October 16, 2016
VIA ELECTRONIC FILING
Honorable Kimberly D. Bose, Secretary Federal Energy Regulatory Commission 888 First Street, NE Washington, D.C. 20426
Re: ISO New England Inc., Filing of 2016 Capital Budget and Revised Tariff Sheets for Recovery of 2016 Administrative Costs; Docket No. ER16-______
Dear Secretary Bose:
Pursuant to Section 205 of the Federal Power Act, Part 35 of the Rules and Regulations of the Federal Energy Regulatory Commission (the “Commission”), Section 12 of the Participants Agreement among ISO New England Inc., the New England Power Pool and any Individual Participants,1 and Section IV.B.6.1 of the ISO New England Inc. Transmission, Markets and Services Tariff (the “Tariff”),2 ISO New England Inc. (the “ISO” or “ISO-NE”) hereby submits its capital budget for calendar year 2016 (the “2016 Capital Budget”) and a revised Section IV.A of the Tariff to reflect the collection of its administrative costs for calendar year 2016 (the “2016 Administrative Expenses Tariff”). The ISO requests that the Commission accept the 2016 Capital Budget and the 2016 Administrative Expenses Tariff as filed, effective January 1, 2016.
Because the ISO is a non-profit entity without equity, it relies totally on collections under its Tariff to fund its operational expenses, including through depreciation. For this reason, the ISO is not in a position to make refunds should the Commission accept the 2016 Capital Budget or the 2016 Administrative Expenses Tariff for filing but set them for hearing subject to refund. That is, the only “refunds” that can be paid to ISO Customers during 2016 would have to be funded by additional charges to other Customers. For this reason, the ISO respectfully requests
1 The Participants Agreement is available at http://www.iso-ne.com/static-assets/documents/regulatory/part_agree/ part_agree_1_15_11.pdf. 2 Capitalized terms used but not otherwise defined in this filing have the meanings given them in the Tariff. October 16, 2015 Page 2 of 33
that the Commission accept the 2016 Capital Budget and the 2016 Administrative Expenses Tariff without suspension and not subject to refund.3
Should the Commission have any questions regarding the 2016 Capital Budget or the 2016 Administrative Expenses Tariff, the ISO respectfully requests that such concerns be resolved in an accelerated fashion and addressed in the Commission’s Order issued prior to January 1, 2016. If the Commission decides to set any issues for hearing, the ISO requests that the Commission set the scope of any such hearing as specifically and narrowly as is feasible, and require a paper hearing process, to ensure conservation of ISO, stakeholder, and Commission staff resources.
I. ISO-NE’S 2016 REVENUE REQUIREMENT AND REVISED SHEETS
A. Overview
This filing presents the 2016 Revenue Requirement4 for operating the ISO. Before incorporating the true-up for 2014’s actual expenses and collections, the 2016 Revenue Requirement is $185.2 million, which is $6.8 million more than in 2015. After the over- collection for 2014 is subtracted, the total 2016 Revenue Requirement decreases to $184.5 million. In comparison, the 2015 total – which was reduced by a much larger over-collection of nearly $10 million – was $168.5 million.
In sum, the 2016 Revenue Requirement is 3.8% higher than in 2015 before the prior years’ true-ups. When the two years’ operating budgets are compared with inclusion of the true- ups (including the nearly $10 million true-up for 2013), the 2016 Revenue Requirement is 9.6% higher than the 2015 Revenue Requirement.
For 2016, more than half of the increase in the Core Operating Budget is necessary to maintain the ISO’s current operations, by funding competitive compensation, software licenses and maintenance, and retirement and medical benefits. Most of the remaining increased costs are attributable to: cyber security enhancements, including the establishment of a 24/7 cyber security operations center, as directed by the ISO’s Board of Directors; meeting the Internal Market Monitor’s resource needs; and implementing Commission-approved changes to the Forward Capacity Market (“FCM”). Each of these initiatives is discussed in more detail in Section I.C, below.
3 This approach is consistent with NEPOOL’s recommendation to the Commission that “contested budget increases should not be implemented subject to ‘refunds’” because of the ISO’s non-profit status, which means that any money already spent “can only be reallocated among the stakeholders, negating any true refund.” Comments of the New England Power Pool Participants Committee at 3, Docket No. RM04-12-000 (Nov. 9, 2004) (“NEPOOL RTO Cost Comments”). 4 As used in this filing, “Revenue Requirement” refers to the combination of: the administrative costs of running the ISO (the “Core Operating Budget”); depreciation and amortization; and the true-up for past over-collection or under- collection in revenues versus expenses. Generally, numbers used herein are rounded for ease of reference and, accordingly, may not sum. October 16, 2015 Page 3 of 33
The ISO seeks to add 8.5 full-time employees in 2016, largely to staff the cyber security operations center and to meet the Internal Market Monitor’s personnel requirements. The ISO is meeting other staffing needs by reassigning existing employees. Barring unforeseen circumstances, the ISO intends to fulfill all of its obligations with existing employees in the next budget cycle.
The remainder of this Section I describes:
• the 2016 budget development process (Section B); • components of the 2016 Revenue Requirement (Section C); • the three services provided by the ISO and funded by the 2016 Revenue Requirement (Section D); and • the allocation of costs among the three primary schedules and the development of the rates reflected in the 2016 Administrative Expenses Tariff (Section E).
B. 2016 Budget Development Process
The ISO has always operated in a climate of cost accountability and transparency.5 The ISO annually files with the Commission updated specific dollar-value, non-formula rates to collect the ISO’s Revenue Requirement for each upcoming calendar year. Instead of using a formula rate allowing the automatic collection of every expense as incurred, the ISO revises its specific rates each year from a proposed annual Revenue Requirement that has been reviewed through a multi-stage stakeholder process, voted on by participants, approved by the ISO’s independent Board of Directors, and ultimately filed with the Commission for approval in an open process in which any interested party may participate.
As in past years, the ISO’s budgeting process was driven by the business planning process led by the ISO’s Board of Directors. The business plan’s timeline is five years and, for that period, contains the following overarching objectives: New England’s bulk power system is reliable in both the short- and long-term and the wholesale electricity markets are competitive and efficient; and business operations are well-managed, cost effective, and responsive to New England’s Market Participants, state officials, and other electricity stakeholders.
These objectives formed the foundation for development of the ISO’s 2016 Core Operating Budget. The full seven-step process, throughout which stakeholder input was sought, requires the ISO to:
• define objectives, activities, and goals; • identify efficiencies for each department;
5 The NEPOOL Participants Committee, the ISO’s primary stakeholder body, has lauded the ISO’s budget process, stating that it “works, not only because NEPOOL provides input, but also because ISO-NE is responsive to that input.” NEPOOL RTO Cost Comments at 6. October 16, 2015 Page 4 of 33
• determine resource requirements; • develop budget estimates for each department; • adjust budgets to ensure that staff resources and activities are aligned with the business plan; • conduct senior staff review to ensure alignment of the budget with the business plan and overall fiscal constraint; and • develop priorities.
ISO-NE reviews the budgets with both the New England Power Pool (“NEPOOL”) and the states. To kick off this year’s process, the ISO presented proposed budgets at the June 7, 2015 meeting with the New England Conference of Public Utilities Commissioners and the June 22, 2015 meeting of the NEPOOL Participants Committee.
The ISO then developed its 2016 Revenue Requirement proposal and posted a detailed budget presentation, which includes more than 120 slides regarding the 2016 Capital Budget and the 2016 Revenue Requirement (the “Budget Presentation”).6 The ISO reviewed the Budget Presentation at the NEPOOL Budget and Finance Subcommittee’s August 26, 2015 meeting and at a meeting for state agencies on August 27, 2015.
Following the August 27 meeting, a number of the state agencies submitted written questions regarding the budgets. ISO-NE provided answers, following which the state agencies submitted written comments regarding the budget review process and the ISO’s headcount. Those comments and the ISO’s response are located at Exhibits 10 and 11 to this filing letter.7
The ISO reviewed the 2016 Capital Budget and the 2016 Revenue Requirement at the NEPOOL Participants Committee’s meetings on September 11 and October 2, 2015. At the October 2 meeting, the two budgets were supported unanimously by the Participants Committee (with abstentions).
Contemporaneously with the stakeholder processes, the Board of Directors undertakes its review of the budget. The Board process includes review of particular elements of the budgets by Board committees with responsibility in a defined area. For example, compensation matters are reviewed by the Compensation and Human Resources Committee and projects with reliability implications are reviewed by the System Planning and Reliability Committee. The Audit and Finance Committee advises management throughout the development of the budgets and engages in a detailed review of the budgets in both May and August.
In addition to receiving updates throughout the process from management regarding the stakeholder process and from the Audit and Finance Committee, the Board engages in an in-
6 The Budget Presentation is available at http://www.iso-ne.com/static-assets/documents/2015/09/2_2016_operat_ capital_budget_update_09_23_2015.pdf. 7 Pursuant to a settlement agreement entered into among certain state agencies and the ISO regarding the 2013 budgets, ISO-NE is required to include these comments and its response in its budget filing. October 16, 2015 Page 5 of 33
depth review of the budgets at its September meeting. Last, after receiving final feedback from stakeholders in the form of the Participants Committee’s vote and the comments of the participating state agencies, the Board votes on the budgets.8 In the instant case, after reviewing all input from stakeholders, including the vote of the Participants Committee, the ISO’s Board of Directors approved the 2016 budgets effective October 15, 2015.
C. The 2016 Revenue Requirement
This section provides an overview of the 2016 Revenue Requirement and detail regarding its significant components. Additional detail can be found at Exhibit 3 in the testimony of Robert C. Ludlow, the ISO’s Chief Financial Officer, and the exhibits thereto.
As noted above, the 2016 Revenue Requirement, after the true-up for 2014, is $184.5 million.9 It includes the following components, each of which is discussed below.
• the 2016 Core Operating Budget ($152.2 million); • depreciation and amortization of regulatory assets ($33 million); and • a true-up for 2014 that reduces the 2016 Revenue Requirement by $600,000 as a result of over-collection of ISO rates in 2014.
While the ISO has amassed a consistent track record of spending integrity – since the inception of its self-funding tariff for calendar year 1998, the ISO’s annual spending has never exceeded its budget – the risk exists that the ISO may have to incur additional expenditures during 2016 that exceed the allocated amounts and contingencies. Specific potential risks include unforeseeable litigation, costs of complying with Order 1000 that exceed estimates, cyber security threats, imposition of new requirements by policymakers, and interest rate changes.
In general, the demands placed on the ISO by Market Participants and regulators will determine the extent of additional work and the resources the ISO will require. In any case, should the need ever arise for the ISO to spend more than a given year’s Revenue Requirement, the ISO will first seek stakeholder support and then file a rate increase with the Commission, thus allowing stakeholder and Commission review before approving such increases.
1. Components of the Core Operating Budget Increase
The ISO proposes to increase its Core Operating Budget from 2015 levels to: (i) maintain competitive compensation and benefits ($3.8 million); (ii) maintain existing software licenses and maintenance ($1.3 million); (iii) fund cyber security initiatives ($1.3 million), including the institution of a 24/7 cyber security operations center which accounts for
8 The ISO must report the results of all Participants Committee votes on the budgets to the Board of Directors and to the Commission. Participants Agreement at §§ 12.3, 12.5 9 See the Budget Presentation for a breakdown of the Revenue Requirement by functional area (slides 24-45) and category (slides 64-77). October 16, 2015 Page 6 of 33
approximately half of the increase; (iv) meet the Internal Market Monitor’s resource needs, including two new headcount ($1.0 million); (v) implement changes to FCM ($800,000); and (vi) miscellaneous increases, including increased costs for hardware leasing, maintenance, information technology consulting, and training. Below, the ISO discusses the costs in each of these categories, including the addition of 8.5 employees,10 and then reviews the savings, efficiencies, and non-recurring work that offset these increases by $3.8 million.11
a. Increases to Maintain Competitive Compensation and Benefits
To maintain medical benefits and life and disability insurance for its employees and to fund its defined contribution pension plan,12 the ISO will incur an additional $700,000 in costs. This category also includes the ISO’s $3.1 million budget for a 2.75% increase in salaries based on merit and a .75% increase for promotions.
The merit and promotional increases are used to keep the ISO’s salaries competitive, thereby attracting and retaining the high-quality employees crucial to the ISO’s operations. This goal remains relevant, as more candidates are declining the ISO’s job offers, and many are citing compensation as the reason; specifically, thirteen candidates declined the ISO’s job offers in 2014 and to this point in 2015 because, in their estimation, the compensation was insufficient.13 In addition, the ISO has lost eighteen employees in 2014 and to date in 2015 to higher-paying jobs.14 With this turnover comes inefficiency; for example, it takes months to fill a transmission engineer vacancy, followed by an inevitable learning curve.
To establish the amounts of the merit and promotional increases, the ISO reviews survey data from several national compensation consultants on expected merit and promotional pool increases, as well as expected salary range adjustments for the coming year. The surveys the ISO used to develop its 2016 Revenue Requirement recommendations collectively polled thousands of employers and include both all-industry and utility-specific data.15
The ISO also complies with the standards of the Internal Revenue Service when determining executive compensation. These standards encompass all aspects of compensation, including base salary and all bonuses, and require that the ISO’s executive and Board compensation fall within a range of competitive practices for total compensation paid by
10 See slide 23 of the Budget Presentation for a breakdown of the new additions. 11 See the Budget Presentation for more information on all of these year-over-year budget changes. 12 As of January 1, 2014, the ISO closed its defined benefit plan to new entrants and offered new employees an enhanced defined contribution plan. 13 See Exhibit 4 at p. 7 and ISO New England Inc., Filing of 2015 Capital Budget and Revised Tariff Sheets for Recovery of 2015 Administrative Costs, Docket No. ER15-112-000 at pp. 6-7 of Exhibit 4 (October 16, 2014). 14 Id. 15 The surveys used by the ISO were conducted by Buck Consultants, Mercer, WorldatWork, the Conference Board, Towers Watson and Aon Hewitt. October 16, 2015 Page 7 of 33
similarly-situated organizations, both taxable and tax-exempt, for functionally comparable positions.16
To ensure compliance, the ISO has engaged a nationally recognized, independent consulting firm, which evaluates the compensation offered by similarly-situated entities. This evaluation includes other system operators and select for-profit “peer” utility organizations (chosen for organizational size, complexity, and scope of responsibilities). It also incorporates a broader comparison across all industries for positions not unique to utilities (again, comparators are selected for organizational size, complexity, and scope of responsibilities). The resulting opinion each year has been that the ISO’s executive and Board compensation is within a reasonable range of competitive practice for functionally comparable positions among similarly- situated entities. The Commission has found that this process results in just and reasonable compensation.17
The testimony of Janice S. Dickstein, the ISO’s Vice President, Human Resources (located at Exhibit 4), provides more detail on the ISO’s compensation practices, as does the Budget Presentation (at slides 46-61).
b. Increases in Computer Licensing and Maintenance Costs
The cost increase of $1.3 million in this category represents increased costs for on-going support, systems backup software, and support for new hardware and software. Most significantly, the costs stem from Microsoft’s determination that independent system operators and regional transmission organizations no longer qualify for pricing as charitable organizations.
c. Cyber Security Costs
Costs in the area of cyber security reflect the growing risk in this area, and the ISO’s vulnerability, given its control of sensitive information about the financial settlement of billions of dollars per year, the topology of the grid, and the protected information of Market Participants and employees.
More than half of the cost increase of $1.3 million in this category is to fund six full-time employees who will provide around-the-clock surveillance of systems and networks in a cyber security operations center. The ISO’s Board of Directors proposed this center after convening an ad hoc Cyber Security Committee to assess and address the cyber security risks to the ISO. The remainder of the cost increase is for new or enhanced monitoring software and for cyber security insurance, a relatively new product that provides protection against the costs of a cyber security event.
16 See Internal Revenue Code § 4958. 17 ISO New England Inc., 117 FERC ¶ 61,310 at P 18 (2006); Order on paper hearing and finding rehearing to be moot, 119 FERC ¶ 61,178 (2007). October 16, 2015 Page 8 of 33
d. Costs to Meet the Internal Market Monitor’s Resource Needs
The ISO’s Internal Market Monitor has identified resources that are required to allow his department to perform their monitoring and mitigation functions. These resources include two new full-time employees and consulting support to address workload created by new features of FCM, including de-list reviews, non-price retirements, Pay For Performance, and an update to the Offer Review Trigger Price. Other portions of the cost increase will fund enhanced monitoring capabilities through improvements in processes, data gathering, and analysis for systems enhancements. Finally, funds have been allocated for information technology support of market monitoring systems.
e. Implementation of Changes to FCM
As noted in the preceding paragraph, there have been a number of changes to FCM that have increased the ISO’s workload. More specifically, the cost increase in this category results from the need for additional consulting and staff time in Market Development to design sloped demand curves, qualification process changes, and auction pricing rules and associated reconfiguration auctions. Other increased costs include consultant funding in System Planning to update the calculation of the Cost of New Entry.
f. Miscellaneous Increases
The cost increase in this category is attributable to increased hardware leasing costs, maintenance of new control room communication systems, consulting services in Information Technology to support Model-On-Demand, support for enhancements to the Energy Management System, training on reliability standards for System Operations, and integration of market enhancements in Settlements and Market Operations. These enhancements include Sub- Hourly Settlements, Divisional Accounting and Oracle Business Intelligence. Finally, this category includes increased dues owed to the North American Electric Reliability Corporation (“NERC”) and the Northeast Power Coordinating Council and fees for the Eastern Interconnect Data Sharing Network.
g. Offsetting Savings; Direct Charge Activities
The ISO works to offset increased costs through cost-cutting and reallocation of resources to emerging initiatives. For 2016, the ISO has realized $3.8 million by reallocating resources, automating work, identifying efficiencies, and eliminating discontinued or non- repetitive work.
To meet 2016 priorities, the ISO will reallocate the responsibilities of six employees in Market Operations and two in System Planning. Additionally, internal ISO employees will assume work previously performed by contractors, under both the operating and capital budgets, including in Market Operations (operating and capital), Legal (operating), and System Planning (operating).
The ISO also expects to reduce salaries as a result of staff turnover. Finally, automation of functions in Market Operations and Settlements, including improvements in data querying and October 16, 2015 Page 9 of 33
validation, resettlement processing and certain reporting tools, will result in reduced data gathering and processing time.
The $3.8 million also includes a small amount of savings in year-over-year contributions to the ISO’s defined benefit pension plan, which was closed to new entrants as of January 1, 2014, but which must still be funded to meet the ISO’s obligations to employees who were enrolled before that cut-off date.
For 2016 and future years, the ISO has changed its funding methodology for the defined benefit pension plan by adopting a “level funding” approach. After consulting with its actuaries and investment consultants, the ISO decided on a flat $10 million contribution to the plans for each of the next ten years (barring unforeseen circumstances). This level funding approach should decrease the volatility of the expense while still maintaining reasonable levels of funding. If the ISO had not adopted this approach, the 2016 contribution would have been $11.05 million.18
The ISO will also offset its costs through certain direct charges. Section IV.A of the Tariff includes provisions for the ISO to assess direct charges to collect reasonable administrative costs for performing certain discrete functions, including transmission studies,19 information requests,20 non-standard contract provisions,21 and non-standard billing.22 Expected revenues to reimburse ISO staff efforts for studies (as opposed to revenues that are flowed through to contractors actually performing the studies) have been used to reduce the relevant schedule’s 2016 Revenue Requirement.
2. Depreciation
As a non-profit entity without equity, the ISO must recover revenues consistent with its obligation to repay the loans funding its projects. In fact, the ability to obtain and maintain independent financing is dependent upon the ISO’s being able to recover the principal portion of debt service through depreciation and amortization.
For 2016, the ISO’s depreciation and amortization costs are $33 million, which is $1.3 more than in 2015. The increased costs are largely attributable to a number of significant capital projects expected to go into service at the end of 2015 or the beginning of 2016, including the Coordinated Transaction Scheduling project, Part 1 of the Generation Control Application project, phase 3 of the Business Continuity Planning project, the project to comply with version
18 See the Budget Presentation at slides 57-58 and Exhibit 3 at p. 15. 19 Tariff § IV.A.6.1 (Transmission Studies). This provision permits, for example, charging for the performance of System Impact Studies, Facilities Studies and FCM qualification studies. 20 Tariff § IV.A.6.2 (Information Requests). 21 Tariff § IV.A.6.3 (Non-Standard Provisions). 22 Tariff § IV.A.6.4 (Non-Standard Billing Service). October 16, 2015 Page 10 of 33
5 of NERC’s Critical Infrastructure Protection standards, and phase 2 of the Wind Integration/Do Not Exceed Dispatch project.23
The ISO’s depreciation rates remain unchanged from those previously accepted by the Commission.24 The ISO uses the straight-line depreciation methodology based on no net salvage value and the various average service lives described below. These service lives reflect the ISO’s historical experience and forecasted expectations for capital projects placed into service, are necessary to comply with the ISO’s funding mechanisms, are consistent with the ISO’s historical experience, and have been repeatedly determined by independent auditors to be reasonable. The service lives are:
• Computer hardware, software and accessories: 3 to 5 years • Software development costs: 3 to 5 years • Furniture and fixtures: 7 years • Machinery and equipment: 7 years • Building: average of 25 years (based on the opinion of independent bond counsel and analysis of the service lives of the different aspects of the building (e.g., the building’s steel and concrete at 40 years, mechanical and electrical work at 25 years, and high wear-and-tear elements at 15 years)) • Leasehold/Building Improvements: lesser of 1 to 25 years or remaining life of the lease or building, as determined at the time of the purchase based on the nature of each such improvement (e.g., rooftop railing at twenty-five years, air conditioning unit at fifteen years, capacitor bank at ten years) • Vehicles: 3-7 years
3. True-Up Mechanism
As set forth in Section IV.A.2.2 of the Tariff, the 2016 Revenue Requirement includes an adjustment for deviations between actual collections and expenses for calendar year 2014. In general, the amount of the true-up is added to (in the case of a revenue shortfall) or subtracted from (in the case of a revenue over-recovery) the ISO’s total estimated budgeted amounts for the upcoming budget year. In the case of the 2014 true-up, the ISO collected $600,000 more than it needed to pay its expenses.25 This sum will be subtracted from the 2016 Revenue Requirement.
With respect to Schedule 1, the ISO had expenses of $38 million, and collected revenues of $36.3 million, resulting in an under-collection for Schedule 1 (i.e., the increase to the 2016
23 See Exhibit 3, RCL-5, Schedule 4, page 2 of 2. 24 In 2006, the Commission examined and accepted the ISO’s depreciation rates after holding a paper hearing. ISO New England Inc., 117 FERC ¶ 61,310 at P 18 (2006), Order on paper hearing and finding rehearing to be moot, 119 FERC ¶ 61,178 (2007). 25 See Exhibit 3, RCL-2, Schedule 2, page 1 of 2. October 16, 2015 Page 11 of 33
Revenue Requirement for Schedule 1) of about $1.7 million.26 With respect to Schedule 2, the ISO had expenses of $75.2 million and collected revenues of $77.5 million, resulting in an over- collection for Schedule 2 (i.e., the decrease to the 2016 Revenue Requirement for Schedule 2) of approximately $2.35 million.27 Finally, with respect to Schedule 3, the ISO had expenses of $49.55 million and collected revenues of $49.51 million, resulting in an under-collection for Schedule 3 (i.e., the increase to the 2016 Revenue Requirement for Schedule 3) of approximately $40,000.28
D. Services Funded by the 2016 Revenue Requirement
This section discusses the three services the ISO provides, which correspond to the rate schedules through which the ISO recovers its Revenue Requirement: Schedule 1 - Scheduling, System Control and Dispatch Service (“Scheduling Service”); Schedule 2 - Energy Administration Service; and Schedule 3 - Reliability Administration Service.
1. Scheduling Service (Schedule 1)
Scheduling Service includes the transmission-related service required to schedule at the pool level the movement of power through, out of, within, or into the New England Control Area. It does not cover expenses of dispatching Energy, which are collected as part of the charges in Schedule 2. Scheduling Service can be provided only by the ISO, and all Transmission Customers must purchase this Service from the ISO. The 2016 Revenue Requirement for Schedule 1 (including true-ups) is $46 million.
Functions performed by the ISO in connection with this Service include:
• 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.
26 See Exhibit 3, RCL-2, Schedule 2, page 2 of 2. 27 See Exhibit 3, RCL-2, Schedule 2, page 2 of 2. Pursuant to Section IV.A.2.2 of the Tariff, the true-up is calculated separately for Schedule 2. See also Section I.E.4.b of this transmittal letter. 28 See Exhibit 3, RCL-2, Schedule, 2 page 2 of 2. October 16, 2015 Page 12 of 33
2. Energy Administration Service (Schedule 2)
Energy Administration Service is the service provided by the ISO to administer the Energy Market. The 2016 Revenue Requirement for Schedule 2 (including true-ups) is $82.4 million.
The ISO’s functions that comprise Energy Administration Service include:
• core operation of the Energy Market; • generation and demand dispatch related to the Energy Market; • energy accounting; • loss determination and allocation; • billing preparation; • market power monitoring and mitigation for the Energy Market; • sanctions activities; • operation of Financial Transmission Rights auctions; • market assessment and reports; and • formulation of additional market rules and proposals to modify existing rules.
3. Reliability Administration Service (Schedule 3)
The ISO provides Reliability Administration Service to administer the Reliability Markets, including FCM, in accordance with Market Rule 1 and to provide other reliability and informational services. These services are of a type not directly related to the services provided under Schedules 1 and 2, and are expenses of operating the New England Control Area generally, rather than expenses attributable to serving a particular Customer. The 2016 Revenue Requirement for Schedule 3 (including true-ups) is $56.1 million.
Examples of the functions performed (in addition to the core operation of the Reliability Markets) include:
• generation and demand dispatch associated with Reliability Markets; • Reliability Markets accounting; • billing preparation; • generation emissions analysis; • risk profile updates; • triennial review of resource adequacy; • studies and qualification of resources under FCM; October 16, 2015 Page 13 of 33
• preparation of regional reports and load forecasts and profiles (Capacity, Energy, Load and Transmission (“CELT”) Reports; reports to the Energy Information Administration of the United States Department of Energy; reports to NERC; Regional System Plan); • support of power supply, environmental and market reliability planning activities; • market power monitoring, mitigation and assessment for the Reliability Markets; and • formulation of additional market rules and proposals to modify existing rules.
E. Cost Allocation and Rate Development
This section describes the new rates proposed herein by: (i) detailing how the ISO generally allocates its costs among the three core rate schedules; (ii) explaining the billing determinants used by each schedule; (iii) explaining how the ISO adjusted the billing determinants for 2016; (iv) describing the rates ultimately derived for 2016 for each schedule; and (v) explaining how and why the Revenue Requirement for each schedule shifted.
1. Cost Allocation Among the ISO’s Services
Most of the ISO’s operating costs are fixed and do not vary based on the volume of a Customer’s activity—a fact recognized by the Commission itself.29 The ISO established the core rate design for its first three schedules through an uncontested settlement approved by the Commission in 2001,30 with additional modifications reflecting necessary changes upon the commencement of Standard Market Design in New England. Although the 2001 settlement is no longer binding, the ISO followed the same cost allocation among the three primary schedules when establishing the rates proposed herein.
The Tariff structure relies upon the activity-based allocation of the ISO’s costs to its three rate schedules, namely Scheduling Service, Energy Administration Service, and Reliability Administration Service. These rate schedules coincide with the main “service categories” of the ISO. Exhibit 3, RCL-3, Schedule 1 contains a Test Year 2016 cost of service for the three rate schedules. This exhibit lays out in detail how the ISO’s costs were assigned to the schedules.
In assessing how costs should be assigned to the various categories of service that the ISO provides to its Customers, the objective is to reflect cost causation principles as much as possible. All costs that could be assigned to the three rate schedules using direct allocators were so allocated. Most activity costs consist of direct labor costs, employee benefits, and other 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
29 ISO New England Inc., 89 FERC ¶ 61,339 at p. 62,019 (1999), reh’g denied, 91 FERC ¶ 61,016 (2000) (finding that the ISO’s expenses “are essentially fixed” and that the issue of rate design involves “not so much cost causation, as it does the equitable allocation of an essentially fixed amount of expenses among many users of the grid”). 30 See Settlement Agreement in Docket No. ER01-316-000 (filed June 1, 2001). October 16, 2015 Page 14 of 33
schedule using the same allocator. Within a given department, known allocators (Alloc-Fixed) for specific cost categories or activities were used to allocate those labor costs that were specifically attributable to a schedule. All remaining labor costs within that department were allocated in proportion to the distribution of the summed Alloc-Fixed labor costs among the three schedules. Labor costs within all departments were allocated in this manner and summed for the entire company.
2. Rate Design and Billing Determinants
As discussed below, each Schedule utilizes different billing determinants and attempts to reflect cost causation principles, to the extent possible. The ISO is not proposing any changes to the design of the billing determinants for 2016; however, as part of its filing of the Coordinated Transaction Scheduling (“CTS”) project with the New York ISO, ISO-NE filed changes to Schedules 1, 2 and 3 of Section IV.A of the Tariff on September 10, 2015.31 Those changes are still pending before the Commission.
CTS is intended to enhance the market efficiency of external transactions (i.e., energy imports and exports) between the two regions through economic clearing of external transactions. As part of that effort, ISO-NE has proposed that certain charges in Schedules 1, 2 and 3 be eliminated, effective on or after December 1, 2015. If the Commission approves the changes, they will affect collections under Schedules 1, 2 and 3. The ISO has estimated the impact of this change using historical monthly average volumes for external transactions and total pool charges, and, based on the analysis performed, has concluded that the eliminated charges make up 1.1% of Schedule 1 total charges, 2.8% of Schedule 2 charges, and 1.4% of Schedule 3 charges. Their elimination will raise the affected billing determinants.32
In its development of rates for 2016, ISO-NE has presumed Commission approval of the pending CTS filing; accordingly, any effects have been incorporated into the 2016 rates that are described herein. Below, ISO-NE highlights the sections of the Schedules where CTS changes have been proposed.
a. Schedule 1
The billing determinants for Schedule 1 are Monthly Regional Network Load and Reserved Capacity; changes are pending before the Commission to exclude Coordinated External Transactions, which are defined in Section I of the Tariff as transactions at external interfaces to which the enhanced scheduling procedures in the CTS rules (located in Tariff Section III.1.10.7.A) apply.
31 ISO New England Inc. and New England Power Pool, Coordination Agreement, Market Rule 1, OATT Conforming Revisions Relating to Coordinated Transaction Scheduling; Docket No. ER15-2641-000 (September 10, 2015). 32 Slides 5-7 of “Coordinated Transaction Scheduling: Self and Capital Funding Tariff,” a presentation to the NEPOOL Budget & Finance Subcommittee that was made in May 2015. The presentation can be found at http://www.iso-ne.com/static-assets/documents/2015/05/5a_coordinated_transaction_sch_self_cap_cft.pdf. October 16, 2015 Page 15 of 33
Monthly Regional Network Load is measured in kilowatts. The determinant based on Reserved Capacity uses the highest amount of Reserved Capacity for an hour for each transaction scheduled to occur during the month as Through or Out Service. Schedule 1 revenues collected from Through or Out Service Customers are credited to each Network Customer that month in proportion to each Network Customer’s Monthly Regional Network Load. Revenues from the Non-Participant Financial Transmission Rights (“FTR”) fee described in Market Rule 1 and non-refundable Long Lead Facility deposits will be credited to the Schedule 1 Revenue Requirement through future true-ups.
b. Schedule 2
The Schedule 2 Revenue Requirement is allocated 15% to Transaction Units (“TUs”) and 85% to Volumetric Measures (“VMs”), subject to the special true-up described below. TUs measure the frequency and duration of activity and are indifferent to the size (e.g., capacity) of any particular transaction. Conversely, VMs seek to capture a Customer’s “physical” reliance on the system administered by the ISO and thus the benefit received.
Schedule 2 utilizes three types of TUs: (i) those associated with Real-Time Energy Market transactions (“Energy TU Based Charges”), (ii) those associated with Increment Offers and Decrement Bids, and (iii) those associated with FTR auction bids.
Energy TU Based Charges: These charges equal the sum per month of a Customer’s Bilateral Contract Block-Hours, Demand Bid Block-Hours, Asset Related Demand Bid 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%. If the Commission approves the pending CTS rules, Energy TUs will be calculated without reference to contributions from Coordinated External Transactions.
TU Charges Based on Increment Offers and Decrement Bids: These charges are based on both of the following: (i) a charge multiplied by the total number of Increment Offers and Decrement Bids submitted; plus (ii) a charge multiplied by the total number of Increment Offers and Decrement Bids that clear the Day-Ahead Energy Market. This category is sometimes referred to as “virtual activity.”
TU Charges Based on FTR Auction Bids Submitted and Cleared: These charges are intended to recover all costs for operating the monthly, multi-month and annual FTR auctions. The charges consist of: (i) a unitized charge multiplied by the total number of bids submitted to the FTR auctions; plus (ii) a unitized charge multiplied by the total number of bids that clear the FTR auctions.
Schedule 2 Volumetric Measures consist of the sum of a Customer’s Monthly Real-Time Load Obligation and Monthly Real-Time Generation Obligation (measured in megawatt hours (MWh)). Under the ISO’s current rate regime, Schedule 2 VMs are priced under a three-tiered October 16, 2015 Page 16 of 33
declining block wherein the highest unitized rate is assessed to the first 250,000 MWh each month. The Customer’s next 1,250,000 MWh are priced at a discount of approximately 10% from the tier-1 unitized rate, and VMs in excess of 1,500,000 MWh incur the lowest unitized monthly rate. If the Commission approves the pending CTS rules, Volumetric Measures will exclude the Monthly Real-Time Generation Obligation associated with Coordinated External Transactions.
c. Schedule 3
Schedule 3 allocates internal load activity based on Real-Time NCP [Non-Coincident Peak] Load Obligation. For Exports, Schedule 3 assesses a volumetric (per MWh) charge.33 Specifically, the ISO divides the Schedule 3 Revenue Requirement by the real-time load obligation forecasted for the upcoming year in the most recent CELT Report to yield the unitized rate per kW-month.34 The remaining revenue requirement for Schedule 3 (i.e., net of that allocated to Exports) is then divided by the total Real-Time NCP Load Obligation forecast to yield the unitized rate per kW-month. If the CTS rules are approved by the Commission, Coordinated External Transactions will be exempt from Schedule 3 Export charges..
3. Adjusting Billing Determinants for 2016
The data used in designing the proposed rates in the 2016 Administrative Expenses Tariff was taken from the ISO markets system for the 12-month period ending July 2015. Consistent with the practice reflected in the ISO’s Tariff filings for 1999 through 2015, the ISO also relied on information contained in the annual CELT Report. The development of the escalation factors is shown in Exhibit 3, RCL-7, Schedules 1 and 2.
In sum, the ISO’s analysis of CELT Report data, other load data, and transaction data through July 2015 suggests that the estimated data for August 2015 through December 2015 should be based, without change, on 2014 data. The ISO’s analysis of the data also led to an increase of 1.0% in the projected data for 2016 (over 2015 levels) for the Schedule 1 (i.e., Regional Network Load) billing determinant. However, this increase is offset by a 1.1% reduction attributable to CTS. The net escalation factor is .999.
The Schedule 2 transaction unit determinants for virtual transactions and FTRs were left flat for 2016, as the numbers of virtual transactions and FTRs have fluctuated in recent years but have not substantially changed overall. Data regarding these calculations appears in Exhibit 3, RCL-7.
The Schedule 2 transaction unit determinants for Energy TUs decrease as a result of CTS by an escalation factor of .967. The volumetric measures in Schedule 2 decrease by a factor of
33 The Commission accepted the current form of the Schedule 3 rate design that distinguishes Exports from internal activity in a June 2, 2006 Letter Order issued in Docket No. ER06-926-000. 34 ISO New England Inc., 2015-2024 Forecast Report of Capacity, Energy, Loads and Transmission (May 1, 2015). See http://www.iso-ne.com/static-assets/documents/2015/05/2015_celt_report.pdf. October 16, 2015 Page 17 of 33
.985, after netting a load increase of 1.0% against a 2.5% reduction based on CTS implementation. See column (i) of RCL-7, Schedule 2.
Finally, the Schedule 3 billing determinant based on export volumes is decreased most dramatically as a result of CTS implementation, by an escalation factor of .655, as shown in RCL-7, Schedule 2, column (k). The remainder of the Schedule 3 revenue requirement is assessed via a billing determinant related to NCP Load Obligation. This billing determinant, like the Schedule 2 volumetric measures and the Schedule 1 billing determinants, is increased by 1.0% based on CELT Report load data, as shown in column (j) of RCL-7, Schedule 2. Although the NCP Load Obligation billing determinant is not directly impacted by CTS implementation, under CTS the rate will increase due to lower estimated volume for Schedule 3 exports since the NCP Load Obligation absorbs the remaining Schedule 3 revenue requirement.
4. Deriving the 2016 Rates
a. Rate Development for Scheduling Service (Schedule 1)
The ISO’s Revenue Requirement for Schedule 1 totals $46 million. The total underlying annual billing determinants for Schedule 1 are 238,898,663 kilowatt-months,35 reflecting the escalation factor discussed above, based on actual plus forecasted activity in 2015. The resulting rate is $0.19275 per kilowatt-month, which is billed as $0.00026 per kilowatt-hour. 36
b. Rate Development for Energy Administration Service (Schedule 2)
In determining the ISO’s Revenue Requirement for 2016, the ISO includes a true-up for 2014 based on both the TU and VM portions of Schedule 2.37 In implementing the true-up adjustment for revenue differences in the VM portion of Schedule 2, the differences will be added to (in the case of a revenue shortfall) or subtracted from (in the case of a revenue 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 2016 Revenue Requirement for Schedule 2. An additional percentage of the shortfall will be added to the ISO’s projected revenue requirement for the Schedule 2 VMs for each percentage decrease that was deemed to have occurred between the number of TUs used in the true-up and the number of TUs that the ISO had used in the original projection of the rates for that year. The maximum percentage of the shortfall that will be added to the VMs is 100%, which would result if the percentage difference between the actual and forecasted TUs was 50% or greater. Any remaining revenue shortfalls will be added to the ISO’s projected revenue requirement for the Schedule 2 TUs.
35 Exhibit 3, RCL-7, Schedule 3, Line 2. 36 Exhibit 3, RCL-7, Schedule 3, Lines 2-3. 37 Consistent with the 2001 Settlement, injections associated with energy imported into the New England Control Area by Bangor Hydro-Electric Company (up to 300 MW) across the New Brunswick Tie are excluded for billing and rate calculation purposes from Energy Administration Service VMs. October 16, 2015 Page 18 of 33
The TU recovery for 2014 was an over-collection of TU revenue in the amount of $1.4 million. As a result of the TU over-collection, the allocation of Schedule 2 revenue will be 85% to VMs and 15% to TUs, with no adjustment necessary.38
The ISO’s Revenue Requirement for Energy Administration Service consists of its expenses for the functions required to provide the Service, as described above. The year 2016 budget costs assigned to Schedule 2 total approximately $82.4 million after true-up.39 Of this total cost, $12.4 million (i.e., 15% of the Energy Administration Service Revenue Requirement) is projected to be recovered pursuant to the rate design through user charges related to TUs.40 Included in this amount is $11.3 million of costs assessed to Energy TUs under a declining block rate, billed as follows: $0.66437 per TU for Block 1; $0.60397 per TU for Block 2; and $0.54358 per TU for Block 3.41 Total projected Energy TUs for 2016 are 17,783,524.42 In addition, $970,196 has been budgeted for operating the FTR auction, and will be recovered through the following rates: $2.02863 per FTR bid submitted; and $2.62374 per FTR bid that clears the auction.43 Finally, the TU Revenue Requirement includes $42,793 for the submission and clearing of Increment Offers and Decrement Bids, which is billed as $.00500 per submitted offer or bid, and $.06000 per cleared offer or bid.44
The remainder of the total Schedule 2 cost for 2016, approximately $70 million45 (i.e., 85% of the Energy Administration Service Revenue Requirement), is projected to be recovered pursuant to the existing rate design through user charges related to VMs incurred under three different declining block rates. The rates are as follows: $0.28296 per VM for Block 1; $0.25723 per VM for Block 2; and $0.23151 per VM for Block 3.46 Total projected Schedule 2 VMs for 2016 are 260,382,763.47
c. Rate Development for Reliability Administration Service (Schedule 3)
The ISO’s 2016 Revenue Requirement for Reliability Administration Service consists of its expenses for the functions required to provide the Service, as described above. These expenses, totaling $56.1 million after true-up, are detailed in Exhibit 3, RCL-3, Schedule 1 to
38 Exhibit 3, RCL-7, Schedule 6. See also RCL-2, Schedule 2 and Section I.C.3. The overall Schedule 2 true-up is an under-collection of $2.35 million. 39 Exhibit 3, RCL-3, Schedule 1. 40 Exhibit 3, RCL-7, Schedule 3, Line 6. 41 Exhibit 3, RCL-7, Schedule 3, Lines 16-19. 42 Exhibit 3, RCL-7, Schedule 3, Line 20. 43 Exhibit 3, RCL-7, Schedule 3, Lines 11-13. 44 Exhibit 3, RCL-7, Schedule 3, Lines 7-9. 45 Exhibit 3, RCL-7, Schedule 3, Line 22. 46 Exhibit 3, RCL-7, Schedule 3, Lines 23-25. 47 Exhibit 3, RCL-7, Schedule 3, Line 26. October 16, 2015 Page 19 of 33
this filing. The ISO recovers its Schedule 3 Revenue Requirement from Market Participants through two separate rates: (i) a Real-Time NCP Load Obligation charge (assessed to internal load); and (ii) a per-MWh rate for Exports. The total underlying Real-Time NCP Load Obligation is 270,740,473 kilowatt-months.48 The resulting rate is $0.20313 per kilowatt- month.49 The Export rate is $0.40 per MWh.50
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 2016 Revenue Requirement to the Schedule 3 forecasted Revenue Requirement for 2002 to the 2002 Reliability Administration Service Fee, to obtain a monthly Fee of $2,347.77, or an hourly rate of $3.22. See Mr. Ludlow’s testimony at Exhibit 3 (pages 42-43) for more details on the calculation of this hourly rate.
5. Analysis of Cost Shifts Across Schedules
Before true-up, the breakdown by schedule shows an increase in Schedule 1 of $2,033,304 (from $42,327,088 to $44,360,392), an increase in Schedule 2 of $3,702,870 (from $81,019,153 to $84,722,023), and an increase in Schedule 3 of $1,100,135 (from $54,968,671 to $56,068,806). Several factors contributed to this result.51
Schedule 1. The increase in the Revenue Requirement for Schedule 1 results from 2016 cost increases and changes that impact all three schedules, including the costs to maintain benefits and compensation, the costs of cyber security improvements, computer service licensing and maintenance, and depreciation expenses for in-service projects including Critical Infrastructure Protection v. 5 and Business Continuity Planning Phase III – Remote Desktop. The remainder of the Schedule 1 increase is depreciation expense for the Coordinated Transaction Scheduling project (predominantly allocated to Schedule 1) and the Generation Control Application Production Part 1 project (allocated evenly between Schedules 1 and 2). All of these costs are discussed in Sections I.C.1 and I.C.2 above.
Schedule 2. The increase in the Schedule 2 Revenue Requirement is largely due to: the increases that impact all three schedules, as discussed in the preceding paragraph; increased funding for market monitoring, as discussed above; and depreciation for the Business Continuity Planning Phase III – Markets Infrastructure project (largely allocated to Schedule 2), the Generation Control Application Production Part 1 project (allocated evenly between Schedules 1 and 2), and the Wind Integration Phase II/Do Not Exceed Dispatch project (allocated evenly between Schedules 2 and 3).
48 Exhibit 3, RCL-7, Schedule 3, Line 31. 49 Id. 50 Exhibit 3, RCL-7, Schedule 3, Line 32. 51 For more information on the factors discussed below, see memo to NEPOOL Budget & Finance Subcommittee and Participants Committee from Bob Ludlow and Cheryl Arnold dated September 23, 2015. The memo is located at http://www.iso-ne.com/static-assets/documents/2015/09/npc_20151002_supplemental_notice.pdf (item 5a). October 16, 2015 Page 20 of 33
Schedule 3. The increase in the Schedule 3 Revenue Requirement is due to: the increased costs allocated to all three schedules (see above); funding for the increased FCM costs discussed above; the increased Market Monitoring costs related to FCM (also discussed above); and depreciation expense for the FCA 10 project (entirely allocated to Schedule 3) and the Wind Integration Phase II/Do Not Exceed Dispatch project (allocated evenly between Schedules 2 and 3). The increases were offset by an overall reduction in depreciation expense as a result of previously-implemented projects becoming fully depreciated during 2016. These projects include the Synchrophasor Infrastructure and Data Utilization project, the Energy Management System Upgrade and Enhancements project, and the FCM Enhancements 2012 project.
II. ISO-NE’S 2016 CAPITAL BUDGET
The 2016 Capital Budget is a list of the ISO’s planned capital expenditures in 2016. The ISO does not make any collections through its capital budget; rather, the capital projects reflected in the budget are funded through private placement financing.52 The ISO funds the capitalized portion of the interest on that financing through recovery of depreciation under its annual operating budget, as discussed in Section I.C.2 above. In sum, the costs of these projects are collected once only, through the depreciation recovery in the Revenue Requirement.
Before describing the projects that comprise the 2016 Capital Budget, the ISO provides context for the Capital Budget in the following Sections II.A and B.
A. The 2016 Capital Funding Arrangements
By way of review and introduction, Section IV.B of the Tariff (called the Capital Funding Arrangements) permits the ISO to collect from Market Participants:
(1) the costs of budgeted capital items, through a Capital Funding Charge, if the costs are not financed by the ISO;
(2) through an Early Amortization Charge, the remaining unamortized costs of assets financed by the ISO in the event of termination, acceleration or required repayment of private financing or, in the case of non-amortizing private financing, payment at maturity if the ISO is unable to refinance such financing;
(3) the working capital amount required by the ISO, if financing arranged by the ISO to meet working capital requirements is terminated early or repayment is accelerated (and no replacement financing has been obtained by the ISO), through an Early Amortization Working Capital Charge; and
52 The debt was approved by the Commission in Docket No. ES04-39-000, 109 FERC ¶ 62,195 (2004) and Docket No. ES12-48-000, 140 FERC ¶ 62,173 (2012). October 16, 2015 Page 21 of 33
(4) the costs that would be required to be paid by the ISO in the event of termination, acceleration or required prepayment of private financing entered into by the ISO in support of weekly billing of a portion of the market settlement system (and no replacement financing has been obtained by the ISO), through an Early Payment Shortfall Funding Charge.
The “backstopping” reflected in the foregoing Capital Funding Arrangements is necessary to help the ISO obtain and/or maintain private financing. When approving the establishment of an independent system operator in New England, the Commission expressed its concern that financial arrangements directly relying on Market Participant support for capital projects could compromise the ISO’s independence.53 Although the Commission allowed the ISO to initially rely on contractual provisions with the NEPOOL to fund then-existing capital assets, the Commission made clear that, “[t]o the extent the ISO required additional, similar facilities in the future, these facilities should be funded by the ISO, not NEPOOL ….”54
After the ISO commenced operations in 1997, it spent several years trying to obtain third- party private financing consistent with the Commission’s directive to maintain independence from NEPOOL participants. The ISO, however, faced a key problem: an inability to provide banks the assurances they needed that the ISO would have the funds to repay a loan in the event of its early termination or acceleration. As a non-profit, non-stock Delaware corporation that is tax-exempt under Section 501(c)(3) of the Internal Revenue Code, the ISO has no equity capital (or ability to raise capital) to fund capital expenditures or working capital. Substantially all of the ISO’s revenues are derived from charges to Customers under Commission-approved arrangements.
Ultimately, a bank expressed willingness to lend to the ISO based on the “backstopping” provisions of the Tariff and the ability to recover debt service through depreciation and amortization charges. Thus, the ISO funds its capital projects with third-party financing to maintain independence from Market Participants, while banks rely on Sections IV.B and IV.A of the Tariff to provide sufficient assurances to finance the ISO.
Given the structure and terms of the Capital Funding Arrangements (which remain unchanged for calendar year 2016 from those on file with and accepted by the Commission), if no termination or acceleration of that financing occurs, then none of the charges described above will be collected for these purposes. The ISO currently has financing for all elements of the 2016 Capital Budget given the structure of its existing Capital Funding Arrangements, and, at this time, the ISO does not foresee the need to obtain capital funds from Market Participants pursuant to these arrangements in calendar year 2016. As a result, the ISO does not anticipate assessing charges to Market Participants under the Capital Funding Arrangements in calendar year 2016.
53 New England Power Pool, 79 FERC ¶ 61,374 at p. 62,590 (1997). 54 Id. October 16, 2015 Page 22 of 33
B. The Transparency of the 2016 Capital Budget
The ISO’s process outlined below makes the ISO’s capital budgeting process transparent to stakeholders and the Commission and keeps them well informed of changes in forecasts or actual expenditures. The process includes regular reviews with stakeholders, a vote on the annual capital budget by the ISO’s independent Board of Directors, and quarterly and annual filings with the Commission pursuant to Section 205 of the Federal Power Act.
