 3,898,855 565,758 2,377,390 955,707
(1) From Exhibit 3 (RCL-3), Schedule 5.0. (2) Provided by ISO-NE. Exhibit 3 (RCL-3) Schedule 4.0 Page 7 of 9
ISO NEW ENGLAND INC. FERC DOCKET NO. ER15-___-000 DIRECT LABOR COST ALLOCATIONS TO SCHEDULES BY COST CATEGORY TEST YEAR 2015
Line Activity Code Allocation Self-Funding Tariff No. No. Description Factor (1) Total (2) Schedule 1 Schedule 2 Schedule 3 (a) (b) (c) (d) (e) (f) (g)
1 213 IT Enterprise Applications Development 2 21707 Application Analysis and Conceptual Design Alloc-Fixed 919,376 - 735,501 183,875 3 21710 ESD - Indirect Supervision and Administration Alloc-Fixed 650,652 - 520,521 130,130 4 21711 EWR and CAPA Analysis Alloc-Fixed 147,757 - 118,206 29,551 5 Total 1,717,785 - 1,374,228 343,557 6 7 102 IT Energy Management Systems 8 21600 EMS - Indirect Supervision and Administration Total Dir Labor 231,831 49,955 119,975 61,901 9 21603 EMS - Applications Support Total Dir Labor 260,394 56,110 134,757 69,527 10 21604 EMS/DTS Support Alloc-Fixed 713,859 571,087 142,772 - 11 21605 EMS - DAM Support Alloc-Fixed 749,238 149,848 449,543 149,848 12 21606 EMS - Real-time Market Support Alloc-Fixed 1,188,572 237,714 713,143 237,714 13 Total 3,143,894 1,064,714 1,560,190 518,990 14 15 16 216 IT Power System Modeling Management 17 21650 PSMM- Indirect Supervision and Administration Total Dir Labor 111,516 24,032 57,710 29,775 18 21654 PSMM- NX9 Administration Alloc-Fixed 155,520 62,208 62,208 31,104 19 21651 PSMM- Power System Modeling Alloc-Fixed 728,461 291,384 291,384 145,692 20 21652 PSMM- System Application Support Alloc-Fixed 176,500 70,600 70,600 35,300 21 21655 PSMM- ICCP Support Alloc-Fixed 472,745 189,098 189,098 94,549 22 21656 PSMM- Transmission Project Management Alloc-Fixed 23,152 18,521 4,630 - 23 21657 PSMM- Model On Demand Admin Alloc-Fixed 287,889 - - 287,889 24 21658 PSMM- Model on Demand Case Requests Alloc-Fixed 56,729 - - 56,729 25 Total 2,012,511 655,843 675,630 681,038 26 27 Total ISO $ 101,119,493 $ 26,530,221 $ 47,612,306 $ 26,976,966
100.0% 26.2% 47.1% 26.7%
(1) From Exhibit 3 (RCL-3), Schedule 5.0. (2) Provided by ISO-NE. Exhibit 3 (RCL-3) Schedule 4.0 Page 8 of 9
ISO NEW ENGLAND INC. FERC DOCKET NO. ER15-___-000 DIRECT LABOR COST ALLOCATIONS TO SCHEDULES BY COST CATEGORY TEST YEAR 2015
Line Activity Code Allocation Self-Funding Tariff No. No. Description Factor (1) Total (2) Schedule 1 Schedule 2 Schedule 3 (a) (b) (c) (d) (e) (f) (g)
1 Cost Ctr. Summary Of Departmental Labor Allocation Using "Alloc-Fixed" Allocators 2 307 Administration-CEO $ - $ - $ - $ - 3 Adm Labor 0.00% 0.00% 0.00% 0.00% 4 302 Finance $ 140,871 $ - $ - $ 140,871 5 Fin Labor 100.00% 0.00% 0.00% 100.00% 6 108 Building Services $ - $ - $ - $ - 7 Bldg Labor 0.00% 0.00% 0.00% 0.00% 8 310 Enterprise Risk Management $ 634,358 $ 224,052 $ 214,148 $ 196,158 9 ERM Labor 100.00% 35.32% 33.76% 30.92% 10 301 Human Resources $ - $ - $ - $ - 11 HR Labor 0.00% 0.00% 0.00% 0.00% 12 306 Legal Department $ 1,188,469 $ 214,784 $ 262,036 $ 711,649 13 Legal Labor 100.00% 18.07% 22.05% 59.88% 14 305 Internal Audit $ 170,119 $ 17,112 $ 136,160 $ 16,847 15 IA Labor 100.00% 10.06% 80.04% 9.90% 16 701 COO-Adm $ 1,294,634 $ 346,981 $ 620,822 $ 326,831 17 COO Labor 100.00% 26.80% 47.95% 25.25% 18 702 Reliability and Operations Services $ 703,313 $ 274,732 $ 141,832 $ 286,749 19 COO Labor 100.00% 39.06% 20.17% 40.77% 20 703 Reliability and Operations Compliance $ 1,259,266 $ 551,692 $ 336,436 $ 371,137 21 COO Labor 100.00% 43.81% 26.72% 29.47% 22 105 System Operations - Administration $ 219,249 $ 75,729 $ 101,775 $ 41,745 23 SYSOPS Labor 100.00% 34.54% 46.42% 19.04% 24 101 Operations $ 11,644,238 $ 3,319,859 $ 6,379,764 $ 1,944,616 25 OPS Labor 100.00% 28.51% 54.79% 16.70% 26 103 Operations Support Services $ 5,863,910 $ 3,165,855 $ 854,737 $ 1,843,319 27 TSO Labor 100.00% 53.99% 14.58% 31.43% 28 109 System Operations Support $ 328,667 $ - $ 65,733 $ 262,934 29 TSO Labor 100.00% 0.00% 20.00% 80.00% 30 415 Market Operations - Adm $ 1,191,222 $ - $ 833,855 $ 357,367 31 MOA Labor 100.00% 0.00% 70.00% 30.00% 32 404 Market Monitoring $ 3,263,753 $ - $ 2,283,796 $ 979,957 33 MMM Labor 100.00% 0.00% 69.97% 30.03% 34 416 Market Operations $ 2,529,923 $ 9,233 $ 2,152,913 $ 367,777 35 MA Labor 100.00% 0.36% 85.10% 14.54% 36 401 Market Anaylsis & Settlements $ 2,024,915 $ 263,612 $ 908,810 $ 852,493 37 STLM Labor 100.00% 13.02% 44.88% 42.10% 38 411 Market Operations Support Services $ 603,115 $ 46,937 $ 442,557 $ 113,621 39 MOSS Labor 100.00% 7.78% 73.38% 18.84% 40 406 Market Services $ 1,951,617 $ 234,432 $ 1,586,575 $ 130,609 41 MS Labor 100.00% 12.01% 81.30% 6.69% 42 410 Market Training and Reliability Contracts $ 855,866 $ - $ 427,933 $ 427,933 43 MAR Labor 100.00% 0.00% 50.00% 50.00% 44 204 System Planning $ 1,141,096 $ 797,632 $ 211,238 $ 132,227 45 SP Labor 100.00% 69.90% 18.51% 11.59% 46 203 Resource Adequacy $ 3,036,985 $ 231,661 $ 776,700 $ 2,028,624 47 PSR Labor 100.00% 7.63% 25.57% 66.80% 48 205 Transmission Planning $ 5,162,034 $ 4,693,029 $ - $ 469,006 49 TP Labor 100.00% 90.91% 0.00% 9.09% 50 304 Program Management $ 1,861,892 $ 713,895 $ 597,826 $ 550,171 51 PMO Labor 100.00% 38.34% 32.11% 29.55% 52 315 Business Architecture and Technology $ - $ - $ - $ - 53 BAT Labor 0.00% 0.00% 0.00% 0.00% 54 408 Market Development Administration $ 196,955 $ 1,180 $ 105,075 $ 90,700 55 MD Labor 100.00% 0.60% 53.35% 46.05% 56 407 Market Design $ 278,878 $ 27,888 $ 125,495 $ 125,495 57 MDES Labor 100.00% 10.00% 45.00% 45.00% 58 409 Demand Resource Strategy $ - $ - $ - $ - 59 DR Labor 0.00% 0.00% 0.00% 0.00%
(1) From Exhibit 3 (RCL-3), Schedule 5.0. (2) Provided by ISO-NE. Exhibit 3 (RCL-3) Schedule 4.0 Page 9 of 9
ISO NEW ENGLAND INC. FERC DOCKET NO. ER15-___-000 DIRECT LABOR COST ALLOCATIONS TO SCHEDULES BY COST CATEGORY TEST YEAR 2015
Line Activity Code Allocation Self-Funding Tariff No. No. Description Factor (1) Total (2) Schedule 1 Schedule 2 Schedule 3 (a) (b) (c) (d) (e) (f) (g)
Cost Ctr. Summary Of Departmental Labor Allocation Using "Alloc-Fixed" Allocators 1 210 IT Management $ 434,720 $ 157,613 $ 154,158 $ 122,949 2 OTM Labor 100.00% 36.26% 35.46% 28.28% 3 201 IT System/Network & Desktop $ 1,174,719 $ - $ 587,359 $ 587,359 4 ITO Labor 100.00% 0.00% 50.00% 50.00% 5 211 IT Enterprise Applications Support $ 1,273,288 $ - $ 1,018,631 $ 254,658 6 ITDG Labor 100.00% 0.00% 80.00% 20.00% 7 212 IT Cyber Security $ - $ - $ - $ - 8 ITCS 0.00% 0.00% 0.00% 0.00% 9 102 IT Energy Management Systems $ 2,651,669 $ 958,649 $ 1,305,458 $ 387,562 10 EMS Labor 100.00% 36.15% 49.23% 14.62% 11 213 IT Enterprise Applications Development $ 1,717,785 $ - $ 1,374,228 $ 343,557 12 ESD 100.00% 0.00% 80.00% 20.00% 13 216 IT Power System Modeling Management $ 1,900,995 $ 631,812 $ 617,921 $ 651,263 14 ITPSM 100.00% 33.24% 32.51% 34.26% 15 Total Direct Labor $ 56,698,523 $ 16,958,370 $ 24,623,971 $ 15,116,181 16 100.00% 29.91% 43.43% 26.66% 17 18 Summary Of Allocations Of Labor Based On Fixed Allocators and Allocated Departmental Labor 19 Total Direct Labor $ 56,698,523 $ 16,958,370 $ 24,623,971 $ 15,116,181 20 Dir Labor 100.00% 29.91% 43.43% 26.66% 21 Total Indirect Labor Labor $ 44,420,970 $ 9,571,851 $ 22,988,335 $ 11,860,785 22 InDir Labor 100.00% 21.55% 51.75% 26.70% 23 Total Labor Expense $ 101,119,493 $ 26,530,221 $ 47,612,306 $ 26,976,966 24 Total Dir Labor 100.00% 26.24% 47.09% 26.68%
(1) From Exhibit 3 (RCL-3), Schedule 5.0. (2) Provided by ISO-NE. ISO NEW ENGLAND INC. Exhibit 3 (RCL-3) FERC DOCKET NO. ER15-___-000 Schedule 5.0 ALLOCATION FACTORS BY COST CATEGORY Page 1 of 11 TEST YEAR 2015
Line Activity Code Allocation Self-Funding Tariff No. No. Description Factor Total Schedule 1 Schedule 2 Schedule 3 Reference (a) (b) (c) (d) (e) (f) (g) (h)
1 307 Administration-CEO 2 12651 Adm/Finance/HR - Indirect Administrative Support Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 3 12652 Adm/Finance/HR - NEPOOL Committee Support Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 4 12653 Adm/Finance/HR - Regional Committee Support Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 5 12654 Adm/Finance/HR - National Committee Support Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 6 12655 Adm/Finance/HR - NEPOOL Review Board Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 7 12657 Adm/Finance/HR - Indirect Administrative Support for BCC Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 8 9 302 Finance 10 11601 Payroll Administration Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 11 11701 Accounts Payable Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 12 11702 Procurement Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 13 11901 Billing for Transmission and Energy Settlements Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 14 12001 Budgeting and Forecasting Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 15 12002 ISO Tariff Design Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 16 12005 Credit Admininstration Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 17 12010 Zone/BU/CCC Support Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 18 12012 Forward Capacity Market Production Alloc-Fixed 100.00% 0.00% 0.00% 100.00% Per ISO-NE Staff 19 12015 BCC Construction Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 20 12017 Forward Capacity Market (FCM) Reforms Alloc-Fixed 100.00% 0.00% 0.00% 100.00% Per ISO-NE Staff 21 12101 Ledger Closing, Financial Statements and Tax Reporting Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 22 12201 Treasury and Cash Management Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 23 12301 Activity Accounting and Reporting Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 24 25554 Generation Information System Alloc-Fixed 100.00% 45.00% 45.00% 10.00% Per ISO-NE Staff 25 92004 Depreciation Expense 2004 Assets Alloc-Fixed 100.00% 20.83% 52.21% 26.96% Per ISO-NE Staff 26 92005 Depreciation Expense 2005 Assets Alloc-Fixed 100.00% 21.16% 52.00% 26.84% Per ISO-NE Staff 27 92006 Depreciation Expense 2006 Assets Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 28 92007 Depreciation Expense 2007 Assets Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 29 92008 Depreciation Expense 2008 Assets Alloc-Fixed 100.00% 54.99% 29.69% 15.32% Per ISO-NE Staff 30 92009 Depreciation Expense 2009 Assets Alloc-Fixed 100.00% 58.53% 31.26% 10.21% Per ISO-NE Staff 31 92010 Depreciation Expense 2010 Assets Alloc-Fixed 100.00% 32.06% 39.13% 28.81% Per ISO-NE Staff 32 92011 Depreciation Expense 2011 Assets Alloc-Fixed 100.00% 19.77% 33.61% 46.62% Per ISO-NE Staff 33 92012 Depreciation Expense 2012 Assets Alloc-Fixed 100.00% 19.01% 43.62% 37.37% Per ISO-NE Staff 34 92013 Depreciation Expense 2013 Assets Alloc-Fixed 100.00% 18.42% 48.03% 33.56% Per ISO-NE Staff 35 92014 Depreciation Expense 2014 Assets Alloc-Fixed 100.00% 30.33% 34.25% 35.42% Per ISO-NE Staff 36 92015 Depreciation Expense 2015 Assets Alloc-Fixed 100.00% 22.80% 49.70% 27.50% Per ISO-NE Staff 37 99705 SMD Amortization - writeoff Alloc-Fixed 100.00% 0.00% 90.00% 10.00% Per ISO-NE Staff 38 99706 SMD Amortization Alloc-Fixed 100.00% 0.00% 90.00% 10.00% Per ISO-NE Staff 39 99707 Amortization of Land Recovery Alloc-Fixed 100.00% 19.33% 35.58% 45.09% Per ISO-NE Staff 40 99995 NPCC/NERC Dues Alloc-Fixed 100.00% 0.00% 0.00% 100.00% Per ISO-NE Staff 41 99996 Operating Contingency Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 42 99997 Depreciation Accruals Alloc-Fixed 100.00% 18.12% 52.46% 29.42% Per ISO-NE Staff 43 99998 Payroll & Other Accruals Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 44 45 108 Building Services 46 12664 Building Maintenance Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 47 12668 Building Maintenance - Offsite Temporary Offices Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 48 49 310 Enterprise Risk Management 50 22701 ERM -Enterprise Risk Mgmnt - Admn Alloc-Fixed 100.00% 33.30% 33.30% 33.40% Per ISO-NE Staff 51 22702 ERM -Enterprise Risk Mgmnt - Initia Alloc-Fixed 100.00% 33.30% 33.30% 33.40% Per ISO-NE Staff 52 22703 ERM-Bus Cont Pl Prog Admin & Support Alloc-Fixed 100.00% 33.30% 33.30% 33.40% Per ISO-NE Staff 53 22704 ERM - Record Retention Services Alloc-Fixed 100.00% 33.30% 33.30% 33.40% Per ISO-NE Staff 54 22705 ERM - Corporate Scorecard Alloc-Fixed 100.00% 33.30% 33.30% 33.40% Per ISO-NE Staff 55 22706 ERM - Document Management Services Alloc-Fixed 100.00% 40.00% 30.00% 30.00% Per ISO-NE Staff 56 22708 ERM Adminstration Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 57 22709 ERM Management Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 58 22710 Employee Development Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 59 22711 FAP Admin - FCM Cap Adjustments Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 60 22712 FAP Admin - Risk Policy Assessments Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 61 22713 FAP Admin - MEC/Financials Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 62 22714 FAP Analysis Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 63 22715 FAP Rules / regulatory Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 64 22716 FAM Rebuild Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 65 22717 3rd Party FTRs Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 66 22718 CAPA 2.0 Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 67 22719 Human Performance Improvement Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 68 22720 Business Process Change Management Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 69 22721 Corp Strategic Risk Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 70 22722 Corp Strategic Plan Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 71 22723 IRC ERM group Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 72 22724 FEAP Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 73 22725 OSHA procedures Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 74 22726 Project Risk Management Meeting Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 75 22727 ERM Business Analysis Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 76 23001 CP - COS, RMR, and PUSH Alloc-Fixed 100.00% 0.00% 50.00% 50.00% Per ISO-NE Staff 77 23002 CP - Strategic and Business Planning Alloc-Fixed 100.00% 33.30% 33.30% 33.40% Per ISO-NE Staff 78 23003 CP - Safety / Security / Facilities Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 79 23006 Business Continuity Planning Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 80 25006 ERM - Business Process Maintenance Alloc-Fixed 100.00% 45.00% 45.00% 10.00% Per ISO-NE Staff 81 25008 QMS - Quality Management System Alloc-Fixed 100.00% 33.30% 33.30% 33.40% Per ISO-NE Staff 82 25009 QMS - Internal QMS Assessment Alloc-Fixed 100.00% 33.30% 33.30% 33.40% Per ISO-NE Staff 83 25011 Corrective Action/Preventive Action Alloc-Fixed 100.00% 33.30% 33.30% 33.40% Per ISO-NE Staff 84 25012 OE - Business Process Re-Engineering Alloc-Fixed 100.00% 33.30% 33.30% 33.40% Per ISO-NE Staff 85 25013 Tariff & Governance Documents Compliance Program Alloc-Fixed 100.00% 25.00% 25.00% 50.00% Per ISO-NE Staff 86 25014 EtQ Tools Dev & Support Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff ISO NEW ENGLAND INC. Exhibit 3 (RCL-3) FERC DOCKET NO. ER15-___-000 Schedule 5.0 ALLOCATION FACTORS BY COST CATEGORY Page 2 of 11 TEST YEAR 2015
Line Activity Code Allocation Self-Funding Tariff No. No. Description Factor Total Schedule 1 Schedule 2 Schedule 3 Reference (a) (b) (c) (d) (e) (f) (g) (h)
1 301 Human Resources 2 12661 Employee Affairs (Recreation Committee) Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 3 12701 Recruiting/Interviewing Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 4 12801 Employee Relations Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 5 12901 Benefit Administration Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 6 12951 Compensation Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 7 12961 HR - General Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 8 12962 HR - Training Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 9 13301 Labor Relations Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 10 13410 Power Training & Development Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 11 13411 Markets Training & Development Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 12 13412 People Training & Development Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 13 13413 Business Skills Trng & Dev Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 14 13414 Technology Trng & Development Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 15 16 305 Internal Audit 17 15001 Audit - Indirect Mgmnt Duties Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 18 15002 Audit- Personnel Management Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 19 15003 Audit- Budget & Forecasting Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 20 15004 Audit- Audit Followup Activities Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 21 15005 Audit - Audit & Finance Committee Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 22 15006 Audit- Internal Audit Business Process Update Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 23 15007 Audit- Annual Audit Work Plan Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 24 15008 Audit-Training Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 25 15010 Internal Audit - Operations Alloc-Fixed 100.00% 33.33% 33.33% 33.33% Per ISO-NE Staff 26 15013 Audit - Indirect Admin Support Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 27 15020 Internal Audit - Finance Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 28 15021 Audit- Perfomance Measurements Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 29 15022 Audit- Vendor Contracts Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 30 15023 Audit- Wire Transfers Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 31 15024 Audit- Sarbanes Oxley Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 32 15025 Audit - Timesheets Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 33 15026 Audit - Financial Assurance Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 34 15027 Audit - Business Continuity / Disaster Recovery Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 35 15031 Audit - Employee Expense Reporting Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 36 15040 Audit-Operations Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 37 15041 Audit-Control Room Operations Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 38 15042 Audit-Forecasting Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 39 15043 Audit-Operations Compliance Oversight Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 40 15044 Audit-Transmission System Model Alloc-Fixed 100.00% 50.00% 0.00% 50.00% Per ISO-NE Staff 41 15045 Audit - FTR /ARR Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 42 15046 Audit - Day Ahead Follow Up / Outage Coordination Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 43 15047 Audit -Transmission Cost Allocation Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 44 15058 Audit - Asset Registration Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 45 15065 Audit - Wind Integration Project Alloc-Fixed 100.00% 40.00% 40.00% 20.00% Per ISO-NE Staff 46 15066 Audit- Day Ahead Markets/Settlements Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 47 15068 Audit - FCM Settlements Audit Alloc-Fixed 100.00% 0.00% 0.00% 100.00% Per ISO-NE Staff 48 15085 Audit - Information Technology Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 49 15086 Audit-Change Mgmnt/Conf Mgmnt - Mkt Sys (SSAE 16 Support) Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 50 15087 Audit-Logical Access-Files/DB/ Infrastructure - Martket Systems Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 51 15088 Audit- Disaster Recovery Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 52 15089 Audit - Logical Access - Settlements & Financial Systems (SSAE Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 53 15090 Audit - Training Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 54 15091 Audit - Logical Access - Energy Management Systems Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 55 15092 Audit - Change Management - Energy Management Systems Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 56 15093 Audit - Change Mgmnt - Settlements & Financial Systems (SSAE Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 57 15094 Audit - AREVA Change Control Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 58 15110 External Audit - Operations Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 59 15111 Audit - Ancillary Services Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 60 15112 Audit - Locational ICAP Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 61 15113 Audit - Real Time Demand Response Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 62 15130 External Audit - General Controls Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 63 15131 Audit- NAMS Support Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 64 15132 Audit- Oper Audit Support Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 65 15133 Audit- Satellite Reviews Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 66 15134 Audit- SCADA Operations Reviews Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 67 15136 Audit- SCADA IT Reviews Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 68 15137 Audit- Satellite IT Reviews Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 69 15150 Internal Audit - Standard Market Design Alloc-Fixed 100.00% 3.00% 40.00% 57.00% Per ISO-NE Staff 70 15160 External Audit - Finance Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 71 15161 External Audit- Pension Audit Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 72 15162 Ext Audit- Financial Audit Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 73 15165 External Audit - Operations Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 74 15166 Ext Audit -Pricing Module Certification Alloc-Fixed 100.00% 0.00% 100.00% 0.00% Per ISO-NE Staff 75 15170 External Audit - Settlements Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 76 15171 Ext Audit-Mgmnt Assertion Audit Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 77 15175 Ext Audit - Info Technology Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 78 15176 Ext Audit - ISO Internet Vulnerability Assessment Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 79 15177 Ext Audit - Satellite / SCADA Internet Vulnerability Assessment Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 80 15180 External Audit - Participants Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 81 15181 Ext Audit - RNS Audit Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 82 15185 External Audit - Other Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 83 15186 Ext Audit - SSAE 16 Direct Support Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 84 15190 Int Audit Special Projects Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 85 15191 IA Special Projects - Audit Universe - Auto Audit Implementation Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 86 15192 IA Special Projects - Data Mining - Audit Command Language Imp Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 87 25702 External Audit - SSAE 16 Alloc-Fixed 100.00% 0.00% 100.00% 0.00% Per ISO-NE Staff 88 28160 Audit - MS Universal Access Gateway Review Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 89 28304 Stimulus Fund Project Compliance, Rpting & Auditing Req Pre-Im Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 90 28581 External Firm Stimulus Funds - Project Mock Audit Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff ISO NEW ENGLAND INC. Exhibit 3 (RCL-3) FERC DOCKET NO. ER15-___-000 Schedule 5.0 ALLOCATION FACTORS BY COST CATEGORY Page 3 of 11 TEST YEAR 2015
