testimony of iso new england on its 2014 budget proposal

8/10/2019 Testimony of ISO New England on Its 2014 Budget Proposal

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Exhibit 3


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ISO New England Inc. Exhibit 3

Recovery of 2014 Administrative Costs

UNITED STATES OF AMERICA

BEFORE THE

FEDERAL ENERGY REGULATORY COMMISSION

ISO New England Inc. ) Docket No. ER14-_____-000

DIRECT TESTIMONY

OF

ROBERT C. LUDLOW

Filed on: October 15, 2013


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TABLE OF CONTENTS

PURPOSE OF TESTIMONY ......................................................................................................... 2

CURRENT OPERATIONS AND ORGANIZATIONAL STRUCTURE OF THE ISO ............... 4

THE BUDGET DEVELOPMENT PROCESS ............................................................................... 5

DESCRIPTION OF THE 2014 REVENUE REQUIREMENT ...................................................... 7

ACTIVITY ACCOUNTING SYSTEM ........................................................................................ 20

2014 COST ALLOCATION AMONG SCHEDULES 1, 2, AND 3 ............................................ 22

THE ISO RATE DESIGN AND BILLING DETERMINANTS .................................................. 34

RATE SUMMARY ...................................................................................................................... 37

FIXED FEES................................................................................................................................. 39

CONCLUSION ............................................................................................................................. 41


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ATTACHMENTS TO THIS TESTIMONY

RCL-1: Organization Chart (CEO direct reports)

RCL-2: Revenue Requirement and True-Up

Schedule 1: [reserved]

Schedule 2: 2014 Revenue Requirement and 2012 True-Up

RCL-3: Test Year 2014 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 CategorySchedule 5: Allocation Factors by Cost Category

Schedule 6: Allocation of Depreciation and Amortization Expense

RCL-4: [reserved]

RCL-5: 2014 Core Operating Budget

Schedule 1: Overview of Operating Expense Budget

Schedule 2: Detail of Components of 2014 Operating Expense Budget

Schedule 3: Variance Summary (vs. 2013)

Schedule 4: Detailed Change in Budget (vs. 2013)Schedule 5: Staffing Projections

Schedule 6: 2014 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 2013 and Test Year 2014

Schedule 3: Rate Design Summary

Schedule 4: Annual Revenue Comparison at Present and Proposed RatesSchedule 5: Comparison of Schedule 2 Revenues from Transaction Units for 2012

Schedule 6: Schedule 2 TU True-Up Summary

RCL-8: NEPOOL Resolution


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Recovery of 2014 Administrative Costs Page 1

UNITED STATES OF AMERICA1

BEFORE THE2

FEDERAL ENERGY REGULATORY COMMISSION3

ISO NEW ENGLAND INC. ) Docket No. ER14-_____-0004

Direct Testimony of Robert C. Ludlow5

Q. PLEASE STATE YOUR NAME AND BUSINESS ADDRESS.6

A. My name is Robert C. Ludlow. My business address is One Sullivan Road,7

Holyoke, Massachusetts 01040-2841.8

Q. WHAT IS YOUR OCCUPATION?9

A. I am a Vice President and the Chief Financial and Compliance Officer of ISO10

New England Inc. (the ISO). I served in the role of Vice President and Chief11

Financial Officer from the time the ISO commenced its operations on July 1, 199712

until September 2000. At that time, I began working as an outside consultant for13

the ISO until August 2002, when I rejoined the ISO as Vice President and Chief14

Financial Officer. In July of 2008 my title changed to reflect my expanded15

responsibility for compliance. The compliance organization is responsible for16

developing and maintaining the Companys compliance management system.17

This system captures the Companys compliance obligations, including those of18

the North American Electric Reliability Corporation (NERC), North American19

Energy Standards Board, and the Northeast Power Coordinating Council20

(NPCC).21


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Q. PLEASE DESCRIBE YOUR EDUCATIONAL BACKGROUND AND1

PROFESSIONAL EXPERIENCE.2

A. I hold a B.B.A. in Accounting from St. Bonaventure University. Prior to joining3

the ISO, I was a Partner at the accounting firm of Marden, Harrison & Kreuter,4

CPAs. I also served as the Chief Financial Officer of Western Beef, Inc. I am a5

Certified Public Accountant.6

Q. HAVE YOU PREVIOUSLY TESTIFIED BEFORE A REGULATORY7

COMMISSION?8

A. Yes. I previously have testified before the Commission to support prior9

administrative rate filings by the ISO in Docket Nos. ER13-185-000 (rates10

proposed for 2013), ER12-191-000 (rates proposed for 2012), ER11-1943-00011

(rates proposed for 2011), ER10-154-000 (rates proposed for 2010), ER09-197-12

000 (rates proposed for 2009), ER08-189-000 (rates proposed for 2008), ER07-13

116-000 (rates proposed for 2007), ER06-94-000 (rates proposed for 2006),14

ER00-395-000 (rates proposed for 2000), and ER98-3554-000 (rates proposed for15

1998).16

PURPOSE OF TESTIMONY17

Q. WHAT IS THE PURPOSE OF YOUR TESTIMONY?18

A. I am providing this testimony primarily to support the ISOs proposed revenue19

requirement for 2014 (2014 Revenue Requirement) and the updated rates to20

collect it. My Direct Testimony presents the ISOs 2014 Revenue Requirement as21


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reflected in the proposed revised tariff sheets attached as Exhibits 1 and 2 (clean1

and blacklined versions, respectively) to the filing letter. Specifically, I will2

summarize the elements of the ISOs 2014 Revenue Requirement (including the3

true-up mechanism), describe the ISOs budget process, present the ISOs 20144

Core Operating Budget, and describe the ISOs activity accounting system. I will5

also present the development of the Test Year 2014 cost of service study6

associated with the ISO providing service under the three primary rate schedules7

included in Section IV.A of the ISOs Transmission, Markets and Services Tariff8

(the Tariff). Section IV.A of the Tariff provides for recovery of the ISOs9

administrative expenses. The three primary rate schedules are: (1) Schedule 1 10

Scheduling, System Control and Dispatch Service (Scheduling Service); (2)11

Schedule 2 Energy Administration Service; and (3) Schedule 3 Reliability12

Administration Service. I will present proposed escalation factors to adjust actual13

load data for the 12-month period ending July 2013to the Test Year 2014 for the14

purpose of rate design, discuss the rate design utilized, and the proposed rates,15

including certain fixed fees.16

Q. HOW WILL YOUR TESTIMONY BE ORGANIZED?17

A. Before offering a conclusion, I will describe:18

(i) the current operations and organizational structure of the ISO;19

(ii) the budget development process;20

(iii) the various elements of the 2014 Revenue Requirement;21


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(iv) the ISOs activity accounting system;1

(v) how the ISO allocated its costs among the rates it proposes to charge in the2

Tariffs Schedules 1, 2, and 3;3

(vi) the 2014 rate design and escalation factors;4

(vii) the 2014 rate design and billing determinants;5

(viii) a rate summary; and6

(ix) fixed fees.7

CURRENT OPERATIONS AND ORGANIZATIONAL STRUCTURE OF THE ISO8

Q. WHAT ARE THE CURRENT OPERATIONS AND ORGANIZATIONAL9

STRUCTURE OF THE ISO?10

A. The ISO provides three basic services to its customers:11

1. Scheduling Service (Schedule 1): Through this service, the ISO schedules12

at the pool level the movement of power through, out of, within, or into13

the New England Control Area.14

2. Energy Administration Service (Schedule 2): Through this service, the15

ISO administers the energy markets and facilitates generation and demand16

dispatch, auctions for Financial Transmission Rights (FTRs), and other17

services (i.e., under Section III of the Tariff).18

3. Reliability Administration Service (Schedule 3): Through this service, the19

ISO administers the reliability markets (and facilitates reliability-related20


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transactions and arrangements) in accordance with Market Rule 1 and1

provides other reliability and informational services.2

The ISO is governed by an independent Board of Directors with a cross-section of3

skills and experience, including regulatory affairs, energy industry management,4

corporate finance, bulk-power systems, public policy, and market development.5

The ISO is overseen by a President and Chief Executive Officer (CEO) who has6

seven direct reports. An Executive Vice President and Chief Operating Officer is7

responsible for Market Operations, System Operations, System Planning, Market8

Development, Program Management, Business Architecture, and Information9

Technology. The other direct reports of the CEO are: Vice President and General10

Counsel; Vice President of External Affairs and Corporate Communications; Vice11

President, Chief Financial & Compliance Officer; Vice President, Human12

Resources; Vice President, Market Monitoring; and Director, Internal Audit. The13

latter two positions report to the CEO for administrative purposes only. See RCL-14

1, attached to this testimony.15

THE BUDGET DEVELOPMENT PROCESS16

Q. HOW WERE THE ISOS BUDGETS DEVELOPED FOR 2014?17

A. The ISO prepares budgets in advance of each upcoming year using a seven-step18

business planning process, throughout which stakeholder input is sought. The19

seven-step process is:20


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1) define objectives, activities and goals;1