The annual capital budgeting process includes review with the NEPOOL Budget and Finance Subcommittee, the NEPOOL Participants Committee55 and representatives of the New England states’ public utilities commissions.56 Following this review, the ISO Board of Directors approves the annual capital budget.57 These steps are precursors to a Section 205 filing of the annual capital budget.
In addition, on a quarterly basis, the ISO reviews updates to the capital budget at meetings of the NEPOOL Budget and Finance Subcommittee and then files these updates with the Commission under Section 205. These updates are described in Section IV.B.6.2 of the Tariff, which requires the ISO to file with the Commission under Section 205 on a quarterly basis: (i) a report specifying by project prior-year spending on multi-year projects, year to date spending, and a forecast of the spending to complete the project in each future calendar year; and (ii) a schedule of the unamortized costs of the ISO’s funded capital expenditures at the end of the quarter and the allocation of those costs to the ISO’s rates (i.e., Schedules 1, 2, and 3 to Section IV.A of the Tariff).
Roughly contemporaneously with the instant filing, the ISO will make a separate quarterly filing for the third quarter of 2015. The accounting is consistent for those capital projects that are reported both in the quarterly update and in the 2016 Capital Budget, although the focus of the two filings is different (i.e., 2015 versus 2016).
In sum, the ISO’s capital budgeting practices create a high degree of transparency and accountability that is unparalleled among other independent system operators and regional transmission organizations—and even among other public utilities.
C. Elements of the 2016 Capital Budget
The 2016 Capital Budget is $27 million. Its primary elements are anticipated to be those projects outlined below and further detailed in the attached prepared testimony of M. David Hameedy, Director of the Program Management Office at the ISO.
The primary deliverable for a majority of the 2016 Capital Budget projects is application software and requisite hardware needed to maintain and improve bulk-power system reliability
55 The process for Market Participant review of ISO budgets is specified in Section IV.B.6.1 of the Tariff. 56 See Section I.B above for a description of the 2016 process. 57 See Section IV.B.6.1 of the Tariff. October 16, 2015 Page 23 of 33
and/or wholesale electric markets.58 Typically, the ISO’s capital projects stem from market initiatives, identified in conjunction with stakeholders, to improve the energy, ancillary services and capacity markets. Other capital projects are driven by the need for increased reliability and information, Operational Excellence activities that aim to improve the efficiency of the organization through measures such as automation of manual business processes, or regulatory requirements imposed by the Commission. In each case, the ISO has determined that the capital project will benefit the region’s stakeholders by improving the ISO’s ability to maintain bulk- power system reliability, administer fair and efficient markets, and provide information to stakeholders to increase transparency and facilitate decision-making.
The following are the material projects that are anticipated to comprise the 2016 Capital Budget. The projects listed in Sections 1 through 6 are well-defined and have had charters approved by management; the remainder are still in the planning stages or are subject to further Commission action.
1. Wind Integration Phase II / Do Not Exceed Dispatch ($2,472,000)
This is the second phase in the project to fully integrate wind power into the ISO-NE system. Phase I of the project established a centralized wind power forecast system for ISO-NE, putting the forecast into use by wind plant operators and ISO-NE. The wind power forecast was a direct recommendation from the New England Wind Integration Study and the first step towards the full integration of wind into ISO-NE systems. The Phase I project implemented an infrastructure that can be used to extend the usage of the wind power forecasts into other ISO-NE processes.
Phase II builds on Phase I by adding both improvements and new functionality. Significantly, Phase II will employ the wind power forecast to facilitate the inclusion of wind resources in the real-time dispatch. Allowing real-time dispatch will alleviate issues with curtailment priorities, allow wind resources to set price, and provide the proper market signals for new capacity. Phase II also includes: short-term wind power forecast improvements; publishing medium-term and long-term forecasts; adding a new wind power forecast analysis archive; improving real-time wind dashboard displays; and adding Do Not Exceed dispatch for intermittent resources.
The target completion date for this project is May 2016.
2. Forward Capacity Auction (“FCA”) 10 ($590,000)
The FCA 10 project will implement Tariff revisions that were filed with the Commission on May 1, 2015 to address the potential exercise of market power. The changes include: increasing the Dynamic De-List Bid Threshold; mitigating New Import Resources that function
58 Capital projects also include project management and design work. If a project’s design is approved and built, this work becomes part of the asset on which the ISO collects depreciation when the asset is placed in service and in future years via the operating budget. On the other hand, if the capital project is abandoned, the ISO writes off the project management and design work and recovers it in full in the year of abandonment. October 16, 2015 Page 24 of 33
more like existing resources than new resources; and establishing a single pivotal supplier test that applies to both capacity imports and existing resources. Other changes include the implementation of a system-wide demand curve in the Annual Reconfiguration Auctions and functionality to support Renewable Technology Resources.
In addition to the market changes discussed above, the FCA-10 project will include upgrades for the software used to support the qualification process. Oracle and Microsoft have announced that the current versions of Oracle (11g) and Internet Explorer (v.8) in use by the ISO have reached their end of life and will not be supported effective January 2016. Accordingly, the existing software will be upgraded to Oracle version 12c and Internet Explorer version 11.
The targeted completion date for this project is May 2016.
3. Divisional Accounting ($496,800)
The Divisional Accounting project is a multi-phased project, implemented at the request of Market Participants, to add software functionality to permit separation of settlement accounts by individual business unit. This capability will facilitate customers’ divisional accounting, allowing customers to easily evaluate their positions by business unit, division or generating facility.
Due to the complexity of the implementation and the vast number of systems impacted (e.g., eMarket, eFTR, Forward Capacity Tracking System), the project was designed with five phased releases originally scheduled to occur in 2014 and 2015. The first four phases of the project are complete. However, due to resource conflicts, specifically with the Coordinated Transaction Scheduling project, the fifth and final phase of the project, which focuses specifically on external transactions and their respective settlements, has been delayed.
Re-planning analysis is underway for the Phase 5 release and initial estimates indicate completion during 2016.
4. Zonal Load Forecast ($225,000)
On May 29, 2012, temperatures in Connecticut were much higher than those in coastal Massachusetts. The load forecast at that time was based on a weighted average of the weather forecasts for various New England locations, an approach that works well when weather follows normal seasonal patterns. However, when very hot and humid conditions occur inland and the coastal regions experience a cooling sea breeze as they did on May 29, 2012, the load forecast is no longer accurate. On that date, the result was unexpectedly high loads in Connecticut and very tight capacity conditions in the inland regions of Massachusetts.
In response to this situation, ISO-NE developed a zonal load forecast prototype which addresses the problem by creating a load forecast for each load zone. This project will build on the successful prototype by incorporating zonal load forecast functionality into the existing load forecast application, and adjusting downstream systems using load forecast data accordingly. With this project, the overall load forecast for the region will improve. October 16, 2015 Page 25 of 33
The targeted completion date for this project is March 2016.
5. Power System Modeling Management Initiatives ($145,000)
The Power System Modeling Management Initiatives project proposes to implement enhancements to processes, procedures, and applications that will improve the power system network model used for the Energy Management System.
The ISO will work with Northeastern University to perform an analysis of the ISO-NE network model to identify: the type and location of all “critical” measurements identified in the ISO-NE measurement configuration; the observable islands identified by the set of buses belonging to each island; and all unobservable branches separating the identified observable islands. In addition, Northeastern University will develop software that will allow for off-line detection and identification of analog measurements and state estimator parameters with significant errors that impact the state estimator solution. Using this software, ISO-NE will work with transmission owners to correct these errors. The goal is to create a more robust and accurate state estimator solution, which in turn will benefit other critical Energy Management System functions and market applications.
The targeted completion date for this project is August 2017.
6. NX9/NX12D – Generator Voltage Data ($50,000)
The NX9/NX12D application, implemented in the fall of 2013, is an externally-facing application that manages the data and certifications provided by ISO-NE customers for specific equipment. Currently, the NX12D section of the application is used to collect information on generators, including reactive data. The NX9 section of the application collects specific nameplate and characteristic data for transmission equipment.
The NX9/NX12D project will update the software associated with these systems to align with ISO-NE Operating Procedure No. 12 (“Voltage & Reactive Control”), which was recently updated in compliance with NERC’s Reliability Standard VAR-001-4.
The targeted completion date for this project is February 2016.
7. FCA 11 ($3,000,000)
This project is dedicated to the design and implementation of zonal sloped demand curves that successfully balance the factors involved in designing capacity market demand curves: reliability, price volatility, market power, and robust performance. The project is intended to be completed with the eleventh FCA, which will be held in February 2017.
8. Sub-Hourly Settlements ($2,500,000)
The real-time markets (energy, reserve, and regulation) are settled hourly, even though the ISO calculates real-time locational marginal prices every five minutes. Existing settlement rules tend to undercompensate certain resources, particularly more flexible generation and storage assets that respond quickly in tight operating conditions, when there are significant mid- October 16, 2015 Page 26 of 33
hour price changes. Compensating resources at the more granular, five-minute price would help improve price formation by ensuring that the price that suppliers are paid for real-time performance is a more accurate signal of the power system’s current operating conditions. In the future, this change may also provide an additional revenue source for wholesale electricity storage resources.
The target completion date for this project is the fourth quarter of 2016.
9. Fast-Start Pricing ($2,500,000)
In practice, fast-start units, even when deployed in economic merit order, often do not set the real-time price given their operating characteristics. This is due to the limitations of ISO- NE’s existing fast-start pricing logic, which was designed fifteen years ago to work with the software and hardware that was available at the time.
The proposed changes will increase the accuracy and efficiency of dispatch, pricing, and compensation when fast-start units are deployed. Price formation will be improved by fast-start resources’ ability to set price more frequently, and prices will reflect the cost of fast-start deployments through transparent market price signals. The result will be improved performance incentives for all resources during tight system conditions.
The targeted completion date for this project is the first quarter of 2017.
10. Submission of FTRs for Clearing ($1,800,000)
The objective of this project, currently in planning, is to institute third-party clearing in order to address the inability to properly collateralize against the risk of a participant default. Currently, ISO-NE holds Financial Assurance that may not be adequate to cover the potential losses of a Market Participant’s default on its FTRs. Specifically, there is no way for ISO-NE to unwind a defaulted FTR position. If a participant acquires a large position in an annual FTR auction, and the amount of negative target allocations exceeds its Financial Assurance, the losses on this position, and the losses to all ISO-NE participants in the event of a default, can continue to accumulate. Under a third-party clearing design, if a Market Participant defaults, its clearing member will liquidate the defaulted portfolio in the secondary market, and if the combined margin held against the portfolio is not adequate to cover the liquidation losses, the clearing member holds the financial responsibility to cover the excess losses.
Regulatory and jurisdictional questions surrounding the project have resulted in major delays. Minimal work on the project will continue in 2015, with the majority of development work anticipated to occur in 2016.
The targeted completion date for this project is the fourth quarter of 2016.
October 16, 2015 Page 27 of 33
11. 2016 Issues Resolution Project ($1,500,000)
The ISO uses a “Corrective Action/Preventative Action” approach to identify and track needed enhancements to existing systems and processes. This project is anticipated to occur in two phases and will continue efforts to resolve as many current outstanding issues that have a software impact as possible. These issues include automation of manual functions, addition of functionality in support of market activities, miscellaneous application improvements, internal and external report updates, and technology improvements. The ISO Information Technology and Systems groups will review the list of issues related to the systems and applications for which they provide support and identify those that can be implemented during the year. The targeted completion date for this project is the fourth quarter of 2016.
12. Expand Energy Offers for Pumps ($900,000)
The ISO does not currently allow Dispatchable Asset Related Demands (“DARDs”) to have inter-temporal constraints (start-up, notification, minimum run and down times, and maximum number of starts per day). In response to the Commission’s Order No. 719, ISO-NE agreed to modify this practice. Specifically, through this project, the ISO will enable DARDs to have maximum demand-dispatch duration, maximum dispatch frequency, and a minimum down- time. In addition, the ISO will expand the rules for Net Commitment Period Compensation and define cost allocation rules for DARDs.
The targeted completion date for this project is the fourth quarter of 2016.
13. Quarterly Release Projects 2016 ($800,000)
In addition to major projects under consideration for 2016, the ISO expects to address a number of minor enhancements requested by stakeholders. These minor enhancements are bundled into two quarterly releases. The targeted completion dates are the second quarter of 2016 for the first release, and the fourth quarter of 2016 for the second release.
14. Asset Characteristics Database & User Interface Redesign ($700,000)
The Asset Characteristics Database User Interface Redesign project will provide participants and ISO-NE Internal Market Monitoring staff enhanced functionality to track generator characteristics for reference level calculations. This project will build upon functionality delivered as part of the Energy Market Offer Flexibility (Hourly Markets) project.
The targeted completion date for this project is the third quarter of 2016.
15. Energy Management Platform Customs Elimination ($600,000)
ISO-NE’s Energy Management System is based on Alstom Grid’s suite of Energy Management Platform applications. When absolutely necessary, the Information Services department customizes Alstom’s software to suit the business needs of ISO-NE. Accordingly, when Alstom upgrades its software, a significant effort is needed to port the customized ISO-NE October 16, 2015 Page 28 of 33
software to the upgraded software. This project involves work with Alstom Grid to eliminate some of the ISO-NE customs, with the goal of simplifying the next software upgrade.
The targeted completion date for this project is the fourth quarter of 2017.
16. Operations Document Management System (“ODMS”) ($600,000)
The ODMS has proven to be a stable and effective tool for managing System Operations Documents. System Operations is currently using ODMS as the sole system for managing the edit, review and sign-off for all transmission operating guides, operating procedures, master local control center procedures, and system operating procedures. ODMS also provides operational functionality, including searching and decision making. Since ISO-NE is phasing out SharePoint- based applications such as ODMS, the project will migrate ODMS to a new software platform.
The targeted completion date for this project is the fourth quarter of 2016.
17. Transmart Rewrite ($500,000)
Transmart is a software application that is used by ISO-NE System Operations staff to support external transactions. The Transmart application has been in existence prior to the implementation of Standard Market Design in 2003. The Transmart Rewrite project upgrades the remaining functionality that still exists in the original Transmart application.
The targeted completion date for this project is the fourth quarter 2016.
18. Web Enhancements 2016 ($500,000)
ISO-NE completed a redesigned website in 2014 that greatly improved ease of use of, and access to, market and power system information for Market Participants, public officials, and other key stakeholders. In an effort to continue to improve the ISO New England web presence, the Web Enhancements 2016 project will improve the usability and technical support of the internal and external websites by implementing stakeholders’ most requested improvements and the highest priority enhancements. The project is targeted for completion in 2016.
19. Asset Registration Automation ($500,000)
The current asset registration process relies on participant submittal of scanned, emailed, or faxed asset registration forms or spreadsheets. This project aims to improve the asset registration process by providing a secure digital format for submission and retrieval of asset registration forms, in addition to requested asset data changes and transfers. The repository would include the required controls for this data and ensure that all customers and business users would have access to timely and accurate asset data without the need to maintain separate databases, spreadsheets, binders, or duplicate forms. This project would also provide a workflow to manage the necessary participant and ISO approvals required for asset registration and changes to existing asset data.
October 16, 2015 Page 29 of 33
The targeted completion date for this project is the third quarter of 2016.
20. Dynamic Interchange Adjustment Tool ($300,000)
Currently, ISO-NE sets hourly interchange schedules with neighboring control areas in New York, Quebec and New Brunswick. The schedules all change concurrently once per hour and are primarily ramped over a ten-minute period beginning five minutes before the top of each hour. System Operating Procedures apply uniform ramp limits to all hours without regard to actual system conditions or system ramping capability. The use of a uniform ramp limit can result in unnecessary curtailment of transactions, or may occasionally fail to account for a shortage of ramping capability. The purpose of the Dynamic Interchange Adjustment Tool project is to predict secure ranges of system ramping capabilities for intra-hour interchange adjustments, and to address the additional layer of complexity created by the advent of intra-hour scheduling with New York.
The target completion date for this project is the fourth quarter of 2016.
21. Oracle 12c Upgrade ($100,000)
Many ISO-NE business applications rely on an Oracle database. To obtain the level of support needed from Oracle to meet the ISO’s availability goals, the ISO must run on the current Oracle database version for each application. This project will ensure all systems are upgraded from Oracle version 11g to Oracle version 12c. Because upgrades are also occurring in the context of current and upcoming projects, this project’s scope will specifically address only database upgrades and performance testing for those systems not covered under a current or upcoming project.
The targeted completion date for this project is the second quarter of 2016.
22. Case Snapshot Enhancements for Market Operator Interface ($100,000)
On July 3, 2013, the Commission approved ISO-NE’s proposal to use the $1 million in funds provided to ISO-NE under the Stipulation and Consent Agreement between Constellation Energy Commodities Group and the Office of Enforcement. That proposal involved the development of new software to allow increased surveillance and oversight of the Day-Ahead Energy Market. The new software (called Case Snapshot) allows the re-execution of the Day- Ahead Energy Market’s Reserve Adequacy Assessment and Security Constrained Reliability Assessment cases using the same market data that existed when the original case was executed and approved.
The initial development and implementation of Case Snapshot occurred at the end of October 2013. Enhancements to augment the data captured in the snapshot tables and the data retention period were subsequently made. On December 22, 2014, ISO-NE reported that the initial implementation was complete at a total project cost of $672,500.
October 16, 2015 Page 30 of 33
ISO-NE is now proposing to use the remaining funds to develop a suite of user interface displays that will provide visibility of the snapshot data when re-running a case and allow the ability to modify this data, including participant offers, before executing the case. In addition, this functionality will facilitate the execution of “what-if” scenarios. Currently, for much of the snapshot data, this can only be achieved using database queries and manual database edits. It is ISO-NE’s expectation that the remaining funding from the settlement will cover most but not all of the costs of developing and implementing the enhancements.
The targeted completion date for this project is the fourth quarter of 2016.
23. Price Responsive Demand ($100,000)
The Price Responsive Demand Project aims to fully integrate demand response into the wholesale markets. The project will create a dispatchable capacity product for demand response, including the application of Peak Energy Rents and performance penalties to demand response, thereby creating disincentives for economic and physical withholding of capacity. In addition, the project will provide a mechanism for capacity replacement for resources that are not able to demonstrate their obligated capacity. Due to the uncertainty surrounding the Commission’s Order No. 745, the ISO has allocated a limited sum for work in 2016, and currently anticipates a completion date for this project is the third quarter of 2018.
24. Non-Project Capital Expenditures ($3,700,000), Other Emerging Work ($1,809,200), and Capitalized Interest ($500,000)
The 2016 Capital Budget includes a total of $3,700,000 for non-project capital expenditures. Non-project capital expenditures fund external and internal capitalized labor necessary to program System Improvement Requests ($2,000,000), non-project related hardware purchases ($1,500,000), and furniture & fixtures ($200,000).
The “Other Emerging Work” category is primarily intended to address emerging work requests during 2016 that result from operational needs, compliance obligations or regulatory/stakeholder feedback.
Last, $500,000 is allocated to capitalized interest. Accounting conventions require that interest be capitalized for capital projects that cross years. In addition, loan fees associated with borrowings to fund capital assets are also capitalized.
D. Caveats
The 2016 Capital Budget cannot accurately predict the ISO’s actual capital expenditures for 2016. For example, protracted stakeholder review of a proposal or extensive litigation contesting a proposal can delay implementation of market improvements, thereby affecting when the ISO might incur a capital expenditure and the amount of that expenditure, as well as the ISO’s cost recovery and ability to fund future projects due to constraints on available lines of credit. It is also likely that the ISO’s capital project priorities will change during the course of the year. Emerging needs that are difficult to anticipate in advance will likely require a shift in priorities. In such situations, it is likely that the distribution of the 2016 Capital Budget will October 16, 2015 Page 31 of 33
change. The quarterly filings under Section IV.B.6.2 of the Tariff will keep stakeholders and the Commission apprised of necessary adjustments.
III. ADDITIONAL SUPPORTING INFORMATION
The ISO submits the following additional information pursuant to Sections 205 of the FPA and 35.13 of the Code of Federal Regulations:
35.13(b)(1) – In addition to this transmittal letter, the ISO provides the following materials:
• Section IV.A of the Tariff (Exhibit 1); • Blacklined version of Section IV.A of the Tariff (Exhibit 2); • Prepared testimony and exhibits of Robert C. Ludlow regarding the 2016 Administrative Expenses Tariff (Exhibit 3); • Prepared testimony of Janice S. Dickstein regarding the 2016 Administrative Expenses Tariff (Exhibit 4); • 2016 Capital Budget (Exhibit 5); • Prepared testimony of M. David Hameedy regarding the 2016 Capital Budget (Exhibit 6); • Table showing cross-references for Statement AA-BM data (Exhibit 7); • Excerpts (income statement, balance sheet, cash flow, notes to the financial statements) from the ISO’s Form 1 for 2014 (Exhibit 8); • Lists of the governors and electric utility regulatory agencies for the six New England states to which the ISO has sent electronic copies of this filing (Exhibit 9);
• Comments of state agencies on proposed 2016 Budgets (Exhibit 10); and
• ISO-NE response to comments of state agencies on proposed 2016 Budgets (Exhibit 11).
As in the past, the ISO has included the cost-of-service data required by Statements 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 repeatedly has accepted the ISO’s rates as supported in this manner, including an explicit acknowledgement that such data is sufficient.59
59 ISO New England Inc., 85 FERC ¶ 61,453 at p. 62,680 (1998) (rejecting a protestor’s request to require the ISO to file the cost-of-service statements set forth in Section 35.13(h) of the Commission’s Rules and Regulations, “find[ing] that the ISO has provided sufficient information to meet the minimum filing requirements”). October 16, 2015 Page 32 of 33
35.13(b)(2) – The ISO requests that the Commission accept the 2016 Capital Budget and the 2016 Administrative Expenses Tariff as filed, effective January 1, 2016.
35.13(b)(3) – Pursuant to Section 17.11(e) of the Participants Agreement, Governance Participants will be served electronically. The names and addresses of the Governance Participants are available through the ISO’s website at http://www.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 2016 Capital Budget and the 2016 Administrative Expenses Tariff.
35.13(b)(6) –The ISO Board of Directors has approved the 2016 Capital Budget, the 2016 Revenue Requirement and resulting rates herein. The ISO also notes that the NEPOOL Participants Committee voted to support the 2016 Capital Budget and the Revenue Requirement.
35.13(b)(7) – The ISO does not have any knowledge of any relevant expenses or costs of service that have been alleged or judged in any administrative or judicial proceeding to be illegal, duplicative, or unnecessary costs that are demonstrably the product of discriminatory employment practices.
35.13(c)(1) – See Exhibit 3 for a comparison of the sales, services and revenues from the rate schedule to be superseded and under the rate schedule change.
35.13(c)(2) – The ISO has no other rates for similar services.
35.13(c)(3) – No specifically assignable facilities have been or will be installed or modified in order for the Commission to accept this filing. October 16, 2015 Page 33 of 33
IV. COMMUNICATIONS
Correspondence and communications regarding this filing should be addressed to the undersigned for the ISO as follows:
Maria A. Gulluni Deputy General Counsel ISO New England Inc. One Sullivan Road Holyoke, MA 01040-2841 Tel: (413) 540-4473 Fax: (413) 535-4379 E-mail: [email protected]
V. CONCLUSION
For the reasons stated herein, the ISO requests that the Commission accept the 2016 Capital Budget and the 2016 Administrative Expenses Tariff as filed, without suspension or hearing, with an effective date of January 1, 2016.
Respectfully submitted,
/s/ Maria A. Gulluni______Maria A. Gulluni Deputy General Counsel 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 $0.19275 per kilowatt month times its Monthly Regional Network Load for that month.
(B) each Customer that is a Transmission Customer receiving Through or Out Service shall pay each month, in arrears, an amount equal to the product of the Transmission Customer’s highest amount of Reserved Capacity (expressed in kilowatts) for an hour for each transaction, other than a Coordinated
External Transaction, that is scheduled to occur during the month as Through or Out Service multiplied by $0.00026 per kilowatt for each hour of service.
Schedule 1 revenues collected from Through or Out Service customers shall be credited to each Network Customer receiving Regional Network Service that month in proportion to each Network Customer’s Monthly Regional Network Load in that month.
Non-Market Participant FTR fees and any portions of Long Lead Facility deposits collected by the ISO under Schedule 22 and Schedule 25 of Section II of the Tariff that become non-refundable will be credited to Schedule 1 Revenue Requirements and will be included in the Schedule 1 true-up calculations.
All general terms and conditions of the Tariff apply to this Service.
Schedule 2 Energy Administration Service
Energy Administration Service (“EAS”) is the Service provided by the ISO to administer the Energy Market.
The ISO’s expenses are based on the functions required to provide EAS and include, but are not limited to:
• Core operation of the Energy Market; • Generation and demand dispatch related to the Energy Market; • Energy accounting; • Loss determination and allocation; • Billing preparation; • Market power monitoring and mitigation for the Energy Market; • Sanctions activities; • Operation of FTR auctions; • Market assessment and reports; and • Formulation of additional market rules and proposals to modify existing rules.
Each Market Participant that has an account for Energy that is settled by the ISO for the current month shall pay each month an amount based on Energy Transaction Units (Energy TUs), Increment Offers, Decrement Bids, Volumetric Measures, submitted FTR auction bids, and cleared FTR auction bids.
Energy TU Based Charges: For purposes of this Schedule 2, Energy TUs shall be calculated without reference to contributions from Coordinated External Transactions. Each Customer that has, during a month, incurred Energy TUs exceeding zero shall pay an amount, in arrears, equal to the sum of the products of:
(1) $0.66437 times the Customer’s first 12,500 Energy TUs for that month; plus
(2) $0.60397 times the amount of Energy TUs that exceed 12,500 but are less than or equal to 39,500; plus
(3) $0.54358 times the amount of Energy TUs that exceed 39,500.
Charges Based on Increment Offers and Decrement Bids: Each Customer submitting Increment Offers and/or Decrement Bids shall pay, in arrears, amounts equal to:
(1) $0.00500 times the number of Increment Offers and Decrement Bids submitted by the Customer for that month; plus
(2) $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 and excluding Coordinated External Transactions) assessed to that Customer during the month exceeds zero (0), in which case, the total EAS VM charges for that Customer shall be equal to the sum of:
(1) Monthly Real-Time Load Obligation (MWh), excluding Monthly Real-Time Load Obligation associated with Coordinated External Transactions; and
(2) Monthly Real-Time Generation Obligation (MWh); provided, however, that Monthly Real-Time Generation Obligation associated with energy imported into the New England Control Area by Bangor Hydro-Electric Company across the New Brunswick ties shall be excluded (up to 300 MW) for billing and rate calculation purposes from EAS VMs, and provided further that Monthly Real-Time Generation Obligation associated with Coordinated External Transactions shall be excluded.
Subject to the foregoing, each Market Participant that is identified as an EAS VM Customer for that month shall pay an amount, in arrears, based on total EAS VM, equal to:
(a) $0.28296 per MWh for the first 250,000 MWh of EAS VM for that month; plus
(b) $0.25723 per MWh for each VM that exceeds 250,000 EAS VM but is less than or equal to 1,500,000 MWh for that month; plus
(c) $0.23151 per MWh for each EAS VM in excess of 1,500,000 MWh for that month.
Charges Based on Submitted and Cleared FTR Bids: Each Customer submitting FTR auction bids shall pay, in arrears, amounts equal to: (1) $2.02863 times the number of bids submitted by the Customer into any FTR auctions held for that month; plus
(2) $2.02863 times the number of bids submitted by the Customer into any annual or multi-month FTR auctions (billed with the invoice for the first month of the annual or multi-month FTR auction); plus
(3) $2.62374 times the number of bids submitted by the Customer during that month that clear any FTR auctions held for that month; plus
(4) $2.62374 times the number of bids submitted by the Customer that clear any annual or 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 $3.22 times the number of hourly Through or Out reservations made for that month.
(B) Each Customer that is a Market Participant shall be considered a RAS Customer and shall pay each month, in arrears, an amount equal to the product of $0.20313 per kilowatt month times the Market Participant’s Real-Time NCP Load Obligation (measured in kilowatts) for that month.
(C) For Exports other than Coordinated External Transactions, each RAS Customer shall pay each month, in arrears, an amount equal to $0.40000 per MWh per Export, where MWh represents the hourly scheduled MWs of associated Export.
In order to preserve the settlement approved in Docket No. ER01-316, Market Participants engaging in “through” transactions using Through or Out Service will not be deemed to have a Real-Time Load Obligation on account of those transactions.
Charges collected under Schedule 3 for RAS do not include any amounts paid by the ISO on behalf of the Market Participants to purchase emergency power.
Charges collected under Schedule 3 for RAS do not include the recovery of costs associated with disclosure or tracking obligations. If one or more states require Market Participants to undertake such activity the ISO will separately charge the expenses associated with such obligations.
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 2015, the six New England states shall bear NESCOE’s budgeted costs as follows. Each Customer that is obligated to pay the Regional Network Service rate shall pay each month, in arrears, an amount equal to the product of $0.00000 per kilowatt times its Monthly Regional Network Load for that month.
EXHIBIT 2
SECTION IV.A RECOVERY OF ISO ADMINISTRATIVE EXPENSES
TABLE OF CONTENTS
IV.A.1 Definitions
IV.A.2 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 $0.192755570 per kilowatt month times its Monthly Regional Network Load for that month.
(B) each Customer that is a Transmission Customer receiving Through or Out Service shall pay each month, in arrears, an amount equal to the product of the Transmission Customer’s highest amount of Reserved Capacity (expressed in kilowatts) for an hour for each transaction, other than a Coordinated
External Transaction, that is scheduled to occur during the month as Through or Out Service multiplied by $0.000261 per kilowatt for each hour of service.
Schedule 1 revenues collected from Through or Out Service customers shall be credited to each Network Customer receiving Regional Network Service that month in proportion to each Network Customer’s Monthly Regional Network Load in that month.
Non-Market Participant FTR fees and any portions of Long Lead Facility deposits collected by the ISO under Schedule 22 and Schedule 25 of Section II of the Tariff that become non-refundable will be credited to Schedule 1 Revenue Requirements and will be included in the Schedule 1 true-up calculations.
All general terms and conditions of the Tariff apply to this Service.
Schedule 2 Energy Administration Service
Energy Administration Service (“EAS”) is the Service provided by the ISO to administer the Energy Market.
The ISO’s expenses are based on the functions required to provide EAS and include, but are not limited to:
• Core operation of the Energy Market; • Generation and demand dispatch related to the Energy Market; • Energy accounting; • Loss determination and allocation; • Billing preparation; • Market power monitoring and mitigation for the Energy Market; • Sanctions activities; • Operation of FTR auctions; • Market assessment and reports; and • Formulation of additional market rules and proposals to modify existing rules.
Each Market Participant that has an account for Energy that is settled by the ISO for the current month shall pay each month an amount based on Energy Transaction Units (Energy TUs), Increment Offers, Decrement Bids, Volumetric Measures, submitted FTR auction bids, and cleared FTR auction bids.
Energy TU Based Charges: For purposes of this Schedule 2, Energy TUs shall be calculated without reference to contributions from Coordinated External Transactions. Each Customer that has, during a month, incurred Energy TUs exceeding zero shall pay an amount, in arrears, equal to the sum of the products of:
(1) $0.6643765101 times the Customer’s first 12,500 Energy TUs for that month; plus
(2) $0.6039759182 times the amount of Energy TUs that exceed 12,500 but are less than or equal to 39,500; plus
(3) $0.5435853264 times the amount of Energy TUs that exceed 39,500.
Charges Based on Increment Offers and Decrement Bids: Each Customer submitting Increment Offers and/or Decrement Bids shall pay, in arrears, amounts equal to:
(1) $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 and excluding Coordinated External Transactions) assessed to that Customer during the month exceeds zero (0), in which case, the total EAS VM charges for that Customer shall be equal to the sum of:
(1) Monthly Real-Time Load Obligation (MWh), excluding Monthly Real-Time Load Obligation associated with Coordinated External Transactions; and
(2) Monthly Real-Time Generation Obligation (MWh); provided, however, that Monthly Real-Time Generation Obligation associated with energy imported into the New England Control Area by Bangor Hydro-Electric Company across the New Brunswick ties shall be excluded (up to 300 MW) for billing and rate calculation purposes from EAS VMs, and provided further that Monthly Real-Time Generation Obligation associated with Coordinated External Transactions shall be excluded.
Subject to the foregoing, each Market Participant that is identified as an EAS VM Customer for that month shall pay an amount, in arrears, based on total EAS VM, equal to:
(a) $0.2829625517 per MWh for the first 250,000 MWh of EAS VM for that month; plus
(b) $0.2572323197 per MWh for each VM that exceeds 250,000 EAS VM but is less than or equal to 1,500,000 MWh for that month; plus
(c) $0.2315120877 per MWh for each EAS VM in excess of 1,500,000 MWh for that month.
Charges Based on Submitted and Cleared FTR Bids: Each Customer submitting FTR auction bids shall pay, in arrears, amounts equal to: (1) $2.02863.85853 times the number of bids submitted by the Customer into any FTR auctions held for that month; plus
(2) $2.02863.85853 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) $2.623741.21377 times the number of bids submitted by the Customer during that month that clear any FTR auctions held for that month; plus
(4) $2.623741.21377 times the number of bids submitted by the Customer that clear any annual or multi-month FTR auctions (billed with the invoice for the first month of the annual or 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 $3.022 times the number of hourly Through or Out reservations made for that month.
(B) Each Customer that is a Market Participant shall be considered a RAS Customer and shall pay each month, in arrears, an amount equal to the product of $0.1876320313 per kilowatt month times the Market Participant’s Real-Time NCP Load Obligation (measured in kilowatts) for that month.
(C) For Exports other than Coordinated External Transactions, each RAS Customer shall pay each month, in arrears, an amount equal to $0.3740000 per MWh per Export, where MWh represents the hourly scheduled MWs of associated Export.
In order to preserve the settlement approved in Docket No. ER01-316, Market Participants engaging in “through” transactions using Through or Out Service will not be deemed to have a Real-Time Load Obligation on account of those transactions.
Charges collected under Schedule 3 for RAS do not include any amounts paid by the ISO on behalf of the Market Participants to purchase emergency power.
Charges collected under Schedule 3 for RAS do not include the recovery of costs associated with disclosure or tracking obligations. If one or more states require Market Participants to undertake such activity the ISO will separately charge the expenses associated with such obligations.
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 2015, the six New England states shall bear NESCOE’s budgeted costs as follows. Each Customer that is obligated to pay the Regional Network Service rate shall pay each month, in arrears, an amount equal to the product of $0.00000 per kilowatt times its Monthly Regional Network Load for that month.
EXHIBIT 3 ISO New England Inc. Exhibit 3 Recovery of 2016 Administrative Costs
UNITED STATES OF AMERICA
BEFORE THE
FEDERAL ENERGY REGULATORY COMMISSION
ISO New England Inc. ) Docket No. ER16-_____-000
DIRECT TESTIMONY
OF
ROBERT C. LUDLOW
Filed on: October 16, 2015
ISO New England Inc. Exhibit 3 Recovery of 2016 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 2016 REVENUE REQUIREMENT ...... 7
ACTIVITY ACCOUNTING SYSTEM ...... 21
2016 COST ALLOCATION AMONG SCHEDULES 1, 2, AND 3 ...... 23
THE ISO RATE DESIGN AND ESCALATION FACTORS ...... 29
THE 2016 BILLING DETERMINANTS ...... 37
RATE SUMMARY ...... 40
FIXED FEES ...... 42
CONCLUSION ...... 44
ISO New England Inc. Exhibit 3 Recovery of 2016 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: 2016 Revenue Requirement and 2014 True-Up
RCL-3: Test Year 2016 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 on Depreciation and Amortization Expense
RCL-4: [reserved]
RCL-5: 2016 Core Operating Budget
Schedule 1: Overview of Operating Expense Budget Schedule 2: Detail of Components of 2016 Operating Expense Budget Schedule 3: Variance Summary (vs. 2015) Schedule 4: Detailed Change in Budget (vs. 2015) Schedule 5: Staffing Projections Schedule 6: 2016 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 2015 and Test Year 2016 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 2014 Schedule 6: Schedule 2 TU True-Up Summary
RCL-8: NEPOOL Resolution
ISO New England Inc. Exhibit 3 Recovery of 2016 Administrative Costs Page 1
1 UNITED STATES OF AMERICA 2 BEFORE THE 3 FEDERAL ENERGY REGULATORY COMMISSION
4 ISO NEW ENGLAND INC. ) Docket No. ER16-_____-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 2016 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. ER15-112-000 (rates
11 proposed for 2015), ER14-90-000 (rates proposed for 2014), ER13-185-000 (rates
12 proposed for 2013), ER12-191-000 (rates proposed for 2012), ER11-1943-000
13 (rates proposed for 2011), ER10-154-000 (rates proposed for 2010), and others.
14 PURPOSE OF TESTIMONY
15 Q. WHAT IS THE PURPOSE OF YOUR TESTIMONY?
16 A. I am providing this testimony primarily to support the ISO’s proposed revenue
17 requirement for 2016 (“2016 Revenue Requirement”) and the updated rates to
18 collect it. My Direct Testimony presents the ISO’s 2016 Revenue Requirement as
19 reflected in the proposed revised tariff sheets attached as Exhibits 1 and 2 (clean
20 and blacklined versions, respectively) to the filing letter. Specifically, I will
21 describe the ISO’s budget process, summarize the elements of the ISO’s 2016
ISO New England Inc. Exhibit 3 Recovery of 2016 Administrative Costs Page 3
1 Revenue Requirement (including the true-up mechanism), present the ISO’s 2016
2 Core Operating Budget, and describe the ISO’s activity accounting system. I will
3 also present the development of the Test Year 2016 cost of service study
4 associated with the ISO providing service under the three primary rate schedules
5 included in Section IV.A of the ISO’s Transmission, Markets and Services Tariff
6 (the “Tariff”). Section IV.A of the Tariff provides for recovery of the ISO’s
7 administrative expenses. The three primary rate schedules are: (1) Schedule 1 –
8 Scheduling, System Control and Dispatch Service (“Scheduling Service”); (2)
9 Schedule 2 – Energy Administration Service; and (3) Schedule 3 – Reliability
10 Administration Service. I will present proposed escalation factors to adjust actual
11 load data for the 12-month period ending July 2015 to the Test Year 2016 for the
12 purpose of rate design, discuss the rate design utilized, and the proposed rates,
13 including certain fixed fees.
14 Q. HOW WILL YOUR TESTIMONY BE ORGANIZED?
15 A. Before offering a conclusion, I will describe:
16 (i) the current operations and organizational structure of the ISO;
17 (ii) the budget development process;
18 (iii) the various elements of the 2016 Revenue Requirement;
19 (iv) the ISO’s activity accounting system;
20 (v) how the ISO allocated its costs among the rates it proposes to charge in the
21 Tariff’s Schedules 1, 2, and 3;
ISO New England Inc. Exhibit 3 Recovery of 2016 Administrative Costs Page 4
1 (vi) the 2016 rate design and escalation factors;
2 (vii) the 2016 billing determinants;
3 (viii) a rate summary; and
4 (ix) fixed fees.
5 CURRENT OPERATIONS AND ORGANIZATIONAL STRUCTURE OF THE ISO
6 Q. WHAT ARE THE CURRENT OPERATIONS AND ORGANIZATIONAL
7 STRUCTURE OF THE ISO?
8 A. The ISO provides three basic services to its customers:
9 1. Scheduling Service (Schedule 1): Through this service, the ISO schedules
10 at the pool level the movement of power through, out of, within, or into
11 the New England Control Area.
12 2. Energy Administration Service (Schedule 2): Through this service, the
13 ISO administers the energy markets and facilitates generation and demand
14 dispatch, auctions for Financial Transmission Rights (“FTRs”), and other
15 services (i.e., under Section III of the Tariff).
16 3. Reliability Administration Service (Schedule 3): Through this service, the
17 ISO administers the reliability markets (and facilitates reliability-related
18 transactions and arrangements) in accordance with Market Rule 1 and
19 provides other reliability and informational services.
ISO New England Inc. Exhibit 3 Recovery of 2016 Administrative Costs Page 5
1 The ISO is governed by an independent Board of Directors with a cross-section of
2 skills and experience, including regulatory affairs, energy industry management,
3 corporate finance, bulk-power systems, public policy, and market development.
4 The ISO is overseen by a President and Chief Executive Officer (“CEO”) who has
5 seven direct reports. An Executive Vice President and Chief Operating Officer is
6 responsible for Market Operations, System Operations, System Planning, Market
7 Development, Program Management, Business Architecture, and Information
8 Technology. The other direct reports of the CEO are: Vice President and General
9 Counsel; Vice President of External Affairs and Corporate Communications; Vice
10 President, Chief Financial & Compliance Officer; Vice President, Human
11 Resources; Vice President, Market Monitoring; and Director, Internal Audit. The
12 latter two positions report to the CEO for administrative purposes only. See RCL-
13 1, attached to this testimony.
14 THE BUDGET DEVELOPMENT PROCESS
15 Q. HOW WERE THE ISO’S BUDGETS DEVELOPED FOR 2016?
16 A. The ISO prepares budgets in advance of each upcoming year using a seven-step
17 business planning process, throughout which stakeholder input is sought. The
18 seven-step process is:
19 1) define objectives, activities and goals;
20 2) identify efficiencies for each department;
21 3) determine resource requirements;
ISO New England Inc. Exhibit 3 Recovery of 2016 Administrative Costs Page 6
1 4) develop budget estimates for each department;
2 5) adjust budgets to ensure that staff resources and activities are aligned with the
3 business plan;
4 6) conduct senior staff review to ensure alignment of budget with the ISO’s
5 business plan and overall fiscal constraint; and
6 7) develop priorities.
7 Q. PLEASE SUMMARIZE THE STAKEHOLDER PROCESS USED TO
8 REVIEW THE 2016 BUDGET.
9 A. After reviewing preliminary budgets with state agencies and NEPOOL at
10 meetings in June, the ISO presented the 2016 Revenue Requirement at the
11 NEPOOL Budget and Finance Subcommittee’s August 26, 2015 meeting and at a
12 meeting for state agencies on August 27, 2015. The ISO also presented the
13 budgets to the NEPOOL Participants Committee at the Committee’s meetings on
14 September 11 and October 2, 2015. At the October 2 meeting, the ISO’s 2016
15 Revenue Requirement was unanimously supported by the Participants Committee
16 (with abstentions). The terms of the NEPOOL Participants Committee’s action
17 are reflected in the resolution in RCL-8, attached to this testimony. In that same
18 resolution, the NEPOOL Participants Committee also supported the capital budget
19 for 2016. The ISO Board of Directors approved the budgets effective on October
20 15, 2015.
ISO New England Inc. Exhibit 3 Recovery of 2016 Administrative Costs Page 7
1 Q. DESCRIBE THE ISO’S HISTORY OF STAYING WITHIN ITS BUDGET.
2 A. The ISO has amassed a consistent track record of spending integrity; since the
3 inception of its self-funding tariff for calendar year 1998, the ISO’s annual
4 spending has never exceeded the budget used to calculate the revenue requirement
5 accepted by the Commission that forms the basis for the rates for the year in
6 question. Should the need ever arise for the ISO to spend beyond a given year’s
7 budget (including contingencies), the ISO will first seek stakeholder support and
8 then file a rate increase with the Commission, thus allowing stakeholder and
9 Commission review before approving such increases.
10 DESCRIPTION OF THE 2016 REVENUE REQUIREMENT1
11 Q. WHAT IS THE 2016 REVENUE REQUIREMENT AND WHAT ARE ITS
12 ELEMENTS?
13 A. As shown in RCL-2, Schedule 2, the 2016 Revenue Requirement is approximately
14 $184.5 million (after true-up). The 2016 Revenue Requirement contains the
15 following components, each of which is discussed below: (1) the 2016 operating
16 budget ($149.6 million) (i.e., the administrative costs of running the ISO);
17 (2) depreciation and amortization of regulatory assets ($33 million); (3) interest
18 expense of $2.5 million; and (iv) a final true-up adjustment for 2014 (the “2014
19 True-Up Amount”) calculated pursuant to Section IV.A.2.2 of the Tariff (a
1 Generally, numbers used herein are rounded for ease of reference and, accordingly, may not sum.
ISO New England Inc. Exhibit 3 Recovery of 2016 Administrative Costs Page 8
1 decrease in the 2016 Revenue Requirement of approximately $600,000 resulting
2 from an over-collection in 2014).
3 Q. WHAT IS THE IMPACT OF THE INCREASED REVENUE
4 REQUIREMENT ON CONSUMER COSTS?
5 A. If the ISO’s Revenue Requirement were fully passed through to end-use
6 customers, their cost would average 99 cents per month, up from 2015 levels of
7 90 cents. This increase is largely due to the change in the true-up amounts year
8 over year. See slide 14 of the ISO’s annual budget presentation to stakeholders
9 (the “Budget Presentation”), which can be found at http://www.iso-ne.com/static-
10 assets /documents/2015/09/2_2016_operat_capital_budget_update_
11 09_23_2015.pdf.
12 Q. WHAT ARE THE MOST SIGNIFICANT CHANGES IN THE 2016
13 OPERATING EXPENSE BUDGET COMPARED WITH THE 2015
14 OPERATING EXPENSE BUDGET?
15 A. As described below, the ISO proposes to increase its Core Operating Budget (all
16 costs other than depreciation and the true-up) from 2015 levels to: (i) maintain
17 competitive compensation and benefits ($3.8 million); (ii) maintain existing
18 software licenses and maintenance ($1.3 million); (iii) cyber security initiatives,
19 including creation of a 24/7 cyber security operations center ($1.3 million); (iv)
20 meet the Internal Market Monitor’s resource needs, including two new headcount
21 ($1.0 million); (v) implement changes to the Forward Capacity Market
ISO New England Inc. Exhibit 3 Recovery of 2016 Administrative Costs Page 9
1 ($800,000); and (vi) and miscellaneous increases, including increased NERC and
2 NPCC dues ($1.2 million). Because the ISO has also realized efficiencies and
3 savings of $3.8 million, the net increase has been reduced to approximately $5.6
4 million.
5 Q. PLEASE DESCRIBE THE COSTS TO MAINTAIN COMPETITIVE
6 COMPENSATION AND BENEFITS.
7 A. To maintain medical benefits and life and disability insurance for its employees
8 and to fund its defined contribution pension plan, the ISO will incur an additional
9 $700,000 in costs. This category also includes the ISO’s $3.1 million budget for a
10 2.75% increase in salaries based on merit and a .75% increase for promotions.
11 The budgeted amounts for merit and promotion are developed using data from
12 several national compensation consultants, and are within the ranges reported in
13 these surveys. Please see Ms. Dickstein’s testimony for detail on the development
14 of these allocations, compensation practices in general, and the ISO’s compliance
15 with the standards of the Internal Revenue Service regarding the reasonableness of
16 executive compensation.
17 Q. PLEASE DESCRIBE THE INCREASES TO MAINTAIN COMPUTER
18 LICENSES AND MAINTENANCE.
19 A. The cost increase of $1.3 million in this category represents increased costs for
20 on-going support, systems backup software, and support for new hardware and
21 software. Most significantly, the costs stem from Microsoft’s determination that
ISO New England Inc. Exhibit 3 Recovery of 2016 Administrative Costs Page 10
1 independent system operators and regional transmission organizations no longer
2 qualify for pricing as charitable organizations.
3 Q. PLEASE DESCRIBE THE INCREASES FOR CYBER SECURITY
4 INITIATIVES, INCLUDING A 24/7 CYBER SECURITY OPERATIONS
5 CENTER.
6 A. More than half of the cost increase of $1.3 million in this category is to fund six
7 full-time employees who will provide around-the-clock surveillance of systems
8 and networks in a cyber security operations center. The ISO’s Board of Directors
9 proposed this center after forming an ad hoc Cyber Security Committee to assess
10 and address the ISO’s cyber security risks. The remainder of the cost increase is
11 for new or enhanced monitoring software and cyber security insurance, a
12 relatively new product that protects against the costs of a cyber security event.
13 Q. PLEASE DESCRIBE THE INCREASES TO MEET THE INTERNAL
14 MARKET MONITOR’S RESOURCE NEEDS.
15 A. The ISO’s internal market monitor has identified resources that are needed for his
16 department to perform its monitoring and mitigation functions. These resources
17 include two new full-time employees and consulting support to address workload
18 created by new features of the Forward Capacity Market, including de-list
19 reviews, non-price retirements, Pay For Performance, and an update to the Offer
20 Review Trigger Price ($300,000). Other portions of the cost increase will fund
21 enhanced monitoring capabilities through improvements in processes, data
ISO New England Inc. Exhibit 3 Recovery of 2016 Administrative Costs Page 11
1 gathering, and analysis for systems enhancements ($500,000). Finally, $200,000
2 has been allocated to funding for information technology support of market
3 monitoring systems.