Line Activity Code Allocation Self-Funding Tariff No. No. Description Factor Total Schedule 1 Schedule 2 Schedule 3 Reference (a) (b) (c) (d) (e) (f) (g) (h)
1 306 Legal Department 2 8301 GC - Federal Regulatory Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 3 12420 NCPC Changes Alloc-Fixed 100.00% 0.00% 25.00% 75.00% Per ISO-NE Staff 4 12421 Demand Integration Alloc-Fixed 100.00% 0.00% 100.00% 0.00% Per ISO-NE Staff 5 12423 GC - Financial Assurance Policy (FAP) Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 6 12425 GC - Price Response Demand Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 7 12502 Board of Directors Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 8 12504 ISO Tariff Litigation Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 9 12505 Administration of OATT Alloc-Fixed 100.00% 100.00% 0.00% 0.00% Per ISO-NE Staff 10 12508 Energy Markets/Compliants/Rule Changes Alloc-Fixed 100.00% 0.00% 100.00% 0.00% Per ISO-NE Staff 11 12509 Market Monitoring and Sanctions Alloc-Fixed 100.00% 0.00% 50.00% 50.00% Per ISO-NE Staff 12 12512 GC - BSIA - General Corporate Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 13 12513 Miscellaneous Labor Matters Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 14 12514 NEPOOL Participants Committee Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 15 12517 Administrative and Clerical Support Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 16 12520 Market Monitoring Rules/Regulations Alloc-Fixed 100.00% 0.00% 40.00% 60.00% Per ISO-NE Staff 17 12521 Billing Disputes Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 18 12523 NEPOOL Information Policy Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 19 12542 Transmission Upgrades CT Alloc-Fixed 100.00% 0.00% 70.00% 30.00% Per ISO-NE Staff 20 12543 Independent Market Advisor Alloc-Fixed 100.00% 0.00% 70.00% 30.00% Per ISO-NE Staff 21 12544 FERC Proceedings Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 22 12547 GC - Creation of New England RTO Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 23 12552 GC - S&G - General Corporate Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 24 12555 GC - Transmission Upgrades - VT Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 25 12556 GC - Patents Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 26 12559 General Corporate Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 27 12561 GC - Schiff Hardin Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 28 12562 Transmission Upgrades VT Alloc-Fixed 100.00% 0.00% 70.00% 30.00% Per ISO-NE Staff 29 12563 Regulatory Matters Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 30 12565 GC - Conn Regulatory Matters - WBAM Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 31 12568 RMR Agreements Alloc-Fixed 100.00% 0.00% 70.00% 30.00% Per ISO-NE Staff 32 12569 NOPR / Rulemaking Comments Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 33 12570 Operations Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 34 12571 ISO Reporting Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 35 12572 GC - BSAI - 205 General Proceedings Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 36 12573 206 General Proceedings Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 37 12574 Market Rule 1 Proceedings Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 38 12575 Transmission Cost Allocation Alloc-Fixed 100.00% 0.00% 70.00% 30.00% Per ISO-NE Staff 39 12579 GC - SH - Market Rule 1 Proceedings Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 40 12583 GC - SH - LICAP Appeal Alloc-Fixed 100.00% 0.00% 0.00% 100.00% Per ISO-NE Staff 41 12584 Installed Capacity Requirements Alloc-Fixed 100.00% 0.00% 0.00% 100.00% Per ISO-NE Staff 42 12587 Capacity Market Development Alloc-Fixed 100.00% 0.00% 0.00% 100.00% Per ISO-NE Staff 43 12588 Web Content Management Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 44 12589 Rhode Island Siting Alloc-Fixed 100.00% 0.00% 70.00% 30.00% Per ISO-NE Staff 45 12594 Maine Transmission Siting Alloc-Fixed 100.00% 0.00% 70.00% 30.00% Per ISO-NE Staff 46 12595 NEEWS Transmission Siting Alloc-Fixed 100.00% 0.00% 70.00% 30.00% Per ISO-NE Staff 47 12663 Public Information Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 48 12669 Government Affairs Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 49 12673 Market Conference Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 50 12674 Energy Efficiency Activities Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 51 12592 GC - State Proceedings Alloc-Fixed 100.00% 0.00% 50.00% 50.00% Per ISO-NE Staff 52 12598 GC - ERO Alloc-Fixed 100.00% 40.00% 40.00% 20.00% Per ISO-NE Staff 53 12602 Exemption for Commodity Futures Trading Commission Alloc-Fixed 100.00% 0.00% 50.00% 50.00% Per ISO-NE Staff 54 55 701 COO-Adm 56 19001 COO - NEPOOL Committee Support Total OPS Labor 100.00% 26.80% 47.95% 25.25% Per ISO-NE Staff 57 19002 COO - Regional Committee Support Total OPS Labor 100.00% 26.80% 47.95% 25.25% Per ISO-NE Staff 58 19003 COO - National Committee Support Total OPS Labor 100.00% 26.80% 47.95% 25.25% Per ISO-NE Staff 59 19004 Employee Development Total OPS Labor 100.00% 26.80% 47.95% 25.25% Per ISO-NE Staff 60 19005 COO - Indirect Supervision/Clerical Support Total OPS Labor 100.00% 26.80% 47.95% 25.25% Per ISO-NE Staff 61 19006 COO - Northeast Disturbance Total OPS Labor 100.00% 26.80% 47.95% 25.25% Per ISO-NE Staff 62 19007 COO - Operational Excellence Total OPS Labor 100.00% 26.80% 47.95% 25.25% Per ISO-NE Staff 63 19009 COO - Renewable Resource Integration Alloc-Fixed 100.00% 0.00% 0.00% 100.00% Per ISO-NE Staff 64 19010 COO - Quality Improvement Total OPS Labor 100.00% 26.80% 47.95% 25.25% Per ISO-NE Staff 65 19011 COO - Advanced Grid Simulator Alloc-Fixed 100.00% 0.00% 50.00% 50.00% Per ISO-NE Staff 66 19012 Changes to the Forward Capacity Market Alloc-Fixed 100.00% 0.00% 0.00% 100.00% Per ISO-NE Staff 67 19013 Changes Relevant to Fuel Security Alloc-Fixed 100.00% 0.00% 80.00% 20.00% Per ISO-NE Staff 68 69 105 System Operations - Administration 70 14404 System Ops Mgt & Adm - NEPOOL Committee Support SOA Labor 100.00% 34.54% 46.42% 19.04% Per ISO-NE Staff 71 14405 System Ops Mgt & Adm - Indirect Supervision/Clerical Support SOA Labor 100.00% 34.54% 46.42% 19.04% Per ISO-NE Staff 72 14407 System Ops Mgt & Adm - Regional Committee Support SOA Labor 100.00% 34.54% 46.42% 19.04% Per ISO-NE Staff 73 14408 System Ops Mgt & Adm - National Committee Support SOA Labor 100.00% 34.54% 46.42% 19.04% Per ISO-NE Staff 74 14409 System Ops Mgt & Adm - Employee Development SOA Labor 100.00% 34.54% 46.42% 19.04% Per ISO-NE Staff ISO NEW ENGLAND INC. Exhibit 3 (RCL-3) FERC DOCKET NO. ER15-___-000 Schedule 5.0 ALLOCATION FACTORS BY COST CATEGORY Page 4 of 11 TEST YEAR 2015
Line Activity Code Allocation Self-Funding Tariff No. No. Description Factor Total Schedule 1 Schedule 2 Schedule 3 Reference (a) (b) (c) (d) (e) (f) (g) (h)
1 101 Operations 2 14001 Ops - Generation Dispatch Alloc-Fixed 100.00% 0.00% 84.00% 16.00% Per ISO-NE Staff 3 14002 Ops - Transmission Operations Alloc-Fixed 100.00% 80.00% 5.00% 15.00% Per ISO-NE Staff 4 14304 Ops - Advanced Scheduling and Forecasting Alloc-Fixed 100.00% 5.00% 79.00% 16.00% Per ISO-NE Staff 5 14402 Ops - Operations Training Alloc-Fixed 100.00% 40.00% 40.00% 20.00% Per ISO-NE Staff 6 14413 Ops - Operations Support Training & Development Alloc-Fixed 100.00% 40.00% 40.00% 20.00% Per ISO-NE Staff 7 14457 Transmission Pilot Program Alloc-Fixed 100.00% 100.00% 0.00% 0.00% Per ISO-NE Staff 8 14561 Ops - NEPOOL Committee Support OPS Labor 100.00% 27.96% 55.36% 16.68% Per ISO-NE Staff 9 14562 Ops - Regional Committee Support OPS Labor 100.00% 27.96% 55.36% 16.68% Per ISO-NE Staff 10 14563 Ops - National Committee Support OPS Labor 100.00% 27.96% 55.36% 16.68% Per ISO-NE Staff 11 14564 Ops - Indirect Supervision/Clerical Support OPS Labor 100.00% 27.96% 55.36% 16.68% Per ISO-NE Staff 12 14565 Ops - Employee Development OPS Labor 100.00% 27.96% 55.36% 16.68% Per ISO-NE Staff 13 14570 Ops - Market Analysis Alloc-Fixed 100.00% 0.00% 100.00% 0.00% Per ISO-NE Staff 14 14702 TPC - Procedure Documentation Alloc-Fixed 100.00% 40.00% 40.00% 20.00% Per ISO-NE Staff 15 15501 OA - Operations Analysis Alloc-Fixed 100.00% 15.00% 70.00% 15.00% Per ISO-NE Staff 16 17 702 Reliability and Operations Services 18 14701 TPC - Compliance Monitoring Alloc-Fixed 100.00% 40.00% 40.00% 20.00% Per ISO-NE Staff 19 14703 TPC - NEPOOL Committee Support OS Labor 100.00% 55.55% 19.33% 25.12% Per ISO-NE Staff 20 14704 TPC - Regional Committee Support OS Labor 100.00% 55.55% 19.33% 25.12% Per ISO-NE Staff 21 14705 TPC - National Committee Support OS Labor 100.00% 55.55% 19.33% 25.12% Per ISO-NE Staff 22 14706 TPC - Indirect Supervision/Clerical Support OS Labor 100.00% 55.55% 19.33% 25.12% Per ISO-NE Staff 23 14707 TPC - Employee Development OS Labor 100.00% 55.55% 19.33% 25.12% Per ISO-NE Staff 24 14710 ISO TMS Tariff-Section 1 - (Genernal Terms and Conditions) Alloc-Fixed 100.00% 33.30% 33.30% 33.40% Per ISO-NE Staff 25 14711 ISO TMS Tariff-Section 2 - (OATT) and Agreements Support Alloc-Fixed 100.00% 33.30% 33.30% 33.40% Per ISO-NE Staff 26 14715 EIPC - Non DOE Funded/Unallowable Alloc-Fixed 100.00% 0.00% 0.00% 100.00% Per ISO-NE Staff 27 14716 EIPC - Initiate Project Alloc-Fixed 100.00% 0.00% 0.00% 100.00% Per ISO-NE Staff 28 14720 EIPC - Macroeconomic Analysis Alloc-Fixed 100.00% 0.00% 0.00% 100.00% Per ISO-NE Staff 29 14721 EIPC - Expansion Scenario Consensus Alloc-Fixed 100.00% 0.00% 0.00% 100.00% Per ISO-NE Staff 30 14722 EIPC - Interim Report Reference Case and Expansion Scen Alloc-Fixed 100.00% 0.00% 0.00% 100.00% Per ISO-NE Staff 31 14723 EIPC - Interregional Transmission Operations Alloc-Fixed 100.00% 0.00% 0.00% 100.00% Per ISO-NE Staff 32 14724 EIPC - Reliability Review Alloc-Fixed 100.00% 0.00% 0.00% 100.00% Per ISO-NE Staff 33 14725 EIPC - Prod. Cost Analysis of Interregional Trans. Options Alloc-Fixed 100.00% 0.00% 0.00% 100.00% Per ISO-NE Staff 34 14726 EIPC - Generation and Transmission Cost Estimates Alloc-Fixed 100.00% 0.00% 0.00% 100.00% Per ISO-NE Staff 35 14727 EIPC - Review of Results Alloc-Fixed 100.00% 0.00% 0.00% 100.00% Per ISO-NE Staff 36 14728 EIPC - Final Report Alloc-Fixed 100.00% 0.00% 0.00% 100.00% Per ISO-NE Staff 37 38 103 Operations Support Services 39 9701 TSO - Database/Software Development Alloc-Fixed 100.00% 30.00% 60.00% 10.00% Per ISO-NE Staff 40 9707 TSO - TTC Forecast Alloc-Fixed 100.00% 100.00% 0.00% 0.00% Per ISO-NE Staff 41 14102 TSO - OATT/RTG Services Alloc-Fixed 100.00% 100.00% 0.00% 0.00% Per ISO-NE Staff 42 14301 TSO - Contract Administration and Scheduling Alloc-Fixed 100.00% 10.00% 70.00% 20.00% Per ISO-NE Staff 43 14303 TSO - Generation Dispatch/Resource Auditing Support Alloc-Fixed 100.00% 0.00% 100.00% 0.00% Per ISO-NE Staff 44 14451 TSO - NEPOOL Committee Support TSO Labor 100.00% 32.37% 47.81% 19.82% Per ISO-NE Staff 45 14452 TSO - Regional Committee Support TSO Labor 100.00% 32.37% 47.81% 19.82% Per ISO-NE Staff 46 14453 TSO - National Committee Support TSO Labor 100.00% 32.37% 47.81% 19.82% Per ISO-NE Staff 47 14454 TSO - Indirect Supervision/Clerical Support TSO Labor 100.00% 32.37% 47.81% 19.82% Per ISO-NE Staff 48 14456 TSO - HVDC Transmission Business Services TSO Labor 100.00% 32.37% 47.81% 19.82% Per ISO-NE Staff 49 14455 TSO - Employee Development TSO Labor 100.00% 32.37% 47.81% 19.82% Per ISO-NE Staff 50 14458 TSO - Reactive Capability Payment Program Alloc-Fixed 100.00% 0.00% 100.00% 0.00% Per ISO-NE Staff 51 14459 TSO - NRTG Transmission Service TSO Labor 100.00% 32.37% 47.81% 19.82% Per ISO-NE Staff 52 14460 TSO - NERC IDC/SDX Data TSO Labor 100.00% 32.37% 47.81% 19.82% Per ISO-NE Staff 53 14461 TSO - Annual Operations Reliability Report Alloc-Fixed 100.00% 0.00% 0.00% 100.00% Per ISO-NE Staff 54 14462 OSS - General Systems Operations Support TSO Labor 100.00% 32.37% 47.81% 19.82% Per ISO-NE Staff 55 14463 OSS - Transmission Outage Report Development Alloc-Fixed 100.00% 50.00% 25.00% 25.00% Per ISO-NE Staff 56 14464 OSS - Econ Anal Equip Out (TOA) Alloc-Fixed 100.00% 100.00% 0.00% 0.00% Per ISO-NE Staff 57 14466 OSS - Monthly Forward Capacity Market (FCM) Alloc-Fixed 100.00% 0.00% 0.00% 100.00% Per ISO-NE Staff 58 14469 OSS – C10/C30 Audits Alloc-Fixed 100.00% 0.00% 80.00% 20.00% Per ISO-NE Staff 59 14470 OSS – Resource Performance Monitoring Alloc-Fixed 100.00% 0.00% 80.00% 20.00% Per ISO-NE Staff 60 14471 OSS – New Generation Coordination & Registration Alloc-Fixed 100.00% 0.00% 70.00% 30.00% Per ISO-NE Staff 61 18361 OSS - Transmission Studies, Operations, OASIS Support Alloc-Fixed 100.00% 80.00% 5.00% 15.00% Per ISO-NE Staff 62 18381 OSS - Transmission Outage Appl - Short Term Alloc-Fixed 100.00% 80.00% 5.00% 15.00% Per ISO-NE Staff 63 18382 OSS - Trans Out Ap Lg Term Alloc-Fixed 100.00% 0.00% 0.00% 100.00% Per ISO-NE Staff 64 65 315 System Operations Support 66 14750 SOS - NEPOOL Committee Support Alloc-Fixed 100.00% 32.37% 47.81% 19.82% Per ISO-NE Staff 67 14751 SOS - Regional Committee Support Alloc-Fixed 100.00% 32.37% 47.81% 19.82% Per ISO-NE Staff 68 14752 SOS - National Committee Support Alloc-Fixed 100.00% 32.37% 47.81% 19.82% Per ISO-NE Staff 69 14753 SOS - Indirect Supervision/Clerical Support Alloc-Fixed 100.00% 32.37% 47.81% 19.82% Per ISO-NE Staff 70 14754 SOS - Employee Development Alloc-Fixed 100.00% 32.37% 47.81% 19.82% Per ISO-NE Staff 71 14755 Winter 2013/14 Reliability Project Alloc-Fixed 100.00% 0.00% 20.00% 80.00% Per ISO-NE Staff 72 14757 Winter 2014/15 Reliability Project Alloc-Fixed 100.00% 0.00% 20.00% 80.00% Per ISO-NE Staff ISO NEW ENGLAND INC. Exhibit 3 (RCL-3) FERC DOCKET NO. ER15-___-000 Schedule 5.0 ALLOCATION FACTORS BY COST CATEGORY Page 5 of 11 TEST YEAR 2015
Line Activity Code Allocation Self-Funding Tariff No. No. Description Factor Total Schedule 1 Schedule 2 Schedule 3 Reference (a) (b) (c) (d) (e) (f) (g) (h)
1 415 Market Operations - Adm 2 19101 MO - NEPOOL Committee Support MOA Labor 100.00% 0.00% 70.00% 30.00% Per ISO-NE Staff 3 19102 MO - Regional Committee Support MOA Labor 100.00% 0.00% 70.00% 30.00% Per ISO-NE Staff 4 19103 MO - National Committee Support MOA Labor 100.00% 0.00% 70.00% 30.00% Per ISO-NE Staff 5 19104 MO - Indirect Supervision/Clerical Support MOA Labor 100.00% 0.00% 70.00% 30.00% Per ISO-NE Staff 6 19105 Employee Development MOA Labor 100.00% 0.00% 70.00% 30.00% Per ISO-NE Staff 7 19112 Settlements - Customer Service MOA Labor 100.00% 0.00% 70.00% 30.00% Per ISO-NE Staff 8 19118 Cost of Poor Quality - COPQ Alloc-Fixed 100.00% 33.33% 33.33% 33.34% Per ISO-NE Staff 9 19120 CEII Requests Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 10 19121 Membership/Participant Support Alloc-Fixed 100.00% 0.00% 50.00% 50.00% Per ISO-NE Staff 11 19122 DR/BLTS Issues Management Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 12 13 404 Market Monitoring 14 16101 Market Power Monitoring and Mitigation Alloc-Fixed 100.00% 0.00% 70.00% 30.00% Per ISO-NE Staff 15 16102 Regulatory Activities Alloc-Fixed 100.00% 0.00% 70.00% 30.00% Per ISO-NE Staff 16 16103 Administration Supervision and Clerical Support Alloc-Fixed 100.00% 0.00% 70.00% 30.00% Per ISO-NE Staff 17 16111 Employee Development MMM Labor 100.00% 0.00% 70.00% 30.00% Per ISO-NE Staff 18 16113 New Software Coding and Testing MMM Labor 100.00% 0.00% 70.00% 30.00% Per ISO-NE Staff 19 16114 Maintenance / Troubleshooting Software MMM Labor 100.00% 0.00% 70.00% 30.00% Per ISO-NE Staff 20 16115 Analysis & Internal Reports MMM Labor 100.00% 0.00% 70.00% 30.00% Per ISO-NE Staff 21 16117 Manuals & Procedures MMM Labor 100.00% 0.00% 70.00% 30.00% Per ISO-NE Staff 22 16121 FCM Market Monitoring Alloc-Fixed 100.00% 0.00% 0.00% 100.00% Per ISO-NE Staff 23 24 416 Market Operations 25 21901 Day Ahead Market Administration Alloc-Fixed 100.00% 0.00% 100.00% 0.00% Per ISO-NE Staff 26 21902 Real Time Price Verification Alloc-Fixed 100.00% 0.00% 100.00% 0.00% Per ISO-NE Staff 27 21903 FTR/ARR Administration Alloc-Fixed 100.00% 50.00% 50.00% 0.00% Per ISO-NE Staff 28 21904 MA - NEPOOL Committee Support MA Labor 100.00% 0.00% 96.84% 3.16% Per ISO-NE Staff 29 21905 MA - Regional Committee Support MA Labor 100.00% 0.00% 96.84% 3.16% Per ISO-NE Staff 30 21906 MA - National Committee Support MA Labor 100.00% 0.00% 96.84% 3.16% Per ISO-NE Staff 31 21907 MA - Indirect Supervision/Clerical Support MA Labor 100.00% 0.00% 96.84% 3.16% Per ISO-NE Staff 32 21908 Employee Development MA Labor 100.00% 0.00% 96.84% 3.16% Per ISO-NE Staff 33 21909 Customer Support MA Labor 100.00% 0.00% 96.84% 3.16% Per ISO-NE Staff 34 21913 MA-Data Collection/Report Writing Alloc-Fixed 100.00% 0.00% 100.00% 0.00% Per ISO-NE Staff 35 21914 QUA Administration Alloc-Fixed 100.00% 50.00% 50.00% 0.00% Per ISO-NE Staff 36 21915 FTR/Auction Administration Alloc-Fixed 100.00% 0.00% 100.00% 0.00% Per ISO-NE Staff 37 21916 Forward Reserve Market - Administration Alloc-Fixed 100.00% 0.00% 0.00% 100.00% Per ISO-NE Staff 38 21917 Real Time Price Finalization Alloc-Fixed 100.00% 0.00% 100.00% 0.00% Per ISO-NE Staff 39 21918 Resource Performance Monitoring Alloc-Fixed 100.00% 20.00% 30.00% 50.00% Per ISO-NE Staff 40 21951 FCM Annual Reconfiguration Auction Administration Alloc-Fixed 100.00% 0.00% 0.00% 100.00% Per ISO-NE Staff 41 21952 FCM Annual CSO Bilaterals Administration Alloc-Fixed 100.00% 0.00% 0.00% 100.00% Per ISO-NE Staff 42 21953 FCM Monthly Administration Alloc-Fixed 100.00% 0.00% 0.00% 100.00% Per ISO-NE Staff 43 21954 Market Schedule Coordination Alloc-Fixed 100.00% 0.00% 30.00% 70.00% Per ISO-NE Staff 44 21955 Incremental Auction Revenue Rights Alloc-Fixed 100.00% 50.00% 50.00% 0.00% Per ISO-NE Staff 45 21956 Changes in Supply Offers (Hourly Reoffers) Alloc-Fixed 100.00% 0.00% 100.00% 0.00% Per ISO-NE Staff 46 47 401 Market Anaylsis & Settlements 48 1701 Billing Statements - Energy Alloc-Fixed 100.00% 0.00% 100.00% 0.00% Per ISO-NE Staff 49 1702 Billing Statements - Transmission Alloc-Fixed 100.00% 100.00% 0.00% 0.00% Per ISO-NE Staff 50 1713 Billing Statements - ISO Tariff Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 51 1714 Billable Tariff Re-billings Alloc-Fixed 100.00% 100.00% 0.00% 0.00% Per ISO-NE Staff 52 2005 Settlements - Customer Service STLM Labor 100.00% 14.79% 48.71% 36.50% Per ISO-NE Staff 53 2007 Settlements - Admin support - NEPOOL Committees STLM Labor 100.00% 14.79% 48.71% 36.50% Per ISO-NE Staff 54 2008 Settlements - Admin support (ISO) STLM Labor 100.00% 14.79% 48.71% 36.50% Per ISO-NE Staff 55 2009 Settlements - Indirect Supervision/Clerical Support STLM Labor 100.00% 14.79% 48.71% 36.50% Per ISO-NE Staff 56 2010 Settlements - Employee Development STLM Labor 100.00% 14.79% 48.71% 36.50% Per ISO-NE Staff 57 2013 Settlements - FTR Administration Alloc-Fixed 100.00% 0.00% 100.00% 0.00% Per ISO-NE Staff 58 2014 Billing Statements - NCPC Alloc-Fixed 100.00% 0.00% 50.00% 50.00% Per ISO-NE Staff 59 2020 Settlements-Billing Disputes Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 60 2021 Settlements-Analysis & Reporting Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 61 2022 Settlements-Demand Response Alloc-Fixed 100.00% 0.00% 0.00% 100.00% Per ISO-NE Staff 62 2024 Settlements - ASM Regulation Alloc-Fixed 100.00% 0.00% 0.00% 100.00% Per ISO-NE Staff 63 2025 Settlements - ASM Locational Forward Reserve Alloc-Fixed 100.00% 0.00% 0.00% 100.00% Per ISO-NE Staff 64 2026 Settlements-Batch Processing Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 65 2030 Settlements - ARR Administration Alloc-Fixed 100.00% 0.00% 90.00% 10.00% Per ISO-NE Staff 66 2032 Settlements - Billing STLM Labor 100.00% 14.79% 48.71% 36.50% Per ISO-NE Staff 67 2033 Settlements - Market Analysis Alloc-Fixed 100.00% 0.00% 100.00% 0.00% Per ISO-NE Staff 68 2034 Settlements - COPQ Alloc-Fixed 100.00% 15.00% 40.00% 45.00% Per ISO-NE Staff 69 2036 MAS - Market Analysis - Projects Alloc-Fixed 100.00% 0.00% 100.00% 0.00% Per ISO-NE Staff 70 2037 MAS - Bill Job Aid Alloc-Fixed 100.00% 15.00% 60.00% 25.00% Per ISO-NE Staff 71 2039 MAS - BITT and Business Tools Alloc-Fixed 100.00% 15.00% 60.00% 25.00% Per ISO-NE Staff 72 2043 MAS - Release Checkout and Support Alloc-Fixed 100.00% 15.00% 60.00% 25.00% Per ISO-NE Staff 73 2044 MAS - EQR Reporting Alloc-Fixed 100.00% 15.00% 60.00% 25.00% Per ISO-NE Staff 74 2047 MAS - Score Card Alloc-Fixed 100.00% 14.79% 48.71% 36.50% Per ISO-NE Staff 75 2048 MAS - FCM Alloc-Fixed 100.00% 0.00% 0.00% 100.00% Per ISO-NE Staff 76 2049 MAS - Product Testing Alloc-Fixed 100.00% 0.00% 80.00% 20.00% Per ISO-NE Staff 77 2050 MAS - Business Acceptance Testing Alloc-Fixed 100.00% 0.00% 80.00% 20.00% Per ISO-NE Staff 78 2051 MAS - Legal Support Alloc-Fixed 100.00% 0.00% 50.00% 50.00% Per ISO-NE Staff 79 2052 MAS - FERC Data Request Alloc-Fixed 100.00% 0.00% 50.00% 50.00% Per ISO-NE Staff 80 2053 MAS - Tariff Change Coordination (TCC) Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 81 2054 MAS - Markets Development Support Alloc-Fixed 100.00% 0.00% 50.00% 50.00% Per ISO-NE Staff ISO NEW ENGLAND INC. Exhibit 3 (RCL-3) FERC DOCKET NO. ER15-___-000 Schedule 5.0 ALLOCATION FACTORS BY COST CATEGORY Page 6 of 11 TEST YEAR 2015