2) identify efficiencies for each department;2

3) determine resource requirements;3

4) develop budget estimates for each department;4

5) adjust budgets to ensure that staff resources and activities are aligned with the5

business plan;6

6) conduct senior staff review to ensure alignment of budget with the ISOs7

business plan and overall fiscal constraint; and8

7) develop priorities.9

Q. PLEASE SUMMARIZE THE STAKEHOLDER PROCESS USED TO10

REVIEW THE 2014 BUDGET.11

A. After reviewing budget scenarios with both state agencies and NEPOOL at12

meetings in June, the ISO presented the 2014 Revenue Requirement at the13

NEPOOL Budget and Finance Subcommittees August 23, 2013 meeting and at a14

meeting for state agencies on August 28, 2013. The ISO also presented the15

budgets to the NEPOOL Participants Committee at the Committees meetings on16

September 13 and October 4, 2013. At the October 4 meeting, the ISOs 201417

Revenue Requirement was supported by 86.28% of the Participants Committee.18

The terms of the NEPOOL Participants Committees action are reflected in the19

resolution in RCL-8, attached to this testimony. In that same resolution, the20

NEPOOL Participants Committee also supported the capital budget for 2014. The21

ISO Board of Directors approved the budgets on October 11, 2013.22


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Q. WHAT IS THE IMPACT OF THE INCREASED REVENUE1

REQUIREMENT ON CONSUMER COSTS?2

A. If the ISOs Revenue Requirement was fully passed through to end-use customers,3

their cost would average 86 cents per month, up from 2013 levels of 83 cents. See4

slide 12 of the ISOs annual budget presentation to stakeholders (the Budget5

Presentation). The presentation is located at http://www.iso-6

ne.com/committees/comm_wkgrps/prtcpnts_comm/budgfin_comm/budgfin/mtrls/7

2013/aug232013/2014_op_cap_budg_nepoool_bf_08_23_13_updated_for_oct_np8

c.pdf.9

Q. WHAT ARE THE MOST SIGNIFICANT CHANGES IN THE 201410

OPERATING EXPENSE BUDGET COMPARED WITH THE 201311

OPERATING EXPENSE BUDGET?12

A. As described below, the ISO proposes to increase its Core Operating Budget by13

approximately $5.3 million from 2013 levels to fund (i) external factors and14

compensation; (ii) new market rules and operational changes; and (iii) other15

measured growth initiatives.16

Q. PLEASE DESCRIBE THE COSTS FOR EXTERNAL FACTORS AND17

COMPENSATION INCREASES.18

A. This category includes merit and promotional increases; increased interest19

expense; increased costs of computer software/maintenance; increased Northeast20


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Power Coordinating Council dues; and incremental costs for operating the new1

Back-Up Control Center.2

The ISO has budgeted for a 3.0% increase in salaries for merit and a .5% increase3

for promotions. The budgeted amounts for merit and promotion are developed4

using data from several national compensation consultants, and are within the5

ranges reported in these surveys. Please see Ms. Dicksteins testimony for detail6

on the development of these allocations, compensation practices in general, and7

the ISOs compliance with the standards of the Internal Revenue Service8

regarding the reasonableness of executive compensation.9

Interest expense for 2014 will increase from 2013 levels. The interest expense on10

the ISOs debt is recovered currently via the Tariff. The cost increase is due in11

part to acceleration of the replacement of the private placement debt that was12

issued in September 2004. This debt funds the ISOs capital program. More13

specifically, the ISO entered into $39 million in private placement notes in14

September 2013 to replace the outstanding 2004 notes. The ISO took this action15

slightly before the expiration of the current notes, in order to take advantage of the16

current low interest rate environment, thereby locking in a favorable interest rate.17

The new private placement notes have a delayed funding date of May 2014 to18

minimize the cost of the additional interest expense.19

In addition, the interest costs on the $36 million in the Connecticut-issued tax-20

exempt bonds that were used to fund the new Back-up Control Center will21


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become an operating expense. There is also a slight increase due to a full years1

impact of interest expense related to the $11 million in private placement notes2

that were issued in November 2012 to supplement the $39 million, again for use3

in the capital program.4

Finally, this category includes costs of operating the new Back-Up Control Center,5

including costs of physical security, maintenance and upkeep, utilities, and other6

costs.7

Q. PLEASE DESCRIBE THE INCREASES FOR NEW MARKET RULES8

AND OPERATIONAL CHANGES.9

A. These costs are in the areas of Market Operations, System Operations, System10

Planning and Information Technology, and follow changes to market rules and11

operations, many of which are related to the Strategic Planning Initiative.12

Through that effort, the region has identified several key risks that will impact the13

regions power system and wholesale electricity markets. The risks are:14

Risk 1: Resource Performance and Flexibility15

Risk 2: Increased Reliance on Natural Gas-Fired Capacity16

Risk 3: Potential Retirement of Generators17


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Risk 4: Integration of a Greater Level of Variable Resources1

Risk 5: Alignment of Markets with Planning2

In 2014, the region will implement related solutions, including verification and3

determination of wind models for operational studies, integration of photovoltaic4

and other variable resources, fuel tracking, and Forward Capacity Market5

performance incentives.6

Q. PLEASE DESCRIBE THE INCREASES FOR MEASURED GROWTH7

INITIATIVES.8

A. This category includes the costs of various projects, including compliance with9

Order No. 1000, Intra-Day Offers, and management of cyber security risks. This10

category includes funding for the following six new full-time employees: one11

full-time transmission planner to facilitate compliance with the new transmission12

planning and cost allocation requirements of Order 1000; three full-time13

employees to manage the new energy market offer process; an employee in the14

Cyber Security area; and an employee to assist in the implementation of the new15

information technology asset management program.16

Q. PLEASE PROVIDE FURTHER INFORMATION ON INCREASED HEAD17

COUNT FOR 2014.18

A. To determine its resource needs for 2014, the ISO looked at the work load to be19

completed, including on-going work from 2013, non-repetitive work from 2013 to20

2014, and new work for 2014. Each area of the Company then reviewed the21


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current resources available to complete this work, utilizing the current employee1

complement to perform this work to the greatest extent possible. Accordingly, in2

approaching the completion of the bottom-up budget, the ISO looked to add3

positions only if (1) the position was needed for resource purposes or (2) the4

position was cost beneficial to the overall budget.5

The ISO is requesting a total of eight additional positions in the 2014 budget6

(funding for five net of vacancy rate). Of the eight requested positions, six are for7

Measured Growth initiatives, as discussed above; the remaining two are for8

positions in Legal and IT Systems that were added as alternatives to higher-cost9

options of external resources (meaning that the savings in professional fees more10

than offset the cost of the new position).11

These eight positions relate to only a small portion of the additional work being12

taken on for 2014. In addition to taking on a portion of Measured Growth work,13

including Order 1000 work, with existing staff, the ISO will also undertake the14

Market Rule and Operational Changes described above with existing staff. The15

increased work stemming from Market Rule and Operational Changes is16

calculated to be $3,700,000, or the full time equivalent of approximately 2517

positions. Rather than increasing the requested headcount by 25, the ISO was able18

to cover this new work and the Measured Growth projects with an increase of19

only eight new positions by redirecting existing employees work.20


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Q. THERE HAS BEEN SIGNIFICANT ORGANIZATIONAL GROWTH IN1

RECENT YEARS. CAN YOU EXPLAIN IT?2

A. The ISO has grown significantly, adding more than 100 new employees since3

2009. This growth reflects the increase in the complexity of the ISOs operations.4

For example, with the integration of demand resources into the Forward Capacity5

Market, the number of registered and modeled assets has increased from a few6

hundred to a few thousand. In addition, compliance with new and emerging7

NERC and NPCC standards has required a significant investment. The ISO has8

also provided additional services, like doubling its billing obligations through9

twice-weekly billing, which further mitigated market participants risk of10

significant payment defaults. All of these changes require personnel.11

More specifically, there are three major areas that have contributed to the need for12

increased staffing. The first major area is that of Strategic Initiatives, Measured13

Growth and Expanded Services. This includes employees to run transmission14

planning and economic studies, to administer the Forward Capacity Market, and15

new market monitoring positions, as well as employees to manage demand16

resource integration.17

Another area that has contributed to the addition of employees is the replacement18

of long-term contractors with FTEs. At least a dozen employees have been added19

to replace temporary help or contractors where the responsible manager made a20

determination that the work being performed is permanent and that it was cost21


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advantageous to convert the position to a FTE. These added positions had little or1

no impact on the budget.2

Finally, the third major area is that of staffing and training requirements for3

System Operators. This includes employees to staff the Back-Up Control Center,4

which is more robust as a result of compliance with more stringent requirements5

from the Commission and NERC, and employees for training and backup for6

Control Room Operators.7

Q. HOW DOES ISO-NES SIZE COMPARE TO OTHER ISOS AND RTOS?8

While the types and scopes of services vary widely among the ISOs and RTOs,9

many costs are largely fixed, because all ISOs and RTOs must comply with the10

Commissions orders and mandatory reliability standards. ISO-NE does review11

what others are spending. (Seedetail on comparisons in the ISOs Budget12

Presentation.) ISO-NEs review indicates that its cost structure is reasonable.13

Q. PLEASE DESCRIBE THE BUDGET CUTS AND DEFERRALS THAT14

OFFSET THESE INCREASED COSTS.15

A. For 2014, the ISO has realized a $1.8 million reduction in pension plan costs due16

to a change in the discount rate. The ISO has also realized $6.2 million in savings17

by reallocating resources, automating work, identifying efficiencies, and18

eliminating discontinued or non-repetitive work.19


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Q. DOES THE REVENUE REQUIREMENT INCLUDE DEPRECIATION ON1

ITEMS IN THE CAPITAL BUDGET THAT ARE PLACED IN SERVICE2

IN 2014?3

A. Yes. The ISOs depreciation rates remain unchanged from those accepted by the4

Commission in the ISOs 2013 Operating Expense Budget. The ISO uses the5

straight-line depreciation methodology based on no net salvage value and the6

various average service lives described below. These service lives reflect the7

ISOs historical experience and forecasted expectations for capital projects placed8

into service, are necessary to comply with the ISOs funding mechanisms, are9

consistent with the ISOs historical experience, and have been repeatedly10

determined by independent auditors to be appropriate. The service lives are:11

Computer hardware, software and accessories: 3 to 5 years12

Software development costs: 3 to 5 years13

Furniture and fixtures: 7 years14

Machinery and equipment: 7 years15

Building: average of 25 years (based on the opinion of independent bond16

counsel and analysis of the service lives of the different aspects of the17

building (e.g., the buildings steel and concrete at 40 years, mechanical18

and electrical work at 25 years, and high wear-and-tear elements at 1519

years))20

Leasehold/Building Improvements: lesser of 1 to 25 years or remaining21

life of the lease or building, as determined at the time of the purchase22


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capital project also includes the first year maintenance cost and license fees for1

any newly capitalized software.2

Q. HOW DOES THE ISO ADDRESS UNEXPECTED COSTS THAT MIGHT3

MATERIALIZE DURING 2014?4

A. The 2014 Core Operating Budget includes two line items to address unexpected5

needs: (i) the CEO Emerging Work allowance of $1.1 million; and (ii) the6

Operating Contingency of $700,000. Inclusion of these contingency amounts7

recognizes that circumstances may arise that the ISO does not foresee in setting its8