4 Q. PLEASE DESCRIBE THE INCREASES TO IMPLEMENT CHANGES TO
5 THE FORWARD CAPACITY MARKET.
6 A. As noted in the description of increased market monitoring costs, there have been
7 a number of changes to the Forward Capacity Market that have increased the
8 ISO’s workload. More specifically, the cost increase of $800,000 in this category
9 results from the need for additional consulting and staff time in Market
10 Development to design sloped demand curves, qualification process changes,
11 auction pricing rules and associated reconfiguration auctions, and to address
12 demand-side participation. Other increased costs include consultant funding in
13 System Planning to update the calculation of the Cost of New Entry.
14 Q. PLEASE DESCRIBE THE MISCELLANEOUS INCREASES.
15 A. The cost increase of $1.2 million in this category is attributable to increased
16 hardware leasing costs, maintenance of new control room communication
17 systems, consulting services in information technology to support Model-On-
18 Demand, support for enhancements to the Energy Management System, training
19 on NERC Standards for System Operations, and integration of market
20 enhancements in Settlements and Market Operations. These enhancements
21 include Sub-Hourly Settlements, Divisional Accounting and Oracle Business
ISO New England Inc. Exhibit 3 Recovery of 2016 Administrative Costs Page 12
1 Intelligence. Finally, this category includes $100,000 to meet increased NERC
2 and NPCC dues and fees for the Eastern Interconnect Data Sharing Network.
3 Q. PLEASE PROVIDE FURTHER INFORMATION ON INCREASED HEAD
4 COUNT FOR 2016.
5 A. To determine its resource needs for 2016, the ISO looked at the work load to be
6 completed, including on-going work from 2015, non-repetitive work from 2015 to
7 2016, and new work for 2016. Each area of the Company then reviewed the
8 current resources available to complete this work, utilizing the current employee
9 complement to perform this work to the greatest extent possible. Accordingly, in
10 approaching the completion of the bottom-up budget, the ISO looked to add
11 positions only if (1) the position was needed for resource purposes or (2) the
12 position was cost beneficial to the overall budget.
13 The ISO is requesting a total of 8.5 additional positions in the 2016 budget. As
14 discussed above, the requested positions include six full-time employees to staff
15 the Cyber Security Operations Center and two full-time employees in Market
16 Monitoring. The remaining .5 is the net of two part-time employees moving to
17 full-time to support power system modeling improvements in Information
18 Technology Department and outage coordination in System Operations, and
19 another employee in a business analyst role is going from full-time to part-time.
ISO New England Inc. Exhibit 3 Recovery of 2016 Administrative Costs Page 13
1 These additional positions relate to only a small portion of the additional work
2 being taken on for 2016. In fact, a number of resources are being reallocated to
3 2016 priorities. Specifically, approximately eight full-time employees will be
4 reallocated to new work, including six in Market Operations and two in System
5 Planning. This was accomplished through a combination of efficiencies gained or
6 the discontinuation of other work previously performed. Additionally, internal
7 ISO employees will assume work previously performed by contractors, under both
8 the operating and capital budgets, including in Market Operations (operating and
9 capital), Legal (operating), and System Planning (operating).
10 Q. THERE HAS BEEN SIGNIFICANT ORGANIZATIONAL GROWTH IN
11 RECENT YEARS. CAN YOU EXPLAIN IT?
12 A. The ISO will have added 52 full-time employees over the course of 2013, 2014,
13 2015 and 2016. This growth reflects the increase in the complexity of the ISO’s
14 operations. For example, compliance with new and emerging NERC and NPCC
15 standards has required a significant investment. The ISO has also provided
16 additional services, like doubling its billing obligations through twice-weekly
17 billing, which further mitigated market participants’ risk of significant payment
18 defaults, and adding transmission planning and economic studies. All of these
19 changes require personnel. Another area that has contributed to the addition of
20 employees is the replacement of long-term contractors with employees where the
21 responsible manager made a determination that the work being performed is
ISO New England Inc. Exhibit 3 Recovery of 2016 Administrative Costs Page 14
1 permanent and that it was cost-advantageous to convert the position to that of a
2 full-time employee. These added positions had little or no impact on the budget.
3 Finally, certain departments have grown, including System Operations, in part due
4 to the need for employees to staff the Back-Up Control Center, which is more
5 robust as a result of compliance with more stringent requirements from the
6 Commission and NERC, and to provide training and backup for Control Room
7 Operators. Market Monitoring has grown as well, given the Commission’s
8 emphasis on this area and the evolution of the markets, including the Forward
9 Capacity Market. As noted above, two of the positions added for 2016 are for
10 Market Monitoring, with the rest of the full-time positions created to meet the
11 increasing cyber security risks through the staffing of a 24/7 Cyber Security
12 Operations Center.
13 Q. HOW DOES ISO-NE’S SIZE COMPARE TO OTHER ISOS AND RTOS?
14 While the types and scopes of services vary widely among the ISOs and RTOs,
15 many costs are largely fixed, because all ISOs and RTOs must comply with the
16 Commission’s orders and mandatory reliability standards. ISO-NE does review
17 what others are spending. (See detail on comparisons in the ISO’s Budget
18 Presentation.) ISO-NE’s review indicates that its cost structure is reasonable.
ISO New England Inc. Exhibit 3 Recovery of 2016 Administrative Costs Page 15
1 Q. PLEASE DESCRIBE THE BUDGET CUTS AND DEFERRALS THAT
2 OFFSET THESE INCREASED COSTS.
3 A. For 2016, the ISO has realized $3.8 million in savings by reallocating resources,
4 automating work, identifying efficiencies, and eliminating discontinued or non-
5 repetitive work. As discussed above, eight employees were reassigned internally
6 to save costs.
7 The $3.8 million also includes a small amount of savings in contributions to the
8 ISO’s defined benefit pension plan, which was closed to new entrants as of
9 January 1, 2014, but which must still be funded to meet the ISO’s obligations to
10 employees who were enrolled before that cut-off date.
11 For 2016 and future years, the ISO has changed its funding methodology for the
12 defined benefit pension plan, by adopting a “level funding” approach. After
13 consulting with its actuaries and investment consultants, the ISO decided on a flat
14 $10 million contribution to the plans for each of the next ten years (barring
15 unforeseen circumstances). This level funding approach should decrease the
16 volatility of the expense while still maintaining reasonable levels of funding. If
17 the ISO had not adopted this approach, the 2016 contribution would have been
18 $11.05 million.
ISO New England Inc. Exhibit 3 Recovery of 2016 Administrative Costs Page 16
1 Q. DOES THE REVENUE REQUIREMENT INCLUDE DEPRECIATION ON
2 ITEMS IN THE CAPITAL BUDGET THAT ARE PLACED IN SERVICE
3 IN 2016?
4 A. Yes. The ISO’s depreciation rates remain unchanged from those accepted by the
5 Commission in the ISO’s 2015 Revenue Requirement. The ISO uses the straight-
6 line depreciation methodology based on no net salvage value and the various
7 average service lives described below. These service lives reflect the ISO’s
8 historical experience and forecasted expectations for capital projects placed into
9 service, are necessary to comply with the ISO’s funding mechanisms, are
10 consistent with the ISO’s historical experience, and have been repeatedly
11 determined by independent auditors to be reasonable. The service lives are:
12 • Computer hardware, software and accessories: 3 to 5 years
13 • Software development costs: 3 to 5 years
14 • Furniture and fixtures: 7 years
15 • Machinery and equipment: 7 years
16 • Building: average of 25 years (based on the opinion of independent bond
17 counsel and analysis of the service lives of the different aspects of the
18 building (e.g., the building’s steel and concrete at 40 years, mechanical
19 and electrical work at 25 years, and high wear-and-tear elements at 15
20 years))
21 • Leasehold/Building Improvements: lesser of 1 to 25 years or remaining
22 life of the lease or building, as determined at the time of the purchase
ISO New England Inc. Exhibit 3 Recovery of 2016 Administrative Costs Page 17
1 based on the nature of each such improvement (e.g., rooftop railing at
2 twenty-five years, air conditioning unit at fifteen years, capacitor bank at
3 ten years)
4 • Vehicles: 3-7 years
5 The ISO uses private placement debt, issued pursuant to Commission
6 authorization under Section 204 of the Federal Power Act, to fund its capital
7 program. The ISO funds future capital expenditures by using amounts collected
8 for depreciation, with the notes covering the delay between project expenditures
9 and the collection of depreciation through rates. In addition, the ISO funds its
10 working capital needs through a revolving line of credit.
11 The private placement notes are non-amortizing, with interest-only payments due
12 semi-annually throughout the life of the notes, and the principal due at the end of
13 the term. Revenue reserved for the depreciation of capital assets, as well as assets
14 placed in service in prior years and still depreciable, will be available to repay the
15 remaining principal amounts on outstanding debt.
16 Please note that capital projects include the cost of the necessary work performed
17 by the product manager, test coordinator and business analyst in the Program
18 Management Office and design work. If the design is approved and built, this
19 project management and design work is part of the asset on which depreciation is
20 collected when the asset is placed in service in future years via the Revenue
ISO New England Inc. Exhibit 3 Recovery of 2016 Administrative Costs Page 18
1 Requirement. On the other hand, if the capital project is abandoned, the ISO
2 writes off the project management and design work and recovers it in full in the
3 year of abandonment. In addition, each capital project also includes the first
4 year’s maintenance cost and license fees for any newly capitalized software.
5 Q. HOW DOES THE ISO ADDRESS UNEXPECTED COSTS THAT MIGHT
6 MATERIALIZE DURING 2016?
7 A. The 2016 Core Operating Budget includes two line items to address unexpected
8 needs: (i) the CEO Emerging Work allowance of $1.1 million; and (ii) the
9 Operating Contingency of $700,000. Inclusion of these contingency amounts
10 recognizes that circumstances may arise that the ISO does not foresee in setting its
11 2016 Revenue Requirement for its various departments and programs.
12 The CEO Emerging Work Allowance covers new or deferred activities and
13 initiatives that emerge or become priorities during the year. Approval from both
14 the CEO and CFO is required before the ISO may draw upon these funds.
15 The Operating Contingency provides a funding source of last resort. ISO
16 management cannot access this fund without first obtaining approval from the
17 ISO’s independent Board of Directors.
ISO New England Inc. Exhibit 3 Recovery of 2016 Administrative Costs Page 19
1 Q. DO YOU FORESEE ANY PARTICULAR CONTINGENCIES THAT
2 WILL WARRANT THE ISO TAPPING INTO THESE FUNDS?
3 A. I cannot say for sure what type of contingencies might arise. There are, however,
4 several ongoing issues that might require additional funds not included in the
5 2016 Core Operating Budget. The biggest issue is litigation that could be initiated
6 or accelerated in 2016. Additional risks include costs to comply with unforeseen
7 significant shifts in federal and state policy, costs of complying with Order 1000
8 that exceed estimates, interest rates, and additional cyber security work. In
9 general, states, Customers and the Commission will determine the extent of
10 additional work and resources required.
11 Q. HAS THE ISO TAKEN ANY ACTION TO MITIGATE THE RISK OF A
12 CHANGING INTEREST RATE ENVIRONMENT?
13 A. The ISO has purchased an interest rate cap for a portion of its tax-exempt bond
14 issuances. The tax-exempt bonds were issued in Massachusetts to fund the
15 refurbishing of the Main Control Center and in Connecticut to fund the
16 development of the Back-Up Control Center. Both sets of bonds are priced at a
17 weekly variable rate. By opting for variable rates on both sets of bonds, the ISO
18 has saved more than $12,100,000 since 2005 when the ISO first issued the
19 Massachusetts tax-exempt bonds (the Connecticut bonds were issued in 2012).
20 The ISO will protect that savings through the interest rate cap. The cap will
21 effectively serve as an insurance policy or “stop loss” mechanism in a changing
ISO New England Inc. Exhibit 3 Recovery of 2016 Administrative Costs Page 20
1 interest rate environment, and is intended to cover the ISO’s interest rate exposure
2 through February 1, 2024 if rates rise significantly.
3 The cap covers only the unhedged portion of the variable rate debt. The ISO has
4 not purchased coverage for the portion of the debt that is hedged by the interest
5 earned on the settlement float that the ISO has through the normal course of
6 participant settlement, billing and payment. In other words, for a portion of the
7 ISO’s debt, the interest earned on the balance carried in the settlement account (as
8 amounts are due two days before they are paid out to customers) offsets the
9 interest due on the bonds. Because the projected average balance in the settlement
10 account does not provide complete cover for the floating rate tax-exempt debt, the
11 ISO purchased the 10-year interest rate cap to protect against a large uptick in the
12 variable tax-exempt interest rates for the uncovered portion.
13 Since the tax-exempt bonds are amortizing, the hedge is only in place until the
14 unamortized amount of the bonds drop below the projected average balance in the
15 settlement account. The cost of the cap is about $88,000 per year.
16 Q. PLEASE DESCRIBE THE CALCULATION OF THE 2014 TRUE-UP.
17 A. As set forth in Section IV.A.2.2 of the Tariff, the ISO has reconciled calendar year
18 2014’s actual expenses and collections under Schedules 1, 2 and 3 of the Tariff by
19 means of a true-up. The actual difference between 2014 expenses and collections
ISO New England Inc. Exhibit 3 Recovery of 2016 Administrative Costs Page 21
1 is an over-collection of approximately $600,000, which decreases the 2016
2 Revenue Requirement by that amount. See RCL–2, Schedule 2.
3 Q. HOW IS THE 2014 TRUE-UP AMOUNT ALLOCATED AMONG THE
4 THREE SCHEDULES?
5 A. Schedule 1 increases by $1.69 million; Schedule 2 decreases by about $2.35
6 million; and Schedule 3 increases by $40,000. See RCL-2, Schedule 2.
7 ACTIVITY ACCOUNTING SYSTEM
8 Q. DESCRIBE THE ISO’S ACTIVITY ACCOUNTING SYSTEM AND THE
9 EXTENT TO WHICH IT PROVIDES COST OF SERVICE
10 INFORMATION FOR EACH OF THE THREE PRIMARY SCHEDULES.
11 A. The activity accounting system was implemented at the ISO’s inception in 1997
12 and refined in 1998. All operating charges recorded in the general ledger system
13 must be cross-referenced to an activity. Each department has identified its major
14 activities. Most activities are department-specific, but some activities may be
15 cross-charged if they are of a project nature. Activities within a department are
16 known as either “direct” activities or “indirect” activities. Direct activities are of
17 an operational nature and are allocated to one or more of the three schedules based
18 on a fixed percentage. This fixed allocation is provided by the department
19 manager annually in preparation for the next year’s budget and tariff filing.
20 Indirect activities are of an administrative nature and are allocated based on
21 current direct labor charges. In addition, the majority of activities for
ISO New England Inc. Exhibit 3 Recovery of 2016 Administrative Costs Page 22
1 administrative departments (Finance, Human Resources, etc.) are allocated based
2 on the total labor charges within the Company.
3 The activity accounting system is largely manual, meaning that timesheets and
4 invoices are coded manually. The ISO found that it would not be prudent to
5 overly expand the system to require each employee to specify the schedule
6 serviced through the week. Further, the ISO does not pre-code employees’ time
7 because duties change often with seasonality or new projects. Therefore, the
8 allocation of activities to the schedules is made at the manager level.
9 The activity system is not designed to track costs to individual markets or
10 transaction units. An employee’s time is not driven by the number of transaction
11 units or markets, but by the number of tasks and projects.
12 If the activity accounting system were expanded to provide for accounting cost in
13 more detail, it would be more costly and difficult to manage without substantially
14 increasing its accuracy.
15 Q. HOW WAS THE TARIFF SCHEDULE ALLOCATION VERIFIED?
16 A. In developing the Revenue Requirement for each schedule, managers with cost
17 center responsibilities are required to review the allocation of each and every
18 activity under their control as to the appropriateness of the allocation. During this
19 lengthy evaluation process, all of the activities used by the ISO are reviewed. It is
ISO New England Inc. Exhibit 3 Recovery of 2016 Administrative Costs Page 23
1 this activity allocation structure that formed the basis of the revenue requirements
2 for each of the three primary schedules.
3 2016 COST ALLOCATION AMONG SCHEDULES 1, 2, AND 3
4 Q. HAVE YOU PREPARED AN EXHIBIT THAT SHOWS THE
5 DEVELOPMENT OF THE COST OF SERVICE (“COS”) ANALYSIS?
6 A. Yes. The following schedules support the COS shown in RCL-3:
7 Schedule 1 Total Cost Allocation to Schedules by Department
8 Schedule 2 Total Direct Labor Allocation to Schedules by Department
9 Schedule 3 Total Cost Allocations to Schedules by Cost Category
10 Schedule 4 Direct Labor Cost Allocations to Schedules by Cost 11 Category
12 Schedule 5 Allocation Factors by Cost Category
13 Schedule 6 Allocation on Depreciation and Amortization Expense
14 Q. WHAT IS THE ISO’S MAIN EXPENSE?
15 A. As a non-profit entity that operates, but does not own, generation or transmission
16 assets, the ISO’s main expense in the Core Operating Budget is personnel. As
17 shown in RCL-5, Schedule 1, the ISO has budgeted $106.1 million of the ISO’s
18 2016 Core Operating Budget for salaries and overhead. This category includes
19 fees for the Board of Directors, as well.
ISO New England Inc. Exhibit 3 Recovery of 2016 Administrative Costs Page 24
1 Q. WOULD YOU PLEASE DESCRIBE YOUR RCL-3?
2 A. RCL-3, Schedule 1 contains the Test Year 2016 COS for each of the three primary
3 rate schedules. The exhibit lays out in detail how ISO costs were assigned to the
4 three schedules.
5 Most activity costs consist of direct labor costs, employee benefits, and other non-
6 labor-related costs (e.g., office supplies, software, hardware, depreciation, interest,
7 consulting, etc.). For each Activity Code, both the labor-related and non-labor-
8 related costs are assigned to the rate schedule using the same allocator.
9 Q. 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 2016. Within a given department, known
13 allocators (“Alloc-Fixed”) for specific cost categories were used to allocate those
14 labor costs that were specifically attributable to a schedule. The Alloc-Fixed labor
15 costs were summed for that department and all remaining labor costs within that
16 department were allocated in proportion to the summed Alloc-Fixed costs. Labor
17 costs within all departments were allocated in this manner and summed for the
18 entire company. Schedule 5 of RCL-3 summarizes the labor allocation factors or
19 labor ratios for each Activity Code. These ratios were then used to allocate
20 various cost items in Schedules 3, 4, and 6 of RCL-3.
ISO New England Inc. Exhibit 3 Recovery of 2016 Administrative Costs Page 25
1 Q. PLEASE SUMMARIZE YOUR PROPOSED 2016 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 2016
5 Operating Expense Revenue Requirement (also provided on line 10 to RCL-2,
6 Schedule 2, page 1) decreased by the true-up amount (also provided on line 14 to
7 RCL-2, Schedule 2, page 1) to result in the total 2016 Revenue Requirement (also
8 provided on line 17 to RCL-2, Schedule 2, page 1).
Table 1 2016 Cost of Service Results (1)
Description Test Year True-Up Total (a) (b) (c) (d)
Schedule 1, Scheduling, System Control and Dispatch Service $ 44,360,392 $ 1,688,404 $ 46,048,796 Schedule 2, Energy Administration Service 84,722,023 (2,348,713) 82,373,310 Schedule 3, Reliability Administration Service 56,068,806 38,565 56,107,371 Total $ 185,151,221 $ (621,744) $ 184,529,477
9 (1) From Exhibit 3 (RCL-3), Schedule 1.0.
10 Q. EXCLUDING TRUE-UP AMOUNTS, HOW DO THE COS RESULTS IN
11 SCHEDULE 1 OF RCL-3 COMPARE WITH THE TEST YEAR 2015 COS
12 RESULTS, ON WHICH THE CURRENT ISO RATES ARE BASED?
13 A. Table 2 below compares, before taking into account any true-ups, the 2016 COS
14 results from Schedule 1 of RCL-3 to the 2015 COS results. Table 2 demonstrates
ISO New England Inc. Exhibit 3 Recovery of 2016 Administrative Costs Page 26
1 how, excluding the true-up amounts, the 2016 COS constitutes a $6.8 million
2 increase from the 2015 COS accepted by the Commission last year.
Table 2 Comparison for Cost of Service Results
(Before True-Ups)
ISO Tariff Schedules Description Total Schedule 1 Schedule 2 Schedule 3 (a) (b) (c) (d) (e)
2016 COS (1) $185,151,221 $44,360,392 $84,722,023 $56,068,806
2015 COS (2) $178,314,912 $42,327,088 $81,019,153 $54,968,671
Difference -$ $6,836,309 $2,033,304 $3,702,870 $1,100,135 -% 3.8% 4.8% 4.6% 2.0%
(1) From Table 1, Column (b).
3 (2) From Exhibit 3 (RCL-3), Sch. 1.0, Ln. 47, in FERC Dkt. No. ER15-112-000.
4 Q. HAVE YOU IDENTIFIED SPECIFIC ACTIVITY ITEMS THAT GIVE
5 RISE TO THE INCREASES AND/OR DECREASES SHOWN ABOVE
6 FOR THE THREE SCHEDULES?
7 A. Yes. Table 3 below highlights key activity items from Test Year 2016 allocated
8 among the three primary schedules by cost category (RCL-3, Schedule 3), along
9 with various depreciation/amortization items (RCL-3, Schedule 6), which changed
10 from 2015. The identified activity items account for the majority of the cost shifts
11 within each of the three schedules.
ISO New England Inc. Exhibit 3 Recovery of 2016 Administrative Costs Page 27
Table 3 Examples of Differences in 2016 Operating Expenses
ISO Tariff Schedules Activity Description Total Schedule 1 Schedule 2 Schedule 3 Code (a) (b) (c) (d) (e) (f) Test Year 2016
Various Depreciation/Amortization $ 32,882,654 8,659,550 13,677,404 10,545,700 6540 Security Compliance and Reporting 2,169,684 467,524 1,122,835 579,325 Various Market Monitoring 4,665,011 - 3,111,632 1,553,379 12017 Forward Capacity Market (FCM) Reforms 810,821 - - 810,821 6512 Host Computer - Hardware 1,146,315 - 859,736 286,579 6595 IT WEB Application Support 722,943 155,780 374,131 193,032 21604 DTS Support 1,544,494 1,235,595 308,899 - 21605 DAM Support 1,000,980 200,196 600,588 200,196 21804 Software Support - Mitigation 451,110 - 360,888 90,222 21654 NX9 Administration 481,016 192,406 192,406 96,203 6541 Security SW Tools Program 333,579 71,880 172,631 89,069 6513 Host Computer - Software 1,763,842 - 1,322,882 440,961 21707 Application Analysis and Conceptual Design 1,074,003 - 859,202 214,801 3000 Hourly Settlements Support 263,183 - 131,592 131,592 2033 M arket Analysis 184,563 - 184,563 - 21651 Power System Modeling 861,609 344,643 344,643 172,322 6615 Host Computer Monitoring 1,254,513 - 627,257 627,257 - Totals $ 51,610,318 $ 11,327,574 $ 24,251,288 $ 16,031,456 Test Year 2015
Various Depreciation/Amortization $ 31,650,319 7,535,487 12,856,039 11,258,793 6540 Security Compliance and Reporting 1,284,381 276,759 664,681 342,941 Various Market Monitoring 3,769,871 - 2,631,545 1,138,326 12017 Forward Capacity Market (FCM) Reforms 140,871 - - 140,871 6512 Host Computer - Hardware 824,921 - 618,691 206,230 6595 IT WEB Application Support 414,337 89,281 214,424 110,632 21604 DTS Support 1,236,045 988,836 247,209 - 21605 DAM Support 749,238 149,848 449,543 149,848 21804 Software Support - Mitigation 239,986 - 191,989 47,997 21654 NX9 Administration 276,854 110,742 110,742 55,371 6541 Security SW Tools Program 148,352 31,967 76,774 39,611 6513 Host Computer - Software 1,596,370 - 1,197,277 399,092 21707 Application Analysis and Conceptual Design 919,376 - 735,501 183,875 3000 Hourly Settlements Support 122,522 - 61,261 61,261 2033 M arket Analysis 81,868 - 81,868 - 21651 Power System Modeling 768,214 307,285 307,285 153,643 6615 Host Computer Monitoring 1,174,719 - 587,359 587,359 Totals $ 45,398,243 $ 9,490,204 $ 21,032,188 $ 14,875,851 Test Year 2016 Costs Minus Test Year 2015 Costs
Various Depreciation/Amortization $ 1,232,335 1,124,063 821,365 (713,093) 6540 Security Compliance and Reporting 885,303 190,765 458,154 236,384 Various Market Monitoring 895,140 - 480,087 415,053 12017 Forward Capacity Market (FCM) Reforms 669,950 - - 669,950 6512 Host Computer - Hardware 321,394 - 241,045 80,348 6595 IT WEB Application Support 308,606 66,498 159,707 82,400 21604 DTS Support 308,449 246,759 61,690 - 21605 DAM Support 251,742 50,348 151,045 50,348 21804 Software Support - Mitigation 211,124 - 168,899 42,225 21654 NX9 Administration 204,162 81,665 81,665 40,832 6541 Security SW Tools Program 185,227 39,913 95,857 49,457 6513 Host Computer - Software 167,472 - 125,604 41,868 21707 Application Analysis and Conceptual Design 154,627 - 123,701 30,925 3000 Hourly Settlements Support 140,661 - 70,331 70,331 2033 M arket Analysis 102,695 - 102,695 - 21651 Power System Modeling 93,395 37,358 37,358 18,679 6615 Host Computer Monitoring 79,794 - 39,897 39,897 Totals $ 6,212,075 $ 1,837,370 $ 3,219,100 $ 1,155,605 All Other Unidentified Changes $ 624,234 $ 195,934 $ 483,771 $ (55,471) Total Change in Cost of Service $ 6,836,309 $ 2,033,304 $ 3,702,870 $ 1,100,135 1 % of Difference shown on Table 2 90.87% 90.36% 86.94% 105.04% ISO New England Inc. Exhibit 3 Recovery of 2016 Administrative Costs Page 28
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 2015 RATE TO THOSE
4 UTILIZED HERE FOR TEST YEAR 2016.
5 A. Schedule 1: The increase in the Revenue Requirement for Schedule 1 results
6 from 2016 cost increases and changes that impact all three schedules, including
7 the costs to maintain the benefits and compensation, the costs of cyber security
8 improvements, computer service licensing and maintenance, and depreciation
9 expenses for in-service projects including Critical Infrastructure Protection v. 5
10 and Business Continuity Planning Phase III – Remote Desktop. The remainder of
11 the Schedule 1 increase is depreciation expense for the Coordinated Transaction
12 Scheduling project (predominantly allocated to Schedule 1) and the Generation
13 Control Application Production Part 1 project (allocated evenly between
14 Schedules 1 and 2).
15 Schedule 2: The increase in the Schedule 2 Revenue Requirement is due to:
16 increases that impact all three schedules, as discussed in the preceding paragraph;
17 increased funding for Market Monitoring, as discussed above; and depreciation
18 for the Business Continuity Planning Phase III – Markets Infrastructure project
19 (largely allocated to Schedule 2), the Generation Control Application Production
20 Part 1 project (allocated evenly between Schedules 1 and 2), and the Wind
ISO New England Inc. Exhibit 3 Recovery of 2016 Administrative Costs Page 29
1 Integration Phase II/Do Not Exceed Dispatch project (allocated evenly between
2 Schedules 2 and 3).
3 Schedule 3: The increase in the Schedule 3 Revenue Requirement is due to: the
4 increased costs allocated to all three schedules (see above); funding for the
5 increased Forward Capacity Market costs discussed above; the increased Market
6 Monitoring costs related to Forward Capacity Market (also discussed above); and
7 depreciation expense for the Forward Capacity Auction 10 project and the Wind
8 Integration Phase II/Do Not Exceed Dispatch project (allocated evenly between
9 Schedules 2 and 3). The increases were offset by an overall reduction in
10 depreciation expense for Schedule 3 as a result of previously-implemented
11 projects becoming fully depreciated during 2016. These projects include the
12 Synchrophasor Infrastructure and Data Utilization project, the Energy
13 Management System Upgrade and Enhancements project, and the Forward
14 Capacity Market Enhancements 2012 project.
15 THE ISO RATE DESIGN AND ESCALATION FACTORS
16 Q. HOW DID YOU DEVELOP THE ESCALATION FACTORS?
17 A. Consistent with the practice reflected in the filings establishing the ISO’s rates to
18 collect its administrative costs for 1999-2015, escalation factors rely on
19 information contained in the 2015-2024 Forecast Report of Capacity, Energy,
20 Loads and Transmission (the “CELT Report”), dated May 1, 2015. The CELT
21 Report contains actual and estimated energy and peak loads for 2015-2024. The
ISO New England Inc. Exhibit 3 Recovery of 2016 Administrative Costs Page 30
1 ISO also relied on information in the ISO markets system for the 12-month period
2 ending July 2015. The development of the escalation factors is shown in RCL-7,
3 Schedule 1.
4 Q. ARE YOU PROPOSING ANY CHANGES TO THE RATE DESIGN?
5 A. The ISO is not proposing any changes to the rate design from that in place in
6 2015. However, as part of its filing of the Coordinated Transaction Scheduling
7 (“CTS”) project with the New York ISO, ISO-NE filed changes to Schedules 1, 2
8 and 3 of Section IV.A of the Tariff on September 10, 2015. Those changes are
9 still pending before the Commission.
10 CTS is intended to enhance the market efficiency of external transactions (i.e.,
11 energy imports and exports) between the two regions through economic clearing
12 of external transactions. As part of that effort, ISO-NE has proposed that certain
13 charges in Schedules 1, 2 and 3 be eliminated, effective on or after December 1,
14 2015.
15 If the Commission approves the changes, they will affect collections under
16 Schedules 1, 2 and 3. The ISO has estimated the impact of this change using
17 historical monthly average volumes for external transactions and total pool
18 charges. The ISO has concluded that the eliminated charges make up 1.1% of
ISO New England Inc. Exhibit 3 Recovery of 2016 Administrative Costs Page 31
1 Schedule 1 total charges; 2.8% of Schedule 2 charges; and 1.4% of Schedule 3
2 charges. Their elimination will raise the affected billing determinants.2
3 In its development of rates for 2016, ISO-NE has presumed Commission
4 approval; accordingly, the projected effects of CTS have been incorporated into
5 the 2016 rates that are described below. Below, ISO-NE highlights the sections of
6 the Schedules where CTS changes have been proposed.
7 Q. PLEASE OUTLINE THE CURRENT RATE DESIGN BEFORE
8 DESCRIBING THE VARIOUS ESCALATION FACTORS.
9 A. As previously indicated, Section IV.A of the Tariff has three rate schedules to
10 cover the ISO’s expenses for providing its three services: Schedule 1 -
11 Scheduling Service; Schedule 2 – Energy Administration Service; and Schedule 3
12 – Reliability Administration Service.
13 • Schedule 1
14 The Schedule 1 revenue requirement is allocated 100% to Monthly Regional
15 Network Load and the Reserved Capacity of Through and Out Service; changes
16 are pending before the Commission to exclude Coordinated External
17 Transactions, which are defined in Section I of the Tariff as transactions at
18 external interfaces to which the enhanced scheduling procedures in the CTS rules
2 Slides 5-7 of “Coordinated Transaction Scheduling: Self and Capital Funding Tariff,” a presentation to the NEPOOL Budget & Finance Subcommittee that was made in May 2015. The presentation can be found at http://www.iso-ne.com/static-assets/documents/2015/05/5a_coordinated_transaction_sch_self_cap_cft.pdf.
ISO New England Inc. Exhibit 3 Recovery of 2016 Administrative Costs Page 32
1 (located in Tariff Section III.1.10.7.A) apply. Schedule 1 revenues collected from
2 Through and Out Service Customers are credited to each Network Customer that
3 month in proportion to each Network Customer’s Monthly Regional Network
4 Load.
5 • Schedule 2
6 The Schedule 2 revenue requirement is allocated 15% to Transaction Units
7 (“TUs”) and 85% to Volumetric Measures (“VMs”), subject to the special true-up
8 described below. TUs measure the frequency and duration of activity and are
9 indifferent to the size (e.g., capacity) of any particular transaction. Conversely,
10 VMs seek to capture a customer’s “physical” reliance on the system administered
11 by the ISO and thus the benefit received.
12 A. Transaction Units
13 Schedule 2 currently utilizes three types of TUs: those associated with Real-Time
14 Energy Market transactions (Energy TU Based Charges), those associated with
15 Increment Offers and Decrement Bids, and those associated with FTR auction
16 submitted and cleared bids.
17 Energy TUs equal the sum per month of a Customer’s Bilateral Contract Block-
18 Hours, Demand Bid Block-Hours, Asset Related Demand Bid Block-Hours,
19 Supply Offer Block-Hours and Energy Non-Zero Spot Market Settlement Hours.
20 Under the ISO’s current rate design, a Customer’s total monthly Energy TUs are
21 priced under a three-tiered declining block rate structure. Under this regime, the
ISO New England Inc. Exhibit 3 Recovery of 2016 Administrative Costs Page 33
1 highest unit rate applies to the first 12,500 Energy TUs incurred in a month; the
2 Customer’s next 27,000 Energy TUs are priced approximately 10% lower; and the
3 balance of monthly Energy TUs, i.e., those in excess of 39,500, are priced at an
4 additional savings of approximately 10% on average. If the Commission
5 approves the pending CTS rules, Energy TUs will be calculated without reference
6 to contributions from Coordinated External Transactions.
7 TU Charges Based on Increment Offers and Decrement Bids are assessed based
8 on both of the following: (i) a charge multiplied by the total number of Increment
9 Offers and Decrement Bids submitted, plus (ii) a charge multiplied by the total
10 number of Increment Offers and Decrement Bids that clear the Day-Ahead Energy
11 Market. This category is sometimes referred to as “virtual activity,”
12 distinguishing it from physical activity.
13 TU Charges Based on FTR Auction Submitted and Cleared Bids are assessed
14 through both of the following: (i) a charge multiplied by the total number of FTR
15 auction bids submitted for that period, plus (ii) a charge multiplied by the total
16 number of FTR auction bids cleared for that period. The FTR charges are
17 designed to recoup the costs the ISO incurs for administering the FTR auctions.
18 The FTR revenue offsets other Schedule 2 TU charge revenues.
ISO New England Inc. Exhibit 3 Recovery of 2016 Administrative Costs Page 34
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. If the Commission approves the
10 pending CTS rules, Volumetric Measures will exclude the Monthly Real-Time
11 Generation Obligation associated with Coordinated External Transactions.
12 • Schedule 3
13 Schedule 3 allocates internal load activity based on Real-Time NCP [Non-
14 Coincident Peak] Load Obligation. For Exports, Schedule 3 assesses a volumetric
15 (per MWh) charge. Specifically, the ISO divides the Schedule 3 Revenue
16 Requirement by the real-time load obligation forecasted for the upcoming year in
17 the most recent CELT Report. The remaining revenue requirement for Schedule 3
18 (i.e., net of that allocated to Exports) is then divided by the total Real-Time NCP
19 Load Obligation forecast to yield the unitized rate per kW-month. If the CTS
20 rules are approved by the Commission, Coordinated External Transactions will be
21 exempt from Schedule 3 Export charges.
ISO New England Inc. Exhibit 3 Recovery of 2016 Administrative Costs Page 35
1 Q. PLEASE EXPLAIN THE ESCALATION FACTORS UTILIZED TO
2 DEVELOP THE BILLING DETERMINANTS FOR 2016.
3 A. The Schedule 1 billing determinants for 2016 were decreased by a net escalation
4 factor of .999. This net is the sum of a 1.0% increase consistent with the
5 increased load projected in the CELT Report data and a 1.1% reduction given the
6 CTS project. See column (c) of RCL-7, Schedule 2.
7 The Schedule 2 transaction unit determinants for Energy TUs, shown in column
8 (d) of RCL-7, Schedule 2, also decrease as a result of CTS by an escalation factor
9 of .967.
10 The Schedule 2 virtual transactions and FTRs were left flat (see columns (e)
11 through (h) of RCL-7, Schedule 2). The numbers of virtual transactions and FTRs
12 have fluctuated in recent years but have not substantially changed overall. Tables
13 4 and 5 below provide, respectively, actual Virtual Energy TU data and actual
14 FTR data from January 2013 through July 2015.
ISO New England Inc. Exhibit 3 Recovery of 2016 Administrative Costs Page 36
1 Table 4
Submitted and Cleared Virtual Energy TUs 450,000 50,000
400,000 45,000 40,000 350,000 35,000 300,000 30,000 250,000 25,000
200,000 Cleared Submitted 20,000 150,000 15,000
100,000 10,000 Submitted 50,000 Cleared 5,000
0 0
2
3 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
4
ISO New England Inc. Exhibit 3 Recovery of 2016 Administrative Costs Page 37
1 The volumetric measures in Schedule 2 decrease by a factor of .985, after netting
2 a load increase of 1.0% against a 2.5% reduction based on CTS implementation.
3 See column (i) of RCL-7, Schedule 2.
4 Finally, the Schedule 3 billing determinant based on export volumes decreases
5 most dramatically as a result of CTS implementation, by an escalation factor of
6 .655, as shown in RCL-7, Schedule 2, column (k). The remainder of the Schedule
7 3 revenue requirement is assessed via a billing determinant related to NCP Load
8 Obligation. This billing determinant, like the Schedule 2 volumetric measures
9 and the Schedule 1 billing determinants, is increased by 1.0% based on CELT
10 Report load data, as shown in column (j) of RCL-7, Schedule 2. Although the
11 NCP Load Obligation billing determinant is not directly impacted by CTS
12 implementation, under CTS the rate will increase due to the lower estimated
13 volume for Schedule 3 exports since the NCP Load Obligation absorbs the
14 remaining Schedule 3 revenue requirement.
15 THE 2016 BILLING DETERMINANTS
16 Q. PLEASE DESCRIBE THE SCHEDULE 1 RATE CALCULATION.
17 A. RCL-7, Schedule 3, lines 1 through 3 show the Schedule 1 Billing Determinants
18 and the Revenue Requirement allocated thereto. Dividing the Revenue
19 Requirement by the forecasted billing units yields the rate for 2016 of
20 $0.00026/kW-hour.
ISO New England Inc. Exhibit 3 Recovery of 2016 Administrative Costs Page 38
1 Q. PLEASE DESCRIBE THE SCHEDULE 2 RATE CALCULATION.
2 A. Schedule 2 employs a declining blocked rate structure for Energy TUs and VMs.
3 The three-tiered declining block structure is discussed earlier in my testimony.
4 Increment Offers and Decrement Bid TUs and FTR TUs incur unitized charges.
5 RCL-7 (Schedule 3) and Table 6 (below) provide the Schedule 2 rates proposed
6 for 2016.
TABLE 6
2 3 Description TY 2016 (a) (b) Transaction Units INC Offers/DEC Bids Submitted $ 0.00500 /Offer or Bid Cleared $ 0.06000 /Offer or Bid
Financial Transmission Rights Submitted $ 2.02863 /Bid Cleared $ 2.62374 /Bid
Energy Transaction Units Block 1 - 1st 12,500 TUs $ 0.66437 /TU-hour Block 2 – Next 27,000 TUs $ 0.60397 /TU-hour Block 3 – Over 39,500 TUs $ 0.54358 /TU-hour
Volumetric Measures Block 1 - 1st 250,000 MWH $ 0.28296 /MWh Block 2 – Next 1,250,000 MWH $ 0.25723 /MWh Block 3 – Over 1,500,000 MWH $ 0.23151 /MWh
ISO New England Inc. Exhibit 3 Recovery of 2016 Administrative Costs Page 39
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
9 obligation forecast for 2016. The export rate is then applied to the total MWh of
10 Exports forecasted for the test year to determine the portion of the Schedule 3
11 Revenue Requirement assessed to exports. The remaining Revenue Requirement
12 for Schedule 3 (i.e., net of that allocated to exports) is then divided by the total
13 Real-Time NCP Load Obligation forecast to yield the unitized rate per kW-month.
ISO New England Inc. Exhibit 3 Recovery of 2016 Administrative Costs Page 40
TABLE 7
Description TY 2016 Amount %
Revenue Requirement ($) $ 56,107,371 100.0%
Real-Time NCP Load Obligation $ 54,996,595 98.0%
Export Rate $ 1,110,776 2.0%
Billing Units
Real-Time NCP Load Obligation 270,740,473 /kW-Mo.
Export Rate 2,776,941 /MWh
Rates
Real-Time NCP Load Obligation $ 0.20313 /kW-Mo.
Rate on Exports $ 0.40 /MWh 1
2 RATE SUMMARY
3 Q. WOULD YOU PLEASE SUMMARIZE THE RATES FOR 2016 THAT
4 YOU ARE SPONSORING?
5 A. Yes. These rates are summarized in Table 8.
ISO New England Inc. Exhibit 3 Recovery of 2016 Administrative Costs Page 41
Table 8 2016 Rate Components (1)
Tariff Schedule Jan. 1, 2016
Schedule 1 Network Load (per kW-hour) $0.00026
Schedule 2 TU Bids (Virtual Inc/Dec) Submitted $0.00500 Cleared $0.06000
FTR Bids Submitted $2.02863 Cleared $2.62374
TU's Block 1 - 1st 12,500 $0.66437 Block 2 - Next 27,000 $0.60397 Block 3 - Over 39,500 $0.54358
Volumetric Block 1 - 1st 250,000 $0.28296 Block 2 - Next 1,250,000 $0.25723 Block 3 - Over 1,500,000 $0.23151
Schedule 3 R-T NCP Load Obligation $0.20313 Export Rate $0.40000
1 (1) From Exh 3, RCL-7, Sch. 3
2 Q. PLEASE EXPLAIN THE SPECIAL CALCULATION FOR A REVENUE
3 SHORTFALL ATTRIBUTABLE TO TUs USED IN SCHEDULE 2.
4 A. In the event of a revenue shortfall attributable to TUs in the true-up year (in this
5 case, 2014), the shortfall allocation has two components. The first component
6 allocates the first 50% of the shortfall to Schedule 2 VMs rather than the usual
ISO New England Inc. Exhibit 3 Recovery of 2016 Administrative Costs Page 42
1 15/85 allocation of Schedule 2 Revenue Requirements between TUs and VMs,
2 respectively. The second component increases the percentage of the shortfall
3 allocated to VMs by an additional percentage for each percentage decrease which
4 occurred between the number of TUs used in the current true-up (based on year-
5 to-date actual data through August of the current year) and the number of TUs that
6 the ISO had used in the original projection of the rates for that year.
7 As shown in RCL-7, Schedule 6, the final 2014 amount is an over-collection of
8 $1.4 million. Accordingly, there is no variation for 2016 to the 15/85 allocation
9 of the Schedule 2 revenue requirement between TUs and VMs.
10 FIXED FEES
11 Q. DO YOU HAVE ANY OTHER COMMENTS REGARDING THE RATES
12 INCLUDED IN THE PROPOSED 2016 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 $3.02 (hourly).
15 For 2016, I am proposing to increase this hourly fee to $3.22.
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 2016 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 2016 Administrative Costs Page 43
1 ($56,107,371/$16,035,649) = $2,347.77), and breaking that down to an hourly
2 rate, which for 2016 is $3.22.
3 Q. DID YOU DEVELOP THE APPROPRIATE RAS FEES FOR THOSE
4 CUSTOMERS WHO TAKE SERVICE FOR PERIODS OF LESS THAN
5 ONE MONTH?
6 A. Yes. These charges are shown below in Table 9.
Table 9 RAS Fees
Line Proposed No. Item Current Jan. 1, 2016 (a) (b) (c)
1 Monthly Calculation $ 2,202.27 $ 2,347.77
2 Hourly Fee $ 3.02 $ 3.22 7
8 Q. UNDER THE RATES PROPOSED IN THIS FILING, WHAT HAPPENS
9 TO THE REVENUE DERIVED FROM THESE RAS FEES?
10 A. Any revenue derived from the RAS Fees will be credited back on a monthly basis
11 to all Market Participants who take service under Schedule 3 in proportion to the
12 total charges incurred by the Market Participants for that month.
