Summary of ISO New England Board and Committee Meetings May 1, 2015 ... · 01-05-2015 · Commission. Next, the Committee was provided with a review of summer 2014 and a report on

Summary of ISO New England Board and Committee Meetings

May 1, 2015 Participants Committee Meeting

Since the last update, the System Planning and Reliability Committee, the Markets

Committee, and the Board of Directors met on April 24 and 25 in Boston.

The System Planning and Reliability Committee discussed the Federal Energy

Regulatory Commission’s Order 1000 and how the Company will be working with

stakeholders to implement Order 1000, including the development of new procedures and

making a compliance filing by May 18 to address outstanding issues identified by the

Commission. Next, the Committee was provided with a review of summer 2014 and a

report on the operational capacity analysis for summer 2015 and the 2016 Summer

NEMA/Boston Transmission Security Assessment Study. The Committee was provided

with a summary of activities that were a major focus during the first quarter of 2015.

Those activities included: results of Forward Capacity Auction #9, preparations for

Forward Capacity Auction #10, regionally-preferred solutions for greater Boston, tariff

changes for elective transmission upgrade reforms, the New England Governors’

Initiative on energy infrastructure issues, and use of solar photovoltaic forecasts. The

Committee also previewed issues likely to be a focus during the second quarter.

The Markets Committee received reports on market monitoring, mitigation and

reliability costs. The Committee discussed electricity prices and NCPC levels, and

received an update on FERC’s rehearing of the winter program order. The Committee

reviewed the Internal Market Monitor’s draft annual markets report for the 2014 calendar

year, and received an update on the Forward Capacity Market, including development of

zonal demand curves and market mitigation rules.

The Board of Directors received a report from the CEO regarding the governors’

infrastructure initiatives and rehearing of the winter program order. The Board also

reviewed the proposed business plan for the five years beginning in 2016, and discussed a

number of strategic issues, including contingency planning for demand response, price

formation and the political environment of higher electricity prices. As part of this

discussion, the Board considered the Company’s resource needs and the pace of change.

Finally, the Board prepared for its meeting with NECPUC, which occurred the next day.

NEPOOL PARTICIPANTS COMMITTEEMAY 1, 2015 MEETING, AGENDA ITEM #3

2

On Friday, the Board met with Commissioner Moeller and, to the extent permitted by the

ex parte rules, discussed the strategic issues facing the Company. With NECPUC, the

Board discussed Order 1000, capacity zones, forecasting solar PV, the winter program,

contingency planning for demand response and transmission cost containment.


M A Y 1 , 2 0 1 5 | P R O V I D E N C E , R I

Vamsi Chadalavada E X E C U T I V E V I C E P R E S I D E N T A N D C H I E F O P E R A T I N G O F F I C E R

May 2015

NEPOOL Participants Committee Report

NEPOOL PARTICIPANTS COMMITTEE 05/01/15 MEETING, AGENDA ITEM #4

2

Table of Contents

• Highlights Page 3

• System Operations Page 11

• Market Operations Page 22

• Back-Up Detail Page 39

– Load Response Page 40 – New Generation Page 42 – Forward Capacity Market Page 49 – Reliability Costs - Net Commitment Period

Compensation (NCPC) Operating Costs Page 56 – Regional System Plan (RSP) & Interregional Planning Page 87 – Operable Capacity Analysis – Spring 2015 Page 116 – Operable Capacity Analysis – Summer 2015 Page 123 – Operable Capacity Analysis – Appendix Page 130


Highlights • Day-Ahead (DA), Real-Time (RT) Prices and Transactions

– Energy Market Value was $210M over the period, down $524M from March 2015 and down $241K from April 2014

– April natural gas prices over the period were 59% lower than March 2015 average values

– Average RT Hub Locational Marginal Prices (LMPs) over the period were 56% lower than March 2015 averages

– Average April 2015 natural gas prices and RT Hub LMPs over the period were down 35% and 38%, respectively, from April 2014 averages

• Average DA cleared physical energy in the peak hours as percent of forecasted load was 98.5% during April, down from 99.9% during March

3

Underlying natural gas data furnished by:

*DA Cleared Physical Energy is the sum of Generation and Net Imports cleared in the DA Energy Market

All data through April 22 (except RT NCPC through April 20)


http://www.theice.com/

Highlights, cont.

• Daily Net Commitment Period Compensation (NCPC)*

– April NCPC payments totaled $9.2M, down $5.6M from March and up $2.1M from April 2014

– First Contingency payments totaled $3.0M, down $6.4M from March

• $3.0M paid to internal resources, down $6.0M from March

– $776K charged to DALO, $2.2M to RT Deviations

• $75K paid to resources at external locations, down $447K from March

– $1K charged to DALO at external locations, $74K to RT Deviations

– Second Contingency payments totaled $6.2M, up $1.3M from the March total of $4.9M

– Voltage payments were $12K, down $435K from March

– Distribution payments were $0, unchanged from March

– NCPC payments over the period as percent of Energy Market value were 4.4%

4


Highlights, cont.

5

• Based on the three economic study requests received, the ISO will present scopes of work and assumptions for 2015 economic studies at the PAC meeting on May 20

• The Distributed Generation Forecast Working Group discussed the final PV forecast on April 14

• FERC Order 1000 final compliance order was received on March 19 and ISO continues working with the Transmission Committee on final tariff changes to be filed by May 18

• All major components of the Maine Power Reliability Program have been constructed and placed in service

• Proposed new capacity zones for Forward Capacity Auction #10 were filed with the FERC on April 6


Forward Capacity Market (FCM) Highlights

6

CCP – Capacity Commitment Period

• CCP #5 (2014-2015) – Approximately 60 MW of resources are non-commercial at this time

and remain on monthly CPS monitoring where progress is being made to become commercial

• CCP #6 (2015-2016) – Discussions with non-commercial resources at risk of being late have

begun – Entering the CCP, the Transmission Security Analysis margin for

NEMA/Boston will be about 211 MW short

• CCP #7 (2016-2017) – Next bilateral transaction window is May 1-7 – Second reconfiguration auction will be held August 3-5


FCM Highlights, cont.

7

• CCP #8 (2017-2018) – First bilateral transaction window is April 1-8 – First reconfiguration auction will be held June 1-3

• CCP #9 (2018-2019) – First bilateral transaction window is April 2016

• CCP #10 (2019-2020) – Potential new capacity zones filed with FERC on April 6 – Upcoming deadlines

• De-list bids are due by the Existing Resource Qualification Deadline of June 1 • Non-Price Retirement window opens on June 1 • New resource qualification packages are due June 16


Highlights, cont.

• The lowest 50/50 and 90/10 Spring Operable Capacity Margin is projected for week beginning May 23, 2015.

8


Summer 2015 Update • Operable Capacity analysis for the 50/50 load forecast

indicates adequate supply

• Operable Capacity analysis for the 90/10 load forecast indicates implementation of Operating Procedure No. 4 – Action in a Capacity Deficiency (OP4) would be required to meet load & reserve requirements

• Operational Readiness ‒ Normal and Emergency Operating Procedures are in place for the

summer period

• Natural Gas – For the summer 2015 capacity period, ISO-NE expects some natural

gas pipeline maintenance to occur for select areas, but does not forecast deliverability issues that would impact availability of natural gas-fired installed capacity

– The first significant Algonquin pipeline expansion project outage will begin in September

9


Upcoming NPCC/NERC Audit

• Two major audits upcoming in June

– NPCC CIP Standards Audit will be conducted from June 1-5

– NPCC Operations and Planning Audit will be conducted from June 8-12, 2015

• Audit Scope: 39 NERC Standards and 348 total requirements

• Audit Period: March 16, 2012 through May 11, 2015

10


SYSTEM OPERATIONS


System Operations Weather Patterns

Boston Temperature – Below normal (-2.0) Max: 69, Min: 30 Precipitation 2.11” - Below Normal Normal - 3.27” Total Snowfall – 0.98”

Hartford Temperature – Below normal ( -1.8) Max: 81 , Min: 26

Precipitation 3.41” - Normal Normal – 3.47”

Total Snowfall – 1.26”

12

Peak Load: 16,380 MW April 08, 2015 20:00

MLCC2: None

OP-4 : None

NPCC Simultaneous Activation of Reserve Events:

04/01/15 IESO 900 MW

04/03/15 NYSIO 750 MW

04/06/15 PJM 850 MW

04/07/15 PJM 1800 MW

04/14/15 IESO 950 MW


System Operations

13

Minimum Generation Warnings & Events: None


14

0.0

2.0

4.0

6.0

8.0

10.0

J F M A M J J A S O N D Cum. Avg

% E

rro

r

All Hours Monthly Average, Daily Maximum and Minimum,

Based on forecast published by 1000 on day before Operating Day

Mo. Avg Day Max Day Min Summer Goal Rest of Year Goal

2015 System Operations – Load Forecast Accuracy Dashboard

Indicator

J F M A M J J A S O N D Avg

Mo Avg 1.70 1.31 1.37 1.59 1.50

Day Max 5.66 3.47 3.35 3.93 4.12

Day Min 0.65 0.57 0.44 0.74 0.60

Summer Goal 2.6 2.6 2.6

Rest of Year Goal 1.50 1.50 1.50 1.50 1.50 1.50 1.50 1.50 1.50

Rest of year Actual 1.70 1.31 1.37 1.59 1.50

Summer Actual

Rest of Year Goal < 1.5%

Summer Goal < 2.6%

Sponsor - John Norden Contact – William Callan

Summer Goal - 2.6%, Rest of Year Goal - 1.5%

Summer consists of June, July & August


15

0.0

2.0

4.0

6.0

8.0

10.0

12.0

J F M A M J J A S O N D Cum. Avg

% E

rro

r

Peak Hours Monthly Average, Daily Maximum and Minimum

Based on forecast published by 1000 on day before Operating Day

Mo. Avg Day Max Day Min Summer Goal Rest of Year Goal

2015 System Operations - Load Forecast Accuracy, cont. Dashboard

Indicator

Rest of Year Goal < 1.5%

Summer Goal < 2.6%

Summer Goal - 2.6%, Rest of Year Goal - 1.5%

Summer consists of June, July & August

J F M A M J J A S O N D Avg

Mo Avg 1.75 1.28 1.36 1.35 1.44

Day Max 6.13 3.41 4.31 3.40 4.34

Day Min 0.00 0.08 0.00 0.03 0.03

Summer Goal 2.6 2.6 2.6

Rest of Year Goal 1.50 1.50 1.50 1.50 1.50 1.50 1.50 1.50 1.50

Rest of year Actual 1.75 1.28 1.36 1.35 1.44

Summer Actual


16

20

30

40

50

60

70

J F M A M J J A S O N D Cum.

Avg

% E

rro

r

Percent of Hours Actual Load Above vs. Below Forecast

Based on LF published by 1000, day before Operating Day

Above Below

2015 System Operations - Load Forecast Accuracy

Target = 50%

Plus/Minus 5%

Percent of hours that the actual load was above versus below the forecast Sponsor –John Norden Contact –William Callan


17

2015 System Operations - Load Forecast Accuracy

Sponsor –John Norden Contact – William Callan


GR:wnnel GR:nel

Ann Tot (TWh): 128.2 127.8 127.1 32.4

Weather Normalized NEL

2012 2013 2014 2015G

Wh

8,000

9,000

10,000

11,000

12,000

13,000

14,000

JAN FEB MAR APR MAY JUN JUL AUG SEP OCT NOV DEC

Ann Tot (TWh): 128.1 129.4 127.2 40.4

Net Energy for Load (NEL)

2012 2013 2014 2015

GW

h

7,000

8,000

9,000

10,000

11,000

12,000

13,000

14,000


Monthly Recorded Net Energy for Load (NEL) and Weather Normalized NEL

18

NEPOOL NEL is the total net energy required to serve load and is analogous to ‘RT system load’. NEL is calculated as: Generation – pumping load + net interchange where imports are positively signed. Current month’s data may be preliminary. Weather normalized NEL may be reported on a one-month lag.

6,800 TWh through April 22


GR:SeasonalPeak GR:PeakEnergy

Weather Normalized Seasonal Peaks

Winter beginning in year displayed

Summer WinterM

W

20,000

21,000

22,000

23,000

24,000

25,000

26,000

27,000

28,000

29,000

30,000

20032004 2005 20062007 2008 2009 20102011 2012 20132014 2015

System Peak Load

2012 2013 2014 2015

MW

15,000

16,000

17,000

18,000

19,000

20,000

21,000

22,000

23,000

24,000

25,000

26,000

27,000

28,000


Monthly Peak Loads and Weather Normalized Seasonal Peak History

19

F – designates forecasted values, which are updated in April/May of the following year; represents “gross forecast”

F


10 20 30 40 50 60 70 80 90 100 110 120 130 140 150 1601680

5

10

15

20

25

30

35

40

45

50

Horizon [Hours Ahead]

Mean A

bsolu

te E

rror

[%]

Rolling 30-day MAE for ISO Wind Power Forecast, as of April 24, 2015

Individual Wind Plants

Fleet

Wind Power Forecast Error Statistics: MAE

Ideally, MAE and Bias would be both equal to zero. As is typical, MAE increases with the forecast horizon. MAE and Bias for the fleet of wind power resources are less due to offsetting errors. Across all time frames, the ISO-NE/GH forecast is very good compared to industry standards, and MAE continues to be well within the yearly performance targets specified in the forecast RFP.

Dashboard Indicator

Yearly Fleet Performance targets

20


10 20 30 40 50 60 70 80 90 100 110 120 130 140 150 160168-30

-20

-10

0

10

20

30

Horizon [Hours Ahead]

Bia

s E

rror

[%]

Rolling 30-day Bias for ISO Wind Power Forecast, as of April 24, 2015

Individual Wind Plants

Fleet

Wind Power Forecast Error Statistics: Bias Dashboard Indicator

Ideally, MAE and Bias would be both equal to zero. Positive bias means less windpower was actually available compared to forecast. Negative bias means more windpower was actually available compared to forecast. Across all time frames, the ISO-NE/GH forecast is very good compared to industry standards, and monthly values for April are near yearly performance targets specified in the forecast RFP.

Yearly Fleet Performance targets

21


MARKET OPERATIONS


GR:Hubwgas

Ele

ctri

city

Pri

ces

($/M

Wh

)

$0.00

$50.00

$100.00

$150.00

$200.00

$250.0004/

01/1

5

04/03

/15

04/05

/15

04/07

/15

04/09

/15

04/11

/15

04/13

/15

04/15

/15

04/17

/15

04/19

/15

04/21

/15

04/23

/15

Fue

l Pri

ce (

$/M

MB

tu)

$0.00

$7.00

$14.00

$21.00

$28.00

$35.00

Gas price is average of Massachusetts delivery pointsAverage percentage difference over this period ABS(DA-RT)/RT Average LMP: 21%

Average price difference over this period ABS(DA-RT): $5.23Average price difference over this period (DA-RT): $2.92

RT LMP DA LMP Natural Gas

Daily DA and RT ISO-NE Hub Prices and Input Fuel Prices: April 1-22, 2015

23




GR:DA_Bar

LMP Congestion Marginal Losses

$/M

Wh

$-20

$0

$20

$40

$60

$80

$100

$120

$140

Hub ME NH VT CT RI SEMA WCMA NEMA

( 2.8%) 0.5% ( 4.7%) ( 5.5%) 1.8% 3.3% ( 0.6%) 3.2%

DA LMPs Average by Zone & Hub, April 2015

24

ME - Maine NH – New Hampshire VT – Vermont CT – Connecticut

RI – Rhode Island SEMA – Southeastern Massachusetts WCMA – Western/Central Massachusetts NEMA – Northeastern Massachusetts


GR:RT_Bar

LMP Congestion Marginal Losses

$/M

Wh

$-20

$0

$20

$40

$60

$80

$100

$120

$140


( 4.6%) ( 2.1%) ( 3.2%) ( 3.4%) ( 0.3%) 0.2% ( 0.8%) 0.7%

RT LMPs Average by Zone & Hub, April 2015

25


Definitions

26

Day-Ahead Concept Definition

Day-Ahead Load Obligation (DALO) The sum of day-ahead cleared load

(including pump load), exports, and virtual purchases (excluding bulk losses)

Day-Ahead Cleared Physical Energy The sum of day-ahead cleared generation

and cleared net imports


GR:Graph36R GR:Graph36L

Fixed Dem PrSens Dem Decs

Losses Exports

Avg

Ho

url

y M

W 0

2,500

5,000

7,500

10,000

12,500

15,000

17,500

20,000

22,500

FEB2015 MAR2015 APR2015

Gen Imports

Incs

Avg

Ho

url

y M

W

0

2,500

5,000

7,500

10,000

12,500

15,000

17,500

20,000

22,500

FEB2015 MAR2015 APR2015

Components of Cleared DA Supply and Demand – Last Three Months

27

DA Fcst Load

Demand

Act Load

Supply

Gen – Generation Incs – Increment Offers DA Fcst Load – Day-Ahead Forecast Load

Fixed Dem – Fixed Demand PrSens Dem – Price Sensitive Demand Decs – Decrement Bids Act Load – Actual Load


GR:Graph37R GR:Graph37L

Load Exports

Avg

Ho

url

y M

W 0

2,500

5,000

7,500

10,000

12,500

15,000

17,500

20,000

22,500

FEB2015 MAR2015 APR2015

Gen Imports

Avg

Ho

url

y M

W

0

2,500

5,000

7,500

10,000

12,500

15,000

17,500

20,000

22,500

FEB2015 MAR2015 APR2015

Components of RT Supply and Demand – Last Three Months

28

Supply

DA Fcst Load

Demand


DAM Volumes vs. RT Actual Load (Peak Hour): Monthly and Daily

29

Note: Percentages were derived for the peak hour of each day (shown on right), then averaged over the month (shown on left). Values at hour of forecasted peak load.