2014 Revenue Requirement for its various departments and programs.9

The CEO Emerging Work Allowance covers new or deferred activities and10

initiatives that emerge or become priorities during the year. Approval from both11

the CEO and CFO is required before the ISO may draw upon these funds.12

The Operating Contingency provides a funding source of last resort. ISO13

management cannot access this fund without first obtaining approval from the14

ISOs independent Board of Directors.15

Q. DO YOU FORESEE ANY PARTICULAR CONTINGENCIES THAT16

WILL WARRANT THE ISO TAPPING INTO THESE FUNDS?17

A. I cannot say for sure what type of contingencies might arise. There are, however,18

several ongoing issues that might require additional funds not included in the19

2014 Core Operating Budget. The biggest issue is litigation that could be initiated20


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or increased in 2014. Additional risks include costs to comply with unforeseen1

significant shifts in federal and state policy, costs of complying with Order 10002

that exceed estimates, and interest rates. In general, Customers and the3

Commission will determine the extent of additional work and resources required.4

Q. HAS THE ISO TAKEN ANY ACTION TO MITIGATE THE RISK OF A5

CHANGING INTEREST RATE ENVIRONMENT?6

A. The ISO intends to purchase an interest rate cap for a portion of its tax-exempt7

bond issuances. The tax-exempt bonds were issued in Massachusetts to fund the8

refurbishing of the Main Control Center and in Connecticut to fund the9

development of the new Back-Up Control Center. Both sets of bonds are priced10

at a weekly variable rate.11

The ISO intends to purchase the cap to cover the unhedged portion of its variable12

rate debt. In other words, the ISO would not seek to cover the portion that is13

naturally hedged by the interest income earned on the settlement float that the ISO14

has through the normal course of participant settlement billing and payment.15

The ISO has saved approximately $7,500,000 by opting for variable rates on its16

tax-exempt bonds since 2005 when the ISO first issued the Massachusetts tax-17

exempt bonds. The ISO seeks to protect that savings by purchasing the interest18

rate cap at a rate of 2.48% (which is the price at which the ISO could have fixed19

the Connecticut tax-exempt bonds when they were issued last year). The cap will20


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effectively serve as an insurance policy or stop loss mechanism in a changing1

interest rate environment, and is intended to cover the ISOs interest rate exposure2

through February 1, 2024 if rates rise significantly.3

After consulting with its external auditors, KPMG, the ISO will amortize the4

approximate $1,000,000 cost of the cap using a straight line method over the life5

of the cap. This amortization would likely result in a similar annual cost if the6

effective interest rate method was used. The operating budget impact will be7

about $88,000/year. For 2014, the annual cost will be funded using the CEO8

Emerging Work Allowance, as the ISO committed to the interest rate cap late in9

the process of formulating the 2014 budget.10

Q. PLEASE DESCRIBE THE CALCULATION OF THE 2012 TRUE-UP11

AMOUNT.12

A. As set forth in Section IV.A.2.2 of the Tariff, the ISO has reconciled calendar year 2012s13

actual expenses and collections under Schedules 1, 2 and 3 of the Tariff by means of a14

true-up. The actual difference between 2012 expenses and collections is an under-15

collection of $1.9 million, which increases the 2014 Revenue Requirement by that16

amount. SeeRCL2, Schedule 2.17


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Q. HOW IS THE 2012 TRUE-UP AMOUNT ALLOCATED AMONG THE1

THREE SCHEDULES?2

A. Schedule 1 has an increase of $805,723; Schedule 2 has an increase of3

$1,871,196; and Schedule 3 has a decrease of $759,165. See RCL-2, Schedule 2.4

ACTIVITY ACCOUNTING SYSTEM5

Q. DESCRIBE THE ISOS ACTIVITY ACCOUNTING SYSTEM AND THE6

EXTENT TO WHICH IT PROVIDES COST OF SERVICE7

INFORMATION FOR EACH OF THE THREE PRIMARY SCHEDULES.8

A. The activity accounting system was implemented at the ISOs inception in 19979

and refined in 1998. All operating charges recorded in the general ledger system10

must be cross-referenced to an activity. Each department has identified its major11

activities. Most activities are department-specific, but some activities may be12

cross-charged if they are of a project nature. Activities within a department are13

known as either direct activities or indirect activities. Direct activities are of14

an operational nature and are allocated to one or more of the three schedules based15

on a fixed percentage. This fixed allocation is provided by the department16

manager annually in preparation for the next years budget and tariff filing.17

Indirect activities are of an administrative nature and are allocated based on18

current direct labor charges. In addition, the majority of activities for19

administrative departments (Finance, Human Resources, etc.) are allocated based20

on the total labor charges within the Company.21


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The activity accounting system is in large part a manual system, meaning that1

timesheets and invoices are coded manually. The ISO found that it would not be2

prudent to overly expand the system and require each employee to determine what3

schedule they serviced through the week. Furthermore, the ISO does not pre-code4

an employees time because duties may change often with seasonality or new5

projects. Therefore, the allocation of activities to the three schedules is made at6

the managerial level.7

The activity system is not designed to track costs to individual markets or8

transaction units. An employees time is not driven by the number of transaction9

units or markets, but by the number of tasks and projects.10

If the activity accounting system were expanded to provide for accounting cost in11

more detail, it would be more costly and difficult to manage without substantially12

increasing its accuracy.13

Q. HOW WAS THE TARIFF SCHEDULE ALLOCATION VERIFIED?14

A. In developing the revenue requirement for each schedule, managers with cost15

center responsibilities are required to review the allocation of each and every16

activity under their control as to the appropriateness of the allocation. During this17

lengthy evaluation process, all of the activities used by the ISO are reviewed. It is18

this activity allocation structure that formed the basis of the revenue requirements19

for each of the three primary schedules.20


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2014 COST ALLOCATION AMONG SCHEDULES 1, 2, AND 31

Q. HAVE YOU PREPARED AND INCLUDED AN EXHIBIT THAT SHOWS2

THE DEVELOPMENT OF THE COST OF SERVICE (COS)3

ANALYSIS?4

A. Yes. The following schedules support the COS shown in RCL-3:5

Schedule 1 Total Cost Allocation to Schedules by Department6

Schedule 2 Total Direct Labor Allocation to Schedules by Department7

Schedule 3 Total Cost Allocations to Schedules by Cost Category8

Schedule 4 Direct Labor Cost Allocations to Schedules by Cost9

Category10

Schedule 5 Allocation Factors by Cost Category11

Schedule 6 Allocation of Depreciation and Amortization Expense12

Q. WHAT IS THE ISOS MAIN EXPENSE?13

A. As a non-profit entity that operates, but does not own, generation or transmission14

assets, the ISOs main expense in the Core Operating Budget is personnel. As15

shown in RCL-5, Schedule 1, the ISO has budgeted $96.9 million of the ISOs16

2014 Core Operating Budget for Salaries and Overhead.17

Q. WOULD YOU PLEASE DESCRIBE YOUR RCL-3?18

A. RCL-3, Schedule 1 contains the Test Year 2014 COS for each of the three primary19

rate schedules. The exhibit lays out in detail how ISO costs were assigned to the20

three schedules.21


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Most activity costs consist of direct labor costs, employee benefits, and other non-1

labor-related costs (e.g., office supplies, software, hardware, depreciation, interest,2

consulting, etc.). For each Activity Code, both the labor-related and non-labor-3

related costs are assigned to the rate schedule using the same allocator.4

Q. PLEASE EXPLAIN HOW LABOR RATIOS WERE DEVELOPED AND5

USED TO ALLOCATE COSTS IN RCL-3.6

A. Schedule 4 of RCL-3 shows an allocation to the three schedules of all ISO direct7

labor costs as projected for Test Year 2014. Within a given department, known8

allocators (Alloc-Fixed) for specific cost categories were used to allocate those9

labor costs that were specifically attributable to a schedule. The Alloc-Fixed labor10

costs were summed for that department and all remaining labor costs within that11

department were allocated in proportion to the summed Alloc-Fixed costs. Labor12

costs within all departments were allocated in this manner and summed for the13

entire company. Schedule 5 of RCL-3 summarizes the labor allocation factors or14

labor ratios for each Activity Code. These ratios were then used to allocate15

various cost items in Schedules 3, 4, and 6 of RCL-3.16

Q. PLEASE SUMMARIZE YOUR PROPOSED 2014 COS RESULTS FROM17

RCL-3 FOR EACH OF THE THREE RATE SCHEDULES.18

A. Table 1 below summarizes the results of all the allocations contained in Schedule19

1 of RCL-3, at Lines 47, 49 and 51. The totals demonstrate an initial 201420

Operating Expense Revenue Requirement (also provided on line 10 to RCL-2,21


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Schedule 2, page 1) increased by the true-up amount (also provided on line 14 to1

RCL-2, Schedule 2, page 1) to result in the total 2014 Revenue Requirement (also2

provided on line 17 to RCL-2, Schedule 2, page 1).3

Description Test Year True-Up Total

(a) (b) (c) (d)

Schedule 1, Scheduling, System Control and Dispatch Service $ 38,455,349 $ 805,723 $ 39,261,072

Schedule 2, Energy Administration Service 78,752,397 1,871,196 80,623,593

Schedule 3, Reliability Administration Service 52,116,450 (759,165) 51,357,285

Total $ 169,324,196 $ 1,917,754 $ 171,241,950

Table 12014 Cost of Service Results (1)

(1) From Exhibit 3 (RCL-3), Schedule 1.0. 4

Q. EXCLUDING ANY TRUE-UP AMOUNTS, HOW DO THE COS RESULTS5

SHOWN IN SCHEDULE 1 OF RCL-3 COMPARE WITH THE TEST6

YEAR 2013 COS RESULTS, INCLUDED IN LAST YEARS FILING, ON7

WHICH THE CURRENT ISO RATES ARE BASED?8

A. Table 2 below compares, beforetaking into account any true-ups, the 2014 COS9

results from Schedule 1 of RCL-3 to the 2013 COS results. Table 2 demonstrates10

how, excluding the true-up amounts, the 2014 COS constitutes a $5.3 million11

increase from the 2013 COS accepted by the Commission last year.12


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Description Total Schedule 1 Schedule 2 Schedule 3

(a) (b) (c) (d) (e)

2014 COS (1) $169,324,196 $38,455,349 $78,752,397 $52,116,450

2013 COS (2) $164,041,738 $39,659,036 $73,841,673 $50,541,029

Difference -$ $5,282,458 ($1,203,687) $4,910,724 $1,575,421

-% 3.2% -3.0% 6.7% 3.1%

ISO Tariff Schedules

(1) From Table 1, Column (b).