Line Activity Code Allocation Self-Funding Tariff No. No. Description Factor Total Schedule 1 Schedule 2 Schedule 3 Reference (a) (b) (c) (d) (e) (f) (g) (h)
1 Market Operations Support Services 2 3000 MOSS - Hourly Settlements Support Alloc-Fixed 100.00% 0.00% 50.00% 50.00% Per ISO-NE Staff 3 3002 MOSS - Monthly Settlements Support Alloc-Fixed 100.00% 50.00% 0.00% 50.00% Per ISO-NE Staff 4 3003 MOSS - Market Analysis Support Alloc-Fixed 100.00% 0.00% 100.00% 0.00% Per ISO-NE Staff 5 3004 MOSS - Generation & Load Admin Support Alloc-Fixed 100.00% 0.00% 100.00% 0.00% Per ISO-NE Staff 6 3005 MOSS - Demand Resource Admin Support Alloc-Fixed 100.00% 0.00% 100.00% 0.00% Per ISO-NE Staff 7 3006 MOSS - Customer Service Alloc-Fixed 100.00% 0.00% 100.00% 0.00% Per ISO-NE Staff 8 3007 MOSS - NEPOOL Committees Support Alloc-Fixed 100.00% 0.00% 50.00% 50.00% Per ISO-NE Staff 9 3008 MOSS - Admin Support Alloc-Fixed 100.00% 0.00% 100.00% 0.00% Per ISO-NE Staff 10 3009 MOSS - Indirect Supervision (Principal Analysts only) Alloc-Fixed 100.00% 0.00% 100.00% 0.00% Per ISO-NE Staff 11 3010 MOSS - Employee Development Alloc-Fixed 100.00% 0.00% 100.00% 0.00% Per ISO-NE Staff 12 3011 MOSS - Release Checkout and Support Alloc-Fixed 100.00% 0.00% 100.00% 0.00% Per ISO-NE Staff 13 3012 MOSS - FERC Data Request Alloc-Fixed 100.00% 0.00% 100.00% 0.00% Per ISO-NE Staff 14 3013 MOSS - Tariff Change Coordination (TCC) Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 15 3014 MOSS - Markets Development Support Alloc-Fixed 100.00% 0.00% 50.00% 50.00% Per ISO-NE Staff 16 17 406 Market Services 18 16001 Participant/membership support Alloc-Fixed 100.00% 0.00% 50.00% 50.00% Per ISO-NE Staff 19 16006 Call Support (HEAT) Alloc-Fixed 100.00% 26.00% 66.00% 8.00% Per ISO-NE Staff 20 16401 MSS NEPOOL Reliability Committee MS Labor 100.00% 0.00% 90.00% 10.00% Per ISO-NE Staff 21 16403 MSS NEPOOL Market Committee MS Labor 100.00% 0.00% 90.00% 10.00% Per ISO-NE Staff 22 16404 MSS NEPOOL Committee Support MS Labor 100.00% 0.00% 90.00% 10.00% Per ISO-NE Staff 23 16407 MSS Employee Development MS Labor 100.00% 0.00% 90.00% 10.00% Per ISO-NE Staff 24 16408 Miscellaneous and Administrative Activities MS Labor 100.00% 0.00% 90.00% 10.00% Per ISO-NE Staff 25 16413 MSS - Market Rules MS Labor 100.00% 0.00% 90.00% 10.00% Per ISO-NE Staff 26 16414 MSS Direct Customer Contact MS Labor 100.00% 0.00% 90.00% 10.00% Per ISO-NE Staff 27 16419 Asset Registration Implemented Alloc-Fixed 100.00% 0.00% 100.00% 0.00% Per ISO-NE Staff 28 16420 Asset Registration Reivew Alloc-Fixed 100.00% 0.00% 100.00% 0.00% Per ISO-NE Staff 29 16421 C10/C30 Audits Alloc-Fixed 100.00% 0.00% 84.00% 16.00% Per ISO-NE Staff 30 16422 Claimed Capability Audits Alloc-Fixed 100.00% 0.00% 100.00% 0.00% Per ISO-NE Staff 31 16423 COPQ/Rework - Cost of Poor Quality Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 32 16424 Demand Resource Audits Alloc-Fixed 100.00% 0.00% 100.00% 0.00% Per ISO-NE Staff 33 16425 DR Registration Implemented Alloc-Fixed 100.00% 0.00% 100.00% 0.00% Per ISO-NE Staff 34 16426 DR Registration Review Alloc-Fixed 100.00% 0.00% 100.00% 0.00% Per ISO-NE Staff 35 16427 MSS Analysis and Reporting Alloc-Fixed 100.00% 0.00% 90.00% 10.00% Per ISO-NE Staff 36 16428 MSS Business Analysis - Issues Management Alloc-Fixed 100.00% 0.00% 90.00% 10.00% Per ISO-NE Staff 37 16429 MSS Business Analysis - Process Improvement Alloc-Fixed 100.00% 0.00% 90.00% 10.00% Per ISO-NE Staff 38 16430 MSS Business Analysis - Committee Monitoring Alloc-Fixed 100.00% 0.00% 90.00% 10.00% Per ISO-NE Staff 39 16431 Network Model Releases and PNODE Activation/Deactivation Alloc-Fixed 100.00% 70.00% 30.00% 0.00% Per ISO-NE Staff 40 16432 New Generation Coordination and Registration Alloc-Fixed 100.00% 0.00% 100.00% 0.00% Per ISO-NE Staff 41 16433 Passive Resource Performance and M&V Review Alloc-Fixed 100.00% 0.00% 100.00% 0.00% Per ISO-NE Staff 42 16434 QMS/CAPA Process and Procedure Updates Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 43 16435 Resource Performance Monitoring Alloc-Fixed 100.00% 0.00% 100.00% 0.00% Per ISO-NE Staff 44 45 410 Market Training and Reliability Contracts 46 19113 RMR Contract Administration Alloc-Fixed 100.00% 0.00% 0.00% 100.00% Per ISO-NE Staff 47 16021 Training Development Alloc-Fixed 100.00% 0.00% 50.00% 50.00% Per ISO-NE Staff 48 16024 Training Delivery Alloc-Fixed 100.00% 0.00% 50.00% 50.00% Per ISO-NE Staff 49 21504 Employee Development Alloc-Fixed 100.00% 0.00% 50.00% 50.00% Per ISO-NE Staff 50 51 204 System Planning 52 18148 SP - NEPOOL Committee Support Alloc-Fixed 100.00% 0.00% 100.00% 0.00% Per ISO-NE Staff 53 18149 SP - National Committee Support Alloc-Fixed 100.00% 0.00% 100.00% 0.00% Per ISO-NE Staff 54 18150 SP - Regional Transmission Expansion Plan Alloc-Fixed 100.00% 75.00% 25.00% 0.00% Per ISO-NE Staff 55 18152 States Requests Alloc-Fixed 100.00% 50.00% 25.00% 25.00% Per ISO-NE Staff 56 18401 SP - Regional Activities Alloc-Fixed 100.00% 100.00% 0.00% 0.00% Per ISO-NE Staff 57 18402 SP - Transmission Planning/Economic Studies Initiative Alloc-Fixed 100.00% 0.00% 50.00% 50.00% Per ISO-NE Staff 58 18461 SP - NERC Activities Alloc-Fixed 100.00% 100.00% 0.00% 0.00% Per ISO-NE Staff 59 18501 SP - Regulatory Activities Alloc-Fixed 100.00% 100.00% 0.00% 0.00% Per ISO-NE Staff 60 18521 SP - Employee Development SP Labor 100.00% 24.83% 17.73% 57.44% Per ISO-NE Staff 61 18531 SP - Indirect Supervision/Clerical Support SP Labor 100.00% 24.83% 17.73% 57.44% Per ISO-NE Staff 62 18532 SP - New England Governors' Study Request Alloc-Fixed 100.00% 100.00% 0.00% 0.00% Per ISO-NE Staff 63 18561 SP - NEPOOL Administrative Support - Schedule 3 Tariff Alloc-Fixed 100.00% 0.00% 0.00% 100.00% Per ISO-NE Staff 64 18562 SP - Project Management Alloc-Fixed 100.00% 100.00% 0.00% 0.00% Per ISO-NE Staff ISO NEW ENGLAND INC. Exhibit 3 (RCL-3) FERC DOCKET NO. ER15-___-000 Schedule 5.0 ALLOCATION FACTORS BY COST CATEGORY Page 7 of 11 TEST YEAR 2015
Line Activity Code Allocation Self-Funding Tariff No. No. Description Factor Total Schedule 1 Schedule 2 Schedule 3 Reference (a) (b) (c) (d) (e) (f) (g) (h)
1 203 Resource Adequacy 2 18101 LF - Develop Load Forecast Alloc-Fixed 100.00% 20.00% 20.00% 60.00% Per ISO-NE Staff 3 18121 SP - Operations Forecast Support Alloc-Fixed 100.00% 20.00% 20.00% 60.00% Per ISO-NE Staff 4 18131 LF - Other Load Forecasting Activities Alloc-Fixed 100.00% 20.00% 20.00% 60.00% Per ISO-NE Staff 5 18132 LF - NEPOOL Administrative Support SP Labor 100.00% 24.83% 17.73% 57.44% Per ISO-NE Staff 6 14307 PSR - NEPOOL Documents Revision Support Alloc-Fixed 100.00% 33.00% 33.00% 34.00% Per ISO-NE Staff 7 14309 PSR - Markets Management and Implementation Alloc-Fixed 100.00% 0.00% 100.00% 0.00% Per ISO-NE Staff 8 14313 PSR - National Committee Support PSR Labor 100.00% 10.87% 5.05% 84.09% Per ISO-NE Staff 9 14315 PSR - Employee Development PSR Labor 100.00% 10.87% 5.05% 84.09% Per ISO-NE Staff 10 17101 PSR Analysis Alloc-Fixed 100.00% 0.00% 70.00% 30.00% Per ISO-NE Staff 11 17131 PSR - Calculate Objective Capability Alloc-Fixed 100.00% 0.00% 0.00% 100.00% Per ISO-NE Staff 12 17201 PSR Regulatory Liaison Alloc-Fixed 100.00% 0.00% 30.00% 70.00% Per ISO-NE Staff 13 17231 PSR Regulatory Filings Alloc-Fixed 100.00% 0.00% 0.00% 100.00% Per ISO-NE Staff 14 17241 PSR-Transmission Plan Admin Support Alloc-Fixed 100.00% 50.00% 50.00% 0.00% Per ISO-NE Staff 15 17251 PSR-Regional Bulk Power System Assessment Alloc-Fixed 100.00% 50.00% 50.00% 0.00% Per ISO-NE Staff 16 17301 PSR 18.4 Applications Alloc-Fixed 100.00% 0.00% 0.00% 100.00% Per ISO-NE Staff 17 17331 PSR NEPOOL Committee Support PSR Labor 100.00% 10.87% 5.05% 84.09% Per ISO-NE Staff 18 17361 PSR Regional Committee Support PSR Labor 100.00% 10.87% 5.05% 84.09% Per ISO-NE Staff 19 17401 PSR Indirect Supervisory Activities PSR Labor 100.00% 10.87% 5.05% 84.09% Per ISO-NE Staff 20 17402 PSR - Project Management Alloc-Fixed 100.00% 100.00% 0.00% 0.00% Per ISO-NE Staff 21 17403 TCA Application Review Alloc-Fixed 100.00% 0.00% 0.00% 100.00% Per ISO-NE Staff 22 17404 Non-Transmission Alternative Analyses Alloc-Fixed 100.00% 0.00% 50.00% 50.00% Per ISO-NE Staff 23 17405 Energy Efficiency Forecast Alloc-Fixed 100.00% 0.00% 0.00% 100.00% Per ISO-NE Staff 24 17406 SP - North American Energy Standards Board (NAESB) Alloc-Fixed 100.00% 0.00% 50.00% 50.00% Per ISO-NE Staff 25 17407 SP - National Standards Work Alloc-Fixed 100.00% 0.00% 50.00% 50.00% Per ISO-NE Staff 26 17408 MA-EEAC Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 27 17501 FCA - Evaluate Existing Resource De-list Bids Alloc-Fixed 100.00% 0.00% 0.00% 100.00% Per ISO-NE Staff 28 17502 FCA - Preliminary Review of Show of Interest Applications Alloc-Fixed 100.00% 0.00% 0.00% 100.00% Per ISO-NE Staff 29 17503 FCA - New Resource Qualification Support Alloc-Fixed 100.00% 0.00% 0.00% 100.00% Per ISO-NE Staff 30 17504 FCA - Perform Transmission / Topology Assessments Alloc-Fixed 100.00% 0.00% 0.00% 100.00% Per ISO-NE Staff 31 17505 FCA - Perform Existing Resource Qualification Alloc-Fixed 100.00% 0.00% 0.00% 100.00% Per ISO-NE Staff 32 17506 FCA - Composite Offer Review Alloc-Fixed 100.00% 0.00% 0.00% 100.00% Per ISO-NE Staff 33 17507 FCA - Auctions & Filings Alloc-Fixed 100.00% 0.00% 0.00% 100.00% Per ISO-NE Staff 34 17508 FCA - Annual Reconfiguration Auction Support/Reliability Review Alloc-Fixed 100.00% 0.00% 0.00% 100.00% Per ISO-NE Staff 35 36 205 Transmission Planning 37 11201 System Design Task Force Alloc-Fixed 100.00% 100.00% 0.00% 0.00% Per ISO-NE Staff 38 18201 TR - Transmission System Assessment Alloc-Fixed 100.00% 100.00% 0.00% 0.00% Per ISO-NE Staff 39 18251 TR - Dynamic Swing Recorder Project Alloc-Fixed 100.00% 100.00% 0.00% 0.00% Per ISO-NE Staff 40 18261 TR - Transmission Tariff Information Requirements Alloc-Fixed 100.00% 100.00% 0.00% 0.00% Per ISO-NE Staff 41 18301 TR - NEPOOL Administrative Support - Schedule 1 Tariff Alloc-Fixed 100.00% 100.00% 0.00% 0.00% Per ISO-NE Staff 42 18331 TR - SIS Preparatory Arrangements Alloc-Fixed 100.00% 100.00% 0.00% 0.00% Per ISO-NE Staff 43 18333 TR - General SIS/FS Alloc-Fixed 100.00% 100.00% 0.00% 0.00% Per ISO-NE Staff 44 18334 TR - Indirect Supervision/Clerical Support TP Labor 100.00% 100.00% 0.00% 0.00% Per ISO-NE Staff 45 18335 TR - Regulatory Activities - NPCC TP Labor 100.00% 100.00% 0.00% 0.00% Per ISO-NE Staff 46 18336 TR - National Activities TP Labor 100.00% 100.00% 0.00% 0.00% Per ISO-NE Staff 47 18337 TR - Regulatory Activities TP Labor 100.00% 100.00% 0.00% 0.00% Per ISO-NE Staff 48 18338 TR - Employee Development TP Labor 100.00% 100.00% 0.00% 0.00% Per ISO-NE Staff 49 18339 SWCT RFP 2004 Transmission Assess. TP Labor 100.00% 0.00% 0.00% 100.00% Per ISO-NE Staff 50 18340 TR - NERC Compliance - Old TP Labor 100.00% 100.00% 0.00% 0.00% Per ISO-NE Staff 51 18341 TR – NERC Compliance TP Labor 100.00% 100.00% 0.00% 0.00% Per ISO-NE Staff 52 18342 TR - Project Management TP Labor 100.00% 100.00% 0.00% 0.00% Per ISO-NE Staff 53 18343 FERC Order 1000 Alloc-Fixed 100.00% 0.00% 0.00% 100.00% Per ISO-NE Staff ISO NEW ENGLAND INC. Exhibit 3 (RCL-3) FERC DOCKET NO. ER15-___-000 Schedule 5.0 ALLOCATION FACTORS BY COST CATEGORY Page 8 of 11 TEST YEAR 2015
Line Activity Code Allocation Self-Funding Tariff No. No. Description Factor Total Schedule 1 Schedule 2 Schedule 3 Reference (a) (b) (c) (d) (e) (f) (g) (h)
1 304 Program Management 2 801 Program Management - Administration Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 3 1661 ISO Program Management Alloc-Fixed 100.00% 0.00% 70.00% 30.00% Per ISO-NE Staff 4 25002 PMO Support Alloc-Fixed 100.00% 30.00% 35.00% 35.00% Per ISO-NE Staff 5 25003 Emerging Work Initiatives Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 6 25706 SMD Minor System Enhancements Alloc-Fixed 100.00% 0.00% 90.00% 10.00% Per ISO-NE Staff 7 25739 Backup Control Center - Test Alloc-Fixed 100.00% 45.00% 45.00% 10.00% Per ISO-NE Staff 8 25741 SSAE 16 Audit Corrective Action Alloc-Fixed 100.00% 33.33% 33.33% 33.33% Per ISO-NE Staff 9 25758 Demand Response Reserve Pilot P1 Alloc-Fixed 100.00% 0.00% 50.00% 50.00% Per ISO-NE Staff 10 25759 Demand Response Reserve Pilot P2 Alloc-Fixed 100.00% 50.00% 25.00% 25.00% Per ISO-NE Staff 11 25788 Facilities Transition Phase 2 Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 12 25795 Long Term Transmission Rights (LTTR) Alloc-Fixed 100.00% 0.00% 100.00% 0.00% Per ISO-NE Staff 13 25798 Architecture Standardization - Phase II Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 14 25822 System Restoration and Blackstart Resource Resource Mgmnt Alloc-Fixed 100.00% 100.00% 0.00% 0.00% Per ISO-NE Staff 15 25825 Tariff Management Software Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 16 25835 FCM Phase III Alloc-Fixed 100.00% 0.00% 0.00% 100.00% Per ISO-NE Staff 17 25840 GE Wind Study Alloc-Fixed 100.00% 0.00% 50.00% 50.00% Per ISO-NE Staff 18 25843 IR Resolution - CAPA Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 19 25849 Allowable Smart Grid SIDU Alloc-Fixed 100.00% 15.00% 15.00% 70.00% Per ISO-NE Staff 20 25850 Unallowable Smart Grid SIDU Alloc-Fixed 100.00% 15.00% 15.00% 70.00% Per ISO-NE Staff 21 25855 Operational Enhancements Alloc-Fixed 100.00% 0.00% 0.00% 100.00% Per ISO-NE Staff 22 25862 Interconnection Agreements PM Tool Alloc-Fixed 100.00% 0.00% 0.00% 100.00% Per ISO-NE Staff 23 25868 Information Delivery OE Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 24 25869 5.21.5 Smart Grid KEMA Admin Alloc-Fixed 100.00% 15.00% 15.00% 70.00% Per ISO-NE Staff 25 25891 Wind Integration Project Alloc-Fixed 100.00% 0.00% 50.00% 50.00% Per ISO-NE Staff 26 25896 Business Intelligence Phase 2 Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 27 25902 Coordinated Transaction Scheduling - O&M Alloc-Fixed 100.00% 70.00% 30.00% 0.00% Per ISO-NE Staff 28 25910 Generation Control Applications (GCA) Phase II Alloc-Fixed 100.00% 50.00% 50.00% 0.00% Per ISO-NE Staff 29 25911 Strategic Planning Initiatives Alloc-Fixed 100.00% 0.00% 0.00% 100.00% Per ISO-NE Staff 30 25912 Generation Auditing - Claim 10/30 Alloc-Fixed 100.00% 0.00% 0.00% 100.00% Per ISO-NE Staff 31 25914 Divisional Accounting (for Market Participants) Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 32 25918 Day Ahead Market Timeline Change Alloc-Fixed 100.00% 20.00% 60.00% 20.00% Per ISO-NE Staff 33 25919 Alternative Technologies & Regulation Market Alloc-Fixed 100.00% 0.00% 0.00% 100.00% Per ISO-NE Staff 34 25926 Hourly Market Alloc-Fixed 100.00% 40.00% 30.00% 30.00% Per ISO-NE Staff 35 25935 Control Room Visualization Alloc-Fixed 100.00% 100.00% 0.00% 0.00% Per ISO-NE Staff 36 25948 FCA 9 Alloc-Fixed 100.00% 0.00% 0.00% 100.00% Per ISO-NE Staff 37 25953 ICCP and ED Network Upgrades Alloc-Fixed 100.00% 90.00% 0.00% 10.00% Per ISO-NE Staff 38 25955 Financial Assurance BI Integration Alloc-Fixed 100.00% 0.00% 50.00% 50.00% Per ISO-NE Staff 39 40 315 Business Architecture and Technology 41 21201 Business Architecture and Technology Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 42 21202 BAT - Indirect Supervision/Clerical Support Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 43 21203 BAT - Employee Development Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 44 21204 BAT - Market Standardization Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 45 21205 BAT - System Architecture Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 46 21206 BAT - Smart Grid Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 47 48 408 Market Development Administration 49 16201 Market Rules and Procedures Alloc-Fixed 100.00% 0.00% 40.00% 60.00% Per ISO-NE Staff 50 16605 NEPOOL Committee Support MD Labor 100.00% 0.60% 53.35% 46.05% Per ISO-NE Staff 51 16606 Regional Committee Support MD Labor 100.00% 0.60% 53.35% 46.05% Per ISO-NE Staff 52 16607 National Committee Support MD Labor 100.00% 0.60% 53.35% 46.05% Per ISO-NE Staff 53 16609 Indirect Supervision and Administrative Support MD Labor 100.00% 0.60% 53.35% 46.05% Per ISO-NE Staff 54 16610 NE-NB Better Integration Alloc-Fixed 100.00% 0.00% 100.00% 0.00% Per ISO-NE Staff 55 16611 NY-NE Efficiences Alloc-Fixed 100.00% 0.00% 100.00% 0.00% Per ISO-NE Staff 56 21001 Markets Development Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 57 21002 MD - Indirect Supervision/Clerical Support Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 58 21003 MD - Employee Development Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 59 21005 MD - ICAP Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 60 21007 MD - Budget/Forecast Support Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 61 21009 Increased Scope of Impact Analysis Alloc-Fixed 100.00% 26.00% 66.00% 8.00% Per ISO-NE Staff 62 21102 ME - Indirect Supervision/Clerical Support Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff ISO NEW ENGLAND INC. Exhibit 3 (RCL-3) FERC DOCKET NO. ER15-___-000 Schedule 5.0 ALLOCATION FACTORS BY COST CATEGORY Page 9 of 11 TEST YEAR 2015
Line Activity Code Allocation Self-Funding Tariff No. No. Description Factor Total Schedule 1 Schedule 2 Schedule 3 Reference (a) (b) (c) (d) (e) (f) (g) (h)