1 Exhibit 3 RCL - 2 Schedule 2 ISO NEW ENGLAND INC. Page 1 of 2 2016 REVENUE REQUIREMENT (in thousands of dollars)
Line No. Operating Expense Budget:
1 Operating Budget $ 149,620.2 2 3 Depreciation and interest expense 4 Depreciation 32,997.1 5 Interest 2,533.9 6 35,531.0 7 8 Total 2016 Operating Expense Budget $ 185,151.2 9 10 2016 Operating Expense Revenue Requirement $ 185,151.2 11 12 True-Up Amount 13 14 2014 (Over)/ Under Collection $ (621.7) 15 16 17 Total 2016 ISO Revenue Requirement $ 184,529.5 Exhibit 3 RCL - 2 Schedule 2 ISO New England Inc. Page 2 of 2 2014 True-Up Amount
Line No. Schedule Total 1 2 3
1 2014 Total Operating Expense $ 162,707,212 $ 37,981,328 $ 75,179,339 $ 49,546,545 2 2014 Total Collections $ 163,328,956 $ 36,292,924 $ 77,528,052 $ 49,507,980 3 4 2014 Total (Over) / Under Collection $ (621,744) $ 1,688,404 $ (2,348,713) $ 38,565 Exhibit 3 (RCL-3) Schedule 1.0
ISO NEW ENGLAND INC. FERC DOCKET NO. ER16-___-000 TOTAL COST ALLOCATION TO SCHEDULES BY DEPARTMENT TEST YEAR 2016
Line Department Self-Funding Tariff No. Description Total Schedule 1 Schedule 2 Schedule 3 (a) (b) (c) (d) (e)
1 Administration-CEO $ 9,135,171 $ 1,968,449 $ 4,727,551 $ 2,439,171 2 3 Finance 57,380,408 12,492,669 22,877,361 22,010,378 4 5 Building Services 3,109,354 670,004 1,609,125 830,225 6 7 Enterprise Risk Management 1,548,371 409,579 695,906 442,885 8 9 Human Resources 7,510,873 1,618,445 3,886,959 2,005,469 10 11 Legal Department 9,661,273 1,917,340 4,727,255 3,016,678 12 13 Internal Audit 1,827,115 298,649 1,172,931 355,535 14 15 ISO Operations 16 COO-Adm 1,545,526 383,618 686,372 475,537 17 System Operations - Administration 414,226 143,074 192,284 78,869 18 Operations 12,209,722 3,910,611 6,291,578 2,007,533 19 Reliability and Operations Services 984,821 365,320 197,826 421,675 20 Reliability and Operations Compliance 1,267,021 526,673 420,110 320,239 21 Operations Support Services 5,547,323 3,298,538 497,765 1,751,020 22 System Operations Support 773,699 90,858 393,637 289,204 23 Market Operations - Adm 1,035,587 5,578 720,187 309,822 24 Market Monitoring 4,665,011 - 3,111,632 1,553,379 25 Market Operations 2,248,016 - 1,988,000 260,016 26 Market Anaylsis & Settlements 2,609,034 387,294 1,197,248 1,024,492 27 Market Operations Support Services 1,039,110 54,218 792,726 192,165 28 Market Services 2,159,294 276,455 1,689,884 192,955 29 Market Training and Reliability Contracts 900,242 - 466,975 433,267 30 System Planning 1,228,630 809,204 288,168 131,258 31 Resource Adequacy 4,458,046 550,337 811,628 3,096,081 32 Transmission Planning 5,326,697 5,001,206 - 325,490 33 Program Management 1,798,076 444,030 810,455 543,591 34 Business Architecture and Technology 2,295,384 494,610 1,187,887 612,888 35 Market Development 3,252,636 540,396 1,875,478 836,763 36 Markets Committee Relations & Rule Integration 740,862 26,178 372,558 342,126 37 Demand Resource Strategy 288,706 23,468 200,199 65,039 38 IT Management 4,323,391 1,019,439 2,158,705 1,145,247 39 IT System/Network & Desktop 11,656,862 1,614,419 6,687,166 3,355,277 40 IT Enterprise Applications Support 8,584,936 1,300,255 5,163,349 2,121,333 41 IT Enterprise Applications Development 1,888,404 3,960 1,460,272 424,173 42 IT Energy Management Systems 5,736,905 2,089,517 2,742,072 905,316 43 IT Cyber Security 3,228,782 695,739 1,670,930 862,113 44 IT Power System Modeling Management 2,771,706 930,264 949,844 891,598 45 Total ISO Operations 94,978,655 24,985,258 45,024,934 24,968,464 46 47 Total ISO Revenue Requirement $ 185,151,221 $ 44,360,392 $ 84,722,023 $ 56,068,806 48 True-up from 2014 (621,744) 1,688,404 (2,348,713) 38,565 49 Total True-up $ (621,744) $ 1,688,404 $ (2,348,713) $ 38,565 50 51 ISO Net Revenue Requirement $ 184,529,477 $ 46,048,796 $ 82,373,310 $ 56,107,371
(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. ER16-___-000 TOTAL DIRECT LABOR ALLOCATION TO SCHEDULES BY DEPARTMENT TEST YEAR 2016
Line Department Self-Funding Tariff No. Description Total Schedule 1 Schedule 2 Schedule 3 (a) (b) (c) (d) (e)
1 Administration-CEO $ 3,038,347 $ 654,704 $ 1,572,378 $ 811,265 2 3 Finance 14,062,314 2,855,435 6,857,793 4,349,086 4 5 Building Services 585,812 126,231 303,164 156,417 6 7 Enterprise Risk Management 1,484,538 393,470 666,569 424,499 8 9 Human Resources 4,283,799 923,074 2,216,913 1,143,812 10 11 Legal Department 6,073,496 1,224,400 2,789,332 2,059,765 12 13 Internal Audit 1,115,445 223,963 628,493 262,990 14 15 ISO Operations 16 COO-Adm 1,219,926 326,958 584,997 307,970 17 System Operations - Administration 278,921 96,339 129,475 53,107 18 Operations 11,902,912 3,790,172 6,166,308 1,946,433 19 Reliability and Operations Services 825,867 322,845 157,380 345,642 20 Reliability and Operations Compliance 1,257,732 520,131 427,698 309,903 21 Operations Support Services 5,563,160 3,286,516 527,018 1,749,626 22 System Operations Support 760,239 86,792 387,453 285,995 23 Market Operations - Adm 1,006,297 5,578 699,684 301,035 24 Market Monitoring 3,644,061 - 2,412,633 1,231,428 25 Market Operations 2,241,527 - 1,981,716 259,811 26 Market Anaylsis & Settlements 2,608,693 387,244 1,197,081 1,024,367 27 Market Operations Support Services 1,039,110 54,218 792,726 192,165 28 Market Services 1,818,114 268,655 1,416,061 133,399 29 Market Training and Reliability Contracts 1,132,684 - 676,289 456,395 30 System Planning 1,048,470 690,228 245,517 112,724 31 Resource Adequacy 3,573,876 518,484 778,365 2,277,027 32 Transmission Planning 4,610,272 4,348,473 - 261,798 33 Program Management 1,681,472 424,544 783,159 473,769 34 Business Architecture and Technology 2,041,781 439,963 1,056,644 545,173 35 Market Development 2,766,119 431,109 1,609,451 725,559 36 Markets Committee Relations & Rule Integration 711,305 24,323 357,629 329,353 37 Demand Resource Strategy 267,765 18,956 189,361 59,448 38 IT Management 3,768,606 899,894 1,871,598 997,114 39 IT System/Network & Desktop 4,883,719 782,125 2,505,419 1,596,175 40 IT Enterprise Applications Support 4,397,414 692,133 2,610,563 1,094,718 41 IT Enterprise Applications Development 1,869,365 - 1,450,232 419,134 42 IT Energy Management Systems 3,149,454 1,023,900 1,593,179 532,374 43 IT Cyber Security 2,189,389 471,770 1,133,033 584,586 44 IT Power System Modeling Management 2,006,012 653,169 671,442 681,400 45 Total ISO Operations 74,264,260 20,564,522 34,412,110 19,287,628 46 47 Total ISO Direct Labor $ 104,908,012 $ 26,965,798 $ 49,446,752 $ 28,495,462
(1) From Exhibit 3 (RCL-3), Schedule 4.0. ISO NEW ENGLAND INC. Exhibit 3 (RCL-3) FERC DOCKET NO. ER16-___-000 Schedule 3.0 TOTAL COST ALLOCATIONS TO SCHEDULES BY COST CATEGORY Page 1 of 7 TEST YEAR 2016
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 Indirect Administrative Support Total Dir Labor $ 8,127,546 $ 1,751,325 $ 4,206,094 $ 2,170,126 3 12652 NEPOOL Committee Support Total Dir Labor 14,971 3,226 7,748 3,997 4 12654 National Committee Support Total Dir Labor 10,926 2,354 5,654 2,917 5 12657 Indirect Administrative Support for BCC Total Dir Labor 981,729 211,543 508,056 262,130 6 Total 9,135,171 1,968,449 4,727,551 2,439,171 7 8 302 Finance 9 11601 Payroll Administration Total Dir Labor 366,853 79,050 189,850 97,953 10 11701 Accounts Payable Total Dir Labor 199,569 43,003 103,279 53,287 11 11702 Procurement Total Dir Labor 479,629 103,351 248,213 128,065 12 11901 Billing for Transmission and Energy Settlements Total Dir Labor 68,142 14,683 35,264 18,195 13 12001 Budgeting and Forecasting Total Dir Labor 498,264 107,366 257,857 133,041 14 12005 Credit Admininstration Total Dir Labor 333,866 71,941 172,779 89,145 15 12017 Forward Capacity Market (FCM) Reforms Alloc-Fixed 810,821 - - 810,821 16 12101 Ledger Closing, Financial Statements and Tax Reporting Total Dir Labor 589,983 127,130 305,323 157,531 17 12201 Treasury and Cash Management Total Dir Labor 2,539,144 547,135 1,314,035 677,974 18 92004 Depreciation Expense 2004 Assets Alloc-Fixed 43,160 8,988 22,535 11,637 19 92005 Depreciation Expense 2005 Assets Alloc-Fixed 802,617 169,813 417,365 215,439 20 92006 Depreciation Expense 2006 Assets Total Dir Labor 570,733 122,993 295,354 152,386 21 92007 Depreciation Expense 2007 Assets Total Dir Labor 162,196 34,953 83,937 43,306 22 92008 Depreciation Expense 2008 Assets Alloc-Fixed 15,026 6,888 5,368 2,770 23 92009 Depreciation Expense 2009 Assets Alloc-Fixed 11,454 5,155 4,155 2,144 24 92010 Depreciation Expense 2010 Assets Alloc-Fixed 103,190 24,473 51,323 27,395 25 92011 Depreciation Expense 2011 Assets Alloc-Fixed 619,573 151,324 216,674 251,575 26 92012 Depreciation Expense 2012 Assets Alloc-Fixed 2,372,346 573,449 878,234 920,664 27 92013 Depreciation Expense 2013 Assets Alloc-Fixed 8,434,369 1,703,917 3,679,657 3,050,794 28 92014 Depreciation Expense 2014 Assets Alloc-Fixed 8,246,713 2,117,577 2,905,411 3,223,724 29 92015 Depreciation Expense 2015 Assets Alloc-Fixed 10,260,470 3,506,762 4,551,536 2,202,173 30 92016 Depreciation Expense 2016 Assets Alloc-Fixed 1,240,806 233,257 565,856 441,693 31 99707 Amortization of Land Recovery Alloc-Fixed 54,396 10,516 19,353 24,527 32 99995 NPCC/NERC Dues Alloc-Fixed 5,892,615 - - 5,892,615 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 10,864,472 2,341,079 5,622,484 2,900,909 36 Total 57,380,408 12,492,669 22,877,361 22,010,378 37 38 108 Building Services 39 12664 Building Maintenance Total Dir Labor 3,109,354 670,004 1,609,125 830,225 40 Total 3,109,354 670,004 1,609,125 830,225 41 42 310 Enterprise Risk Management 43 22701 Enterprise Risk Mgmnt - Admin Alloc-Fixed 2,282 760 760 762 44 22703 Bus Cont Pl Prog Admin & Support Alloc-Fixed 141,205 47,021 47,021 47,162 45 22704 Record Retention Services Alloc-Fixed 80,512 26,810 26,810 26,891 46 22705 Corporate Scorecard Alloc-Fixed 31,379 10,449 10,449 10,481 47 22706 Document Management Services Alloc-Fixed 109,826 43,930 32,948 32,948 48 22708 Adminstration Total Dir Labor 15,689 3,381 8,119 4,189 49 22709 Management Total Dir Labor 94,137 20,285 48,717 25,135 50 22710 Employee Development Total Dir Labor 15,689 3,381 8,119 4,189 51 22711 Forward Capacity Market (FCM) Cap Adjustments Total Dir Labor 21,509 4,635 11,131 5,743 52 22712 Risk Policy Assessments Total Dir Labor 15,689 3,381 8,119 4,189 53 22713 MEC/Financials Total Dir Labor 31,379 6,762 16,239 8,378 54 22714 Analysis Total Dir Labor 125,515 27,046 64,956 33,514 55 22716 Financial Assurance Management (FAM) Rebuild Total Dir Labor 109,826 23,665 56,836 29,325 56 22719 Human Performance Improvement Total Dir Labor 9,894 2,132 5,120 2,642 57 22720 Business Process Change Management Total Dir Labor 125,515 27,046 64,956 33,514 58 22721 Corp Strategic Risk Total Dir Labor 23,534 5,071 12,179 6,284 59 22725 OSHA procedures Total Dir Labor 15,689 3,381 8,119 4,189 60 22727 ERM Business Analysis Total Dir Labor 62,758 13,523 32,478 16,757 61 23003 Safety / Security / Facilities Total Dir Labor 78,447 16,904 40,597 20,946 62 23006 Business Continuity Planning Total Dir Labor 47,068 10,142 24,358 12,568 63 25006 Business Process Maintenance Alloc-Fixed 19,625 8,831 8,831 1,963 64 25011 Corrective Action/Preventive Action Alloc-Fixed 179,175 59,665 59,665 59,845 65 25014 EtQ Tools Dev & Support Total Dir Labor 106,530 22,955 55,131 28,444 66 25015 Coord Tariff Change Committee (TCC) Total Dir Labor 54,117 11,661 28,006 14,450 67 25017 Scorecard Operational Excellence Excercise -- I.3.9 Process Total Dir Labor 31,379 6,762 16,239 8,378 68 Total 1,548,371 409,579 695,906 442,885
(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. ER16-___-000 Schedule 3.0 TOTAL COST ALLOCATIONS TO SCHEDULES BY COST CATEGORY Page 2 of 7 TEST YEAR 2016
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 21,821 4,702 11,292 5,826 3 12701 Recruiting/Interviewing Total Dir Labor 553,457 119,259 286,420 147,778 4 12801 Employee Relations Total Dir Labor 8,943 1,927 4,628 2,388 5 12901 Benefit Administration Total Dir Labor 1,139,839 245,613 589,879 304,347 6 12951 Compensation Total Dir Labor 501,581 108,081 259,574 133,927 7 12961 HR - General Total Dir Labor 1,124,146 242,231 581,758 300,157 8 12962 HR - Training Total Dir Labor 1,049,652 226,179 543,206 280,266 9 13410 Power Training & Development Total Dir Labor 1,176,010 253,407 608,598 314,005 10 13411 Markets Training & Development Total Dir Labor 375,057 80,817 194,096 100,144 11 13412 People Training & Development Total Dir Labor 580,066 124,993 300,191 154,883 12 13413 Business Skills Trng & Dev Total Dir Labor 167,452 36,083 86,658 44,711 13 13414 Technology Trng & Development Total Dir Labor 812,849 175,153 420,658 217,038 14 Total 7,510,873 1,618,445 3,886,959 2,005,469 15 16 306 Legal Department 17 8301 Federal Regulatory Total Dir Labor 265,674 57,247 137,489 70,937 18 12426 Interconnection Agreements Alloc-Fixed 29,038 - 14,519 14,519 19 12502 Board of Directors Total Dir Labor 448,228 96,584 231,963 119,681 20 12504 ISO Tariff Litigation Total Dir Labor 72,595 15,643 37,569 19,384 21 12505 Administration of OATT (Open Access Transmission Tariff) Alloc-Fixed 339,894 339,894 - - 22 12508 Energy Markets / Complaints / Rule Changes Alloc-Fixed 58,076 - 58,076 - 23 12509 Market Monitoring and Sanctions Alloc-Fixed 87,114 - 43,557 43,557 24 12512 BSAI - General Corporate Total Dir Labor 80,002 17,239 41,402 21,361 25 12513 Miscellaneous Labor Matters Total Dir Labor 120,003 25,858 62,103 32,042 26 12514 NEPOOL Participants Committee Total Dir Labor 100,674 21,693 52,100 26,881 27 12517 Administrative and Clerical Support Total Dir Labor 450,091 96,986 232,927 120,178 28 12520 Market Monitoring Rules/Regulations Alloc-Fixed 290,381 - 116,152 174,229 29 12521 Billing Disputes Total Dir Labor 126,291 27,213 65,357 33,721 30 12523 NEPOOL Information Policy Total Dir Labor 36,298 7,821 18,784 9,692 31 12542 Transmission Upgrades CT Alloc-Fixed 29,992 - 20,994 8,998 32 12543 Independent Market Advisor Alloc-Fixed 900,000 - 630,000 270,000 33 12544 FERC Proceedings Total Dir Labor 209,877 45,224 108,614 56,039 34 12552 S&G - General Corporate Total Dir Labor 234,992 50,636 121,611 62,745 35 12559 General Corporate Total Dir Labor 901,039 194,156 466,298 240,585 36 12563 Regulatory Matters Total Dir Labor 49,992 10,772 25,872 13,348 37 12572 205 General Proceedings Total Dir Labor 29,992 6,463 15,521 8,008 38 12573 206 General Proceedings Total Dir Labor 29,992 6,463 15,521 8,008 39 12574 Market Rule 1 Proceedings Total Dir Labor 479,994 103,429 248,402 128,163 40 12587 Capacity Market Development Alloc-Fixed 509,797 - - 509,797 41 12588 Web Content Management Total Dir Labor 571,803 123,212 295,914 152,676 42 12594 Maine Transmission Siting Alloc-Fixed 35,005 - 24,504 10,502 43 12595 NEEWS Transmission Siting Alloc-Fixed 1,370 - 959 411 44 12609 FTR Clearing Alloc-Fixed 60,002 - 30,001 30,001 45 12663 Public Information Total Dir Labor 1,393,147 300,196 720,969 371,983 46 12669 Government Affairs Total Dir Labor 1,719,920 370,609 890,078 459,234 47 Total 9,661,273 1,917,340 4,727,255 3,016,678 48 49 305 Internal Audit 50 15001 Indirect Management Duties Total Dir Labor 126,067 27,165 65,241 33,661 51 15002 Personnel Management Total Dir Labor 19,659 4,236 10,174 5,249 52 15003 Budget & Forecasting Total Dir Labor 14,744 3,177 7,630 3,937 53 15004 Audit Follow-up Activities Total Dir Labor 68,805 14,826 35,607 18,371 54 15005 Audit & Finance Committee Total Dir Labor 62,564 13,481 32,378 16,705 55 15006 Internal Audit Business Process Update Total Dir Labor 5,898 1,271 3,052 1,575 56 15007 Annual Audit Work Plan Total Dir Labor 34,402 7,413 17,804 9,186 57 15008 Training Total Dir Labor 39,317 8,472 20,347 10,498 58 15020 Internal Audit - Finance Total Dir Labor 26,688 5,751 13,811 7,126 59 15021 Perfomance Measurements Total Dir Labor 24,573 5,295 12,717 6,561 60 15022 Vendor Contracts Total Dir Labor 9,829 2,118 5,087 2,624 61 15023 Wire Transfers Total Dir Labor 11,795 2,542 6,104 3,149 62 15031 Employee Expense Reporting Total Dir Labor 11,795 2,542 6,104 3,149 63 15040 Operations Total Dir Labor 98,293 21,180 50,868 26,245 64 15065 Wind Integration Project Alloc-Fixed 49,146 19,659 19,659 9,829 65 15085 Information Technology Total Dir Labor 336,697 72,552 174,245 89,901 66 15131 NAMS Support Total Dir Labor 4,915 1,059 2,543 1,312 67 15133 Satellite Reviews Total Dir Labor 70,704 15,235 36,590 18,879 68 15134 SCADA Operations Reviews Total Dir Labor 72,422 15,605 37,479 19,337 69 15161 External Audit- Pension Audit Total Dir Labor 62,251 13,414 32,215 16,621 70 15162 External Audit- Financial Audit Total Dir Labor 110,352 23,779 57,108 29,465 71 15166 External Audit -Pricing Module Certification Alloc-Fixed 25,168 - 25,168 - 72 15175 External Audit - Info Technology Total Dir Labor 15,488 3,337 8,015 4,135 73 15186 External Audit - SSAE 16 Direct Support Total Dir Labor 24,573 5,295 12,717 6,561 74 25702 External Audit - SSAE 16 Alloc-Fixed 458,064 - 458,064 - 75 28160 MS Universal Access Gateway Review Total Dir Labor 42,906 9,245 22,204 11,456 76 Total 1,827,115 298,649 1,172,931 355,535
(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. ER16-___-000 Schedule 3.0 TOTAL COST ALLOCATIONS TO SCHEDULES BY COST CATEGORY Page 3 of 7 TEST YEAR 2016
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 NEPOOL Committee Support Total OPS Labor 57,751 15,478 27,693 14,579 3 19002 Regional Committee Support Total OPS Labor 31,400 8,416 15,057 7,927 4 19003 National Committee Support Total OPS Labor 57,656 15,453 27,648 14,555 5 19005 Indirect Supervision/Clerical Support Total OPS Labor 1,284,522 344,271 615,973 324,278 6 19009 Renewable Resource Integration Alloc-Fixed 114,197 - - 114,197 7 Total 1,545,526 383,618 686,372 475,537 8 9 10 105 System Operations - Administration 11 14404 NEPOOL Committee Support SOA Labor 12,256 4,233 5,689 2,334 12 14405 Indirect Supervision/Clerical Support SOA Labor 350,021 120,897 162,480 66,644 13 14407 Regional Committee Support SOA Labor 12,256 4,233 5,689 2,334 14 14408 National Committee Support SOA Labor 39,692 13,710 18,425 7,557 15 Total 414,226 143,074 192,284 78,869 16 17 101 Operations 18 14001 Generation Dispatch Alloc-Fixed 3,880,735 - 3,259,817 620,918 19 14002 Transmission Operations Alloc-Fixed 3,326,344 2,661,075 166,317 498,952 20 14304 Advanced Scheduling and Forecasting Alloc-Fixed 1,669,702 83,485 1,319,065 267,152 21 14402 Operations Training Alloc-Fixed 1,139,161 455,665 455,665 227,832 22 14413 Operations Support Training & Development Alloc-Fixed 269,900 107,960 107,960 53,980 23 14564 Indirect Supervision/Clerical Support OPS Labor 1,387,703 387,955 768,284 231,464 24 14702 Procedure Documentation Alloc-Fixed 536,178 214,471 214,471 107,236 25 Total 12,209,722 3,910,611 6,291,578 2,007,533 26 27 702 Reliability and Operations Services 28 14703 NEPOOL Committee Support OS Labor 440,571 244,723 85,173 110,675 29 14706 Indirect Supervision/Clerical Support OS Labor 21,933 12,183 4,240 5,510 30 14711 ISO TMS Tariff - Section 2 - (OATT) and Agreements Support Alloc-Fixed 207,354 69,049 69,049 69,256 31 14715 Non DOE Funded/Unallowable Alloc-Fixed 216,552 - - 216,552 32 14813 ICP Policy/Procedure Alloc-Fixed 98,411 39,364 39,364 19,682 33 Total 984,821 365,320 197,826 421,675 34 35 703 Reliability and Operations Compliance 36 14801 Compliance Monitoring Alloc-Fixed 659,625 263,850 263,850 131,925 37 14803 Regional Committee Support OS Labor 18,140 9,070 - 9,070 38 14804 National Committee Support OS Labor 146,408 73,204 - 73,204 39 14806 Employee Development Alloc-Fixed 9,841 5,466 1,903 2,472 40 14808 Change Management Alloc-Fixed 49,205 22,142 4,921 22,142 41 14809 Tariff Compliance Alloc-Fixed 49,205 14,762 29,523 4,921 42 14810 NERC Self Certifications Alloc-Fixed 98,411 83,649 - 14,762 43 14812 NPCC MP Referral Alloc-Fixed 19,682 7,873 7,873 3,936 44 14814 Compliance Risk Assessment Total Dir Labor 19,682 4,242 10,186 5,255 45 14815 Identifications and Description of Internal Controls Total Dir Labor 196,822 42,415 101,855 52,551 46 Total 1,267,021 526,673 420,110 320,239 47 48 103 Operations Support Services 49 14301 Contract Administration and Scheduling Alloc-Fixed (60,000) (6,000) (42,000) (12,000) 50 14452 Regional Committee Support TSO Labor 9,665 3,129 4,621 1,915 51 14453 National Committee Support TSO Labor 127,286 41,208 60,853 25,224 52 14454 Indirect Supervision/Clerical Support TSO Labor 493,763 159,852 236,061 97,850 53 14462 General Systems Operations Support TSO Labor 134,044 43,396 64,085 26,564 54 14476 Process Automation for On-Call Support of Control Room Alloc-Fixed 270,626 270,626 - - 55 18361 Transmission Studies, Operations, OASIS Support Alloc-Fixed 2,400,403 1,920,323 120,020 360,060 56 18381 Transmission Outage Appl - Short Term Alloc-Fixed 1,082,505 866,004 54,125 162,376 57 18382 Trans Out Ap Lg Term Alloc-Fixed 1,089,030 - - 1,089,030 58 Total 5,547,323 3,298,538 497,765 1,751,020 59 60 System Operations Support 61 14469 C10/C30 Audits Alloc-Fixed 134,044 - 107,236 26,809 62 14470 Resource Performance Monitoring Alloc-Fixed 134,044 - 107,236 26,809 63 14750 NEPOOL Committee Support Alloc-Fixed 134,044 43,396 64,085 26,564 64 14751 Regional Committee Support Alloc-Fixed 12,560 4,066 6,005 2,489 65 14753 Indirect Supervision/Clerical Support Alloc-Fixed 134,044 43,396 64,085 26,564 66 14757 Winter Reliability Project Alloc-Fixed 224,962 - 44,992 179,969 67 Total 773,699 90,858 393,637 289,204 68 69 415 Market Operations - Adm 70 19101 NEPOOL Committee Support MOA Labor 33,475 - 23,433 10,043 71 19103 National Committee Support MOA Labor 14,021 - 9,815 4,206 72 19104 Indirect Supervision/Clerical Support MOA Labor 937,732 - 656,412 281,319 73 19105 Employee Development MOA Labor 6,471 - 4,530 1,941 74 19112 Settlements - Customer Service MOA Labor 18,003 - 12,602 5,401 75 19120 CEII Requests Total Dir Labor 25,885 5,578 13,396 6,911 76 Total 1,035,587 5,578 720,187 309,822
(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. ER16-___-000 Schedule 3.0 TOTAL COST ALLOCATIONS TO SCHEDULES BY COST CATEGORY Page 4 of 7 TEST YEAR 2016
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 3,591,744 - 2,514,220 1,077,523 3 16102 Regulatory Activities Alloc-Fixed 365,402 - 255,781 109,621 4 16111 Employee Development MMM Labor 254,824 - 178,377 76,447 5 16114 Maintenance / Troubleshooting Software MMM Labor 761 - 533 228 6 16115 Analysis & Internal Reports MMM Labor 232,458 - 162,720 69,737 7 16121 FCM Market Monitoring Alloc-Fixed 219,822 - - 219,822 8 Total 4,665,011 - 3,111,632 1,553,379 9 10 416 Market Operations 11 21901 Day Ahead Market Administration Alloc-Fixed 345,499 - 345,499 - 12 21902 Real Time Price Verification Alloc-Fixed 345,499 - 345,499 - 13 21904 NEPOOL Committee Support MA Labor 4,551 - 4,407 144 14 21907 Indirect Supervision/Clerical Support MA Labor 456,984 - 442,553 14,431 15 21908 Employee Development MA Labor 33,707 - 32,643 1,064 16 21913 Data Collection/Report Writing Alloc-Fixed 337,072 - 337,072 - 17 21915 FTR/Auction Administration Alloc-Fixed 303,365 - 303,365 - 18 21916 Forward Reserve Market - Administration Alloc-Fixed 33,707 - - 33,707 19 21917 Real Time Price Finalization Alloc-Fixed 176,963 - 176,963 - 20 21951 FCM Annual Reconfiguration Auction Administration Alloc-Fixed 33,707 - - 33,707 21 21953 FCM Monthly Administration Alloc-Fixed 176,963 - - 176,963 22 Total 2,248,016 - 1,988,000 260,016 23 24 401 Market Anaylsis & Settlements 25 1701 Billing Statements - Energy Alloc-Fixed 87,109 - 87,109 - 26 1702 Billing Statements - Transmission Alloc-Fixed 72,682 72,682 - - 27 1713 Billing Statements - ISO Tariff Total Dir Labor 23,955 5,162 12,397 6,396 28 1714 Billable Tariff Re-billings Alloc-Fixed 72,410 72,410 - - 29 2039 BITT and Business Tools Alloc-Fixed 2,178 327 1,307 544 30 2047 Score Card Alloc-Fixed 10,616 1,570 5,171 3,875 31 2048 FCM Alloc-Fixed 211,240 - - 211,240 32 2049 Product Testing Alloc-Fixed 21,777 - 17,422 4,355 33 2051 Legal Support Alloc-Fixed 23,138 - 11,569 11,569 34 2052 FERC Data Request Alloc-Fixed 544 - 272 272 35 2054 MAS - Markets Development Support Alloc-Fixed 2,994 - 1,497 1,497 36 2005 Customer Service STLM Labor 119,775 17,712 58,347 43,716 37 2007 Admin support - NEPOOL Committees STLM Labor 16,877 2,496 8,222 6,160 38 2008 Admin support (ISO) STLM Labor 77,966 11,530 37,980 28,456 39 2009 Indirect Supervision/Clerical Support STLM Labor 790,516 116,902 385,090 288,525 40 2010 Employee Development STLM Labor 107,798 15,941 52,512 39,344 41 2013 FTR Administration Alloc-Fixed 24,772 - 24,772 - 42 2014 Billing Statements - NCPC Alloc-Fixed 258,878 - 129,439 129,439 43 2020 Billing Disputes Total Dir Labor 12,522 2,698 6,480 3,343 44 2021 Analysis & Reporting Total Dir Labor 241,728 52,088 125,097 64,544 45 2022 Demand Response Alloc-Fixed 7,078 - - 7,078 46 2024 ASM Regulation Alloc-Fixed 31,577 - - 31,577 47 2025 ASM Locational Forward Reserve Alloc-Fixed 111,881 - - 111,881 48 2026 Batch Processing Total Dir Labor 32,122 6,922 16,623 8,577 49 2030 ARR Administration Alloc-Fixed 2,450 - 2,205 245 50 2032 Billing STLM Labor 59,888 8,856 29,173 21,858 51 2033 Market Analysis Alloc-Fixed 184,563 - 184,563 - 52 Total 2,609,034 387,294 1,197,248 1,024,492 53 54 Market Operations Support Services 55 3000 Hourly Settlements Support Alloc-Fixed 263,183 - 131,592 131,592 56 3002 Monthly Settlements Support Alloc-Fixed 108,370 54,185 - 54,185 57 3003 Market Analysis Support Alloc-Fixed 774 - 774 - 58 3004 Generation & Load Admin Support Alloc-Fixed 193,982 - 193,982 - 59 3005 Demand Resource Admin Support Alloc-Fixed 97,533 - 97,533 - 60 3006 Customer Service Alloc-Fixed 154,814 - 154,814 - 61 3007 NEPOOL Committees Support Alloc-Fixed 2,632 - 1,316 1,316 62 3008 Admin Support Alloc-Fixed 57,281 - 57,281 - 63 3009 Indirect Supervision (Principal Analysts only) Alloc-Fixed 86,696 - 86,696 - 64 3010 Employee Development Alloc-Fixed 15,791 - 15,791 - 65 3011 Release Checkout and Support Alloc-Fixed 1,858 - 1,858 - 66 3012 FERC Data Request Alloc-Fixed 44,896 - 44,896 - 67 3013 Tariff Change Coordination (TCC) Total Dir Labor 155 33 80 41 68 3014 Markets Development Support Alloc-Fixed 10,063 - 5,031 5,031 69 3015 Market Administration Support Alloc-Fixed 1,084 - 1,084 - 70 Total 1,039,110 54,218 792,726 192,165
(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. ER16-___-000 Schedule 3.0 TOTAL COST ALLOCATIONS TO SCHEDULES BY COST CATEGORY Page 5 of 7 TEST YEAR 2016
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 65,096 - 32,548 32,548 3 16006 Call Support (Ask ISO) Alloc-Fixed 853,752 221,976 563,477 68,300 4 16404 NEPOOL Committee Support MS Labor 86,134 - 77,521 8,613 5 16414 Direct Customer Contact MS Labor 159,795 - 143,815 15,979 6 16419 Asset Registration Implemented Alloc-Fixed 244,377 - 244,377 - 7 16420 Asset Registration Review Alloc-Fixed 210,670 - 210,670 - 8 16422 Claimed Capability Audits Alloc-Fixed 33,707 - 33,707 - 9 16424 Demand Resource Audits Alloc-Fixed 185,390 - 185,390 - 10 16425 DR Registration Implemented Alloc-Fixed 33,707 - 33,707 - 11 16429 Business Analysis - Process Improvement Alloc-Fixed 155 - 139 15 12 16434 QMS/CAPA Process and Procedure Updates Total Dir Labor 252,804 54,479 130,826 67,499 13 16435 Resource Performance Monitoring Alloc-Fixed 33,707 - 33,707 - 14 Total 2,159,294 276,455 1,689,884 192,955 15 16 410 Market Training and Reliability Contracts 17 16021 Training Development Alloc-Fixed 858,368 - 429,184 429,184 18 16024 Training Delivery Alloc-Fixed 8,166 - 4,083 4,083 19 16433 Passive Resource Performance and M&V Review Alloc-Fixed 33,707 - 33,707 - 20 Total 900,242 - 466,975 433,267 21 22 203 Resource Adequacy 23 14313 National Committee Support PSR Labor 41,007 4,456 2,069 34,482 24 14315 Employee Development PSR Labor 139,271 15,133 7,028 117,110 25 17101 Analysis Alloc-Fixed 709,940 - 496,958 212,982 26 17131 Calculate Objective Capability Alloc-Fixed 317,359 - - 317,359 27 17231 Regulatory Filings Alloc-Fixed 33,807 - - 33,807 28 17241 Transmission Plan Admin Support Alloc-Fixed 33,807 16,903 16,903 - 29 17251 Regional Bulk Power System Assessment Alloc-Fixed 304,260 152,130 152,130 - 30 17331 NEPOOL Committee Support PSR Labor 105,953 11,513 5,347 89,094 31 17361 Regional Committee Support PSR Labor 35,140 3,818 1,773 29,548 32 17401 Indirect Supervisory Activities PSR Labor 169,953 18,467 8,577 142,909 33 17402 Project Management Alloc-Fixed 236,647 236,647 - - 34 17403 TCA Application Review Alloc-Fixed 70,857 - - 70,857 35 17405 Energy Efficiency Forecast Alloc-Fixed 67,613 - - 67,613 36 17406 North American Energy Standards Board (NAESB) Alloc-Fixed 36,873 - 18,437 18,437 37 17408 MA-EEAC Total Dir Labor 36,873 7,946 19,082 9,845 38 17501 FCA - Evaluate Existing Resource De-list Bids Alloc-Fixed 73,097 - - 73,097 39 17502 FCA - Preliminary Review of Show of Interest Applications Alloc-Fixed 140,710 - - 140,710 40 17503 FCA - New Resource Qualification Support Alloc-Fixed 295,797 - - 295,797 41 17504 FCA - Perform Transmission / Topology Assessments Alloc-Fixed 101,420 - - 101,420 42 17505 FCA - Perform Existing Resource Qualification Alloc-Fixed 208,323 - - 208,323 43 17507 FCA - Auctions & Filings Alloc-Fixed 809,626 - - 809,626 44 17508 FCA - Annual Reconfiguration Auction Support/Reliability Reviews Alloc-Fixed 73,097 - - 73,097 45 18101 Develop Load Forecast Alloc-Fixed 315,198 63,040 63,040 189,119 46 18121 Operations Forecast Support Alloc-Fixed 67,613 13,523 13,523 40,568 47 18131 Other Load Forecasting Activities Alloc-Fixed 33,807 6,761 6,761 20,284 48 Total 4,458,046 550,337 811,628 3,096,081 49 50 204 System Planning 51 18150 Regional Transmission Expansion Plan Alloc-Fixed 887,395 665,546 221,849 - 52 18152 States Requests Alloc-Fixed 149,323 74,661 37,331 37,331 53 18401 Regional Activities Alloc-Fixed 11,245 11,245 - - 54 18501 Regulatory Activities Alloc-Fixed 17,158 17,158 - - 55 18521 Employee Development SP Labor 2,024 502 359 1,163 56 18531 Indirect Supervision/Clerical Support SP Labor 161,485 40,091 28,629 92,765 57 Total 1,228,630 809,204 288,168 131,258 58 59 205 Transmission Planning 60 11201 System Design Task Force Alloc-Fixed 3,524 3,524 - - 61 18201 Transmission System Assessment Alloc-Fixed 3,469,289 3,469,289 - - 62 18261 Transmission Tariff Information Requirements Alloc-Fixed 9,758 9,758 - - 63 18301 NEPOOL Administrative Support - Schedule 1 Tariff Alloc-Fixed 76,625 76,625 - - 64 18331 SIS Preparatory Arrangements Alloc-Fixed 3,524 3,524 - - 65 18333 General SIS/FS Alloc-Fixed 655,879 655,879 - - 66 18334 Indirect Supervision/Clerical Support TP Labor 366,454 366,454 - - 67 18335 Regulatory Activities - NPCC TP Labor 99,979 99,979 - - 68 18336 National Activities TP Labor 78,398 78,398 - - 69 18337 Regulatory Activities TP Labor 109,597 109,597 - - 70 18338 Employee Development TP Labor 116,462 116,462 - - 71 18341 NERC Compliance TP Labor 11,717 11,717 - - 72 18343 FERC Order 1000 Alloc-Fixed 319,257 - - 319,257 73 18344 Transmission Planning Siting Support Alloc-Fixed 6,233 - - 6,233 74 Total 5,326,697 5,001,206 - 325,490
(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. ER16-___-000 Schedule 3.0 TOTAL COST ALLOCATIONS TO SCHEDULES BY COST CATEGORY Page 6 of 7 TEST YEAR 2016
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 824,303 177,621 426,586 220,096 3 1661 ISO Program Management Alloc-Fixed 342,618 - 239,833 102,785 4 25002 PMO Support Alloc-Fixed 16,548 4,964 5,792 5,792 5 25902 Coordinated Transaction Scheduling - O&M Alloc-Fixed 116,869 81,808 35,061 - 6 25914 Divisional Accounting (for Market Participants) Total Dir Labor 66,825 14,400 34,583 17,843 7 25919 Alternative Technologies & Regulation Market Alloc-Fixed 39,711 - - 39,711 8 25926 Hourly Market Alloc-Fixed 154,814 61,925 46,444 46,444 9 25938 Asset Registration Automation Total Dir Labor 16,720 3,603 8,653 4,464 10 25940 Non-Reimburseable Smart Grid SIDU Observation Period Alloc-Fixed 90,029 13,504 13,504 63,021 11 25943 Submission of FTRs for Clearing Alloc-Fixed 33,856 - - 33,856 12 25953 ICCP and ED Network Upgrades Alloc-Fixed 95,782 86,204 - 9,578 13 Total 1,798,076 444,030 810,455 543,591 14 15 315 Business Architecture and Technology 16 21201 Business Architecture and Technology Total Dir Labor 2,246,284 484,030 1,162,477 599,778 17 21203 Employee Development Total Dir Labor 49,100 10,580 25,410 13,110 18 Total 2,295,384 494,610 1,187,887 612,888 19 20 408 Market Development 21 21001 Market Development Total Dir Labor 2,128,297 458,606 1,101,417 568,274 22 21002 Administration Total Dir Labor 183,849 39,616 95,144 49,089 23 21003 Employee Development Total Dir Labor 13,780 2,969 7,131 3,679 24 21007 Budget/Forecast Support Total Dir Labor 61,283 13,205 31,715 16,363 25 21009 Increased Scope of Impact Analysis Alloc-Fixed 99,999 26,000 65,999 8,000 26 22656 Energy, Reserve, and Regulation Markets Alloc-Fixed 765,429 - 574,072 191,357 27 Total 3,252,636 540,396 1,875,478 836,763 28 29 407 Markets Committee Relations & Rule Integration 30 22602 NEPOOL Committee Meetings & Support Alloc-Fixed 619,376 - 309,688 309,688 31 22607 NEPOOL Markets Committee Administration Total Dir Labor 121,485 26,178 62,870 32,438 32 Total 740,862 26,178 372,558 342,126 33 34 409 Demand Resource Strategy 35 22401 Administration Total Dir Labor 87,011 18,749 45,029 23,233 36 22402 Working Group Meetings and Support Total Dir Labor 21,899 4,719 11,333 5,847 37 22404 Price Responsive Demand Alloc-Fixed 179,796 - 143,837 35,959 38 Total 288,706 23,468 200,199 65,039 39 40 210 IT Management 41 6517 Employee Development - Hardware/Software Total Dir Labor 95,555 20,590 49,451 25,514 42 6519 Indirect Supervision and Clerical Support Total Dir Labor 3,118,865 672,054 1,614,047 832,764 43 6552 Security Total Dir Labor 405,253 87,324 209,723 108,206 44 6556 Budget Preparation, Tracking & Forecast Total Dir Labor 145,731 31,402 75,417 38,911 45 6557 Information Technology Committee Total Dir Labor 18,277 3,938 9,459 4,880 46 22501 Change Management Support Alloc-Fixed 187,538 84,392 84,392 18,754 47 22505 Administrative Alloc-Fixed 352,172 119,738 116,217 116,217 48 Total 4,323,391 1,019,439 2,158,705 1,145,247 49 50 201 IT System/Network & Desktop 51 6510 Desktop Support - Hardware Total Dir Labor 399,247 86,030 206,615 106,602 52 6511 Desktop Support - Software Total Dir Labor 796,785 171,691 412,345 212,749 53 6512 Host Computer - Hardware Alloc-Fixed 1,146,315 - 859,736 286,579 54 6513 Host Computer - Software Alloc-Fixed 1,763,842 - 1,322,882 440,961 55 6514 Networking - Hardware Total Dir Labor 816,849 176,015 422,728 218,106 56 6516 Communications Total Dir Labor 1,678,847 361,758 868,822 448,267 57 6550 Data Communications Support Total Dir Labor 270,398 58,265 139,934 72,199 58 6602 Help Desk Support Total Dir Labor 335,290 72,248 173,516 89,525 59 6615 Host Computer Monitoring Alloc-Fixed 1,254,513 - 627,257 627,257 60 6616 Desktop Support Total Dir Labor 499,800 107,697 258,652 133,451 61 6617 System Administration - Unix Total Dir Labor 678,400 146,182 351,079 181,139 62 6618 System Administration - Windows Total Dir Labor 838,710 180,725 434,042 223,943 63 6619 Systems Support Misc Total Dir Labor 85,170 18,352 44,076 22,741 64 6620 Systems Support - Security Total Dir Labor 245,577 52,917 127,089 65,571 65 6621 Network Support Total Dir Labor 415,081 89,442 214,809 110,830 66 6622 Network/Systems Compliance Total Dir Labor 11,019 2,374 5,703 2,942 67 6623 Asset Management Total Dir Labor 421,020 90,721 217,882 112,416 68 Total 11,656,862 1,614,419 6,687,166 3,355,277
(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. ER16-___-000 Schedule 3.0 TOTAL COST ALLOCATIONS TO SCHEDULES BY COST CATEGORY Page 7 of 7 TEST YEAR 2016
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 Policy/Procedures Program Total Dir Labor 55,939 12,054 28,949 14,936 3 6540 Security Compliance and Reporting Total Dir Labor 2,169,684 467,524 1,122,835 579,325 4 6540A Controls Assessment Total Dir Labor 39,245 8,456 20,310 10,479 5 6540B Virus/Malware Reporting and Response Total Dir Labor 19,622 4,228 10,155 5,239 6 6540D Intrusion Monitoring and Response Total Dir Labor 98,111 21,141 50,774 26,197 7 6540E System Compliance Enhancement Total Dir Labor 156,978 33,826 81,238 41,915 8 6541 Security SW Tools Program Total Dir Labor 333,579 71,880 172,631 89,069 9 6543 Critical Infrastructure Protection WG (NERC) Total Dir Labor 6,677 1,439 3,455 1,783 10 6544 Infragrad (FBI) Total Dir Labor 97,632 21,038 50,526 26,069 11 6546 Internal Audit Support Total Dir Labor 19,622 4,228 10,155 5,239 12 6547 Security Training Total Dir Labor 19,622 4,228 10,155 5,239 13 6548 CIP Compliance & Monitoring Total Dir Labor 212,070 45,697 109,748 56,625 14 Total 3,228,782 695,739 1,670,930 862,113 15 16 211 IT Enterprise Applications Support 17 6571 DBA Support - MOPS Total Dir Labor 2,396,535 516,406 1,240,233 639,896 18 6591 Data Architect - MOPS Total Dir Labor 256,136 55,192 132,553 68,391 19 6594 IT Data Analyst Total Dir Labor 265,629 57,238 137,466 70,925 20 6595 IT WEB Application Support Total Dir Labor 722,943 155,780 374,131 193,032 21 6596 IT Data Governance Total Dir Labor 150,067 32,336 77,661 40,069 22 21706 IT Markets Software Development - Enterprise Total Dir Labor 439,846 94,778 227,625 117,443 23 21801 Software Support - Settlements Alloc-Fixed 554,480 - 443,584 110,896 24 21802 Software Support - Publishing Alloc-Fixed 258,139 - 206,512 51,628 25 21803 Software Support - Finance Alloc-Fixed 255,909 - 204,727 51,182 26 21804 Software Support - Mitigation Alloc-Fixed 451,110 - 360,888 90,222 27 21805 Software Support - TSO Total Dir Labor 352,451 75,946 182,397 94,107 28 21806 Software Support - Enterprise Total Dir Labor 1,001,874 215,884 518,481 267,509 29 21807 Software Support - Planning Alloc-Fixed 475,646 - 380,517 95,129 30 21808 Training Delivery to NON-IT Alloc-Fixed 330,952 - 264,762 66,190 31 21809 Tools Alloc-Fixed 144,875 - 115,900 28,975 32 21811 Single Sign On Support Alloc-Fixed 79,608 - 63,686 15,922 33 21816 CMS Support Total Dir Labor 212,483 45,786 109,962 56,735 34 21818 Discoverer Support Total Dir Labor 103,576 22,319 53,602 27,656 35 21819 Ceridian Support Total Dir Labor 79,608 17,154 41,198 21,256 36 21821 Compliance Management Total Dir Labor 53,072 11,436 27,465 14,171 37 Total 8,584,936 1,300,255 5,163,349 2,121,333 38 39 102 IT Energy Management Systems 40 21600 Indirect Supervision and Administration Total Dir Labor 361,281 77,849 186,967 96,465 41 21601 Power System Modeling Total Dir Labor 29,012 6,251 15,014 7,746 42 21603 Applications Support Total Dir Labor 607,099 130,818 314,180 162,101 43 21604 DTS Support Alloc-Fixed 1,544,494 1,235,595 308,899 - 44 21605 DAM Support Alloc-Fixed 1,000,980 200,196 600,588 200,196 45 21606 Real-time Market Support Alloc-Fixed 2,092,680 418,536 1,255,608 418,536 46 21607 Forecast Support Alloc-Fixed 101,360 20,272 60,816 20,272 47 Total 5,736,905 2,089,517 2,742,072 905,316 48 49 213 IT Enterprise Applications Development 50 6518 Employee Development - Software Total Dir Labor 18,375 3,960 9,509 4,906 51 21702 IT Corporate Application Support Alloc-Fixed 75,435 - 15,087 60,348 52 21707 Application Analysis and Conceptual Design Alloc-Fixed 1,074,003 - 859,202 214,801 53 21709 Technology Evaluation and Selection Alloc-Fixed 17,788 - 14,230 3,558 54 21710 Indirect Supervision and Administration Alloc-Fixed 531,681 - 425,344 106,336 55 21711 EWR and CAPA Analysis Alloc-Fixed 171,124 - 136,899 34,225 56 Total 1,888,404 3,960 1,460,272 424,173 57 58 216 IT Power System Modeling Management 59 21650 Indirect Supervision and Administration Total Dir Labor 111,703 24,072 57,806 29,825 60 21651 Power System Modeling Alloc-Fixed 861,609 344,643 344,643 172,322 61 21652 System Application Support Alloc-Fixed 176,841 70,737 70,737 35,368 62 21654 NX9 Administration Alloc-Fixed 481,016 192,406 192,406 96,203 63 21655 ICCP Support Alloc-Fixed 698,834 279,534 279,534 139,767 64 21656 Transmission Project Management Alloc-Fixed 23,590 18,872 4,718 - 65 21657 Model On Demand Admin Alloc-Fixed 340,984 - - 340,984 66 21658 Model on Demand Case Requests Alloc-Fixed 77,129 - - 77,129 67 Total 2,771,706 930,264 949,844 891,598 68 69 70 Total ISO $ 185,151,221 $ 44,360,392 $ 84,722,023 $ 56,068,806
(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. ER16-___-000 DIRECT LABOR COST ALLOCATIONS TO SCHEDULES BY COST CATEGORY TEST YEAR 2016
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 Indirect Administrative Support Total Dir Labor $ 3,038,347 $ 654,704 $ 1,572,378 $ 811,265 3 Total 3,038,347 654,704 1,572,378 811,265 4 5 302 Finance 6 11601 Payroll Administration Total Dir Labor 225,939 48,685 116,926 60,328 7 11701 Accounts Payable Total Dir Labor 199,569 43,003 103,279 53,287 8 11702 Procurement Total Dir Labor 479,629 103,351 248,213 128,065 9 11901 Billing for Transmission and Energy Settlements Total Dir Labor 68,142 14,683 35,264 18,195 10 12001 Budgeting and Forecasting Total Dir Labor 498,264 107,366 257,857 133,041 11 12005 Credit Admininstration Total Dir Labor 189,500 40,834 98,068 50,598 12 12017 Forward Capacity Market (FCM) Reforms Alloc-Fixed 810,821 - - 810,821 13 12101 Ledger Closing, Financial Statements and Tax Reporting Total Dir Labor 589,983 127,130 305,323 157,531 14 12201 Treasury and Cash Management Total Dir Labor 135,994 29,304 70,378 36,312 15 99998 Payroll & Other Accruals Total Dir Labor 10,864,472 2,341,079 5,622,484 2,900,909 16 Total 14,062,314 2,855,435 6,857,793 4,349,086 17 18 108 Building Services 19 12664 Building Maintenance Total Dir Labor 585,812 126,231 303,164 156,417 20 Total 585,812 126,231 303,164 156,417 21 22 310 Enterprise Risk Management 23 22703 Bus Cont Pl Prog Admin & Support Alloc-Fixed 141,205 47,021 47,021 47,162 24 22704 Record Retention Services Alloc-Fixed 62,758 20,898 20,898 20,961 25 22705 Corporate Scorecard Alloc-Fixed 31,379 10,449 10,449 10,481 26 22706 Document Management Services Alloc-Fixed 109,826 43,930 32,948 32,948 27 22708 Adminstration Total Dir Labor 15,689 3,381 8,119 4,189 28 22709 Management Total Dir Labor 94,137 20,285 48,717 25,135 29 22710 Employee Development Total Dir Labor 15,689 3,381 8,119 4,189 30 22711 Forward Capacity Market (FCM) Cap Adjustments Total Dir Labor 15,689 3,381 8,119 4,189 31 22712 Risk Policy Assessments Total Dir Labor 15,689 3,381 8,119 4,189 32 22713 MEC/Financials Total Dir Labor 31,379 6,762 16,239 8,378 33 22714 Analysis Total Dir Labor 125,515 27,046 64,956 33,514 34 22716 Financial Assurance Management (FAM) Rebuild Total Dir Labor 109,826 23,665 56,836 29,325 35 22720 Business Process Change Management Total Dir Labor 125,515 27,046 64,956 33,514 36 22721 Corp Strategic Risk Total Dir Labor 23,534 5,071 12,179 6,284 37 22725 OSHA procedures Total Dir Labor 15,689 3,381 8,119 4,189 38 22727 ERM Business Analysis Total Dir Labor 62,758 13,523 32,478 16,757 39 23003 Safety / Security / Facilities Total Dir Labor 78,447 16,904 40,597 20,946 40 23006 Business Continuity Planning Total Dir Labor 47,068 10,142 24,358 12,568 41 25006 Business Process Maintenance Alloc-Fixed 19,625 8,831 8,831 1,963 42 25011 Corrective Action/Preventive Action Alloc-Fixed 179,175 59,665 59,665 59,845 43 25014 EtQ Tools Dev & Support Total Dir Labor 78,447 16,904 40,597 20,946 44 25015 Coord Tariff Change Committee (TCC) Total Dir Labor 54,117 11,661 28,006 14,450 45 25017 Scorecard Operational Excellence Excercise -- I.3.9 Process Total Dir Labor 31,379 6,762 16,239 8,378 46 Total 1,484,538 393,470 666,569 424,499 47 48 301 Human Resources 49 12661 Employee Affairs (Recreation Committee) Total Dir Labor 5,713 1,231 2,956 1,525 50 12701 Recruiting/Interviewing Total Dir Labor 181,609 39,133 93,985 48,491 51 12901 Benefit Administration Total Dir Labor 207,553 44,724 107,411 55,419 52 12951 Compensation Total Dir Labor 389,163 83,857 201,396 103,910 53 12961 HR - General Total Dir Labor 985,879 212,437 510,203 263,238 54 12962 HR - Training Total Dir Labor 778,326 167,714 402,792 207,820 55 13410 Power Training & Development Total Dir Labor 772,560 166,471 399,808 206,280 56 13411 Markets Training & Development Total Dir Labor 257,445 55,474 133,230 68,740 57 13412 People Training & Development Total Dir Labor 234,464 50,522 121,338 62,604 58 13413 Business Skills Trng & Dev Total Dir Labor 81,731 17,611 42,297 21,823 59 13414 Technology Trng & Development Total Dir Labor 389,357 83,899 201,496 103,962 60 Total 4,283,799 923,074 2,216,913 1,143,812