60%

70%

80%

90%

100%

110%

120%

130%

140%

Ap

r-1

4

Ma

y-1

4

Jun

-14

Jul-

14

Au

g-1

4

Se

p-1

4

Oc

t-1

4

No

v-1

4

De

c-1

4

Jan

-15

Fe

b-1

5

Ma

r-1

5

Ap

r-1

5

% o

f R

T A

ctu

al L

oa

d

DA Bid Fixed DA Bid Price

DALO DA Phys Clrd Energy

100%

60%

70%

80%

90%

100%

110%

120%

130%

140%

1-A

pr

2-A

pr

3-A

pr

4-A

pr

5-A

pr

6-A

pr

7-A

pr

8-A

pr

9-A

pr

10

-Ap

r

11

-Ap

r

12

-Ap

r

13

-Ap

r

14

-Ap

r

15

-Ap

r

16

-Ap

r

17

-Ap

r

18

-Ap

r

19

-Ap

r

20

-Ap

r

21

-Ap

r

22

-Ap

r

% o

f A

ctu

al R

T L

oa

d

DA Bid Fixed DA Bid PriceDALO DA Phys Clrd Energy100%


GR:Graph26 GR:Graph27

DA

% o

f R

T

96.8%

97.0%

97.2%

97.4%

97.6%

97.8%

98.0%

98.2%

98.4%

98.6%

98.8%

99.0%

99.2%

APR2014

MAY2

014

JUN

2014

JUL2

014

AUG

2014

SEP2

014

OCT2

014

NO

V2014

DEC

2014

JAN

2015

FEB20

15M

AR2015

APR2015

Monthly, Last 13 Months

DA

% o

f R

T

94%

95%

96%

97%

98%

99%

100%

101%

102%

103%

4/ 1

4/ 2

4/ 3

4/ 4

4/ 5

4/ 6

4/ 7

4/ 8

4/ 9

4/10

4/11

4/12

4/13

4/14

4/15

4/16

4/17

4/18

4/19

4/20

4/21

4/22

4/23

4/24

4/25

4/26

4/27

4/28

4/29

4/30

Daily, This Year vs. Last Year

Last_Year This_Year

DA vs. RT Load Obligation: April, This Year vs. Last Year

30

*Hourly average values


GR:dapce_dalo_pct_fxlo_fpk_dly_small GR:dapce_dalo_pct_fxlo_fpk_mly_small

Perc

enta

ge o

f Pea

k Fo

reca

st L

oad

80.0%

84.0%

88.0%

92.0%

96.0%

100%

104%

108%

112%

01APR15

02APR15

03APR15

04APR15

05APR15

06APR15

07APR15

08APR15

09APR15

10APR15

11APR15

12APR15

13APR15

14APR15

15APR15

16APR15

17APR15

18APR15

19APR15

20APR15

21APR15

22APR15

Daily: This Month

DA Cleared Physical Energy DALO100% line

Perc

enta

ge o

f Pea

k Fo

reca

st L

oad

92.0%

94.0%

96.0%

98.0%

100%

102%

104%

APR2014

MAY2014

JUN2014

JUL2

014

AUG2014

SEP2014

OCT2014

NOV2014

DEC2014

JAN2015

FEB2015

MAR2015

APR2015


DA Cleared Physical Energy DALO100% line

DA Volumes as % of Forecast (Peak Hour)

31

*Forecasted peak hour is reflected.


GR:dapce_delta_fpk_dly_bar

MW

h

-3,000

-2,500

-2,000

-1,500

-1,000

-500

0

500

1,000

1,500

01APR201

502A

PR2015

03APR201

504A

PR2015

05APR201

506A

PR2015

07APR201

508A

PR2015

09APR201

510A

PR2015

11APR201

512A

PR2015

13APR201

514A

PR2015

15APR201

516A

PR2015

17APR201

518A

PR2015

19APR201

520A

PR2015

21APR201

522A

PR2015

DA Cleared Physical Energy Difference from RT System Load at Peak Hour

32

*Negative values indicate DA Cleared Physical Energy value below its RT counterpart. Forecast peak hour reflected.

DA

Hig

her

DA

Low

er


GR:Graph32 GR:Graph33

Ne

t M

Wh

0

500

1,000

1,500

2,000

2,500

3,000

3,500

4,000

01

AP

R1

40

2A

PR

14

03

AP

R1

40

4A

PR

14

05

AP

R1

40

6A

PR

14

07

AP

R1

40

8A

PR

14

09

AP

R1

41

0A

PR

14

11

AP

R1

41

2A

PR

14

13

AP

R1

41

4A

PR

14

15

AP

R1

41

6A

PR

14

17

AP

R1

41

8A

PR

14

19

AP

R1

42

0A

PR

14

21

AP

R1

42

2A

PR

14

23

AP

R1

42

4A

PR

14

25

AP

R1

42

6A

PR

14

27

AP

R1

42

8A

PR

14

29

AP

R1

43

0A

PR

14

Hourly Average by Day, Last Year

Day-Ahead Real-Time

Ne

t M

Wh

0

500

1,000

1,500

2,000

2,500

3,000

3,500

4,000

01

AP

R1

5

02

AP

R1

5

03

AP

R1

5

04

AP

R1

5

05

AP

R1

5

06

AP

R1

5

07

AP

R1

5

08

AP

R1

5

09

AP

R1

5

10

AP

R1

5

11

AP

R1

5

12

AP

R1

5

13

AP

R1

5

14

AP

R1

5

15

AP

R1

5

16

AP

R1

5

17

AP

R1

5

18

AP

R1

5

19

AP

R1

5

20

AP

R1

5

21

AP

R1

5

22

AP

R1

5

Hourly Average by Day, This Year

Day-Ahead Real-Time

DA vs. RT Net Interchange April 2015 vs. April 2014

33

Net Interchange is the sum of daily imports minus the sum of daily exports Positive values are net imports


GR:Var_Cost_Gas_Mly

$0

$40

$80

$120

$160

$200APR

2013

MAY2

013

JUN

2013

JUL2

013

AUG20

13SE

P201

3O

CT20

13N

OV20

13DEC

2013

JAN

2014

FEB20

14M

AR2014

APR20

14M

AY201

4JU

N20

14JU

L201

4AU

G2014

SEP2

014

OCT

2014

NO

V2014

DEC20

14JA

N20

15FE

B2015

MAR20

15APR

2015

Var Cost Gas

Variable Production Cost of Natural Gas: Monthly

34

Note: Assumes proxy heat rate of 7,800,000 Btu/MWh for natural gas units.


GR:Var_Cost_Gas_Dly

$0

$40

$80

$120

$160

$200

$240

01APR

2015

02APR

2015

03APR

2015

04APR

2015

05APR

2015

06APR

2015

07APR

2015

08APR

2015

09APR

2015

10APR

2015

11APR

2015

12APR

2015

13APR

2015

14APR

2015

15APR

2015

16APR

2015

17APR

2015

18APR

2015

19APR

2015

20APR

2015

21APR

2015

22APR

2015

Var Cost Gas

Variable Production Cost of Natural Gas: Daily

35

Note: Assumes proxy heat rate of 7,800,000 Btu/MWh for natural gas units.


GR:DA_Hrly

$/M

Wh

$-100

$-50

$0

$50

$100

$150

$200

$250

$300

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23

Hourly Day-Ahead LMPs

Hub ME NH VT CTRI SEMA NEMA WCMA

Hourly DA LMPs, April 1-22, 2015

36

Binding constraint on the Northwest VT Interface due to virtual bidding


GR:RT_Hrly

$/M

Wh

$-100

$-50

$0

$50

$100

$150

$200

$250

$300

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23

Hourly Real-Time LMPs

Hub ME NH VT CTRI SEMA NEMA WCMA

Hourly RT LMPs, April 1-22, 2015

37

Negative system pricing on April 1, 4, 14, 17, and 20; not Min Gen Emergencies


System Unit Availability

38

Data as of 4/27/15

Year Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec YTD

2015 97 89 88 82 89

2014 87 92 84 76 77 95 96 95 93 81 82 95 88

2013 89 87 85 76 81 90 90 92 88 80 81 92 86

2012 93 92 88 75 83 93 95 95 91 76 80 89 88

60

65

70

75

80

85

90

95

100

Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Annual

Syste

m W

EA

FAnnual/Monthly Weighted Equivalent Availability Factor (WEAF)

2013 2014 2015


BACK-UP DETAIL


LOAD RESPONSE


Capacity Supply Obligation (CSO) MW by Demand Resource Type for April 2015

41

* Real Time Demand Response

** Real Time Emergency Generation

NOTE: CSO values include T&D loss factor (8%) and, as applicable, a reserve margin gross-up of

either 14.3% or 16.1%, respectively, for portions of resources that selected a multi-year obligation

in the FCA 1 or FCA 2. Otherwise, reserve margin gross-ups were discontinued with FCA 3.

Load Zone RTDR* RTEG** On Peak

Seasonal

Peak Total

ME 113.6 3.8 103.1 0.0 220.5

NH 8.2 14.3 69.9 0.0 92.4

VT 27.4 3.0 94.2 0.0 124.6

CT 84.6 73.1 77.5 312.3 547.5

RI 13.5 13.8 83.6 0.0 110.9

SEMA 11.1 9.5 152.7 0.0 173.3

WCMA 26.2 19.9 140.3 34.9 221.3

NEMA 34.2 3.5 307.5 0.0 345.1

Total 318.7 140.9 1,028.8 347.2 1,835.6


NEW GENERATION


New Generation Update Based on 4/27/15 Interim Queue Update

• No new projects have applied for interconnection study since the last update

• One project withdrew from the Queue, resulting in a net decrease in new generation projects of 837 MW

• In total, 78 generation projects are currently being tracked by the ISO, totaling approximately 10,462 MW

43


Actual and Projected Annual Capacity Additions By Supply Fuel Type and Demand Resource Type

• 2015 values include the 27 MW of generation that has gone commercial in 2015 •DR reflects changes from the initial FCM Capacity Supply Obligations in 2010-11

44

-1,000

-500

0

500

1,000

1,500

2,000

2,500

3,000

3,500

4,000

2015 2016 2017 2018 2019 2020

Me

ga

wa

tts

(M

W)

Demand Response -Passive

Demand Reponse -Active

Wind/Other Renewables

Oil

Natural Gas/Oil

Natural Gas

2015 2016 2017 2018 2019 2020Total

MW

% of

Total1

Demand Response - Passive 157 -12 330 196 0 0 670 6.8

Demand Response - Active 3 -868 -37 -433 0 0 -1,335 -13.6

Wind & Other Renewables 77 620 1,309 458 1,092 698 4,254 43.3

Oil 0 0 0 0 0 0 0 0.0

Natural Gas/Oil2 0 10 567 2,726 632 0 3,935 40.1

Natural Gas 180 135 745 210 1,030 0 2,300 23.4

Totals 417 -115 2,914 3,157 2,754 698 9,824 100.01 Sum may not equal 100% due to rounding2 The projects in this category are dual fuel, w ith either gas or oil as the primary fuel


Actual and Projected Annual Generator Capacity Additions By State

45

• 2015 values include the 27 MW of generation that has gone commercial in 2015

0

500

1,000

1,500

2,000

2,500

3,000

3,500

4,000

2015 2016 2017 2018 2019 2020

Me

ga

wa

tts

(M

W)

Vermont

Rhode Island

New Hampshire

Maine

Massachusetts

Connecticut

2015 2016 2017 2018 2019 2020Total

MW

% of

Total1

Vermont 3 58 0 0 30 97 188 1.8

Rhode Island 27 51 0 0 1,661 0 1,739 16.6

New Hampshire 81 0 79 0 0 0 160 1.5

Maine 52 490 726 488 999 601 3,356 32.0

Massachusetts 10 65 1,816 1,267 1 0 3,159 30.1

Connecticut 84 101 0 1,639 63 0 1,887 18.0

Totals 257 765 2,621 3,394 2,754 698 10,489 100.01 Sum may not equal 100% due to rounding


New Generation Projection By Fuel Type

•Projects in the Natural Gas/Oil category may have either gas or oil as the primary fuel •Green denotes projects with a high probability of going into service • Yellow denotes projects with a lower probability of going into service or new applications

46

Fuel Type

No. of

Projects

Capacity

(MW)

No. of

Projects

Capacity

(MW)

No. of

Projects

Capacity

(MW)

Biomass/Wood Waste 2 70 0 0 2 70

Hydro 6 38 0 0 6 38

Landfill Gas 0 0 0 0 0 0

Natural Gas 16 2,336 0 0 16 2,336

Natural Gas/Oil 17 3,935 0 0 17 3,935

Oil 0 0 0 0 0 0

Solar 1 10 1 10 0 0

Wind 36 4,073 6 294 30 3,779

Total 78 10,462 7 304 71 10,158

Green YellowTotal


New Generation Projection By Operating Type

• Green denotes projects with a high probability of going into service • Yellow denotes projects with a lower probability of going into service or new applications

47

Operating Type

No. of

Projects

Capacity

(MW)

No. of

Projects

Capacity

(MW)

No. of

Projects

Capacity

(MW)

Baseload 3 133 0 0 3 133

Intermediate 25 4,628 0 0 25 4,628

Peaker 14 1,628 1 10 13 1,618

Wind Turbine 36 4,073 6 294 30 3,779

Total 78 10,462 7 304 71 10,158

Total Green Yellow


New Generation Projection By Operating Type and Fuel Type

48

• Projects in the Natural Gas/Oil category may have either gas or oil as the primary fuel

Fuel Type

No. of

Projects

Capacity

(MW)

No. of

Projects

Capacity

(MW)

No. of

Projects

Capacity

(MW)

No. of

Projects

Capacity

(MW)

No. of

Projects

Capacity

(MW)

Biomass/Wood Waste 2 70 2 70 0 0 0 0 0 0

Hydro 6 38 0 0 5 13 1 25 0 0

Landfill Gas 0 0 0 0 0 0 0 0 0 0

Natural Gas 16 2,336 1 63 12 2,182 3 91 0 0

Natural Gas/Oil 17 3,935 0 0 8 2,433 9 1,502 0 0

Oil 0 0 0 0 0 0 0 0 0 0

Solar 1 10 0 0 0 0 1 10 0 0

Wind 36 4,073 0 0 0 0 0 0 36 4,073

Total 78 10,462 3 133 25 4,628 14 1,628 36 4,073

Wind TurbineBaseload Intermediate PeakerTotal


FORWARD CAPACITY MARKET


Capacity Supply Obligation FCA 5

50

* Real-time Emergency Generators (RTEG) CSO not capped at 600.000 MW

** Change columns contain the changes in CSO amount resulting from the specific FCM Event as well as adjustments for Delisted MW released according to MR 1, Section 13.2.5.2, and changes that occurred (terminations, etc.) prior to the event reported in the column.