1 407 Market Design 2 22601 MDes-Direct Supervision&Clerical Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 3 22602 MDes-Committee Meetings Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 4 22603 MDes-Employee Development Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 5 22606 MDes-Market Analysis/Governing Documents Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 6 22607 MDes - NEPOOL Markets Committee Administration Alloc-Fixed 100.00% 10.00% 45.00% 45.00% Per ISO-NE Staff 7 22608 MDes - Market Rules Alloc-Fixed 100.00% 10.00% 45.00% 45.00% Per ISO-NE Staff 8 22609 MDes - ISO Integration Team Alloc-Fixed 100.00% 20.00% 40.00% 40.00% Per ISO-NE Staff 9 10 409 Demand Resource Strategy 11 22401 Demand Response Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 12 22402 DR-Regulatory Ccmmittees and Working Groups Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 13 22403 DR-IBCS Open Solution Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 14 22404 RFP Linkages Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 15 22406 DR-Filings/Reports Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 16 22407 DR-Evaluation Alloc-Fixed 100.00% 50.0% 20.0% 30.0% Per ISO-NE Staff 17 22408 DR-SWCT RFP Support Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 18 22409 DR - Winter Supplemental Program Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 19 20 210 IT Management 21 6517 Employee Development - Hardware/Software Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 22 6519 Indirect Supervision and Clerical Support Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 23 6552 IT - Security Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 24 6554 IT - NESEC Project Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 25 6555 IT - Procedure Development Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 26 6556 IT - Budget Preparation, Tracking & Forecast Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 27 6557 IT - Information Technology Committee Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 28 6559 IT - Server Consolidation Project Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 29 30 201 IT System/Network & Desktop 31 6510 Desktop Support - Hardware Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 32 6511 Desktop Support - Software Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 33 6512 Host Computer - Hardware Alloc-Fixed 100.00% 0.00% 75.00% 25.00% Per ISO-NE Staff 34 6513 Host Computer - Software Alloc-Fixed 100.00% 0.00% 75.00% 25.00% Per ISO-NE Staff 35 6514 Networking - Hardware Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 36 6515 Networking - Software Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 37 6516 Communications Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 38 6550 IT - Data Communications Support Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 39 6602 Help Desk Support Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 40 6615 IT - Host Computer Monitoring Alloc-Fixed 100.00% 0.00% 50.00% 50.00% Per ISO-NE Staff 41 6616 IT - Desktop Support Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 42 6617 IT - System Administration - Unix Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 43 6618 IT - System Administration - Windows Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 44 6619 IT - Systems Support Misc Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 45 6620 IT - Systems Support - Security Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 46 6621 IT - Network Support Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 47 6622 IT - Network/Systems Compliance 2009 Initiative Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 48 6623 IT - Asset Management Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 49 50 212 IT Cyber Security 51 6539 IT Policy/Procedures Program Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 52 6539A Activation/Reactivation Work Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 53 6540 IT Security Compliance and Reporting Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 54 6540A IT Controls Assessment Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 55 6540B IT Virus/Malware Reporting and Response Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 56 6540D IT Intrusion Monitoring and Response Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 57 6540E IT System Compliance Enhancement Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 58 6541 IT Security SW Tools Program Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 59 6543 Critical Infrastructure Protection WG (NERC) Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 60 6544 Infragrad (FBI) Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 61 6546 IT Internal Audit Support Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 62 6547 IT - Security Training Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 63 6548 CIP Compliance & Monitoring Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff ISO NEW ENGLAND INC. Exhibit 3 (RCL-3) FERC DOCKET NO. ER15-___-000 Schedule 5.0 ALLOCATION FACTORS BY COST CATEGORY Page 10 of 11 TEST YEAR 2015
Line Activity Code Allocation Self-Funding Tariff No. No. Description Factor Total Schedule 1 Schedule 2 Schedule 3 Reference (a) (b) (c) (d) (e) (f) (g) (h)
1 211 IT Enterprise Applications Support 2 21801 IT Markets Software Support - Settlements Alloc-Fixed 100.00% 0.00% 80.00% 20.00% Per ISO-NE Staff 3 21802 IT Markets Software Support - Publishing Alloc-Fixed 100.00% 0.00% 80.00% 20.00% Per ISO-NE Staff 4 21803 IT Markets Software Support - Finance Alloc-Fixed 100.00% 0.00% 80.00% 20.00% Per ISO-NE Staff 5 21804 IT Markets Software Support - Mitigation Alloc-Fixed 100.00% 0.00% 80.00% 20.00% Per ISO-NE Staff 6 21805 IT Markets Software Support - TSO Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 7 21806 IT Markets Software Support - Enterprise Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 8 21807 IT Markets Software Support - Planning Alloc-Fixed 100.00% 0.00% 80.00% 20.00% Per ISO-NE Staff 9 21808 IT CM/QA - Training Delivery to NON-IT Alloc-Fixed 100.00% 0.00% 80.00% 20.00% Per ISO-NE Staff 10 21809 IT CM/QA - Tools Alloc-Fixed 100.00% 0.00% 80.00% 20.00% Per ISO-NE Staff 11 21810 IT Issue Resolution Alloc-Fixed 100.00% 0.00% 80.00% 20.00% Per ISO-NE Staff 12 21811 FSIT - Single Sign On Support Alloc-Fixed 100.00% 0.00% 80.00% 20.00% Per ISO-NE Staff 13 21812 FSIT - GADS Support Alloc-Fixed 100.00% 0.00% 80.00% 20.00% Per ISO-NE Staff 14 21813 FSIT - Service Management Support Alloc-Fixed 100.00% 0.00% 80.00% 20.00% Per ISO-NE Staff 15 21816 CMS Support Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 16 21818 Discoverer Support Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 17 21819 Ceridian Support Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 18 21821 Compliance Management Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 19 9704 NEPOOL OASIS Administration Alloc-Fixed 100.00% 100.00% 0.00% 0.00% Per ISO-NE Staff 20 6571 DBA Support - MOPS Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 21 21706 IT Markets Software Development - Enterprise Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 22 9705 VACAR OASIS Administration Alloc-Fixed 100.00% 100.00% 0.00% 0.00% Per ISO-NE Staff 23 6581 Oracle Support - MOPS Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 24 6591 Data Architect - MOPS Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 25 6594 IT Data Analyst Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 26 6595 IT WEB Application Support Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 27 6596 IT Data Governance Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 28 6702 IT WEB Support Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 29 21814 IT - Manual Database Edit Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 30 31 102 IT Energy Management Systems 32 21600 EMS - Indirect Supervision and Administration Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 33 21601 EMS - Power System Modeling Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 34 21602 EMS - Applications Development Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 35 21603 EMS - Applications Support Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 36 21604 EMS/DTS Support Alloc-Fixed 100.00% 80.00% 20.00% 0.00% Per ISO-NE Staff 37 21605 EMS - DAM Support Alloc-Fixed 100.00% 20.00% 60.00% 20.00% Per ISO-NE Staff 38 21606 EMS - Real-time Market Support Alloc-Fixed 100.00% 20.00% 60.00% 20.00% Per ISO-NE Staff 39 21607 EMS - Forecast Support Alloc-Fixed 100.00% 20.00% 60.00% 20.00% Per ISO-NE Staff 40 21608 EMS - FTR Support Alloc-Fixed 100.00% 0.00% 100.00% 0.00% Per ISO-NE Staff 41 42 210 IT Change Management 43 22501 IT CM/QA - Change Management Support Alloc-Fixed 100.00% 45.00% 45.00% 10.00% Per ISO-NE Staff 44 22502 IT CM/QA - QA Support Alloc-Fixed 100.00% 34.00% 33.00% 33.00% Per ISO-NE Staff 45 22504 IT CM/QA - ISO 900x Support Alloc-Fixed 100.00% 34.00% 33.00% 33.00% Per ISO-NE Staff 46 22505 IT CM/QA - Administrative Alloc-Fixed 100.00% 34.00% 33.00% 33.00% Per ISO-NE Staff 47 22506 IT CM/QA - External Meeting Support Alloc-Fixed 100.00% 34.00% 33.00% 33.00% Per ISO-NE Staff 48 22507 IT CM/QA - Training Delivery to IT Alloc-Fixed 100.00% 34.00% 33.00% 33.00% Per ISO-NE Staff 49 22508 IT CM/QA - Training Delivery to NON-IT Alloc-Fixed 100.00% 34.00% 33.00% 33.00% Per ISO-NE Staff 50 22509 IT CM/QA - Tools Alloc-Fixed 100.00% 34.00% 33.00% 33.00% Per ISO-NE Staff 51 22510 IT CM/QA - Configuration Management Support Alloc-Fixed 100.00% 34.00% 33.00% 33.00% Per ISO-NE Staff 52 22511 IT CM/QA - Professional Training Alloc-Fixed 100.00% 34.00% 33.00% 33.00% Per ISO-NE Staff 53 22512 IT CM/QA - Daily Code Reconciliation Alloc-Fixed 100.00% 34.00% 33.00% 33.00% Per ISO-NE Staff 54 22513 IT NPCC - Product Build Alloc-Fixed 100.00% 0.00% 0.00% 100.00% Per ISO-NE Staff 55 22514 IT NPCC - Service/Maintenance Alloc-Fixed 100.00% 0.00% 0.00% 100.00% Per ISO-NE Staff 56 22515 IT - General Counsel Support Data Retrieval Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 57 58 213 IT Enterprise Applications Development 59 21701 IT Settlement Application Support Alloc-Fixed 100.00% 0.00% 20.00% 80.00% Per ISO-NE Staff 60 21702 IT Corporate Application Support Alloc-Fixed 100.00% 0.00% 20.00% 80.00% Per ISO-NE Staff 61 21703 IT WEB & TSO Application Support Alloc-Fixed 100.00% 0.00% 20.00% 80.00% Per ISO-NE Staff 62 21707 Application Analysis and Conceptual Design Alloc-Fixed 100.00% 0.00% 80.00% 20.00% Per ISO-NE Staff 63 21708 Application Design Evaluation and Selection Alloc-Fixed 100.00% 0.00% 80.00% 20.00% Per ISO-NE Staff 64 21709 Technology Evaluation and Selection Alloc-Fixed 100.00% 0.00% 80.00% 20.00% Per ISO-NE Staff 65 21710 ESD - Indirect Supervision and Administration Alloc-Fixed 100.00% 0.00% 80.00% 20.00% Per ISO-NE Staff 66 21711 EWR and CAPA Analysis Alloc-Fixed 100.00% 0.00% 80.00% 20.00% Per ISO-NE Staff 67 6518 Employee Development - Software Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 68 69 215 IT Software Systems Testing 70 21752 SST-Web Support Alloc-Fixed 100.00% 35.00% 35.00% 30.00% Per ISO-NE Staff 71 21753 SST-TSO Support Alloc-Fixed 100.00% 5.00% 5.00% 90.00% Per ISO-NE Staff 72 21754 SST-Settlement Support Alloc-Fixed 100.00% 35.00% 35.00% 30.00% Per ISO-NE Staff 73 21755 SST-MSS Support Alloc-Fixed 100.00% 40.00% 45.00% 15.00% Per ISO-NE Staff 74 21756 SST-EMS Support Alloc-Fixed 100.00% 35.00% 35.00% 30.00% Per ISO-NE Staff 75 21757 SST-Market Support Alloc-Fixed 100.00% 35.00% 35.00% 30.00% Per ISO-NE Staff 76 21758 SST-Operations Support Alloc-Fixed 100.00% 40.00% 45.00% 15.00% Per ISO-NE Staff 77 21759 SST-Finance Support Alloc-Fixed 100.00% 35.00% 35.00% 30.00% Per ISO-NE Staff 78 21760 SST-Infrastructure Support Alloc-Fixed 100.00% 35.00% 35.00% 30.00% Per ISO-NE Staff ISO NEW ENGLAND INC. Exhibit 3 (RCL-3) FERC DOCKET NO. ER15-___-000 Schedule 5.0 ALLOCATION FACTORS BY COST CATEGORY Page 11 of 11 TEST YEAR 2015
Line Activity Code Allocation Self-Funding Tariff No. No. Description Factor Total Schedule 1 Schedule 2 Schedule 3 Reference (a) (b) (c) (d) (e) (f) (g) (h)
1 216 IT Power System Modeling Management 2 21650 PSMM- Indirect Supervision and Administration Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 3 21651 PSMM- Power System Modeling Alloc-Fixed 100.00% 40.00% 40.00% 20.00% Per ISO-NE Staff 4 21652 PSMM- System Application Support Alloc-Fixed 100.00% 40.00% 40.00% 20.00% Per ISO-NE Staff 5 21653 PSMM-TTSE Support Alloc-Fixed 100.00% 80.00% 20.00% 0.00% Per ISO-NE Staff 6 21654 PSMM- NX9 Administration Alloc-Fixed 100.00% 40.00% 40.00% 20.00% Per ISO-NE Staff 7 21655 PSMM- ICCP Support Alloc-Fixed 100.00% 40.00% 40.00% 20.00% Per ISO-NE Staff 8 21656 PSMM- Transmission Project Management Alloc-Fixed 100.00% 80.00% 20.00% 0.00% Per ISO-NE Staff 9 21657 PSMM- Model On Demand Admin Alloc-Fixed 100.00% 0.00% 0.00% 100.00% Per ISO-NE Staff 10 21658 PSMM- Model on Demand Case Requests Alloc-Fixed 100.00% 0.00% 0.00% 100.00% Per ISO-NE Staff 11 12 703 Reliability and Operations Compliance 13 14801 ROC - Compliance Monitoring Alloc-Fixed 100.00% 40.00% 40.00% 20.00% Per ISO-NE Staff 14 14802 ROC - NEPOOL Committee Support OS Labor 100.00% 50.00% 0.00% 50.00% Per ISO-NE Staff 15 14803 ROC - Regional Committee Support OS Labor 100.00% 50.00% 0.00% 50.00% Per ISO-NE Staff 16 14804 ROC - National Committee Support OS Labor 100.00% 50.00% 0.00% 50.00% Per ISO-NE Staff 17 14805 ROC - Indirect Supervision/Clerical Support Alloc-Fixed 100.00% 55.55% 19.33% 25.12% Per ISO-NE Staff 18 14806 ROC - Employee Development Alloc-Fixed 100.00% 55.55% 19.33% 25.12% Per ISO-NE Staff 19 14807 ROC - Compliance Audit OS Labor 100.00% 50.00% 0.00% 50.00% Per ISO-NE Staff 20 14808 ROC - Change Management Alloc-Fixed 100.00% 45.00% 10.00% 45.00% Per ISO-NE Staff 21 14809 ROC - Tariff Compliance Alloc-Fixed 100.00% 30.00% 60.00% 10.00% Per ISO-NE Staff 22 14810 ROC - NERC Self Certifications Alloc-Fixed 100.00% 85.00% 0.00% 15.00% Per ISO-NE Staff 23 14811 ROC - NERC Spot Check/CVI Alloc-Fixed 100.00% 45.00% 10.00% 45.00% Per ISO-NE Staff 24 14813 ROC - ICP Policy/Procedure Alloc-Fixed 100.00% 40.00% 40.00% 20.00% Per ISO-NE Staff Exhibit 3 (RCL-3) Schedule 6.0 Page 1 of 2
ISO NEW ENGLAND INC. FERC Docket No. ER15-____-000 ALLOCATION ON DEPRECIATION AND AMORTIZATION EXPENSE TEST YEAR 2015
Line Depreciation Self-Funding Tariff No. Description Total Adjustments Adj. Total Total Schedule 1 Schedule 2 Schedule 3 (a) (b) (c) (d) (e) (f) (g) (h) (i) 1 2015 Items: 2 Facilities Project $ - $ - $ - $ - $ - . $ - 3 Back-up Control Center ------3 Furniture, Fixtures, and Equipment 14,286 14,286 14,286 3,079 7,393 3,814 4 Non-Project Capital Spending (Hardware and Software) 166,667 - 166,667 166,667 35,917 86,250 44,500 5 Market Systems and Enhancement Projects 183,333 - 183,333 183,333 39,508 94,875 48,950 6 Non-Market Systems and Enhancement Projects 197,108 - 197,108 197,108 49,486 90,504 57,118 7 Total 2015 Items - $ $ 561,394 $ - $ 561,394 $ 561,394 $ 127,989 $ 279,022 $ 154,383 8 Total 2015 Items - % 100.00% 22.80% 49.70% 27.50% 9 1 2014 Items: 2 Facilities Project $ 9,657 $ - $ 9,657 $ 9,657 $ 2,081 $ 4,998 $ 2,579 3 Back-up Control Center 458,435 - 458,435 458,435 98,793 237,240 122,402 3 Furniture, Fixtures, and Equipment 58,931 58,931 58,931 $ 12,700 $ 30,497 $ 15,735 4 Non-Project Capital Spending (Hardware and Software) 924,791 - 924,791 924,791 $ 199,292 $ 478,579 $ 246,919 5 Market Systems and Enhancement Projects 8,810,762 - 8,810,762 8,810,762 $ 2,727,624 $ 2,787,465 $ 3,295,673 6 Non-Market Systems and Enhancement Projects 1,988,266 - 1,988,266 1,988,266 675,271 656,975 656,021 7 Total 2014 Items - $ $ 12,250,843 $ - $ 12,250,843 $ 12,250,843 $ 3,715,761 $ 4,195,754 $ 4,339,328 8 Total 2014Items - % 100.00% 30.33% 34.25% 35.42% 9 10 2013 Items: 11 Facilities Project $ 20,236 $ - $ 20,236 $ 20,236 $ 4,361 $ 10,472 $ 5,403 12 Back-up Control Center 954,272 - 954,272 954,272 205,646 493,836 254,791 12 Furniture, Fixtures, and Equipment 148,566 148,566 148,566 $ 32,016 $ 76,883 $ 39,667 13 Non-Project Capital Spending (Hardware and Software) 1,565,969 - 1,565,969 1,565,969 $ 337,466 $ 810,389 $ 418,114 14 Market Systems and Enhancement Projects 3,066,305 - 3,066,305 3,066,305 $ 426,792 $ 1,669,272 $ 970,241 15 Non-Market Systems and Enhancement Projects 1,771,913 - 1,771,913 1,771,913 379,936 554,306 837,671 16 Total 2013 Items - $ $ 7,527,261 $ - $ 7,527,261 $ 7,527,261 $ 1,386,217 $ 3,615,157 $ 2,525,887 17 Total 2013 Items - % 100.00% 18.42% 48.03% 33.56% 18 19 2012 Items: 20 Facilities Project $ 21,021 $ - $ 21,021 $ 21,021 $ 4,530 $ 10,879 $ 5,613 21 Back-up Control Center 156,262 - 156,262 156,262 33,675 80,866 41,722 21 Furniture, Fixtures, and Equipment 6,987 6,987 6,987 1,506 3,616 1,865 22 Non-Project Capital Spending (Hardware and Software) 403,082 - 403,082 403,082 86,864 208,595 107,623 23 Market Systems and Enhancement Projects 3,588,521 - 3,588,521 3,588,521 472,382 1,523,669 1,592,470 24 Non-Market Systems and Enhancement Projects 2,314,337 - 2,314,337 2,314,337 634,695 1,003,530 676,111 25 Total 2012 Items - $ $ 6,490,210 $ - $ 6,490,210 $ 6,490,210 $ 1,233,652 $ 2,831,154 $ 2,425,404 26 Total 2012 Items - % 100.00% 19.01% 43.62% 37.37% 27 28 2011 Items: 29 Facilities Project $ 44,743 $ - $ 44,743 $ 44,743 $ 9,642 $ 23,155 $ 11,946 30 Furniture, Fixtures, and Equipment 4,031 4,031 4,031 869 2,086 1,076 31 Non-Project Capital Spending (Hardware and Software) 802 - 802 802 173 415 214 32 Market Systems and Enhancement Projects 1,204,539 - 1,204,539 1,204,539 190,476 175,378 838,685 33 Non-Market Systems and Enhancement Projects 1,388,437 - 1,388,437 1,388,437 321,205 687,129 380,102 34 Total 2011 Items - $ $ 2,642,552 $ - $ 2,642,552 $ 2,642,552 $ 522,364 $ 888,163 $ 1,232,024 35 Total 2011 Items - % 100.00% 19.77% 33.61% 46.62% 36 37 2010 Items: 38 Facilities Project $ 32,037 $ - $ 32,037 $ 32,037 $ 6,904 $ 16,579 $ 8,554 39 Furniture, Fixtures, and Equipment 1,537 1,537 1,537 331 796 410 40 Non-Project Capital Spending (Hardware and Software) ------41 Market Systems and Enhancement Projects 241,328 - 241,328 241,328 105,098 61,505 74,725 42 Non-Market Systems and Enhancement Projects 235,944 - 235,944 235,944 51,433 121,034 63,477 43 Total 2010 Items - $ $ 510,846 $ - $ 510,846 $ 510,846 $ 163,766 $ 199,913 $ 147,167 44 Total 2010 Items - % 100.00% 32.06% 39.13% 28.81% 45 46 2009 Items: 47 Facilities Project $ 14,558 $ - $ 14,558 $ 14,558 $ 3,137 $ 7,534 $ 3,887 48 Furniture, Fixtures, and Equipment 965 965 965 208 500 258 49 Non-Project Capital Spending (Hardware and Software) 313 - 313 313 67 162 83 50 Market Systems and Enhancement Projects 25,580 - 25,580 25,580 20,828 4,753 - 51 Non-Market Systems and Enhancement Projects ------52 Total 2009 Items - $ $ 41,416 $ - $ 41,416 $ 41,416 $ 24,240 $ 12,948 $ 4,228 53 Total 2009 Items - % 100.00% 58.53% 31.26% 10.21% 54 55 2008 Items: 56 Facilities Project $ 20,239 $ - $ 20,239 $ 20,239 $ 4,361 $ 10,474 $ 5,404 57 Furniture, Fixtures, and Equipment 2,968 2,968 2,968 640 1,536 793 58 Non-Project Capital Spending (Hardware and Software) ------59 Market Systems and Enhancement Projects 18,612 - 18,612 18,612 18,612 - - 60 Non-Market Systems and Enhancement Projects 1,848 - 1,848 1,848 398 956 493 61 Total 2008 Items - $ $ 43,667 $ - $ 43,667 $ 43,667 $ 24,011 $ 12,966 $ 6,690 62 Total 2008 Items - % 100.00% 54.99% 29.69% 15.32% Exhibit 3 (RCL-3) Schedule 6.0 Page 2 of 2
ISO NEW ENGLAND INC. FERC Docket No. ER15-____-000 ALLOCATION ON DEPRECIATION AND AMORTIZATION EXPENSE TEST YEAR 2015
Line Depreciation Self-Funding Tariff No. Description Total Adjustments Adj. Total Total Schedule 1 Schedule 2 Schedule 3 (a) (b) (c) (d) (e) (f) (g) (h) (i) 1 2 2007 Items: 3 Facilities Project $ 162,196 $ - $ 162,196 $ 162,196 $ 34,953 $ 83,936 $ 43,306 4 Furniture, Fixtures, and Equipment ------5 Non-Project Capital Spending (Hardware and Software) ------6 Market Systems and Enhancement Projects ------7 Non-Market Systems and Enhancement Projects 3,264 - 3,264 3,264 703 1,689 872 8 Total 2007 Items - $ $ 165,460 $ - $ 165,460 $ 165,460 $ 35,657 $ 85,626 $ 44,178 9 Total 2007 Items - % 100.00% 21.55% 51.75% 26.70% 10 11 2006 Items: 12 Facilities Project $ 570,895 $ - $ 570,895 $ 570,895 $ 123,028 $ 295,438 $ 152,429 13 Furniture, Fixtures, and Equipment ------14 Non-Project Capital Spending (Hardware and Software) ------15 Market Systems and Enhancement Projects ------16 Non-Market Systems and Enhancement Projects ------17 Total 2006 Items - $ $ 570,895 $ - $ 570,895 $ 570,895 $ 123,028 $ 295,438 $ 152,429 18 Total 2006 Items - % 100.00% 21.55% 51.75% 26.70% 19 20 2005 Items: 21 Building/property improv. (Renov. workspace, network & voice rewiring) $ 787,995 $ - $ 787,995 $ 787,995 $ 169,813 $ 407,787 $ 210,395 22 Enhancements to Other Existing Market Systems ------23 Hardware and Software Upgrades to existing Non Market Systems ------24 Capital Interest/Fees 14,622 - 14,622 14,622 - 9,577 5,044 25 Internal Development Costs ------26 Amortization of Reg Asset ------27 Total 2005 Items - $ $ 802,617 $ - $ 802,617 $ 802,617 $ 169,813 $ 417,365 $ 215,439 28 Total 2005 Items - % 100.00% 21.16% 52.00% 26.84% 29 30 2004 Items: 31 Building/property improv. (Renov. workspace, network & voice rewiring) $ 41,709 $ - $ 41,709 $ 41,709 $ 8,988 $ 21,585 $ 11,136 32 Enhancements to Other Existing Market Systems ------33 Hardware and Software Upgrades to existing Non Market Systems ------34 Internal Development Costs ------35 Capital Interest/Fees 1,451 - 1,451 1,451 - 950 501 36 Total 2004 Items - $ $ 43,160 $ - $ 43,160 $ 43,160 $ 8,988 $ 22,535 $ 11,637 37 Total 2004 Items - % 100.00% 20.83% 52.21% 26.96% 38 39 Total Budgeted Depreciation $ 31,650,319 $ - $ 31,650,319 $ 31,650,319 $ 7,535,487 $ 12,856,039 $ 11,258,793 40 - % 100.00% 23.81% 40.62% 35.57% Exhibit 3 RCL-5 Schedule 1 ISO NEW ENGLAND INC. 2015 Operating Expense Budget
Line No. Cost Category Amount (a) (b)
1 Revenues and Other Income $ (445,760) 2 Salaries and Overhead 102,300,186 3 Professional Fees & Consultants 12,627,499 4 Building Services 2,983,610 5 Rents/Leases 1,032,228 6 Communication Expenses 2,037,662 7 Computer Services 9,733,234 8 Data Services and Office Expenses 1,263,890 9 NPCC/NERC Dues 5,775,936 10 Insurance Expense 2,007,645 11 Meetings & Related Expenses 1,540,519 12 Education & Training 1,207,168 13 Regulatory Fees, Taxes, and Licenses 360,324 14 CEO Emerging Work Allowance 1,100,000 15 Operating Contingency 700,000 16 Net Expense before Depreciation and Debt Service 144,224,141 17 18 Depreciation and Debt Service 34,090,739 19 20 Total Operating Expense Budget $ 178,314,880 Exhibit 3 RCL - 5 Schedule 2 ISO New England Inc. 2015 Operating Expense Budget Page 1
Line No. Revenues and Other Income 1 Interest income (110,912) 2 Includes fees for Participant training seminars and materials (230,448) 3 Purchase Discounts (104,400) 4 $ (445,760) 5 Salaries and Overhead 6 Salaries 75,459,756 7 Payroll Taxes and Employee Benefits 25,670,020 8 Board Fees and Expenses 1,170,410 9 102,300,186 10 Professional Fees and Consultants 11 Consulting Information Technology support for market system maintenance, Energy 12 Management System maintenance, Network and Desktop Support, Architecture 2,711,775 planning, Cyber Security, IT Asset Management and Network Model Tools.