(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. ER16-___-000 DIRECT LABOR COST ALLOCATIONS TO SCHEDULES BY COST CATEGORY TEST YEAR 2016
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 Federal Regulatory Total Dir Labor 246,824 53,186 127,734 65,904 3 12426 Interconnection Agreements Alloc-Fixed 29,038 - 14,519 14,519 4 12502 Board of Directors Total Dir Labor 145,191 31,286 75,138 38,767 5 12504 ISO Tariff Litigation Total Dir Labor 72,595 15,643 37,569 19,384 6 12505 Administration of OATT (Open Access Transmission Tariff) Alloc-Fixed 159,710 159,710 - - 7 12508 Energy Markets / Complaints / Rule Changes Alloc-Fixed 58,076 - 58,076 - 8 12509 Market Monitoring and Sanctions Alloc-Fixed 87,114 - 43,557 43,557 9 12514 NEPOOL Participants Committee Total Dir Labor 87,114 18,771 45,083 23,260 10 12517 Administrative and Clerical Support Total Dir Labor 450,091 96,986 232,927 120,178 11 12520 Market Monitoring Rules/Regulations Alloc-Fixed 290,381 - 116,152 174,229 12 12521 Billing Disputes Total Dir Labor 36,298 7,821 18,784 9,692 13 12523 NEPOOL Information Policy Total Dir Labor 36,298 7,821 18,784 9,692 14 12544 FERC Proceedings Total Dir Labor 203,267 43,800 105,193 54,274 15 12559 General Corporate Total Dir Labor 834,939 179,913 432,090 222,936 16 12587 Capacity Market Development Alloc-Fixed 508,167 - - 508,167 17 12588 Web Content Management Total Dir Labor 512,409 110,414 265,177 136,818 18 12663 Public Information Total Dir Labor 1,123,240 242,036 581,289 299,915 19 12669 Government Affairs Total Dir Labor 1,192,745 257,013 617,259 318,473 20 Total 6,073,496 1,224,400 2,789,332 2,059,765 21 22 305 Internal Audit 23 15001 Indirect Management Duties Total Dir Labor 120,214 25,904 62,212 32,098 24 15002 Personnel Management Total Dir Labor 19,659 4,236 10,174 5,249 25 15003 Budget & Forecasting Total Dir Labor 14,744 3,177 7,630 3,937 26 15004 Audit Follow-up Activities Total Dir Labor 68,805 14,826 35,607 18,371 27 15005 Audit & Finance Committee Total Dir Labor 62,564 13,481 32,378 16,705 28 15006 Internal Audit Business Process Update Total Dir Labor 5,898 1,271 3,052 1,575 29 15007 Annual Audit Work Plan Total Dir Labor 34,402 7,413 17,804 9,186 30 15008 Training Total Dir Labor 39,317 8,472 20,347 10,498 31 15021 Perfomance Measurements Total Dir Labor 24,573 5,295 12,717 6,561 32 15022 Vendor Contracts Total Dir Labor 9,829 2,118 5,087 2,624 33 15023 Wire Transfers Total Dir Labor 11,795 2,542 6,104 3,149 34 15031 Employee Expense Reporting Total Dir Labor 11,795 2,542 6,104 3,149 35 15065 Wind Integration Project Alloc-Fixed 49,146 19,659 19,659 9,829 36 15085 Information Technology Total Dir Labor 196,585 42,360 101,735 52,490 37 15040 Operations Total Dir Labor 98,293 21,180 50,868 26,245 38 15131 NAMS Support Total Dir Labor 4,915 1,059 2,543 1,312 39 15133 Satellite Reviews Total Dir Labor 68,805 14,826 35,607 18,371 40 15134 SCADA Operations Reviews Total Dir Labor 68,805 14,826 35,607 18,371 41 15161 External Audit- Pension Audit Total Dir Labor 19,659 4,236 10,174 5,249 42 15186 External Audit - SSAE 16 Direct Support Total Dir Labor 24,573 5,295 12,717 6,561 43 25702 External Audit - SSAE 16 Alloc-Fixed 118,164 - 118,164 - 44 28160 MS Universal Access Gateway Review Total Dir Labor 42,906 9,245 22,204 11,456 45 Total 1,115,445 223,963 628,493 262,990 46 47 701 COO-Adm 48 19001 NEPOOL Committee Support Total OPS Labor 56,741 15,207 27,209 14,324 49 19002 Regional Committee Support Total OPS Labor 28,370 7,604 13,605 7,162 50 19003 National Committee Support Total OPS Labor 28,370 7,604 13,605 7,162 51 19005 Indirect Supervision/Clerical Support Total OPS Labor 1,106,444 296,544 530,578 279,322 52 Total 1,219,926 326,958 584,997 307,970 53 54 702 Reliability and Operations Services 55 14703 NEPOOL Committee Support OS Labor 434,972 241,613 84,090 109,268 56 14706 Indirect Supervision/Clerical Support OS Labor 21,933 12,183 4,240 5,510 57 14711 ISO TMS Tariff - Section 2 - (OATT) and Agreements Support Alloc-Fixed 207,354 69,049 69,049 69,256 58 14715 Non DOE Funded/Unallowable Alloc-Fixed 161,608 - - 161,608 59 Total 825,867 322,845 157,380 345,642 60 61 703 Reliability and Operations Compliance 62 14801 Compliance Monitoring Alloc-Fixed 580,185 232,074 232,074 116,037 63 14804 National Committee Support OS Labor 136,288 68,144 - 68,144 64 14806 Employee Development Alloc-Fixed 9,841 5,466 1,903 2,472 65 14808 Change Management Alloc-Fixed 49,205 22,142 4,921 22,142 66 14809 Tariff Compliance Alloc-Fixed 49,205 14,762 29,523 4,921 67 14810 NERC Self Certifications Alloc-Fixed 98,411 83,649 - 14,762 68 14812 NPCC MP Referral Alloc-Fixed 19,682 7,873 7,873 3,936 69 14813 ICP Policy/Procedure Alloc-Fixed 98,411 39,364 39,364 19,682 70 14814 Compliance Risk Assessment Total Dir Labor 19,682 4,242 10,186 5,255 71 14815 Identifications and Description of Internal Controls Total Dir Labor 196,822 42,415 101,855 52,551 72 Total 1,257,732 520,131 427,698 309,903
(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. ER16-___-000 DIRECT LABOR COST ALLOCATIONS TO SCHEDULES BY COST CATEGORY TEST YEAR 2016
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 Indirect Supervision/Clerical Support SOA Labor 278,921 96,339 129,475 53,107 3 Total 278,921 96,339 129,475 53,107 4 5 101 Operations 6 14001 Generation Dispatch Alloc-Fixed 3,880,735 - 3,259,817 620,918 7 14002 Transmission Operations Alloc-Fixed 3,326,344 2,661,075 166,317 498,952 8 14304 Advanced Scheduling and Forecasting Alloc-Fixed 1,663,172 83,159 1,313,906 266,108 9 14402 Operations Training Alloc-Fixed 1,108,781 443,513 443,513 221,756 10 14564 Indirect Supervision/Clerical Support OPS Labor 1,387,703 387,955 768,284 231,464 11 14702 Procedure Documentation Alloc-Fixed 536,178 214,471 214,471 107,236 12 Total 11,902,912 3,790,172 6,166,308 1,946,433 13 14 103 Operations Support Services 15 14453 National Committee Support TSO Labor 111,569 36,120 53,339 22,110 16 14454 Indirect Supervision/Clerical Support TSO Labor 493,763 159,852 236,061 97,850 17 14462 General Systems Operations Support TSO Labor 134,044 43,396 64,085 26,564 18 14476 Process Automation for On-Call Support of Control Room Alloc-Fixed 270,626 270,626 - - 19 18361 Transmission Studies, Operations, OASIS Support Alloc-Fixed 2,388,147 1,910,518 119,407 358,222 20 18381 Transmission Outage Appl - Short Term Alloc-Fixed 1,082,505 866,004 54,125 162,376 21 18382 Trans Out Ap Lg Term Alloc-Fixed 1,082,505 - - 1,082,505 22 Total 5,563,160 3,286,516 527,018 1,749,626 23 24 System Operations Support 25 14469 C10/C30 Audits Alloc-Fixed 134,044 - 107,236 26,809 26 14470 Resource Performance Monitoring Alloc-Fixed 134,044 - 107,236 26,809 27 14750 NEPOOL Committee Support Alloc-Fixed 134,044 43,396 64,085 26,564 28 14753 Indirect Supervision/Clerical Support Alloc-Fixed 134,044 43,396 64,085 26,564 29 14757 Winter Reliability Project Alloc-Fixed 224,062 - 44,812 179,249 30 Total 760,239 86,792 387,453 285,995 31 32 415 Market Operations - Adm 33 19101 NEPOOL Committee Support MOA Labor 25,885 - 18,120 7,766 34 19104 Indirect Supervision/Clerical Support MOA Labor 935,112 - 654,579 280,534 35 19105 Employee Development MOA Labor 6,471 - 4,530 1,941 36 19112 Settlements - Customer Service MOA Labor 12,943 - 9,060 3,883 37 19120 CEII Requests Total Dir Labor 25,885 5,578 13,396 6,911 38 Total 1,006,297 5,578 699,684 301,035 39 40 404 Market Monitoring 41 16101 Market Power Monitoring and Mitigation Alloc-Fixed 2,599,467 - 1,819,627 779,840 42 16102 Regulatory Activities Alloc-Fixed 359,870 - 251,909 107,961 43 16111 Employee Development MMM Labor 254,824 - 178,377 76,447 44 16115 Analysis & Internal Reports MMM Labor 232,458 - 162,720 69,737 45 16121 FCM Market Monitoring Alloc-Fixed 197,442 - - 197,442 46 Total 3,644,061 - 2,412,633 1,231,428 47 48 416 Market Operations 49 21901 Day Ahead Market Administration Alloc-Fixed 345,499 - 345,499 - 50 21902 Real Time Price Verification Alloc-Fixed 345,499 - 345,499 - 51 21907 Indirect Supervision/Clerical Support MA Labor 455,046 - 440,676 14,370 52 21908 Employee Development MA Labor 33,707 - 32,643 1,064 53 21913 Data Collection/Report Writing Alloc-Fixed 337,072 - 337,072 - 54 21915 FTR/Auction Administration Alloc-Fixed 303,365 - 303,365 - 55 21916 Forward Reserve Market - Administration Alloc-Fixed 33,707 - - 33,707 56 21917 Real Time Price Finalization Alloc-Fixed 176,963 - 176,963 - 57 21951 FCM Annual Reconfiguration Auction Administration Alloc-Fixed 33,707 - - 33,707 58 21953 FCM Monthly Administration Alloc-Fixed 176,963 - - 176,963 59 Total 2,241,527 - 1,981,716 259,811
(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. ER16-___-000 DIRECT LABOR COST ALLOCATIONS TO SCHEDULES BY COST CATEGORY TEST YEAR 2016
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 87,109 - 87,109 - 3 1702 Billing Statements - Transmission Alloc-Fixed 72,682 72,682 - - 4 1713 Billing Statements - ISO Tariff Total Dir Labor 23,955 5,162 12,397 6,396 5 1714 Billable Tariff Re-billings Alloc-Fixed 72,410 72,410 - - 6 2005 Customer Service STLM Labor 119,775 17,712 58,347 43,716 7 2007 Admin support - NEPOOL Committees STLM Labor 16,877 2,496 8,222 6,160 8 2008 Admin support (ISO) STLM Labor 77,625 11,479 37,814 28,332 9 2009 Indirect Supervision/Clerical Support STLM Labor 790,516 116,902 385,090 288,525 10 2010 Employee Development STLM Labor 107,798 15,941 52,512 39,344 11 2013 FTR Administration Alloc-Fixed 24,772 - 24,772 - 12 2014 Billing Statements - NCPC Alloc-Fixed 258,878 - 129,439 129,439 13 2020 Billing Disputes Total Dir Labor 12,522 2,698 6,480 3,343 14 2021 Analysis & Reporting Total Dir Labor 241,728 52,088 125,097 64,544 15 2022 Demand Response Alloc-Fixed 7,078 - - 7,078 16 2024 ASM Regulation Alloc-Fixed 31,577 - - 31,577 17 2025 ASM Locational Forward Reserve Alloc-Fixed 111,881 - - 111,881 18 2026 Batch Processing Total Dir Labor 32,122 6,922 16,623 8,577 19 2030 ARR Administration Alloc-Fixed 2,450 - 2,205 245 20 2032 Billing STLM Labor 59,888 8,856 29,173 21,858 21 2033 Market Analysis Alloc-Fixed 184,563 - 184,563 - 22 2039 BITT and Business Tools Alloc-Fixed 2,178 327 1,307 544 23 2047 Score Card Alloc-Fixed 10,616 1,570 5,171 3,875 24 2048 FCM Alloc-Fixed 211,240 - - 211,240 25 2049 Product Testing Alloc-Fixed 21,777 - 17,422 4,355 26 2051 Legal Support Alloc-Fixed 23,138 - 11,569 11,569 27 2052 FERC Data Request Alloc-Fixed 544 - 272 272 28 2054 Markets Development Support Alloc-Fixed 2,994 - 1,497 1,497 29 Total 2,608,693 387,244 1,197,081 1,024,367 30 31 Market Operations Support Services 32 3000 Hourly Settlements Support Alloc-Fixed 263,183 - 131,592 131,592 33 3002 Monthly Settlements Support Alloc-Fixed 108,370 54,185 - 54,185 34 3003 Market Analysis Support Alloc-Fixed 774 - 774 - 35 3004 Generation & Load Admin Support Alloc-Fixed 193,982 - 193,982 - 36 3005 Demand Resource Admin Support Alloc-Fixed 97,533 - 97,533 - 37 3006 Customer Service Alloc-Fixed 154,814 - 154,814 - 38 3007 NEPOOL Committees Support Alloc-Fixed 2,632 - 1,316 1,316 39 3008 Admin Support Alloc-Fixed 57,281 - 57,281 - 40 3009 Indirect Supervision (Principal Analysts only) Alloc-Fixed 86,696 - 86,696 - 41 3010 Employee Development Alloc-Fixed 15,791 - 15,791 - 42 3011 Release Checkout and Support Alloc-Fixed 1,858 - 1,858 - 43 3012 FERC Data Request Alloc-Fixed 44,896 - 44,896 - 44 3013 Tariff Change Coordination (TCC) Total Dir Labor 155 33 80 41 45 3014 Markets Development Support Alloc-Fixed 10,063 - 5,031 5,031 46 3015 Market Administration Support Alloc-Fixed 1,084 - 1,084 - 47 Total 1,039,110 54,218 792,726 192,165 48 49 406 Market Services 50 16006 Call Support (Ask ISO) Alloc-Fixed 823,752 214,176 543,677 65,900 51 16419 Asset Registration Implemented Alloc-Fixed 244,377 - 244,377 - 52 16420 Asset Registration Review Alloc-Fixed 210,670 - 210,670 - 53 16422 Claimed Capability Audits Alloc-Fixed 33,707 - 33,707 - 54 16424 Demand Resource Audits Alloc-Fixed 185,390 - 185,390 - 55 16425 DR Registration Implemented Alloc-Fixed 33,707 - 33,707 - 56 16434 QMS/CAPA Process and Procedure Updates Total Dir Labor 252,804 54,479 130,826 67,499 57 16435 Resource Performance Monitoring Alloc-Fixed 33,707 - 33,707 - 58 Total 1,818,114 268,655 1,416,061 133,399 59 60 410 Market Training and Reliability Contracts 61 16021 Training Development Alloc-Fixed 858,076 - 429,038 429,038 62 16024 Training Delivery Alloc-Fixed 8,166 - 4,083 4,083 63 16433 Passive Resource Performance and M&V Review Alloc-Fixed 33,707 - 33,707 - 64 16404 NEPOOL Committee Support MS Labor 86,134 - 77,521 8,613 65 16414 Direct Customer Contact MS Labor 146,445 - 131,800 14,644 66 16429 Business Analysis - Process Improvement Alloc-Fixed 155 - 139 15 67 Total 1,132,684 - 676,289 456,395
(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. ER16-___-000 DIRECT LABOR COST ALLOCATIONS TO SCHEDULES BY COST CATEGORY TEST YEAR 2016
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)
1 203 Resource Adequacy 2 14313 National Committee Support PSR Labor 33,807 3,673 1,706 28,427 3 14315 Employee Development PSR Labor 135,227 14,694 6,824 113,709 4 18101 Develop Load Forecast Alloc-Fixed 169,033 33,807 33,807 101,420 5 18121 Operations Forecast Support Alloc-Fixed 67,613 13,523 13,523 40,568 6 18131 Other Load Forecasting Activities Alloc-Fixed 33,807 6,761 6,761 20,284 7 17101 Analysis Alloc-Fixed 709,940 - 496,958 212,982 8 17131 Calculate Objective Capability Alloc-Fixed 169,033 - - 169,033 9 17231 Regulatory Filings Alloc-Fixed 33,807 - - 33,807 10 17241 Transmission Plan Admin Support Alloc-Fixed 33,807 16,903 16,903 - 11 17251 Regional Bulk Power System Assessment Alloc-Fixed 304,260 152,130 152,130 - 12 17331 NEPOOL Committee Support PSR Labor 101,420 11,020 5,118 85,281 13 17361 Regional Committee Support PSR Labor 33,807 3,673 1,706 28,427 14 17401 Indirect Supervisory Activities PSR Labor 169,033 18,367 8,530 142,136 15 17402 Project Management Alloc-Fixed 236,647 236,647 - - 16 17403 TCA Application Review Alloc-Fixed 70,489 - - 70,489 17 17405 Energy Efficiency Forecast Alloc-Fixed 67,613 - - 67,613 18 17406 North American Energy Standards Board (NAESB) Alloc-Fixed 33,807 - 16,903 16,903 19 17408 MA-EEAC Total Dir Labor 33,807 7,285 17,495 9,026 20 17501 FCA - Evaluate Existing Resource De-list Bids Alloc-Fixed 73,097 - - 73,097 21 17502 FCA - Preliminary Review of Show of Interest Applications Alloc-Fixed 140,710 - - 140,710 22 17503 FCA - New Resource Qualification Support Alloc-Fixed 208,323 - - 208,323 23 17504 FCA - Perform Transmission / Topology Assessments Alloc-Fixed 101,420 - - 101,420 24 17505 FCA - Perform Existing Resource Qualification Alloc-Fixed 208,323 - - 208,323 25 17507 FCA - Auctions & Filings Alloc-Fixed 331,951 - - 331,951 26 17508 FCA - Annual Reconfiguration Auction Support/Reliability Revie Alloc-Fixed 73,097 - - 73,097 27 Total 3,573,876 518,484 778,365 2,277,027 28 29 204 System Planning 30 18150 Regional Transmission Expansion Plan Alloc-Fixed 740,236 555,177 185,059 - 31 18152 States Requests Alloc-Fixed 148,511 74,256 37,128 37,128 32 18401 Regional Activities Alloc-Fixed 10,966 10,966 - - 33 18501 Regulatory Activities Alloc-Fixed 17,158 17,158 - - 34 18531 Indirect Supervision/Clerical Support SP Labor 131,598 32,671 23,331 75,596 35 Total 1,048,470 690,228 245,517 112,724 36 37 205 Transmission Planning 38 11201 System Design Task Force Alloc-Fixed 3,524 3,524 - - 39 18201 Transmission System Assessment Alloc-Fixed 3,066,230 3,066,230 - - 40 18261 Transmission Tariff Information Requirements Alloc-Fixed 9,758 9,758 - - 41 18301 NEPOOL Administrative Support - Schedule 1 Tariff Alloc-Fixed 69,447 69,447 - - 42 18331 SIS Preparatory Arrangements Alloc-Fixed 3,524 3,524 - - 43 18333 General SIS/FS Alloc-Fixed 435,079 435,079 - - 44 18334 Indirect Supervision/Clerical Support TP Labor 366,454 366,454 - - 45 18335 Regulatory Activities - NPCC TP Labor 90,732 90,732 - - 46 18336 National Activities TP Labor 72,061 72,061 - - 47 18337 Regulatory Activities TP Labor 108,205 108,205 - - 48 18338 Employee Development TP Labor 111,741 111,741 - - 49 18341 NERC Compliance TP Labor 11,717 11,717 - - 50 18343 FERC Order 1000 Alloc-Fixed 255,565 - - 255,565 51 18344 Transmission Planning Siting Support Alloc-Fixed 6,233 - - 6,233 52 Total 4,610,272 4,348,473 - 261,798 53 54 304 Program Management 55 801 Program Management - Administration Total Dir Labor 801,603 172,730 414,838 214,035 56 1661 ISO Program Management Alloc-Fixed 340,444 - 238,311 102,133 57 25002 PMO Support Alloc-Fixed 16,298 4,889 5,704 5,704 58 25902 Coordinated Transaction Scheduling - O&M Alloc-Fixed 115,419 80,793 34,626 - 59 25914 Divisional Accounting (for Market Participants) Total Dir Labor 66,825 14,400 34,583 17,843 60 25919 Alternative Technologies & Regulation Market Alloc-Fixed 39,711 - - 39,711 61 25926 Hourly Market Alloc-Fixed 154,814 61,925 46,444 46,444 62 25938 Asset Registration Automation Total Dir Labor 16,720 3,603 8,653 4,464 63 25943 Submission of FTRs for Clearing Alloc-Fixed 33,856 - - 33,856 64 25953 ICCP and ED Network Upgrades Alloc-Fixed 95,782 86,204 - 9,578 65 Total 1,681,472 424,544 783,159 473,769 66 67 315 Business Architecture and Technology 68 21201 Business Architecture and Technology Total Dir Labor 2,005,775 432,205 1,038,011 535,559 69 21203 Employee Development Total Dir Labor 36,006 7,759 18,634 9,614 70 Total 2,041,781 439,963 1,056,644 545,173 71 72 408 Market Development 73 21001 Market Development Total Dir Labor 1,751,638 377,443 906,492 467,703 74 21002 Administration Total Dir Labor 183,849 39,616 95,144 49,089 75 21003 Employee Development Total Dir Labor 3,920 845 2,029 1,047 76 21007 Budget/Forecast Support Total Dir Labor 61,283 13,205 31,715 16,363 77 22656 Energy, Reserve, and Regulation Markets Alloc-Fixed 765,429 - 574,072 191,357 78 Total 2,766,119 431,109 1,609,451 725,559
(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. ER16-___-000 DIRECT LABOR COST ALLOCATIONS TO SCHEDULES BY COST CATEGORY TEST YEAR 2016
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 Markets Committee Relations & Rule Integration 2 22602 NEPOOL Committee Meetings & Support Alloc-Fixed 598,427 - 299,213 299,213 3 22607 NEPOOL Markets Committee Administration Total Dir Labor 112,878 24,323 58,416 30,139 4 Total 711,305 24,323 357,629 329,353 5 6 409 Demand Resource Strategy 7 22401 Administration Total Dir Labor 66,070 14,237 34,192 17,641 8 22402 Working Group Meetings and Support Total Dir Labor 21,899 4,719 11,333 5,847 9 22404 Price Responsive Demand Alloc-Fixed 179,796 - 143,837 35,959 10 Total 267,765 18,956 189,361 59,448 11 12 210 IT Management 13 6517 Employee Development - Hardware/Software Total Dir Labor 74,438 16,040 38,522 19,876 14 6519 Indirect Supervision and Clerical Support Total Dir Labor 2,988,976 644,065 1,546,828 798,083 15 6552 Security Total Dir Labor 7,024 1,514 3,635 1,875 16 6556 Budget Preparation, Tracking & Forecast Total Dir Labor 145,731 31,402 75,417 38,911 17 6557 Information Technology Committee Total Dir Labor 12,727 2,743 6,587 3,398 18 22501 Change Management Support Alloc-Fixed 187,538 84,392 84,392 18,754 19 22505 Administrative Alloc-Fixed 352,172 119,738 116,217 116,217 20 Total 3,768,606 899,894 1,871,598 997,114 21 22 201 IT System/Network & Desktop 23 6550 Data Communications Support Total Dir Labor 270,398 58,265 139,934 72,199 24 6602 Help Desk Support Total Dir Labor 334,649 72,110 173,184 89,354 25 6615 Host Computer Monitoring Alloc-Fixed 1,254,035 - 627,017 627,017 26 6516 Communications Total Dir Labor 19,345 4,168 10,011 5,165 27 6616 Desktop Support Total Dir Labor 499,125 107,552 258,303 133,271 28 6617 System Administration - Unix Total Dir Labor 678,400 146,182 351,079 181,139 29 6618 System Administration - Windows Total Dir Labor 838,453 180,670 433,909 223,874 30 6619 Systems Support Misc Total Dir Labor 85,170 18,352 44,076 22,741 31 6620 Systems Support - Security Total Dir Labor 245,577 52,917 127,089 65,571 32 6621 Network Support Total Dir Labor 413,609 89,125 214,047 110,437 33 6622 Network/Systems Compliance Total Dir Labor 11,019 2,374 5,703 2,942 34 6623 Asset Management Total Dir Labor 233,940 50,409 121,067 62,464 35 Total 4,883,719 782,125 2,505,419 1,596,175 36 37 212 IT Cyber Security 38 6539 Policy/Procedures Program Total Dir Labor 19,622 4,228 10,155 5,239 39 6540A Controls Assessment Total Dir Labor 39,245 8,456 20,310 10,479 40 6540B Virus/Malware Reporting and Response Total Dir Labor 19,622 4,228 10,155 5,239 41 6540D Intrusion Monitoring and Response Total Dir Labor 98,111 21,141 50,774 26,197 42 6540E System Compliance Enhancement Total Dir Labor 156,978 33,826 81,238 41,915 43 6540 Security Compliance and Reporting Total Dir Labor 1,336,004 287,883 691,397 356,725 44 6541 Security SW Tools Program Total Dir Labor 333,579 71,880 172,631 89,069 45 6546 Internal Audit Support Total Dir Labor 19,622 4,228 10,155 5,239 46 6547 Security Training Total Dir Labor 19,622 4,228 10,155 5,239 47 6548 CIP Compliance & Monitoring Total Dir Labor 146,982 31,672 76,065 39,245 48 2,189,389 471,770 1,133,033 584,586 49 211 IT Enterprise Applications Support 50 6571 DBA Support - MOPS Total Dir Labor 909,895 196,064 470,880 242,950 51 6591 Data Architect - MOPS Total Dir Labor 256,136 55,192 132,553 68,391 52 6594 IT Data Analyst Total Dir Labor 265,629 57,238 137,466 70,925 53 6595 IT WEB Application Support Total Dir Labor 663,397 142,949 343,315 177,133 54 6596 IT Data Governance Total Dir Labor 150,067 32,336 77,661 40,069 55 21806 Software Support - Enterprise Total Dir Labor 434,067 93,533 224,635 115,900 56 21706 IT Markets Software Development - Enterprise Total Dir Labor 400,178 86,231 207,097 106,851 57 21801 Software Support - Settlements Alloc-Fixed 336,218 - 268,974 67,244 58 21803 Software Support - Finance Alloc-Fixed 79,608 - 63,686 15,922 59 21804 Software Support - Mitigation Alloc-Fixed 451,110 - 360,888 90,222 60 21802 Software Support - Publishing Alloc-Fixed 238,823 - 191,058 47,765 61 21811 Single Sign On Support Alloc-Fixed 79,608 - 63,686 15,922 62 21819 Ceridian Support Total Dir Labor 79,608 17,154 41,198 21,256 63 21821 Compliance Management Total Dir Labor 53,072 11,436 27,465 14,171 64 Total 4,397,414 692,133 2,610,563 1,094,718
(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. ER16-___-000 DIRECT LABOR COST ALLOCATIONS TO SCHEDULES BY COST CATEGORY TEST YEAR 2016
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 21702 IT Corporate Application Support Alloc-Fixed 75,435 - 15,087 60,348 3 21709 Technology Evaluation and Selection Alloc-Fixed 17,788 - 14,230 3,558 4 21707 Application Analysis and Conceptual Design Alloc-Fixed 1,074,003 - 859,202 214,801 5 21710 Indirect Supervision and Administration Alloc-Fixed 531,017 - 424,813 106,203 6 21711 EWR and CAPA Analysis Alloc-Fixed 171,124 - 136,899 34,225 7 Total 1,869,365 - 1,450,232 419,134 8 9 102 IT Energy Management Systems 10 21600 Indirect Supervision and Administration Total Dir Labor 228,214 49,176 118,103 60,935 11 21603 Applications Support Total Dir Labor 240,405 51,802 124,412 64,190 12 21604 DTS Support Alloc-Fixed 644,592 515,674 128,918 - 13 21605 DAM Support Alloc-Fixed 918,647 183,729 551,188 183,729 14 21606 Real-time Market Support Alloc-Fixed 1,117,595 223,519 670,557 223,519 15 Total 3,149,454 1,023,900 1,593,179 532,374 16 17 18 216 IT Power System Modeling Management 19 21650 Indirect Supervision and Administration Total Dir Labor 107,374 23,139 55,566 28,669 20 21654 NX9 Administration Alloc-Fixed 149,822 59,929 59,929 29,964 21 21651 Power System Modeling Alloc-Fixed 720,224 288,090 288,090 144,045 22 21652 System Application Support Alloc-Fixed 176,841 70,737 70,737 35,368 23 21655 ICCP Support Alloc-Fixed 481,009 192,403 192,403 96,202 24 21656 Transmission Project Management Alloc-Fixed 23,590 18,872 4,718 - 25 21657 Model On Demand Admin Alloc-Fixed 272,624 - - 272,624 26 21658 Model on Demand Case Requests Alloc-Fixed 74,528 - - 74,528 27 Total 2,006,012 653,169 671,442 681,400 28 29 Total ISO $ 104,908,012 $ 26,965,798 $ 49,446,752 $ 28,495,462
100.0% 25.7% 47.1% 27.2%
(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. ER16-___-000 DIRECT LABOR COST ALLOCATIONS TO SCHEDULES BY COST CATEGORY TEST YEAR 2016
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 $ 810,821 $ - $ - $ 810,821 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 $ 543,968 $ 190,796 $ 179,813 $ 173,359 9 ERM Labor 100.00% 35.07% 33.06% 31.87% 10 301 Human Resources $ - $ - $ - $ - 11 HR Labor 0.00% 0.00% 0.00% 0.00% 12 306 Legal Department $ 1,132,486 $ 159,710 $ 232,305 $ 740,472 13 Legal Labor 100.00% 14.10% 20.51% 65.38% 14 305 Internal Audit $ 167,311 $ 19,659 $ 137,823 $ 9,829 15 IA Labor 100.00% 11.75% 82.38% 5.87% 16 701 COO-Adm $ 1,219,926 $ 326,958 $ 584,997 $ 307,970 17 COO Labor 100.00% 26.80% 47.95% 25.25% 18 702 Reliability and Operations Services $ 825,867 $ 322,845 $ 157,380 $ 345,642 19 COO Labor 100.00% 39.09% 19.06% 41.85% 20 703 Reliability and Operations Compliance $ 1,041,228 $ 473,475 $ 315,658 $ 252,096 21 COO Labor 100.00% 45.47% 30.32% 24.21% 22 105 System Operations - Administration $ 278,921 $ 96,339 $ 129,475 $ 53,107 23 SYSOPS Labor 100.00% 34.54% 46.42% 19.04% 24 101 Operations $ 11,902,912 $ 3,790,172 $ 6,166,308 $ 1,946,433 25 OPS Labor 100.00% 31.84% 51.81% 16.35% 26 103 Operations Support Services $ 5,563,160 $ 3,286,516 $ 527,018 $ 1,749,626 27 TSO Labor 100.00% 59.08% 9.47% 31.45% 28 109 System Operations Support $ 760,239 $ 86,792 $ 387,453 $ 285,995 29 TSO Labor 100.00% 11.42% 50.96% 37.62% 30 415 Market Operations - Adm $ 980,412 $ - $ 686,288 $ 294,124 31 MOA Labor 100.00% 0.00% 70.00% 30.00% 32 404 Market Monitoring $ 3,644,061 $ - $ 2,412,633 $ 1,231,428 33 MMM Labor 100.00% 0.00% 66.21% 33.79% 34 416 Market Operations $ 2,241,527 $ - $ 1,981,716 $ 259,811 35 MA Labor 100.00% 0.00% 88.41% 11.59% 36 401 Market Anaylsis & Settlements $ 2,298,366 $ 320,375 $ 1,036,484 $ 941,507 37 STLM Labor 100.00% 13.94% 45.10% 40.96% 38 411 Market Operations Support Services $ 1,038,955 $ 54,185 $ 792,646 $ 192,124 39 MOSS Labor 100.00% 5.22% 76.29% 18.49% 40 406 Market Services $ 1,565,310 $ 214,176 $ 1,285,235 $ 65,900 41 MS Labor 100.00% 13.68% 82.11% 4.21% 42 410 Market Training and Reliability Contracts $ 1,132,684 $ - $ 676,289 $ 456,395 43 MAR Labor 100.00% 0.00% 59.71% 40.29% 44 204 System Planning $ 1,048,470 $ 690,228 $ 245,517 $ 112,724 45 SP Labor 100.00% 65.83% 23.42% 10.75% 46 203 Resource Adequacy $ 3,540,070 $ 511,199 $ 760,870 $ 2,268,001 47 PSR Labor 100.00% 14.44% 21.49% 64.07% 48 205 Transmission Planning $ 4,610,272 $ 4,348,473 $ - $ 261,798 49 TP Labor 100.00% 94.32% 0.00% 5.68% 50 304 Program Management $ 796,324 $ 233,812 $ 325,085 $ 237,427 51 PMO Labor 100.00% 29.36% 40.82% 29.82% 52 315 Business Architecture and Technology $ - $ - $ - $ - 53 BAT Labor 0.00% 0.00% 0.00% 0.00% 54 408 Market Development $ 765,429 $ - $ 574,072 $ 191,357 55 MD Labor 100.00% 0.00% 75.00% 25.00% 56 407 Markets Committee Relations & Rule Integration $ 598,427 $ - $ 299,213 $ 299,213 57 MDES Labor 100.00% 0.00% 50.00% 50.00% 58 409 Demand Resource Strategy $ 179,796 $ - $ 143,837 $ 35,959 59 DR Labor 100.00% 0.00% 80.00% 20.00%
(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. ER16-___-000 DIRECT LABOR COST ALLOCATIONS TO SCHEDULES BY COST CATEGORY TEST YEAR 2016
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 $ 539,710 $ 204,131 $ 200,609 $ 134,971 2 OTM Labor 100.00% 37.82% 37.17% 25.01% 3 201 IT System/Network & Desktop $ 1,254,035 $ - $ 627,017 $ 627,017 4 ITO Labor 100.00% 0.00% 50.00% 50.00% 5 211 IT Enterprise Applications Support $ 1,185,366 $ - $ 948,293 $ 237,073 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 $ 2,680,834 $ 922,922 $ 1,350,664 $ 407,248 10 EMS Labor 100.00% 34.43% 50.38% 15.19% 11 213 IT Enterprise Applications Development $ 1,869,365 $ - $ 1,450,232 $ 419,134 12 ESD 100.00% 0.00% 77.58% 22.42% 13 216 IT Power System Modeling Management $ 1,898,637 $ 630,030 $ 615,876 $ 652,731 14 ITPSM 100.00% 33.18% 32.44% 34.38% 15 Total Direct Labor $ 58,114,888 $ 16,882,792 $ 25,230,803 $ 16,001,293 16 100.00% 29.05% 43.42% 27.53% 17 18 Summary Of Allocations Of Labor Based On Fixed Allocators and Allocated Departmental Labor 19 Total Direct Labor $ 58,114,888 $ 16,882,792 $ 25,230,803 $ 16,001,293 20 Dir Labor 100.00% 29.05% 43.42% 27.53% 21 Total Indirect Labor Labor $ 46,793,124 $ 10,083,006 $ 24,215,949 $ 12,494,169 22 InDir Labor 100.00% 21.55% 51.75% 26.70% 23 Total Labor Expense $ 104,908,012 $ 26,965,798 $ 49,446,752 $ 28,495,462 24 Total Dir Labor 100.00% 25.70% 47.13% 27.16%
(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. ER16-___-000 Schedule 5.0 ALLOCATION FACTORS BY COST CATEGORY Page 1 of 7 TEST YEAR 2016
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 Indirect Administrative Support Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 3 12652 NEPOOL Committee Support Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 4 12654 National Committee Support Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 5 12657 Indirect Administrative Support for BCC Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 6 7 302 Finance 8 11601 Payroll Administration Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 9 11701 Accounts Payable Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 10 11702 Procurement Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 11 11901 Billing for Transmission and Energy Settlements Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 12 12001 Budgeting and Forecasting Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 13 12005 Credit Admininstration Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 14 12015 Backup Control Center (BCC) Construction Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 15 12017 Forward Capacity Market (FCM) Reforms Alloc-Fixed 100.00% 0.00% 0.00% 100.00% Per ISO-NE Staff 16 12101 Ledger Closing, Financial Statements and Tax Reporting Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 17 12201 Treasury and Cash Management Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 18 92004 Depreciation Expense 2004 Assets Alloc-Fixed 100.00% 20.83% 52.21% 26.96% Per ISO-NE Staff 19 92005 Depreciation Expense 2005 Assets Alloc-Fixed 100.00% 21.16% 52.00% 26.84% Per ISO-NE Staff 20 92006 Depreciation Expense 2006 Assets Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 21 92007 Depreciation Expense 2007 Assets Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 22 92008 Depreciation Expense 2008 Assets Alloc-Fixed 100.00% 45.84% 35.73% 18.43% Per ISO-NE Staff 23 92009 Depreciation Expense 2009 Assets Alloc-Fixed 100.00% 45.01% 36.28% 18.72% Per ISO-NE Staff 24 92010 Depreciation Expense 2010 Assets Alloc-Fixed 100.00% 23.72% 49.74% 26.55% Per ISO-NE Staff 25 92011 Depreciation Expense 2011 Assets Alloc-Fixed 100.00% 24.42% 34.97% 40.60% Per ISO-NE Staff 26 92012 Depreciation Expense 2012 Assets Alloc-Fixed 100.00% 24.17% 37.02% 38.81% Per ISO-NE Staff 27 92013 Depreciation Expense 2013 Assets Alloc-Fixed 100.00% 20.20% 43.63% 36.17% Per ISO-NE Staff 28 92014 Depreciation Expense 2014 Assets Alloc-Fixed 100.00% 25.68% 35.23% 39.09% Per ISO-NE Staff 29 92015 Depreciation Expense 2015 Assets Alloc-Fixed 100.00% 34.18% 44.36% 21.46% Per ISO-NE Staff 30 92016 Depreciation Expense 2016 Assets Alloc-Fixed 100.00% 18.80% 45.60% 35.60% Per ISO-NE Staff 31 99707 Amortization of Land Recovery Alloc-Fixed 100.00% 19.33% 35.58% 45.09% Per ISO-NE Staff 32 99995 NPCC/NERC Dues Alloc-Fixed 100.00% 0.00% 0.00% 100.00% Per ISO-NE Staff 33 99996 Operating Contingency Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 34 99998 Payroll & Other Accruals Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 35 36 108 Building Services 37 12664 Building Maintenance Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 38 39 310 Enterprise Risk Management 40 22701 Enterprise Risk Mgmnt - Admin Alloc-Fixed 100.00% 33.30% 33.30% 33.40% Per ISO-NE Staff 41 22703 Bus Cont Pl Prog Admin & Support Alloc-Fixed 100.00% 33.30% 33.30% 33.40% Per ISO-NE Staff 42 22704 Record Retention Services Alloc-Fixed 100.00% 33.30% 33.30% 33.40% Per ISO-NE Staff 43 22705 Corporate Scorecard Alloc-Fixed 100.00% 33.30% 33.30% 33.40% Per ISO-NE Staff 44 22706 Document Management Services Alloc-Fixed 100.00% 40.00% 30.00% 30.00% Per ISO-NE Staff 45 22708 Adminstration Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 46 22709 Management Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 47 22710 Employee Development Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 48 22711 Forward Capacity Market (FCM) Cap Adjustments Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 49 22712 Risk Policy Assessments Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 50 22713 MEC/Financials Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 51 22714 Analysis Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 52 22716 Financial Assurance Management (FAM) Rebuild Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 53 22719 Human Performance Improvement Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 54 22720 Business Process Change Management Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 55 22721 Corp Strategic Risk Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 56 22725 OSHA procedures Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 57 22727 ERM Business Analysis Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 58 23003 Safety / Security / Facilities Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 59 23006 Business Continuity Planning Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 60 25006 Business Process Maintenance Alloc-Fixed 100.00% 45.00% 45.00% 10.00% Per ISO-NE Staff 61 25011 Corrective Action/Preventive Action Alloc-Fixed 100.00% 33.30% 33.30% 33.40% Per ISO-NE Staff 62 25014 EtQ Tools Dev & Support Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 63 25015 Coord Tariff Change Committee (TCC) Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 64 25017 Scorecard Operational Excellence Excercise -- I.3.9 Process Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 65 301 Human Resources 66 12661 Employee Affairs (Recreation Committee) Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 67 12701 Recruiting/Interviewing Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 68 12801 Employee Relations Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 69 12901 Benefit Administration Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 70 12951 Compensation Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 71 12961 HR - General Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 72 12962 HR - Training Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 73 13410 Power Training & Development Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 74 13411 Markets Training & Development Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 75 13412 People Training & Development Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 76 13413 Business Skills Trng & Dev Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 77 13414 Technology Trng & Development 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. ER16-___-000 Schedule 5.0 ALLOCATION FACTORS BY COST CATEGORY Page 2 of 7 TEST YEAR 2016
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)
1 305 Internal Audit 2 15001 Indirect Management Duties Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 3 15002 Personnel Management Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 4 15003 Budget & Forecasting Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 5 15004 Audit Follow-up Activities Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 6 15005 Audit & Finance Committee Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 7 15006 Internal Audit Business Process Update Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 8 15007 Annual Audit Work Plan Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 9 15008 Training Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 10 15020 Internal Audit - Finance Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 11 15021 Perfomance Measurements Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 12 15022 Vendor Contracts Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 13 15023 Wire Transfers Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 14 15031 Employee Expense Reporting Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 15 15040 Operations Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 16 15065 Wind Integration Project Alloc-Fixed 100.00% 40.00% 40.00% 20.00% Per ISO-NE Staff 17 15085 Information Technology Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 18 15131 NAMS Support Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 19 15133 Satellite Reviews Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 20 15134 SCADA Operations Reviews Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 21 15161 External Audit- Pension Audit Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 22 15162 External Audit- Financial Audit Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 23 15166 External Audit -Pricing Module Certification Alloc-Fixed 100.00% 0.00% 100.00% 0.00% Per ISO-NE Staff 24 15175 External Audit - Info Technology Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 25 15186 External Audit - SSAE 16 Direct Support Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 26 25702 External Audit - SSAE 16 Alloc-Fixed 100.00% 0.00% 100.00% 0.00% Per ISO-NE Staff 27 28160 MS Universal Access Gateway Review Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 28 29 306 Legal Department 30 8301 Federal Regulatory Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 31 12426 Interconnection Agreements Alloc-Fixed 100.00% 0.00% 50.00% 50.00% Per ISO-NE Staff 32 12502 Board of Directors Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 33 12504 ISO Tariff Litigation Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 34 12505 Administration of OATT (Open Access Transmission Tariff) Alloc-Fixed 100.00% 100.00% 0.00% 0.00% Per ISO-NE Staff 35 12508 Energy Markets / Complaints / Rule Changes Alloc-Fixed 100.00% 0.00% 100.00% 0.00% Per ISO-NE Staff 36 12509 Market Monitoring and Sanctions Alloc-Fixed 100.00% 0.00% 50.00% 50.00% Per ISO-NE Staff 37 12512 BSAI - General Corporate Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 38 12513 Miscellaneous Labor Matters Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 39 12514 NEPOOL Participants Committee Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 40 12517 Administrative and Clerical Support Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 41 12520 Market Monitoring Rules/Regulations Alloc-Fixed 100.00% 0.00% 40.00% 60.00% Per ISO-NE Staff 42 12521 Billing Disputes Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 43 12523 NEPOOL Information Policy Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 44 12542 Transmission Upgrades CT Alloc-Fixed 100.00% 0.00% 70.00% 30.00% Per ISO-NE Staff 45 12543 Independent Market Advisor Alloc-Fixed 100.00% 0.00% 70.00% 30.00% Per ISO-NE Staff 46 12544 FERC Proceedings Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 47 12552 S&G - General Corporate Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 48 12559 General Corporate Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 49 12563 Regulatory Matters Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 50 12572 205 General Proceedings Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 51 12573 206 General Proceedings Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 52 12574 Market Rule 1 Proceedings Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 53 12587 Capacity Market Development Alloc-Fixed 100.00% 0.00% 0.00% 100.00% Per ISO-NE Staff 54 12588 Web Content Management Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 55 12594 Maine Transmission Siting Alloc-Fixed 100.00% 0.00% 70.00% 30.00% Per ISO-NE Staff 56 12595 NEEWS Transmission Siting Alloc-Fixed 100.00% 0.00% 70.00% 30.00% Per ISO-NE Staff 57 12609 FTR Clearing Alloc-Fixed 100.00% 0.00% 50.00% 50.00% Per ISO-NE Staff 58 12663 Public Information Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 59 12669 Government Affairs Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 60 61 701 COO-Adm 62 19001 NEPOOL Committee Support Total OPS Labor 100.00% 26.80% 47.95% 25.25% Per ISO-NE Staff 63 19002 Regional Committee Support Total OPS Labor 100.00% 26.80% 47.95% 25.25% Per ISO-NE Staff 64 19003 National Committee Support Total OPS Labor 100.00% 26.80% 47.95% 25.25% Per ISO-NE Staff 65 19005 Indirect Supervision/Clerical Support Total OPS Labor 100.00% 26.80% 47.95% 25.25% Per ISO-NE Staff 66 19009 Renewable Resource Integration Alloc-Fixed 100.00% 0.00% 0.00% 100.00% Per ISO-NE Staff 67 19012 Changes to the Forward Capacity Market Alloc-Fixed 100.00% 0.00% 0.00% 100.00% Per ISO-NE Staff 68 69 105 System Operations - Administration 70 14404 NEPOOL Committee Support SOA Labor 100.00% 34.54% 46.42% 19.04% Per ISO-NE Staff 71 14405 Indirect Supervision/Clerical Support SOA Labor 100.00% 34.54% 46.42% 19.04% Per ISO-NE Staff 72 14407 Regional Committee Support SOA Labor 100.00% 34.54% 46.42% 19.04% Per ISO-NE Staff 73 14408 National Committee Support 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. ER16-___-000 Schedule 5.0 ALLOCATION FACTORS BY COST CATEGORY Page 3 of 7 TEST YEAR 2016