*** Grand Total reflects both CSO Grand Total and the net total of the Change Column.

Resource

Type

Resource

Type

FCA Proration Annual Bilateral for ARA 2 ARA 2 Annual Bilateral for ARA 3 ARA 3

*CSO CSO **Change ARA 2 Change CSO Change CSO Change CSO Change

MW MW MW MW MW MW MW MW MW MW MW

Demand

Active Demand 2,104.14 2,001.13 -103.02 1,385.67 -615.46 1,074.46 -311.21 899.13 -175.34 699.93 -199.20

Passive

Demand 1,485.71 1,397.59 -88.13 1,345.28 -52.30 1,348.59 3.31 1,365.95 17.35 1,399.56 33.62

Demand Total 3,589.85 3,398.71 -191.14 2,730.95 -667.76 2,423.05 -307.90 2,265.07 -157.98 2,099.49 -165.58

Generator

Non-

Intermittent 30,558.22 28,337.48 -2,220.74 27,917.69 -419.79 28,364.59 446.90 28,517.10 152.51 28,557.86 40.76

Intermittent 880.737 827.804 -52.933 778.165 -49.639 795.545 17.38 795.767 0.222 718.908 -76.859

Generator Total 31,438.96 29,165.29 -2,273.67 28,695.86 -469.43 29,160.13 464.28 29,312.86 152.73 29,276.76 -36.10

Import Total 2,011.00 1,831.37 -179.63 1,831.37 0.00 1,635.84 -195.54 1,635.84 0.00 1,382.55 -253.28

***Grand Total 37,039.81 34,395.37 -2,644.44 33,258.18 -1,137.19 33,219.02 -39.16 33,213.77 -5.25 32,758.81 -454.96

Net ICR (NICR) 33,200 33,200 0 33,200 0 32,209 -991 32,209 0 32,588 379



51

Resource

Type

Resource

Type

FCA Proration Annual Bilateral for

ARA 1 ARA 1

Annual Bilateral for ARA 2

ARA 2 Annual Bilateral for

ARA 3 ARA 3

*CSO CSO **Change CSO Change CSO Change CSO Change CSO Chan

ge CSO Change CSO Change

MW MW MW MW MW MW MW MW MW MW MW MW MW MW MW

Demand

Active

Demand 2,001.510 1,918.662 -82.848 1,368.608 -550.054 1,271.984 -96.624 1,085.347 -186.64 842.791 -242.56 789.366 -53.425 638.393 -150.973

Passive

Demand 1,643.334 1,553.054 -90.280 1,521.535 -31.519 1,521.535 0.000 1,516.504 -5.03 1,700.586 184.08 1,694.766 -5.82 1,687.458 -7.308

Demand Total 3,644.844 3,471.716 -173.128 2,890.143 -581.573 2,793.519 -96.624 2,601.851 -191.67 2,543.377 -58.47 2,484.132 -59.245 2,325.851 -158.281

Generator

Non-

Intermittent 29,866.098 27,957.613 -1,908.485 28,121.731 164.118 28,343.440 221.709 28,442.424 98.98 28,727.16 284.73 28,881.019 153.859 28,971.511 90.492

Intermittent 891.069 840.563 -50.506 827.047 -13.516 828.252 1.205 829.219 0.97 820.743 -8.48 777.924 -42.819 754.101 -23.823

Generator Total 30,757.167 28,798.176 -1,958.991 28,948.778 150.602 29,171.692 222.914 29,271.643 99.95 29,547.9 276.26 29,658.943 111.043 29,725.612 66.669

Import Total 1,924.000 1,768.111 -155.889 1,768.111 0.000 1,641.821 -126.290 1,616.821 -25.00 1,399.037 -217.78 1,337.037 -62 1,337.037 0

***Grand Total 36,326.011 34,038.003 -2,288.008 33,607.032 -430.971 33,607.032 0.000 33,490.315 -116.72 33,490.32 0.00 33,480.112 -10.208 33,388.5 -91.612

Net ICR (NICR) 33,456 33,456 0 33,456 0 33,456 0 33,114 -342 33,114 0.00 33,391 277 33,391 0






52

Resource

Type Resource Type

FCA Proration Annual Bilateral for

ARA 1 ARA 1



ARA 3 ARA 3

*CSO CSO **Change CSO Change CSO Change CSO Change CSO Change CSO Change CSO Change

MW MW MW MW MW MW MW MW MW MW MW MW MW MW MW

Demand

Active Demand 1,116.698 1,043.719 -72.979 944.27 -99.45 932.721 -11.549

Passive Demand 1,631.335 1,519.740 -111.595 1,519.311 -0.43 1,543.793 24.482

Demand Total 2,748.033 2,563.459 -184.574 2,463.581 -99.88 2,476.514 12.933

Generator

Non-

Intermittent 30,704.578 28,146.837 -2,557.741 28,127.044 -19.79 28,523.002 395.958

Intermittent 936.913 893.710 -43.203 903.244 9.53 913.083 9.839

Generator Total 31,641.491 29,040.547 -2,600.944 29,030.288 -10.26 29,436.085 405.797

Import Total 1,830.000 1,606.862 -223.138 1,606.862 0.00 1,616.401 9.539

***Grand Total 36,219.524 33,210.868 -3,008.656 33,100.731 -110.14 33,529.000 428.269

Net ICR (NICR) 32,968 32,968 0

33,529

561

33,529

0






53

Resource

Type Resource Type

FCA Annual Bilateral

for ARA 1 ARA 1



ARA 3 ARA 3

*CSO CSO Change CSO Change CSO Change CSO Change CSO Change CSO Change

MW MW MW MW MW MW MW MW MW MW MW MW MW

Demand

Active Demand 1,080.079

Passive Demand 1,960.517

Demand Total 3,040.596

Generator

Non-

Intermittent 28,547.813

Intermittent 876.925

Generator Total 29,424.738

Import Total 1,237.034

***Grand Total 33,702.368

Net ICR (NICR) 33,855






54

Resource

Type Resource Type

FCA Annual Bilateral

for ARA 1 ARA 1



ARA 3 ARA 3

*CSO CSO Change CSO Change CSO Change CSO Change CSO Change CSO Change

MW MW MW MW MW MW MW MW MW MW MW MW MW

Demand

Active Demand 647.26

Passive Demand 2,156.151

Demand Total 2,803.411

Generator

Non-

Intermittent 29,550.564

Intermittent 891.616

Generator Total 30,442.18

Import Total 1,449

***Grand Total 34,694.591

Net ICR (NICR) 34,189





Active/Passive Demand Response CSO Totals by Commitment Period

55

Commitment Period Active/Passive Existing New Grand Total

2010-11

Active 1246.399 603.675 1850.074

Passive 119.211 584.277 703.488

Grand Total 1365.61 1187.952 2553.562

2011-12

Active 1768.392 184.99 1953.382

Passive 719.98 263.25 983.23

Grand Total 2488.372 448.24 2936.612

2012-13

Active 1726.548 98.227 1824.775

Passive 861.602 211.261 1072.863

Grand Total 2588.15 309.488 2897.638

2013-14

Active 1794.195 257.341 2051.536

Passive 1040.113 257.793 1297.906

Grand Total 2834.308 515.134 3349.442

2014-15

Active 2062.196 41.945 2104.141

Passive 1264.641 221.072 1485.713

Grand Total 3326.837 263.017 3589.854

2015-16

Active 1935.406 66.104 2001.51

Passive 1395.885 247.449 1643.334

Grand Total 3331.291 313.553 3644.844

2016-17

Active 1116.468 0.23 1116.698

Passive 1386.56 244.775 1631.335

Grand Total 2503.028 245.005 2748.033

2017-18

Active 1066.593 13.486 1080.079

Passive 1619.147 341.37 1960.517 Grand Total 2685.74 354.856 3040.596

2018-19

Active 565.866 81.394 647.26

Passive 1870.549 285.602 2156.151

Grand Total 2436.415 366.996 2803.411


RELIABILITY COSTS – NET COMMITMENT PERIOD COMPENSATION (NCPC) OPERATING COSTS


What are Daily NCPC Payments?

• “Make-whole” payments made to resources whose hourly commitment and dispatch by ISO-NE resulted in a shortfall between the resource’s offered value in the Energy and Regulation Markets and the revenue earned from output over the course of the day

• Typically, this is the result of some out-of-merit operation of resources occurring in order to protect the overall resource adequacy and transmission security of specific locations or of the entire control area

57


Definitions

58

1st Contingency NCPC Payments

Reliability costs paid to eligible resources that are providing first contingency (1stC) protection (including low voltage, system operating reserve, and load serving) either system-wide or locally

2nd Contingency NCPC Payments

Reliability costs paid to resources providing capacity in constrained areas to respond to a local second contingency. They are committed based on 2nd Contingency (2ndC) protocols, and are also known as Local Second Contingency Protection Resources (LSCPR)

Voltage NCPC Payments Reliability costs paid to resources operated by ISO-NE to provide voltage support or control in specific locations

Distribution NCPC Payments

Reliability costs paid to units dispatched at the request of local transmission providers for purpose of managing constraints on the low voltage (distribution) system. These requirements are not modeled in the DA Market software

Delisted Units Resources within the control area that have requested to be classified as a non-installed capacity (ICAP) resource, and as such, are not required to offer their capacity into the DA Energy Market

OATT Open Access Transmission Tariff


Charge Allocation Key

59

Allocation Category

Market / OATT

Allocation

System 1st Contingency

Market

DA 1st C (excluding at external nodes) is allocated to system DALO. RT 1st C (at all locations) is allocated to System ‘Daily Deviations’. Daily Deviations = sum of(generator deviations, load deviations, generation obligation deviations at external nodes, increment offer deviations)

External DA 1st Contingency

Market

DA 1st C at external nodes (from imports, exports, Incs and Decs) are allocated to activity at the specific external node or interface involved

Zonal 2nd Contingency

Market DA and RT 2nd C NCPC are allocated to load obligation in the Reliability Region (zone) served

System Low Voltage

OATT (Low) Voltage Support NCPC is allocated to system Regional Network Load and Open Access Same-Time Information Service (OASIS) reservations

Zonal High Voltage

OATT

High Voltage Control NCPC is allocated to zonal Regional Network Load

Distribution - PTO OATT

Distribution NCPC is allocated to the specific Participant Transmission Owner (PTO) requesting the service

System – Other Market Includes GPA, Min Generation Emergency, and Generator and DARD NCPC


GR:Graph23 GR:Graph23m NCPC Dollars

2012 2013

2014 2015

Mill

ion

s

$0

$10

$20

$30

$40

$50

$60

$70

$80


NCPC Energy*

2012 2013

2014 2015

GW

h

0

100

200

300

400

500

600

700

800

900


Year-Over-Year Total NCPC Dollars and Energy

60

* NCPC Energy GWh reflect the DA and/or RT economic minimum loadings of all units receiving DA or RT NCPC credits, assessed during hours in which they are NCPC-eligible. All NCPC components (1st Contingency, 2nd Contingency, Voltage, and RT Distribution) are reflected.


GR:Graph01 GR:Graph02 APR-15 Total = $9.24 M

Day-Ahead Real-Time

46%

54%

DA and RT NCPC Charges

61

Last 13 Months

Day-Ahead Real-Time

Mill

ion

s $0

$15

$30

$45

$60

$75

APR2014

MAY2

014

JUN

2014

JUL2

014

AUG

2014

SEP2

014

OCT2

014

NO

V2014

DEC

2014

JAN

2015

FEB20

15M

AR2015

APR2015


GR:Graph04 GR:Graph03 APR-15 Total = $9.24 M

1st C 2nd CVoltage

33%

67%

0%

NCPC Charges by Type

62

1st C – First Contingency

2nd C – Second Contingency

Distrib – Distribution

Voltage – Voltage

Last 13 Months

1st C 2nd CVoltage Distrib

Mill

ion

s $0

$15

$30

$45

$60

$75

APR14

MAY1

4JU

N14

JUL1

4AU

G14

SEP1

4O

CT14

NO

V14D

EC14

JAN

15

FEB15

MAR15

APR15


GR:ncpc_bytype_stack_dly

1st C 2nd C Voltage

Mil

lio

ns

$0.0

$0.1

$0.2

$0.3

$0.4

$0.5

$0.6

$0.7

$0.8

$0.9

$1.0

$1.1

$1.2

$1.3

$1.4

$1.5

$1.6

$1.701A

PR2015

02APR20

1503A

PR2015

04APR20

1505A

PR2015

06APR20

1507A

PR2015

08APR20

1509A

PR2015

10APR20

1511A

PR2015

12APR20

1513A

PR2015

14APR20

1515A

PR2015

16APR20

1517A

PR2015

18APR20

1519A

PR2015

20APR20

1521A

PR2015

22APR20

15

Daily NCPC Charges by Type

63


GR:xchart_ncpc_chgs_alloc_cat GR:xpie_ncpc_chgs_alloc_cat APR-15 Total = $9.23 M

System 1stC Ext DA 1stCZonal 2ndC Dist - PTOSystem Other

32%0.0%

67%

0.0%0.8%

NCPC Charges by Allocation

64

0.8%

Last 13 Months

System 1stC Ext DA 1stCZonal 2ndC System Low VZonal High V

Mill

ion

s

$0.0

$8.0

$16.0

$24.0

$32.0

$40.0

APR14

MAY1

4JU

N14

JUL1

4AU

G14

SEP1

4O

CT14

NO

V14D

EC14

JAN

15FE

B15M

AR15APR1

5


GR:chart_firstc_rt_bydev_13mo GR:pie_firstc_rt_bydev APR-15 Total = $2.26 M

Gen ImportInc Load

9.9%

10.7%13.3%

66.1%

RT First Contingency Charges by Deviation Type

65

Gen – Generator deviations

Inc – Increment Offer deviations

Imp – Import deviations

Load – Load obligation deviations

Last 13 Months

Gen ImportInc Load

Mill

ion

s $0

$1

$2

$3

$4

$5

$6

$7

$8

$9

$10

APR14

MAY1

4JU

N14

JUL1

4AU

G14

SEP1

4O

CT14

NO

V14D

EC14

JAN

15FE

B15M

AR15APR1

5


GR:lscpr_charges_byzone_13mo

CT ME NEMA NHRI SEMA VT WCMA

Mil

lio

ns

$0.0

$1.0

$2.0

$3.0

$4.0

$5.0

$6.0

$7.0

APR14

MAY14

JUN

14

JUL1

4

AUG14

SEP14

OCT14

NO

V14

DEC14

JAN

15

FEB15

MAR15

APR15

LSCPR Charges by Zone

66

CT – Connecticut Region

ME – Maine Region

NH – New Hampshire Region

RI – Rhode Island Region

VT – Vermont Region

SEMA – Southeast Massachusetts Region

WCMA – Western/Central Massachusetts Region

NEMA – Northeast Massachusetts Region

EXT – External Locations


GR:var_charges_stack_13mo

DA LV NCPC RT LV NCPC DA HV NCPC

Mil

lio

ns

$0.0

$0.1

$0.2

$0.3

$0.4

$0.5

$0.6

$0.7

$0.8

$0.9

$1.0

$1.1

$1.2

$1.3

$1.4

$1.5

$1.6

APR14

MAY14

JUN

14

JUL1

4

AUG14

SEP14

OCT14

NO

V14

DEC14

JAN

15

FEB15

MAR15

APR15

NCPC Charges for Voltage Support and High Voltage Control

67


GR:NCPC_Stack Value of Charges

1st C 2nd C Distr Voltg

Mill

ions

$0

$25

$50

$75

$100

$125

$150

$175

2013

2014

2015

JAN

2015

FEB20

15

MAR20

15

APR2015

MAY201

5

JUN2015

JUL2

015

AUG20

15

SEP2015

OCT2

015

NOV201

5

DEC2015

$158.7 $

174.7

$45.2

$9.8

$11.4

$14.8

$9.2

NCPC Charges by Type

68


GR:NCPC_pct_Stack NCPC By Type as Percent of Energy Market

1st C 2nd C Distr Voltg

Perc

ent

0.0%

1.0%

2.0%

3.0%

4.0%

5.0%

2013

2014

2015

JAN

2015

FEB20

15

MAR20

15

APR2015

MAY201

5

JUN2015

JUL2

015

AUG20

15

SEP2015

OCT2

015

NOV201

5

DEC2015

2.0

%

1.9

%

1.4

%

1.1

%

0.8

%

2.0

%

4.4

%

NCPC Charges as Percent of Energy Market

69


GR:Graph19 GR:Graph20 Value of Charges

Mill

ion

s

$0

$20

$40

$60

$80

$100

$120

$140

2013

2014

2015

JAN

2015

FEB

2015

MA

R20

15A

PR2

015

MA

Y201

5JU

N20

15JU

L201

5A

UG

2015

SEP2

015

OC

T201

5N

OV

2015

DEC

2015

$98.9

$135.3

$30.2

$8.6

$9.2

$9.5

$3.0

% of Energy Market Value

0.0%

1.0%

2.0%

3.0%

4.0%

2013

2014

2015

JAN

2015

FEB

2015

MA

R20

15A

PR2

015

MA

Y201

5JU

N20

15JU

L201

5A

UG

2015

SEP2

015

OC

T201

5N

OV

2015

DEC

2015

1.2

% 1.5

%

0.9

%

1.0

%

0.7

%

1.3

%

1.4

%

First Contingency NCPC Charges

70

Note: Energy Market value is the hourly locational product of load obligation and price in the DA Market plus the hourly locational product of price and RT Load Obligation Deviation in the RT Market