(2) From Exhibit 3 (RCL-3), Sch. 1.0, Ln. 46, in FERC Dkt. No. ER13-185-000.

Table 2Comparison for Cost of Service Results

(Before True-Ups)

1

Q. HAVE YOU IDENTIFIED SPECIFIC ACTIVITY ITEMS THAT GIVE2

RISE TO THE INCREASES AND/OR DECREASES SHOWN ABOVE3

FOR THE THREE SCHEDULES?4

A. Yes. Table 3 below highlights key activity items from Test Year 2014 allocated5

among the three primary schedules by cost category (RCL-3, Schedule 3), along6

with various depreciation/amortization items (RCL-3, Schedule 6), which changed7

from 2013. The identified activity items account for the majority of the cost shifts8

within each of the three schedules.9


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Q. PLEASE EXPLAIN IN FURTHER DETAIL HOW THE REVENUE1

REQUIREMENTS CHANGED FOR EACH SCHEDULE FROM THOSE2

UTILIZED IN THE FILING SUPPORTING THE 2013 RATE TO THOSE3

UTILIZED HERE FOR TEST YEAR 2014.4

A. Schedule 1: The decrease in the Revenue Requirement for Schedule 1 results5

from a reallocation of resources from transmission planning to Order No. 10006

compliance (Schedule 3) and from system operations to winter and fuel security7

programs (Schedules 2 and 3). In 2014, there will also be a small reduction in8

Schedule 1 depreciation expense as certain projects that were allocated9

exclusively to Schedule 1 become fully depreciated (e.g., Outage Coordination10

Economic Analysis Tool). These decreases are partially offset by 2014 cost11

increases and changes that impact all three schedules, including cyber security,12

information technology asset management, and new operating costs of the BCC.13

Schedule 2: The increase in the Schedule 2 Revenue Requirement is due in part14

to funding for new initiatives that have a major impact on Schedule 2 (e.g., Intra-15

Day Offers, increased impact analyses, and winter and fuel security initiatives).16

Certain resources were also reallocated to Schedule 2 for work related to demand17

response registration, review and auditing, divisional accounting, and integration18

of variable resources. Schedule 2 also has increased depreciation costs for19

projects, including the Markets Database Infrastructure Update, and for costs20

allocated to all three schedules (e.g., for operation of the new BCC).21


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Schedule 3: The increase in the Schedule 3 Revenue Requirement is due to1

anticipated costs of complying with Order No. 1000, the reallocation of resources2

to Schedule 3 for work on FCM performance incentives, and for increased costs3

allocated to all three schedules (see above).4

THE ISO RATE DESIGN AND ESCALATION FACTORS5

Q. HOW DID YOU DEVELOP THE ESCALATION FACTORS?6

A. Consistent with the practice reflected in the filings establishing the ISOs rates to7

collect its administrative costs for 1999-2013, escalation factors rely on8

information contained in the 2013-2022 Forecast Report of Capacity, Energy,9

Loads and Transmission (CELT Report, dated May 2013). The CELT Report10

contains actual and estimated energy and peak loads for 2013-2022. The ISO also11

relied on information in the ISO markets system for the 12-month period ending12

July 2013. The development of the escalation factors is shown in RCL-7,13

Schedule 1.14

Q. PLEASE OUTLINE THE CURRENT RATE DESIGN BEFORE15

DESCRIBING THE VARIOUS ESCALATION FACTORS.16

A. As previously indicated, Section IV.A of the Tariff has three rate schedules to17

cover the ISOs expenses for providing its three services: Schedule 1 -18

Scheduling Service; Schedule 2 Energy Administration Service; and Schedule 319

Reliability Administration Service.20


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Schedule 11

The Schedule 1 revenue requirement is allocated 100% to Network Load and the2

Reserved Capacity of Through and Out Service (including Unauthorized Use).3

Schedule 1 revenues collected from Through and Out Service Customers are4

credited to each Network Customer that month in proportion to each Network5

Customers Monthly Regional Network Load in that month.6

Schedule 27

The Schedule 2 revenue requirement is allocated 15% to Transaction Units8

(TUs) and 85% to Volumetric Measures (VMs), subject to the special true-up9

described below. TUs measure the frequency and duration of activity and are10

indifferent to the size (e.g., capacity) of any particular transaction. Conversely,11

VMs seek to capture a customers physical reliance on the system administered12

by the ISO and thus the benefit received.13

A. Transaction Units14

Schedule 2 currently utilizes three types of TUs: those associated with Real-Time15

Market Transactions (Energy TU Based Charges), those associated with16

Increment Offers and Decrement Bids, and those associated with FTR Auction17

Submitted and Cleared Bids.18

Energy TUs equal the sum per month of a Customers Bilateral Contract Block-19

Hours, Demand Bid Block-Hours, Asset Related Demand Bid Block-Hours,20

Supply Offer Block-Hours and Energy Non-Zero Spot Market Settlement Hours.21


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Under the ISOs current rate design, a Customers total monthly Energy TUs are1

priced under a three-tiered declining block rate structure. Under this regime, the2

highest unit rate applies to the first 12,500 Energy TUs incurred in a month; the3

Customers next 27,000 Energy TUs are priced approximately 10% lower; and the4

balance of monthly Energy TUs, i.e., those in excess of 39,500, are priced at an5

additional savings of approximately 10% on average.6

TU Charges Based on Increment Offers and Decrement Bidsare assessed based7

on both of the following: (i) a charge multiplied by the total number of Increment8

Offers and Decrement Bids submitted, plus (ii) a charge multiplied by the total9

number of Increment Offers and Decrement Bids that clear the Day-Ahead Energy10

Market. This category is sometimes referred to as virtual activity,11

distinguishing it from physical activity.12

TUCharges Based on FTR Auction Submitted and Cleared Bidsare assessed on13

both of the following: (i) a charge multiplied by the total number of FTR auction14

bids submitted for that period, plus (ii) a charge multiplied by the total number of15

FTR auction bids cleared for that period. The FTR charges are designed to recoup16

the costs the ISO incurs for administering the FTR auctions. The FTR revenue17

offsets other Schedule 2 TU charge revenues.18


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B. Volumetric Measures1

Schedule 2 Volumetric Measures consist of the sum of a Customers Monthly2

Real-Time Load Obligation and Monthly Real-Time Generation Obligation3

(measured in megawatt hours, MWh). Under the ISOs current rate regime,4

Schedule 2 VMs are priced under a three-tiered declining block rate structure5

wherein the highest unitized rate is assessed to the first 250,000 MWh each6

month; the Customers next 1,250,000 MWh are priced at a discount of7

approximately 10% from the tier-1 unitized rate; and VMs in excess of 1,500,0008

MWh incur the lowest unitized monthly rate.9

Schedule 310

Schedule 3 allocates internal load activity based on Real-Time NCP [Non-11

Coincident Peak] Load Obligation. For Exports, Schedule 3 assesses a volumetric12

(per MWh) charge. Specifically, the ISO divides the Schedule 3 Revenue13

Requirement by the real-time load obligation forecasted for the upcoming year in14

the most recent CELT Report. The remaining revenue requirement for Schedule 315

(i.e., net of that allocated to Exports) is then divided by the total Real-Time NCP16

Load Obligation forecast to yield the unitized rate per kW-month.17

Q. PLEASE EXPLAIN THE ESCALATION FACTORS UTILIZED TO18

DEVELOP THE BILLING DETERMINANTS FOR 2014.19

A. The Schedule 1 billing determinants for August through December 2013 were left20

flat and the determinants for 2014 were increased by 1.4%, consistent with the21


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CELT report data, other load data, and transaction data through July 2013. See1

column (c) of RCL-7, Schedule 2. The volumetric measures in Schedule 2 and2

the Schedule 3 billing determinant related to NCP Load Obligation, which (like3

the Schedule 1 billing determinants) are also based on load data, were treated the4

same as the Schedule 1 determinants. These results are presented in columns (i)5

and (j), respectively, of RCL-7, Schedule 2.6

The Schedule 2 transaction unit determinants for Energy TUs, virtual transactions7

and FTRs were left flat. The decision regarding Energy TUs was based on a8

review of the volume of transactions, which has been consistent for several years9