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 Generation Dispatch Alloc-Fixed 100.00% 0.00% 84.00% 16.00% Per ISO-NE Staff 3 14002 Transmission Operations Alloc-Fixed 100.00% 80.00% 5.00% 15.00% Per ISO-NE Staff 4 14304 Advanced Scheduling and Forecasting Alloc-Fixed 100.00% 5.00% 79.00% 16.00% Per ISO-NE Staff 5 14402 Operations Training Alloc-Fixed 100.00% 40.00% 40.00% 20.00% Per ISO-NE Staff 6 14413 Operations Support Training & Development Alloc-Fixed 100.00% 40.00% 40.00% 20.00% Per ISO-NE Staff 7 14564 Indirect Supervision/Clerical Support OPS Labor 100.00% 27.96% 55.36% 16.68% Per ISO-NE Staff 8 14702 Procedure Documentation Alloc-Fixed 100.00% 40.00% 40.00% 20.00% Per ISO-NE Staff 9 10 702 Reliability and Operations Services 11 14703 NEPOOL Committee Support OS Labor 100.00% 55.55% 19.33% 25.12% Per ISO-NE Staff 12 14706 Indirect Supervision/Clerical Support OS Labor 100.00% 55.55% 19.33% 25.12% Per ISO-NE Staff 13 14711 ISO TMS Tariff - Section 2 - (OATT) and Agreements Support Alloc-Fixed 100.00% 33.30% 33.30% 33.40% Per ISO-NE Staff 14 14715 Non DOE Funded/Unallowable Alloc-Fixed 100.00% 0.00% 0.00% 100.00% Per ISO-NE Staff 15 16 103 Operations Support Services 17 14301 Contract Administration and Scheduling Alloc-Fixed 100.00% 10.00% 70.00% 20.00% Per ISO-NE Staff 18 14452 Regional Committee Support TSO Labor 100.00% 32.37% 47.81% 19.82% Per ISO-NE Staff 19 14453 National Committee Support TSO Labor 100.00% 32.37% 47.81% 19.82% Per ISO-NE Staff 20 14454 Indirect Supervision/Clerical Support TSO Labor 100.00% 32.37% 47.81% 19.82% Per ISO-NE Staff 21 14462 General Systems Operations Support TSO Labor 100.00% 32.37% 47.81% 19.82% Per ISO-NE Staff 22 14476 Process Automation for On-Call Support of Control Room Alloc-Fixed 100.00% 100.00% 0.00% 0.00% Per ISO-NE Staff 23 18361 Transmission Studies, Operations, OASIS Support Alloc-Fixed 100.00% 80.00% 5.00% 15.00% Per ISO-NE Staff 24 18381 Transmission Outage Appl - Short Term Alloc-Fixed 100.00% 80.00% 5.00% 15.00% Per ISO-NE Staff 25 18382 Trans Out Ap Lg Term Alloc-Fixed 100.00% 0.00% 0.00% 100.00% Per ISO-NE Staff 26 27 315 System Operations Support 28 14469 C10/C30 Audits Alloc-Fixed 100.00% 0.00% 80.00% 20.00% Per ISO-NE Staff 29 14470 Resource Performance Monitoring Alloc-Fixed 100.00% 0.00% 80.00% 20.00% Per ISO-NE Staff 30 14750 NEPOOL Committee Support Alloc-Fixed 100.00% 32.37% 47.81% 19.82% Per ISO-NE Staff 31 14751 Regional Committee Support Alloc-Fixed 100.00% 32.37% 47.81% 19.82% Per ISO-NE Staff 32 14753 Indirect Supervision/Clerical Support Alloc-Fixed 100.00% 32.37% 47.81% 19.82% Per ISO-NE Staff 33 14757 Winter Reliability Project Alloc-Fixed 100.00% 0.00% 20.00% 80.00% Per ISO-NE Staff 34 35 415 Market Operations - Adm 36 19101 NEPOOL Committee Support MOA Labor 100.00% 0.00% 70.00% 30.00% Per ISO-NE Staff 37 19103 National Committee Support MOA Labor 100.00% 0.00% 70.00% 30.00% Per ISO-NE Staff 38 19104 Indirect Supervision/Clerical Support MOA Labor 100.00% 0.00% 70.00% 30.00% Per ISO-NE Staff 39 19105 Employee Development MOA Labor 100.00% 0.00% 70.00% 30.00% Per ISO-NE Staff 40 19112 Settlements - Customer Service MOA Labor 100.00% 0.00% 70.00% 30.00% Per ISO-NE Staff 41 19120 CEII Requests Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 42 43 404 Market Monitoring 44 16101 Market Power Monitoring and Mitigation Alloc-Fixed 100.00% 0.00% 70.00% 30.00% Per ISO-NE Staff 45 16102 Regulatory Activities Alloc-Fixed 100.00% 0.00% 70.00% 30.00% Per ISO-NE Staff 46 16111 Employee Development MMM Labor 100.00% 0.00% 70.00% 30.00% Per ISO-NE Staff 47 16114 Maintenance / Troubleshooting Software MMM Labor 100.00% 0.00% 70.00% 30.00% Per ISO-NE Staff 48 16115 Analysis & Internal Reports MMM Labor 100.00% 0.00% 70.00% 30.00% Per ISO-NE Staff 49 16121 FCM Market Monitoring Alloc-Fixed 100.00% 0.00% 0.00% 100.00% Per ISO-NE Staff 50 51 416 Market Operations 52 21901 Day Ahead Market Administration Alloc-Fixed 100.00% 0.00% 100.00% 0.00% Per ISO-NE Staff 53 21902 Real Time Price Verification Alloc-Fixed 100.00% 0.00% 100.00% 0.00% Per ISO-NE Staff 54 21904 NEPOOL Committee Support MA Labor 100.00% 0.00% 96.84% 3.16% Per ISO-NE Staff 55 21907 Indirect Supervision/Clerical Support MA Labor 100.00% 0.00% 96.84% 3.16% Per ISO-NE Staff 56 21908 Employee Development MA Labor 100.00% 0.00% 96.84% 3.16% Per ISO-NE Staff 57 21913 Data Collection/Report Writing Alloc-Fixed 100.00% 0.00% 100.00% 0.00% Per ISO-NE Staff 58 21915 FTR/Auction Administration Alloc-Fixed 100.00% 0.00% 100.00% 0.00% Per ISO-NE Staff 59 21916 Forward Reserve Market - Administration Alloc-Fixed 100.00% 0.00% 0.00% 100.00% Per ISO-NE Staff 60 21917 Real Time Price Finalization Alloc-Fixed 100.00% 0.00% 100.00% 0.00% Per ISO-NE Staff 61 21951 FCM Annual Reconfiguration Auction Administration Alloc-Fixed 100.00% 0.00% 0.00% 100.00% Per ISO-NE Staff 62 21953 FCM Monthly Administration 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. ER16-___-000 Schedule 5.0 ALLOCATION FACTORS BY COST CATEGORY Page 4 of 7 TEST YEAR 2016
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)
1 401 Market Anaylsis & Settlements 2 1701 Billing Statements - Energy Alloc-Fixed 100.00% 0.00% 100.00% 0.00% Per ISO-NE Staff 3 1702 Billing Statements - Transmission Alloc-Fixed 100.00% 100.00% 0.00% 0.00% Per ISO-NE Staff 4 1713 Billing Statements - ISO Tariff Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 5 1714 Billable Tariff Re-billings Alloc-Fixed 100.00% 100.00% 0.00% 0.00% Per ISO-NE Staff 6 2005 Customer Service STLM Labor 100.00% 14.79% 48.71% 36.50% Per ISO-NE Staff 7 2007 Admin support - NEPOOL Committees STLM Labor 100.00% 14.79% 48.71% 36.50% Per ISO-NE Staff 8 2008 Admin support (ISO) STLM Labor 100.00% 14.79% 48.71% 36.50% Per ISO-NE Staff 9 2009 Indirect Supervision/Clerical Support STLM Labor 100.00% 14.79% 48.71% 36.50% Per ISO-NE Staff 10 2010 Employee Development STLM Labor 100.00% 14.79% 48.71% 36.50% Per ISO-NE Staff 11 2013 FTR Administration Alloc-Fixed 100.00% 0.00% 100.00% 0.00% Per ISO-NE Staff 12 2014 Billing Statements - NCPC Alloc-Fixed 100.00% 0.00% 50.00% 50.00% Per ISO-NE Staff 13 2020 Billing Disputes Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 14 2021 Analysis & Reporting Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 15 2022 Demand Response Alloc-Fixed 100.00% 0.00% 0.00% 100.00% Per ISO-NE Staff 16 2024 ASM Regulation Alloc-Fixed 100.00% 0.00% 0.00% 100.00% Per ISO-NE Staff 17 2025 ASM Locational Forward Reserve Alloc-Fixed 100.00% 0.00% 0.00% 100.00% Per ISO-NE Staff 18 2026 Batch Processing Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 19 2030 ARR Administration Alloc-Fixed 100.00% 0.00% 90.00% 10.00% Per ISO-NE Staff 20 2032 Billing STLM Labor 100.00% 14.79% 48.71% 36.50% Per ISO-NE Staff 21 2033 Market Analysis Alloc-Fixed 100.00% 0.00% 100.00% 0.00% Per ISO-NE Staff 22 2039 BITT and Business Tools Alloc-Fixed 100.00% 15.00% 60.00% 25.00% Per ISO-NE Staff 23 2047 Score Card Alloc-Fixed 100.00% 14.79% 48.71% 36.50% Per ISO-NE Staff 24 2048 FCM Alloc-Fixed 100.00% 0.00% 0.00% 100.00% Per ISO-NE Staff 25 2049 Product Testing Alloc-Fixed 100.00% 0.00% 80.00% 20.00% Per ISO-NE Staff 26 2051 Legal Support Alloc-Fixed 100.00% 0.00% 50.00% 50.00% Per ISO-NE Staff 27 2052 FERC Data Request Alloc-Fixed 100.00% 0.00% 50.00% 50.00% Per ISO-NE Staff 28 2054 Markets Development Support Alloc-Fixed 100.00% 0.00% 50.00% 50.00% Per ISO-NE Staff 29 30 Market Operations Support Services 31 3000 Hourly Settlements Support Alloc-Fixed 100.00% 0.00% 50.00% 50.00% Per ISO-NE Staff 32 3002 Monthly Settlements Support Alloc-Fixed 100.00% 50.00% 0.00% 50.00% Per ISO-NE Staff 33 3003 Market Analysis Support Alloc-Fixed 100.00% 0.00% 100.00% 0.00% Per ISO-NE Staff 34 3004 Generation & Load Admin Support Alloc-Fixed 100.00% 0.00% 100.00% 0.00% Per ISO-NE Staff 35 3005 Demand Resource Admin Support Alloc-Fixed 100.00% 0.00% 100.00% 0.00% Per ISO-NE Staff 36 3006 Customer Service Alloc-Fixed 100.00% 0.00% 100.00% 0.00% Per ISO-NE Staff 37 3007 NEPOOL Committees Support Alloc-Fixed 100.00% 0.00% 50.00% 50.00% Per ISO-NE Staff 38 3008 Admin Support Alloc-Fixed 100.00% 0.00% 100.00% 0.00% Per ISO-NE Staff 39 3009 Indirect Supervision (Principal Analysts only) Alloc-Fixed 100.00% 0.00% 100.00% 0.00% Per ISO-NE Staff 40 3010 Employee Development Alloc-Fixed 100.00% 0.00% 100.00% 0.00% Per ISO-NE Staff 41 3011 Release Checkout and Support Alloc-Fixed 100.00% 0.00% 100.00% 0.00% Per ISO-NE Staff 42 3012 FERC Data Request Alloc-Fixed 100.00% 0.00% 100.00% 0.00% Per ISO-NE Staff 43 3013 Tariff Change Coordination (TCC) Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 44 3014 Markets Development Support Alloc-Fixed 100.00% 0.00% 50.00% 50.00% Per ISO-NE Staff 45 3015 Market Administration Support Alloc-Fixed 100.00% 0.00% 100.00% 0.00% Per ISO-NE Staff 46 47 406 Market Services 48 16001 Participant/membership support Alloc-Fixed 100.00% 0.00% 50.00% 50.00% Per ISO-NE Staff 49 16006 Call Support (Ask ISO) Alloc-Fixed 100.00% 26.00% 66.00% 8.00% Per ISO-NE Staff 50 16404 NEPOOL Committee Support MS Labor 100.00% 0.00% 90.00% 10.00% Per ISO-NE Staff 51 16414 Direct Customer Contact MS Labor 100.00% 0.00% 90.00% 10.00% Per ISO-NE Staff 52 16419 Asset Registration Implemented Alloc-Fixed 100.00% 0.00% 100.00% 0.00% Per ISO-NE Staff 53 16420 Asset Registration Review Alloc-Fixed 100.00% 0.00% 100.00% 0.00% Per ISO-NE Staff 54 16422 Claimed Capability Audits Alloc-Fixed 100.00% 0.00% 100.00% 0.00% Per ISO-NE Staff 55 16424 Demand Resource Audits Alloc-Fixed 100.00% 0.00% 100.00% 0.00% Per ISO-NE Staff 56 16425 DR Registration Implemented Alloc-Fixed 100.00% 0.00% 100.00% 0.00% Per ISO-NE Staff 57 16429 Business Analysis - Process Improvement Alloc-Fixed 100.00% 0.00% 90.00% 10.00% Per ISO-NE Staff 58 16434 QMS/CAPA Process and Procedure Updates Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 59 16435 Resource Performance Monitoring Alloc-Fixed 100.00% 0.00% 100.00% 0.00% Per ISO-NE Staff 60 61 410 Market Training and Reliability Contracts 62 16021 Training Development Alloc-Fixed 100.00% 0.00% 50.00% 50.00% Per ISO-NE Staff 63 16024 Training Delivery Alloc-Fixed 100.00% 0.00% 50.00% 50.00% Per ISO-NE Staff 64 16433 Passive Resource Performance and M&V Review Alloc-Fixed 100.00% 0.00% 100.00% 0.00% Per ISO-NE Staff 65 66 204 System Planning 67 18150 Regional Transmission Expansion Plan Alloc-Fixed 100.00% 75.00% 25.00% 0.00% Per ISO-NE Staff 68 18152 States Requests Alloc-Fixed 100.00% 50.00% 25.00% 25.00% Per ISO-NE Staff 69 18401 Regional Activities Alloc-Fixed 100.00% 100.00% 0.00% 0.00% Per ISO-NE Staff 70 18501 Regulatory Activities Alloc-Fixed 100.00% 100.00% 0.00% 0.00% Per ISO-NE Staff 71 18521 Employee Development SP Labor 100.00% 24.83% 17.73% 57.44% Per ISO-NE Staff 72 18531 Indirect Supervision/Clerical Support SP Labor 100.00% 24.83% 17.73% 57.44% Per ISO-NE Staff ISO NEW ENGLAND INC. Exhibit 3 (RCL-3) FERC DOCKET NO. ER16-___-000 Schedule 5.0 ALLOCATION FACTORS BY COST CATEGORY Page 5 of 7 TEST YEAR 2016
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 Develop Load Forecast Alloc-Fixed 100.00% 20.00% 20.00% 60.00% Per ISO-NE Staff 3 18121 Operations Forecast Support Alloc-Fixed 100.00% 20.00% 20.00% 60.00% Per ISO-NE Staff 4 18131 Other Load Forecasting Activities Alloc-Fixed 100.00% 20.00% 20.00% 60.00% Per ISO-NE Staff 5 14313 National Committee Support PSR Labor 100.00% 10.87% 5.05% 84.09% Per ISO-NE Staff 6 14315 Employee Development PSR Labor 100.00% 10.87% 5.05% 84.09% Per ISO-NE Staff 7 17101 Analysis Alloc-Fixed 100.00% 0.00% 70.00% 30.00% Per ISO-NE Staff 8 17131 Calculate Objective Capability Alloc-Fixed 100.00% 0.00% 0.00% 100.00% Per ISO-NE Staff 9 17231 Regulatory Filings Alloc-Fixed 100.00% 0.00% 0.00% 100.00% Per ISO-NE Staff 10 17241 Transmission Plan Admin Support Alloc-Fixed 100.00% 50.00% 50.00% 0.00% Per ISO-NE Staff 11 17251 Regional Bulk Power System Assessment Alloc-Fixed 100.00% 50.00% 50.00% 0.00% Per ISO-NE Staff 12 17331 NEPOOL Committee Support PSR Labor 100.00% 10.87% 5.05% 84.09% Per ISO-NE Staff 13 17361 Regional Committee Support PSR Labor 100.00% 10.87% 5.05% 84.09% Per ISO-NE Staff 14 17401 Indirect Supervisory Activities PSR Labor 100.00% 10.87% 5.05% 84.09% Per ISO-NE Staff 15 17402 Project Management Alloc-Fixed 100.00% 100.00% 0.00% 0.00% Per ISO-NE Staff 16 17403 TCA Application Review Alloc-Fixed 100.00% 0.00% 0.00% 100.00% Per ISO-NE Staff 17 17405 Energy Efficiency Forecast Alloc-Fixed 100.00% 0.00% 0.00% 100.00% Per ISO-NE Staff 18 17406 North American Energy Standards Board (NAESB) Alloc-Fixed 100.00% 0.00% 50.00% 50.00% Per ISO-NE Staff 19 17408 MA-EEAC Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 20 17501 FCA - Evaluate Existing Resource De-list Bids Alloc-Fixed 100.00% 0.00% 0.00% 100.00% Per ISO-NE Staff 21 17502 FCA - Preliminary Review of Show of Interest Applications Alloc-Fixed 100.00% 0.00% 0.00% 100.00% Per ISO-NE Staff 22 17503 FCA - New Resource Qualification Support Alloc-Fixed 100.00% 0.00% 0.00% 100.00% Per ISO-NE Staff 23 17504 FCA - Perform Transmission / Topology Assessments Alloc-Fixed 100.00% 0.00% 0.00% 100.00% Per ISO-NE Staff 24 17505 FCA - Perform Existing Resource Qualification Alloc-Fixed 100.00% 0.00% 0.00% 100.00% Per ISO-NE Staff 25 17507 FCA - Auctions & Filings Alloc-Fixed 100.00% 0.00% 0.00% 100.00% Per ISO-NE Staff 26 17508 FCA - Annual Reconfiguration Auction Support/Reliability Reviews Alloc-Fixed 100.00% 0.00% 0.00% 100.00% Per ISO-NE Staff 27 28 205 Transmission Planning 29 11201 System Design Task Force Alloc-Fixed 100.00% 100.00% 0.00% 0.00% Per ISO-NE Staff 30 18201 Transmission System Assessment Alloc-Fixed 100.00% 100.00% 0.00% 0.00% Per ISO-NE Staff 31 18261 Transmission Tariff Information Requirements Alloc-Fixed 100.00% 100.00% 0.00% 0.00% Per ISO-NE Staff 32 18301 NEPOOL Administrative Support - Schedule 1 Tariff Alloc-Fixed 100.00% 100.00% 0.00% 0.00% Per ISO-NE Staff 33 18331 SIS Preparatory Arrangements Alloc-Fixed 100.00% 100.00% 0.00% 0.00% Per ISO-NE Staff 34 18333 General SIS/FS Alloc-Fixed 100.00% 100.00% 0.00% 0.00% Per ISO-NE Staff 35 18334 Indirect Supervision/Clerical Support TP Labor 100.00% 100.00% 0.00% 0.00% Per ISO-NE Staff 36 18335 Regulatory Activities - NPCC TP Labor 100.00% 100.00% 0.00% 0.00% Per ISO-NE Staff 37 18336 National Activities TP Labor 100.00% 100.00% 0.00% 0.00% Per ISO-NE Staff 38 18337 Regulatory Activities TP Labor 100.00% 100.00% 0.00% 0.00% Per ISO-NE Staff 39 18338 Employee Development TP Labor 100.00% 100.00% 0.00% 0.00% Per ISO-NE Staff 40 18341 NERC Compliance TP Labor 100.00% 100.00% 0.00% 0.00% Per ISO-NE Staff 41 18343 FERC Order 1000 Alloc-Fixed 100.00% 0.00% 0.00% 100.00% Per ISO-NE Staff 42 18344 Transmission Planning Siting Support Alloc-Fixed 100.00% 0.00% 0.00% 100.00% Per ISO-NE Staff 43 44 304 Program Management 45 801 Program Management - Administration Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 46 1661 ISO Program Management Alloc-Fixed 100.00% 0.00% 70.00% 30.00% Per ISO-NE Staff 47 25002 PMO Support Alloc-Fixed 100.00% 30.00% 35.00% 35.00% Per ISO-NE Staff 48 25902 Coordinated Transaction Scheduling - O&M Alloc-Fixed 100.00% 70.00% 30.00% 0.00% Per ISO-NE Staff 49 25914 Divisional Accounting (for Market Participants) Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 50 25919 Alternative Technologies & Regulation Market Alloc-Fixed 100.00% 0.00% 0.00% 100.00% Per ISO-NE Staff 51 25926 Hourly Market Alloc-Fixed 100.00% 40.00% 30.00% 30.00% Per ISO-NE Staff 52 25938 Asset Registration Automation Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 53 25940 Non-Reimburseable Smart Grid SIDU Observation Period Alloc-Fixed 100.00% 15.00% 15.00% 70.00% Per ISO-NE Staff 54 25943 Submission of FTRs for Clearing Alloc-Fixed 100.00% 0.00% 0.00% 100.00% Per ISO-NE Staff 55 25953 ICCP and ED Network Upgrades Alloc-Fixed 100.00% 90.00% 0.00% 10.00% Per ISO-NE Staff 56 57 315 Business Architecture and Technology 58 21201 Business Architecture and Technology Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 59 21203 Employee Development Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 60 61 408 Market Development 62 21001 Market Development Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 63 21002 Administration Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 64 21003 Employee Development Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 65 21007 Budget/Forecast Support Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 66 21009 Increased Scope of Impact Analysis Alloc-Fixed 100.00% 26.00% 66.00% 8.00% Per ISO-NE Staff 67 22656 Energy, Reserve, and Regulation Markets Alloc-Fixed 100.00% 0.00% 75.00% 25.00% Per ISO-NE Staff ISO NEW ENGLAND INC. Exhibit 3 (RCL-3) FERC DOCKET NO. ER16-___-000 Schedule 5.0 ALLOCATION FACTORS BY COST CATEGORY Page 6 of 7 TEST YEAR 2016
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 Markets Committee Relations & Rule Integration 2 22602 NEPOOL Committee Meetings & Support Alloc-Fixed 100.00% 0.00% 50.00% 50.00% Per ISO-NE Staff 3 22607 NEPOOL Markets Committee Administration Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 4 5 409 Demand Resource Strategy 6 22401 Administration Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 7 22402 Working Group Meetings and Support Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 8 22404 Price Responsive Demand Alloc-Fixed 100.00% 0.00% 80.00% 20.00% Per ISO-NE Staff 9 10 210 IT Management 11 6517 Employee Development - Hardware/Software Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 12 6519 Indirect Supervision and Clerical Support Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 13 6552 Security Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 14 6556 Budget Preparation, Tracking & Forecast Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 15 6557 Information Technology Committee Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 16 17 201 IT System/Network & Desktop 18 6510 Desktop Support - Hardware Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 19 6511 Desktop Support - Software Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 20 6512 Host Computer - Hardware Alloc-Fixed 100.00% 0.00% 75.00% 25.00% Per ISO-NE Staff 21 6513 Host Computer - Software Alloc-Fixed 100.00% 0.00% 75.00% 25.00% Per ISO-NE Staff 22 6514 Networking - Hardware Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 23 6516 Communications Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 24 6550 Data Communications Support Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 25 6602 Help Desk Support Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 26 6615 Host Computer Monitoring Alloc-Fixed 100.00% 0.00% 50.00% 50.00% Per ISO-NE Staff 27 6616 Desktop Support Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 28 6617 System Administration - Unix Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 29 6618 System Administration - Windows Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 30 6619 Systems Support Misc Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 31 6620 Systems Support - Security Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 32 6621 Network Support Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 33 6622 Network/Systems Compliance Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 34 6623 Asset Management Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 35 36 212 IT Cyber Security 37 6539 Policy/Procedures Program Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 38 6540 Security Compliance and Reporting Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 39 6540A Controls Assessment Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 40 6540B Virus/Malware Reporting and Response Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 41 6540D Intrusion Monitoring and Response Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 42 6540E System Compliance Enhancement Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 43 6541 Security SW Tools Program Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 44 6543 Critical Infrastructure Protection WG (NERC) Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 45 6544 Infragrad (FBI) Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 46 6546 Internal Audit Support Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 47 6547 Security Training Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 48 6548 CIP Compliance & Monitoring Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 49 50 211 IT Enterprise Applications Support 51 21801 Software Support - Settlements Alloc-Fixed 100.00% 0.00% 80.00% 20.00% Per ISO-NE Staff 52 21802 Software Support - Publishing Alloc-Fixed 100.00% 0.00% 80.00% 20.00% Per ISO-NE Staff 53 21803 Software Support - Finance Alloc-Fixed 100.00% 0.00% 80.00% 20.00% Per ISO-NE Staff 54 21804 Software Support - Mitigation Alloc-Fixed 100.00% 0.00% 80.00% 20.00% Per ISO-NE Staff 55 21805 Software Support - TSO Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 56 21806 Software Support - Enterprise Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 57 21807 Software Support - Planning Alloc-Fixed 100.00% 0.00% 80.00% 20.00% Per ISO-NE Staff 58 21808 Training Delivery to NON-IT Alloc-Fixed 100.00% 0.00% 80.00% 20.00% Per ISO-NE Staff 59 21809 Tools Alloc-Fixed 100.00% 0.00% 80.00% 20.00% Per ISO-NE Staff 60 21811 Single Sign On Support Alloc-Fixed 100.00% 0.00% 80.00% 20.00% Per ISO-NE Staff 61 21816 CMS Support Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 62 21818 Discoverer Support Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 63 21819 Ceridian Support Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 64 21821 Compliance Management Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 65 6571 DBA Support - MOPS Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 66 21706 IT Markets Software Development - Enterprise Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 67 6591 Data Architect - MOPS Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 68 6594 IT Data Analyst Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 69 6595 IT WEB Application Support Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 70 6596 IT Data Governance Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 71 72 102 IT Energy Management Systems 73 21600 Indirect Supervision and Administration Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 74 21601 Power System Modeling Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 75 21603 Applications Support Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 76 21604 DTS Support Alloc-Fixed 100.00% 80.00% 20.00% 0.00% Per ISO-NE Staff 77 21605 DAM Support Alloc-Fixed 100.00% 20.00% 60.00% 20.00% Per ISO-NE Staff 78 21606 Real-time Market Support Alloc-Fixed 100.00% 20.00% 60.00% 20.00% Per ISO-NE Staff 79 21607 Forecast Support Alloc-Fixed 100.00% 20.00% 60.00% 20.00% Per ISO-NE Staff ISO NEW ENGLAND INC. Exhibit 3 (RCL-3) FERC DOCKET NO. ER16-___-000 Schedule 5.0 ALLOCATION FACTORS BY COST CATEGORY Page 7 of 7 TEST YEAR 2016
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)
1 210 IT Change Management 2 22501 Change Management Support Alloc-Fixed 100.00% 45.00% 45.00% 10.00% Per ISO-NE Staff 3 22505 Administrative Alloc-Fixed 100.00% 34.00% 33.00% 33.00% Per ISO-NE Staff 4 5 213 IT Enterprise Applications Development 6 21702 IT Corporate Application Support Alloc-Fixed 100.00% 0.00% 20.00% 80.00% Per ISO-NE Staff 7 21707 Application Analysis and Conceptual Design Alloc-Fixed 100.00% 0.00% 80.00% 20.00% Per ISO-NE Staff 8 21709 Technology Evaluation and Selection Alloc-Fixed 100.00% 0.00% 80.00% 20.00% Per ISO-NE Staff 9 21710 Indirect Supervision and Administration Alloc-Fixed 100.00% 0.00% 80.00% 20.00% Per ISO-NE Staff 10 21711 EWR and CAPA Analysis Alloc-Fixed 100.00% 0.00% 80.00% 20.00% Per ISO-NE Staff 11 6518 Employee Development - Software Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 12 13 216 IT Power System Modeling Management 14 21650 Indirect Supervision and Administration Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 15 21651 Power System Modeling Alloc-Fixed 100.00% 40.00% 40.00% 20.00% Per ISO-NE Staff 16 21652 System Application Support Alloc-Fixed 100.00% 40.00% 40.00% 20.00% Per ISO-NE Staff 17 21654 NX9 Administration Alloc-Fixed 100.00% 40.00% 40.00% 20.00% Per ISO-NE Staff 18 21655 ICCP Support Alloc-Fixed 100.00% 40.00% 40.00% 20.00% Per ISO-NE Staff 19 21656 Transmission Project Management Alloc-Fixed 100.00% 80.00% 20.00% 0.00% Per ISO-NE Staff 20 21657 Model On Demand Admin Alloc-Fixed 100.00% 0.00% 0.00% 100.00% Per ISO-NE Staff 21 21658 Model on Demand Case Requests Alloc-Fixed 100.00% 0.00% 0.00% 100.00% Per ISO-NE Staff 22 23 703 Reliability and Operations Compliance 24 14801 Compliance Monitoring Alloc-Fixed 100.00% 40.00% 40.00% 20.00% Per ISO-NE Staff 25 14803 Regional Committee Support OS Labor 100.00% 50.00% 0.00% 50.00% Per ISO-NE Staff 26 14804 National Committee Support OS Labor 100.00% 50.00% 0.00% 50.00% Per ISO-NE Staff 27 14806 Employee Development Alloc-Fixed 100.00% 55.55% 19.33% 25.12% Per ISO-NE Staff 28 14808 Change Management Alloc-Fixed 100.00% 45.00% 10.00% 45.00% Per ISO-NE Staff 29 14809 Tariff Compliance Alloc-Fixed 100.00% 30.00% 60.00% 10.00% Per ISO-NE Staff 30 14810 NERC Self Certifications Alloc-Fixed 100.00% 85.00% 0.00% 15.00% Per ISO-NE Staff 31 14812 NPCC MP Referral Alloc-Fixed 100.00% 40.00% 40.00% 20.00% Per ISO-NE Staff 32 14813 ICP Policy/Procedure Alloc-Fixed 100.00% 40.00% 40.00% 20.00% Per ISO-NE Staff 33 14814 Compliance Risk Assessment Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff 34 14815 Identifications and Description of Internal Controls Total Dir Labor 100.00% 21.55% 51.75% 26.70% Per ISO-NE Staff Exhibit 3 (RCL-3) Schedule 6.0 ISO NEW ENGLAND INC. Page 1 of 2 FERC Docket No. ER16-____-000 ALLOCATION ON DEPRECIATION AND AMORTIZATION EXPENSE TEST YEAR 2016
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 2016 Items: 2 Building Improvements $ - $ - $ - $ - $ - $ - $ - 3 Back-up Control Center ------4 Furniture, Fixtures, and Equipment 250,000.00 - 250,000 250,000 53,875.00 129,375.00 66,750.00 5 Non-Project Capital Spending (Hardware and Software) 455,472.23 - 455,472 455,472 98,154.26 235,706.88 121,611.08 6 Market Systems and Enhancement Projects 535,334 - 535,334 535,334 81,228.17 200,774.13 253,331.92 7 Non-Market Systems and Enhancement Projects ------8 Total 2016 Items - $ $ 1,240,806 $ - $ 1,240,806 $ 1,240,806 $ 233,257 $ 565,856 $ 441,693 9 Total 2016 Items - % 100.00% 18.80% 45.60% 35.60% 1 2015 Items: 2 Building Improvements $ 4,895 $ - $ 4,895 $ 4,895 $ 1,055 $ 2,533 $ 1,307 3 Back-up Control Center 29,237 - 29,237 29,237 6,300.61 15,130.25 7,806.33 4 Furniture, Fixtures, and Equipment 621,694 - 621,694 621,694 133,975.00 321,726.50 165,992.22 5 Non-Project Capital Spending (Hardware and Software) 8,105,314 - 8,105,314 8,105,314 2,822,043.91 3,490,220.03 1,793,049.69 6 Market Systems and Enhancement Projects 1,499,330 - 1,499,330 1,499,330 543,387.71 721,925.46 234,017.30 7 Non-Market Systems and Enhancement Projects ------8 Total 2015 Items - $ $ 10,260,470 $ - $ 10,260,470 $ 10,260,470 $ 3,506,762 $ 4,551,536 $ 2,202,173 9 Total 2015 Items - % 100.00% 34.18% 44.36% 21.46% 10 2014 Items: 11 Building Improvements $ 18,243 $ - $ 18,243 $ 18,243 $ 3,931 $ 9,441 $ 4,871 12 Back-up Control Center 234,329 - 234,329 234,329 50,498 121,265 62,566 13 Furniture, Fixtures, and Equipment 71,660 - 71,660 71,660 15,443 37,084 19,133 14 Non-Project Capital Spending (Hardware and Software) 1,480,659 - 1,480,659 1,480,659 319,082 766,241 395,336 15 Market Systems and Enhancement Projects 5,536,872 - 5,536,872 5,536,872 1,451,809 1,729,241 2,355,822 16 Non-Market Systems and Enhancement Projects 904,949 - 904,949 904,949 276,814 242,139 385,996 17 Total 2014 Items - $ $ 8,246,713 $ - $ 8,246,713 $ 8,246,713 $ 2,117,577 $ 2,905,411 $ 3,223,724 18 Total 2014 Items - % 100.00% 25.68% 35.23% 39.09% 19 2013 Items: 20 Building Improvements $ 21,402 $ - $ 21,402 $ 21,402 $ 4,612 $ 11,076 $ 5,714 21 Back-up Control Center 935,877 - 935,877 935,877 201,681 484,316 249,879 22 Furniture, Fixtures, and Equipment 148,566 - 148,566 148,566 32,016 76,883 39,667 23 Non-Project Capital Spending (Hardware and Software) 1,183,562 - 1,183,562 1,183,562 255,058 612,493 316,011 24 Market Systems and Enhancement Projects 4,357,464 - 4,357,464 4,357,464 816,311 1,934,893 1,606,260 25 Non-Market Systems and Enhancement Projects 1,787,497 - 1,787,497 1,787,497 394,239 559,996 833,263 26 Total 2013 Items - $ $ 8,434,369 $ - $ 8,434,369 $ 8,434,369 $ 1,703,917 $ 3,679,657 $ 3,050,794 27 Total 2013 Items - % 100.00% 20.20% 43.63% 36.17% 28 29 2012 Items: 30 Building Improvements $ 20,450 $ - $ 20,450 $ 20,450 $ 4,407 $ 10,583 $ 5,460 31 Back-up Control Center 159,069 - 159,069 159,069 34,279 82,318 42,472 32 Furniture, Fixtures, and Equipment 1,629 - 1,629 1,629 351 843 435 33 Non-Project Capital Spending (Hardware and Software) 35,392 - 35,392 35,392 7,627 18,315 9,450 34 Market Systems and Enhancement Projects 1,409,941 - 1,409,941 1,409,941 276,628 589,505 543,808 35 Non-Market Systems and Enhancement Projects 745,866 - 745,866 745,866 250,157 176,670 319,040 36 Total 2012 Items - $ $ 2,372,346 $ - $ 2,372,346 $ 2,372,346 $ 573,449 $ 878,234 $ 920,664 37 Total 2012 Items - % 100.00% 24.17% 37.02% 38.81% 38 39 2011 Items: 40 Facilities Project $ 40,667 $ - $ 40,667 $ 40,667 $ 8,764 $ 21,045 $ 10,858 41 Furniture, Fixtures, and Equipment 4,031 4,031 4,031 869 2,086 1,076 42 Non-Project Capital Spending (Hardware and Software) ------43 Market Systems and Enhancement Projects 155,689 - 155,689 155,689 1,439 67,415 86,835 44 Non-Market Systems and Enhancement Projects 419,185 - 419,185 419,185 140,253 126,127 152,805 45 Total 2011 Items - $ $ 619,573 $ - $ 619,573 $ 619,573 $ 151,324 $ 216,674 $ 251,575 46 Total 2011 Items - % 100.00% 24.42% 34.97% 40.60% 47 48 2010 Items: 49 Facilities Project $ 7,715 $ - $ 7,715 $ 7,715 $ 1,663 $ 3,993 $ 2,060 50 Furniture, Fixtures, and Equipment 1,537 1,537 1,537 331 796 410 51 Non-Project Capital Spending (Hardware and Software) ------52 Market Systems and Enhancement Projects 2,508 - 2,508 2,508 2,189 287 32 53 Non-Market Systems and Enhancement Projects 91,430 - 91,430 91,430 20,290 46,248 24,892 54 Total 2010 Items - $ $ 103,190 $ - $ 103,190 $ 103,190 $ 24,473 $ 51,323 $ 27,395 55 Total 2010 Items - % 100.00% 23.72% 49.74% 26.55% 56 57 2009 Items: 58 Facilities Project $ 7,100 $ - $ 7,100 $ 7,100 $ 1,530 $ 3,674 $ 1,896 59 Furniture, Fixtures, and Equipment 616 616 616 133 319 165 60 Non-Project Capital Spending (Hardware and Software) 313 - 313 313 67 162 83 61 Market Systems and Enhancement Projects 3,425 - 3,425 3,425 3,425 - - 62 Non-Market Systems and Enhancement Projects ------63 Total 2009 Items - $ $ 11,454 $ - $ 11,454 $ 11,454 $ 5,155 $ 4,155 $ 2,144 64 Total 2009 Items - % 100.00% 45.01% 36.28% 18.72% Exhibit 3 (RCL-3) Schedule 6.0 ISO NEW ENGLAND INC. Page 2 of 2 FERC Docket No. ER16-____-000 ALLOCATION ON DEPRECIATION AND AMORTIZATION EXPENSE TEST YEAR 2016
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 2008 Items: 3 Facilities Project $ 10,373 $ - $ 10,373 $ 10,373 $ 2,235 $ 5,368 $ 2,770 4 Furniture, Fixtures, and Equipment ------5 Non-Project Capital Spending (Hardware and Software) ------6 Market Systems and Enhancement Projects 4,652 - 4,652 4,652 4,652 - - 7 Non-Market Systems and Enhancement Projects ------8 Total 2008 Items - $ $ 15,026 $ - $ 15,026 $ 15,026 $ 6,888 $ 5,368 $ 2,770 9 Total 2008 Items - % 100.00% 45.84% 35.73% 18.43% 10 11 2007 Items: 12 Facilities Project $ 162,196 $ - $ 162,196 $ 162,196 $ 34,953 $ 83,936 $ 43,306 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 2007 Items - $ $ 162,196 $ - $ 162,196 $ 162,196 $ 34,953 $ 83,936 $ 43,306 18 Total 2007 Items - % 100.00% 21.55% 51.75% 26.70% 19 20 2006 Items: 21 Facilities Project $ 570,733 $ - $ 570,733 $ 570,733 $ 122,993 $ 295,355 $ 152,386 22 Furniture, Fixtures, and Equipment ------23 Non-Project Capital Spending (Hardware and Software) ------24 Market Systems and Enhancement Projects ------25 Non-Market Systems and Enhancement Projects ------26 Total 2006 Items - $ $ 570,733 $ - $ 570,733 $ 570,733 $ 122,993 $ 295,355 $ 152,386 27 Total 2006 Items - % 100.00% 21.55% 51.75% 26.70% 28 29 2005 Items: 30 Building/property improv. (Renov. workspace, network & voice rewiring) $ 787,995 $ - $ 787,995 $ 787,995 $ 169,813 $ 407,787 $ 210,395 31 Enhancements to Other Existing Market Systems ------32 Hardware and Software Upgrades to existing Non Market Systems ------33 Capital Interest/Fees 14,622 - 14,622 14,622 - 9,577 5,044 34 Internal Development Costs ------35 Amortization of Reg Asset ------36 Total 2005 Items - $ $ 802,617 $ - $ 802,617 $ 802,617 $ 169,813 $ 417,365 $ 215,439 37 Total 2005 Items - % 100.00% 21.16% 52.00% 26.84% 38 39 2004 Items: 40 Building/property improv. (Renov. workspace, network & voice rewiring) $ 41,709 $ - $ 41,709 $ 41,709 $ 8,988 $ 21,585 $ 11,136 41 Enhancements to Other Existing Market Systems ------42 Hardware and Software Upgrades to existing Non Market Systems ------43 Internal Development Costs ------44 Capital Interest/Fees 1,451 - 1,451 1,451 - 950 501 45 Total 2004 Items - $ $ 43,160 $ - $ 43,160 $ 43,160 $ 8,988 $ 22,535 $ 11,637 46 Total 2004 Items - % 100.00% 20.83% 52.21% 26.96% 47 48 Total Budgeted Depreciation $ 32,882,653 $ - $ 32,882,653 $ 32,882,653 $ 8,659,550 $ 13,677,404 $ 10,545,700 49 - % 100.00% 26.33% 41.59% 32.07% Exhibit 3 RCL-5 Schedule 1 ISO NEW ENGLAND INC. 2016 Operating Expense Budget
Line No. Cost Category Amount (a) (b)
1 Revenues and Other Income $ (440,506) 2 Salaries and Overhead 106,088,741 3 Professional Fees & Consultants 12,053,010 4 Building Services 2,858,616 5 Rents/Leases 1,142,220 6 Communication Expenses 2,190,173 7 Computer Services 11,453,790 8 Data Services and Office Expenses 1,349,684 9 NPCC/NERC Dues 5,892,615 10 Insurance Expense 2,200,809 11 Meetings & Related Expenses 1,486,708 12 Education & Training 1,222,510 13 Regulatory Fees, Taxes, and Licenses 321,886 14 CEO Emerging Work Allowance 1,100,000 15 Operating Contingency 700,000 16 Net Expense before Depreciation and Debt Service 149,620,256 17 18 Depreciation and Debt Service 35,530,965 19 20 Total Operating Expense Budget $ 185,151,221 Exhibit 3 RCL - 5 Schedule 2 ISO New England Inc. Page 1 2016 Operating Expense Budget
Line No. Revenues and Other Income 1 Interest income (82,378) 2 Includes fees for Participant training seminars and materials (253,728) 3 Purchase Discounts (104,400) 4 $ (440,506) 5 Salaries and Overhead 6 Salaries 78,266,951 7 Payroll Taxes and Employee Benefits 26,651,380 8 Board Fees and Expenses 1,170,410 9 106,088,741 10 Professional Fees and Consultants 11 Consulting Information Technology support for market system and Energy Management 12 System daily operations, Network and Desktop Support, Architecture planning, 2,810,514 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, and 1,783,600 Improved Tools & Optimization.
Resource Adequacy (including Forward Capacity Market Analytical & Auction Work and Load Forecasting), Transmission Planning (including OATT/Generation Interconnection Work & Project Planning, Elective 14 1,886,636 Transmission Upgrade Process, Short Circuit Analysis, and Bulk Power System Testing & Investigation), Operations Project Support (including Integration of Variable Resources), Operations, and Operations Planning.
15 Human Resource Consulting and Recruiting Services 1,462,260 16 Legal fees 1,810,000
Includes legal fees for OATT, regulatory filings, energy markets, market rules and proceedings, Market Monitoring Support, Siting costs, billing disputes, new 17 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 746,000 21 Auditors fees - SSAE Type 16 Audit, Network, Operations, Financial, Pension 700,300 22 Risk and Quality Management and Reliability and Operations Compliance 58,200 23 Finance Support and Payroll Service, Misc Other 163,492 24 12,053,010 25 Building Services 26 Repairs and maintenance 318,066 27 Utilities 1,456,500 Exhibit 3 RCL - 5 Schedule 2 ISO New England Inc. Page 2 2016 Operating Expense Budget
28 Miscellaneous (grounds keeping, supplies, building security) 1,084,050 29 2,858,616 30 Rents/Leases 31 Various office equipment leases 1,082,577 32 Auto leases and Auto Maintenance 59,643 33 1,142,220 34 Communications Expenses 35 Shared microwave 228,600 36 Network circuits and Internet circuits 883,528 37 Telephone and long distance lines 775,664 38 Miscellaneous maintenance and service items 302,381 39 2,190,173 40 Computer Services 41 Software and licensing costs 1,641,550 42 Maintenance contracts 9,646,040 43 Computer supplies 166,200 44 11,453,790 45 Data Services and Office expenses 46 Office supplies 113,429 47 Postage and courier 41,000 48 Printing Expense 118,425 49 Data Services, Dues, and subscriptions 951,965 50 Office equipment maintenance 100,000 51 Other Miscellaneous 24,865 52 1,349,684 53 54 NPCC/NERC Dues 55 Budget for NPCC and NERC Dues 5,822,615 56 Eastern Interconnect Data Sharing Network Allocation/Dues 70,000 57 5,892,615 58 59 Insurance Expense 60 Property and liability (including Cyber Security) 1,862,925 61 Directors and officers 337,884 62 2,200,809 63 64 Meetings & Related Expenses 1,486,708 Includes travel and related expenses for stakeholder meetings throughout the region, for regulatory meetings and support including 65 FERC, NERC, NPCC, and state agencies, and for attendance at Industry and Other Conference attendance, in addition to other miscellaneous travel reimbursement and employee service recognition Exhibit 3 RCL - 5 Schedule 2 ISO New England Inc. Page 3 2016 Operating Expense Budget
66 67 Education & Training 1,222,510 Includes funding for Enterprise wide training including Leadership and Management Development, Cyber Security Degree Program, Technical 68 and NERC Certification Training, Communications and Presentation 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 81,886 73 321,886 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 32,997,050 83 Interest expense 2,533,915 84 35,530,965 85 86 Total Operating Expense Budget $ 185,151,221 Exhibit 3 RCL-5 Schedule 3 ISO New England Inc. Operating Expense Budget Variance Summary Proposed Year 2016 Budget vs 2015 Budget (amounts in thousands)
Proposed Variance 2016 Annual Budget Original 2015 Budget vs 2015 Line No. DESCRIPTION 2016 Budget Budget Inc/(Decrease)
1 Revenues and Other Income $ (440.5) $ (445.8) $ 5.3 2 Salaries and Overhead 106,088.7 102,300.2 3,788.6 3 Professional Fees & Consultants 12,053.0 12,627.5 (574.5) 4 Building Services 2,858.6 2,983.6 (125.0) 5 Rents/Leases 1,142.2 1,032.2 110.0 6 Communication Expenses 2,190.2 2,037.7 152.5 7 Computer Services 11,453.8 9,733.2 1,720.6 8 Data Services and Office Expenses 1,349.7 1,263.9 85.8 9 NPCC/NERC Dues 5,892.6 5,775.9 116.7 10 Insurance Expense 2,200.8 2,007.6 193.2 11 Meetings & Related Expenses 1,486.7 1,540.5 (53.8) 12 Education & Training 1,222.5 1,207.2 15.3 13 Regulatory Fees, Taxes, and Licenses 321.9 360.3 (38.4) 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 149,620.3 144,224.1 5,396.1 17 18 Depreciation and Debt Service 35,531.0 34,090.7 1,440.2 19 20 Total Operating Expense Budget $ 185,151.2 $ 178,314.9 $ 6,836.3 ISO NEW ENGLAND INC. Change in Operating Expense Budgets Proposed Year 2016 Budget vs. 2015 Budget Exhibit 3 (Amounts in thousands) RCL-5 Line No. Schedule 4 1 Revenues and Other Income Page 1 2 Interest Income 28.5 3 Participant Market Training Fees (23.3) 4 Purchase Discounts - 5 Total change in Revenues and Other Income $ 5.3 6 7 Salaries and Overhead 8 Merit and Promotion 3,186.0 9 Net Increase of 8.5 Additional Staff 1,060.0 10 Health Plan Rate Increase 382.6 Post Retirement Benefit and Pension Costs 300.3 11 Other (includes Increase in Internal Capital Development and Salary Rate Changes) (1,140.3) 12 Total change in Salaries and Overhead 3,788.6 13 14 Professional Fees and Consultants Legal - Reduction due to less reliance on external counsel and absorbtion of work by internal 15 (500.0) counsel Transmission Strategy & Services - FERC Order 1000 $(265)K, $(72.8) absorption by 16 (337.8) internal staff.
Chief Operating Officer Admin - Impact Analysis $(100)K, Cyber Security $90K, and Other 17 (210.0) Strategic Initiatives related funding $(200)K
Operations Support Services - Post-MPRP (Maine Power Reliability Program) out-study work 18 (200.0) $(200)K
19 Market Operations Support Services - all consultant hours and fees absorbed by internal staff (168.5)
20 Cyber Security - reduction in consulting for NERC CIP v5 Transition (128.2)
Enterprise Risk Management - Information Governance Program Design completed by 21 (61.0) internal staff in 2015
Market Monitoring - review of Offer Review Trigger Prices (ORTP) which is reuiqred once 22 446.0 each three years $250K, Internal Market Monitor (IMM) Data Infrastruture $150K, Other $46K
IT Power System Modeling Management - increase for Model On Demand consultant 23 202.3 $172.3K and NX9/NX12 Support $30K
24 Resource Adequacy - Calculation of CONE and Net CONE for FCA12 150.0
Market Development Admin - $75K for FCM Qualification Process Changes and $50K for 25 125.0 FCA Pricing Rules Analysis
26 Operations - increase in consulting related to NERC Std. PER-005-2 (training). 117.0
27 Other minor changes (9.3)
28 Total change in Professional Fees and Consultants (574.5) 29
The primary change in the building services budget is a reduction in building security costs at the Backup Control Center of $(185)K. The original plan was to utilize the local police force 30 Building Services (125.0) but a private security firm was ultimately employed. Offsetting this reduction is increased utility costs of $36.5K. Other miscellaneous repair and maintenance increases equal $23.5K.
31 The increase for 2016 is related to the expansion of the leasing program to replace old 32 Rents/Leases 110.0 laptops, desktops, and monitors. 33 ISO NEW ENGLAND INC. Change in Operating Expense Budgets Proposed Year 2016 Budget vs. 2015 Budget Exhibit 3 (Amounts in thousands) RCL-5 Line No. Schedule 4 Increases include $106K for maintenance and support on new Control Room phone systems Page 2 34 Communication Expenses for both the Backup Control Center and Main Control Center, $33K for SIDU circuits for which 152.5 charge back to LCC's ended June 2015, and $12.6K for Shared Microwave. 35 The change in costs for Computer Services include inflationary increases and new software maintenance as a result of software upgrades or enhancements completed, or will be completed in 2015, of $599.4K (NetMRI/Infobox, Load Balancer, Smartnet Support, Citrix Open Licenses, Net Scaler, EMC VPLEX (for BCP Phase III Markets), increased Microsoft 36 Computer Services 1,720.6 product pricing due to the elimination of "Charity Pricing" $530.7K, new IT Asset & License Management software (Aspera) and consulting services to address Cyber Security initiatives $347.6K, upgraded backup manager software $169.5K, licenses for intranet upgrade and additional SAS licenses $124.5K. Other $(51.1)K 37
Increases in Dues & Subscriptions include $50K in Market Monitoring for FCM Capacity Price 38 Data Services and Office Expenses Forecast subscriptions, and $35.8K for various other small dollar increases and inflationary 85.8 items.