GR:Graph22 GR:Graph21 % of Energy Market Value

0.0%

0.8%

1.6%

2.4%

3.2%

4.0%

2013

2014

2015

JAN

2015

FEB

2015

MA

R20

15A

PR2

015

MA

Y201

5JU

N20

15JU

L201

5A

UG

2015

SEP2

015

OC

T201

5N

OV

2015

DEC

2015

0.5

%

0.4

%

0.4

%

0.1

%

0.1

%

0.7

%

3.0

%

Value of Charges

Mill

ion

s

$0

$10

$20

$30

$40

2013

2014

2015

JAN

2015

FEB

2015

MA

R20

15A

PR2

015

MA

Y201

5JU

N20

15JU

L201

5A

UG

2015

SEP2

015

OC

T201

5N

OV

2015

DEC

2015

$38.0

$32.4

$12.5

$0.6

$0.9

$4.9

$6.2

Second Contingency NCPC Charges

71



GR:Graph18 GR:Graph17 % of Energy Market Value

0.0%

1.0%

2.0%

3.0%

4.0%

2013

2014

2015

JAN

2015

FEB

2015

MA

R20

15A

PR2

015

MA

Y201

5JU

N20

15JU

L201

5A

UG

2015

SEP2

015

OC

T201

5N

OV

2015

DEC

2015

0.3

%

0.1

%

0.1

%

0.1

%

0.1

%

0.1

%

0.0

%

Value of Charges

Mill

ion

s

$0

$10

$20

$30

$40

2013

2014

2015

JAN

2015

FEB

2015

MA

R20

15A

PR2

015

MA

Y201

5JU

N20

15JU

L201

5A

UG

2015

SEP2

015

OC

T201

5N

OV

2015

DEC

2015

$21.8

$7.0

$2.4

$0.7

$1.3

$0.4

$0.0

Voltage and Distribution NCPC Charges

72



DA vs. RT Pricing

The following slides outline:

• This month vs. prior year’s average LMPs and fuel costs

• Reserve Market results

• DA cleared load vs. RT load

• Zonal and total incs and decs

• Self-schedules

• DA vs. RT net interchange

73


DA vs. RT LMPs ($/MWh)

74

Year 2013 NEMA CT ME NH VT RI SEMA WCMA Hub

Day-Ahead $56.90 $55.43 $54.48 $55.98 $55.36 $57.80 $57.02 $56.38 $56.43

Real-Time $56.32 $55.90 $53.23 $55.15 $55.08 $56.10 $56.43 $56.12 $56.06

RT Delta % -1.0% 0.8% -2.3% -1.5% -0.5% -2.9% -1.0% -0.5% -0.7%

Year 2014 NEMA CT ME NH VT RI SEMA WCMA Hub

Day-Ahead $64.98 $64.10 $61.95 $64.12 $63.82 $64.98 $64.71 $64.66 $64.57

Real-Time $64.03 $63.11 $59.04 $61.48 $61.60 $63.34 $63.45 $63.29 $63.32

RT Delta % -1.5% -1.5% -4.7% -4.1% -3.5% -2.5% -2.0% -2.1% -1.9%

April-14 NEMA CT ME NH VT RI SEMA WCMA Hub

Day-Ahead $45.47 $45.00 $43.62 $45.05 $44.00 $44.54 $44.81 $45.09 $44.98

Real-Time $41.86 $41.19 $40.28 $41.19 $40.01 $40.94 $41.16 $41.26 $41.20

RT Delta % -7.9% -8.5% -7.7% -8.6% -9.1% -8.1% -8.1% -8.5% -8.4%

April-15 NEMA CT ME NH VT RI SEMA WCMA Hub

Day-Ahead $28.66 $27.83 $28.10 $28.23 $31.12 $29.15 $28.60 $28.33 $28.34

Real-Time $25.67 $25.15 $25.15 $25.13 $24.44 $25.59 $25.48 $25.43 $25.41

RT Delta % -10.4% -9.6% -10.5% -11.0% -21.5% -12.2% -10.9% -10.3% -10.3%

Annual Diff. NEMA CT ME NH VT RI SEMA WCMA Hub

Yr over Yr DA -37.0% -38.2% -35.6% -37.3% -29.3% -34.6% -36.2% -37.2% -37.0%

Yr over Yr RT -38.7% -39.0% -37.6% -39.0% -38.9% -37.5% -38.1% -38.4% -38.3%


GR:Graph25

Ma

rch

20

03

=1

.00

0

0.000

1.000

2.000

3.000

MAR20

03JU

N20

03SE

P200

3D

EC20

03M

AR2004

JUN

2004

SEP2

004

DEC

2004

MAR20

05JU

N20

05SE

P200

5D

EC20

05M

AR2006

JUN

2006

SEP2

006

DEC

2006

MAR20

07JU

N20

07SE

P200

7D

EC20

07M

AR2008

JUN

2008

SEP2

008

DEC

2008

MAR20

09JU

N20

09SE

P200

9D

EC20

09M

AR2010

JUN

2010

SEP2

010

DEC

2010

MAR20

11JU

N20

11SE

P201

1D

EC20

11M

AR2012

JUN

2012

SEP2

012

DEC

2012

MAR20

13JU

N20

13SE

P201

3D

EC20

13M

AR2014

JUN

2014

SEP2

014

DEC

2014

MAR20

15JU

N20

15SE

P201

5

Natural Gas Hub RT LMP

Monthly Average Fuel Price and RT Hub LMP Indexes

75




GR:hubwgas_mly_smd $

/M

MB

tu (

Fu

el)

$0.00

$3.00

$6.00

$9.00

$12.00

$15.00

$18.00

$21.00

$24.00

$27.00

$30.00

MAR20

03JU

N20

03SE

P200

3D

EC20

03M

AR2004

JUN

2004

SEP2

004

DEC

2004

MAR20

05JU

N20

05SE

P200

5D

EC20

05M

AR2006

JUN

2006

SEP2

006

DEC

2006

MAR20

07JU

N20

07SE

P200

7D

EC20

07M

AR2008

JUN

2008

SEP2

008

DEC

2008

MAR20

09JU

N20

09SE

P200

9D

EC20

09M

AR2010

JUN

2010

SEP2

010

DEC

2010

MAR20

11JU

N20

11SE

P201

1D

EC20

11M

AR2012

JUN

2012

SEP2

012

DEC

2012

MAR20

13JU

N20

13SE

P201

3D

EC20

13M

AR2014

JUN

2014

SEP2

014

DEC

2014

MAR20

15JU

N20

15SE

P201

5

$/

MW

h (

Ele

ctri

city

)

$0.00

$40.00

$80.00

$120.00

$160.00

$200.00

Natural Gas Hub RT LMP

Monthly Average Fuel Price and RT Hub LMP

76




GR:three_pools_prices_dly GR:three_pools_prices_mly

Ele

ctri

city

Pri

ces

($/M

Wh

)

$10

$20

$30

$40

$50

$60

01APR15

02APR15

03APR15

04APR15

05APR15

06APR15

07APR15

08APR15

09APR15

10APR15

11APR15

12APR15

13APR15

14APR15

15APR15

16APR15

17APR15

18APR15

19APR15

20APR15

21APR15

22APR15

Daily: This Month

*Note: Hourly average prices are shown.

ISO-NE NY-ISO PJM

Ele

ctri

city

Pri

ces

($/M

Wh

)

$20

$30

$40

$50

$60

$70

$80

$90

$100

$110

$120

$130

APR2014

MAY2

014

JUN

2014

JUL2

014

AUG

2014

SEP2

014

OCT2

014

NO

V2014

DEC

2014

JAN

2015

FEB20

15M

AR2015

APR2015


*Note: Hourly average prices are shown.

ISO-NE NY-ISO PJM

New England, NY, and PJM Real Time Prices

77


GR:three_pools_prices_fpk_dly GR:three_pools_prices_fpk_mly

Ele

ctri

city

Pri

ces

($/M

Wh

)

$10

$20

$30

$40

$50

$60

$70

$80

$90

$100

$110

01APR15

02APR15

03APR15

04APR15

05APR15

06APR15

07APR15

08APR15

09APR15

10APR15

11APR15

12APR15

13APR15

14APR15

15APR15

16APR15

17APR15

18APR15

19APR15

20APR15

21APR15

22APR15

Daily: This Month

ISO-NE NY-ISO PJM

Ele

ctri

city

Pri

ces

($/M

Wh

)

$30 $40 $50 $60 $70 $80 $90

$100 $110 $120 $130 $140 $150 $160 $170

APR2014

MAY2

014

JUN

2014

JUL2

014

AUG

2014

SEP2

014

OCT2

014

NO

V2014

DEC

2014

JAN

2015

FEB20

15M

AR2015

APR2015


ISO-NE NY-ISO PJM

New England, NY, and PJM Real Time Prices (Peak Hour)

78

*Forecasted peak hour is reflected.


Reserve Market Results – April 2015

• Maximum potential Forward Reserve Market payments of $10.1M were reduced by credit reductions of $238K, failure-to-reserve penalties of $356K and failure-to-activate penalties of $0, resulting in a net payout of $9.5M or 94% of maximum – Rest of System: $5.40M/$5.53M (98%) – Southwest Connecticut: $0.58M/$0.81M (72%) – Connecticut: $3.49M/$3.72M (94%)

• $114K total Real-Time credits were reduced by $0 in Forward Reserve Energy Obligation Charges for a net of $114K in Real-Time Reserve payments – Rest of System: 72 hours, $108K – Southwest Connecticut: 72 hours, $2K – Connecticut: 72 hours, $2K – NEMA: 72 hours, $3K

79

* “Failure to reserve” results in both credit reductions and penalties in the Locational Forward Reserve Market.


GR:Graph39 LFRM Charges by Zone, Last 13 Months

CT ME NEMA NH

RI SEMA VT WCMA

Mill

ion

s

$0.0

$5.0

$10.0

$15.0

$20.0

$25.0APR14

MAY14

JUN14

JUL1

4

AUG14

SEP14

OCT1

4

NOV14

DEC14

JAN

15

FEB15

MAR15

APR15

LFRM Charges to Load by Load Zone ($)

80


GR:Graph28 April Monthly Totals by Zone

Cleared Offered

MW

h

0

10,000

20,000

30,000

40,000

50,000

60,000

70,000

80,000

90,000

100,000

110,000

120,000


20

14

20

15

20

14

20

15

20

14

20

15

20

14

20

15

20

14

20

15

20

14

20

15

20

14

20

15

20

14

20

15

20

14

20

15

Zonal Increment Offers and Cleared Amounts

81


GR:Graph29 April Monthly Totals by Zone

Cleared Bid

MW

h

0

10,000

20,000

30,000

40,000

50,000


20

14

20

15

20

14

20

15

20

14

20

15

20

14

20

15

20

14

20

15

20

14

20

15

20

14

20

15

20

14

20

15

20

14

20

15

Zonal Decrement Bids and Cleared Amounts

82


GR:Graph30 Zonal Level, Last 13 Months

Cleared Bid/Offered

MW

h

0

200,000

400,000

600,000

800,000

AP

R2

01

4

MA

Y2

01

4

JUN

20

14

JUL2

01

4

AU

G2

01

4

SEP

20

14

OC

T20

14

NO

V2

01

4

DEC

20

14

JAN

20

15

FEB

20

15

MA

R2

01

5

AP

R2

01

5

INC

DEC IN

C

DEC IN

C

DEC IN

C

DEC IN

C

DEC IN

C

DEC IN

C

DEC IN

C

DEC IN

C

DEC IN

C

DEC IN

C

DEC IN

C

DEC IN

C

DEC

Total Increment Offers and Decrement Bids

83

Data excludes nodal offers and bids


GR:Graph31 Total Monthly Energy; Dispatchable % Shown

Non-Dispatchable Dispatchable

GW

h

0

2,000

4,000

6,000

8,000

10,000

12,000

14,000APR201

4

MAY201

4

JUN2014

JUL2

014

AUG20

14

SEP2014

OCT2

014

NOV201

4

DEC2014

JAN

2015

FEB20

15

MAR20

15

APR2015

24.8

%

19.2

% 24.6

%

30.7

%

26.3

%

22.8

%

19.9

%

17.1

% 34.1

%

41.2

%

49.7

%

42.0

%

37.9

%

Dispatchable vs. Non-Dispatchable Generation

84

* Dispatchable MWh here are defined to be generation output that is not self-scheduled (i.e, not self-committed or ‘must run’ by the customer).


GR:rolling_avg_per_big

Maine Rest-of-Pool

$/K

W-M

on

th

$0.00

$0.04

$0.08

$0.12

$0.16

$0.20

monthAPR14 MAY14 JUN14 JUL14 AUG14 SEP14 OCT14 NOV14 DEC14 JAN15 FEB15 MAR15 APR15

Rolling Average Peak Energy Rent (PER)

85

Rolling Average PER is currently calculated as a rolling twelve month average of individual monthly PER values for the twelve months preceding the obligation month.

Individual monthly PER values are published to the ISO web site here: Home > Markets > Other Markets Data > Forward Capacity Market > Reports and are subject to resettlement.

NEW SLIDE


GR:fcm_per_adj_byzone_big

Maine Rest-of-Pool

Mil

lio

ns

($)

$0.0

$1.0

$2.0

$3.0

monthAPR14 MAY14 JUN14 JUL14 AUG14 SEP14 OCT14 NOV14 DEC14 JAN15 FEB15 MAR15 APR15

PER Adjustments

86

NEW SLIDE

PER Adjustments are reductions to Forward Capacity Market monthly payments resulting from the rolling average PER.


REGIONAL SYSTEM PLAN (RSP) AND INTERREGIONAL PLANNING


Planning Advisory Committee (PAC)

88

• The next PAC meeting is scheduled for May 20. Major agenda topics will include:

– Update on EIPC Activities

– Discussion on Scope of Work for 2015 Economic Studies based on the three requests discussed at the April 22 PAC meeting

• Offshore wind development in MA and RI

• Onshore wind development in ME

• Onshore wind development focusing on the Keene Road interface


Distributed Generation Forecast Working Group (DGFWG)

89

• DGFWG meeting was held on April 14 and the ISO finalized the PV forecast

• The CELT 2015 and DGFWG website includes more details on the final 2015 PV forecasts

– Forecasts show PV nameplate, estimated seasonal claimed capability, and energy production

– Forecasts have been developed for the overall system, states, and RSP bubbles

• The next DGFWG meeting will be a teleconference or webinar on June 12


DGFWG, cont.