(see the data for 2013 in column (d) of RCL-7, Schedule 2).10

The numbers of virtual transactions have decreased and are not expected to11

rebound, given transmission system improvements that have reduced the ability to12

profit from these transactions. The data regarding virtual transactions in 201313

appears in columns (e) and (f) of RCL-7, Schedule 2. Table 4 below provides14

historic Virtual Energy TU data from January 2011 through July 2013.15


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Table 41

0

10,000

20,000

30,000

40,000

50,000

60,000

0

50,000

100,000

150,000

200,000

250,000

300,000

350,000

400,000

Cleared

Submitted

Submi tted and Cleared Virtual Energy TUs

Submitted

Cleared

2

The ISOs analysis on Schedule 2 FTR Auction Submitted Bids through July 20133

indicates that the billing determinant should remain flat since the amount of4

submitted bids has decreased and is not expected to rebound, given factors5

including transmission system improvements. Table 5 presents actual FTR data6

from January 2011 - July 2013, and RCL-7, Schedule 2, columns (g) and (h) also7

show data for 2013.8


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Table 51

0

7,000

14,000

21,000

28,000

35,000

42,000

49,000

0

10,000

20,000

30,000

40,000

50,000

60,000

70,000

80,000

90,000

100,000

Cleared

Submitted

Submitted and Cleared FTR TUs (Bids)

Submitted

Cleared

2

Consistent with the downward trend in ISO Schedule 2 virtual activity and FTR3

auction bids, export activity has also decreased in recent years. To calculate the4

billing determinant in Schedule 3 for exports, the ISO has maintained the5

estimated values for the same period in the previous year. See column (k) of6

RCL-7, Schedule 2.7

THE ISO RATE DESIGN AND BILLING DETERMINANTS8

Q. DOES THE ISO PROPOSE ANY CHANGES TO THE EXISTING RATE9

DESIGNS FOR SCHEDULES 1, 2, AND 3?10

A. There are no changes to the rate design.11


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TABLE 6

Description TY 2014

(a) (b)

Transaction Units

INC Offers/DEC Bids

Submitted $ 0.00500 /Offer or Bid

Cleared $ 0.06000 /Offer or Bid

Financial Transmission Rights

Submitted $ 1.23712 /Bid

Cleared $ 1.76776 /Bid

Energy Transaction Units

Block 1 - 1st 12,500 TUs $ 0.73167 /TU-hour

Block 2 Next 27,000 TUs $ 0.66515 /TU-hour

Block 3 Over 39,500 TUs $ 0.59864 /TU-hour

Volumetric Measures

Block 1 - 1st 250,000 MWH $ 0.26149 /MWh

Block 2 Next 1,250,000 MWH $ 0.23772 /MWh

Block 3 Over 1,500,000 MWH $ 0.21395 /MWh

Q. PLEASE EXPLAIN HOW THE RATES FOR EACH BLOCK ARE1

CALCULATED.2

A. The rate components in all cases reflect an approximate 10% differential from the3

average rate.4

Q. PLEASE DESCRIBE THE SCHEDULE 3 RATE CALCULATION.5

A. RCL-7, Schedule 3 at lines 30 through 33 and Table 7 below list the billing rate6

calculation. Exports are assessed a unitized charge per MWh based on the7

Schedule 3 Revenue Requirement using the CELT Reports real-time load8

obligation forecast for 2014. The export rate is then applied to the total MWh of9


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Exports forecasted for the test year to determine the portion of the Schedule 31

Revenue Requirement assessed to exports. The remaining revenue requirement2

for Schedule 3 (i.e., net of that allocated to exports) is then divided by the total3

Real-Time NCP Load Obligation forecast to yield the unitized rate per kW-month.4

TABLE 7

Description TY 2014

Amount %

Revenue Requirement ($) $ 51,357,285 100.0%

Real-Time NCP Load Obligation $ 49,292,927 96.0%

Export Rate $ 2,064,358 4.0%

Billing Units

Real-Time NCP Load Obligation 277,089,079 /kW-Mo.

Export Rate 5,579,347 /MWh

Rates

Real-Time NCP Load Obligation $ 0.17790 /kW-Mo.

Rate on Exports $ 0.37 /MWh

5

RATE SUMMARY6

Q. WOULD YOU PLEASE SUMMARIZE THE RATES FOR 2014 THAT7

YOU ARE SPONSORING?8

A. Yes. These rates are summarized in Table 8.9


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Tariff Schedule Jan. 1, 2014

(a) (b)

Schedule 1

Network Load (per kW-hour) $0.00021

Schedule 2

TU Bids (Virtual Inc/Dec)

Submitted $0.00500

Cleared $0.06000

FTR Bids

Submitted $1.23712

Cleared $1.76776

TU's

Block 1 - 1st 12,500 $0.73167

Block 2 - Next 27,000 $0.66515

Block 3 - Over 39,500 $0.59864

Volumetric

Block 1 - 1st 250,000 $0.26149

Block 2 - Next 1,250,000 $0.23772

Block 3 - Over 1,500,000 $0.21395

Schedule 3 R-T NCP Load Obligation $0.17790

Export Rate $0.37000

(1) From Exh 3, RCL-7, Sch 3.

Table 8

2014 Rate Components (1)

1

Q. HAVE YOU TAKEN INTO ACCOUNT ANY REVENUE SHORTFALL2

ATTRIBUTABLE TO TUs USED IN SCHEDULE 2?3

A. Yes. In the event of a revenue shortfall attributable to TUs, the shortfall4

allocation has two components. This first component allocates the first 50% of5

the shortfall to Schedule 2 VMs rather than the usual 15/85 allocation of Schedule6


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($51,357,285/$16,035,649) = $2,149.01) and breaking that down to an hourly1

rate, which for 2014 is $2.94.2

Q. DID YOU DEVELOP THE APPROPRIATE RAS FEES FOR THOSE3

CUSTOMERS WHO TAKE SERVICE FOR PERIODS OF LESS THAN4

ONE MONTH?5

A. Yes. These charges are shown below in Table 9.6

Table 9RAS Fees

LineNo. Item Current

ProposedJan. 1, 2014

(a) (b) (c)

1 Monthly Calculation $ 2,100.34 $ 2,149.01

2 Hourly Fee $ 2.88 $ 2.94

7

Q. UNDER THE RATES PROPOSED IN THIS FILING, WHAT HAPPENS8

TO THE REVENUE DERIVED FROM THESE RAS FEES?9

A. Any revenue derived from the RAS Fees will be credited back on a monthly basis10

to all Market Participants who take service under Schedule 3 in proportion to the11

total charges incurred by the Market Participants for that month.12


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Exhibit 3RCL - 2

Schedule 2Page 2 of 2ISO New England Inc.

2012 True-Up Amount

Line No. ScheduleTotal 1 2 3

1 2012 Total Operating Expense 147,878,597$ 35,635,105$ 66,262,624$ 45,980,868$2 2012 Total Collections 145,960,842$ 34,829,382$ 64,391,427$ 46,740,033$

34 2012 Total (Over) / Under Collection 1,917,754$ 805,723$ 1,871,196$ (759,165)$


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Exhibit 3 (RCL-3)

Exhibits For Robert C. Ludlow

ISO NEW ENGLAND INC.

FERC DOCKET NO. ER14-___-000

COST ALLOCATIONS

TEST YEAR 2014


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Exhibi t 3 (RCL-3)

Schedule 1.0

(1) From Exhibit 3 (RCL-3), Schedule 3.0.

Line Department

No. Description Total Schedule 1 Schedule 2 Schedule 3(a) (b) (c) (d) (e)

1 Admin is tration-CEO 7,523,381$ 1,621,140$ 3,893,432$ 2,008,809$23 Finance 49,988,690 9,296,347 21,684,587 19,007,75545 Building Services 4,047,595 872,177 2,094,675 1,080,74367 Enterprise Risk Management 1,767,083 497,661 750,317 519,10589 Human Resources 4,633,640 998,458 2,397,960 1,237,223

1011 Legal Department 9,504,313 2,057,735 4,529,436 2,917,14312

13 Internal Audit 1,772,997 290,869 1,121,702 360,4261415 ISO Operation s16 COO-Adm 3,065,009 410,477 1,240,376 1,414,15617 System Operations - Administration 410,156 141,668 190,394 78,09418 Operations 10,251,738 3,022,786 5,488,442 1,740,51019 Reliability and Operations Services 817,341 305,951 166,862 344,52920 Reliability and Operations Compliance 1,254,149 543,128 387,077 323,94421 Operations Support Services 6,078,427 3,098,409 1,325,351 1,654,66722 System Operations Support 1,334,221 2,590 269,069 1,062,56223 Market Operations - Adm 893,101 12,987 612,517 267,59824 Market Monitoring 3,073,422 - 2,049,678 1,023,74425 Market Operations 2,822,812 17,710 2,554,282 250,82026 Market Anaylsis & Settlements 2,502,217 304,318 1,179,447 1,018,45227 Market Operations Support Services 1,211,434 101,379 901,182 208,873

28 Market Services 2,975,840 311,705 2,366,165 297,97029 Market Training and Reliability Contracts 622,836 - 311,418 311,41830 System Planning 1,270,617 813,957 267,901 188,76031 Resource Adequacy 4,055,989 256,698 981,952 2,817,34032 Transmission Planning 6,586,082 5,281,505 - 1,304,57633 Program Management 1,968,508 508,498 827,561 632,45034 Business Architecture and Technology 2,169,813 467,552 1,122,902 579,35935 Market Development Administration 3,657,801 597,102 1,965,888 1,094,81136 Market Design 466,791 100,113 241,294 125,38437 Demand Resource Strategy 508,330 109,535 263,067 135,72938 IT Management 4,445,068 1,032,915 2,229,222 1,182,93239 IT System/Network & Desktop 9,318,934 1,580,744 5,018,768 2,719,42240 IT Enterprise Applications Support 7,864,174 928,906 5,073,568 1,861,70141 IT Enterprise Applications Development 1,442,194 412 1,153,060 288,72342 IT Energy Management Systems 4,808,101 1,714,640 2,300,629 792,832

43 IT Cyber Security 2,046,011 440,875 1,058,833 546,30344 IT Power System Modeling Management 2,165,379 714,403 733,385 717,59145 Total ISO Operations 90,086,498 22,820,963 42,280,288 24,985,2474647 Total ISO Revenue Requirement 169,324,196$ 38,455,349$ 78,752,397$ 52,116,450$

48 True-up from 2012 1,917,754 805,723 1,871,196 (759,165)49 Total True-up 1,917,754$ 805,723$ 1,871,196$ (759,165)$5051 ISO Net Revenue Requirement 171,241,950$ 39,261,072$ 80,623,593$ 51,357,285$