Market Advisor, Demand Resources, Market Development, Market Services, 13 Various R&D projects including special projects for Impact Analysis, Winter 2,109,080 2014/2015 Reliability, and Improved Tools & Optimization. Resource Adequacy (including Forward Capacity Market Analytical & Auction Work and Load Forecasting), Transmission Planning (including FERC Order 1000, OATT/Generation Interconnection Work & Project Planning, Elective 14 Transmission Upgrade Process, Short Circuit Analysis, and Bulk Power System 2,114,221 Testing & Investigation), Operations Project Support (including Day Ahead Market Changes, Resource Performance & Flexibility and Integration of Variable Resources), Operations, and Operations Planning. 15 Human Resource Consulting and Recruiting Services 1,490,115 16 Legal fees 2,327,000 Includes legal fees for OATT, regulatory filings, energy markets, market rules and proceedings, FERC Order 1000, Price Response Demand, Market 17 Monitoring Support, Sitting costs, TCA allocations, new initiatives/emerging issues funding, tariff and corporate matters, and miscellaneous labor matters. 18 External Affairs 426,898 19 Corporate Communications Support 205,110 20 Market Monitoring 300,000 21 Auditors fees - SSAE Type 16 Audit, Network, Operations, Financial, Pension 652,800 22 Risk and Quality Management and Reliability and Operations Compliance 119,200 23 Finance Support and Payroll Service, Misc Other 171,300 24 12,627,499 Exhibit 3 RCL - 5 Schedule 2 ISO New England Inc. 2015 Operating Expense Budget Page 2
25 Building Services 26 Repairs and maintenance 309,804 27 Utilities 1,420,000 28 Miscellaneous (grounds keeping, supplies, building security) 1,253,806 29 2,983,610 30 Rents/Leases 31 Various office equipment leases 974,199 32 Auto leases and Auto Maintenance 58,029 33 1,032,228 34 Communications Expenses 35 Shared microwave 216,000 36 Network circuits and Internet circuits 816,900 37 Telephone and long distance lines 796,320 38 Miscellaneous maintenance and service items 208,442 39 2,037,662 40 Computer Services 41 Software and licensing costs 1,674,985 42 Maintenance contracts 7,904,049 43 Computer supplies 154,200 44 9,733,234 45 Data Services and Office expenses 46 Office supplies 124,589 47 Postage and courier 35,600 48 Printing Expense 115,140 49 Data Services, Dues, and subscriptions 868,696 50 Office equipment maintenance 100,000 51 Other Miscellaneous 19,865 52 1,263,890 53 54 NPCC/NERC Dues 55 Budget for NPCC and NERC Dues 5,710,368 56 Eastern Interconnect Data Sharing Network Allocation/Dues 65,568 57 5,775,936 58 59 Insurance Expense 60 Property and liability 1,681,125 61 Directors and officers 326,520 62 2,007,645 63 64 Meetings & Related Expenses 1,540,519 Exhibit 3 RCL - 5 Schedule 2 ISO New England Inc. 2015 Operating Expense Budget Page 3
Includes travel and related expenses for stakeholder meetings throughout the region, for regulatory meetings and support including FERC, NERC, 65 NPCC, and state agencies, and for attendance at Industry and Other Conference attendance, in addition to other miscellaneous travel reimbursement and employee service recognition 66 67 Education & Training 1,207,168 Includes funding for Enterprise wide training including Leadership and Management Development, Power System Management Degree 68 Program, Cyber Security Degree Program, Technical and NERC Certification Training, Management and General Training, and Education Reimbursement 69 70 Regulatory Fees, Taxes and Licenses 71 Real estate tax 240,000 72 Business license and Bank Fees 120,324 73 360,324 74 75 CEO Emerging Work Allowance 76 New activities and initiatives that occur during the year. 1,100,000 77 78 Operating Contingency 79 Funding of last resort to cover unknown expenses. 700,000 80 81 Depreciation and Debt Service of Capitalized Costs 82 Depreciation and Amortization expense and Disposal 31,764,715 83 Interest expense 2,326,024 84 34,090,739 85 86 Total Operating Expense Budget $ 178,314,880 Exhibit 3 RCL-5 Schedule 3 ISO New England Inc. Operating Expense Budget Variance Summary Proposed Year 2015 Budget vs 2014 Budget (amounts in thousands)
Proposed Variance 2015 Annual Budget Original 2014 Budget vs 2014 Line No. DESCRIPTION 2015 Budget Budget Inc/(Decrease)
1 Revenues and Other Income $ (445.8) $ (459.9) $ 14.1 2 Salaries and Overhead 102,300.2 96,893.6 5,406.6 3 Professional Fees & Consultants 12,627.5 13,194.2 (566.7) 4 Building Services 2,983.6 3,095.4 (111.8) 5 Rents/Leases 1,032.2 1,002.3 29.9 6 Communication Expenses 2,037.7 2,047.6 (10.0) 7 Computer Services 9,733.2 8,583.1 1,150.1 8 Data Services and Office Expenses 1,263.9 1,178.8 85.1 9 NPCC/NERC Dues 5,775.9 5,322.6 453.3 10 Insurance Expense 2,007.6 2,011.3 (3.7) 11 Meetings & Related Expenses 1,540.5 1,526.1 14.4 12 Education & Training 1,207.2 1,234.7 (27.5) 13 Regulatory Fees, Taxes, and Licenses 360.3 342.7 17.6 14 CEO Emerging Work Allowance 1,100.0 1,100.0 - 15 Operating Contingency 700.0 700.0 - 16 Net Expense before Depreciation and Debt Service 144,224.1 137,772.7 6,451.5 17 18 Depreciation and Debt Service 34,090.7 31,551.5 2,539.2 19 20 Total Operating Expense Budget $ 178,314.9 $ 169,324.2 $ 8,990.7 ISO NEW ENGLAND INC. Change in Operating Expense Budgets Proposed Year 2015 Budget vs. 2014 Budget Exhibit 3 (Amounts in thousands) RCL-5 Line No. Schedule 4 1 Revenues and Other Income Page 1 2 Interest Income 7.9 3 Participant Market Training Fees (2.9) 4 Purchase Discounts 9.1 5 Total change in Revenues and Other Income $ 14.1 6 7 Salaries and Overhead 8 Merit and Promotion 2,800.4 9 Net Increase of 9 Additional Staff, net of change in vacancy rate 1,138.1 10 Post Retirement Benefit and Pension Costs 1,801.8 Health & Dental Plan Rate Increase 322.8 11 Other (includes Increase in Internal Capital Dev Allocation and Salary Rate Changes) (656.5) 12 Total change in Salaries and Overhead 5,406.6 13 14 Professional Fees and Consultants Chief Operating Officer Admin - Winter 2014/2015 $(450)K, Impact Analysis $(200)K, and Other 15 (940.0) Strategic Initiatives related funding $(290)K 16 Transmission Strategy & Services - FERC Order 1000 (500.0) Market Operations Support Services reduction in consultant hours and fees absorbed by 17 (303.0) internal staff 18 IT Power System Modeling Management (160.1) Finance - Backup Control Center (BCC) Moving Expense $(163.3)K offset by Increased Payroll 19 (152.5) Services $10.2K. Other $0.6K System Operations - Administration - $(50)K American Recovery and Reinvestment 20 Act/Department of Energy Reporting, $(12.0)K Synchrophasor Infrastructure and Data (62.0) Utilization (SIDU) related IT System/Network & Desktop - Compliance Analyst $153.6K, Systems and Application Support 21 320.8 $112.8K, IT Help Desk Admin $70.0K, Other $(15.6)K
22 IT Energy Management Systems - market software support for Energy Management System 283.0
Enterprise Application Support - to support SAS development and integration environments 23 173.7 $151.0K, Settlements Market Systems and Market Information System support $17.5K Operations Support Services - Post-MPRP (Maine Power Reliability Program) out-study work 24 $200.0K, Engineering Support $23.0K, Phasor Measurement Unit work $(35.0)K and power 138.0 system and data management training $(50.0)K Transmission Planning - Bulk Power System (BPS) Testing and Investigation $133.7K, Greater 25 Boston Working Group $41.0K, Southeastern Massachusetts/Rhode Island Needs Assessment 131.7 $(43.0)K 26 Market Monitoring - $120.0K for the evaluation of Forward Capacity Auction 10 de-list bids 120.0
27 Resource Adequacy - Load Forecasting Supplemental Staff Support $129.1K. Other $(13.0)K 116.1
Human Resources - Relocation $84.0K, Pension and Voluntary Employee Beneficiary 28 Association services and Pension Benefit Guaranty Corporation premium $19.7K, VISA Costs 79.6 $(44.5)K, Other $14.4K 29 IT Development and Power Systems Support - In-house Training 45.0 30 Market Operations Admin - Forward Capacity Auction Management Fees 45.0 31 Cyber Security Social Engineering Assessment 40.0 32 IT Asset & License Management 24.0 33 Other minor changes 34.0 34 Total change in Professional Fees and Consultants (566.7) 35 Changes include a $(130)K decrease for 2014 UPS Battery replacement (every 4 years), a $(48)K reduction in BCC Cleaning Services upon finalization of contract, $(24)K for North Building Generator Maintenance (every 3 years) a $(12)K reduction in Master Control Center 36 Building Services (111.8) (MCC) Cleaning costs in line with current run rate. These were partially offset by increased electric and gas expense of $105.0K (almost exclusively for the BCC in conjunction with its first full year of operation). Other $(2.8)K. 37 ISO NEW ENGLAND INC. Change in Operating Expense Budgets Proposed Year 2015 Budget vs. 2014 Budget Exhibit 3 (Amounts in thousands) RCL-5 Line No. Schedule 4 Changes for 2015 include an increase in equipment leases of $126K for laptop and desktops at Page 2 the MCC and an auto lease increase of $15.7K for a replacement van and additional car for 38 Rents/Leases 29.9 company travel. These were offset by an $111.8K reduction for the discontinuation of the old (Newington) BCC lease. 39 Costs are essentially flat to 2014 budget. Reductions include $39K for Internet Access by switching vendors, $24K for Shared Microwave, and $23K for additional 3 months reduction (over 2014) for high speed fiber from MCC to BCC (due to shorter distance to new BCC). 40 Communication Expenses (10.0) These were largely offset by $39K for SIDU circuits for which charge back to LCC's ends in June 2015, and removal of $30K phone credit no longer to be received (due to end of contract term). 41 Increased costs for Computer Services include new software maintenance as a result of software upgrades or enhancements completed, or will be completed in 2014, of $545.5K (VMWare Configuration Mgt, PI System [Hourly Market], JBoss), license count increases or contract term changes to remain in conformity to agreements or to allow more widespread use 42 Computer Services 1,150.1 of licenses across the organization equaling $372.2K (Distributed Denial of Service (DDoS) Mitigation software [Cyber Security], DB Enterprise Edition, Business Intelligence Licenses, PI System maintenance [Hourly Market]), and $232.4K for inflationary increases on existing license and maintenance agreements. 43 Increases in Dues & Subscriptions include $32.0K for Veracode Cloud Security Subscriptions 44 Data Services and Office Expenses as part of Security Plan, $23.5K increase in Market Monitoring for Argus Media Oil & Coal 85.1 subscriptions, and $16.0K for other small dollar increases and inflationary items. 45 Pass through of increases in NPCC and NERC budgets of $387.7K plus an increase for the 46 NPCC/NERC Dues 453.3 addition of Eastern Interconnect Data Sharing Network fees of $65.6K. 47 48 Insurance Expense Reflects projected rates from carriers which are flat overall. (3.7) 49 Costs are essentially flat with minor increase for additional NERC and National Meetings and 50 Meetings & Related Expenses 14.4 other travel. 51 Reduced enrollment in Power System $(50.9)K and Cyber Security degreed programs $(13.9)K and Leadership and Management Development training has been reduced $(49.3)K. Offsets 52 Education & Training include NERC certification training for non-operators $50.0K, anti-harassment training $10K (27.5) (every other year), and Distributed Generation Forecast Working Group (DGFWG) Meetings $9.0K. 53 Regulatory Fees, Taxes, and 54 Expected increase in bank fees. 17.6 Licenses 55 56 Total Change in Net Expense before Depreciation and Debt Service $ 6,451.5 57 Depreciation expense is increasing due to a number of large projects which will go live in the second half of 2014 including: Energy Market Offer Flexibility (Hourly Market) to be complete in Q4 2014, Simultaneous Feasibility Test and Market System Upgrade (Q4 2014), Web 58 Depreciation and Debt Service 3,358.5 Enhancements Phase II (Q3 2014), NX9/NX12 Data Integration & Automation Phase II (Q4 2014), Generation Control Application Production Part 1 (Q2 2015) and also as a result of a full year's depreciation on the new Backup Control Center. Reduction in interest expense of $(926)K primarily from the renewal of the $39M Private Placement Debt which is slightly offset by $107K increase in Backup Control Center (BCC) term 59 Interest Expense (819.3) loan fees with the facility now in service and amortization of the interest rate cap on the BCC Debt. 60 Total Depreciation and Debt Service 2,539.2 61 62 Total Change in Operating Expense Budget $ 8,990.7 Exhibit 3 RCL - 5 ISO NEW ENGLAND INC. Schedule 5 Staffing Projections Page 1
2014 Budget 2015 Budget Line No. Department Staff Level Staff Level
1 COO - Administration 8.0 8.0 2 3 System Operations Management 5.0 5.0 4 Operations 59.0 59.0 5 Operations Support Services 31.0 31.0 6 System Operations Support 8.0 8.0 7 System Operations 103.0 103.0 8 9 Resource Adequacy 26.0 24.0 10 Transmission Planning 19.0 19.0 11 Transmission Strategy & Services 9.0 9.0 12 System Planning 8.0 8.0 13 Reliability and Operations Services 3.0 3.0 14 System Planning 65.0 63.0 15 16 Customer Service and Training 14.0 14.0 17 Markets Operations Administration 4.0 6.0 18 Market Operations Support Services 12.0 13.0 19 Settlements 22.0 20.0 20 Market Operations 25.0 25.0 21 Market Operations 77.0 78.0 22 23 Mkt Development Admin 5.0 5.0 24 Market Design 3.0 3.0 25 Markets Development 11.0 11.0 26 Demand Resource Strategy 2.0 2.0 27 Markets Development 21.0 21.0 28 29 Energy Management Systems 26.0 27.0 30 Enterprise Applications Development 18.0 20.0 31 Cyber Security 7.0 7.0 32 Enterprise Applications Support 14.0 15.0 33 Systems/Network & Desktop 36.0 37.0 34 IT Management 6.0 6.0 35 IT System Testing 2.0 2.0 36 Power System Modeling Management 11.0 12.0 37 DB & Ent Support Services 20.0 21.0 38 Sftwr Dev & Pow Sys Supp Admin 4.0 4.0 39 Infra & Ent Supp Svs Admin 3.0 3.0 40 IT Asset & License Management 1.0 1.0 41 Information Technology 148.0 155.0 42 43 Business Architecture and Technology 10.0 10.0 Exhibit 3 RCL - 5 ISO NEW ENGLAND INC. Schedule 5 Staffing Projections Page 2
2014 Budget 2015 Budget Line No. Department Staff Level Staff Level
44 Program Management 20.0 21.0 45 46 Total COO 452.0 459.0 47 48 Chief Executive Officer - Administration 9.0 9.0 49 50 Enterprise Risk Management 10.0 11.0 51 Building Services 3.0 3.0 52 Reliability, Operations, and Compliance 6.0 6.0 53 Finance 20.0 21.0 54 Finance and Compliance 39.0 41.0 55 56 Legal Department 14.0 14.0 57 Corporate Communications & External Affairs 17.0 17.0 58 Legal and Public Affairs 31.0 31.0 59 60 Human Resources 13.0 13.0 61 62 Market Monitoring and Mitigation 5.0 5.0 63 64 Market Monitoring Assessment and Investigation 13.0 13.0 65 66 Internal Audits 5.0 5.0 67 68 Total Administration 115.0 117.0 69 70 Total FTE's 567.0 576.0 71 72 Total Part-timers (X @ 0.5) 1.0 1.0 73 74 Total Number of Employees 568.0 577.0
Note: Staffing levels are net of the estimated and budgeted vacancy. Exhibit 3 RCL - 5 Schedule 6 ISO New England Inc. 2015 Capital Budget
Line No. Description 2015
1 Capital Projects - Approved Charters 2 . Coordinated Transaction Scheduling $ 4,170,500 3 . Generation Control Application (GCA) Production Part 1 1,694,300 4 . Divisional Accounting 1,066,500 5 . Alternative Technologies and Regulation Market (ATRM) 470,000 6 . Forward Capacity Auction (FCA) 9 230,000 7 . Voltage Stability 75,000 8 . Control Room Visualization 47,100 9 Subtotal Projects with Approved Charters 7,753,400 10 Capital Projects in Conceptual Design 11 . Business Continuity Plan Infrastructure Enhancements Phase III 2,000,000 12 . Forward Capacity Auction (FCA) 10 2,000,000 13 . Third Party Financial Transmission Rights (FTR) Administration 1,800,000 14 . Generation Control Application (GCA) Production Part 2 1,500,000 15 . VPN System Upgrade 1,000,000 16 . Issues Resolution Project 2015 1,000,000 17 . Simultaneous Feasibility Test Lite Production Version 1,000,000 18 . Power System Modeling 1,000,000 19 . Quarterly Release Projects 2015 800,000 20 . LMP Calculator Replacement 500,000 21 . Wind Integration Phase II 500,000 22 . Web Enhancements 500,000 23 . Phasor Measurement Unit (PMU) Data Application 500,000 24 . Price Response Demand 300,000 25 . Software Testing Tool 2015 300,000 26 . Other Emerging Work 1,646,600 27 Subtotal Conceptual Design 16,346,600 28 . Non-Project Capital Expenditures 3,400,000 29 . Capitalized Interest and loan fees 500,000 30 TOTAL Capital Projects (including Capitalized Interest) $ 28,000,000 Exhibit 3 RCL-7 Schedule 1
ISO New England Inc. FERC DOCKET NO. ER15- -000 Development of Escalation Factors
From CELT Report (As Published) From Monthly Market Reports Monthly Monthly Monthly Monthly Net Data Source Data Source Month Peak Load Net Energy Peak Load Energy Line No. (MW) (GWH) (MW) (GWH) (a) (b) (c) (d) (e) (f) (g) (h)
1 Aug-00 21,736 11,173 Actual 21,736 11,173 Actual 2 Sep-00 21,369 10,068 Actual 21,369 10,068 Actual 3 Oct-00 18,021 9,989 Actual 18,021 9,989 Actual 4 Nov-00 18,642 10,051 Actual 18,642 10,051 Actual 5 Dec-00 20,088 11,572 Actual 20,088 11,572 Actual 6 Jan-01 19,833 11,466 Actual 19,833 11,466 Actual 7 Feb-01 19,357 10,058 Actual 19,357 10,058 Actual 8 Mar-01 18,622 10,719 Actual 18,622 10,719 Actual 9 Apr-01 16,854 9,425 Actual 16,854 9,425 Actual 10 May-01 18,904 9,818 Actual 18,904 9,818 Actual 11 Jun-01 22,358 10,873 Actual 22,358 10,873 Actual 12 Jul-01 23,952 10,936 Actual 23,952 10,936 Actual 13 Aug-01 24,967 12,246 Actual 24,967 12,246 Actual 14 Sep-01 20,594 10,017 Actual 20,594 10,017 Actual 15 Oct-01 17,246 9,978 Actual 17,246 9,978 Actual 16 Nov-01 18,116 9,751 Actual 18,116 9,751 Actual 17 Dec-01 19,872 10,689 Actual 19,872 10,689 Actual 18 Jan-02 19,241 11,009 Actual 19,241 11,009 Actual 19 Feb-02 19,260 9,785 Actual 19,260 9,785 Actual 20 Mar-02 18,327 10,331 Actual 18,327 10,331 Actual 21 Apr-02 18,450 9,557 Actual 18,450 9,557 Actual 22 May-02 18,287 9,769 Actual 18,287 9,769 Actual 23 Jun-02 22,953 10,317 Actual 22,953 10,317 Actual 24 Jul-02 24,780 12,132 Actual 24,780 12,132 Actual 25 Aug-02 25,348 12,345 Actual 25,348 12,345 Actual 26 Sep-02 22,370 10,379 Actual 22,370 10,379 Actual 27 Oct-02 19,373 10,258 Actual 19,373 10,258 Actual 28 Nov-02 18,763 10,191 Actual 18,763 10,191 Actual 29 Dec-02 20,850 11,382 Actual 20,850 11,382 Actual 30 Jan-03 21,533 12,042 Actual 21,533 12,042 Actual 31 Feb-03 20,410 10,612 Actual 20,410 10,612 Actual 32 Mar-03 20,223 10,848 Actual 20,223 10,848 Actual 33 Apr-03 18,126 9,954 Actual 18,126 9,954 Actual 34 May-03 16,783 9,758 Actual 16,783 9,758 Actual 35 Jun-03 24,494 10,450 Actual 24,494 10,450 Actual 36 Jul-03 23,981 12,269 Actual 23,981 12,269 Actual 37 Aug-03 24,685 12,627 Actual 24,685 12,627 Actual 38 Sep-03 19,339 10,332 Actual 19,339 10,331 Actual 39 Oct-03 18,148 10,228 Actual 18,148 10,228 Actual From CELT Report (As Published) From Monthly Market Reports Monthly Monthly Monthly Monthly Net Data Source Data Source Month Peak Load Net Energy Peak Load Energy Line No. (MW) (GWH) (MW) (GWH) (a) (b) (c) (d) (e) (f) (g) (h)
40 Nov-03 18,551 10,123 Actual 18,551 10,123 Actual 41 Dec-03 20,771 11,534 Actual 20,771 11,534 Actual 42 Jan-04 22,818 12,627 Actual 22,818 12,627 Actual 43 Feb-04 19,977 10,862 Actual 19,977 10,861 Actual 44 Mar-04 19,246 10,896 Actual 19,246 10,896 Actual 45 Apr-04 18,042 9,872 Actual 18,042 9,872 Actual 46 May-04 18,281 10,107 Actual 18,281 10,107 Actual 47 Jun-04 22,940 10,772 Actual 22,940 10,772 Actual 48 Jul-04 23,147 11,911 Actual 23,147 11,911 Actual 49 Aug-04 24,116 12,311 Actual 24,116 12,311 Actual 50 Sep-04 20,829 10,687 Actual 20,829 10,687 Actual 51 Oct-04 17,763 10,315 Actual 17,763 10,315 Actual 52 Nov-04 19,044 10,395 Actual 19,044 10,395 Actual 53 Dec-04 22,631 11,761 Actual 22,631 11,761 Actual 54 Jan-05 22,141 12,235 Actual 22,141 12,235 Actual 55 Feb-05 19,887 10,534 Actual 19,887 10,534 Actual 56 Mar-05 20,178 11,332 Actual 20,178 11,332 Actual 57 Apr-05 17,024 9,832 Actual 17,024 9,832 Actual 58 May-05 16,710 10,010 Actual 16,710 10,010 Actual 59 Jun-05 25,231 11,870 Actual 25,231 11,870 Actual 60 Jul-05 26,885 12,949 Actual 26,885 12,949 Actual 61 Aug-05 25,983 13,332 Actual 25,983 13,332 Actual 62 Sep-05 22,425 11,190 Actual 22,425 11,190 Actual 63 Oct-05 18,970 10,671 Actual 18,972 10,671 Actual 64 Nov-05 19,330 10,463 Actual 19,331 10,463 Actual 65 Dec-05 21,733 11,938 Actual 21,768 11,938 Actual 66 Jan-06 20,559 11,509 Actual 20,559 11,509 Actual 67 Feb-06 20,458 10,504 Actual 20,469 10,504 Actual 68 Mar-06 19,598 11,010 Actual 19,598 11,010 Actual 69 Apr-06 17,146 9,630 Actual 17,146 9,630 Actual 70 May-06 19,411 10,239 Actual 19,411 10,239 Actual 71 Jun-06 24,070 11,331 Actual 24,070 11,331 Actual 72 Jul-06 27,329 13,365 Actual 27,329 13,364 Actual 73 Aug-06 28,130 12,380 Actual 28,130 12,380 Actual 74 Sep-06 19,168 10,244 Actual 19,168 10,244 Actual 75 Oct-06 18,036 10,384 Actual 18,036 10,384 Actual 76 Nov-06 18,945 10,237 Actual 18,938 10,237 Actual 77 Dec-06 20,702 11,255 Actual 20,701 11,255 Actual 78 Jan-07 21,034 11,754 Actual 21,034 11,754 Actual 79 Feb-07 21,640 10,983 Actual 21,640 10,983 Actual 80 Mar-07 21,439 11,208 Actual 21,439 11,208 Actual 81 Apr-07 18,071 10,137 Actual 18,071 10,137 Actual 82 May-07 20,463 10,455 Actual 20,463 10,455 Actual 83 Jun-07 26,055 11,139 Actual 26,055 11,139 Actual 84 Jul-07 24,332 12,380 Actual 24,332 12,380 Actual 85 Aug-07 26,145 12,656 Actual 26,145 12,656 Actual 86 Sep-07 22,570 10,778 Actual 22,570 10,778 Actual 87 Oct-07 19,323 10,599 Actual 19,323 10,599 Actual 88 Nov-07 19,141 10,542 Actual 19,129 10,542 Actual From CELT Report (As Published) From Monthly Market Reports Monthly Monthly Monthly Monthly Net Data Source Data Source Month Peak Load Net Energy Peak Load Energy Line No. (MW) (GWH) (MW) (GWH) (a) (b) (c) (d) (e) (f) (g) (h)
89 Dec-07 21,164 11,837 Actual 21,305 11,837 Actual 90 Jan-08 21,782 11,751 Actual 21,774 11,751 Actual 91 Feb-08 20,498 10,877 Actual 20,489 10,877 Actual 92 Mar-08 18,377 11,002 Actual 18,369 11,002 Actual 93 Apr-08 16,992 9,814 Actual 16,972 9,814 Actual 94 May-08 17,884 9,891 Actual 17,884 9,896 Actual 95 Jun-08 26,111 11,338 Actual 26,138 11,338 Actual 96 Jul-08 24,723 13,021 Actual 24,733 13,021 Actual 97 Aug-08 22,189 11,567 Actual 22,195 11,569 Actual 98 Sep-08 22,189 10,614 Actual 22,204 10,616 Actual 99 Oct-08 17,685 10,185 Actual 17,685 10,185 Actual 100 Nov-08 19,375 10,297 Actual 19,362 10,297 Actual 101 Dec-08 21,022 11,387 Actual 21,022 11,388 Actual 102 Jan-09 20,701 12,004 Actual 20,701 12,005 Actual 103 Feb-09 20,338 10,144 Actual 20,338 10,144 Actual 104 Mar-09 19,622 10,543 Actual 19,622 10,540 Actual 105 Apr-09 18,082 9,517 Actual 18,082 9,515 Actual 106 May-09 17,736 9,667 Actual 17,736 9,663 Actual 107 Jun-09 18,468 9,953 Actual 18,468 9,960 Actual 108 Jul-09 22,621 11,292 Actual 22,621 11,291 Actual 109 Aug-09 25,081 12,553 Actual 25,081 12,557 Actual 110 Sep-09 18,215 9,890 Actual 18,215 9,885 Actual 111 Oct-09 17,326 10,004 Actual 17,326 10,002 Actual 112 Nov-09 17,935 9,750 Actual 17,935 9,750 Actual 113 Dec-09 20,791 11,525 Actual 20,791 11,527 Actual 114 Jan-10 19,901 11,568 Actual 19,902 11,569 Actual 115 Feb-10 19,289 10,143 Actual 19,289 10,143 Actual 116 Mar-10 18,202 10,351 Actual 18,202 10,351 Actual 117 Apr-10 16,356 9,373 Actual 16,356 9,373 Actual 118 May-10 22,823 10,173 Actual 22,823 10,173 Actual 119 Jun-10 24,237 11,230 Actual 24,237 11,230 Actual 120 Jul-10 27,102 13,384 Actual 27,102 13,384 Actual 121 Aug-10 25,691 12,258 Actual 25,691 12,258 Actual 122 Sep-10 25,902 10,670 Actual 25,902 10,670 Actual 123 Oct-10 18,272 9,953 Actual 18,272 9,953 Actual 124 Nov-10 18,237 10,061 Actual 18,237 10,061 Actual 125 Dec-10 20,622 11,606 Actual 20,622 11,606 Actual 126 Jan-11 21,053 11,732 Actual 21,053 11,732 Actual 127 Feb-11 19,980 10,376 Actual 19,980 10,376 Actual 128 Mar-11 18,790 10,690 Actual 18,790 10,690 Actual 129 Apr-11 16,590 9,581 Actual 16,590 9,581 Actual 130 May-11 19,847 9,998 Actual 19,847 9,998 Actual 131 Jun-11 23,322 10,731 Actual 23,322 10,731 Actual 132 Jul-11 27,707 12,934 Actual 27,707 12,934 Actual 133 Aug-11 23,344 11,983 Actual 23,344 11,983 Actual 134 Sep-11 20,315 10,609 Actual 20,315 10,609 Actual 135 Oct-11 17,270 9,861 Actual 17,270 9,861 Actual 136 Nov-11 17,819 9,749 Actual 17,819 9,749 Actual 137 Dec-11 19,357 10,918 Actual 19,357 10,918 Actual From CELT Report (As Published) From Monthly Market Reports Monthly Monthly Monthly Monthly Net Data Source Data Source Month Peak Load Net Energy Peak Load Energy Line No. (MW) (GWH) (MW) (GWH) (a) (b) (c) (d) (e) (f) (g) (h)