90

• ISO has classified PV resources by market participation type – FCM resources with capacity supply obligations – Settlement-only resources (energy market only) – Behind-the-meter resources that are already accounted for as part of the ISO

load forecast – Remaining behind-the-meter resources

• ISO urges DG resources to participate in the FCM

• A portion of the behind-the-meter PV forecast has been identified as a part of the demand forecast that needs to be captured for purposes of Installed Capacity Requirement calculations

– ISO will continue working with the PSPC and the RC to receive stakeholder input in preparation for FCA #10

• PV forecast will be used in new economic studies and new transmission planning studies

• ISO is working with the transmission owners, distribution owners, the states, and IEEE to resolve interconnection issues

• ISO will continue participation in DOE projects that support operational and planning forecasts of PV


91

Environmental Matters

• Environmental Advisory Group meeting was held on April 7 to discuss EPA Regulatory & Litigation Developments and a Greenhouse Gas Regulatory Update


RSP Project Stage Descriptions

92

Stage Description

1 Planning and Preparation of Project Configuration

2 Pre-construction (e.g., material ordering, project scheduling)

3 Construction in Progress 4 In Service


NEEWS: Interstate Reliability Project Status as of 4/27/15

Plan Benefit: Improves New England reliability by increasing transfer limits of three critical interfaces

93

Upgrade

Expected

In-service

Present

Stage

Build New 345 kV Line 3271 Card - Lake Road Dec-15 3

Card 345 kV Substation Expansion Dec-15 3

Lake Road 345 kV Substation Expansion Dec-15 3

Build New 345 kV Line 341 Lake Road to CT/RI Border Dec-15 3

Build New 345 kV Line 341 CT/RI Border to West Farnum Dec-15 3

West Farnum 345 kV Substation Additions (New Line Terminations) Dec-15 3

New Sherman Road 345 kV Substation Dec-15 3

West Farnum 115 kV Substation Upgrades Sep-14 4

Reconductor 345 kV Line 328 West Farnum to Sherman Road Dec-15 3

Riverside Substation Relay Upgrades Sep-14 4

Woonsocket Substation Relay Upgrades Sep-14 4

Hartford Avenue Substation Relay Upgrades Sep-14 4

Build New 345 kV Line 366 West Farnum to MA/RI Border Dec-15 3

Build New 345 kV Line 366 MA/RI Border to Millbury 3 Dec-15 3

Millbury 3 Substation Expansion Dec-15 3

Carpenter Hill Substation Relay Upgrades Dec-15 3


Maine Power Reliability Program (MPRP) Status as of 4/27/15

Project Benefit: Addresses long-term system needs of Emera Maine and Central Maine Power, thermal and voltage issues in western Maine and supports load growth in southern Maine

94

New 345 kV Lines

Expected

In-Service

Present

Stage

Construct New Section 3023 Orrington to Albion Road May-13 4

Construct New Section 3024 Albion Road to Coopers Mills Mar-15 4

Construct New Section 3025 Coopers Mills to Larrabee Road Apr-15 4

Construct New Section 3026 Larrabee Road to Surowiec Dec-12 4

Construct New Section 3020 Surowiec to Raven Farm Nov-13 4

Construct New Section 3021 South Gorham to Maguire Road Apr-14 4

Construct New Section 3022 Maguire Road to Eliot Aug-14 4

Note 1: This is the final status update presentation for the MPRP project. The majority of the project is complete and in service as of April 2015 with lines 255 and 256 planned to be in service in March 2017. For future updates on the status of these two lines, please see the RSP Project List updates at http://www.iso-ne.com/system-planning/system-plans-studies/rsp. Note 2: The above listing focuses on major transmission line construction and rebuilding.


http://www.iso-ne.com/system-planning/system-plans-studies/rsp










Maine Power Reliability Program, cont. Status as of 4/6/15


95

New 115 kV Lines

Expected

In-Service

Present

Stage

Construct New Section 254 Orrington to Coopers Mills Mar-15 4

Construct New Section 243A Livermore Falls to Junction Section 243 May-14 4

Construct New Section 251 Livermore Falls to Larrabee Road May-14 4

Construct New Section 255 Larrabee Road to Middle Street Mar-17 3

Construct New Section 86A Tap to Belfast Jul-14 4

Construct New Section 256 Middle Street to Lewiston Lower Mar-17 1














96

115 kV Lines Rebuilds

Expected

In-Service

Present

Stage

Rebuild Section 60 Coopers Mills to Bowman Street Feb-15 4

Rebuild Section 88 Coopers Mills to Augusta East Side Feb-15 4

Rebuild Section 89 Livermore Falls to Riley May-14 4

Rebuild Section 229 Riley to Rumford IP May-13 4

Rebuild Section 212 Monmouth to Larrabee Road Feb-13 4

Rebuild Section 269 Bowman Street to Monmouth May-12 4

Rebuild Section 238 Louden to Maguire Road Feb-12 4

Rebuild Section 250 Maguire Road to Three Rivers Dec-13 4















97


345/115 kV Autotransformers

Expected

In-Service

Present

Stage

Install One 345/115 kV Autotransformer at Albion Road Apr-13 4

Install One 345/115 kV Autotransformer at Coopers Mills Mar-15 4

Install One 345/115 kV Autotransformer at Larrabee Road Dec-12 4

Install One 345/115 kV Autotransformer at Maguire Road Apr-14 4

Install One 345/115 kV Autotransformer at South Gorham Nov-09 4













New Hampshire/Vermont 10-Year Upgrades Status as of 4/27/15

Project Benefit: Addresses Needs in New Hampshire and Vermont

98

Note: The above listing focuses on major transmission line construction and rebuilding.

Upgrade

Expected

In-Service

Present

Stage

Eagle Substation Add: 345/115 kV autotransformer Dec-16 2

Littleton Substation Add: Second 230/115 kV autotransformer Oct-14 4

New C-203 230 kV line tap to Littleton NH Substation Nov-14 4

New 115 kV overhead line, Fitzwilliam-Monadnock Dec-15 3

New 115 kV overhead line, Scobie Pond-Huse Road Dec-15 3

New 115 kV overhead/submarine line, Madbury-Portsmouth Dec-17 2

New 115 kV overhead line, Scobie Pond-Chester Dec-15 3

New 115 kV overhead line, Coolidge-Ascutney Dec-16 1


New Hampshire/Vermont 10-Year Upgrades, cont. Status as of 4/27/15


99


Upgrade

Expected

In-Service

Present

Stage

Saco Valley Substation - Add two 25 MVAR dynamic reactive devices Dec-16 3

Rebuild 115 kV line K165, W157 tap Eagle-Power Street May-15 3

Rebuild 115 kV line H137, Merrimack-Garvins Jun-13 4

Rebuild 115 kV line D118, Deerfield-Pine Hill Nov-14 4

Oak Hill Substation - Loop in 115 kV line V182, Garvins-Webster Apr-15 4*

Uprate 115 kV line G146, Garvins-Deerfield Mar-15 4

Uprate 115 kV line P145, Oak Hill-Merrimack May-14 4

* Placed in-service ahead of schedule


New Hampshire/Vermont 10-Year Upgrades, cont. Status as of 4/27/15


100


Upgrade

Expected

In-Service

Present

Stage

Upgrade 115 kV line H141, Chester-Great Bay Nov-14 4

Upgrade 115 kV line R193, Scobie Pond-Kingston Tap Mar-15 4*

Upgrade 115 kV line T198, Keene-Monadnock Nov-13 4

Upgrade 345 kV line 326, Scobie Pond-NH/MA Border Dec-13 4

Upgrade 115 kV line J114-2, Greggs - Rimmon Dec-13 4

Upgrade 345 kV line 381, between MA/NH border and NH/VT border Jun-13 4

* Placed in-service ahead of schedule


Greater Hartford and Central Connecticut (GHCC) Projects* Status as of 4/27/15

101

Upgrade

Expected

In-service

Present

Stage

Add a 2nd 345/115 kV autotransformer at Haddam substation and reconfigure

the 3-terminal 345 kV 348 line into two 2-terminal lines Dec-16 2

Terminal equipment upgrades on the 345 kV line between Haddam Neck and

Beseck (362) Dec-17 1

Redesign the Green Hill 115 kV substation from a straight bus to a ring bus and

add two 115 kV 25.2 MVAR capacitor banks Dec-17 1

Add a 37.8 MVAR capacitor bank at the Hopewell 115 kV substation Dec-16 1

Separation of 115 kV double circuit towers corresponding to the Branford –

Branford RR line (1537) and the Branford to North Haven (1655) line and

adding a 115 kV breaker at Branford 115 kV substation Dec-17 1

Increase the size of the existing 115 kV capacitor bank at Branford Substation

from 37.8 to 50.4 MVAR Dec-17 1

Separation of 115 kV double circuit towers corresponding to the Middletown –

Pratt and Whitney line (1572) and the Middletown to Haddam (1620) line Dec-17 1

Plan Benefit: Addresses long-term system needs in the four study sub-areas of Greater Hartford, Middletown, Barbour Hill and Northwestern Connecticut and increases western Connecticut import capability

* Replaces the NEEWS Central Connecticut Reliability Project


Greater Hartford and Central Connecticut Projects, cont.* Status as of 4/27/15

102

Upgrade

Expected

In-service

Present

Stage

Terminal equipment upgrades on the 115 kV line from Middletown to Dooley

(1050) Dec-17 1

Terminal equipment upgrades on the 115 kV line from Middletown to Portland

(1443) Dec-17 1

Add a new 115 kV underground cable from Newington to Southwest Hartford

and associated terminal equipment including a 2% series reactor Dec-18 1

Add a 115 kV 25.2 MVAR capacitor at Westside 115 kV substation Dec-16 1

Loop the 1779 line between South Meadow and Bloomfield into the Rood

Avenue substation and reconfigure the Rood Avenue substation Dec-17 1

Reconfigure the Berlin 115 kV substation including two new 115 kV breakers

and the relocation of a capacitor bank Dec-18 1

Reconductor the 115 kV line between Newington and Newington Tap (1783) Dec-18 1





103

Upgrade

Expected

In-service

Present

Stage

Separation of 115 kV DCT corresponding to the Bloomfield to South Meadow

(1779) line and the Bloomfield to North Bloomfield (1777) line and add a

breaker at Bloomfield 115 kV substation Dec-17 1

Separation of 115 kV DCT corresponding to the Bloomfield to North

Bloomfield (1777) line and the North Bloomfield – Rood Avenue – Northwest

Hartford (1751) line and add a breaker at North Bloomfield 115 kV substation Dec-17 1

Install a 115 kV 3% reactor on the 115 kV line between South Meadow and

Southwest Hartford (1704) Dec-18 1

Replace the existing 3% series reactors on the 115 kV lines between

Southington and Todd (1910) and between Southington and Canal (1950) with

a 5% series reactors Dec-17 1

Replace the normally open 19T breaker at Southington 115 kV with a normally

closed 3% series reactor Dec-17 1

Add a 345 kV breaker in series with breaker 5T at Southington Dec-17 1





104

Upgrade

Expected

In-service

Present

Stage

Add a new control house at Southington 115 kV substation Dec-17 1

Add a new 115 kV line from Frost Bridge to Campville Dec-18 1

Separation of 115 kV DCT corresponding to the Frost Bridge to Campville

(1191) line and the Thomaston to Campville (1921) line and add a breaker at

Campville 115 kV substation Dec-18 1

Upgrade the 115 kV line between Southington and Lake Avenue Junction

(1810-1) Dec-17 1

Add a new 345/115 kV autotransformer at Barbour Hill substation Dec-16 2

Add a 345 kV breaker in series with breaker 24T at the Manchester 345 kV

substation Dec-16 2

Reconductor the 115 kV line between Manchester and Barbour Hill (1763) Dec-16 2




Southwest Connecticut (SWCT) Projects Status as of 4/27/15

105

Upgrade

Expected

In-service

Present

Stage

Add a 25.2 MVAR capacitor bank at the Oxford substation Dec-17 1

Add 2 x 25 MVAR capacitor banks at the Ansonia substation Dec-17 1

Close the normally open 115 kV 2T circuit breaker at Baldwin substation Dec-17 1

Rebuild Bunker Hill to a 9-breaker substation in breaker-and-a-half

configuration Dec-17 1

Reconductor the 115 kV line between Bunker Hill and Baldwin Junction (1575) Dec-17 1

Loop the 1990 line in and out the Bunker Hill substation Dec-17 1

Expand Pootatuck (formerly known as Shelton) substation to 4-breaker ring

bus configuration and add a 30 MVAR capacitor bank at Pootatuck Dec-17 1

Loop the 1570 line in and out the Pootatuck substation Dec-17 1

Replace two 115 kV circuit breakers at the Freight substation Dec-17 1

Plan Benefit: Addresses long-term system needs in the four study sub-areas of Frost Bridge/Naugatuck Valley, Housatonic Valley/Plumtree – Norwalk, Bridgeport, New Haven – Southington and improves system reliability


Southwest Connecticut Projects, cont. Status as of 4/27/15

106


Upgrade

Expected

In-service

Present

Stage

Add two 14.4 MVAR capacitor banks at the West Brookfield substation Dec-17 1

Add a new 115 kV line from Plumtree to Brookfield Junction Dec-17 1

Reconductor the 115 kV line between West Brookfield and Brookfield

Junction (1887) Dec-17 1

Reduce the existing 25.2 MVAR capacitor bank at the Rocky River

substation to 14.4 MVAR Dec-17 1

Reconfigure the 1887 line into a three-terminal line (Plumtree - W.

Brookfield - Shepaug) Dec-17 1

Reconfigure the 1770 line into 2 two-terminal lines (Plumtree - Stony Hill and

Stony Hill - Bates Rock) Dec-17 1

Install a synchronous condenser (+25/-12.5 MVAR) at Stony Hill Dec-17 1

Relocate an existing 37.8 MVAR capacitor bank at Stony Hill to the 25.2

MVAR capacitor bank side Dec-17 1



107

Upgrade

Expected

In-service

Present

Stage

Relocate the existing 37.8 MVAR capacitor bank from 115 kV B bus to

115 kV A bus at the Plumtree substation Dec-17 1

Add a 115 kV circuit breaker in series with the existing 29T breaker at the

Plumtree substation Dec-17 1

Terminal equipment upgrade at the Newtown substation (1876) Dec-17 1

Rebuild the 115 kV line from Wilton to Norwalk (1682) and upgrade

Wilton substation terminal equipment Dec-17 1

Reconductor the 115 kV line from Wilton to Ridgefield Junction (1470-1) Dec-17 1

Reconductor the 115 kV line from Ridgefield Junction to Peaceable

(1470-3) Dec-17 1




108

Upgrade

Expected

In-service

Present

Stage

Add 2 x 20 MVAR capacitor banks at the Hawthorne substation Jun-16 2

Upgrade the 115 kV bus at the Baird substation Dec-17 1

Upgrade the 115 kV bus system and 11 disconnect switches at the

Pequonnock substationDec-14 4

Add a 345 kV breaker in series with the existing 11T breaker at the East

Devon substationDec-16 2

Rebuild the 115 kV lines from Baird to Congress (8809A / 8909B) Dec-18 1

Rebuild the 115 kV lines from Housatonic River Crossing (HRX) to Barnum

to Baird (88006A / 89006B)Apr-19 1

Plan Benefit: Addresses long-term system needs in the four study sub areas of Frost Bridge/Naugatuck Valley, Housatonic Valley/Plumtree – Norwalk, Bridgeport, New Haven – Southington and improves system reliability



109

Upgrade

Expected

In-service

Present

Stage

Remove the Sackett phase shifter Dec-17 1

Install a 7.5 ohm series reactor on 1610 line at the Mix Avenue substation Dec-17 1

Add 2 x 20 MVAR capacitor banks at the Mix Avenue substation Dec-17 1

Separate the 3827 (Beseck to East Devon) and 1610 (Southington to June

to Mix Avenue) double circuit towersDec-17 1

Upgrade the 1630 line relay at North Haven and Wallingford 1630 terminal

equipmentDec-16 1

Rebuild the 115 kV lines from Devon Tie to Milvon (88005A / 89005B) Dec-16 2

Replace two 115 kV circuit breakers at Mill River Dec-14 4

Plan Benefit: Addresses long-term system needs in the four study sub areas of Frost Bridge/Naugatuck Valley, Housatonic Valley/Plumtree – Norwalk, Bridgeport, New Haven – Southington and improves system reliability


Greater Boston Projects Status as of 4/27/15

110

Upgrade

Expected

In-service

Present

Stage

Install new 345 kV line from Scobie to Tewksbury Dec-17 1

Reconductor the Y-151 115 kV line from Dracut Junction to Power Street Dec-17 1

Reconductor the M-139 115 kV line from Tewksbury to Pinehurst and

associated work at Tewksbury Dec-16 1

Reconductor the N-140 115 kV line from Tewksbury to Pinehurst and

associated work at TewksburyDec-16 1

Reconductor the F-158N 115 kV line from Wakefield Junction to

Maplewood and associated work at MaplewoodJun-16 1

Reconductor the F-158S 115 kV line from Maplewood to Everett Jun-16 1

Install new 345 kV cable from Woburn to Wakefield Junction, install two new

160 MVAR variable shunt reactors and associated work at Wakefield

Junction and Woburn

Dec-18 1

Refurbish X-24 69 kV line from Millbury to Northboro Road Dec-15 1

Reconductor W-23W 69 kV line from Woodside to Northboro Road Jun-16 1

Plan Benefit: Addresses long-term system needs in the Greater Boston area and improves system reliability