Self-Funding Tariff

ISO NEW ENGLAND INC.FERC DOCKET NO. ER14-___-000

TOTAL COST ALLOCATION TO SCHEDULES BY DEPARTMENTTEST YEAR 2014


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Exhibit 3 (RCL-3)

Schedule 2.0

Page 1 of 1

Line Department

No. Description Total Schedule 1 Schedule 2 Schedule 3(a) (b) (c) (d) (e)

1 Administration-CEO 2,976,197$ 641,312$ 1,540,215$ 794,671$23 Finance 10,561,175 2,279,867 5,464,331 2,816,97645 Building Services 472,472 101,808 244,509 126,15467 Enterprise Risk Management 1,600,955 454,084 676,559 470,31389 Human Resources 2,260,870 487,173 1,170,025 603,6721011 Legal Department 6,000,628 1,288,064 2,684,945 2,027,61912

13 Internal Audit 1,109,537 223,004 610,202 276,3311415 ISO Operations16 COO-Adm 1,915,371 390,419 716,488 808,46317 System Operations - Administration 208,448 71,998 96,762 39,68918 Operations 9,969,888 2,933,127 5,346,079 1,690,68319 Reliability and Operations Services 749,809 299,957 164,776 285,07720 Reliability and Operations Compliance 1,230,549 531,348 386,997 312,20421 Operations Support Services 5,991,163 3,044,771 1,305,123 1,641,26922 System Operations Support 1,326,221 - 265,244 1,060,97723 Market Operations - Adm 851,101 12,987 583,117 254,99824 Market Monitoring 2,683,046 - 1,782,295 900,75125 Market Operations 2,351,909 17,710 2,084,039 250,15926 Market Anaylsis & Settlements 2,481,551 301,262 1,169,380 1,010,90927 Market Operations Support Services 1,200,189 101,379 889,954 208,85628 Market Services 2,396,312 303,385 1,874,564 218,36329 Market Training and Reliability Contracts 621,196 - 310,598 310,59830 System Planning 1,136,210 734,353 236,287 165,57031 Resource Adequacy 3,499,916 248,430 973,582 2,277,90332 Transmission Planning 4,954,766 4,417,625 - 537,14033 Program Management 1,717,595 482,704 704,357 530,53534 Business Architecture and Technology 1,916,686 413,008 991,906 511,77235 Market Development Administration 3,059,273 454,244 1,598,848 1,006,18136 Market Design 458,629 98,825 237,345 122,45837 Demand Resource Strategy 365,044 78,660 188,915 97,47038 IT Management 3,775,008 888,530 1,882,458 1,004,02039 IT System/Network & Desktop 4,670,588 778,358 2,398,547 1,493,68240 IT Enterprise Applications Support 4,054,639 591,078 2,468,823 994,73841 IT Enterprise Applications Development 1,436,306 - 1,149,045 287,26142 IT Energy Management Systems 2,813,008 948,131 1,412,802 452,07543 IT Cyber Security 1,197,735 258,088 619,841 319,806

44 IT Power System Modeling Management 1,698,910 536,973 552,602 609,33545 Total ISO Operations 70,731,067 18,937,351 32,390,774 19,402,9424647 Total ISO Direct Labor 95,712,902$ 24,412,662$ 44,781,561$ 26,518,678$

Self-Funding Tariff


TOTAL DIRECT LABOR ALLOCATION TO SCHEDULES BY DEPARTMENT

TEST YEAR 2014



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Exhibit 3 (RCL-3)

Schedule 3.0

Page 2 of 7

Line Allocation

No. No. Description Factor (1) Total (2) Schedule 1 Schedule 2 Schedule 3

(a) (b) (c) (d) (e) (f) (g)

Activity Code Self-Funding Tariff


TOTAL COST ALLOCATIONS TO SCHEDULES BY COST CATEGORY

TEST YEAR 2014

1 301 Human Resources2 12661 Employee Affairs (Recreation Committee) Total Dir Labor 11,841 2,552 6,128 3,162

3 12701 Recruiting/Interviewing Total Dir Labor 519,475 111,937 268,834 138,704

4 12801 Employee Relations Total Dir Labor 14,376 3,098 7,440 3,839

5 12901 Benefit Administration Total Dir Labor 1,164,349 250,894 602,563 310,891

6 12951 Compensation Total Dir Labor 299,765 64,593 155,132 80,040

7 12961 HR - General Total Dir Labor 1,064,981 229,482 551,139 284,359

8 12962 HR - Training Total Dir Labor 1,558,853 335,902 806,724 416,2279 Total 4,633,640 998,458 2,397,960 1,237,22310

11 306 Legal Department12 8301 GC - Federal Regulatory Total Dir Labor 76,344 16,451 39,509 20,384

13 12423 GC - Financial Assurance Policy (FAP) Total Dir Labor 167,488 36,090 86,677 44,721

14 12425 GC - Price Response Demand Total Dir Labor 60,009 12,931 31,055 16,02315 12502 Board of Directors Total Dir Labor 177,733 38,298 91,979 47,456

16 12504 ISO Tariff Litigation Total Dir Labor 111,885 24,109 57,902 29,874

17 12505 Administration of OATT Alloc-Fixed 582,599 582,599 - -

18 12508 Energy Markets/Compliants/Rule Changes Alloc-Fixed 47,771 - 47,771 -

19 12509 Market Monitoring and Sanctions Alloc-Fixed 68,244 - 34,122 34,122

20 12512 GC - BSIA - General Corporate Total Dir Labor 119,994 25,856 62,098 32,03921 12513 Miscellaneous Labor Matters Total Dir Labor 155,989 33,613 80,726 41,651

22 12514 NEPOOL Participants Committee Total Dir Labor 95,844 20,652 49,600 25,591

23 12517 Administrative and Clerical Support Total Dir Labor 481,455 103,744 249,158 128,553

24 12520 Market Monitoring Rules/Regulations Alloc-Fixed 341,218 - 136,487 204,731

25 12521 Billing Disputes Total Dir Labor 42,820 9,227 22,160 11,433

26 12523 NEPOOL Information Policy Total Dir Labor 54,595 11,764 28,253 14,577

27 12542 Transmission Upgrades CT Alloc-Fixed 62,400 - 43,680 18,720

28 12543 Independent Market Advisor Alloc-Fixed 865,000 - 605,500 259,50029 12544 FERC Proceedings Total Dir Labor 219,731 47,348 113,713 58,670

30 12547 GC - Creation of New England RTO Total Dir Labor 35,996 7,756 18,628 9,611

31 12552 GC - S&G - General Corporate Total Dir Labor 278,961 60,110 144,365 74,485

32 12555 GC - Transmission Upgrades - VT Total Dir Labor 6,589 1,420 3,410 1,759

33 12556 GC - Patents Total Dir Labor 6,589 1,420 3,410 1,75934 12559 General Corporate Total Dir Labor 820,510 176,804 424,623 219,083

35 12562 Transmission Upgrades VT Alloc-Fixed 13,202 - 9,242 3,961

36 12563 Regulatory Matters Total Dir Labor 123,605 26,634 63,967 33,004

37 12565 GC - Conn Regulatory Matters - WBAM Total Dir Labor 13,202 2,845 6,832 3,525

38 12569 NOPR / Rulemaking Comments Total Dir Labor 12,006 2,587 6,213 3,206

39 12570 GC - BSAI - Operations Total Dir Labor 31,189 6,721 16,140 8,32840 12571 ISO Reporting Total Dir Labor 12,006 2,587 6,213 3,206

41 12572 GC - BSAI - 205 General Proceedings Total Dir Labor 12,006 2,587 6,213 3,206

42 12573 206 General Proceedings Total Dir Labor 32,994 7,110 17,075 8,810

43 12574 Market Rule 1 Proceedings Total Dir Labor 96,004 20,687 49,683 25,634

44 12575 Transmission Cost Allocation Alloc-Fixed 105,056 - 73,539 31,517

45 12587 Capacity Market Development Alloc-Fixed 519,701 - - 519,70146 12588 Web Content Management Total Dir Labor 631,513 136,079 326,815 168,620

47 12592 GC - State Proceedings Alloc-Fixed 12,006 - 6,003 6,003

48 12594 Maine Transmission Siting Alloc-Fixed 31,189 - 21,832 9,357

49 12595 NEEWS Transmission Siting Alloc-Fixed 40,946 - 28,662 12,28450 12598 GC - ERO Alloc-Fixed 35,996 14,398 14,398 7,199

51 12663 Public Information Total Dir Labor 1,247,867 268,891 645,785 333,19252 12669 Government Affairs Total Dir Labor 1,654,060 356,417 855,994 441,649

53 Total 9,504,313 2,057,735 4,529,436 2,917,14354

55 305 Internal Audit56 15001 Audit - Indirect Mgmnt Duties Total Dir Labor 402,990 86,836 208,552 107,602

57 15002 Audit- Personnel Management Total Dir Labor 30,172 6,501 15,614 8,056

58 15003 Audit- Budget & Forecasting Total Dir Labor 7,543 1,625 3,904 2,014

59 15004 Audit- Audit Follow-up Activities Total Dir Labor 15,086 3,251 7,807 4,02860 15005 Audit - Audit & Finance Committee Total Dir Labor 22,629 4,876 11,711 6,042

61 15006 Audit- Internal Audit Business Process Update Total Dir Labor 7,543 1,625 3,904 2,014

62 15007 Audit- Annual Audit Work Plan Total Dir Labor 22,629 4,876 11,711 6,042

63 15008 Audit-Training Total Dir Labor 69,448 14,965 35,940 18,543

64 15020 Internal Audit - Finance Total Dir Labor 64,623 13,925 33,443 17,255

65 15021 Audit- Perfomance Measurements Total Dir Labor 15,086 3,251 7,807 4,028

66 15022 Audit- Vendor Contracts Total Dir Labor 15,086 3,251 7,807 4,02867 15023 Audit- Wire Transfers Total Dir Labor 7,543 1,625 3,904 2,014