138 Jan-12 19,926 11,266 Actual 19,926 11,266 Actual 139 Feb-12 18,333 10,100 Actual 18,333 10,100 Actual 140 Mar-12 18,371 10,104 Actual 18,371 10,104 Actual 141 Apr-12 16,412 9,297 Actual 16,412 9,297 Actual 142 May-12 19,869 10,045 Actual 19,869 10,045 Actual 143 Jun-12 25,678 10,698 Actual 25,678 10,698 Actual 144 Jul-12 25,880 12,837 Actual 25,880 12,837 Actual 145 Aug-12 24,751 12,740 Actual 24,751 12,740 Actual 146 Sep-12 21,439 10,164 Actual 21,439 10,164 Actual 147 Oct-12 16,681 9,751 Actual 16,681 9,751 Actual 148 Nov-12 18,792 10,072 Actual 18,792 10,072 Actual 149 Dec-12 19,119 10,998 Actual 19,133 11,008 Actual 150 Jan-13 20,887 11,508 Actual 20,887 11,508 Actual 151 Feb-13 19,463 10,224 Actual 19,463 10,224 Actual 152 Mar-13 18,460 10,588 Actual 18,460 10,588 Actual 153 Apr-13 16,781 9,432 Actual 16,781 9,432 Actual 154 May-13 22,479 9,835 Actual 22,479 9,835 Actual 155 Jun-13 25,129 10,944 Actual 25,129 10,944 Actual 156 Jul-13 27,379 13,646 Actual 27,379 13,646 Actual 157 Aug-13 22,416 11,573 Actual 22,416 11,573 Actual 158 Sep-13 24,451 10,118 Actual 24,451 10,118 Actual 159 Oct-13 17,207 9,867 Actual 17,207 9,867 Actual 160 Nov-13 19,058 10,142 Actual 19,058 10,142 Actual 161 Dec-13 21,448 11,490 Actual 21,453 11,500 Actual 162 Jan-14 21,293 12,009 Actual 21,334 12,022 Actual 163 Feb-14 19,636 10,448 Actual 19,654 10,468 Actual 164 Mar-14 19,890 11,449 Forecast 19,696 11,037 Actual 165 Apr-14 17,825 10,164 Forecast 16,011 9,452 Actual 166 May-14 19,950 10,567 Forecast 16,185 9,449 Actual 167 Jun-14 25,270 11,700 Forecast 21,228 10,377 Actual 168 Jul-14 28,165 13,452 Forecast 24,409 12,230 Actual 169 Aug-14 28,165 13,095 Forecast 28,165 13,095 Forecast 170 Sep-14 23,340 10,950 Forecast 23,340 10,950 Forecast 171 Oct-14 18,580 10,633 Forecast 18,580 10,633 Forecast 172 Nov-14 20,275 10,721 Forecast 20,275 10,721 Forecast 173 Dec-14 22,575 12,175 Forecast 22,575 12,175 Forecast 174 Jan-15 22,575 12,669 Forecast 22,575 12,669 Forecast 175 Feb-15 21,490 11,162 Forecast 21,490 11,162 Forecast 176 Mar-15 20,025 11,617 Forecast 20,025 11,617 Forecast 177 Apr-15 17,965 10,313 Forecast 17,965 10,313 Forecast 178 May-15 20,145 10,723 Forecast 20,145 10,723 Forecast 179 Jun-15 25,615 11,872 Forecast 25,615 11,872 Forecast 180 Jul-15 28,615 13,650 Forecast 28,615 13,650 Forecast 181 Aug-15 28,615 13,288 Forecast 28,615 13,288 Forecast 182 Sep-15 23,655 11,111 Forecast 23,655 11,111 Forecast 183 Oct-15 18,730 10,790 Forecast 18,730 10,790 Forecast 184 Nov-15 20,445 10,879 Forecast 20,445 10,879 Forecast 185 Dec-15 22,755 12,354 Forecast 22,755 12,354 Forecast From CELT Report (As Published) From Monthly Market Reports Monthly Monthly Monthly Monthly Net Data Source Data Source Month Peak Load Net Energy Peak Load Energy Line No. (MW) (GWH) (MW) (GWH) (a) (b) (c) (d) (e) (f) (g) (h)
1 Annualized Figures 2 Average Total Average Total 3 2001 20,056 125,976 20,056 125,976 4 2002 20,667 127,455 20,667 127,455 5 2003 20,587 130,776 20,587 130,776 6 2004 20,736 132,517 20,736 132,515 7 2005 21,375 136,355 21,378 136,356 8 2006 21,129 132,087 21,130 132,087 9 2007 21,781 134,468 21,792 134,468 10 2008 20,736 131,743 20,736 131,754 11 2009 19,743 126,842 19,743 126,839 12 2010 21,386 130,770 21,386 130,771 13 2011 20,450 129,162 20,450 129,162 14 2012 20,438 128,072 20,439 128,082 15 2013 21,263 129,367 21,264 129,377 16 2014 22,080 137,363 20,954 132,609 17 2015 22,553 140,428 22,553 140,428 18 Annual Escalation 19 2002 1.0304 1.0117 1.0304 1.0117 20 2003 0.9961 1.0261 0.9961 1.0261 21 2004 1.0072 1.0133 1.0072 1.0133 22 2005 1.0308 1.0290 1.0309 1.0290 23 2006 0.9885 0.9687 0.9884 0.9687 24 2007 1.0309 1.0180 1.0314 1.0180 25 2008 0.9520 0.9797 0.9515 0.9798 26 2009 0.9521 0.9628 0.9521 0.9627 27 2010 1.0832 1.0310 1.0832 1.0310 28 2011 0.9562 0.9877 0.9562 0.9877 29 2012 0.9994 0.9916 0.9995 0.9916 30 2013 1.0404 1.0101 1.0404 1.0101 31 2014 1.0384 1.0618 0.9855 1.0250 32 2015 1.0214 1.0223 1.0763 1.0590 33 1.009 1.008 NOT USED 34 Last Five Months of Calendar Year 35 Average Total Average Total 36 Dec-00 19,971 52,852 19,971 52,853 Actual 37 Dec-01 20,159 52,681 20,159 52,681 Actual 38 Dec-02 21,341 54,554 21,341 54,555 Actual 39 Dec-03 20,299 54,844 20,299 54,843 Actual 40 Dec-04 20,877 55,469 20,877 55,469 Actual 41 Dec-05 21,688 57,593 21,696 57,594 Actual 42 Dec-06 20,996 54,499 20,995 54,500 Actual 43 Dec-07 21,669 56,412 21,694 56,412 Actual 44 Dec-08 20,492 54,050 20,494 54,055 Actual 45 Dec-09 19,870 53,722 19,870 53,721 Actual 46 Dec-10 21,745 54,548 21,745 54,548 Actual 47 Dec-11 19,621 53,120 19,621 53,120 Actual 48 Dec-12 20,156 53,725 20,159 53,735 Actual 49 Dec-13 20,916 53,190 20,917 53,200 Actual From CELT Report (As Published) From Monthly Market Reports Monthly Monthly Monthly Monthly Net Data Source Data Source Month Peak Load Net Energy Peak Load Energy Line No. (MW) (GWH) (MW) (GWH) (a) (b) (c) (d) (e) (f) (g) (h)
50 Dec-14 22,587 57,574 22,587 57,574 Forecast 51 Escalation Used for Last Five Months of Calendar Year 52 Dec-01 1.0094 0.9967 Actual 53 Dec-02 1.0586 1.0356 Actual 54 Dec-03 0.9512 1.0053 Actual 55 Dec-04 1.0285 1.0114 Actual 56 Dec-05 1.0392 1.0383 Actual 57 Dec-06 0.9677 0.9463 Actual 58 Dec-07 1.0333 1.0351 Actual 59 Dec-08 0.9446 0.9582 Actual 60 Dec-09 0.9696 0.9938 Actual 61 Dec-10 1.0944 1.0154 Actual 62 Dec-11 0.9023 0.9738 Actual 63 Dec-12 1.0274 1.0116 Actual 64 Dec-13 1.0376 0.9900 Actual 65 Dec-14 1.0798 1.0822 Forecast 66 1.010 1.007 NOT USED Exhibit 3 RCL-7 Schedule 2
ISO New England Inc. FERC DOCKET NO. ER15- -000 Billing Determinants for Calendar Year 2014 and Test Year 2015 TEST YEAR 2015
Schedule 1 Schedule 2 Schedule 3 Financial Transmission Rights Network Load Transaction Units (TUs) Volumes (FTRs) Peak Volumes Export Line Data Month Electrical Load Volumes No. Source Submitted Cleared Virtual Submitted FTR Cleared FTR (kW) Energy TUs (GWH) (kW) (MWh) Virtual Energy Energy Bids Bids
(a) (b) (c) (d) (e) (f) (g) (h) (i) (j) (k) CALENDAR YEAR 2014 1 Jan-14 Actual 21,079,734 1,530,447 225,047 38,358 109,035 24,308 24,907,984 23,207,924 372,580 2 Feb-14 Actual 19,304,615 1,399,296 157,878 23,738 42,473 12,015 21,486,953 21,417,669 206,327 3 Mar-14 Actual 19,338,314 1,495,523 196,447 22,406 46,801 14,158 22,951,994 21,431,553 378,295 4 Apr-14 Actual 15,861,101 1,409,223 232,543 24,648 39,540 11,499 19,763,340 18,152,674 384,899 5 May-14 Actual 16,561,128 1,463,066 257,936 25,882 30,119 11,837 19,767,706 18,602,283 341,919 6 Jun-14 Actual 21,031,184 1,482,683 235,151 21,501 37,446 12,163 21,846,285 23,604,672 467,275 7 Jul-14 Actual 24,074,256 1,583,296 227,882 23,319 25,939 10,190 25,544,304 26,796,981 433,735 8 Aug-14 Est. 22,102,345 a 1,488,319 a 155,762 a 24,136 a 21,404 a 7,253 a 24,331,246 a 24,152,721 a 551,361 a 9 Sep-14 Est. 23,990,502 a 1,402,904 a 229,331 a 29,668 a 32,582 a 10,191 a 21,416,359 a 26,343,753 a 557,322 a 10 Oct-14 Est. 17,018,459 a 1,428,894 a 260,930 a 41,080 a 34,809 a 10,871 a 21,055,770 a 19,705,283 a 613,575 a 11 Nov-14 Est. 18,679,781 a 1,409,777 a 226,118 a 32,679 a 34,516 a 12,046 a 21,105,868 a 21,425,264 a 350,688 a 12 Dec-14 Est. 21,036,855 a 1,534,723 a 239,776 a 28,996 a 34,532 a 11,762 a 23,822,003 a 23,306,949 a 311,267 a 13 Totals 240,078,274 17,628,151 2,644,801 336,411 489,196 148,293 267,999,813 268,147,726 4,969,243 14 15 TEST YEAR 2015 16 Jan-15 Est. 21,395,930 b 1,530,447 a 225,047 a 38,358 a 109,035 a 24,308 a 25,281,604 b 23,556,043 b 316,693 c 17 Feb-15 Est. 19,594,184 b 1,399,296 a 157,878 a 23,738 a 42,473 a 12,015 a 21,809,257 b 21,738,934 b 175,378 c 18 Mar-15 Est. 19,628,389 b 1,495,523 a 196,447 a 22,406 a 46,801 a 14,158 a 23,296,273 b 21,753,026 b 321,551 c 19 Apr-15 Est. 16,099,018 b 1,409,223 a 232,543 a 24,648 a 39,540 a 11,499 a 20,059,790 b 18,424,964 b 327,164 c 20 May-15 Est. 16,809,545 b 1,463,066 a 257,936 a 25,882 a 30,119 a 11,837 a 20,064,222 b 18,881,317 b 290,631 c 21 Jun-15 Est. 21,346,652 b 1,482,683 a 235,151 a 21,501 a 37,446 a 12,163 a 22,173,980 b 23,958,742 b 397,184 c 22 Jul-15 Est. 24,435,370 b 1,583,296 a 227,882 a 23,319 a 25,939 a 10,190 a 25,927,469 b 27,198,936 b 368,675 c 23 Aug-15 Est. 22,433,880 b 1,488,319 a 155,762 a 24,136 a 21,404 a 7,253 a 24,696,215 b 24,515,012 b 468,657 c 24 Sep-15 Est. 24,350,360 b 1,402,904 a 229,331 a 29,668 a 32,582 a 10,191 a 21,737,605 b 26,738,909 b 473,724 c 25 Oct-15 Est. 17,273,736 b 1,428,894 a 260,930 a 41,080 a 34,809 a 10,871 a 21,371,606 b 20,000,862 b 521,539 c 26 Nov-15 Est. 18,959,978 b 1,409,777 a 226,118 a 32,679 a 34,516 a 12,046 a 21,422,456 b 21,746,643 b 298,085 c 27 Dec-15 Est. 21,352,408 b 1,534,723 a 239,776 a 28,996 a 34,532 a 11,762 a 24,179,333 b 23,656,553 b 264,577 c 28 Total 243,679,448 17,628,151 2,644,801 336,411 489,196 148,293 272,019,810 272,169,942 4,223,857
Escalation Factors a 1.00 b 1.015 c 0.85 Exhibit 3 RCL-7 Schedule 3
ISO NEW ENGLAND INC. FERC DOCKET NO. ER15- -000 Rate Design Summary TEST YEAR 2015
Revenue Billing Units Line Requirement for Proposed Rates Calculated Revenue Tariff Schedule No. Test Year 2015 Blocks Total (a) (b) (c) (d) (e) (f) (g) (d) x (e) 1 Schedule 1 $ 37,940,742 2 Network Total 243,679,448 $ 0.15570 /kW-mo. $ 37,940,742 3 Through or Out Service $ 0.00021 /kW-hour 4 5 Schedule 2 $ 77,966,032 6 Transaction Units $ 11,694,905 15.00% 7 INC Offers/DEC Bids $ 33,409 8 Submitted 2,644,801 $ 0.00500 /Offer or Bid $ 13,224 9 Cleared 336,411 $ 0.06000 /Offer or Bid $ 20,185 10 Total 2,981,212 $ 33,409 11 Financial Transmission Rights $ 599,982 12 Submitted FTR Bids $ 419,988 70% 489,196 $ 0.85853 /Bid $ 419,988 13 Cleared FTR Bids $ 179,994 30% 148,293 $ 1.21377 /Bid $ 179,994 14 Total 637,489 $ 599,982 15 16 Energy TUs $ 11,061,515 17 Block 1 First 12,500 12,556,611 $ 0.65101 /TU-hour $ 8,174,438 18 Block 2 Next 27,000 3,138,830 $ 0.59182 /TU-hour $ 1,857,635 19 Block 3 Over 39,500 1,932,710 $ 0.53264 /TU-hour $ 1,029,442 20 Total 17,628,151 $ 11,061,515 21 22 Volumetric Measures $ 66,271,126 85.00% 23 Block 1 First 250,000 144,122,641 $ 0.25517 /mWh $ 36,775,337 24 Block 2 Next 1,250,000 120,460,247 $ 0.23197 /mWh $ 27,943,161 25 Block 3 Over 1,500,000 7,436,922 $ 0.20877 /mWh $ 1,552,628 26 Total 272,019,810 $ 66,271,126 27 28 Total $ 77,966,032 29 30 Schedule 3 $ 52,630,263 31 RT NCP Load Obligation $ 51,067,436 Total 272,169,942 $ 0.18763 /kW-mo. $ 51,067,436 32 Exports $ 1,562,827 Total 4,223,857 $ 0.37000 /mWh $ 1,562,827 33 $ 52,630,263 34 35 Totals $ 168,537,037 $ 168,537,037 Exhibit 3 RCL-7 Schedule 4
ISO NEW ENGLAND INC. FERC DOCKET NO. ER15- -000 Annual Revenue Comparison at Present and Proposed Rates TEST YEAR 2015
Annual Revenue Analysis Line 2015 Billing Units 2014 Approved Rates 2015 Proposed Rates Change Tariff Schedule No. Effective Rates Calculated Revenue Proposed Rates Total Revenue (1) Blocks Total $ % (a) (b) (c) (d) (e) (f) (g) (h) (i) (j) (k) (c) x (d) (i) - (f) (j) / (f) 1 Schedule 1 2 Network Total 243,679,448 $0.15640 /kW-mo. $ 38,111,466 $ 0.15570 /kW-mo. $ 37,940,742 $ (170,724) (0.45)% 3 4 Schedule 2 5 Transaction Units 6 INC Offers/DEC Bids 7 Submitted 2,644,801 $0.00500 /Offer or Bid $ 13,224 $ 0.00500 /Offer or Bid $ 13,224 8 Cleared 336,411 $0.06000 /Offer or Bid $ 20,185 $ 0.06000 /Offer or Bid $ 20,185 9 Total 2,981,212 $ 33,409 $ 33,409 10 Financial Transmission Rights 11 Submitted FTR Bids 489,196 $1.23712 /Bid $ 605,194 $ 0.85853 /Bid $ 419,988 12 Cleared FTR Bids 148,293 $1.76776 /Bid $ 262,146 $ 1.21377 /Bid $ 179,994 13 Total 637,489 $ 867,341 $ 599,982 14 15 Energy Transaction Units 16 Block 1 First 12,500 12,556,611 $0.73167 /TU-hour $ 9,187,296 $ 0.65101 /TU-hour $ 8,174,438 17 Block 2 Next 27,000 3,138,830 $0.66515 /TU-hour $ 2,087,793 $ 0.59182 /TU-hour $ 1,857,635 18 Block 3 Over 39,500 1,932,710 $0.59864 /TU-hour $ 1,156,997 $ 0.53264 /TU-hour $ 1,029,442 19 Total 17,628,151 $ 12,432,086 $ 11,061,515 20 Volumetric Measures 21 Block 1 First 250,000 144,122,641 $0.26149 /mWh $ 37,686,629 $ 0.25517 /mWh $ 36,775,337 22 Block 2 Next 1,250,000 120,460,247 $0.23772 /mWh $ 28,635,810 $ 0.23197 /mWh $ 27,943,161 23 Block 3 Over 1,500,000 7,436,922 $0.21395 /mWh $ 1,591,130 $ 0.20877 /mWh $ 1,552,628 24 Total 272,019,810 $ 67,913,569 $ 66,271,126 25 26 Total $ 81,246,404 $ 77,966,032 $ (3,280,372) (4.04)% 27 Schedule 3 28 RT NCP Load Obligation Total 272,169,942 $0.17790 /kW-mo. $ 48,419,033 $ 0.18763 /kW-mo. $ 51,067,436 29 Exports Total 4,223,857 $0.37000 /mWh $ 1,562,827 $ 0.37000 /mWh $ 1,562,827 30 $ 49,981,860 $ 52,630,263 $ 2,648,403 5.30% 31 32 Totals $ 169,339,729 $ 168,537,037 $ (802,692) (0.47)% Exhibit 3 RCL-7 Schedule 5
ISO NEW ENGLAND INC. FERC DOCKET NO. ER15- -000 Comparison of Schedule 2 Revenues from Transaction Units (TUs) for 2013 TEST YEAR 2015
Comparison Of Monthly TU Data For CY 2013 TUs Per ISO Tariff Filing for TY 2013 TUs Per ISO Tariff Filing for CY 2013 Line Source For TY First Next Over Source For First Next Over Month Total TUs Total TUs No. 2013 12,500 27,000 39,500 TY 2015 12,500 27,000 39,500 (a) (b) (c) (d) (e) (f) (g) (h) (i) (j) (k) Billing Determinants - Energy TUs 1 Jan-13 Jan-12 1,324,495 929,302 286,483 108,709 Actual 1,379,716 972,182 272,225 135,309 2 Feb-13 Feb-12 1,255,618 880,976 271,585 103,056 Actual 1,259,732 910,954 249,608 99,170 3 Mar-13 Mar-12 1,320,775 926,692 285,679 108,404 Actual 1,364,713 966,058 271,209 127,446 4 Apr-13 Apr-12 1,231,865 864,311 266,448 101,107 Actual 1,282,914 925,211 251,382 106,321 5 May-13 May-12 1,355,925 951,355 293,282 111,289 Actual 1,373,164 977,606 269,538 126,020 6 Jun-13 Jun-12 1,377,891 966,766 298,033 113,092 Actual 1,404,233 1,001,923 265,001 137,309 7 Jul-13 Jul-12 1,389,454 974,879 300,534 114,041 Actual 1,466,087 1,045,345 272,437 148,305 8 Aug-13 Aug-11 1,401,012 982,989 303,034 114,989 Actual 1,488,319 1,055,800 282,139 150,380 9 Sep-13 Sep-11 1,254,032 879,864 271,242 102,926 Actual 1,402,904 1,022,927 249,772 130,205 10 Oct-13 Oct-11 1,199,869 841,861 259,527 98,480 Actual 1,428,894 1,031,279 255,871 141,744 11 Nov-13 Nov-11 1,191,721 836,144 257,765 97,812 Actual 1,409,777 1,028,542 249,135 132,100 12 Dec-13 Dec-11 1,285,942 902,253 278,144 105,545 Actual 1,534,723 1,075,119 289,316 170,288 13 Totals 15,588,599 10,937,393 3,371,756 1,279,450 16,795,176 12,012,946 3,177,633 1,604,597 14 15 Totals 15,588,599 16,795,176
16 2013 Approved Rates for Schedule 2 17 $0.71278 $0.64798 $0.58318 $0.71278 $0.64798 $0.58318 18 19 Initial Estimate of Revenue From Energy TUs 20 Jan-13 Jan-12 $ 911,423 $ 662,389 $ 185,636 $ 63,397 Actual $ 948,258 $ 692,952 $ 176,396 $ 78,910 21 Feb-13 Feb-12 $ 864,026 $ 627,942 $ 175,983 $ 60,100 Actual $ 868,885 $ 649,310 $ 161,741 $ 57,834 22 Mar-13 Mar-12 $ 908,862 $ 660,528 $ 185,115 $ 63,219 Actual $ 938,649 $ 688,587 $ 175,738 $ 74,324 23 Apr-13 Apr-12 $ 847,681 $ 616,063 $ 172,653 $ 58,964 Actual $ 884,367 $ 659,472 $ 162,891 $ 62,004 24 May-13 May-12 $ 933,050 $ 678,106 $ 190,042 $ 64,901 Actual $ 944,966 $ 696,818 $ 174,655 $ 73,492 25 Jun-13 Jun-12 $ 948,167 $ 689,093 $ 193,120 $ 65,954 Actual $ 965,942 $ 714,151 $ 171,715 $ 80,076 26 Jul-13 Jul-12 $ 956,122 $ 694,876 $ 194,740 $ 66,506 Actual $ 1,008,123 $ 745,101 $ 176,534 $ 86,489 27 Aug-13 Aug-11 $ 964,077 $ 700,656 $ 196,361 $ 67,061 Actual $ 1,023,072 $ 752,553 $ 182,820 $ 87,699 28 Sep-13 Sep-11 $ 862,934 $ 627,149 $ 175,761 $ 60,024 Actual $ 966,902 $ 729,122 $ 161,847 $ 75,933 29 Oct-13 Oct-11 $ 825,663 $ 600,062 $ 168,168 $ 57,433 Actual $ 983,537 $ 735,075 $ 165,799 $ 82,662 30 Nov-13 Nov-11 $ 820,055 $ 595,987 $ 167,026 $ 57,042 Actual $ 971,597 $ 733,124 $ 161,434 $ 77,038 31 Dec-13 Dec-11 $ 884,892 $ 643,108 $ 180,233 $ 61,552 Actual $ 1,053,103 $ 766,323 $ 187,471 $ 99,309 32 Totals $ 10,726,951 $ 7,795,959 $ 2,184,838 $ 746,154 $ 11,557,399 $ 8,562,588 $ 2,059,043 $ 935,769 33
Total Energy TU- Revenue $ 10,726,951 $ 11,557,399 34 35 Total Rate ($) Total Rate ($) 36 Submitted Virtual Energy Bids/Offers TUs 2,861,066 $0.00500 14,305 2,602,981 $0.00500 13,015 37 Cleared Virtual Energy Bids/Offers TUs 333,192 $0.06000 19,992 311,438 $0.06000 18,686 38 $ 34,297 $ 31,701 39 Total Rate ($) Total Rate ($) 40 Submitted FTR Bid TUs 314,616 $1.12347 353,462 391,618 $1.12347 439,971 41 Cleared FTR Bid TUs 101,405 $1.49385 151,484 121,553 $1.49385 181,582 42 $ 504,946 $ 621,553 43
Total Schedule 2 TU- Revenue $ 11,266,194 $ 12,210,653 44 45 Final True-Up - Over (Under) Recovery For Jan - Dec 2013 $ 944,459 Exhibit 3 RCL-7 Schedule 6
ISO NEW ENGLAND INC. FERC DOCKET NO. ER15- -000 Schedule 2 TU True-Up Summary TEST YEAR 2015
Line Total Schedule 2 TU No. Revenues % TU Difference 1 2 Final 2013 True-Up 3 2013 Final TU Collections $ 12,210,653 4 2012 Projected TU Collections in TY 2013 Filing $ 11,266,194 5 Final Schedule 2 TU Over/(Under) Collection $ 944,459 8.38% 6 7 8 Initial Allocation to Volumetric 50% N/A - Over Collected 9 2013 Final True-Up (as calculated above) 10 Total Projected Undercollection to Vol. Meas. 11 12 Allocated to 13 Total TUs VMs 14 Schedule 2 Allocation before True-up $ 77,966,032 $ 11,694,905 $ 66,271,127 15 Allocated TU Under-recovery $ - $ - $ - 16 Total Revenue Requirement After True-Up $ 77,966,032 $ 11,694,905 $ 66,271,127 17 % Allocation 100.00% 15.00% 85.00% Exhibit 3 RCL-8
NEW ENGLAND POWER POOL PARTICIPANTS COMMITTEE MEETING
October 3, 2014
RESOLUTION REGARDING THE ISO 2015 BUDGET
RESOLVED, that the Participants Committee supports the Year 2015 operating budget and capital budget proposed by the ISO, as presented at this meeting.
EXHIBIT 4 ISO New England Inc. Recovery of 2015 Administrative Costs
UNITED STATES OF AMERICA
BEFORE THE
FEDERAL ENERGY REGULATORY COMMISSION
ISO New England Inc. ) Docket No. ER15-___-000
TESTIMONY
OF
JANICE S. DICKSTEIN
Filed on: October 16, 2014 ISO New England Inc. Recovery of 2015 Administrative Costs Page 1
UNITED STATES OF AMERICA 1 BEFORE THE 2 FEDERAL ENERGY REGULATORY COMMISSION 3 4 5 ISO NEW ENGLAND INC. ) Docket No. ER15-___-000 6 7 8
9 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 ISO New England Inc. Recovery of 2015 Administrative Costs 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: WHAT IS THE PURPOSE OF YOUR TESTIMONY?
11 A. My testimony discusses the components of the proposed 2015 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 ISO New England Inc. Recovery of 2015 Administrative Costs Page 3
1 OBJECTIVE OF COMPENSATION PROGRAM
2 Q. WHAT IS THE OBJECTIVE OF THE ISO’S COMPENSATION
3 PROGRAM?
4 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. WHAT ARE THE CHALLENGES TO MEETING THE OBJECTIVE OF
11 THE ISO’S COMPENSATION PROGRAM?
12 A. There are two primary challenges. The first is that there is a shortage of critical
13 talent in the utility industry. As documented by numerous studies over the past
14 several years, the electric industry workforce is considered to be the oldest aged
15 workforce in the United States, with close to 50% of the workforce eligible to
16 retire in the next five to ten years.
17 In January of 2012, the National Regulatory Research Institute wrote that “[t]he
18 energy industry is facing an impending workforce shortage. The shortage reflects
19 an unprecedented number of retirements expected to occur in the next decade,
20 coupled with increasing energy demand...” The U.S. Department of Labor
21 predicts that 500,000 energy industry workers will retire in the next decade, a ISO New England Inc. Recovery of 2015 Administrative Costs Page 4
1 turnover rate of 50 percent. An August, 2013 article entitled “Solving the
2 Looming Talent Shortage in the Energy Industry” predicts turnover of 40 percent,
3 stating that “[t]he unprecedented loss of highly-skilled, senior workers is
4 compounding challenges posed by aging infrastructure, rising power demand, and
5 climate stress.” A 2012 article from Power Grid Engineering, LLC entitled
6 “Restoring the Aging Work Force in the Power Industry,” reports that “[t]he
7 Nuclear Energy Institute predicts that up to 120,000 to 160,000 workers will be
8 needed by 2013 to fill the gap in the electricity sector. These figures pose an
9 alarming demand for engineers to deliver the work needed to sustain our nations’
10 [sic] energy requirements.”
11 The effects of these retirements were characterized in a 2011 presentation
12 prepared by the Power Systems Engineering Research Center (PSERC) for the
13 National Research Council’s Energy and Mining Workforce Committee. In that
14 presentation, PSERC re-emphasizes 2006 and 2007 statements made by the North
15 American Electric Reliability Corporation, asserting that “[t]he reliability of the
16 North American electric utility grid is dependent on the accumulated experience
17 and technical expertise of those who design and operate the system. As the
18 rapidly aging workforce leaves the industry over the next five to ten years, the
19 challenge to the electric utility industry will be to fill this void…” The PSERC
20 presentation goes on to say that “[h]iring experienced engineers is a critical
21 need….” Similarly, as reported by the National Regulatory Research Institute, ISO New England Inc. Recovery of 2015 Administrative Costs Page 5
1 “[b]oth the Department and the North American Electric Reliability Corporation
2 have expressed concerns that the anticipated workforce shortfall threatens the
3 reliability, efficiency and security of utility services.”
4 Finally, a February 2014 Congressional Research Report entitled “The U.S.
5 Science and Engineering Workforce: Recent, Current, and Projected
6 Employment, Wages, and Unemployment,” which was prepared for Members and
7 Committees of Congress, reported that, between 2008 and 2012, the employment
8 growth for computer science professionals and electric engineers exceeded that of
9 the general population.1 The research paper also projected that employment
10 growth for this same technical sector would exceed that of the general population
11 through 2022.
12 The second challenge is that the ISO is competing for this shrinking pool of talent
13 with for-profit utilities. These utilities are offering aggressive compensation to
14 recruit and retain key positions. As one example, Transmission Owners within
15 our region continue to increase the compensation they pay to their transmission
16 planning engineers, primarily as a retention tool to staff major infrastructure
17 projects. The Hay Group reported that, twice in 2008, Transmission Owners in
18 the Northeast increased compensation for transmission planning engineers by 7-
19 20%. Since that time, survey data continues to indicate that compensation for this
20 group of professionals increases at an above industry average rate of
1 More than half of the ISO’s employees are electric engineers and/or computer science professionals, ISO New England Inc. Recovery of 2015 Administrative Costs Page 6
1 approximately 5% - 6%, in contrast to the 3% industry average. This problem is
2 exacerbated by the fact that the ISO cannot offer equity compensation as public
3 for-profit companies do.