39 Primarliy due to pass through of increases in NPCC and NERC budgets of $112K plus a 40 NPCC/NERC Dues 116.7 small increase in Eastern Interconnect Data Sharing Network fees. 41 42 Insurance Expense Funding for Cyber Insurance of $200K, Other $(6.8)K 193.2 43
44 Meetings & Related Expenses Costs are essentially flat with minor decreases in travel in various departments (53.8)
45 46 Education & Training Costs are essentially flat with various adjustments in company training programs. 15.3 47 Regulatory Fees, Taxes, and 48 Expected decrease in bank fees. (38.4) Licenses 49 50 Total Change in Net Expense before Depreciation and Debt Service $ 5,396.2 51
Increases include Generation Control Application Phase I and Coordinated Transaction Scheduling projects expected to be completed in the fourth quarter of 2015, Wind Integration Phase II / Do Not Exceed (DNE) Dispatch project expected to go live in the first quarter of 2016, the Business Continuity Plan Infrastructure Enhancements Phase III – Markets Infrastructure and Remote Desktop projects (Q4 2015), Critical Infrastructure Protection 52 Depreciation and Debt Service 1,232.3 (CIP) v5 project (Q4 2015), Forward Capacity Auction (FCA) 10 (Q1 2016), and other various projects. These increases were partially offset by assets becoming fully depreciated in 2015 or 2016, and include the Energy Management System 2.6 Upgrade, Synchrophasor Infrastructure and Data Utilization, Forward Capacity Market Enhancements 2012, Financial Transmission Rights Multi-Round and Balancing Monthly Auctions, and other various projects
Increase for fees and interest expense for the line of credit needed for clearing Financial Transmission Rights through the clearinghouse; partially offset by a reduction in fees and 53 Interest Expense 207.9 expense due to a lower outstanding amount of tax-exempt debt as principal payments are made quarterly. 54 Total Depreciation and Debt Service 1,440.2 55 56 Total Change in Operating Expense Budget $ 6,836.3 Exhibit 3 RCL - 5 ISO NEW ENGLAND INC. Schedule 5 Staffing Projections Page 1
2015 Budget 2016 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 32.0 6 System Operations Support 8.0 8.0 7 System Operations 103.0 104.0 8 9 Resource Adequacy 24.0 23.0 10 Transmission Planning 19.0 17.0 11 Transmission Strategy & Services 9.0 11.0 12 System Planning 8.0 10.0 13 Reliability and Operations Services 3.0 2.0 14 System Planning 63.0 63.0 15 16 Customer Service and Training 14.0 13.0 17 Markets Operations Administration 6.0 6.0 18 Market Operations Support Services 13.0 14.0 19 Settlements 20.0 20.0 20 Market Operations 25.0 25.0 21 Market Operations 78.0 78.0 22 23 Mkt Development Admin 5.0 5.0 24 Markets Committee Relations & Rule Integration 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 27.0 27.0 30 Enterprise Applications Development 20.0 20.0 31 Cyber Security 7.0 13.0 32 Enterprise Applications Support 15.0 15.0 33 Systems/Network & Desktop 37.0 37.0 34 IT Management 6.0 6.0 35 IT System Testing 2.0 2.0 36 Power System Modeling Management 12.0 13.0 37 DB & Ent Support Services 21.0 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 155.0 162.0 42 43 Business Architecture and Technology 10.0 10.0 Exhibit 3 RCL - 5 ISO NEW ENGLAND INC. Schedule 5 Staffing Projections Page 2
2015 Budget 2016 Budget Line No. Department Staff Level Staff Level
44 Program Management 21.0 20.0 45 46 Total COO 459.0 466.0 47 48 Chief Executive Officer - Administration 9.0 9.0 49 50 Enterprise Risk Management 11.0 11.0 51 Building Services 3.0 4.0 52 Reliability, Operations, and Compliance 6.0 6.0 53 Finance 21.0 20.0 54 Finance and Compliance 41.0 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 4.0 63 64 Market Monitoring Assessment and Investigation 13.0 16.0 65 66 Internal Audits 5.0 5.0 67 68 Total Administration 117.0 119.0 69 70 Total FTE's 576.0 585.0 71 72 Total Part-timers (X @ 0.5) 1.0 0.5 73 74 Total Number of Employees 577.0 585.5
Note: Staffing levels are net of the estimated and budgeted vacancy. Exhibit 3 RCL - 5 Schedule 6 ISO New England Inc. 2016 Capital Budget
Line No. Description 2016
1 Capital Projects - Approved Charters 2 . Wind Integration Phase II / Do Not Exceed (DNE) Dispatch $ 2,472,000 3 . Divisional Accounting 496,800 4 . Forward Capacity Auction (FCA) 10 590,000 5 . Zonal Load Forecast 225,000 6 . Power System Modeling Management Initiatives 145,000 7 . NX9/NX12D - Generator Voltage Data 50,000 8 . Internet Explorer 11 Upgrade 12,000 9 Subtotal Projects with Approved Charters 3,990,800 10 Capital Projects in Conceptual Design 11 . Forward Capacity Auction (FCA) 11 3,000,000 12 . Sub-hourly Settlements 2,500,000 13 . Fast-Start Pricing 2,500,000 14 . Submission of Financial Transmission Rights (FTR) for Clearing 1,800,000 15 . 2016 Issues Resolution Project 1,500,000 16 . Expand Energy Offers for Pumps 900,000 17 . Quarterly Release Projects 2016 800,000 18 . Asset Characteristic Database & User Interface Re-design 700,000 19 . Energy Management Platform Customs Elimination 600,000 20 . Operations Document Management System 600,000 21 . Transmart Rewrite 500,000 22 . Web Enhancements 2016 500,000 23 . Asset Registration Automation 500,000 24 . Dynamic Interchange Adjustment Tool 300,000 25 . Oracle 12c Upgrade 100,000 26 . Case Snapshot Enhancements for Market Operator Interface 100,000 27 . Price Responsive Demand 100,000 28 . Other Emerging Work Projects 1,809,200 29 Subtotal Conceptual Design 18,809,200 30 . Non-Project Capital Expenditures 3,700,000 31 . Capitalized Interest and loan fees 500,000 32 TOTAL Capital Projects (including Capitalized Interest) $ 27,000,000 Exhibit 3 RCL-7 Schedule 1
ISO New England Inc. FERC DOCKET NO. ER16 -000 Development of Escalation Factors
From CELT Report (As Published) From Monthly Market Reports Monthly Peak Monthly Net Monthly Peak Monthly Net Data Source Data Source Month Load Energy 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 Peak Monthly Net Monthly Peak Monthly Net Data Source Data Source Month Load Energy 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 89 Dec-07 21,164 11,837 Actual 21,305 11,837 Actual From CELT Report (As Published) From Monthly Market Reports Monthly Peak Monthly Net Monthly Peak Monthly Net Data Source Data Source Month Load Energy Load Energy Line No. (MW) (GWH) (MW) (GWH) (a) (b) (c) (d) (e) (f) (g) (h)
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 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 From CELT Report (As Published) From Monthly Market Reports Monthly Peak Monthly Net Monthly Peak Monthly Net Data Source Data Source Month Load Energy Load Energy Line No. (MW) (GWH) (MW) (GWH) (a) (b) (c) (d) (e) (f) (g) (h)
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 21,453 11,500 Actual 21,453 11,500 Actual 162 Jan-14 21,334 12,022 Actual 21,334 12,022 Actual 163 Feb-14 19,654 10,468 Actual 19,654 10,468 Actual 164 Mar-14 19,696 11,037 Actual 19,696 11,037 Actual 165 Apr-14 16,011 9,452 Actual 16,011 9,452 Actual 166 May-14 16,222 9,463 Actual 16,222 9,463 Actual 167 Jun-14 21,263 10,400 Actual 21,263 10,400 Actual 168 Jul-14 24,443 12,244 Actual 24,443 12,244 Actual 169 Aug-14 22,694 11,229 Actual 22,694 11,229 Actual 170 Sep-14 23,715 10,236 Actual 23,715 10,236 Actual 171 Oct-14 17,053 9,710 Actual 17,053 9,710 Actual 172 Nov-14 18,369 9,968 Actual 18,369 9,968 Actual 173 Dec-14 19,812 10,926 Actual 19,843 10,945 Actual 174 Jan-15 20,556 11,713 Actual 20,583 11,732 Actual 175 Feb-15 20,070 11,015 Actual 20,108 11,032 Actual 176 Mar-15 19,635 11,524 Forecast 18,848 10,869 Actual 177 Apr-15 17,735 10,092 Forecast 16,455 9,239 Actual 178 May-15 19,905 10,440 Forecast 19,505 9,710 Actual 179 Jun-15 25,230 11,664 Forecast 20,895 10,146 Actual 180 Jul-15 28,251 13,357 Forecast 24,398 12,077 Actual 181 Aug-15 28,251 13,014 Forecast 28,251 13,014 Forecast 182 Sep-15 23,160 10,854 Forecast 23,160 10,854 Forecast 183 Oct-15 18,670 10,549 Forecast 18,670 10,549 Forecast 184 Nov-15 20,350 10,794 Forecast 20,350 10,794 Forecast 185 Dec-15 22,740 12,194 Forecast 22,740 12,194 Forecast 186 Jan-16 22,740 12,771 Forecast 22,740 12,771 Forecast 187 Feb-16 21,505 11,166 Forecast 21,505 11,166 Forecast 188 Mar-16 19,770 11,643 Forecast 19,770 11,643 Forecast 189 Apr-16 17,870 10,186 Forecast 17,870 10,186 Forecast From CELT Report (As Published) From Monthly Market Reports Monthly Peak Monthly Net Monthly Peak Monthly Net Data Source Data Source Month Load Energy Load Energy Line No. (MW) (GWH) (MW) (GWH) (a) (b) (c) (d) (e) (f) (g) (h)
190 May-16 20,008 10,539 Forecast 20,008 10,539 Forecast 191 Jun-16 25,463 11,777 Forecast 25,463 11,777 Forecast 192 Jul-16 28,673 13,489 Forecast 28,673 13,489 Forecast 193 Aug-16 28,673 13,143 Forecast 28,673 13,143 Forecast 194 Sep-16 23,338 10,960 Forecast 23,338 10,960 Forecast 195 Oct-16 18,770 10,661 Forecast 18,770 10,661 Forecast 194 Nov-16 20,500 10,912 Forecast 20,500 10,912 Forecast 195 Dec-16 22,920 12,336 Forecast 22,920 12,336 Forecast
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 21,264 129,377 21,264 129,377 16 2014 20,022 127,155 20,025 127,174 17 2015 22,046 137,210 21,164 132,210 18 2016 22,519 139,583 22,519 139,583 19 Annual Escalation 20 2002 1.0304 1.0117 1.0304 1.0117 21 2003 0.9961 1.0261 0.9961 1.0261 22 2004 1.0072 1.0133 1.0072 1.0133 23 2005 1.0308 1.0290 1.0309 1.0290 24 2006 0.9885 0.9687 0.9884 0.9687 25 2007 1.0309 1.0180 1.0314 1.0180 26 2008 0.9520 0.9797 0.9515 0.9798 27 2009 0.9521 0.9628 0.9521 0.9627 28 2010 1.0832 1.0310 1.0832 1.0310 29 2011 0.9562 0.9877 0.9562 0.9877 30 2012 0.9994 0.9916 0.9995 0.9916 31 2013 1.0404 1.0102 1.0404 1.0101 32 2014 0.9416 0.9828 0.9417 0.9830 33 2015 1.1011 1.0791 1.0569 1.0396 34 2016 1.0215 1.0173 1.0641 1.0558 35 1.009 1.007 NOT USED 36 Last Five Months of Calendar Year 37 Average Total Average Total 38 Dec-00 19,971 52,852 19,971 52,853 Actual 39 Dec-01 20,159 52,681 20,159 52,681 Actual From CELT Report (As Published) From Monthly Market Reports Monthly Peak Monthly Net Monthly Peak Monthly Net Data Source Data Source Month Load Energy Load Energy Line No. (MW) (GWH) (MW) (GWH) (a) (b) (c) (d) (e) (f) (g) (h)
40 Dec-02 21,341 54,554 21,341 54,555 Actual 41 Dec-03 20,299 54,844 20,299 54,843 Actual 42 Dec-04 20,877 55,469 20,877 55,469 Actual 43 Dec-05 21,688 57,593 21,696 57,594 Actual 44 Dec-06 20,996 54,499 20,995 54,500 Actual 45 Dec-07 21,669 56,412 21,694 56,412 Actual 46 Dec-08 20,492 54,050 20,494 54,055 Actual 47 Dec-09 19,870 53,722 19,870 53,721 Actual 48 Dec-10 21,745 54,548 21,745 54,548 Actual 49 Dec-11 19,621 53,120 19,621 53,120 Actual 50 Dec-12 20,156 53,725 20,159 53,735 Actual 51 Dec-13 20,917 53,200 20,917 53,200 Actual 52 Dec-14 20,329 52,069 20,335 52,088 Actual 53 Dec-15 22,634 57,405 22,634 57,405 Forecast 54 Escalation Used for Last Five Months of Calendar Year 55 Dec-01 1.0094 0.9967 Actual 56 Dec-02 1.0586 1.0356 Actual 57 Dec-03 0.9512 1.0053 Actual 58 Dec-04 1.0285 1.0114 Actual 59 Dec-05 1.0392 1.0383 Actual 60 Dec-06 0.9677 0.9463 Actual 61 Dec-07 1.0333 1.0351 Actual 62 Dec-08 0.9446 0.9582 Actual 63 Dec-09 0.9696 0.9938 Actual 64 Dec-10 1.0944 1.0154 Actual 65 Dec-11 0.9023 0.9738 Actual 66 Dec-12 1.0274 1.0116 Actual 67 Dec-13 1.0376 0.9900 Actual 68 Dec-14 0.9722 0.9791 Actual 69 Dec-15 1.1131 1.1021 Forecast 70 1.010 1.006 NOT USED Exhibit 3 RCL-7 Schedule 2
ISO New England Inc. FERC DOCKET NO. ER16 -000 Billing Determinants for Calendar Year 2015 and Test Year 2016 TEST YEAR 2016
Schedule 1 Schedule 2 Schedule 3 Financial Transmission Rights Network Load Transaction Units (TUs) Volumes (FTRs) Peak Volumes Export Line Data Month Cleared Electrical Load Volumes No. Source Submitted Submitted Cleared (kW) Energy TUs Virtual (GWH) (kW) (MWh) Virtual Energy FTR Bids FTR Bids Energy
(a) (b) (c) (d) (e) (f) (g) (h) (i) (j) (k) CALENDAR YEAR 2015 1 Jan-15 Actual 20,287,685 1,598,514 244,782 29,718 84,452 20,424 24,041,826 22,584,487 215,186 2 Feb-15 Actual 19,910,998 1,443,266 270,554 26,840 27,931 8,778 22,683,446 22,549,635 253,954 3 Mar-15 Actual 18,580,936 1,567,775 312,726 46,881 21,711 6,340 22,419,291 21,106,685 257,365 4 Apr-15 Actual 16,133,097 1,469,579 385,557 44,346 27,516 7,886 19,296,344 18,776,591 335,199 5 May-15 Actual 19,305,827 1,536,549 394,561 40,577 19,761 6,000 20,676,276 21,397,099 537,076 6 Jun-15 Actual 20,826,343 1,545,562 297,407 35,013 19,526 6,410 21,688,837 22,504,650 611,054 7 Jul-15 Actual 24,144,201 1,649,755 357,828 32,054 15,856 6,834 25,589,169 26,585,742 589,243 8 Aug-15 Est. 22,211,418 a 1,581,723 a 260,925 a 23,438 a 24,568 a 10,446 a 23,683,152 a 24,604,508 a 527,741 a 9 Sep-15 Est. 23,367,341 a 1,476,222 a 234,132 a 32,643 a 21,661 a 9,091 a 21,287,121 a 25,891,654 a 308,904 a 10 Oct-15 Est. 16,828,635 a 1,476,829 a 293,861 a 32,126 a 26,780 a 9,959 a 20,012,028 a 19,444,208 a 202,991 a 11 Nov-15 Est. 18,043,001 a 1,455,383 a 300,057 a 31,070 a 24,985 a 10,656 a 20,570,086 a 20,655,779 a 226,396 a 12 Dec-15 Est. 19,498,319 a 1,589,250 a 274,574 a 36,265 a 20,030 a 8,109 a 22,400,407 a 21,958,836 a 174,495 a 13 Totals 239,137,801 18,390,407 3,626,964 410,971 334,777 110,933 264,347,983 268,059,874 4,239,604 14 15 TEST YEAR 2016 16 Jan-16 Est. 20,267,397 b 1,545,763 c 244,782 a 29,718 a 84,452 a 20,424 a 23,681,199 d 22,810,332 e 140,947 f 17 Feb-16 Est. 19,891,087 b 1,395,638 c 270,554 a 26,840 a 27,931 a 8,778 a 22,343,195 d 22,775,131 e 166,340 f 18 Mar-16 Est. 18,562,355 b 1,516,038 c 312,726 a 46,881 a 21,711 a 6,340 a 22,083,001 d 21,317,752 e 168,574 f 19 Apr-16 Est. 16,116,964 b 1,421,083 c 385,557 a 44,346 a 27,516 a 7,886 a 19,006,899 d 18,964,357 e 219,555 f 20 May-16 Est. 19,286,521 b 1,485,843 c 394,561 a 40,577 a 19,761 a 6,000 a 20,366,132 d 21,611,070 e 351,785 f 21 Jun-16 Est. 20,805,517 b 1,494,558 c 297,407 a 35,013 a 19,526 a 6,410 a 21,363,505 d 22,729,697 e 400,240 f 22 Jul-16 Est. 24,120,057 b 1,595,313 c 357,828 a 32,054 a 15,856 a 6,834 a 25,205,332 d 26,851,599 e 385,954 f 23 Aug-16 Est. 22,189,207 b 1,529,526 c 260,925 a 23,438 a 24,568 a 10,446 a 23,327,905 d 24,850,553 e 345,670 f 24 Sep-16 Est. 23,343,974 b 1,427,507 c 234,132 a 32,643 a 21,661 a 9,091 a 20,967,814 d 26,150,571 e 202,332 f 25 Oct-16 Est. 16,811,806 b 1,428,094 c 293,861 a 32,126 a 26,780 a 9,959 a 19,711,847 d 19,638,650 e 132,959 f 26 Nov-16 Est. 18,024,958 b 1,407,355 c 300,057 a 31,070 a 24,985 a 10,656 a 20,261,534 d 20,862,337 e 148,289 f 27 Dec-16 Est. 19,478,821 b 1,536,805 c 274,574 a 36,265 a 20,030 a 8,109 a 22,064,401 d 22,178,424 e 114,294 f 28 Total 238,898,663 17,783,524 3,626,964 410,971 334,777 110,933 260,382,763 270,740,473 2,776,941
Escalation Factors a 1.000 b 0.999 c 0.967 d 0.985 e 1.010 f 0.655 Exhibit 3 RCL-7 Schedule 3
ISO NEW ENGLAND INC. FERC DOCKET NO. ER16 -000 Rate Design Summary TEST YEAR 2016
Revenue Billing Units Line Requirement for Proposed Rates Calculated Revenue Tariff Schedule No. Test Year 2016 Blocks Total (a) (b) (c) (d) (e) (f) (g) (d) x (e) 1 Schedule 1 $ 46,048,796 2 Network Total 238,898,663 $ 0.19275 /kW-mo. $ 46,048,796 3 Through or Out Service $ 0.00026 /kW-hour 4 5 Schedule 2 $ 82,373,310 6 Transaction Units $ 12,355,997 15.00% 7 INC Offers/DEC Bids $ 42,793 8 Submitted 3,626,964 $ 0.00500 /Offer or Bid $ 18,135 9 Cleared 410,971 $ 0.06000 /Offer or Bid $ 24,658 10 Total 4,037,935 $ 42,793 11 Financial Transmission Rights $ 970,196 12 Submitted FTR Bids $ 679,137 70% 334,777 $ 2.02863 /Bid $ 679,137 13 Cleared FTR Bids $ 291,059 30% 110,933 $ 2.62374 /Bid $ 291,059 14 Total 445,710 $ 970,196 15 16 Energy TUs $ 11,343,007 17 Block 1 First 12,500 12,158,008 $ 0.66437 /TU-hour $ 8,077,423 18 Block 2 Next 27,000 3,438,723 $ 0.60397 /TU-hour $ 2,076,896 19 Block 3 Over 39,500 2,186,793 $ 0.54358 /TU-hour $ 1,188,688 20 Total 17,783,524 $ 11,343,007 21 22 Volumetric Measures $ 70,017,314 85.00% 23 Block 1 First 250,000 133,352,189 $ 0.28296 /mWh $ 37,732,929 24 Block 2 Next 1,250,000 111,785,794 $ 0.25723 /mWh $ 28,755,062 25 Block 3 Over 1,500,000 15,244,780 $ 0.23151 /mWh $ 3,529,323 26 Total 260,382,763 $ 70,017,314 27 28 Total $ 82,373,310 29 30 Schedule 3 $ 56,107,371 31 RT NCP Load Obligation $ 54,996,595 Total 270,740,473 $ 0.20313 /kW-mo. $ 54,996,595 32 Exports $ 1,110,776 Total 2,776,941 $ 0.40000 /mWh $ 1,110,776 33 $ 56,107,371 34 35 Totals $ 184,529,477 $ 184,529,477 Exhibit 3 RCL-7 Schedule 4
ISO NEW ENGLAND INC. FERC DOCKET NO. ER16 -000 Annual Revenue Comparison at Present and Proposed Rates TEST YEAR 2016
Annual Revenue Analysis Line 2016 Billing Units 2015 Approved Rates 2016 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 238,898,663 $0.15570 /kW-mo. $ 37,196,522 $ 0.19275 /kW-mo. $ 46,048,796 $ 8,852,274 23.80% 3 4 Schedule 2 5 Transaction Units 6 INC Offers/DEC Bids 7 Submitted 3,626,964 $0.00500 /Offer or Bid $ 18,135 $ 0.00500 /Offer or Bid $ 18,135 8 Cleared 410,971 $0.06000 /Offer or Bid $ 24,658 $ 0.06000 /Offer or Bid $ 24,658 9 Total 4,037,935 $ 42,793 $ 42,793 10 Financial Transmission Rights 11 Submitted FTR Bids 334,777 $0.85853 /Bid $ 287,416 $ 2.02863 /Bid $ 679,137 12 Cleared FTR Bids 110,933 $1.21377 /Bid $ 134,647 $ 2.62374 /Bid $ 291,059 13 Total 445,710 $ 422,063 $ 970,196 14 15 Energy Transaction Units 16 Block 1 First 12,500 12,158,008 $0.65101 /TU-hour $ 7,914,985 $ 0.66437 /TU-hour $ 8,077,423 17 Block 2 Next 27,000 3,438,723 $0.59182 /TU-hour $ 2,035,105 $ 0.60397 /TU-hour $ 2,076,896 18 Block 3 Over 39,500 2,186,793 $0.53264 /TU-hour $ 1,164,773 $ 0.54358 /TU-hour $ 1,188,688 19 Total 17,783,524 $ 11,114,863 $ 11,343,007 20 Volumetric Measures 21 Block 1 First 250,000 133,352,189 $0.25517 /mWh $ 34,027,478 $ 0.28296 /mWh $ 37,732,929 22 Block 2 Next 1,250,000 111,785,794 $0.23197 /mWh $ 25,930,951 $ 0.25723 /mWh $ 28,755,062 23 Block 3 Over 1,500,000 15,244,780 $0.20877 /mWh $ 3,182,653 $ 0.23151 /mWh $ 3,529,323 24 Total 260,382,763 $ 63,141,081 $ 70,017,314 25 26 Total $ 74,720,801 $ 82,373,310 $ 7,652,509 10.24% 27 Schedule 3 28 RT NCP Load Obligation Total 270,740,473 $0.18763 /kW-mo. $ 50,799,035 $ 0.20313 /kW-mo. $ 54,996,595 29 Exports Total 2,776,941 $0.37000 /mWh $ 1,027,468 $ 0.40000 /mWh $ 1,110,776 30 $ 51,826,503 $ 56,107,371 $ 4,280,868 8.26% 31 32 Totals $ 163,743,826 $ 184,529,477 $ 20,785,651 12.69% Exhibit 3 RCL-7 Schedule 5
ISO NEW ENGLAND INC. FERC DOCKET NO. ER16 -000 Comparison of Schedule 2 Revenues from Transaction Units (TUs) for 2014 TEST YEAR 2016
Comparison Of Monthly TU Data For CY 2014 TUs Per ISO Tariff Filing for TY 2014 TUs Per ISO Tariff Filing for CY 2014 Line Source For TY First Next Over Source For First Next Over Month Total TUs Total TUs No. 2014 12500 27000 39500 TY 2016 12500 27000 39500 (a) (b) (c) (d) (e) (f) (g) (h) (i) (j) (k) Billing Determinants - Energy TUs 1 Jan-14 Jan-13 1,379,716 972,182 272,225 135,309 Actual 1,530,445 1,083,555 275,647 171,243 2 Feb-14 Feb-13 1,259,732 910,954 249,608 99,170 Actual 1,399,304 1,012,994 242,196 144,114 3 Mar-14 Mar-13 1,364,713 966,058 271,209 127,446 Actual 1,495,523 1,065,153 263,635 166,735 4 Apr-14 Apr-13 1,282,913 925,210 251,382 106,321 Actual 1,409,469 1,018,234 243,991 147,244 5 May-14 May-13 1,373,080 977,522 269,538 126,020 Actual 1,463,493 1,047,178 258,717 157,598 6 Jun-14 Jun-13 1,404,103 1,001,793 265,001 137,309 Actual 1,483,121 1,052,913 265,098 165,110 7 Jul-14 Jul-13 1,465,640 1,044,898 272,437 148,305 Actual 1,583,869 1,103,656 296,023 184,190 8 Aug-14 Aug-12 1,401,678 999,955 272,308 129,415 Actual 1,581,723 1,101,594 297,011 183,118 9 Sep-14 Sep-12 1,337,862 954,429 259,910 123,523 Actual 1,476,222 1,052,676 277,075 146,471 10 Oct-14 Oct-12 1,335,119 952,472 259,377 123,269 Actual 1,476,829 1,059,149 266,013 151,667 11 Nov-14 Nov-12 1,277,896 911,649 248,260 117,986 Actual 1,455,383 1,043,632 261,547 150,204 12 Dec-14 Dec-12 1,364,206 973,223 265,028 125,955 Actual 1,589,250 1,105,948 293,228 190,074 13 Totals 16,246,658 11,590,346 3,156,284 1,500,028 17,944,631 12,746,682 3,240,181 1,957,768 14 15 Totals 16,246,658 17,944,631 16 2014 Approved Rates for 17 Schedule 2 $0.73167 $0.66515 $0.59864 $0.73167 $0.66515 $0.59864 18 19 Initial Estimate of Revenue From Energy TUs 20 Jan-14 Jan-13 $ 973,388 $ 711,316 $ 181,070 $ 81,001 Actual $ 1,078,664 $ 792,805 $ 183,347 $ 102,513 21 Feb-14 Feb-13 $ 891,912 $ 666,518 $ 166,027 $ 59,367 Actual $ 988,546 $ 741,177 $ 161,097 $ 86,272 22 Mar-14 Mar-13 $ 963,525 $ 706,836 $ 180,395 $ 76,294 Actual $ 1,054,512 $ 779,340 $ 175,357 $ 99,814 23 Apr-14 Apr-13 $ 907,803 $ 676,948 $ 167,207 $ 63,648 Actual $ 995,448 $ 745,011 $ 162,291 $ 88,146 24 May-14 May-13 $ 969,947 $ 715,224 $ 179,283 $ 75,441 Actual $ 1,032,619 $ 766,189 $ 172,086 $ 94,344 25 Jun-14 Jun-13 $ 991,446 $ 732,982 $ 176,265 $ 82,199 Actual $ 1,045,556 $ 770,385 $ 176,330 $ 98,841 26 Jul-14 Jul-13 $ 1,034,513 $ 764,521 $ 181,211 $ 88,781 Actual $ 1,114,675 $ 807,512 $ 196,900 $ 110,264 27 Aug-14 Aug-12 $ 990,236 $ 731,637 $ 181,126 $ 77,473 Actual $ 1,113,182 $ 806,003 $ 197,557 $ 109,622 28 Sep-14 Sep-12 $ 945,152 $ 698,327 $ 172,879 $ 73,946 Actual $ 1,042,191 $ 770,211 $ 184,296 $ 87,683 29 Oct-14 Oct-12 $ 943,214 $ 696,895 $ 172,525 $ 73,794 Actual $ 1,042,680 $ 774,948 $ 176,939 $ 90,794 30 Nov-14 Nov-12 $ 902,788 $ 667,027 $ 165,130 $ 70,631 Actual $ 1,027,480 $ 763,594 $ 173,968 $ 89,918 31 Dec-14 Dec-12 $ 963,763 $ 712,078 $ 176,283 $ 75,402 Actual $ 1,118,015 $ 809,189 $ 195,041 $ 113,786 32 Totals $ 11,477,688 $ 8,480,309 $ 2,099,402 $ 897,977 $ 12,653,569 $ 9,326,365 $ 2,155,206 $ 1,171,998 33
Total Energy TU- Revenue $ 11,477,688 $ 12,653,569 34 35 Total Rate ($) Total Rate ($) 36 Submitted Virtual Energy Bids/Offers TUs 2,760,474 $0.00500 13,802 2,896,433 $0.00500 14,482 37 Cleared Virtual Energy Bids/Offers TUs 279,137 $0.06000 16,748 335,394 $0.06000 20,124 38 $ 30,551 $ 34,606 39 Total Rate ($) Total Rate ($) 40 Submitted FTR Bid TUs 331,175 $1.23712 409,701 449,377 $1.23712 555,933 41 Cleared FTR Bid TUs 99,327 $1.76776 175,586 144,431 $1.76776 255,319 42 $ 585,288 $ 811,253 43
Total Schedule 2 TU- Revenue $ 12,093,526 $ 13,499,428 44 45 True-Up - Over (Under) Recovery For Jan - Dec $ 1,405,902 Exhibit 3 RCL-7 Schedule 6
ISO NEW ENGLAND INC. FERC DOCKET NO. ER16- -000 Schedule 2 TU True-Up Summary TEST YEAR 2016
Line Total Schedule 2 TU No. Revenues % TU Difference 1 2 Final 2014 True-Up 3 2014 Final TU Collections $ 13,499,428 4 Projected TU Collections in TY 2014 Filing $ 12,093,526 5 Final Schedule 2 TU Over/(Under) Collection $ 1,405,902 11.63% 6 7 8 Initial Allocation to Volumetric 50% N/A - Over Collected 9 2014 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 $ 82,373,310 $ 12,355,997 $ 70,017,314 15 Allocated TU Under-recovery $ - $ - $ - 16 Total Revenue Requirement After True-Up $ 82,373,310 $ 12,355,997 $ 70,017,314 17 % Allocation 100.00% 15.00% 85.00% Exhibit 3 RCL-8
NEW ENGLAND POWER POOL PARTICIPANTS COMMITTEE MEETING
October 2, 2015
RESOLUTION REGARDING THE ISO 2016 BUDGET
RESOLVED, that the Participants Committee supports the Year 2016 operating budget and capital budget proposed by the ISO, as presented at this meeting.
EXHIBIT 4 ISO New England Inc. Recovery of 2016 Administrative Costs
UNITED STATES OF AMERICA
BEFORE THE
FEDERAL ENERGY REGULATORY COMMISSION
ISO New England Inc. ) Docket No. ER16-___-000
TESTIMONY
OF
JANICE S. DICKSTEIN
Filed on: October 16, 2015 ISO New England Inc. Recovery of 2016 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. ER16-___-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 2016 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 2016 administrative
12 expenses related to compensation.
13 Q: HOW IS YOUR TESTIMONY ORGANIZED?
14 A. My testimony is organized as follows:
15 • objective of compensation program
16 • components of compensation
17 • budget for merit and promotional salary increases
18 • framework for determining executive compensation ISO New England Inc. Recovery of 2016 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. The second challenge is that the most critical
14 functions within our organization, IT and engineering, are also the most difficult
15 to recruit for and retain.
16 Q. PLEASE DESCRIBE THE SHORTAGE OF CRITICAL TALENT IN THE
17 UTILITY INDUSTRY.
18 A. As documented by numerous studies over the past several years, the electric
19 industry workforce is considered to be the oldest aged workforce in the United
20 States, with close to 50% of the workforce eligible to retire in the next several
21 years. ISO New England Inc. Recovery of 2016 Administrative Costs Page 4
1 In January of 2012, the National Regulatory Research Institute wrote that “[t]he
2 energy industry is facing an impending workforce shortage. The shortage reflects
3 an unprecedented number of retirements expected to occur in the next decade,
4 coupled with increasing energy demand...” The U.S. Department of Labor
5 predicts that 500,000 energy industry workers will retire in the next decade, a
6 turnover rate of 50 percent. These statistics have been confirmed in a number of
7 more recent writings.
8 A February 2014 Congressional Research Report entitled “The U.S. Science and
9 Engineering Workforce: Recent, Current, and Projected Employment, Wages,
10 and Unemployment,” which was prepared for Members and Committees of
11 Congress, reported that, between 2008 and 2012, the employment growth for
12 computer science professionals and electric engineers exceeded that of the general
13 population. The research paper also projected that employment growth for this
14 same technical sector would exceed that of the general population through 2022.
15 In May of 2014, Forbes.com reported on the lack of skilled workers. Quoting
16 Manpower Group, Forbes.com stated that “[t]his dichotomy exists in a world
17 where jobs in the energy industry are expected to nearly double to 3 million by
18 2020. But its research says that 72 percent of energy employers are having
19 difficulty finding quality candidates to fill their positions. The reason for that is
20 because the experts are getting on and getting ready to retire while rapid
21 evolutions in technology are altering the way business is done.” ISO New England Inc. Recovery of 2016 Administrative Costs Page 5
1 And, in February of 2015, a U.S. News & World Report article reported that:
2 About half of the workforce in engineering and advanced manufacturing is 3 approaching retirement, and the growth in the percentage of young 4 workers is not keeping pace… In fact, the number of young STEM 5 workers has actually declined since 2001, said Claus von Zastrow, chief 6 operating officer and director of research for Change the Equation. “Since 7 2001, the percentage of non-STEM workers under the age of 25 has 8 increased by 1 percent… Meanwhile, the percentages of engineering and 9 computing workers under 25 have decreased by 25 percent and 15 10 percent….This is not because these jobs aren't available. Every other 11 indicator we have shows there's actually robust demand here…We're 12 going to need all the talent we can get – we're going to need all hands on 13 deck.…”
14 According to the U.S. News/Raytheon STEM Index, high school student 15 interest in STEM fields reached a low point in 2004, dropping nearly 19 16 percent from the base-year calculations. Interest levels climbed steadily 17 until 2009, when they began to decline again. In spite of the intense drive 18 to encourage students to study science, interest levels fell between 2009 19 and 2013 and are now just slightly below where they were in 2000.
20 Q. PLEASE DESCRIBE THE CHALLENGE IN RECRUITING FOR THE
21 MOST CRITICAL FUNCTIONS WITHIN THE ORGANIZATION (IT
22 AND ENGINEERING).
23 A. This theme was highlighted in both Mercer’s 2015/2016 U.S. Compensation
24 Planning survey and Aon Hewitt’s 2015 U.S. Salary Increase survey. Mercer
25 survey respondents cited losing top performers and the ability to afford their
26 replacements as the most pressing issue facing their organizations. Aon Hewitt
27 survey respondents reported the highest use of sign-on and retention bonus
28 programs for their IT and engineering positions. In addition to attraction and
29 retention pressures, starting salaries of new graduates in IT and engineering ISO New England Inc. Recovery of 2016 Administrative Costs Page 6
1 positions in the energy industry continue to be strong, as evidenced in Towers
2 Watson’s 2015 General Industry Salary Budget Survey. This report shows that
3 starting salaries of engineers ranged from $72,000 - $85,000 and IT professionals
4 from $61,000 - $75,000.
5 Additionally, the February 2014 Congressional Research Report cited above
6 stated that “[i]n 2012, the mean annual wage for all scientists and engineers
7 [S&E] was $87,330; the mean annual wage for all occupations – professional and
8 non-professional – was $45,790. S&E managers had the highest mean annual
9 wage of all S&E occupational groups at $130,660 followed by engineers,
10 $90,960….” The National Academy of Sciences wrote about this in its 2013
11 paper entitled “Emerging Workforce Trends in the US Energy and Mining
12 Industries: A Call to Action,” when it noted that “[o]ptions for finding additional
13 workers are limited, especially as other countries face the same shortages and
14 attempt to attract U.S. workers with higher pay.”
15 Q. HOW ARE THESE CHALLENGES MANIFESTING THEMSELVES?
16 A. These challenges are manifested in turnover in the ISO industry. While industry
17 turnover was trending downward in 2008 - 2010, due to the depressed national
18 economy, it has increased as companies have begun hiring again and as
19 employees, who had deferred their retirements during the economic downturn,
20 now begin to exit the workforce. To date in 2015, the ISO’s turnover is running
21 at 5.8%. While on par with 2014 full year turnover, it is up from 2013 turnover, ISO New England Inc. Recovery of 2016 Administrative Costs Page 7
1 and significantly higher than the turnover seen prior to that. Individuals who have
2 departed this year were primarily in information technology, engineering and
3 economist positions, from System Operations, System Planning, Market
4 Operations and Market Development, all areas that are critical to operating the
5 grid and running our markets. In addition, to date in 2015, nine ISO employees
6 have resigned for similar but higher paying jobs at other employers; and, in 2015
7 thus far, five candidates have declined ISO-NE job offers, stating that the
8 compensation was not sufficient.
9 Q. HOW DOES THE ISO MAINTAIN THE COMPETITIVENESS OF ITS
10 COMPENSATION?
11 A. The ISO first identifies the industries with which it competes for talent – in other
12 words, the industries from which the ISO recruits, and to which the ISO loses
13 employees. These are other ISOs and RTOs, for-profit utility companies, energy-
14 related consulting firms, and the broader industry (for positions not specific to
15 utilities).
16 Next, the ISO defines target ranges of compensation within these markets. For
17 non-exempt, non-union employees, the target market range of compensation is the
18 50th percentile of the local market. For both executives and middle management
19 and professionals, this target is the 50th to 75th percentile of the national market.
20 For middle management and professionals, the following factors led to the
21 determination of this target: nation-wide recruitment; national shortages of ISO New England Inc. Recovery of 2016 Administrative Costs Page 8
1 qualified candidates; and difficulty in attracting candidates to the location. For
2 executives, we also considered: complexity of responsibilities; alignment with
3 higher salaries paid in the Northeast; and the limited promotional opportunities in
4 a smaller organization.
5 Last, as discussed in more detail below, the ISO regularly monitors job-specific
6 salary survey data to determine these targets.
7 COMPONENTS OF COMPENSATION
8 Q. WHAT ARE THE COMPONENTS OF THE ISO’S COMPENSATION?
9 A. The ISO has a “pay for performance” compensation program composed of two
10 components for all employees, and an additional long-term component for
11 executives and certain key employees.
12 The first component is annual base salary, which reflects external
13 competitiveness, the employee’s productivity and performance, the qualifications
14 for the position, and internal equity. An employee’s annual base salary evolves
15 based on his or her job performance, following the annual performance review
16 process. (These are the merit and promotional increases that will be discussed
17 below.) These changes to salary are one of the ways in which the ISO maintains
18 the competitiveness of its salaries within the target ranges previously discussed.
19 The second component of compensation is annual incentive compensation. This
20 program is intended to motivate employees to achieve superior performance on ISO New England Inc. Recovery of 2016 Administrative Costs Page 9
1 critical annual business and customer service objectives and goals. Subject to
2 eligibility criteria, employees may receive an annual award based on a formula
3 that includes company performance, individual performance, annual base salary
4 and a grade-related salary percentage. Company performance is determined using
5 goals that are set in advance by the Board. These goals are objective and
6 measurable and represent organizational goals for operational reliability, efficient
7 and competitive markets, budget performance and service excellence in
8 stakeholder processes. Performance against these goals is measured using a
9 corporate scorecard that is regularly published to all employees, and the
10 calculation of which is verified by the ISO’s internal auditors. The Board of
11 Directors then assigns a final score to the achievement of annual goals.
12 For executives and certain key employees, the third and final component of
13 compensation is a long-term incentive plan that is designed to encourage retention
14 by deferring payments for two and one-half years after they are declared. This
15 program is intended to provide compensation in lieu of the stock programs
16 provided by for-profit competitors. These awards are determined using a formula
17 of performance against specific corporate goals, individual performance and
18 annual base salary. Again, the goals and their performance are determined by the
19 Board. Additionally, before the payout, the Board conducts a retrospective
20 review of the quality and impact of the goal achievement supporting the award. ISO New England Inc. Recovery of 2016 Administrative Costs Page 10
1 Employees are not eligible for either type of award in a year in which they receive
2 a performance rating of “Clearly Below Expectations” or in the event of a major
3 collapse of the bulk electric power system. Similarly, if the ISO underperforms in
4 the management of the bulk electric power system or in its other functions in a
5 manner that is not captured in the goal performance score, the Board of Directors
6 can reduce or eliminate the payment of the awards. The Board has taken this step
7 in the past.
8 BUDGET FOR MERIT AND PROMOTIONAL SALARY INCREASES
9 Q: PLEASE EXPLAIN THE MERIT AND PROMOTIONAL INCREASE
10 BUDGET.
11 A. This is a budget that establishes annually the amount that management and the
12 Board can distribute to the entire employee base for salary increases following the
13 annual performance review process that occurs in the first quarter of each year, as
14 well as changes as a result of promotion. This is a critical component of our
15 ability to maintain competitive salaries, which, as discussed above, enables us to
16 retain our employees in a very competitive marketplace for their talent.
17 Q. HOW IS THIS BUDGET DETERMINED?
18 A. The Compensation and Human Resources Committee of the Board of Directors
19 determines this budget annually after reviewing national survey data that project
20 what other employers will do for these programs in the coming year. We
21 typically gather data from six surveys, prepared by Mercer, WorldatWork, the ISO New England Inc. Recovery of 2016 Administrative Costs Page 11
1 Conference Board, Buck Consultants, Aon Hewitt, and TowersWatson. The
2 surveys report the planned budget increases of several thousand employers,
3 including nearly 400 energy and utility companies. These surveys provide
4 information on all industries nationwide, as well as the utility industry separately,
5 and are used by most major companies to determine their compensation budgets.
6 The ISO utilizes nationwide benchmark data for both all-industry and utility-
7 specific employers, because it recruits a majority of its employees on a
8 nationwide basis given the unique skill sets required for many of its positions.
9 The ISO further assesses the data by employee group, reviewing data reported
10 specifically for executive, exempt employees, and non-union non-exempt
11 employees.
12 Q. WHAT WERE THE SURVEY RESULTS REGARDING PROJECTED
13 INCREASES FOR 2016?
14 A. For merit increase budgets, the surveys showed an average of slightly higher than
15 3.0% for all industries nationwide, and slightly lower than 3.0% for the utility
16 industry. For promotional increase budgets, the surveys showed a range of 0.5%
17 to 1.0% for all industries nationwide and 0.0% - 0.8% for the energy and utility
18 industry. Some of the energy and utility data is influenced by cut backs at oil and
19 gas companies, which have been affected by the decrease in oil and gas prices
20 nationwide. ISO New England Inc. Recovery of 2016 Administrative Costs Page 12
1 In 2008 and 2009, because employers were reducing their compensation budgets
2 given the economic downturn, the survey firms updated their data at year end.
3 The ISO reviewed this data in both years to ensure that the following year’s
4 budgeted increases remained within the survey ranges. In 2008, the ISO reduced
5 its 2009 compensation budget by $500,000 as a result. In 2010, only one of the
6 survey firms produced an update. There were no updates in 2011, and one update
7 in each of 2012, 2013 and 2014. We expect that one firm will issue an update in
8 2015, and we will review and consider that data, but expect that, consistent with
9 the last few years, it will not indicate any material changes in employers’
10 compensation budgets.
11 Q. WHAT ARE THE ISO’S MERIT AND PROMOTIONAL INCREASE
12 BUDGETS FOR 2016?
13 A. After reviewing the survey data, the Committee approved a merit increase budget
14 of 2.75% and a promotional increase budget of .75%. We chose to be on the
15 lower side of the survey data for the merit increase budget in order to move funds
16 into the promotional increase budget, where we are on the higher side of the
17 average survey data. This positioning will enable us to continue benchmarking
18 and adjusting compensation for engineers and informational technology
19 professionals, among others, when market data indicates that our salaries are not
20 competitive. ISO New England Inc. Recovery of 2016 Administrative Costs Page 13
1 FRAMEWORK FOR DETERMINING EXECUTIVE COMPENSATION
2 Q. WHAT IS THE FRAMEWORK FOR THE ISO’S DETERMINATION OF
3 EXECUTIVE COMPENSATION?
4 A. The ISO is a not-for-profit company under Section 501(c)(3) of the Internal
5 Revenue Code. The Internal Revenue Code and related Treasury regulations
6 require that the compensation paid to executive officers meet a standard of
7 “reasonableness.” Specifically, compensation must fall within a range of
8 competitive practices for total compensation paid by similarly-situated
9 organizations, both taxable and tax-exempt, for functionally comparable
10 positions.
11 The Internal Revenue Code allows a tax-exempt organization to establish a
12 “rebuttable presumption” of reasonableness. This places the onus on the Internal
13 Revenue Service to show that compensation is unreasonable. The rebuttable
14 presumption requires that the compensation arrangement be approved in advance
15 by independent individuals (e.g., the Board of Directors), that the Board has
16 obtained and relied upon appropriate data as to comparability (i.e., compensation
17 paid by similarly-situated entities – taxable and tax-exempt – for positions with a
18 similar scope of responsibility), and that the Board adequately documents the
19 basis for its determination. ISO New England Inc. Recovery of 2016 Administrative Costs Page 14
1 Q. HOW HAS THE ISO ATTEMPTED TO SECURE THE BENEFIT OF THE
2 PRESUMPTION OF REASONABLENESS?
3 A. The ISO’s Board of Directors approves all executive compensation, and
4 documents the basis for its determination. In order to ensure that the Board has
5 obtained and relied upon appropriate data as to comparability, the ISO retains an
6 outside compensation advisor, Mercer Consulting. Mercer prepares an opinion
7 annually on the reasonableness of the ISO’s executive compensation, using as
8 comparators other ISOs and RTOs, as well as for-profit utilities and other
9 companies, based on their organizational character/complexity, geographic
10 location, role of the incumbent and labor market for the executive team. The data
11 for these groups is then blended to create a composite market reference as an
12 overall benchmark. This composite reflects the fact that the ISO competes for
13 executive talent in the energy industry, as well as in the broader general industry
14 for positions in areas like Legal, Finance and Human Resources.
15 Q. WHAT IS THE BOARD’S PROCESS FOR DETERMINING EXECUTIVE
16 COMPENSATION?
17 A. This process occurs in the first quarter of each year. In determining executive
18 compensation, the Board first asks its Compensation and Human Resources
19 Committee to consider appropriate compensation. Both the Committee, and then
20 the Board, consider the CEO’s appraisal of each executive’s experience,
21 responsibilities, performance, specific skill set, and contribution to strategic goal ISO New England Inc. Recovery of 2016 Administrative Costs Page 15
1 achievement (and, for the CEO, the Chair’s appraisal of the same factors as
2 related to the CEO), and the Company’s financial and operational achievement.
3 The Board then provides its compensation recommendations to Mercer for an
4 opinion on reasonableness, prior to implementation.
5 Q. WHAT WAS THE CONCLUSION OF MERCER’S MOST RECENT
6 REASONABLENESS OPINION?
7 A. Mercer’s most recent reasonableness opinion concludes that the proposed 2015
8 total compensation for executives was reasonable.
9 Q. HOW WILL 2016 EXECUTIVE COMPENSATION BE DETERMINED?
10 A. The Board will use the same process described above, involving the
11 Compensation and Human Resources Committee’s review and approval followed
12 by full Board approval of executive compensation. Likewise, the Board will
13 employ Mercer to ensure the reasonableness of 2016 compensation. While 2016
14 compensation has not yet been determined, 2015 executive compensation will be
15 the base for 2016 compensation and the Board has not authorized any wholesale
16 changes to the compensation programs described above. Consequently, it is
17 reasonable to presume that the 2016 executive compensation will be similar to the
18 2015 compensation, with changes necessary to maintain its competitiveness.