Greater Boston Projects, cont. Status as of 4/27/15

111

Upgrade

Expected

In-service

Present

Stage

Separate X-24 and E-157W DCT Dec-15 1

Separate Q-169 and F-158N DCT Dec-15 1

Reconductor M-139/211-503 and N-140/211-504 115 kV lines from

Pinehurst to North Woburn tapMay-17 1

Install new 115 kV station at Sharon to segment three 115 kV lines from

West Walpole to HolbrookMay-17 1

Install third 115 kV line from West Walpole to Holbrook Dec-16 1

Install new 345 kV breaker in series with the 104 breaker at Stoughton Dec-16 1

Install new 230/115 kV autotransformer at Sudbury and loop the 282-602

230 kV line in and out of the new 230 kV switchyard at Sudbury Dec-15 1

Install a new 115 kV line from Sudbury to Hudson Dec-18 1




112

Upgrade

Expected

In-service

Present

Stage

Replace 345/115 kV autotransformer, 345 kV breakers, and 115 kV

switchgear at WoburnDec-17 1

Install a 345 kV breaker in series with breaker 104 at Woburn Dec-16 1

Reconfigure Waltham by relocating PARs, 282-507 line, and a breaker May-16 1

Upgrade 533-508 115 kV line from Lexington to Hartwell and associated

work at the stationsDec-15 1

Install a new 115 kV 54 MVAR capacitor bank at Newton Dec-16 1

Install a new 115 kV 36.7 MVAR capacitor bank at Sudbury Dec-16 1

Install a second Mystic 345/115 kV autotransformer and reconfigure the bus Dec-16 1

Install a 115 kV breaker on the West bus at K Street Dec-15 1

Install 115 kV cable from Mystic to Chelsea Dec-17 1

Split 110-522 and 240-510 DCT from Baker Street to Needham for a

portion of the way and install a 115 kV cable for the rest of the wayDec-17 1




113

Upgrade

Expected

In-service

Present

Stage

Install a second 115 kV cable from Mystic to Woburn to create a bifurcated

211-514 lineDec-17 1

Open lines 329-510/511 and 250-516/517 at Mystic and Chatham,

respectively. Operate K Street as a normally closed stationDec-16 1

Upgrade Kingston to create a second normally closed 115 kV bus tie and

reconfigure the 345 kV switchyardDec-17 1

Relocate the Chelsea capacitor bank to the 128-518 termination postion Dec-17 1




114

Upgrade

Expected

In-service

Present

Stage

Upgrade North Cambridge to mitigate 115 kV 5 and 10 stuck breaker

contingenciesJun-16 1

Upgrade Edgar 115 kV station to BPS standards Dec-20 1

Upgrade Dover 115 kV station to BPS standards Dec-20 1

Upgrade East Cambridge 115 kV station to BPS standards Dec-19 1

Upgrade West Methuen 115 kV station to BPS standards Jun-18 1

Upgrade Medway 115 kV station to BPS standards Dec-19 1

Install a 200 MVAR STATCOM at Coopers Mills TBD 1

Install a 115 kV 36.7 MVAR capacitor bank at Hartwell May-17 1

Install a 345 kV 160 MVAR shunt reactor at K Street May-18 1

Install a 115 kV breaker in series with the 5 breaker at Framingham Jun-17 1

Install a 115 kV breaker in series with the 29 breaker at K Street Dec-15 1



Status of Tariff Studies

115

17

8 11 12 105 5 6 8 10

24 24 25

4

77 7

7

7 6 5 44

7 9 9

0

00 0

0

0 0 0 00

00 0

16

1818 15

1521 21 19

2121

22 17 16

11

11

1 1 00

00

00 0

68

76 7 7

77

88

10 13 1321

20 18 2119 18 21 22

2222

22 24 24

33 3 3

3 3 4 44 4

46 5

0

10

20

30

40

50

60

70

80

90

100

Apr-14 May-14 Jun-14 Jul-14 Aug-14 Sep-14 Oct-14 Nov-14 Dec-14 Jan-15 Feb-15 Mar-15 Apr-15

7,341MW

6,907MW

8,345MW

8,293MW

8,268MW

8,268MW

8,311MW

8,355MW

9,579MW

10,597MW

11,208MW

11,367MW

11,294MW

Nu

mb

er

of

Pro

jects

Project Status

Distribution

Executed IA

Negotiating IA

Facility Study

Sys. Impact Study

Optional Study

Feasibility Study

Scoping

89

67

6265

63

69686565

6264

93 92

https://irtt.iso-ne.com/external.aspx Note: April 2015 based on partial data


https://irtt.iso-ne.com/external.aspx



OPERABLE CAPACITY ANALYSIS

Spring 2015


117

50/50 Load Forecast (Reference) May - 20152

CSO

May- 20152

SCC

Generator Operable Capacity MW 1 30,128 32,828

OP CAP From OP-4 RTDR (+) 319 319

OP CAP From OP-4 RTEG (+) 141 141

Operable Capacity Generator with OP-4 DR and RTEG 30,588 33,288

External Node Available Net Capacity, CSO imports minus firm capacity exports (+)

594 594

Non Commercial Capacity (+) 0 87

Non Gas-fired Planned Outage MW (-) 1,413 1,598

Gas Generator Outages MW (-) 778 952

Allowance for Unplanned Outages (-) 3,400 3,400

Generation at Risk Due to Gas Supply (-) 4 0 0

Net Capacity (NET OPCAP SUPPLY MW) 3 25,591 28,019

Peak Load Forecast MW(adjusted for Other Demand Resources) 2 21,868 21,868

Operating Reserve Requirement MW 2,375 2,375

Operable Capacity Required (NET LOAD OBLIGATION MW) 24,243 24,248

Operable Capacity Margin 3 1,348 3,776

1 Generator Operable Capacity is based on data as of April 15, 2015 and does not include Capacity associated with Settlement Only Generators, Passive and Active Demand Response, and external capacity. 2 Load based on 2015 CELT report and week with lowest Operable Capacity Margin, week beginning May 23, 2015. 3 Includes OP4 actions associated with RTEG and RTDR 4 Total of (Gas at Risk MW) – (Gas Gen Outages MW)

Spring 2015 Operable Capacity Analysis


118

Spring 2015 Operable Capacity Analysis

90/10 Load Forecast (Extreme) May - 20152

CSO

May - 20152

SCC






594 594


Non Gas-fired Planned Outage MW (-) 1,413 1,598








Operable Capacity Margin 3 -586 1,842



Spring 2015 Operable Capacity Analysis(MW) 50/50 Forecast (Reference)

119

(2,000)

(1,000)

0

1,000

2,000

3,000

2-M

ay

9-M

ay

16-M

ay

23-M

ay

Op

era

ble

Cap

acit

y M

arg

in (M

W)

ISO-NE 2015 OPERABLE CAPACITY ANALYSIS - - with RTDR and RTEG

- 50/50 FORECAST

May 2, 2015 - May 29, 2015 W/B Saturday


Spring 2015 Operable Capacity Analysis(MW) 90/10 Forecast (Extreme)

120

(2,000)

(1,000)

0

1,000

2,000

3,000

2-M

ay

9-M

ay

16-M

ay

23-M

ay

Op

era

ble

Cap

acit

y M

arg

in (M

W)

May 2, 2015 - May 29, 2015 W/B Saturday

ISO-NE 2015 OPERABLE CAPACITY ANALYSIS with RTDR and RTEG

- 90/10 FORECAST

- -


Spring 2015 Operable Capacity Analysis(MW) 50/50 Forecast (Reference)

121

CSO 50/50

CSO4/15/15 13:55

JSB_April_27_CO

O 50/50 with RTDR and RTEGSCC 90/10

AVAILABLE

OPCAP MW

EXTERNAL

NODE AVAIL

CAPACITY MW

NON

COMMERCIAL

CAPACITY MW

NON-GAS

PLANNED

OUTAGES CSO

MW

GAS

GENERAT

OR

OUTAGES

CSO MW

ALLOWANCE

FOR

UNPLANNED

OUTAGES MW

GAS AT

RISK MW

NET OPCAP

SUPPLY MW

PEAK LOAD

FORECAST

MW

OPER RESERVE

REQUIREMENT

MW

NET LOAD

OBLIGATION MW

OPCAP

MARGIN

MW

OPCAP FROM

OP4 ACTIVE

REAL-TIME DR

MW

OPCAP

MARGIN w/

OP4 actions

through OP4

Step 2 MW

OPCAP FROM

OP4 REAL-

TIME EMER.

GEN MW

OPCAP MARGIN

w/ OP4 actions

through OP4

Step 6 MW

[1] [2] [3] [4] [5] [6] [7] [8] [9] [10] [11] [12] [13] [14] [15] [16]

5/2/2015 30,128 594 0 5,286 1,080 3,400 0 20,956 16,243 2,375 18,618 2,338 319 2,657 141 2,798

5/9/2015 30,128 500 0 2,935 870 3,400 0 23,423 19,945 2,375 22,320 1,103 319 1,422 141 1,563

5/16/2015 30,128 594 0 1,424 1,023 3,400 0 24,875 20,942 2,375 23,317 1,558 319 1,877 141 2,018

5/23/2015 30,128 594 0 1,413 778 3,400 0 25,131 21,868 2,375 24,243 888 319 1,207 141 1,348(2,683)

1. Available OPCAP MW based on resource Capacity Supply Obligations, CSO. Does not include Settlement Only Generators.

2. External Node Available Capacity MW based on the sum of external Capacity Supply Obligations (CSO) imports and exports.

3. New resources and generator improvements that have acquired a CSO but have not become commercial.

4.Non-Gas Planned Outages is the total of Non Gas-fired Generator/DARD Outages for the period. This value would also include any known long-term Non Gas-fired Forced Outages.

5. All Planned Gas-fired generation outage for the period. This value would also include any known long-term Gas-fired Forced Outages.

6. Allowance for Unplanned Outages includes forced outages and maintenance outages scheduled less than 14 days in advance per ISO New England Operating Procedure No. 5 Appendix A.

7. Generation at Risk due to Gas Supply pertains to gas fired capacity expected to be at risk during cold weather conditions or gas pipeline maintenance outages.

8. Net OpCap Supply MW Available (1 + 2 + 3 - 4 - 5 - 6 - 7 = 8)

9. Peak Load Forecast as provided in the 2015 CELT Report and adjusted for Passive Demand Resources. http:/ /www.iso-ne.com/system-planning/ system-plans-studies/ celt

10. Operating Reserve Requirement based on 125% of first largest contingency plus 50% of the second largest contingency.

11. Total Net Load Obligation per the formula(9 + 10 = 11)

12. Net OPCAP Margin MW = Net Op Cap Supply MW minus Net Load Obligation (8 - 11 = 12)

13. OP 4 Action 2 Real-time Demand Response based on OP4 Appendix A. Reserve Margins and Distribution Loss Factor Gross Ups are Included.

14. OPCAP Margin taking into account Real Time Demand Response through OP4 Step 2 (12 + 13 = 14)

15. OP 4 Action 6 Emergency Generation Response without the Voltage Reduction requiring > 10 Minutes based on OP4 Appendix A. Real Time Emergency Generation is capped at 600MW.

Reserve Margins and Distribution Loss Factor Gross Ups are Included.

16. OPCAP Margin taking into account Real Time Demand Response and Real Time Emergency Generation through OP4 Step 6 (14 + 15 = 16) This does not include Emergency Energy Transactions (EETs).

ISO-NE 2015 OPERABLE CAPACITY ANALYSIS

STUDY WEEK

(Week Beginning,

Saturday)

This analysis is a tabulation of weekly assessments shown in one single table. The information shows the operable capacity situation under assumed conditions for each week. It is not expected that the system peak will occur every week during June, July, and August and M id September.

May 1, 2015 - 50/50 FORECAST using CSO values


Spring 2015 Operable Capacity Analysis(MW) 90/10 Forecast (Extreme)

122

CSO 50/50

CSO4/15/15 14:08

JSB_April_27_CO


AVAILABLE

OPCAP MW

EXTERNAL

NODE AVAIL

CAPACITY MW

NON

COMMERCIAL

CAPACITY MW

NON-GAS

PLANNED

OUTAGES CSO

MW

GAS

GENERAT

OR

OUTAGES

CSO MW

ALLOWANCE

FOR

UNPLANNED

OUTAGES MW

GAS AT

RISK MW

NET OPCAP

SUPPLY MW

PEAK LOAD

FORECAST

MW

OPER RESERVE

REQUIREMENT MW

NET LOAD

OBLIGATION

MW

OPCAP

MARGIN

MW

OPCAP FROM

OP4 ACTIVE

REAL-TIME DR

MW

OPCAP

MARGIN w/

OP4 actions

through OP4

Step 2 MW

OPCAP FROM

OP4 REAL-

TIME EMER.

GEN MW

OPCAP MARGIN

w/ OP4 actions

through OP4

Step 6 MW

[1] [2] [3] [4] [5] [6] [7] [8] [9] [10] [11] [12] [13] [14] [15] [16]

5/2/2015 30,128 594 0 5,286 1,080 3,400 0 20,956 16,761 2,375 19,136 1,820 319 2,139 141 2,280

5/9/2015 30,128 500 0 2,935 870 3,400 0 23,423 21,721 2,375 24,096 (673) 319 (354) 141 (213)

5/16/2015 30,128 594 0 1,424 1,023 3,400 0 24,875 22,800 2,375 25,175 (300) 319 19 141 160

5/23/2015 30,128 594 0 1,413 778 3,400 0 25,131 23,802 2,375 26,177 (1,046) 319 (727) 141 (586)(4,173)



3. New resources that have acquired a CSO but have not become commercial.






9. Peak Load Forecast as provided in the 2015 CELT Report and adjusted for Passive Demand Resources. http://www.iso-ne.com/system-planning/system-plans-studies/celt

10. Operating Reserve Requirement based on 125% of first largest contingency plus 50% the second largest contingency.









STUDY WEEK

(Week Beginning,

Saturday)




OPERABLE CAPACITY ANALYSIS

Summer 2015


124

50/50 Load Forecast (Reference) June - 20152

CSO

June - 20152

SCC






1237 1237


Non Gas-fired Planned Outage MW (-) 0 0








Operable Capacity Margin 3 -506 244

1 Generator Operable Capacity is based on data as of April 15, 2015 and does not include Capacity associated with Settlement Only Generators, Passive and Active Demand Response, and external capacity. 2 Load based on 2015 CELT report and week with lowest Operable Capacity Margin, weeks beginning May 30, 2015. 3 Includes OP4 actions associated with RTEG and RTDR 4 Total of (Gas at Risk MW) – (Gas Gen Outages MW)

Summer 2015 Operable Capacity Analysis


125

Summer 2015 Operable Capacity Analysis 90/10 Load Forecast (Extreme) June - 20152

CSO

June - 20152

SCC






1237 1237


Non Gas-fired Planned Outage MW (-) 0 0








Operable Capacity Margin 3 -2,856 -2,106



Summer 2015 Operable Capacity Analysis(MW) 50/50 Forecast (Reference)

126

(4,000)

(3,000)

(2,000)

(1,000)

0

1,000

2,000

30-M

ay

6-J

un

13-J

un

20-J

un

27-J

un

4-J

ul

11-J

ul

18-J

ul

25-J

ul

1-A

ug

8-A

ug

15-A

ug

22-A

ug

29-A

ug

5-S

ep

12-S

ep

19-S

ep

Op

era

ble

Cap

acit

y M

arg

in (M

W)

ISO-NE 2015 OPERABLE CAPACITY ANALYSIS - - with RTDR and RTEG

- 50/50 FORECAST

May 30, 2015 - September 25, 2015 W/B Saturday


Summer 2015 Operable Capacity Analysis(MW) 90/10 Forecast (Extreme)

127

(4,000)

(3,000)

(2,000)

(1,000)

0

1,000

2,000

30-M

ay

6-J

un

13-J

un

20-J

un

27-J

un

4-J

ul

11-J

ul

18-J

ul

25-J

ul

1-A

ug

8-A

ug

15-A

ug

22-A

ug

29-A

ug

5-S

ep

12-S

ep

19-S

ep

Op

era

ble

Cap

acit

y M

arg

in (M

W)

May 30, 2015 - September 25, 2015 W/B Saturday

ISO-NE 2015 OPERABLE CAPACITY ANALYSIS with RTDR and RTEG

- 90/10 FORECAST

- -


Summer 2015 Operable Capacity Analysis(MW) 50/50 Forecast (Reference)

128

CSO 50/50

CSO4/15/15 13:55

JSB_April_27_CO


AVAILABLE

OPCAP MW

EXTERNAL

NODE AVAIL

CAPACITY MW

NON

COMMERCIAL

CAPACITY MW

NON-GAS

PLANNED

OUTAGES CSO

MW

GAS

GENERAT

OR

OUTAGES

CSO MW

ALLOWANCE

FOR

UNPLANNED

OUTAGES MW

GAS AT

RISK MW

NET OPCAP

SUPPLY MW

PEAK LOAD

FORECAST

MW

OPER RESERVE

REQUIREMENT

MW

NET LOAD

OBLIGATION MW

OPCAP

MARGIN

MW

OPCAP FROM

OP4 ACTIVE

REAL-TIME DR

MW

OPCAP

MARGIN w/

OP4 actions

through OP4

Step 2 MW

OPCAP FROM

OP4 REAL-

TIME EMER.