4 Additionally, the February 2014 Congressional Research Report cited above
5 stated that “[i]n 2012, the mean annual wage for all scientists and engineers
6 [S&E] was $87,330; the mean annual wage for all occupations – professional and
7 non-professional – was $45,790. S&E managers had the highest mean annual
8 wage of all S&E occupational groups at $130,660 followed by engineers,
9 $90,960….”
10 Q. HOW ARE THESE CHALLENGES MANIFESTING THEMSELVES?
11 A. These challenges are manifested in turnover in the ISO industry. While industry
12 turnover was trending downward in 2008 - 2010, due to the depressed national
13 economy, it has increased as companies have begun hiring again and as
14 employees, who had deferred their retirements during the economic downturn,
15 now begin to exit the workforce. To date in 2014, the ISO’s turnover is running
16 at 5.5% - up from 2013 turnover, and significantly higher than the turnover seen
17 prior to that. Most of the individuals who have departed this year were in
18 information technology positions, with a number also departing from System
19 Operations, System Planning and Market Operations, all areas that are critical to
20 operating the grid and running our markets. In addition, to date in 2014, nine ISO
21 employees have resigned for similar but higher paying jobs at other employers; ISO New England Inc. Recovery of 2015 Administrative Costs Page 7
1 and, in 2014 thus far, eight candidates have declined ISO-NE job offers, stating
2 that the compensation was not sufficient.
3 Q. HOW DOES THE ISO MAINTAIN THE COMPETITIVENESS OF ITS
4 COMPENSATION?
5 A. The ISO first identifies the industries with which it competes for talent – in other
6 words, the industries from which the ISO recruits, and to which the ISO loses
7 employees. These are other ISOs and RTOs, for-profit utility companies, energy-
8 related consulting firms, and the broader industry (for positions not specific to
9 utilities).
10 Next, the ISO defines target ranges of compensation within these markets. For
11 non-exempt, non-union employees, the target market range of compensation is the
12 50th percentile of the local market. For both executives and middle management
13 and professionals, this target is the 50th to 75th percentile of the national market.
14 For middle management and professionals, the following factors led to the
15 determination of this target: nation-wide recruitment; national shortages of
16 qualified candidates; and difficulty in attracting candidates to the location. For
17 executives, we also considered: complexity of responsibilities; alignment with
18 higher salaries paid in the Northeast; and the limited promotional opportunities in
19 a smaller organization. ISO New England Inc. Recovery of 2015 Administrative Costs Page 8
1 Last, as discussed in more detail below, the ISO regularly monitors job-specific
2 salary survey data to determine these targets.
3 COMPONENTS OF COMPENSATION
4 Q. WHAT ARE THE COMPONENTS OF THE ISO’S COMPENSATION?
5 A. The ISO has a “pay for performance” compensation program composed of two
6 components for all employees, and an additional long-term component for
7 executives and certain key employees.
8 The first component is annual base salary, which reflects external
9 competitiveness, the employee’s productivity and performance, the qualifications
10 for the position, and internal equity. An employee’s annual base salary evolves
11 based on his or her job performance, following the annual performance review
12 process. (These are the merit and promotional increases that will be discussed
13 below.) These changes to salary are one of the ways in which the ISO maintains
14 the competitiveness of its salaries within the target ranges previously discussed.
15 The second component of compensation is annual incentive compensation. This
16 program is intended to motivate employees to achieve superior performance on
17 critical annual business and customer service objectives and goals. Subject to
18 eligibility criteria, employees may receive an annual award based on a formula
19 that includes company performance, individual performance, annual base salary
20 and a grade-related salary percentage. Company performance is determined using ISO New England Inc. Recovery of 2015 Administrative Costs Page 9
1 goals that are set in advance by the Board. These goals are objective and
2 measurable and represent organizational goals for operational reliability, efficient
3 and competitive markets, budget performance and service excellence in
4 stakeholder processes. Performance against these goals is measured using a
5 corporate scorecard that is regularly published to all employees, and the
6 calculation of which is verified by the ISO’s internal auditors. The Board of
7 Directors then assigns a final score to the achievement of annual goals.
8 For executives and certain key employees, the third and final component of
9 compensation is a long-term incentive plan that is designed to encourage retention
10 by deferring payments for two and one-half years after they are declared. This
11 program is intended to provide compensation in lieu of the stock programs
12 provided by for-profit competitors. These awards are determined using a formula
13 of performance against specific corporate goals, individual performance and
14 annual base salary. Again, the goals and their performance are determined by the
15 Board. Additionally, before the payout, the Board conducts a retrospective
16 review of the quality and impact of the goal achievement supporting the award.
17 Employees are not eligible for either type of award in a year in which they receive
18 a performance rating of “Clearly Below Expectations” or in the event of a major
19 collapse of the bulk electric power system. Similarly, if the ISO underperforms in
20 the management of the bulk electric power system or in its other functions in a
21 manner that is not captured in the goal performance score, the Board of Directors ISO New England Inc. Recovery of 2015 Administrative Costs Page 10
1 can reduce or eliminate the payment of the awards. The Board has taken this step
2 in the past.
3 BUDGET FOR MERIT AND PROMOTIONAL SALARY INCREASES
4 Q: PLEASE EXPLAIN THE MERIT AND PROMOTIONAL INCREASE
5 BUDGET.
6 A. This is a budget that establishes annually the amount that management and the
7 Board can distribute to the entire employee base for salary increases following the
8 annual performance review process that occurs in the first quarter of each year, as
9 well as changes as a result of promotion. This is a critical component of our
10 ability to maintain competitive salaries, which, as discussed above, enables us to
11 retain our employees in a very competitive marketplace for their talent.
12 Q. HOW IS THIS BUDGET DETERMINED?
13 A. The Compensation and Human Resources Committee of the Board of Directors
14 determines this budget annually after reviewing national survey data that project
15 what other employers will do for these programs in the coming year. We
16 typically gather data from six surveys, prepared by Mercer, WorldatWork, the
17 Conference Board, Buck Consultants, Aon Hewitt, and TowersWatson. The
18 surveys report the planned budget increases of several thousand employers,
19 including more than 100 utility companies. These surveys provide information on
20 all industries nationwide, as well as the utility industry separately, and are used by
21 most major companies to determine their compensation budgets. The ISO utilizes ISO New England Inc. Recovery of 2015 Administrative Costs Page 11
1 nationwide benchmark data for both all-industry and utility-specific employers,
2 because it recruits a majority of its employees on a nationwide basis given the
3 unique skill sets required for many of its positions. The ISO further assesses the
4 data by employee group, reviewing data reported specifically for executive,
5 exempt employees, and non-union non-exempt employees.
6 Q. WHAT WERE THE SURVEY RESULTS REGARDING PROJECTED
7 INCREASES FOR 2015?
8 A. For merit increase budgets, the surveys showed an average of 2.99% for all
9 industries nationwide, and 2.98% for the utility industry. For promotional
10 increase budgets, the surveys showed a range of 0.5% to 0.9% for all industries
11 nationwide and 0.5% - 1.0% for the utility industry.
12 In 2008 and 2009, because employers were reducing their compensation budgets
13 given the economic downturn, the survey firms updated their data at year end.
14 The ISO reviewed this data in both years to ensure that the following year’s
15 budgeted increases remained within the survey ranges. In 2008, the ISO reduced
16 its 2009 compensation budget by $500,000 as a result. In 2010, only one of the
17 survey firms produced an update. There were no updates in 2011, one update in
18 each of 2012 and 2013 and five of the firms have told us they will not produce
19 updates at the end of 2014. One firm will make its final determination closer to
20 year-end. ISO New England Inc. Recovery of 2015 Administrative Costs Page 12
1 Q. WHAT ARE THE ISO’S MERIT AND PROMOTIONAL INCREASE
2 BUDGETS FOR 2015?
3 A. After reviewing the survey data, the Committee approved a merit increase budget
4 of 3.0% and a promotional increase budget of .5%.
5 FRAMEWORK FOR DETERMINING EXECUTIVE COMPENSATION
6 Q. WHAT IS THE FRAMEWORK FOR THE ISO’S DETERMINATION OF
7 EXECUTIVE COMPENSATION?
8 A. The ISO is a not-for-profit company under Section 501(c)(3) of the Internal
9 Revenue Code. The Internal Revenue Code and related Treasury regulations
10 require that the compensation paid to executive officers meet a standard of
11 “reasonableness.” Specifically, compensation must fall within a range of
12 competitive practices for total compensation paid by similarly-situated
13 organizations, both taxable and tax-exempt, for functionally comparable
14 positions.
15 The Internal Revenue Code allows a tax-exempt organization to establish a
16 “rebuttable presumption” of reasonableness. This places the onus on the Internal
17 Revenue Service to show that compensation is unreasonable. The rebuttable
18 presumption requires that the compensation arrangement be approved in advance
19 by independent individuals (e.g., the Board of Directors), that the Board has
20 obtained and relied upon appropriate data as to comparability (i.e., compensation
21 paid by similarly-situated entities – taxable and tax-exempt – for positions with a ISO New England Inc. Recovery of 2015 Administrative Costs Page 13
1 similar scope of responsibility), and that the Board adequately documents the
2 basis for its determination.
3 Q. HOW HAS THE ISO ATTEMPTED TO SECURE THE BENEFIT OF THE
4 PRESUMPTION OF REASONABLENESS?
5 A. The ISO’s Board of Directors approves all executive compensation, and
6 documents the basis for its determination. In order to ensure that the Board has
7 obtained and relied upon appropriate data as to comparability, the ISO retains an
8 outside compensation advisor, Mercer Consulting. Mercer prepares an opinion
9 annually on the reasonableness of the ISO’s executive compensation, using as
10 comparators other ISOs and RTOs, as well as for-profit utilities and other
11 companies, based on their organizational character/complexity, geographic
12 location, role of the incumbent and labor market for the executive team. The data
13 for these groups is then blended to create a composite market reference as an
14 overall benchmark. This composite reflects the fact that the ISO competes for
15 executive talent in the energy industry, as well as in the broader general industry
16 for positions in areas like Legal, Finance and Human Resources.
17 Q. WHAT IS THE BOARD’S PROCESS FOR DETERMINING EXECUTIVE
18 COMPENSATION?
19 A. This process occurs in the first quarter of each year. In determining executive
20 compensation, the Board first asks its Compensation and Human Resources
21 Committee to consider appropriate compensation. Both the Committee, and then ISO New England Inc. Recovery of 2015 Administrative Costs Page 14
1 the Board, consider the CEO’s appraisal of each executive’s experience,
2 responsibilities, performance, specific skill set, and contribution to strategic goal
3 achievement (and, for the CEO, the Chair’s appraisal of the same factors as
4 related to the CEO), and the Company’s financial and operational achievement.
5 The Board then provides its compensation recommendations to Mercer for an
6 opinion on reasonableness, prior to implementation.
7 Q. WHAT WAS THE CONCLUSION OF MERCER’S MOST RECENT
8 REASONABLENESS OPINION?
9 A. Mercer’s most recent reasonableness opinion concludes that the proposed 2014
10 total compensation for executives was reasonable.
11 Q. HOW WILL 2015 EXECUTIVE COMPENSATION BE DETERMINED?
12 A. The Board will use the same process described above, involving the
13 Compensation and Human Resources Committee’s review and approval followed
14 by full Board approval of executive compensation. Likewise, the Board will
15 employ Mercer to ensure the reasonableness of 2015 compensation. While 2015
16 compensation has not yet been determined, 2014 executive compensation will be
17 the base for 2015 compensation and the Board has not authorized any wholesale
18 changes to the compensation programs described above. Consequently, it is
19 reasonable to presume that the 2015 executive compensation will be similar to the
20 2014 compensation, with changes necessary to maintain its competitiveness.
EXHIBIT 5 Exhibit 5
ISO New England Inc. 2015 Capital Projects Schedule
Current Year Estimated Project-To- (2014) Cost to 2015 Cost to Total Project Complete Description Date Complete [1] Complete Costs Date
Capital Projects - Approved Charters . Coordinated Transaction Scheduling $ 814.2 $ 795.3 $ 4,170.5 $ 5,780.0 11/2015 . Generation Control Application (GCA) Production Part 1 1,888.5 1,417.2 1,694.3 5,000.0 6/2015 . Divisional Accounting 1,251.8 432.5 1,066.5 2,750.8 11/2015 . Alternative Technologies and Regulation Market (ATRM) 1,869.3 629.4 470.0 2,968.7 3/2015 . Forward Capacity Auction (FCA) 9 338.7 1,320.2 230.0 1,888.9 2/2015 . Voltage Stability 432.5 390.8 75.0 898.3 3/2015 . Control Room Visualization 320.4 245.1 47.1 612.6 2/2015 Sub Total Projects with Approved Charters 6,915.4 5,230.5 7,753.4 19,899.3 Planning/Conceptual Design [2] . Business Continuity Plan Infrastructure Enhancements Phase III 449.4 24.0 2,000.0 2,473.4 TBD . Forward Capacity Auction (FCA) 10 - - 2,000.0 2,000.0 TBD . Third Party Financial Transmission Rights (FTR) Administration 14.3 59.2 1,800.0 1,873.5 TBD . Generation Control Application (GCA) Production Part 2 - - 1,500.0 1,500.0 TBD . VPN System Upgrade - - 1,000.0 1,000.0 TBD . Issues Resolution Project 2015 - - 1,000.0 1,000.0 TBD . Simultaneous Feasibility Test Lite Production Version - - 1,000.0 1,000.0 TBD . Power System Modeling - - 1,000.0 1,000.0 TBD . Long-Term FTRs 907.5 - - 907.5 [3] TBD . Quarterly Release Projects 2015 - - 800.0 800.0 TBD . LMP Calculator Replacement 1.1 448.9 500.0 950.0 TBD . Wind Integration Phase II - - 500.0 500.0 TBD . Web Enhancements - - 500.0 500.0 TBD . Phasor Measurement Unit (PMU) Data Application - - 500.0 500.0 TBD . Price Response Demand - - 300.0 300.0 TBD . Software Testing Tool 2015 - - 300.0 300.0 TBD . Other Emerging Work Projects - - 1,646.6 1,646.6 TBD Sub Total Conceptual Design 1,372.3 532.1 16,346.6 18,251.0 - . Non-Project Capital Expenditures - - 3,400.0 3,400.0 . Capitalized Interest and Loan Fees 229.8 270.2 500.0 1,000.0 Total Capital Projects (Including Capitalized Interest) $ 8,517.5 $ 6,032.8 $ 28,000.0 $ 42,550.3
[1] The amounts under the "Current Year (2014) Cost to Complete" list only includes those projects with budgeted costs in 2015 and beyond. [2] The 2015 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. [3] The LTTR project has been indefinitely deferred pending the development of appropriate credit requirements.
EXHIBIT 6 ISO New England Inc. 2015 Capital Budget
UNITED STATES OF AMERICA
BEFORE THE
FEDERAL ENERGY REGULATORY COMMISSION
ISO NEW ENGLAND INC. ) Docket No. ER15-_____-000
DIRECT TESTIMONY
OF
M. DAVID HAMEEDY
Filed on: October 16, 2014 ISO New England Inc. 2015 Capital Budget Page 1
1 UNITED STATES OF AMERICA
2 BEFORE THE FEDERAL ENERGY REGULATORY COMMISSION
3
4 ISO NEW ENGLAND INC. ) Docket No. ER15-_____-000
5
6 Direct Testimony of M. David Hameedy
7 Q. PLEASE STATE YOUR NAME AND BUSINESS ADDRESS.
8 A. My name is M. David Hameedy. My business address is One Sullivan Road,
9 Holyoke, Massachusetts 01040-2841.
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. ISO New England Inc. 2015 Capital Budget Page 2
1 Q. PLEASE DESCRIBE YOUR EDUCATIONAL BACKGROUND AND
2 PROFESSIONAL EXPERIENCE.
3 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. WHAT IS THE PURPOSE OF YOUR TESTIMONY?
10 A. I am providing this testimony in support of the filing of the ISO’s capital budget
11 for 2015 (“2015 Capital Budget”).
12 My Direct Testimony describes:
13 (i) the Capital Budget development process;
14 (ii) elements of the 2015 Capital Budget; and
15 (iii) funding of the 2015 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. ISO New England Inc. 2015 Capital Budget Page 3
1 Q. HOW WERE THE ISO’S BUDGETS DEVELOPED FOR 2015?
2 A. The ISO prepares budgets in advance of each upcoming year, including a capital
3 budget. To develop these budgets for 2015, 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 ELEMENTS OF THE 2015 CAPITAL BUDGET
16 Q. IN GENERAL, HOW WILL THE ISO SPEND THE MONEY REQUIRED
17 FOR THE CAPITAL PROJECTS DISCUSSED ABOVE?
18 A. The primary deliverable for a majority of the projects listed in the 2015 Capital
19 Budget is application software and requisite hardware needed to maintain and
20 improve bulk-power system reliability and/or wholesale electric markets. ISO New England Inc. 2015 Capital Budget Page 4
1 Q. HAS THE 2015 CAPITAL BUDGET CHANGED FROM 2014 LEVELS?
2 A. The 2015 Capital Budget is $28 million, which is equivalent to the 2014 budget.
3 Q. PLEASE DESCRIBE THE ELEMENTS OF THE CAPITAL BUDGET.
4 A. The 2015 Capital Budget contains the following projects: Coordinated
5 Transaction Scheduling; Generation Control Application Production Part 1;
6 Divisional Accounting; Alternative Technologies and Regulation Market;
7 Forward Capacity Auction 9; Voltage Stability; Control Room Visualization
8 Project; Business Continuity Plan Infrastructure Enhancements Phase III; Forward
9 Capacity Auction 10; Third-Party Financial Transmission Rights Administration;
10 Generation Control Application Production Part 2; VPN System Upgrade: Issue
11 Resolution Project 2015; Simultaneous Feasibility Test Lite Production Version;
12 Power System Modeling; Quarterly Release Projects; Locational Marginal Price
13 Calculator Replacement; Wind Integration Phase II; Web Enhancements; Phasor
14 Measurement Unit Data Application; Price Responsive Demand; Software Testing
15 Tool 2015; Non-Project Capital Expenditures; and Other Emerging Work. The
16 2015 Capital Budget also includes $500,000 to pay for capitalized interest and
17 loan fees. ISO New England Inc. 2015 Capital Budget Page 5
1 Q. PLEASE DESCRIBE THE COORDINATED TRANSACTION
2 SCHEDULING PROJECT.
3 A. This is a joint project of ISO-NE and the New York ISO that seeks to improve
4 transmission network scheduling between the two regions. Studies performed by
5 the ISOs and market monitors have indicated that more efficient utilization of the
6 existing transmission infrastructure between regions would lower total system
7 production costs. The project will provide the capability to submit interface bids
8 with fifteen minute granularity, eliminate price disparity, and move to fifteen
9 minute scheduling (from hourly today). Specific enhancements include increasing
10 the frequency of scheduling energy transactions over the transmission network
11 between regions, implementing software changes to enable the two ISOs to
12 coordinate selection of the most economic transactions, and eliminating certain
13 fees. The target completion date for this project is November 2015.
14 Q. PLEASE DESCRIBE THE GENERATION CONTROL APPLICATION
15 PART 1 PROJECT.
16 A. This is a multi-phased project to develop a short-term look-ahead unit
17 commitment and dispatch analysis application designed to provide dispatchers
18 with the capability to manage changes in load, generation, interchange and
19 transmission security constraints simultaneously on an intra-day and near real-
20 time operational basis. This application will provide improved accuracy and ISO New England Inc. 2015 Capital Budget Page 6
1 optimality of the fast-start unit and pump Dispatchable Asset-Related Demand
2 commitments and shutdowns. The application will also dispatch slow-moving
3 units using ramping constraints to relieve future reserve or transmission
4 constraints, better account for self-scheduled and pump units that are coming on-
5 line or shutting down, provide automatic detection/prediction for minimum
6 generation conditions, and improve external transaction scheduling by developing
7 a next-hour interchange predictor for the New York North Interface.
8 The application will optimize and minimize total production costs over the look-
9 ahead period, and will also eliminate the need for out-of-merit manual
10 commitment and dispatch of fast start units and slow-moving units to deal with
11 future reserve or transmission constraints beyond the fifteen-minute look ahead
12 interval of the real-time dispatch application. Reducing the out-of-merit manual
13 commitment improves price formation in real-time, thereby strengthening
14 incentives for resources to be available in real-time. This should further improve
15 the reliability of the system, in addition to improving market efficiency. The
16 targeted completion date for this project is June 2015.
17 Q. PLEASE DESCRIBE THE DIVISIONAL ACCOUNTING PROJECT.
18 A. Market Participants with business interests in different aspects of the New
19 England electricity markets have requested separate settlement accounts for their
20 individual business units, allowing them to facilitate divisional accounting. This ISO New England Inc. 2015 Capital Budget Page 7
1 project will implement changes, in phases, to various ISO-NE systems to allow
2 Market Participants to create and maintain subaccounts and associate their
3 resources and transactions to these subaccounts.
4 The complexity of the implementation and the vast number of systems impacted
5 resulted in five phased releases to occur in 2014 and 2015. The first two planned
6 releases, which have been completed, allow Customers to create and maintain
7 subaccounts, and include report modifications so Customers can receive reports
8 for settlements for entity-based transactions by subaccounts.
9 Subsequent phases, which will be completed by November 2015, will include
10 modifications to systems such as eMarket (a web based software application for
11 use by Market Participants to submit supply offers and bids), eFTR (Financial
12 Transmission Rights) and the Forward Capacity Tracking System to allow
13 Customers to link transactions that are not associated with assets and resources to
14 subaccounts, thereby allowing settlements for those transactions to be calculated
15 and reported at the subaccount level.
16 Q. PLEASE DESCRIBE THE ALTERNATIVE TECHNOLOGIES AND
17 REGULATION MARKET PROJECT.
18 A. The project will implement modifications to the regulation market resource
19 selection process, Automatic Generation Control dispatch, and settlements to
20 comply with the Commission’s Order No. 755. The design will fully integrate ISO New England Inc. 2015 Capital Budget Page 8
1 alternative technology regulation resources into the existing regulation market,
2 provide hourly offer flexibility to allow regulation assets to change their offers as
3 prices and conditions change, and allow the dispatch of regulation resources (both
4 conventional and alternative technology) using continuous, energy neutral
5 continuous and energy neutral trinary dispatch methods. Resources will be able to
6 make separate bids for regulation capacity and regulation service (mileage), and
7 will receive market-based compensation for actual capacity and mileage delivered.
8 The target completion date is March 2015.
9 Q. PLEASE DESCRIBE THE FORWARD CAPACITY AUCTION 9
10 PROJECT.
11 A. The ISO developed the Forward Capacity Market to address New England’s
12 resource adequacy needs by providing incentives for investing in new supply and
13 demand resources and to improve resource performance. The start of the
14 commitment period for the first auction occurred in June 2010.
15 This project, chartered in May 2014 and scheduled for completion in February
16 2015, includes two primary efforts to be implemented before the ninth Forward
17 Capacity Auction. The first effort is to implement a downward-sloping demand
18 curve, which is a long-term solution to the problems associated with the Forward
19 Capacity Market administrative pricing provisions related to capacity carry
20 forward, inadequate supply and insufficient competition. ISO New England Inc. 2015 Capital Budget Page 9
1 The second effort involves improvements to the Financial Assurance provisions
2 for Non-Commercial Capacity to improve the timing for Non-Commercial
3 Capacity, strengthen incentives for Non-Commercial Capacity to achieve
4 “commercial” status in a timely manner, reflect the capacity price in the
5 calculation of Financial Assurance, and eliminate unnecessary Financial
6 Assurance associated with obligations acquired through reconfiguration auctions
7 or bilateral transactions.
8 Q. PLEASE DESCRIBE THE VOLTAGE STABILITY PROJECT.
9 A. This project will replace the existing voltage transfer limit calculator for the
10 Connecticut and Southwest Connecticut regions and will implement a real-time
11 voltage analysis tool and integrate it with the existing Energy Management
12 System. The new analysis tool will be available for use in real-time, to conduct
13 studies, and in the Testing and Training Simulation Environment.
14 New transmission facilities are being installed in Connecticut. The ISO’s past
15 experience with large transmission expansions indicates that the manual process
16 used to calculate voltage reduces the accuracy of the voltage limits, leading to a
17 number of issues and inefficiencies in conducting day-ahead studies and in real-
18 time operations. Moreover, the manual processes results in infrequent updates to
19 voltage calculators, inconsistent results, and susceptibility to human error when
20 creating formulas for voltage calculation. ISO New England Inc. 2015 Capital Budget Page 10
1 The new software is expected to improve the efficiency of the voltage calculation
2 process, the accuracy of the calculated voltage transfer limit results, and
3 consistency with new automated technology for determining thermal limits.
4 Ultimately, the project will enhance the reliability of grid operations. The
5 software will be implemented in March 2015.
6 Q. PLEASE DESCRIBE THE CONTROL ROOM VISUALIZATION
7 PROJECT.
8 A. The Control Room Visualization project, chartered in the third quarter 2013 and
9 targeted for completion in February 2015, is an effort to improve the visualization
10 of power system conditions by merging several hundred individual substation
11 displays into a single display that will allow System Operators a better viewpoint
12 of interactions between substations. The combined system display will appear on
13 the control room wallboard display and be available on each operator’s individual
14 system.
15 By creating a single display for use on both the wallboard and operator consoles,
16 the ISO reduces its support effort and the vendor-supplied software costs for
17 maintaining separate displays. The same benefit will be realized in the Testing
18 and Training Simulation Environment.
19 In addition, enhancements will be added to provide operators with context-
20 sensitive access from the new display to Transmission Operating Guides and other ISO New England Inc. 2015 Capital Budget Page 11
1 documents stored on the Operations Document Management System. This will
2 make these documents more easily accessible to the operators.
3 Q. PLEASE DESCRIBE THE BUSINESS CONTINUITY PLAN
4 INFRASTRUCTURE ENHANCEMENTS PHASE III PROJECT.
5 A. This is the final phase of the three-phase project initiated in 2008 to significantly
6 upgrade and enhance the Business Continuity Plan infrastructure, in order to
7 maintain a high level of reliability and comply with regulatory requirements. The
8 upgrade is intended to improve overall utilization of the Back-up Control Center
9 by having real-time Energy Management System and markets data on-line for
10 increased systems redundancy, thereby reducing the time to restore applications to
11 service from a back-up.