68 15031 Audit - Employee Expense Reporting Total Dir Labor 7,543 1,625 3,904 2,014

69 15040 Audit-Operations Total Dir Labor 200,396 43,181 103,707 53,50870 15066 Audit- Day Ahead Markets/Settlements Total Dir Labor 22,629 4,876 11,711 6,042

71 15085 Audit - Information Technology Total Dir Labor 90,516 19,504 46,843 24,168

72 15110 External Audit - Operations Total Dir Labor 75,430 16,254 39,036 20,14073 15133 Audit- Satellite Reviews Total Dir Labor 8,593 1,852 4,447 2,294

74 15161 External Audit- Pension Audit Total Dir Labor 57,682 12,429 29,851 15,402

75 15162 Ext Audit- Financial Audit Total Dir Labor 127,120 27,392 65,786 33,942

76 15166 Ext Audit -Pricing Module Certification Alloc-Fixed 29,510 - 29,510 -

77 15170 External Audit - Settlements Total Dir Labor 2,270 489 1,175 60678 15175 Ext Audit - Info Technology Total Dir Labor 15,890 3,424 8,223 4,243

79 15186 Ext Audit - SSAE 16 Direct Support Total Dir Labor 22,629 4,876 11,711 6,042

80 15192 IA Special Projects - Data Mining - Aud it Command Language Im Total D ir Labor 24 ,035 5,179 12,438 6,418

81 25702 External Audit - SSAE 16 Alloc-Fixed 393,622 - 393,622 -

82 28304 Sti mulus Fund Project Compl iance, Rpti ng & Audit ing Req Pre-I Total Di r Labor 14,756 3,180 7,636 3,940

83 Total 1,772,997 290,869 1,121,702 360,426


(2) Provided by ISO-NE.


54/102

Exhibit 3 (RCL-3)

Schedule 3.0

Page 3 of 7

Line Allocation


(a) (b) (c) (d) (e) (f) (g)




TEST YEAR 2014

1 701 COO-Adm2 19001 COO - NEPOOL Committee Support Total OPS Labor 34,564 9,264 16,575 8,726

3 19002 COO - Regional Committee Support Total OPS Labor 27,485 7,366 13,180 6,939

4 19003 COO - National Committee Support Total OPS Labor 76,685 20,553 36,773 19,359

5 19005 COO - Indirect Supervision/Clerical Support Total OPS Labor 1,392,812 373,295 667,902 351,616

6 19009 COO - Renewable Resource Integration Alloc-Fixed 108,235 - - 108,235

7 19012 Changes to the Forward Capacity Market Alloc-Fixed 792,795 - - 792,795

8 19013 Changes Relevant to Fuel Security Alloc-Fixed 632,433 - 505,947 126,4879 Total 3,065,009 410,477 1,240,376 1,414,156

10

11

12 105 System Operations - Administration13 14404 System Ops Mgt & Adm - NEPOOL Committee Support SOA Labor 16,118 5,567 7,482 3,069

14 14405 System Ops Mgt & Adm - Indirect Supervision/Clerical Support SOA Labor 383,293 132,389 177,925 72,979

15 14407 System Ops Mgt & Adm - Regional Committee Support SOA Labor 10,745 3,711 4,988 2,046

16 Total 410,156 141,668 190,394 78,09417

18 101 Operations

19 14001 Ops - Generation Dispatch Alloc-Fixed 2,563,285 - 2,153,159 410,126

20 14002 Ops - Transmission Operations Alloc-Fixed 1,787,971 1,430,377 89,399 268,19621 14304 Ops - Advanced Scheduling and Forecasting Alloc-Fixed 1,673,261 83,663 1,321,876 267,722

22 14402 Ops - Operations Training Alloc-Fixed 1,783,991 713,596 713,596 356,798

23 14413 Ops - Operations Support Training & Development Alloc-Fixed 521,137 208,455 208,455 104,227

24 14561 Ops - NEPOOL Committee Support OPS Labor 4,240 1,185 2,347 707

25 14562 Ops - Regional Committee Support OPS Labor 16,960 4,741 9,390 2,829

26 14563 Ops - National Committee Support OPS Labor 38,160 10,668 21,127 6,365

27 14564 Ops - Indirect Supervision/Clerical Support OPS Labor 1,421,243 397,332 786,853 237,059

28 14565 Ops - Employee Development OPS Labor 3,620 1,012 2,004 60429 14570 Ops - Market Analysis Alloc-Fixed 8,480 - 8,480 -

30 14702 TPC - Procedure Documentation Alloc-Fixed 429,390 171,756 171,756 85,878

31 Total 10,251,738 3,022,786 5,488,442 1,740,51032

33 702 Reliability and Operations Services34 14703 TPC - NEPOOL Committee Support OS Labor 366,881 203,791 70,927 92,163

35 14706 TPC - Indirect Supervision/Clerical Support OS Labor 17,189 9,548 3,323 4,318

36 14711 ISO TMS Tariff-Section 2 - (OATT) and Agreements Support Alloc-Fixed 278,114 92,612 92,612 92,890

37 14715 EIPC - Non DOE Funded/Unallowable Alloc-Fixed 155,158 - - 155,158

38 Total 817,341 305,951 166,862 344,529

3940 703 Reliability and Operations Compliance41 14801 ROC - Compliance Monitoring Alloc-Fixed 803,383 321,353 321,353 160,677

42 14803 ROC - Regional Committee Support OS Labor 26,824 13,412 - 13,412

43 14804 ROC - National Committee Support OS Labor 229,182 114,591 - 114,591

44 14806 ROC - Employee Development Alloc-Fixed 18,549 10,303 3,586 4,660

45 14807 ROC - Compliance Audit OS Labor 18,549 9,274 - 9,27446 14808 ROC - Change Management Alloc-Fixed 9,274 4,173 927 4,173

47 14809 ROC - Tariff Compliance Alloc-Fixed 102,017 30,605 61,210 10,202

48 14810 ROC - NERC Self Certifications Alloc-Fixed 46,371 39,416 - 6,956

49 Total 1,254,149 543,128 387,077 323,944

50

51 103 Operations Support Services52 14451 TSO - NEPOOL Committee Support TSO Labor 17,823 5,770 8,521 3,532

53 14452 TSO - Regional Committee Support TSO Labor 6,400 2,072 3,060 1,268

54 14453 TSO - National Committee Support TSO Labor 10,870 3,519 5,197 2,154

55 14454 TSO - Indirect Supervision/Clerical Support TSO Labor 710,650 230,068 339,751 140,831

56 14455 TSO - Employee Development TSO Labor 497,133 160,943 237,672 98,518

57 14462 OSS - General Systems Operations Support TSO Labor 797,715 258,255 381,376 158,08558 14469 OSS C10/C30 Audits Alloc-Fixed 122,683 - 98,146 24,537

59 14470 OSS Resource Performance Monitoring Alloc-Fixed 122,683 - 98,146 24,537

60 14471 OSS New Generation Coordination & Registration Alloc-Fixed 1,600 - 1,120 480

61 18361 OSS - Transmission Studies, Operations, OASIS Support Alloc-Fixed 2,065,211 1,652,169 103,261 309,782

62 18381 OSS - Transmission Outage Appl - Short Term Alloc-Fixed 982,016 785,613 49,101 147,302

63 18382 OSS - Trans Out Ap Lg Term Alloc-Fixed 743,642 - - 743,64264 Total 6,078,427 3,098,409 1,325,351 1,654,6676566 System Operations Support67 14750 SOS - NEPOOL Committee Support Alloc-Fixed 1,600 518 765 31768 14752 SOS - National Committee Support Alloc-Fixed 6,400 2,072 3,060 1,268

69 14753 SOS - Indirect Supervision/Clerical Support Alloc-Fixed - - - -70 14755 Winter 2013/14 Reliability Project Alloc-Fixed 1,326,221 - 265,244 1,060,97771 1,334,221 2,590 269,069 1,062,562

72

73 415 Market Operations - Adm

74 19101 MO - NEPOOL Committee Support MOA Labor 23,942 - 16,759 7,18375 19103 MO - National Committee Support MOA Labor 17,352 - 12,146 5,206

76 19104 MO - Indirect Supervision/Clerical Support MOA Labor 751,474 - 526,032 225,442

77 19105 Employee Development MOA Labor 20,022 - 14,015 6,007

78 19112 Settlements - Customer Service MOA Labor 11,767 - 8,237 3,530

79 19120 CEII Requests Total Dir Labor 24,843 5,354 12,856 6,633

80 19121 Membership/Participant Support Alloc-Fixed 8,281 - 4,141 4,141

81 19122 DR/BLTS Issues Management Total Dir Labor 35,420 7,633 18,330 9,45782 Total 893,101 12,987 612,517 267,598




55/102

Exhibit 3 (RCL-3)

Schedule 3.0

Page 4 of 7

Line Allocation


(a) (b) (c) (d) (e) (f) (g)




TEST YEAR 2014

1 404 Market Monitoring

2 16101 Market Power Monitoring and Mitigation Alloc-Fixed 1,803,808 - 1,262,666 541,1423 16102 Regulatory Activities Alloc-Fixed 292,066 - 204,446 87,620

4 16103 Administration Supervision and Clerical Support Alloc-Fixed 257,478 - 180,234 77,243

5 16111 Employee Development MMM Labor 221,326 - 154,928 66,398

6 16115 Analysis & Internal Reports MMM Labor 353,433 - 247,403 106,030

7 16121 FCM Market Monitoring Alloc-Fixed 145,311 - - 145,311

8 Total 3,073,422 - 2,049,678 1,023,7449

10 416 Market Operations11 21901 Day Ahead Market Administration Alloc-Fixed 299,931 - 299,931 -