GEN MW

OPCAP MARGIN

w/ OP4 actions

through OP4

Step 6 MW

[1] [2] [3] [4] [5] [6] [7] [8] [9] [10] [11] [12] [13] [14] [15] [16]

5/30/2015 29,576 1,237 0 0 72 2,800 0 27,941 26,710 2,375 29,085 (1,144) 446 (698) 192 (506)

6/6/2015 29,576 1,237 0 0 0 2,800 0 28,013 26,710 2,375 29,085 (1,072) 446 (626) 192 (434)

6/13/2015 29,576 1,237 0 12 0 2,800 0 28,001 26,710 2,375 29,085 (1,084) 446 (638) 192 (446)

6/20/2015 29,576 1,237 0 12 0 2,800 0 28,001 26,710 2,375 29,085 (1,084) 446 (638) 192 (446)

6/27/2015 29,576 1,237 0 12 0 2,800 0 28,001 26,710 2,375 29,085 (1,084) 446 (638) 192 (446)

7/4/2015 29,576 1,237 0 12 0 2,100 0 28,701 26,710 2,375 29,085 (384) 446 62 192 254

7/11/2015 29,576 1,237 0 0 0 2,100 0 28,713 26,710 2,375 29,085 (372) 446 74 192 266

7/18/2015 29,576 1,237 0 0 0 2,100 0 28,713 26,710 2,375 29,085 (372) 446 74 192 266

7/25/2015 29,576 1,237 0 12 0 2,100 0 28,701 26,710 2,375 29,085 (384) 446 62 192 254

8/1/2015 29,576 1,237 0 0 0 2,100 0 28,713 26,710 2,375 29,085 (372) 446 74 192 266

8/8/2015 29,576 1,237 0 0 0 2,100 0 28,713 26,710 2,375 29,085 (372) 446 74 192 266

8/15/2015 29,576 1,237 0 12 0 2,100 0 28,701 26,710 2,375 29,085 (384) 446 62 192 254

8/22/2015 29,576 1,237 0 0 0 2,100 0 28,713 26,710 2,375 29,085 (372) 446 74 192 266

8/29/2015 29,576 1,237 6 0 0 2,100 0 28,719 26,710 2,375 29,085 (366) 446 80 192 272

9/5/2015 29,576 1,237 6 12 493 2,100 0 28,214 26,710 2,375 29,085 (871) 446 (425) 192 (233)

9/12/2015 29,576 1,237 6 1,361 802 2,100 0 26,556 23,016 2,375 25,391 1,165 446 1,611 192 1,803

9/19/2015 29,576 1,058 6 2,466 1,082 2,100 0 24,992 22,641 2,375 25,016 (24) 446 422 192 614(2,683)



3. New resources and generator improvements that have acquired a CSO but have not become commercial.






9. Peak Load Forecast as provided in the 2015 CELT Report and adjusted for Passive Demand Resources. http:/ /www.iso-ne.com/system-planning/ system-plans-studies/ celt

10. Operating Reserve Requirement based on 125% of first largest contingency plus 50% of the second largest contingency.









STUDY WEEK

(Week Beginning,

Saturday)




Summer 2015 Operable Capacity Analysis(MW) 90/10 Forecast (Extreme)

129

CSO 50/50

CSO4/15/15 14:08

JSB_April_27_CO


AVAILABLE

OPCAP MW

EXTERNAL

NODE AVAIL

CAPACITY MW

NON

COMMERCIAL

CAPACITY MW

NON-GAS

PLANNED

OUTAGES CSO

MW

GAS

GENERAT

OR

OUTAGES

CSO MW

ALLOWANCE

FOR

UNPLANNED

OUTAGES MW

GAS AT

RISK MW

NET OPCAP

SUPPLY MW

PEAK LOAD

FORECAST

MW

OPER RESERVE

REQUIREMENT MW

NET LOAD

OBLIGATION

MW

OPCAP

MARGIN

MW

OPCAP FROM

OP4 ACTIVE

REAL-TIME DR

MW

OPCAP

MARGIN w/

OP4 actions

through OP4

Step 2 MW

OPCAP FROM

OP4 REAL-

TIME EMER.

GEN MW

OPCAP MARGIN

w/ OP4 actions

through OP4

Step 6 MW

[1] [2] [3] [4] [5] [6] [7] [8] [9] [10] [11] [12] [13] [14] [15] [16]

5/30/2015 29,576 1,237 0 0 72 2,800 0 27,941 29,060 2,375 31,435 (3,494) 446 (3,048) 192 (2,856)

6/6/2015 29,576 1,237 0 0 0 2,800 0 28,013 29,060 2,375 31,435 (3,422) 446 (2,976) 192 (2,784)

6/13/2015 29,576 1,237 0 12 0 2,800 0 28,001 29,060 2,375 31,435 (3,434) 446 (2,988) 192 (2,796)

6/20/2015 29,576 1,237 0 12 0 2,800 0 28,001 29,060 2,375 31,435 (3,434) 446 (2,988) 192 (2,796)

6/27/2015 29,576 1,237 0 12 0 2,800 0 28,001 29,060 2,375 31,435 (3,434) 446 (2,988) 192 (2,796)

7/4/2015 29,576 1,237 0 12 0 2,100 0 28,701 29,060 2,375 31,435 (2,734) 446 (2,288) 192 (2,096)

7/11/2015 29,576 1,237 0 0 0 2,100 0 28,713 29,060 2,375 31,435 (2,722) 446 (2,276) 192 (2,084)

7/18/2015 29,576 1,237 0 0 0 2,100 0 28,713 29,060 2,375 31,435 (2,722) 446 (2,276) 192 (2,084)

7/25/2015 29,576 1,237 0 12 0 2,100 0 28,701 29,060 2,375 31,435 (2,734) 446 (2,288) 192 (2,096)

8/1/2015 29,576 1,237 0 0 0 2,100 0 28,713 29,060 2,375 31,435 (2,722) 446 (2,276) 192 (2,084)

8/8/2015 29,576 1,237 0 0 0 2,100 0 28,713 29,060 2,375 31,435 (2,722) 446 (2,276) 192 (2,084)

8/15/2015 29,576 1,237 0 12 0 2,100 0 28,701 29,060 2,375 31,435 (2,734) 446 (2,288) 192 (2,096)

8/22/2015 29,576 1,237 0 0 0 2,100 0 28,713 29,060 2,375 31,435 (2,722) 446 (2,276) 192 (2,084)

8/29/2015 29,576 1,237 6 0 0 2,100 0 28,719 29,060 2,375 31,435 (2,716) 446 (2,270) 192 (2,078)

9/5/2015 29,576 1,237 6 12 493 2,100 0 28,214 29,060 2,375 31,435 (3,221) 446 (2,775) 192 (2,583)

9/12/2015 29,576 1,237 6 1,361 802 2,100 0 26,556 25,060 2,375 27,435 (879) 446 (433) 192 (241)

9/19/2015 29,576 1,058 6 2,466 1,082 2,100 0 24,992 24,654 2,375 27,029 (2,037) 446 (1,591) 192 (1,399)(4,173)



3. New resources that have acquired a CSO but have not become commercial.






9. Peak Load Forecast as provided in the 2015 CELT Report and adjusted for Passive Demand Resources. http://www.iso-ne.com/system-planning/system-plans-studies/celt

10. Operating Reserve Requirement based on 125% of first largest contingency plus 50% the second largest contingency.









STUDY WEEK

(Week Beginning,

Saturday)




OPERABLE CAPACITY ANALYSIS Appendix


Possible Relief Under OP4 based on OP4 Appendix A

131

OP 4 Action

Number Page 1 of 2

Action Description

Amount Assumed Obtainable Under OP 4

(MW)

1 Implement Power Caution and advise Resources with a CSO to prepare to provide capacity and notify “Settlement Only” generators with a CSO to monitor reserve pricing to meet those obligations.

Begin to allow depletion of 30-minute reserve.

0 1

600

2 Dispatch real time Demand Resources. May 319 3

June – September 446 3

3 Voluntary Load Curtailment of Market Participants’ facilities. 40 2

4 Implement Power Watch 0

5 Schedule Emergency Energy Transactions and arrange to purchase Control Area-to-Control Area Emergency

1,000

6 Voltage Reduction requiring > 10 minutes

Dispatch real time Emergency Generation

133 4

May 141 3

June – September 192 3 NOTES: 1. Based on Summer Ratings. Assumes 25% of total MW Settlement Only units <5 MW will be available and respond. 2. The actual load relief obtained is highly dependent on circumstances surrounding the appeals, including timing and the amount of advanced

notice that can be given. 3. The RTDR and RTEG MW values are based on FCM results as of April 15, 2015. 4. The MW values are based on a 26,658 MW system load and the most recent voltage reduction test % achieved.


Possible Relief Under OP4 based on OP4 Appendix A

132

OP 4 Action

Number Page 2 of 2

Action Description Amount Assumed Obtainable

Under OP 4 (MW)

7 Request generating resources not subject to a Capacity Supply Obligation to voluntary provide energy for reliability purposes

0

8 Voltage Reduction requiring 10 minutes or less 267 4

9 Transmission Customer Generation Not Contractually Available to Market Participants during a Capacity Deficiency.

Voluntary Load Curtailment by Large Industrial and Commercial Customers.

5

200 2

10 Radio and TV Appeals for Voluntary Load Curtailment Implement Power Warning

200 2

11 Request State Governors to Reinforce Power Warning Appeals.

100 2

Total May 3,005 MW

June – September 3,183 MW NOTES: 1. Based on Summer Ratings. Assumes 25% of total MW Settlement Only units <5 MW will be available and respond. 2. The actual load relief obtained is highly dependent on circumstances surrounding the appeals, including timing and the amount of advanced

notice that can be given. 3. The RTDR and RTEG MW values are based on FCM results as of April 15, 2015. 4. The MW values are based on a 26,658 MW system load and the most recent voltage reduction test % achieved.



ATTACHMENT 5.C-4Additional Materials Circulated Apr 29, 2015

UI AMENDMENT (REVISED)

III.13.2.3.3. Step 3: Determination of the Outcome of Each Round.

The auctioneer shall use the offers and bids for the round as described in Section III.13.2.3.2 to determine

the aggregate supply curves for the New England Control Area and for each modeled Capacity Zone

included in the round. The aggregate supply curve for the New England Control Area (the “Total System

Capacity”) shall reflect at each price the sum of (the amount of capacity offered in all Capacity Zones

modeled as import-constrained Capacity Zones at that price (excluding capacity offered from New Import

Capacity Resources and Existing Import Capacity Resources)) plus (the amount of capacity offered in the

Rest-of-Pool Capacity Zone at that price (excluding capacity offered from New Import Capacity

Resources and Existing Import Capacity Resources)) plus (for each Capacity Zone modeled as an export-

constrained Capacity Zone, the lesser of the amount of capacity offered in the Capacity Zone at that price

(excluding capacity offered from New Import Capacity Resources and Existing Import Capacity

Resources) or the Capacity Zone’s Maximum Capacity Limit) plus (for each interface between the New

England Control Area and an external Control Area, the lesser of that interface’s approved capacity

transfer limit (net of tie benefits) or the amount of capacity offered from New Import Capacity Resources

and Existing Import Capacity Resources). In computing the Total System Capacity, capacity associated

with any New Capacity Offer at any price greater than the Forward Capacity Auction Starting Price will

not be included in the tally of total capacity at the Forward Capacity Auction Starting Price for that

Capacity Zone. In no event shall the Capacity Clearing Price for a Capacity Zone be greater than the

Forward Capacity Auction Starting Price for that Capacity Zone. On the basis of these aggregate supply

curves, the auctioneer shall determine the outcome of the round for each modeled Capacity Zone as

follows:

(a) Import-Constrained Capacity Zones.

For a Capacity Zone modeled as an import-constrained Capacity Zone, if either of the following two

conditions is met during the round:

(1) the aggregate supply curve for the import-constrained Capacity Zone, adjusted as

necessary in accordance with Section III.13.2.6 (Capacity Rationing Rule), equals or is less than

the Capacity Zone’s Local Sourcing Requirement; or




-2-.

(2) the Total System Capacity, adjusted as necessary in accordance with Section III.13.2.6

(Capacity Rationing Rule), equals or is less than the amount of capacity determined by the

System-Wide Capacity Demand Curve;

then the Forward Capacity Auction for that Capacity Zone is concluded and such Capacity Zone

will not be included in further rounds of the Forward Capacity Auction. The Capacity Clearing

Price for that Capacity Zone shall be set at the highest price at which either of the two conditions

above are satisfied, subject to the other provisions of this Section III.13.2. If neither of the two

conditions above are met in the round, then the auctioneer shall publish the quantity of system-

wide excess supply at the End-of-Round Price (the amount of capacity offered at the End-of-

Round Price in all modeled Capacity Zones minus the amount of capacity determined by the

System-Wide Capacity Demand Curve at the End-of-Round Price) and the quantity of capacity

from Demand Resources by type at the End-of-Round Price, and that Capacity Zone will be

included in the next round of the Forward Capacity Auction. Notwithstanding any other provision

of Section III.13, the auctioneer shall not publish the quantity of system-wide excess supply at the

End-of-Round Price at the end of the round prior to the round in which the Dynamic De-List Bid

Threshold is equal to either the Start-of-Round Price or End-of-Round Price, or in between the

Start-of-Round Price and End-of-Round Price, and for any subsequent rounds.

(b) Rest-of-Pool Capacity Zone. For the Rest-of-Pool Capacity Zone, if the Total System Capacity

adjusted as necessary in accordance with Section III.13.2.6 (Capacity Rationing Rule), equals or is less

than the amount of capacity determined by the System-Wide Capacity Demand Curve, then the Forward

Capacity Auction for the Rest-of-Pool Capacity Zone is concluded and the Rest-of-Pool Capacity Zone

will not be included in further rounds of the Forward Capacity Auction. The Capacity Clearing Price for

the Rest-of-Pool Capacity Zone shall be set at the highest price at which the Total System Capacity is less

than or equal to the amount of capacity determined by the System-Wide Capacity Demand Curve, subject

to the other provisions of this Section III.13.2. If the Total System Capacity exceeds the amount of

capacity determined by the System-Wide Capacity Demand Curve at the End-of-Round Price, then the

auctioneer shall publish the quantity of system-wide excess supply at the End-of-Round Price (the amount

of capacity offered at the End-of-Round Price in all modeled Capacity Zones minus the amount of

capacity determined by the System-Wide Capacity Demand Curve at the End-of-Round Price) and the

quantity of capacity from Demand Resources by type at the End-of-Round Price, and the Rest-of-Pool

Capacity Zone will be included in the next round of the Forward Capacity Auction. Notwithstanding any

other provision of Section III.13, the auctioneer shall not publish the quantity of system-wide excess




-3-.

supply at the End-of-Round Price at the end of the round prior to the round in which the Dynamic De-List

Bid Threshold is equal to either the Start-of-Round Price or End-of-Round Price, or in between the Start-

of-Round Price and End-of-Round Price, and for any subsequent rounds.