12 In this third phase, the project will implement the four-way Markets Database and
13 expand the virtual desktop functionality to production. This virtual functionality
14 will allow ISO personnel to conduct business remotely in the case of a pandemic
15 or other unavailability of the primary control center, replicate virtual desktop
16 capability to servers located at the Back-up Control Center, and gain the ability to
17 transfer operations to or from market application servers (e.g., wholesale market
18 applications, settlement applications, financial applications, etc.) located either at
19 the Master or Back-up Control Center in minutes. The targeted completion date
20 for this project is fourth quarter of 2015. ISO New England Inc. 2015 Capital Budget Page 12
1 Q. PLEASE DESCRIBE THE FORWARD CAPACITY AUCTION 10
2 PROJECT.
3 A. In addition to the ISO’s project to implement a system-wide sloped demand curve
4 to be effective for the ninth Forward Capacity Auction (as described above), ISO-
5 NE and stakeholders are working on sloped demand curves at the zonal level for
6 the tenth Forward Capacity Auction. This project also includes work with
7 stakeholders to address how reconfiguration auctions will work for Capacity
8 Commitment Periods associated with the ninth and later Forward Capacity
9 Auctions. The targeted completion date for this project is the first quarter of
10 2016.
11 Q. PLEASE DESCRIBE THE THIRD-PARTY FINANCIAL TRANSMISSION
12 RIGHTS ADMINISTRATION PROJECT.
13 A. ISO-NE holds Financial Assurance that may not be adequate to cover the potential
14 losses of a Market Participant’s default on its Financial Transmission Rights
15 (“FTRs”). Specifically, there is no way for ISO-NE to unwind a defaulted FTR
16 position. If a Market Participant acquires a large position in an annual FTR
17 auction, and the amount of negative target allocations exceeds its Financial
18 Assurance, the losses on this position, and therefore the losses to all Market
19 Participants in the event of a default, can continue to accumulate.
20 Third-party clearing of FTRs addresses the primary deficiency related to the ISO New England Inc. 2015 Capital Budget Page 13
1 current FTR market design – the inability to properly collateralize against the risk
2 of a Market Participant default. Under a third-party clearing design, if a Market
3 Participant defaults, its clearing member will liquidate the defaulted portfolio in
4 the secondary market, and if the combined margin held against the portfolio is not
5 adequate to cover the liquidation losses, the clearing member holds the financial
6 responsibility to cover the excess losses. This project will make the necessary
7 Tariff language changes regarding third-party clearing. In addition, the project
8 will design and implement software that is capable of administering third-party
9 clearing. The targeted completion date for this project is the third quarter of 2016.
10 Q. PLEASE DESCRIBE THE GENERATION CONTROL APPLICATION
11 PRODUCTION PART 2 PROJECT.
12 A. This is the second phase of the project described above. During this phase of the
13 project, targeted for completion in the fourth quarter of 2016, ISO-NE will
14 address the inclusion in the look-ahead intervals of topology changes, especially
15 those stemming from planned transmission line and transformer outages starting
16 or ending in the look-ahead intervals. Topology changes affect the generator
17 sensitivities to transmission constraints, and can affect the optimization of the
18 commitment of fast-start units when the topology changes result in binding
19 transmission constraints in congested areas of the power system. With its look-
20 ahead functionality, the Generation Control Application can account for these ISO New England Inc. 2015 Capital Budget Page 14
1 potential future congestion conditions and dispatch the on-line generation and the
2 commitment of fast-start units to prevent the congestion, or alert the operator of
3 the system conditions that will exist if the planned outages are allowed to proceed.
4 Q. PLEASE DESCRIBE THE VPN SYSTEM UPGRADE PROJECT.
5 A. The systems supporting Virtual Private Network (“VPN”) access to ISO-NE
6 networks have been in place since 2006 and are in need of a technology update.
7 Recent third party vulnerability assessments have consistently pointed out that the
8 current technology requires updating to remain current and to reduce risk of an
9 externally-initiated compromise of internal network access.
10 This project will undertake the replacement of network devices supporting the
11 VPN endpoints and address the needs of client systems to update software and
12 credentials. This will include replacements/updates as needed for current access,
13 backend authentication, authorization and accounting database components,
14 systems and supporting tracking of VPN access, and reporting on unused
15 accounts. This upgrade will not only enhance the current value of remote access
16 for ISO-NE staff and ongoing efforts to support business continuity and pandemic
17 response efforts, but will also improve security associated with using VPN access.
18 The targeted completion date for this project is the third quarter of 2015. ISO New England Inc. 2015 Capital Budget Page 15
1 Q. PLEASE DESCRIBE THE ISSUE RESOLUTION PROJECT 2015.
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 2015.
12 Q. PLEASE DESCRIBE THE SIMULTANEOUS FEASIBILITY TEST LITE
13 PRODUCTION VERSION PROJECT.
14 A. Simultaneous Feasibility Test is the network analysis package that is used to
15 perform contingency analysis and to calculate loss sensitivities in the Market
16 Systems. Currently, the ISO uses an Alternating Current contingency analysis
17 application in the clearing of the Day-Ahead Market and the Security Constrained
18 Reliability Analysis process. In 2014, the Day-Ahead Performance Enhancement
19 Prototype study evaluated a new product known as “SFT [Simultaneous
20 Feasibility Test]-Lite,” which is a Direct Current contingency analysis application. ISO New England Inc. 2015 Capital Budget Page 16
1 The evaluation demonstrated that an appreciable reduction in the elapsed time to
2 execute a Day-Ahead case could potentially be gained by switching to “SFT-
3 Lite.”
4 This project proposes to further enhance the “SFT-Lite” product and improve the
5 workflow between the various applications that are executed in the clearing of the
6 Day-Ahead Market, with the goal of achieving a significant reduction in case
7 execution elapsed time. This reduction should benefit Market Participants by
8 allowing more time to make fuel arrangements.
9 The targeted completion date for this project is the fourth quarter of 2015.
10 Q. PLEASE DESCRIBE THE POWER SYSTEM MODELING PROJECT.
11 A. The Power System Modeling project proposes to implement enhancements to
12 process, procedures and applications that will improve the power system network
13 model used for the Energy Management System. Key areas of focus include:
14 improving state estimation solution accuracy; introducing state estimation metrics
15 to track performance; introducing methods for detecting parameter errors and
16 developing an off-line tool that allows for on-going analysis of these functions to
17 be performed with each major network model release; exploring the use of the
18 Common Information Model in model management with a focus on reducing the
19 network model release life cycle times; initiating the process for requirements
20 gathering, and evaluating the purchase or development of tools to satisfy standards ISO New England Inc. 2015 Capital Budget Page 17
1 that require entities to provide steady‐state, dynamics, and short circuit modeling
2 data to its Transmission Planner(s) and Planning Coordinator(s); and evaluating
3 tools and procedures to facilitate dynamic model validation per standards. The
4 targeted completion date for this project is the fourth quarter of 2015.
5 Q. PLEASE DESCRIBE THE QUARTERLY RELEASE PROJECTS 2015.
6 A. In addition to major projects under consideration for 2015, the ISO expects to
7 address a number of minor enhancements requested by stakeholders. These minor
8 enhancements are bundled into two quarterly releases. The targeted completion
9 date for the first release is the second quarter of 2015, and the second release is
10 targeted for completion in the fourth quarter of 2015.
11 Q. PLEASE DESCRIBE THE LOCATIONAL MARGINAL PRICE
12 CALCULATOR REPLACEMENT PROJECT.
13 A. The number of occurrences of price corrections has been increasing over the past
14 year and, upon investigation, the software vendor has been able to identify issues
15 contributing to the need for these price corrections. While fixes are scheduled to
16 be implemented in production software effective December 3, 2014, the vendor
17 cannot guarantee that these fixes will eliminate the need to make price
18 corrections, especially in the presence of binding transmission and binding reserve
19 constraints; moreover, the introduction of Energy Market Offer Flexibility may
20 further compound this issue. This project will include collaboration with the ISO New England Inc. 2015 Capital Budget Page 18
1 vendor to replace the current ex-post Locational Marginal Price Calculator to
2 eliminate the need to make these price corrections. The targeted completion date
3 for this project is the second quarter of 2015.
4 Q. PLEASE DESCRIBE THE WIND INTEGRATION PHASE II PROJECT.
5 A. The Wind Integration Phase II project is the second phase in the progression of
6 steps necessary to fully integrate wind power into the ISO-NE system. This
7 project will design and implement functionality that will incorporate wind
8 resources into Real-Time dispatch. This involves incorporating the wind forecasts
9 to align with the Real-Time dispatch processes and issuance of dispatch signals.
10 In addition, the project will incorporate wind power forecasts into the reserves
11 scheduling and procurement processes and will provide enhancements to the
12 situational awareness tools for the control room. The targeted completion date for
13 this project is the fourth quarter of 2015.
14 Q. PLEASE DESCRIBE THE WEB ENHANCEMENTS PROJECT.
15 A. ISO-NE completed a redesigned website in 2014 that greatly improved access to,
16 and the ease of use of, market and power system information for Market
17 Participants, public officials, and other key stakeholders. In 2015, the ISO will
18 evaluate the latest developments in web content and messaging and will develop a
19 project scope to address any issues or concerns resulting from this evaluation.
20 The target completion date for this project is the third quarter of 2015. ISO New England Inc. 2015 Capital Budget Page 19
1 Q. PLEASE DESCRIBE THE PHASOR MEASUREMENT UNIT DATA
2 APPLICATION PROJECT.
3 A. With the recent implementation of the Synchrophasor Infrastructure and Data
4 Utilization project, ISO-NE will begin to work in 2015 toward completion of a
5 multi-year plan to fully integrate Phasor Measurement Unit data into operations,
6 thereby enhancing system reliability. The targeted completion date for this project
7 is the fourth quarter of 2015.
8 This project proposes to acquire Phasor Measurement Unit data from neighboring
9 ISOs and RTOs to enhance ISO-NE’s visibility into neighboring networks and
10 wide area monitoring. The project will also enhance islanding, disturbance and
11 oscillation detection and alarming in the PhasorPoint software. ISO-NE also
12 plans to research a state estimator for Phasor Measurement Units in the 345 kV
13 network and explore Area Control Error calculation and Automatic Generation
14 Control based on Phasor Measurement Units. Throughout the project, ISO-NE
15 will work with one transmission owner to establish a base (“golden”) Phasor
16 Measurement Unit within New England that will provide a reference to calibrate
17 other like data across New England.
18 Q. PLEASE DESCRIBE THE PRICE RESPONSE DEMAND PROJECT.
19 A. To comply with FERC Order 745 (Demand Response Compensation in Organized
20 Wholesale Energy Markets), ISO-NE proposed a two-step implementation. The ISO New England Inc. 2015 Capital Budget Page 20
1 first step was a transition period which primarily maintained the existing demand
2 response programs and their participation in the Day-Ahead Energy Market, but
3 incorporated the payment of Locational Marginal Prices to active demand
4 response in the Forward Capacity Market when they were dispatched to reduce
5 consumption. This step was implemented by the ISO in 2012.
6 This project, the second step, will implement the full integration of active demand
7 response into the Capacity, Energy and Ancillary Service Markets. A common
8 model will be created for a single representation of demand response that can
9 either reduce consumption or provide supply. Modifications will be made to
10 Capacity, Energy and Ancillary Service Markets to incorporate and effectively
11 implement this model into the ISO-NE markets. The project will provide
12 comparable treatment to other supply resources and allow demand response assets
13 to directly impact the prices within the markets. The transition program will be
14 terminated with the implementation of this project.
15 The targeted completion date for this project is the second quarter of 2018.
16 Q. PLEASE DESCRIBE THE SOFTWARE TESTING TOOL PROJECT.
17 A. During 2011, ISO-NE initiated a proof of concept to incorporate automated
18 testing as part of new application design and testing. Since then, the ISO has
19 expanded the creation of software testing tool scripts for various applications that
20 have been implemented in previously-completed capital development projects. ISO New England Inc. 2015 Capital Budget Page 21
1 Given the success of these efforts in improving the quality and efficiency of
2 testing, the ISO plans to continue its efforts and identify several other applications
3 for which it will create automated test scripts in 2015. The targeted completion
4 date for this project is the third quarter of 2015.
5 Q. PLEASE DESCRIBE THE NON-PROJECT CAPITAL EXPENDITURES
6 ITEM.
7 A. The 2015 Capital Budget includes $3.4 million for non-project capital
8 expenditures. Non-project capital expenditures fund external and internal
9 capitalized labor necessary to program System Improvement Requests
10 ($1,500,000), non-project related hardware purchases ($1,500,000), and furniture
11 & fixtures ($400,000).
12 Q. PLEASE DESCRIBE THE “OTHER EMERGING WORK” PROJECTS.
13 A. This category is primarily intended to deal with emerging work requests during
14 2015 that result from operational needs, compliance obligations or
15 regulatory/stakeholder feedback.
16 Q. DESCRIBE THE ACCURACY OF THE EXPENDITURE ESTIMATES
17 FOR THE PROJECTS INCLUDED IN THE 2015 CAPITAL BUDGET.
18 A. The 2015 Capital Budget includes seven projects with approved charters:
19 Coordinated Transaction Scheduling; Generation Control Application Production
20 Part I; Divisional Accounting; Alternative Technologies and Regulation Market; ISO New England Inc. 2015 Capital Budget Page 22
1 Forward Capacity Auction 9; Voltage Stability; and Control Room Visualization
2 Project. The ISO has not finalized the design, scope, and charters for the
3 remaining projects. As a result, the cost estimates for such items are likely to
4 change. Furthermore, the capital budget is quite dynamic, and the ISO uses it to
5 reflect any changing market needs, when possible. To the extent new and urgent
6 priorities arise, the ISO will adjust accordingly and reflect these adjustments in its
7 quarterly Section 205 filings.
8 CAPITAL BUDGET FUNDING
9 Q. PLEASE DETAIL HOW THE CAPITAL EXPENDITURES OF THE
10 CAPITAL BUDGET ARE TYPICALLY FUNDED AND REPAID.
11 A. The ISO’s existing and future capital projects are financed by drawing upon the
12 private placement debt, issued with Commission authorization. (See orders in
13 Docket No. ES04-39-000, 109 FERC ¶ 62,195 (2004), and Docket No. ES12-48-
14 000, 140 FERC ¶ 62,173 (September 6, 2012).) The ISO funds the repayment of
15 this debt through recovery of depreciation under its annual operating budgets
16 collected through the rates specified in Section IV.A of the Tariff – Recovery of
17 ISO Administrative Expenses. The Customers that are repaying the charges under
18 the schedules in Section IV.A of the Tariff are receiving the benefits of the
19 services rendered under those schedules. In no case will the costs of items be
20 recovered twice. ISO New England Inc. 2015 Capital Budget Page 23
1 If for some reason the ISO is unable to use private financing to cover its full
2 capital budget, Section IV.B of the Tariff (the “Capital Funding Arrangements”)
3 provides four different charges the ISO may use to recover such costs from
4 Market Participants. The Capital Funding Charge allows the ISO to collect from
5 Market Participants funds for the direct purchase of capital assets not previously
6 funded by Market Participants if the ISO does not enter into private financing to
7 fund these purchases or the ISO funds the purchases through interim financings
8 and does not enter into private financing to provide long-term funding of these
9 purchases. In order to encourage banks to lend for the ISO’s capital and working
10 capital needs, Section IV.B of the Tariff includes an Early Amortization Capital
11 Charge and an Early Amortization Working Capital Charge. These charges
12 ensure that the ISO can recover its working capital and the unamortized costs of
13 the assets privately financed in the event of termination, acceleration or other
14 required repayment of the loans. Finally, the Early Payment Shortfall Funding
15 Charge allows the ISO to collect from Market Participants such funds as are
16 required for the repayment of the “Shortfall Funding Arrangement” financing
17 entered into by the ISO in support of weekly billing under the Billing Policy.
18 Q. IS THE ISO’S CURRENT PRIVATE PLACEMENT DEBT SUFFICIENT
19 TO COVER THE 2015 CAPITAL BUDGET?
20 A. Yes. At this time, the ISO does not foresee the need to recover any 2015 Capital
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 2013 Form 1 (Exhibit 8).
Statement AB Income statements: See income statements from ISO’s 2013 Form 1 (Exhibit 8 hereto). A comparison of budgeted net operating expenses for 2015 with budgeted 2014 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 2013 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 Services1 provided by the ISO.
Statement AE Accumulated depreciation and amortization: See 2013 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 2014 and 2015 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 147 FERC ¶ 62,091 (2014). 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 108 FERC ¶ 62,049 (2004); 109 FERC ¶ 62,194 (2004); 139 FERC ¶ 62,248 (2012); 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 2015 Revenue Requirement reflects credits from prior year true-up, as described in Sections 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
Maine Vermont Department of Public Service 112 State Street, Drawer 20 The Honorable Paul LePage Montpelier, VT 05620-2601 One State House Station [email protected] Office of the Governor [email protected] Augusta, ME 04333-0001 [email protected] [email protected]
Maine Public Utilities Commission Massachusetts 18 State House Station Augusta, ME 04333-0018 The Honorable Deval Patrick [email protected] Office of the Governor Rm. 360 State House Boston, MA 02133 New Hampshire Massachusetts Attorney General Office The Honorable Maggie Hassan One Ashburton Place Office of the Governor Boston, MA 02108 26 Capital Street [email protected] Concord NH 03301 [email protected] Massachusetts Department of Public Utilities [email protected] One South Station Boston, MA 02110 New Hampshire Public Utilities Commission [email protected] 21 South Fruit Street, Ste. 10 Concord, NH 03301-2429 [email protected] Rhode Island [email protected] [email protected] The Honorable Lincoln Chafee [email protected] Office of the Governor [email protected] State House Room 115 [email protected] Providence, RI 02903 [email protected] [email protected] Vermont [email protected] [email protected]
The Honorable Peter Shumlin Office of the Governor 109 State Street, Pavilion Rhode Island Public Utilities Commission Montpelier, VT 05609 89 Jefferson Blvd. [email protected] Warwick, RI 02888 [email protected] [email protected]
Vermont Public Service Board 112 State Street Montpelier, VT 05620-2701 [email protected]
New England Governors, State Utility Regulators and Related Agencies
Connecticut
The Honorable Dannel P. Malloy Office of the Governor Harvey L. Reiter, Esq. State Capitol Counsel for New England Conference of Public 210 Capitol Ave. Utilities Commissioners, Inc. Hartford, CT 06106 c/o Stinson Morrison Hecker LLP [email protected] 1150 18th Street, N.W., Ste. 800 [email protected] Washington, DC 20036-3816 [email protected] [email protected]
Connecticut Public Utilities Regulatory Authority 10 Franklin Square New Britain, CT 06051-2605 [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]
Sarah Hofman, Executive Director New England Conference of Public Utilities Commissioners 50 State Street – Suite 1 Montpelier, VT 05602 [email protected] [email protected]
James Volz, President New England Conference of Public Utilities Commissioners 112 State Street, Drawer 20 Montpelier, VT 05620-2601 [email protected]
EXHIBIT 10
September 25, 2014
Philip N. Shapiro Chairman ISO New England One Sullivan Road Holyoke, MA 01040
Re: Comments of State Agencies on proposed 2015 ISO Budget
Dear Chairman Shapiro:
In conformance with the FERC-approved Settlement Agreement dated May 13, 2013 in docket nos. ER13-185 and ER13-192 between ISO and the New England State Agencies (the "Settlement Agreement"), the undersigned New England State Agencies are pleased to continue their role of providing written comments concerning ISO's proposed 2015 budget. For its 2015 Budget, ISO New England management proposes a 4.4% increase in spending. Because of a $9.8 million over-collection from last year's tariff, the proposed 4.4% increase is offset entirely by the over-collection, resulting in an anticipated reduction of 1.2% in revenue requirements and a 2.1% reduction in the proposed $/kWh rate.1 We note that $2.25 million of the $9.8 million offset from this year is returned pursuant to the FERC-approved Settlement Agreement.
We believe that the Settlement Agreement sets forth an efficient, effective means for the States to review and express their views regarding ISO's annual budgets. This process is having positive results, but some of the details of the review, input and communication process are not yet working smoothly. We therefore ask for your continued support and commitment to this process. As an example of an issue of concern, the Settlement Agreement requires the States to provide written comments no later than September 25, and for ISO-NE to respond to those comments no later than "five business days before the ISO-NE Board of Directors votes on the proposed budgets."2 By its terms, the Settlement Agreement contemplates that the ISO Board will consider the States' comments. Thus we were surprised to learn that the Board considered and discussed the budget on September 18, 2014, a week before the deadline for our comments. We understand that the Board's actual vote on the budget will be by written consent, on or before October 16.3 Since the Business Plan has ISO submitting its budget to FERC on the same day, there is no meaningful opportunity for the Board to consider the States’ comments or to change any aspect of the budget
1 We were informed that the actual tariff impact would not be available until the end of this month and thus rely upon the representations made in the budget presentation materials. 2 Settlement Agreement II.B.5. 3 See ISO New England's 2015-2019 Business Plan, p.7.
Philip N. Shapiro Chairman, ISO New England September 25, 2014 Page 2
based on its consideration of those comments.4 We respectfully submit that this process fails to comply with the intent and structure of the Settlement Agreement, namely that the ISO-NE Board of Directors fully consider, discuss and evaluate formal input from State governments before approving a budget that is funded by New England ratepayers. Moreover, despite a commitment otherwise in last year's budget answers, the required process established in the Settlement Agreement is not reflected in either the 2015-2019 Business Plan (see p.7), or the budget presentation.5 We request your commitment to full compliance with the letter and intent of the Settlement Agreement for the 2016 budget process.
For the 2015 Budget, we appreciate that management is proposing a reduction in the tariff rate and the revenue requirement. We understand that management could have found ways to spend the over-collection, and give management full credit for returning an amount that effectively offsets this year's requested budget increase.
We also approve and appreciate some of the specific steps management has taken to contain administrative and operational costs. For example, in the Settlement Agreement, ISO agreed to switch from a defined benefit to a defined contribution retirement plan for new employees, a change we welcome. We agree that it will provide budgeting predictability and lower overall expense in the long run.6
The largest driver of costs in ISO's budget is personnel. We recognize the high quality and caliber of ISO staff. We support management's stated commitment to redeploy existing personnel to address new programmatic challenges. We would, however, request a better quantification of that redeployment, and a more effective effort to comply with the Settlement Agreement's mandate to rely "to the greatest extent possible on its current employee complement to perform all existing and proposed new projects."7 On December 31, 2012, ISO employed 539.5 full-time employees (FTEs), and eighteen months later, as of June 30, 2014, it employs 572 FTEs, or 32.5 additional employees.8 In its proposed 2015 budget, management seeks an additional 9.5 FTE positions, in addition to the eight new FTE positions obtained in the 2014 budget and
4 See ISO New England's 2015-2019 Business Plan, p.7. 5 See ISO 2014 Response to State Agencies' question no. 4. 6 We do note that the adopted defined contribution plan is not modest, as it contributes between 4% and 9% of an employee's combined base salary and performance bonus into the defined contribution account on an annual basis. This is in addition to the existing 401(k) plan, where New England ratepayers are matching 100% of employee contributions up to 3% of wages, and 50% of employee contributions for the next 2%. 7 Settlement Agreement II.A. 8 See ISO 2015 Response to State Agencies' question no. 1.
Philip N. Shapiro Chairman, ISO New England September 25, 2014 Page 3
the 26 new FTE positions obtained in the 2013 budget. This continued growth raises the total number of FTE positions to 595 for the 2015 budget.9
We ask the ISO Board to seriously question why management requires increasing the numbers of employees at this rate. While the New England State Agencies are not proposing a moratorium on new hires at this time, it is often the case that a defined limit on new hires spurs the creativity needed to respond to changing conditions without adding new personnel. We suggest that the ISO-NE Board set a guideline of limiting new hires to a number that more closely approximates the budget constraints of most other employers, including competitive businesses, regulated monopolies and regulatory agencies. This will control costs and encourage management to find ways to better deploy and redeploy the significant personnel resources currently available. Certainly the rate of growth in the employee count that we have seen at ISO over the past decade is not sustainable.
The State Agencies submit that the ISO could update its practices in its planning area to significantly reduce operating expenses. For example, as the ISO has recognized, most major transmission congestion issues have been eliminated. Given the reduced need to study transmission congestion needs, the ISO should consider conducting Regional System Planning studies biennially instead of annually, and redeploying any affected staff to new projects. Moreover, ISO could either eliminate Economic Studies or allocate the costs of conducting such studies in a more equitable manner. We are certain that if pressed, ISO's management could identify other areas where resources critical for a prior need can now be better deployed to address current needs. We understand that some cost savings may require tariff changes and we are willing to participate in such efforts.
In your 2013 CELT Report, you predicted a decline in electricity demand in New England over the next ten years, and you predicted a very modest increase in your 2014 CELT report.10 Nonetheless, with the exception of Hawaii, New England has the highest electricity costs in the country, and ISO-NE is the most expensive RTO in the country. As State Agencies, and on behalf of the ratepayers of New England, we ask the ISO Board to affirm and adopt a commitment to lower and more reasonable electricity rates as part of its metrics for evaluating management's performance, particularly given the forecast for level or a slight increase in electricity demand.
9 Management contends that because of its anticipated vacancy rate, it is only seeking budget authority for 577 FTE positions. Since management requests 9.5 new positions rather than five new hires for 2015 in addition to its current employee count of 572 FTEs, management clearly does not view 577 as a cap on total number of FTEs, but instead anticipates it is able to hire up to the full 595 FTE complement requested. 10 See ISO 2013-2023 Forecast of Capacity, Energy, Loads and Transmission (2013 CELT Report), issued May 1, 2013; ISO 2014-2023 Forecast of Capacity, Energy, Loads and Transmission (2014 CELT Report), revised May 16, 2014.
Philip N. Shapiro Chairman, ISO New England September 25, 2014 Page 4
We look forward to continuing our collaboration to ensure reliable, secure and affordable electricity in New England.
Respectfully submitted,
_Arthur H. House______Elin Swanson Katz______Arthur H. House Elin Swanson Katz Chairman Consumer Counsel Public Utilities Regulatory Authority Office of the Consumer Counsel Ten Franklin Square Ten Franklin Square New Britain, CT 06051 New Britain, CT 06051
_Susan W. Chamberlin______Timothy Schneider______Susan W. Chamberlin, Esq. Timothy Schneider Consumer Advocate Maine Public Advocate Office of the Consumer Advocate Office of the Maine Public Advocate 21 S. Fruit St. Suite 18 112 State House Station Concord, NH 03301 Augusta, ME 04333
_George Jepsen______Leo Wold______George Jepsen Leo Wold, Assistant Attorney General Attorney General Rhode Island Division of Public Utilities Office of the Attorney General and Carriers 55 Elm Street 89 Jefferson Blvd Hartford, CT 06103 Warwick, RI 02888
_Leo Wold______Leo Wold, Assistant Attorney General for Attorney General Peter Kilmartin 150 South Main Street Providence, RI 02903
Cc: Gordon van Welie, President and CEO Raymond W. Hepper, General Counsel Robert C. Ludlow, Vice President and Chief Financial & Compliance Officer
EXHIBIT 11