12 21902 Real Time Price Verification Alloc-Fixed 299,931 - 299,931 -

13 21903 FTR/ARR Administration Alloc-Fixed 35,420 17,710 17,710 -

14 21904 MA - NEPOOL Committee Support MA Labor 74,052 - 71,713 2,33815 21906 MA - National Committee Support MA Labor 8,855 - 8,575 280

16 21907 MA - Indirect Supervision/Clerical Support MA Labor 382,488 - 370,410 12,079

17 21908 Employee Development MA Labor 115,670 - 112,017 3,653

18 21909 Customer Support MA Labor 70,841 - 68,604 2,237

19 21913 MA-Data Collection/Report Writing Alloc-Fixed 177,102 - 177,102 -

20 21915 FTR/Auction Administration Alloc-Fixed 265,650 - 265,650 -21 21916 Forward Reserve Market - Administration Alloc-Fixed 17,710 - - 17,710

22 21917 Real Time Price Finalization Alloc-Fixed 106,261 - 106,261 -

23 21951 FCM Annual Reconfiguration Auction Administration Alloc-Fixed 35,420 - - 35,420

24 21953 FCM Monthly Administration Alloc-Fixed 177,102 - - 177,102

25 21956 Changes in Supply Offers (Hourly Reoffers) Alloc-Fixed 756,377 - 756,377 -

26 Total 2,822,812 17,710 2,554,282 250,820

27

28 401 Market Anaylsis & Settlements29 1701 Billing Statements - Energy Alloc-Fixed 57,114 - 57,114 -

30 1702 Billing Statements - Transmission Alloc-Fixed 42,836 42,836 - -

31 1713 Billing Statements - ISO Tariff Total Dir Labor 49,975 10,769 25,863 13,344

32 1714 MAS - Billable Tariff Re-billings Alloc-Fixed 1,428 1,428 - -

33 2036 MAS - Market Analysis - Projects Alloc-Fixed 7,139 - 7,139 -34 2037 MAS - Bill Job Aid Alloc-Fixed 2,856 428 1,713 714

35 2039 MAS - BITT and Business Tools Alloc-Fixed 7,139 1,071 4,284 1,785

36 2043 MAS - Release Checkout and Support Alloc-Fixed 14,279 2,142 8,567 3,570

37 2044 MAS - EQR Reporting Alloc-Fixed 2,856 428 1,713 714

38 2048 MAS - FCM Alloc-Fixed 214,178 - - 214,178

39 2049 MAS - Product Testing Alloc-Fixed 42,836 - 34,269 8,56740 2051 MAS - Legal Support Alloc-Fixed 1,428 - 714 714

41 2052 MAS - FERC Data Request Alloc-Fixed 49,975 - 24,987 24,987

42 2053 MAS - Tariff Change Coordination (TCC) Total Dir Labor 129,935 28,001 67,241 34,693

43 2054 MAS - Markets Development Support Alloc-Fixed 7,139 - 3,570 3,570

44 2005 Settlements - Customer Service STLM Labor 54,643 8,081 26,619 19,944

45 2007 Settlements - Admin support - NEPOOL Committees STLM Labor 28,615 4,232 13,940 10,44446 2008 Settlements - Admin support (ISO) STLM Labor 128,507 19,004 62,600 46,903

47 2009 Settlements - Indirect Supervision/Clerical Support STLM Labor 514,699 76,114 250,729 187,856

48 2010 Settlements - Employee Development STLM Labor 223,675 33,077 108,960 81,637

49 2013 Settlements - FTR Administration Alloc-Fixed 28,557 - 28,557 -50 2014 Billing Statements - NCPC Alloc-Fixed 171,343 - 85,671 85,671

51 2020 Settlements-Billing Disputes Total Dir Labor 21,418 4,615 11,084 5,71952 2021 Settlements-Analysis & Reporting Total Dir Labor 199,900 43,074 103,450 53,375

53 2022 Settlements-Demand Response Alloc-Fixed 35,696 - - 35,696

54 2024 Settlements - ASM Regulation Alloc-Fixed 14,279 - - 14,279

55 2025 Settlements - ASM Locational Forward Reserve Alloc-Fixed 99,950 - - 99,950

56 2026 Settlements-Batch Processing Total Dir Labor 35,696 7,692 18,473 9,531

57 2032 Settlements - Billing STLM Labor 42,836 6,335 20,867 15,63458 2033 Settlements - Market Analysis Alloc-Fixed 171,343 - 171,343 -

59 2034 Settlements - COPQ Alloc-Fixed 99,950 14,992 39,980 44,977

60 Total 2,502,217 304,318 1,179,447 1,018,452

61

62 Market Operations Support Services

63 3000 MOSS - Hourly Settlements Support Alloc-Fixed 200,792 - 100,396 100,396

64 3002 MOSS - Monthly Settlements Support Alloc-Fixed 200,792 100,396 - 100,39665 3003 MOSS - Market Analysis Support Alloc-Fixed 109,523 - 109,523 -

66 3004 MOSS - Generation & Load Admin Support Alloc-Fixed 200,792 - 200,792 -

67 3005 MOSS - Demand Resource Admin Support Alloc-Fixed 292,061 - 292,061 -

68 3006 MOSS - Customer Service Alloc-Fixed 41,071 - 41,071 -

69 3007 MOSS - NEPOOL Committees Support Alloc-Fixed 4,597 - 2,299 2,29970 3008 MOSS - Admin Support Alloc-Fixed 9,127 - 9,127 -71 3009 MOSS - Indirect Supervision (Principal Analysts only) Alloc-Fixed 4,563 - 4,563 -

72 3010 MOSS - Employee Development Alloc-Fixed 34,028 - 34,028 -

73 3011 MOSS - Release Checkout and Support Alloc-Fixed 36,508 - 36,508 -

74 3012 MOSS - FERC Data Request Alloc-Fixed 63,888 - 63,888 -

75 3013 MOSS - Tariff Change Coordination (TCC) Total Dir Labor 4,563 983 2,362 1,218

76 3014 MOSS - Markets Development Support Alloc-Fixed 9,127 - 4,563 4,56377 Total 1,211,434 101,379 901,182 208,873




56/102


57/102

Exhibit 3 (RCL-3)

Schedule 3.0

Page 6 of 7

Line Allocation


(a) (b) (c) (d) (e) (f) (g)




TEST YEAR 2014

1 304 Program Management2 801 Program Management - Administration Total Dir Labor 598,934 129,058 309,955 159,921

3 1661 ISO Program Management Alloc-Fixed 302,335 - 211,635 90,701

4 25002 PMO Support Alloc-Fixed 317,454 95,236 111,109 111,109

5 25739 IT BCC Support Alloc-Fixed - - - -

6 25822 System Restoration and Blackstart Resource Resource Mgmnt Alloc-Fixed 168,490 168,490 - -

7 25849 Allowable Smart Grid SIDU Alloc-Fixed 8,118 1,218 1,218 5,683

8 25850 Unallowable Smart Grid SIDU Alloc-Fixed 12,006 1,801 1,801 8,4049 25891 Wind Integration Project - O&M Alloc-Fixed 127,560 - 63,780 63,780

10 25910 Generation Control Applications (GCA) Phase II Alloc-Fixed 36,508 18,254 18,254 -

11 25911 Strategic Planning Initiatives Alloc-Fixed 37,463 - - 37,463

12 25912 Generation Auditing - Claim 10/30 Alloc-Fixed 73,015 - - 73,01513 25914 Divisional Accounting (for Market Participants) Total Dir Labor 109,523 23,600 56,679 29,244

14 25926 Hourly Market Alloc-Fixed 177,102 70,841 53,131 53,131

15 25935 Control Room Visualization Alloc-Fixed - - - -

16 Total 1,968,508 508,498 827,561 632,450

17

18 315 Business Architecture and Technology19 21201 Business Architecture and Technology Total Dir Labor 2,140,368 461,207 1,107,664 571,497

20 21203 BAT - Employee Development Total Dir Labor 29,445 6,345 15,238 7,862

21 Total 2,169,813 467,552 1,122,902 579,35922

23 408 Market Development Administration24 21001 Markets Development Total Dir Labor 2,057,320 443,312 1,064,686 549,322

25 21002 MD - Indirect Supervision/Clerical Support Total Dir Labor 56,085 12,085 29,024 14,975

26 21003 MD - Employee Development Total Dir Labor 124,819 26,896 64,595 33,328

27 21007 MD - Budget/Forecast Support Total Dir Labor 22,434 4,834 11,610 5,990

28 21009 Increased Scope of Impact Analysis Alloc-Fixed 400,000 104,000 264,000 32,00029 21102 ME - Indirect Supervision/Clerical Support Total Dir Labor - - - -30 16607 National Committee Support MD Labor 997,144 5,975 531,973 459,196

31 Total 3,657,801 597,102 1,965,888 1,094,811

32

33 407 Market Design

34 22601 MDes-Direct Supervision&Clerical Total Dir Labor 112,169 24,170 58,049 29,950

35 22602 MDes-Committee Meetings Total Dir Labor 70,160 15,118 36,309 18,73336 22606 MDes-Market Analysis/Governing Documents Total Dir Labor 280,380 60,416 145,100 74,864

37 22607 MDes - NEPOOL Markets Committee Administration Alloc-Fixed 4,081 408 1,836 1,836

38 Total 466,791 100,113 241,294 125,384

39

40 409 Demand Resource Strategy

41 22401 Demand Response Total Dir Labor 160,161 34,511 82,885 42,76442 22402 DR-Regulatory Ccmmittees and Working Groups Total Dir Labor 37,148 8,005 19,224 9,919

43 22404 RFP Linkages Total Dir Labor 311,022 67,019 160,957 83,046

44 Total 508,330 109,535 263,067 135,729

46 210 IT Management47 6517 Employee Development - Hardware/Software Total Dir Labor 742,126 159,914 384,059 198,154

48 6519 Indirect Supervision and Clerical Support Total Dir Labor 2,409,957 519,298 1,247,179 643,480

49 6552 IT - Security Total Dir Labor 595,388 128,294 308,120 158,97450 6554 IT - NESEC Projec