EXHIBIT 5 Exhibit 5 ISO New England Inc. 2016 Capital Projects Schedule
Current Year Project-To- (2015) Cost to 2016 Cost to Total Project Estimated Description Date Complete [1] Complete Costs Complete Date
Capital Projects - Approved Charters . Wind Integration Phase II / Do Not Exceed (DNE) Dispatch $ 1,308.8 $ 1,359.9 $ 2,472.0 $ 5,140.7 5/2016 . Divisional Accounting 2,232.0 72.0 496.8 2,800.8 2016 . Forward Capacity Auction (FCA) 10 758.5 1,366.5 590.0 2,715.0 5/2016 . Zonal Load Forecast 48.2 406.8 225.0 680.0 3/2016 . Power System Modeling Management Initiatives 12.5 97.5 145.0 420.0 [2] 8/2017 . NX9/NX12D - Generator Voltage Data 112.6 192.4 50.0 355.0 2/2016 . Internet Explorer 11 Upgrade 89.1 200.9 12.0 302.0 12/2015 Sub Total Projects with Approved Charters 4,561.7 3,696.0 3,990.8 12,413.5 Planning/Conceptual Design [3] . Forward Capacity Auction (FCA) 11 - 100.0 3,000.0 3,100.0 TBD . Sub-hourly Settlements - 85.0 2,500.0 2,585.0 TBD . Fast-Start Pricing - - 2,500.0 2,500.0 TBD . Submission of Financial Transmission Rights (FTR) for Clearing 88.9 21.2 1,800.0 1,910.1 TBD . 2016 Issues Resolution Project - - 1,500.0 1,500.0 TBD . Long-term FTRs 907.5 - - 907.5 [4] TBD . Expand Energy Offers for Pumps - - 900.0 900.0 TBD . Quarterly Release Projects 2016 - - 800.0 800.0 TBD . Asset Characteristic Database & User Interface Re-design 1.0 39.0 700.0 740.0 TBD . Energy Management Platform Customs Elimination - - 600.0 600.0 TBD . Operations Document Management System - - 600.0 600.0 TBD . Asset Registration Automation 30.2 27.5 500.0 557.7 TBD . Transmart Rewrite - - 500.0 500.0 TBD . Web Enhancements 2016 - - 500.0 500.0 TBD . Dynamic Interchange Adjustment Tool - - 300.0 300.0 TBD . Oracle 12c Upgrade 17.4 32.6 100.0 150.0 TBD . Case Snapshot Enhancements for Market Operator Interface - - 100.0 100.0 TBD . Price Responsive Demand - - 100.0 100.0 TBD . Other Emerging Work Projects - - 1,809.2 1,809.2 TBD Sub Total Conceptual Design 1,045.0 305.3 18,809.2 20,159.5 . Non-Project Capital Expenditures - - 3,700.0 3,700.0 . Capitalized Interest and Loan Fees - - 500.0 500.0 Total Capital Projects (Including Capitalized Interest) $ 5,606.7 $ 4,001.3 $ 27,000.0 $ 36,773.0
[1] The amounts under the "Current Year (2015) Cost to Complete" list only includes those projects with budgeted costs in 2016 and beyond. [2] Total Project Costs for the Power System Modeling Management Initiatives project includes 2017 estimated expense of $165,000. [3] The 2016 Budget for Projects in Planning and Conceptual Design is not final. Once the project scope and timeline have been determined the budget will be finalized. [4] The Long-term FTRs project has been indefinitely deferred pending the development of appropriate credit requirements.
EXHIBIT 6 ISO New England Inc. 2016 Capital Budget
UNITED STATES OF AMERICA
BEFORE THE
FEDERAL ENERGY REGULATORY COMMISSION
ISO NEW ENGLAND INC. ) Docket No. ER16-_____-000
DIRECT TESTIMONY
OF
M. DAVID HAMEEDY
Filed on: October 16, 2015 ISO New England Inc. 2016 Capital Budget Page 1
1 UNITED STATES OF AMERICA
2 BEFORE THE FEDERAL ENERGY REGULATORY COMMISSION
3
4 ISO NEW ENGLAND INC. ) Docket No. ER16-_____-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. 2016 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 2016 (“2016 Capital Budget”).
12 My Direct Testimony describes:
13 (i) the Capital Budget development process;
14 (ii) elements of the 2016 Capital Budget; and
15 (iii) funding of the 2016 Capital Budget.
16 THE CAPITAL BUDGET DEVELOPMENT PROCESS
17 Q. WHAT BUDGETS DOES THE ISO DEVELOP FOR EACH YEAR?
18 A. The ISO develops an operating budget and a capital budget. The capital budget
19 supports important capital needs for New England. ISO New England Inc. 2016 Capital Budget Page 3
1 Q. HOW WERE THE ISO’S BUDGETS DEVELOPED FOR 2016?
2 A. The ISO prepares budgets in advance of each upcoming year, including a capital
3 budget. To develop these budgets for 2016, the CEO held meetings with the
4 Chief Financial and Compliance Officer, members of the ISO Board, officers and
5 certain key managers to discuss the existing and changing responsibilities of the
6 organization. Based on the results of these meetings and the priorities established
7 with stakeholders, estimates of the resources necessary to carry out the ISO’s
8 responsibilities were submitted by each of the responsible directors and managers.
9 Following these efforts, the ISO develops a project charter for each capital project.
10 All projects with completed charters were reviewed to ensure that the estimates
11 were reasonable and that no costs were double-counted. The ISO management
12 team meets once a month to discuss the project charters. An approval by the ISO
13 management team is essential prior to the authorization of budgets and the start of
14 project work.
15 ELEMENTS OF THE 2016 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 2016 Capital
19 Budget is application software and requisite hardware needed to maintain and
20 improve bulk-power system reliability and/or wholesale electric markets. ISO New England Inc. 2016 Capital Budget Page 4
1 Q. HAS THE 2016 CAPITAL BUDGET CHANGED FROM 2015 LEVELS?
2 A. The 2016 Capital Budget is $27 million, which is $1 million less than the 2015
3 budget.
4 Q. PLEASE DESCRIBE THE ELEMENTS OF THE CAPITAL BUDGET.
5 A. The 2016 Capital Budget contains the following projects: Wind Integration Phase
6 II / Do Not Exceed Dispatch; Forward Capacity Auction 10; Divisional
7 Accounting; Zonal Load Forecast; Power System Modeling Management
8 Initiatives; NX9/NX12D – Generator Voltage Data; Forward Capacity Auction
9 (“FCA”) 11; Sub-Hourly Settlements; Fast-Start Pricing; Submission of Financial
10 Transmission Rights for Clearing; 2016 Issues Resolution Project; Expand Energy
11 Offers for Pumps; Quarterly Release Projects 2016; Asset Characteristics
12 Database & User Interface Redesign; Energy Management Platform Customs
13 Elimination; Operations Document Management System; Transmart Rewrite;
14 Web Enhancements 2016; Asset Registration Automation; Dynamic Interchange
15 Adjustment Tool; Oracle 12c Upgrade; Case Snapshot Enhancements for Market
16 Operator Interface; Price Responsive Demand; Non-Project Capital Expenditures;
17 and Other Emerging Work. The 2016 Capital Budget also includes $500,000 to
18 pay for capitalized interest and loan fees. ISO New England Inc. 2016 Capital Budget Page 5
1 Q. PLEASE DESCRIBE THE WIND INTEGRATION PHASE II / DO NOT
2 EXCEED DISPATCH PROJECT.
3 A. The ISO has budgeted $2,472,000 in 2016 for this effort, which is expected to be
4 complete in May 2016. This is the second phase in the project to fully integrate
5 wind power into the ISO-NE system. Phase I of the project established a
6 centralized wind power forecast system for ISO-NE, putting the forecast into use
7 by wind plant operators and ISO-NE. The wind power forecast was a direct
8 recommendation from the New England Wind Integration Study and the first step
9 towards the full integration of wind into ISO-NE systems. The Phase I project
10 implemented an infrastructure that can be used to extend the usage of the wind
11 power forecasts into other ISO-NE processes.
12 Phase II builds on Phase I by adding both improvements and new functionality.
13 Significantly, Phase II will employ the wind power forecast to facilitate the
14 inclusion of wind resources in the real-time dispatch. Allowing real-time dispatch
15 will alleviate issues with curtailment priorities, allow wind resources to set price,
16 and provide the proper market signals for new capacity. Phase II also includes:
17 short-term wind power forecast improvements; publishing medium-term and long-
18 term forecasts; adding a new wind power forecast analysis archive; improving
19 real-time wind dashboard displays; and adding Do Not Exceed dispatch for
20 intermittent resources. ISO New England Inc. 2016 Capital Budget Page 6
1 Q. PLEASE DESCRIBE THE FORWARD CAPACITY AUCTION 10
2 PROJECT.
3 A. The FCA 10 project will implement Tariff revisions that were filed with the
4 Commission on May 1, 2015 to address the potential exercise of market power.
5 The changes include: increasing the Dynamic De-List Bid Threshold; mitigating
6 New Import Resources that function more like existing resources than new
7 resources; and establishing a single pivotal supplier test that applies to both
8 capacity imports and existing resources. Other changes include the
9 implementation of a system-wide demand curve in the Annual Reconfiguration
10 Auctions and functionality to support Renewable Technology Resources.
11 In addition to the market changes discussed above, the FCA 10 project will
12 include upgrades for the software used to support the qualification process.
13 Oracle and Microsoft have announced that the current versions of Oracle (11g)
14 and Internet Explorer (v.8) in use by the ISO have reached their end of life and
15 will not be supported effective January 2016. Accordingly, the existing software
16 will be upgraded to Oracle version 12c and Internet Explorer version 11.
17 The targeted completion date for this project is May 2016 and it is expected to
18 cost $590,000 in 2016. ISO New England Inc. 2016 Capital Budget Page 7
1 Q. PLEASE DESCRIBE THE DIVISIONAL ACCOUNTING PROJECT.
2 A. Market Participants with business interests in different aspects of the New
3 England electricity markets have requested separate settlement accounts for their
4 individual business units, allowing them to evaluate their positions by business
5 unit, division or generating facility. This project will implement changes, in
6 phases, to various ISO-NE systems to allow Market Participants to create and
7 maintain subaccounts and associate their resources and transactions to these
8 subaccounts.
9 The complexity of the implementation and the vast number of systems impacted
10 resulted in five phased releases to occur in 2014 and 2015. The first four planned
11 phases have been completed, and allow Customers to create and maintain
12 subaccounts and receive reports for settlements for entity-based transactions by
13 subaccounts. In addition, the ISO has completed the necessary modifications to
14 eMarket (a web based software application for use by Market Participants to
15 submit supply offers and bids), eFTR (Financial Transmission Rights) and the
16 Forward Capacity Tracking System to allow Customers to link transactions that
17 are not associated with assets and resources to subaccounts, thereby allowing
18 settlements for those transactions to be calculated and reported at the subaccount
19 level. ISO New England Inc. 2016 Capital Budget Page 8
1 The fifth and final phase of the project has been delayed due to resource conflicts,
2 specifically with the Coordinated Transaction Scheduling project. The final phase
3 is focused specifically on external transactions and their respective settlements.
4 Re-planning analysis is underway, and initial estimates indicate completion during
5 2016 at a cost of $496,800.
6 Q. PLEASE DESCRIBE THE ZONAL LOAD FORECAST PROJECT.
7 A. This project, for which $225,000 is budgeted in 2016, addresses a load forecasting
8 need related to weather events in which hot and humid conditions occur inland
9 and the coastal regions experience a cooling sea breeze. In response to this
10 situation, ISO-NE developed a zonal load forecast prototype which addresses the
11 problem by creating a load forecast for each load zone. This project will build on
12 the successful prototype by incorporating zonal load forecast functionality into the
13 existing load forecast application, and adjusting downstream systems using load
14 forecast data accordingly. With this project, the overall load forecast for the
15 region will improve. The targeted completion date for this project is March 2016.
16 Q. PLEASE DESCRIBE THE POWER SYSTEM MODELING
17 MANAGEMENT INITIATIVES PROJECT.
18 A. The ISO has budgeted $145,000 for this project, which is intended to implement
19 enhancements to processes, procedures, and applications that will improve the
20 power system network model used for the Energy Management System. The ISO ISO New England Inc. 2016 Capital Budget Page 9
1 will work with Northeastern University to perform an analysis of the ISO-NE
2 network model to identify: the type and location of all “critical” measurements
3 identified in the measurement configuration; the observable islands identified by
4 the set of buses belonging to each island; and all unobservable branches
5 separating the identified observable islands. In addition, Northeastern University
6 will develop software that will allow for off-line detection and identification of
7 analog measurements and state estimator parameters with significant errors that
8 impact the state estimator solution. Using this software, ISO-NE will work with
9 transmission owners to correct these errors. The goal is to create a more robust
10 and accurate state estimator solution, which in turn will benefit other critical
11 energy management system functions and market applications. The targeted
12 completion date for this project is August 2017.
13 Q. PLEASE DESCRIBE THE NX9/NX12D – GENERATOR VOLTAGE
14 DATA PROJECT.
15 A. The NX9/NX12D application, implemented in the fall of 2013, is an externally-
16 facing application that manages the data and certifications provided by ISO-NE
17 customers for specific equipment. Currently, the NX12D section of the
18 application is used to collect information on generators, including reactive
19 data. The NX9 section of the application collects specific nameplate and
20 characteristic data for transmission equipment. At a 2016 cost to complete of ISO New England Inc. 2016 Capital Budget Page 10
1 $50,000, the NX9/NX12D project will update the software associated with these
2 systems to align with ISO-NE Operating Procedure No. 12 (“Voltage & Reactive
3 Control”), which was recently updated in compliance with the North American
4 Electric Reliability Corporation’s Reliability Standard VAR-001-4. The targeted
5 completion date for this project is February 2016.
6 Q. PLEASE DESCRIBE THE FCA 11 PROJECT.
7 A. This project is dedicated to the design and implementation of zonal sloped
8 demand curves that balance the factors involved in designing capacity market
9 demand curves: reliability, price volatility, market power, and robust
10 performance. The project is intended to be completed with the eleventh FCA,
11 which will be held in February 2017. The 2016 Capital Budget includes
12 $3,000,000 for this project.
13 Q. PLEASE DESCRIBE THE SUB-HOURLY SETTLEMENTS PROJECT.
14 A. The real-time markets (energy, reserve, and regulation) are settled hourly, even
15 though the ISO calculates real-time locational marginal prices every five minutes.
16 Existing settlement rules tend to undercompensate certain resources, particularly
17 more flexible generation and storage assets that respond quickly in tight operating
18 conditions, when there are significant mid-hour price changes. Compensating
19 resources at the more granular, five-minute price would help improve price
20 formation by ensuring that the price that suppliers are paid for real-time ISO New England Inc. 2016 Capital Budget Page 11
1 performance is a more accurate signal of the power system’s current operating
2 conditions. In the future, this change may also provide an additional revenue
3 source for wholesale electricity storage resources. The target completion date for
4 this project is the fourth quarter of 2016, and the 2016 Capital Budget includes
5 $2,500,000 for its completion.
6 Q. PLEASE DESCRIBE THE FAST-START PRICING PROJECT.
7 A. In practice, fast-start units, even when deployed in economic merit order, often do
8 not set the real-time price given their operating characteristics. This is due to the
9 limitations of ISO-NE’s existing fast-start pricing logic, which was designed
10 fifteen years ago to work with the software and hardware that was available at the
11 time. The proposed changes will increase the accuracy and efficiency of dispatch,
12 pricing, and compensation when fast-start units are deployed. Price formation
13 will be improved by fast-start resources’ ability to set price more frequently, and
14 prices will reflect the cost of fast-start deployments through transparent market
15 price signals. The result will be improved performance incentives for all
16 resources during tight system conditions. The targeted completion date for this
17 project is the first quarter of 2017. The 2016 Capital Budget includes $2,500,000
18 for this project. ISO New England Inc. 2016 Capital Budget Page 12
1 Q. PLEASE DESCRIBE THE SUBMISSION OF FINANCIAL
2 TRANSMISSION RIGHTS FOR CLEARING PROJECT.
3 A. The objective of this project, currently in planning, is to institute third-party
4 clearing in order to address the inability to properly collateralize against the risk
5 of a participant default. Currently, ISO-NE holds Financial Assurance that may
6 not be adequate to cover the potential losses of a Market Participant’s default on
7 its FTRs. Specifically, there is no way for ISO-NE to unwind a defaulted FTR
8 position. If a participant acquires a large position in an annual FTR auction, and
9 the amount of negative target allocations exceeds its Financial Assurance, the
10 losses on this position, and the losses to all ISO-NE participants in the event of a
11 default, can continue to accumulate. Under a third-party clearing design, if a
12 Market Participant defaults, its clearing member will liquidate the defaulted
13 portfolio in the secondary market, and if the combined margin held against the
14 portfolio is not adequate to cover the liquidation losses, the clearing member
15 holds the financial responsibility to cover the excess losses.
16 Regulatory and jurisdictional questions surrounding the project have resulted in
17 major delays. Minimal work on the project will continue in 2015, with the
18 majority of development work anticipated to occur in 2016 at a cost of
19 $1,800,000. The targeted completion date for this project is the fourth quarter of
20 2016. ISO New England Inc. 2016 Capital Budget Page 13
1 Q. PLEASE DESCRIBE THE ISSUE RESOLUTION PROJECT 2016.
2 A. The ISO uses a “Corrective Action/Preventative Action” approach to identify and
3 track needed enhancements to existing systems and processes. This project
4 continues efforts to resolve as many current outstanding issues that have a
5 software impact as possible. These issues include automation of manual
6 functions, addition of functionality in support of market activities, miscellaneous
7 application improvements, internal and external report updates, and technology
8 improvements. The ISO Information Technology and System groups will review
9 the list of issues related to the systems and applications for which they provide
10 support and identify those that can be implemented during the year. The targeted
11 completion date for this project is the fourth quarter of 2016 and the anticipated
12 cost is $1,500,000.
13 Q. PLEASE DESCRIBE THE EXPAND ENERGY OFFERS FOR PUMPS
14 PROJECT.
15 A. The ISO does not currently allow Dispatchable Asset Related Demands
16 (“DARDs”) to have inter-temporal constraints (start-up, notification, minimum
17 run and down times, and maximum number of starts per day). In response to the
18 Commission’s Order No. 719, ISO-NE agreed to modify this practice.
19 Specifically, through this project, the ISO will enable DARDs to have maximum
20 demand-dispatch duration, maximum dispatch frequency, and a minimum down- ISO New England Inc. 2016 Capital Budget Page 14
1 time. In addition, the ISO will expand the rules for Net Commitment Period
2 Compensation and define cost allocation rules for DARDs. The targeted
3 completion date for this project is the fourth quarter of 2016. The Capital Budget
4 includes $900,000 for this project in 2016.
5 Q. PLEASE DESCRIBE THE QUARTERLY RELEASE PROJECTS 2016
6 PROJECT.
7 A. In addition to major projects under consideration for 2016, the ISO expects to
8 address a number of minor enhancements requested by stakeholders at a cost of
9 $800,000. These enhancements are bundled into two quarterly releases. The
10 targeted completion dates are the second quarter of 2016 for the first release, and
11 the fourth quarter of 2016 for the second release.
12 Q. PLEASE DESCRIBE THE ASSET CHARACTERISTICS DATABASE &
13 USER INTERFACE REDESIGN PROJECT.
14 A. This project will provide participants and ISO-NE Internal Market Monitoring
15 staff with enhanced functionality to track generator characteristics for reference
16 level calculations. This project will build upon functionality delivered as part of
17 the Energy Market Offer Flexibility (Hourly Markets) project. The targeted
18 completion date for this project is the third quarter of 2016 and the Capital Budget
19 includes $700,000 for its completion. ISO New England Inc. 2016 Capital Budget Page 15
1 Q. PLEASE DESCRIBE THE ENERGY MANAGEMENT PLATFORM
2 CUSTOMS ELIMINATION PROJECT.
3 A. ISO-NE’s Energy Management System is based on Alstom Grid’s suite of Energy
4 Management Platform applications. When absolutely necessary, the Information
5 Services department customizes Alstom’s software to meet the business needs of
6 ISO-NE. Accordingly, when Alstom upgrades its software, a significant effort is
7 needed to port the customized ISO-NE software to the upgraded software. This
8 project involves work with Alstom Grid to eliminate some of the ISO-NE
9 customs, with the goal of simplifying the next software upgrade. The targeted
10 completion date for this project is the fourth quarter of 2017, and $600,000 has
11 been included for it in the 2016 Capital Budget.
12 Q. PLEASE DESCRIBE THE OPERATIONS DOCUMENT MANAGEMENT
13 SYSTEM PROJECT.
14 A. System Operations is currently using the Operations Document Management
15 System (“ODMS”) as the sole system for managing the edit, review and sign-off
16 for all transmission operating guides, operating procedures, master local control
17 center procedures, and system operating procedures. ODMS also provides
18 operational functionality, including searching and decision making. Since ISO-
19 NE is phasing out SharePoint-based applications such as ODMS, the project will ISO New England Inc. 2016 Capital Budget Page 16
1 migrate ODMS to a new software platform. The targeted completion date for this
2 project is the fourth quarter of 2016 at a cost of $600,000 in 2016.
3 Q. PLEASE DESCRIBE THE TRANSMART REWRITE PROJECT.
4 A. Transmart is a software application that is used by ISO-NE System Operations
5 staff to support external transactions. The Transmart application has been in
6 existence since before the implementation of Standard Market Design in 2003.
7 The Transmart Rewrite project upgrades the remaining functionality that still
8 exists in the original Transmart application. The targeted completion date for this
9 project is the fourth quarter 2016 and the Capital Budget includes $500,000 for
10 this project.
11 Q. PLEASE DESCRIBE THE WEB ENHANCEMENTS 2016 PROJECT.
12 A. ISO-NE completed a redesigned website in 2014 that greatly improved ease of use
13 of, and access to, market and power system information for Market Participants,
14 public officials, and other key stakeholders. In an effort to continue to improve
15 the ISO New England web presence, the Web Enhancements 2016 project, at a
16 cost of $500,000, will improve the usability and technical support of the internal
17 and external websites by implementing stakeholders’ most requested
18 improvements and the highest priority enhancements. The project is targeted for
19 completion in 2016. ISO New England Inc. 2016 Capital Budget Page 17
1 Q. PLEASE DESCRIBE THE ASSET REGISTRATION PROJECT.
2 A. The current asset registration process relies on participant submittal of scanned,
3 emailed, or faxed asset registration forms or spreadsheets. This project aims to
4 improve the asset registration process by providing a secure digital format for
5 submission and retrieval of asset registration forms, in addition to requested asset
6 data changes and transfers. The repository would include the required controls for
7 this data and ensure that all customers and business users would have access to
8 timely and accurate asset data without the need to maintain separate databases,
9 spreadsheets, binders, or duplicate forms. This project would also provide a
10 workflow to manage the necessary participant and ISO approvals required for
11 asset registration and changes to existing asset data. The targeted completion date
12 for this project is the third quarter of 2016 and the anticipated cost to complete the
13 work in 2016 is $500,000.
14 Q. PLEASE DESCRIBE THE DYNAMIC INTERCHANGE ADJUSTMENT
15 TOOL PROJECT.
16 A. Currently, ISO-NE sets hourly interchange schedules with neighboring control
17 areas in New York, Quebec and New Brunswick. The schedules all change
18 concurrently once per hour and are primarily ramped over a ten-minute period
19 beginning five minutes before the top of each hour. System Operating Procedures
20 apply uniform ramp limits to all hours without regard to actual system conditions ISO New England Inc. 2016 Capital Budget Page 18
1 or system ramping capability. As the use of a uniform ramp limit can result in
2 unnecessary curtailment of transactions, or may occasionally fail to account for a
3 shortage of ramping capability, the Dynamic Interchange Adjustment Tool project
4 will replace uniform ramp limits with secure ranges of system ramping
5 capabilities for intra-hour interchange adjustments. The project will also address
6 the additional layer of complexity created by the advent of intra-hour scheduling
7 with New York. The target completion date for this project is the fourth quarter
8 of 2016 at a cost of $300,000 in 2016.
9 Q. PLEASE DESCRIBE THE ORACLE 12c UPGRADE PROJECT.
10 A. Many ISO-NE business applications rely on an Oracle database. To obtain the
11 level of support needed from Oracle to meet the ISO’s availability goals, the ISO
12 must run on the current Oracle database version for each application. This project
13 will ensure all systems are upgraded from Oracle version 11g to Oracle version
14 12c. Because upgrades are also occurring in the context of current and upcoming
15 projects, this project’s scope will specifically address only database upgrades and
16 performance testing for those systems not covered under a current or upcoming
17 project. The targeted completion date for this project is the second quarter of 2016
18 and the Capital Budget includes $100,000 for this project. ISO New England Inc. 2016 Capital Budget Page 19
1 Q. PLEASE DESCRIBE THE CASE SNAPSHOT ENHANCEMENTS FOR
2 MARKET OPERATOR INTERFACE PROJECT.
3 A. On July 3, 2013, the Commission approved ISO-NE’s proposal to use the $1
4 million in funds provided to ISO-NE under the Stipulation and Consent
5 Agreement between Constellation Energy Commodities Group and the Office of
6 Enforcement. That proposal involved the development of new software to allow
7 increased surveillance and oversight of the Day-Ahead Energy Market. The new
8 software (called Case Snapshot) allows the re-execution of the Day-Ahead Energy
9 Market’s Reserve Adequacy Assessment and Security Constrained Reliability
10 Assessment cases using the same market data that existed when the original case
11 was executed and approved. The initial development and implementation of Case
12 Snapshot occurred at the end of October 2013. Enhancements to augment the data
13 captured in the snapshot tables and the data retention period were subsequently
14 made. On December 22, 2014, ISO-NE reported that the initial implementation
15 was complete at a total project cost of $672,500.
16 ISO-NE is now proposing to use the remaining funds to develop a suite of user
17 interface displays that will provide visibility of the snapshot data when re-running
18 a case and allow the ability to modify this data, including participant offers, before
19 executing the case. In addition, this functionality will facilitate the execution of
20 “what-if” scenarios. Currently, for much of the snapshot data, this can only be ISO New England Inc. 2016 Capital Budget Page 20
1 achieved using database queries and manual database edits. It is ISO-NE’s
2 expectation that the remaining funding from the settlement will cover most but
3 not all of the costs of developing and implementing the enhancements.
4 Accordingly, the 2016 Capital Budget includes $100,000 for this project. The
5 targeted completion date is the fourth quarter of 2016.
6 Q. PLEASE DESCRIBE THE PRICE RESPONSIVE DEMAND PROJECT.
7 A. This project aims to fully integrate demand response into the wholesale markets.
8 The project will create a dispatchable capacity product for demand response,
9 including the application of Peak Energy Rents and performance penalties to
10 demand response, thereby creating disincentives for economic and physical
11 withholding of capacity. In addition, the project will provide a mechanism for
12 capacity replacement for resources that are not able to demonstrate their obligated
13 capacity. Due to the uncertainty surrounding the Commission’s Order No. 745,
14 the ISO has allocated only $100,000 for work in 2016, and currently anticipates a
15 completion date for this project is the third quarter of 2018.
16 Q. PLEASE DESCRIBE THE NON-PROJECT CAPITAL EXPENDITURES
17 ITEM.
18 A. The 2016 Capital Budget includes $3.7 million for non-project capital
19 expenditures. Non-project capital expenditures fund external and internal
20 capitalized labor necessary to program System Improvement Requests ISO New England Inc. 2016 Capital Budget Page 21
1 ($2,000,000), non-project related hardware purchases ($1,500,000), and furniture
2 & fixtures ($200,000).
3 Q. PLEASE DESCRIBE THE “OTHER EMERGING WORK” PROJECTS.
4 A. This category is primarily intended to deal with emerging work requests during
5 2016 that result from operational needs, compliance obligations or
6 regulatory/stakeholder feedback.
7 Q. DESCRIBE THE ACCURACY OF THE EXPENDITURE ESTIMATES
8 FOR THE PROJECTS INCLUDED IN THE 2016 CAPITAL BUDGET.
9 A. The 2016 Capital Budget includes six projects with approved charters: Wind
10 Integration Phase II / Do Not Exceed Dispatch; Forward Capacity Auction 10;
11 Divisional Accounting; Zonal Load Forecast; Power System Modeling
12 Management Initiatives; and NX9/NX12D – Generator Voltage Data. The ISO
13 has not finalized the design, scope, and charters for the remaining projects. As a
14 result, the cost estimates for such items are likely to change. Furthermore, the
15 capital budget is quite dynamic, and the ISO uses it to reflect any changing market
16 needs, when possible. To the extent new and urgent priorities arise, the ISO will
17 adjust accordingly and reflect these adjustments in its quarterly Section 205
18 filings. ISO New England Inc. 2016 Capital Budget Page 22
1 CAPITAL BUDGET FUNDING
2 Q. PLEASE DETAIL HOW THE EXPENDITURES CAPTURED IN THE
3 CAPITAL BUDGET ARE TYPICALLY FUNDED AND REPAID.
4 A. The ISO’s existing and future capital projects are financed by drawing upon the
5 private placement debt, issued with Commission authorization. (See orders in
6 Docket No. ES04-39-000, 109 FERC ¶ 62,195 (2004), and Docket No. ES12-48-
7 000, 140 FERC ¶ 62,173 (September 6, 2012).) The ISO funds the repayment of
8 this debt through recovery of depreciation under its annual operating budgets
9 collected through the rates specified in Section IV.A of the Tariff – Recovery of
10 ISO Administrative Expenses. The Customers that are repaying the charges under
11 the schedules in Section IV.A of the Tariff are receiving the benefits of the
12 services rendered under those schedules. In no case will the costs of items be
13 recovered twice.
14 If for some reason the ISO is unable to use private financing to cover its full
15 capital budget, Section IV.B of the Tariff (the “Capital Funding Arrangements”)
16 provides four different charges the ISO may use to recover such costs from
17 Market Participants. The Capital Funding Charge allows the ISO to collect from
18 Market Participants funds for the direct purchase of capital assets not previously
19 funded by Market Participants if the ISO does not enter into private financing to
20 fund these purchases or the ISO funds the purchases through interim financings ISO New England Inc. 2016 Capital Budget Page 23
1 and does not enter into private financing to provide long-term funding of these
2 purchases. In order to encourage banks to lend for the ISO’s capital and working
3 capital needs, Section IV.B of the Tariff includes an Early Amortization Capital
4 Charge and an Early Amortization Working Capital Charge. These charges
5 ensure that the ISO can recover its working capital and the unamortized costs of
6 the assets privately financed in the event of termination, acceleration or other
7 required repayment of the loans. Finally, the Early Payment Shortfall Funding
8 Charge allows the ISO to collect from Market Participants such funds as are
9 required for the repayment of the “Shortfall Funding Arrangement” financing
10 entered into by the ISO in support of weekly billing under the Billing Policy.
11 Q. IS THE ISO’S CURRENT PRIVATE PLACEMENT DEBT SUFFICIENT
12 TO COVER THE 2016 CAPITAL BUDGET?
13 A. Yes. At this time, the ISO does not foresee the need to recover any 2016 Capital
14 Budget expenditures from Market Participants pursuant to the charges provided in
15 the Capital Funding Arrangements of the Tariff. The ISO has sufficient financing
16 to cover its 2016 Capital Budget by drawing on its private placement debt.
EXHIBIT 7 Exhibit 7 Page 1 of 4 CROSS-REFERENCE TABLE (showing location in the ISO’s filing of applicable items from Statements AA - BM in Section 35.13(h))
Statement AA Balance sheets: See balance sheets from ISO’s 2014 Form 1 (Exhibit 8).
Statement AB Income statements: See income statements from ISO’s 2014 Form 1 (Exhibit 8 hereto). A comparison of budgeted net operating expenses for 2016 with budgeted 2015 operating expenses is contained in Exhibit 3, RCL-5, Schedules 3 and 4.
Statement AC Retained earnings statement: Not applicable.
Statement AD Cost of plant: The ISO’s “plant” consists of office furniture and equipment (Account 391). The ISO does not own generation, transmission or distribution equipment. See 2014 ISO Form 1 balance sheet (Exhibit 8) at page 110, lines 2 and 4. The three “functions” of the ISO (and reflected in Section IV.A. of the ISO New England Inc. Transmission, Markets and Services Tariff, FERC Electric Tariff No. 3 (the “Tariff”)) are the three Services1 provided by the ISO.
Statement AE Accumulated depreciation and amortization: See 2014 ISO Form 1 balance sheet (Exhibit 8) at page 110, line 5.
Statement AF Specified deferred credits: Not applicable
Statement AG Specified plant accounts (other than plant in service): Not applicable, because the ISO is not seeking a return on rate base.
Statement AH Operation and maintenance expenses: These are functionalized among the Services in Exhibit 3.
Statement AI Wages and salaries: These are functionalized among the Services in Exhibit 3, RCL-3, Schedules 2.0 and 4.0. A comparison of staffing levels for 2015 and 2016 is contained in Exhibit 3, RCL-5, Schedule 5.
Statement AJ Depreciation and amortization (lease and sublease) expenses: These are functionalized among the Services in Exhibit 3, RCL-3, Schedule 3.0. Depreciation and amortization rates are discussed in
1 Capitalized terms not otherwise defined in this Exhibit have the meanings ascribed thereto in the Tariff. Exhibit 7 Page 2 of 4 Section I.C.2 of the transmittal letter and in Mr. Ludlow’s testimony (Exhibit 3).
Statement AK Taxes other than income taxes: See Exhibit 3, RCL-5, Schedules 1 and 2.
Statement AL Working capital: The Commission has authorized a revolving line of credit of $20 million for the ISO’s working capital needs. See 151 FERC ¶ 62,185 (2015). Due to the nature of the limited plant owned by the ISO, the concepts of supplies, fuel supplies, plant materials and operating supplies are not applicable to the ISO. Prepaid expenses for the ISO consist mainly of insurance costs.
Statement AM Construction work in process: not applicable.
Statement AN Notes payable: see description of notes authorized in 109 FERC ¶ 62,194 (2004); 140 FERC ¶ 62,172 (2012); 140 FERC ¶ 62,173 (2012); 144 FERC ¶ 62,087 (2013).
Statement AO Rate for allowance for funds used during construction: not applicable
Statement AP Federal income tax deductions - interest: The ISO is exempt from federal income taxation.
Statement AQ Federal income tax deductions - other than interest: The ISO is exempt from federal income taxation.
Statement AR Federal tax adjustments: The ISO is exempt from federal income taxation.
Statement AS Additional state income tax deductions: The ISO pays no state income taxes.
Statement AT State tax adjustments: The ISO pays no state income taxes.
Statement AU Revenue credits: Not applicable with respect to generation or transmission. The 2016 Revenue Requirement reflects credits from prior year true-up, as described in Section I.C.3 of the filing letter, and Exhibit 3, RCL-2.
Statement AV Rate of return: Not applicable because the ISO seeks no rate of return.
Statement AW Cost of short-term debt: No short-term debt.
Exhibit 7 Page 3 of 4 Statement AX Other recent and pending rate changes: The ISO has no operating revenues that are currently subject to refund.
Statement AY Income and revenue tax rate data: Not applicable because the ISO pays no federal or state income tax, and no revenue taxes.
Statement BA Wholesale customer rate groups:
For each Service (i.e., each Rate Schedule), the cost of service equals the revenues from the customer group, as ensured by the true-up mechanism contained in Section IV.A.2.2 of the Tariff.
For Rate Schedule 1, all transmission customers under the Open Access Transmission Tariff (Section II of the Tariff); for Rate Schedule 2, all Market Participants that participate in the New England Markets for energy; for Rate Schedule 3, all Market Participants that have load, and non-Participant Point-to-Point Transmission Service customers.
Statement BB Allocation demand and capability data: Not applicable because the ISO’s revenue requirement is not based on generation or transmission expenses. The denominators used in the rate design for each Service are explained in Section I.E of the transmittal letter.
Statement BC Reliability data: Not applicable because the ISO’s revenue requirement is not based on generation or transmission expenses. The denominators used in the rate design for each Service are explained in Section I.E of the filing letter.
Statement BD Allocation energy and supporting data: Not applicable because the ISO’s revenue requirement is not based on generation expenses. The denominators used in the rate design for each Service are explained in Section I.E of the transmittal letter.
Statement BE Specific assignment data: See Exhibit 3 for direct allocations to the three rate schedules in Section IV.A of the Tariff.
Statement BF Exclusive-use commitments of major power supply facilities: Not applicable.
Statement BG Revenue data to reflect changed rates: See Sections I.C and I.E of the transmittal letter. The entire projected revenue requirement for a Service (discussed in Exhibit 3) is paid for by the corresponding customer group described in the Statement BA discussion, above. Exhibit 7 Page 4 of 4 The billing determinants for each Service are discussed in Section I.E of the filing letter. The ISO has no fuel clause.
Statement BH Revenue data to reflect present rate: See Sections I.C. and I.E of the filing letter.
Statement BI Fuel cost adjustment factors: not applicable.
Statement BJ Summary cost tables: See Exhibit 3.
Statement BK Electric utility department cost of service: See Exhibit 3.
Statement BL Rate design information: See Section I.E of the filing letter.
Statement BM Construction program statement: Not applicable.
EXHIBIT 8
EXHIBIT 9 New England Governors, State Utility Regulators and Related Agencies*
Connecticut
The Honorable Dannel P. Malloy New Hampshire Office of the Governor State Capitol The Honorable Maggie Hassan 210 Capitol Ave. Office of the Governor Hartford, CT 06106 26 Capital Street [email protected] Concord NH 03301 [email protected] [email protected] [email protected] Connecticut Public Utilities Regulatory Authority 10 Franklin Square New Hampshire Public Utilities Commission New Britain, CT 06051-2605 21 South Fruit Street, Ste. 10 [email protected] Concord, NH 03301-2429 [email protected] [email protected] [email protected] [email protected] [email protected] [email protected] Maine [email protected] [email protected] The Honorable Paul LePage One State House Station Office of the Governor Augusta, ME 04333-0001 Rhode Island [email protected] The Honorable Gina Raimondo Maine Public Utilities Commission Office of the Governor 18 State House Station 82 Smith Street Augusta, ME 04333-0018 Providence, RI 02903 [email protected] [email protected] [email protected]
[email protected] Massachusetts [email protected] The Honorable Charles Baker [email protected] Office of the Governor [email protected] State House Boston, MA 02133
Massachusetts Attorney General Office One Ashburton Place Rhode Island Public Utilities Commission Boston, MA 02108 89 Jefferson Blvd. [email protected] Warwick, RI 02888 [email protected] [email protected] Massachusetts Department of Public Utilities [email protected] One South Station
Boston, MA 02110
[email protected] Vermont [email protected]
5/1/2015 New England Governors, State Utility Regulators and Related Agencies*
The Honorable Peter Shumlin New England Conference of Public Utilities Office of the Governor Commissioners 109 State Street, Pavilion 89 Jefferson Boulevard Montpelier, VT 05609 Warwick, RI 02888 [email protected] [email protected] [email protected]
Harvey L. Reiter, Esq. Vermont Public Service Board Counsel for New England Conference of Public 112 State Street Utilities Commissioners, Inc. Montpelier, VT 05620-2701 c/o Stinson Morrison Hecker LLP [email protected] 1150 18th Street, N.W., Ste. 800 [email protected] Washington, DC 20036-3816 [email protected] Vermont Department of Public Service 112 State Street, Drawer 20 Montpelier, VT 05620-2601 [email protected] [email protected] [email protected]
New England Governors, Utility Regulatory and Related Agencies
Anne Stubbs Coalition of Northeastern Governors 400 North Capitol Street, NW Washington, DC 20001 [email protected]
Heather Hunt, Executive Director New England States Committee on Electricity 655 Longmeadow Street Longmeadow, MA 01106 [email protected] [email protected]
Rachel Goldwasser, Executive Director New England Conference of Public Utilities Commissioners Concord, NH 03301 [email protected]
Margaret “Meg” Curran, President
5/1/2015
EXHIBIT 10
September 29, 2015 David J. Vitale Chairman ISO New England One Sullivan Road Holyoke, MA 01040
Re: Comments on proposed 2016 ISO New England Budget
Dear Chairman Vitale:
On behalf of the undersigned New England state agencies, we hereby offer comments regarding the ISO New England (“ISO-NE or “ISO”) proposed 2016 administrative and capital budgets. We welcome this opportunity to provide direct feedback to you regarding the budgets.
We deeply appreciated the ISO-NE Board of Directors’ (“Board”) Board's attendance at the budget briefing in June, and commend you and your fellow Board members for your efforts to keep cost increases within reasonable limits. We appreciate that the overall cost increase was restricted to 3.9% for the operating budget. We also appreciate the change to a level funding approach for the defined benefit pension liability, as it will ease the volatility of the expense.
The processes that have been developed to date, and the efforts of all parties involved, have helped to limit our comments to two areas. First, we wish to propose a timing change in the states' review of ISO's budget, to accommodate the Board's calendar and better align the purpose of the process. Second, we wish to express our repeated, and continuing concerns about the sustained, rapid growth in staffing levels.
I. The Budget Review Process Should Occur Sooner in Order to Provide the Board with the States' Position When the Board Discusses the Budget.
We believe the new budget review procedure has resulted in a much more cooperative and productive process. However, we propose that this review process be modified to occur earlier, so that the States' comments are submitted to the Board prior to the Board's in-person meeting on the budget. We realize that the Board met and reviewed the budget on September 17, more than a week before the States' comments were due. We also understand that the Board will receive the States' comments, management's response and the results of the NEPOOL Participants' Committee vote prior to acting on the budget by written consent (electronically) in mid-October. We
Daniel J. Vitale Chairman, ISO New England September 29, 2015 Page 2
would like to modify this process so that the Board has the benefit of the States' comments and ISO management's response when it meets and deliberates in person on the budget.
The Settlement Agreement provides that the State Parties:
may submit comments regarding any proposed adjustments to the proposed budget within five weeks after the August budget presentation meeting but no later than September 25. ISO-NE shall respond in writing to any written comments and proposed adjustments within two weeks of receipt, but no later than five business days before the ISO-NE Board of Directors votes on the proposed budgets.
The intent of providing written comments was to provide the ISO NE Board with the opportunity to consider and discuss the States' concerns prior to voting on the budget. Moreover, as last year's comments and this year's comments should demonstrate, knowledge of the questions submitted is not dispositive of the States' position on a budget. To comply with the intent of the Settlement Agreement, and to provide the Board with the States' views during the Board's in-person review of the budget, we request that the process be modified to ensure that the Board has the States' comments prior to reviewing the budget in person.
II. The Continuing Escalation of Staff
With this budget, ISO-NE will have added 52 full-time, funded employees since FY 2013.1 As the first substantive term in the 2013 Settlement Agreement, ISO-NE agreed that it would rely:
to the greatest extent possible on its current employee complement to perform all existing and proposed new projects, and shall document its efforts to do so as set forth below.
Section II.A of the Settlement Agreement. An additional 52 full-time, funded positions does not appear to comport with this obligation. Moreover, this continuing escalation of staff is not sustainable.
1 As of December 31, 2012, ISO-NE had 539.5 FTEs. By the end of 2013, ISO-NE employed 560 FTEs, and by the end of 2014, had 567.5 employees. Pursuant to last year's budget, ISO has 577 funded FTE positions for this year, of which 576 were filed by June 30, 2015. From FY2013 to FY2015, ISO-NE added 43.5 new funded FTE positions in its budgets, and now seeks to add an additional 8.5 FTEs for FY 2016, for a total of an additional 52 full-time, funded positions since FY2013.
Daniel J. Vitale Chairman, ISO New England September 29, 2015 Page 3
As part of its oral presentation in June 2015, ISO management stated that it would not seek additional FTE positions for its FY 2017 budget. When asked to confirm this commitment, management responded "That is our current intention, but it is subject to changes in workload brought about by regulatory and other exigent priorities." Every state agency and most businesses have workload changes and exigent priorities, and yet do not have the ability to add employees when a significant new directive arises. Rather, as new directives are introduced, other priorities must make way or other efficiencies must be explored.
We ask you to address this repeated, multi-year concern. The growth in full-time employees served as one of the major drivers for the challenge to the budget that resulted in the Settlement Agreement now governing this budget review process. We are available to meet with management or the Board on this issue if it would assist in resolving this continuing issue.
CONCLUSION
The undersigned New England State Agencies are heartened by the progress made during this year’s budget review. However, we ask that the process for next year's budget review be rescheduled so you have the benefit of our comments before you deliberate and discuss the budget in person, and we look forward to discussing this proposal with management. We also respectfully request that you consider and address our continuing concern with the escalation of staffing levels at ISO NE.
Respectfully submitted,
_/s/ Arthur H. House______/s/ Elin Swanson Katz______Arthur H. House Elin Swanson Katz Chairman Consumer Counsel Public Utilities Regulatory Authority Office of Consumer Counsel Ten Franklin Square Ten Franklin Square New Britain, CT 06051 New Britain, CT 06051
_/s/ George Jepsen______/s/ Ed McNamara______George Jepsen Ed McNamara Attorney General Regional Policy Director Office of the Attorney General Vermont Department of Public Service 55 Elm Street 112 State Street Hartford, CT 06105 Montpelier, VT 05620
Daniel J. Vitale Chairman, ISO New England September 29, 2015 Page 4
_/s/ Leo J. Wold______/s/ Susan Chamberlin______Leo J. Wold, Assistant Attorney General Susan Chamberlin Rhode Island Department of Attorney General Consumer Advocate 150 South Main Street Office of the Consumer Advocate Providence, RI 02903 21 South Fruit Street For Peter F. Kilmartin, Attorney General Concord, NH 03301 of the State of Rhode Island and the Rhode Island Division of Public Utilities and Carriers
EXHIBIT 11
Philip Shapiro Chairman, Board of Directors
October 9, 2015
Susan W. Chamberlin, New Hampshire Consumer Advocate Arthur H. House, Chairman, Connecticut Public Utilities Regulatory Authority George Jepsen, Connecticut Attorney General Elin Swanson Katz, Connecticut Consumer Counsel Peter Kilmartin, Rhode Island Attorney General Ed McNamara, Vermont Department of Public Service Leo Wold, Rhode Island Division of Public Utilities and Carriers
Dear State Officials:
Thank you for your letter dated September 29, 2015 regarding ISO New England’s 2016 operating and capital budgets. I appreciate your comments and your involvement in ISO New England’s budget process. Below, I address your comments.
Budget Review Process In your letter, you propose modifying the budget review process to ensure that the ISO Board of Directors receives the states’ comments before the Board’s September meeting, at which the Board reviews the budgets in detail. As you note, the states’ comments are due no later than September 25, and the Board typically meets in the middle of September. In 2016, the Board will meet on September 15.
We would be very happy to have the benefit of the states’ formal comments for consideration at our Board meeting.1 If the states are able to offer their written comments before the Board meeting, I will ensure that they are distributed to the full Board.
Currently, the budget review process entails a number of steps before the states submit their comments. These steps include: (i) the ISO’s preparation of the comprehensive budget presentation; (ii) a budget review meeting with the states within three days of the ISO’s meeting with the NEPOOL Budget & Finance Subcommittee; (iii) the ISO’s receipt of questions from the states within two weeks of the budget review meeting; and (iv) completion of the ISO’s responses to the questions within a week of their receipt.
The timeline to complete these steps is constrained by the time required to prepare the budget presentation and the meeting date with NEPOOL. As you note in your letter that “knowledge of the questions submitted is not dispositive of the States’ position on a budget,” I am hopeful that the change required to meet your objective is as simple as the states submitting comments early in the
1 The Board also receives informal feedback from the states about the budget, including through Board attendance at the NECPUC annual symposium.
ISO New England Inc. iso‐ne.com One Sullivan Road isonewswire.com Holyoke, MA 01040 ‐2841 @isonewengland 413‐535‐4000 iso‐ne.com/isotogo iso‐ne.com/isoexpress State Officials October 9, 2015 Page 2 of 2
process. In that case, we understand that you may reserve your rights to submit further comments pending the completion of the above‐referenced process.
If you believe that further change to the process is required, I will ask the ISO’s staff to work with you and NEPOOL. Although, as noted above, the timeline is constrained, we believe that we can move the steps forward by approximately a week on our end. With the consent of you and NEPOOL, the revised process would require: our circulation of the budget presentation during the first week of August; holding the Budget & Finance Subcommittee and state meetings during the second week of August; the states’ submission of their questions within a week of their meeting; and the ISO’s submission of answers within the next week. This schedule should enable you to deliver your comments to the Board before the mid‐September meeting.
Headcount In your letter, you note that the ISO will have added 52 full‐time employees over the course of 2013, 2014, 2015 and 2016. You also note our obligation to use existing employees to perform all work, to the greatest extent possible.
We do not believe that these two facts are mutually exclusive. Simply put, our workload has grown beyond an amount that our existing employees can handle. In general, this is due to requirements imposed on us by the Federal Energy Regulatory Commission and priorities established by stakeholders and the states. For example, the growth of renewable and distributed energy as a result of state policies will increase the complexity of planning for and operation of the system – and additional resources may be required to maintain the reliability of the grid.
The foregoing is just one example of a situation in which the Board, exercising its fiduciary duty, and management (joined, possibly, by stakeholders) may determine that there are unacceptable risks in not hiring. That was the case for 2016, when we directed management to establish a 24/7 cyber security control center. The center accounts for the bulk of the headcount additions in 2016. The remaining full‐time positions were identified as necessary by our internal market monitor.
You note that ISO management has stated their intention to keep headcount flat in 2017. As this statement indicates, we are aware of the cost implications of increasing headcount. Accordingly, we plan to use consultants to manage the variability of our workload in 2017, but will continue to measure the costs of so doing against the costs of using full‐time employees. (As reported in past years, some of the 52 headcount that were added served to reduce our overall costs.) We will also balance our intention to keep headcount flat in 2017 against our recognition of the risks that are sometimes inherent in forgoing additional resources.
Thank you again for your letter. We look forward to continuing to work together with you to ensure the continued reliable and efficient delivery of electricity to New England.
Sincerely,
Philip Shapiro Chairman of the Board of Directors
ISO New England Inc. iso‐ne.com One Sullivan Road isonewswire.com Holyoke, MA 01040 ‐2841 @isonewengland 413‐535‐4000 iso‐ne.com/isotogo iso‐ne.com/isoexpress