(c) Export-Constrained Capacity Zones. For a Capacity Zone modeled as an export-constrained

Capacity Zone, if both of the following two conditions are met during the round:

(i) the aggregate supply curve for the export-constrained Capacity Zone, adjusted as

necessary in accordance with Section III.13.2.6 (Capacity Rationing Rule), is equal to or below

the Capacity Zone’s Maximum Capacity Limit; and

(ii) the Total System Capacity, adjusted as necessary in accordance with Section III.13.2.6

(Capacity Rationing Rule), equals or is less than the amount of capacity determined by the

System-Wide Capacity Demand Curve;

then the Forward Capacity Auction for that Capacity Zone is concluded and such Capacity Zone

will not be included in further rounds of the Forward Capacity Auction. The Capacity Clearing

Price for that Capacity Zone shall be set at the highest price at which both of the conditions above

are satisfied, subject to the other provisions of this Section III.13.2. If it is not the case that both

of the two conditions above are satisfied in the round, then the auctioneer shall publish the

quantity of system-wide excess supply at the End-of-Round Price (the amount of capacity offered

at the End-of-Round Price in all modeled Capacity Zones minus the amount of capacity

determined by the System-Wide Capacity Demand Curve) and the quantity of excess supply in

the export-constrained Capacity Zone (the amount of capacity offered at the End-of-Round Price

in the export-constrained Capacity Zone minus the Maximum Capacity Limit of the export-

constrained Capacity Zone) and the quantity of capacity from Demand Resource`s by type at the

End-of-Round Price, and that Capacity Zone will be included in the next round of the Forward

Capacity Auction. Notwithstanding any other provision of Section III.13, the auctioneer shall not

publish the quantity of system-wide excess supply or the quantity of excess supply in the export-

constrained Capacity Zone at the End-of-Round Price at the end of the round prior to the round in

which the Dynamic De-List Bid Threshold is equal to either the Start-of-Round Price or End-of-

Round Price, or in between the Start-of-Round Price and End-of-Round Price, and for any

subsequent rounds.




-4-.

(d) Treatment of Import Capacity. Where the amount of capacity offered from New Import

Capacity Resources and Existing Import Capacity Resources over an interface between the New England

Control Area and an external Control Area is less than or equal to that interface’s approved capacity

transfer limit (net of tie benefits, or net of HQICC in the case of the Phase I/II HVDC-TF), then the

capacity offers from those resources shall be treated as capacity offers in the modeled Capacity Zone

associated with that interface. Where the amount of capacity offered from New Import Capacity

Resources and Existing Import Capacity Resources over an interface between the New England Control

Area and an external Control Area is greater than that interface’s approved capacity transfer limit (net of

tie benefits, or net of HQICC in the case of the Phase I/II HVDC-TF), then the following provisions shall

apply (separately for each such interface):

(i) For purposes of determining which capacity offers from the New Import Capacity

Resources and Existing Import Capacity Resources over the interface shall clear and at what

price, the offers over the interface shall be treated in the descending-clock auction as if they

comprised a separately-modeled export-constrained capacity zone, with an aggregate supply

curve consisting of the offers from the New Import Capacity Resources and Existing Import

Capacity Resources over the interface.

(ii) The amount of capacity offered over the interface that will be included in the aggregate

supply curve of the modeled Capacity Zone associated with the interface shall be the lesser of the

following two quantities: the amount of capacity offered from New Import Capacity Resources

and Existing Import Capacity Resources over the interface; and the interface’s approved capacity

transfer limit (net of tie benefits, or net of HQICC in the case of the Phase I/II HVDC-TF).

(iii) The Forward Capacity Auction for New Import Capacity Resources and Existing Import

Capacity Resources over the interface is concluded when the following two conditions are both

satisfied: the amount of capacity offered from New Import Capacity Resource and Existing

Import Capacity Resources over the interface is less than or equal to the interface’s approved

capacity transfer limit (net of tie benefits, or net of HQICC in the case of the Phase I/II HVDC-

TF); and the Forward Capacity Auction is concluded in the modeled Capacity Zone associated

with the interface.




-5-.

(e) Treatment of Export Capacity. Any Export Bid or any Administrative Export De-List Bid that

is used to export capacity through an export interface connected to an import-constrained Capacity Zone

from another Capacity Zone, or through an export interface connected to the Rest-of-Pool Capacity Zone

from an export-constrained Capacity Zone in the Forward Capacity Auction will be modeled in the

Capacity Zone where the export interface that is identified in the Existing Capacity Qualification Package

is located. The Export Bid or Administrative Export De-List Bid clears against the Capacity Clearing

Price in the Capacity Zone where the Export Bid or Administrative Export De-List Bid is modeled.

(i) Then the MW quantity equal to the relevant Export Bid or Administrative Export De-List

Bid from the resource associated with the Export Bid or Administrative Export De-List Bid will

be de-listed in the Capacity Zone where the resource is located. If the export interface is

connected to an import-constrained Capacity Zone, the MW quantity procured will be in addition

to the Local Sourcing Requirement of the import-constrained Capacity Zone.

(ii) If the Export Bid or Administrative Export De-List Bid does not clear, then the resource

associated with the Export Bid or Administrative Export De-List Bid will not be de-listed in the

Capacity Zone where the resource is located.

(f) Treatment of Real-Time Emergency Generation Resources. In determining when the Forward

Capacity Auction is concluded, no more than 600 MW of capacity from Real-Time Emergency

Generation Resources shall be counted towards meeting the cleared amount of capacity determined by the

System-Wide Capacity Demand Curve. If the sum of the Capacity Supply Obligations of Real-Time

Emergency Generation Resources exceeds 600 MW, the Capacity Clearing Price, or in the case of

Inadequate Supply or Insufficient Competition, the payment as described in Section III.13.2.8, (as

adjusted pursuant to Section III.13.2.7.3(b)) paid to all Real-Time Emergency Generation Resources shall

be adjusted by the ratio of 600 MW divided by the total of the final Capacity Supply Obligations of Real-

Time Emergency Generation Resources. The acceptance of a Real-Time Emergency Generation

Resource Static De-list Bid, Dynamic De-list Bid, or Permanent De-list Bid shall be based on the

effective Capacity Clearing Price as described in Section III.13.2.7.

April 29, 2015 Report NEPOOL PARTICIPANTS COMMITTEEMAY 1, 2015 MEETING, AGENDA ITEM #9

Page ES-141536280.150

EXECUTIVE SUMMARYStatus Report of Current Regulatory and Legal Proceedings

as of April 29, 2015

The following activity, as more fully described in the attached litigation report, has occurred since the reportdated April 9, 2015 was circulated. New matters/proceedings since the last Report are preceded by an asterisk ‘*’.Page numbers precede the matter description.

I. Complaints

1 NRG Canal 2 2015/16 ARA3Complaint/Waiver Req. (EL15-57)

Apr 16-29 NEPOOL, Calpine, ConEd, Entergy, NESCOE intervene

4 Base ROE Complaints (2012 &2014) Consolidated(EL14-86 & EL13-33)

Apr 21 TOs submit cross-answering testimony; Complainant-Aligned Partiesnotice May 8 deposition of W. Avera

6 NESCOE FCM RenewablesExemption Complaint (EL13-34)

Apr 20 FERC denies rehearing of its Feb 12, 2013 order denying NESCOE’sFCM Renewable Exemption Complaint

7 Base ROE Complaint (2011)(EL11-66)

Apr 10 FERC grants an extension of time to complete refunds and refundreports - to Nov 2, 2015, for local refunds and to Dec 31, 2015, for afinal refund report

II. Rate, ICR, FCA, Cost Recovery Filings

8 FCA-10 Capacity Zone Boundaries(ER15-1462)

Apr 13-28

Apr 21Apr 27

Champlain VT, ConEd, Dynegy, Emera, Entergy, Eversource, Exelon,Footprint, GDF Suez, MMWEC, NESCOE, NHEC, SunEdison, VersointerveneNEPOOL submits commentsCalpine comments; Dominion, NEPGA, New England Suppliers,NRG, PSEG file protests

8 Opinion 531-A Compliance Filing:TOs (ER15-414)

Apr 22 TOs submit amended Opinion 531-A compliance filing;comment date May 13

9 FCA9 Results Filing (ER15-1137) Apr 13Apr 13Apr 28

CPV Towantic, NEPGA, interveneUWUA Local 464 files protestNEPGA answers UWUA Local 464 protest

* 10 ISO Securities: Authorization forFuture Drawdowns (ES15-15)

Apr 15 ISO requests continued authorization for drawdowns under previouslyauthorized Revolving Credit Line and Payment Default ShortfallFund; comment date May 6

* 10 2014/2015 Power Year TransmissionRate Filing (ER09-1532; RT04-2)

Apr 28 Public Representatives protest in part PTO AC Jul 31, 2014informational filing (inclusion of planning costs for NHT’s proposed“SeaLink” project)

III. Market Rule and Information Policy Changes, Interpretations and Waiver Requests

* 10 DNE Dispatch Changes(ER15-1509)

Apr 15

Apr 16Apr 23-29

ISO and NEPOOL jointly file changes to provide for the dispatch ofcertain wind and hydro Intermittent Power Resources using Do NotExceed (DNE) Dispatch Points; comment date May 7ISO corrects eTariff sheet errorsDominion, Entergy, Exelon, NESCOE intervene

11 eTariff Corrections(ER15-1455)

Apr 22-23 Exelon, NEPOOL intervene

11 LMP Calculator Replacement(ER15-1238)

Apr 17 FERC accepts changes, effective May 27

11 PER Mechanism Elimination (FCA-10) (ER15-1184)

Apr 13 NEPOOL responds to the Mar 27 pleadings of NEPGA and GDF Suez


Page ES-241536280.150

11 Winter 2014/15 Reliability Program(ER14-2407)

Apr 17 FERC grants rehearing of its Jan 20 Winter Reliability ProgramClarification Order

13 FCM Redesign Compliance Filing:FCA8 Revisions (ER12-953 et al.)

Apr 20 FERC denies Mar 15, 2013 requests for rehearing of the FCA8Revisions Order

IV. OATT Amendments / TOAs / Coordination Agreements

14 ETU Rule Changes(ER15-1050, -1051)

Apr 14 FERC accepts changes, effective Feb 16, 2015, and rejects ChamplainVT’s protest regarding transition period

14 Order 676-H Compliance: PTOs,SSPs, CSC et al. (ER15-517)

Apr 14 Filing Parties supplement Dec 1 compliance filing with request forwaiver of NITS and SAMTS WEQ Standards; comment date May 5

16 Order 1000 Compliance Filing(ER13-193; ER13-196)

Apr 20

Apr 29

ISO-NE requests expedited clarification, and/or re-hearing of 2 aspectsof FERC’s Mar 19 Order 1000 Compliance Rehearing OrderLSP Transmission opposes ISO-NE’s Apr 20 motion

V. Financial Assurance/Billing Policy Amendments

* 17 Deposit Account Changes(ER15-1493)

Apr 10Apr 22

ISO-NE and NEPOOL jointly file changes; comment date May 1Exelon intervenes

VI. Schedule 20/21/22/23 Changes

18 Schedule 20A-EM and 21-EM(ER15-1434)

Apr 22 Eversource intervenes

VII. NEPOOL Agreement/Participants Agreement Amendments

No Activity to Report

VIII. Regional Reports

* 19 LFTR Implementation: 26th QuarterlyStatus Report (ER07-476)

Apr 15 ISO files its 26th quarterly report

* 19 ISO-NE FERC Form 1 Apr 13 ISO submits 2014 annual report of Major Electric Utilities, Licenseesand Others

* 19 ISO-NE FERC Form 582 Apr 15 ISO submits annual report of total MWh of transmission service

IX. Membership Filings

20 Suspension Notice (not docketed) Apr 15Apr 16

Demansys suspended from New England MarketsISO files notice of suspension

X. Misc. - ERO Rules, Filings; Reliability Standards

22 NOPR: Revised Reliability Standard:PRC-005-4 (RM15-9)

Apr 16 FERC issues NOPR; comment date Jun 22

23 NOPR: Revised Reliability Standard:PRC-002-2 (RM15-4)

Apr 16 FERC issues NOPR; comment date Jun 22

24 Order 808: Revised ReliabilityStandard: COM-001-2 and COM-002-4 (RM14-13)

Apr 16 FERC approves COM changes; directs modification to COM-001-2that addresses internal communications capabilities that could involvethe issuance or receipt of Operating Instructions or othercommunications that could have an impact on reliability

24 Order 810: Revised ReliabilityStandard: BAL-001-2 (RM14-10)

Apr 16 FERC approves BAL-001 Changes, effective Jun 1, 2016; directsinformational filing and changes to definition of ACE Reporting


Page ES-341536280.150

XI. Misc. - of Regional Interest

* 26 203 Application: CSC/AIA Energy(EC15-122)

Apr 15 CSC and AIA Energy request authorization of a transaction that willmake CSC an indirect, wholly-owned subsidiary of AIA Energy;comment date May 6

* 26 Riggs v. RI PUC: Deepwater WindFPA/PURPA/Supremacy ClauseComplaint (EL15-61)

Apr 21 Riggs files complaint alleging RI PUC approval of 20-year PPAviolates the FPA and US Constitution’s Supremacy Clause;comment date May 12

* 27 IAs – CMP/Brookfield/FPL Energy(ER15-1553 et al.)

Apr 22 CMP files four, non-conforming IAs to replace a single ContinuingSite/Interconnection Agreement (also to be cancelled);comment date May 13

* 28 Termination of Braintree Participationin REMVEC II Agreement(ER15-1530)

Apr 17 National Grid files materials supporting termination;comment date May 8

* 28 CL&P Amended WholesaleDistribution Service Agreementwith CMEEC (ER15-1525)

Apr 17 NU, on CL&P’s behalf, files amended agreement;comment date May 8

28 EPC Agreement: Blue Sky West &Emera Maine (ER15-1459)

Apr 24 SunEdison intervenes

28 Emera MPD OATT Changes(ER15-1429)

Apr 22Apr 29

MPUC and Maine Customer Group file protestsEmera Maine replies to protests

29 Emera Maine Order 676-HCompliance Filing (ER15-1419)

Apr 28 Emera Maine amends filing to withdraw its request for waiver ofNAESB business practice standard WEQ-012

29 NSTAR/HQ US CMEEC Use RightsTransfer Agreement (ER15-1383)

Apr 16 CMEEC requests that effective date of Agreement be set atMar 26, 2015

29 Opinion 531-A Compliance Filing:NGrid IFA Amendments(ER15-418)

Apr 16 FERC rejects compliance filing

30 FERC Enforcement Action: CityPower Marketing and Tsingas(IN15-5)

Apr 20Apr 21Apr 23

Enforcement requests revised briefing scheduleFERC denies Enforcements Apr 20 requestCity Power Respondents respond to PJM’s Apr 1 comments

30 FERC Enforcement Action: MaximPower and K. Mitton (IN15-4)

Apr 14 Maxim Respondents supplement their Apr 6 reply to Enforcement’sMar 23 answer

31 FERC Enforcement Action:Powhatan Energy, HEEP Fund, CUFund, and Chen (IN15-3)

Apr 14Apr 23

Powhatan Respondents answer PJM’s commentsPowhatan Respondents highlight authority in ONEOK case they asserthas relevance to this proceeding

XII. Misc. - Administrative & Rulemaking Proceedings

32 Technical Conferences onImplications of EnvironmentalRegulations (AD15-4)

Apr 10-27

Apr 21

America’s Natural Gas Alliance, AEP, Southern Company submitcommentsNERC submits chapter from report entitled “Potential ReliabilityImpacts of EPA’s Proposed Clean Power Plan – Phase 1”

34 RTO/ISO Winter 2013/14 Operationsand Market Performance (AD14-8)

Apr 21 Organization of MISO States submits comments regarding fuelassurance activities being undertaken by regulatory commissions in theMISO footprint

34 NOPR: Third-Party Provision ofPrimary Frequency ResponseService (RM15-2)

Apr 17-27 Nearly 20 parties file comments

35 Order 807: Open Access and PriorityRights on ICIF (RM14-11)

Apr 20 APPA/TAPS and NRECA request rehearing or Order 807


Page ES-441536280.150

37 Order 676-H: Incorporation of WEQVersion 003 Standards (RM05-5)

Apr 16 FERC grants clarification in part, but otherwise denies EEI and NYISOrequests for rehearing and/or clarification of Order 676-H

XIII. Natural Gas Proceedings

38 Order 809: Coordination of theScheduling Processes of InterstateNatural Gas Pipelines and PublicUtilities (RM14-2)

Apr 16 FERC issues Final Rule, effective Jul 8, 2015;compliance filings due Jul 23, 2015

XIV. State Proceedings & Federal Legislative Proceedings


XV. Federal Courts

41 FCM Administrative Pricing RulesComplaint (15-1071**)

Apr 23

Apr 24

NEPGA files Docketing Statement, Statement of Issues, andAppearances; NEPGA requests case be held in abeyance pending aFERC order on rehearing in EL15-23NEPOOL, CT PURA, CT OCC, PSEG intervene

41 Demand Curve Changes(15-1070**)

Apr 21-27 NEPOOL, the ISO, CT PURA, NESCOE intervene

41 FCA8 Results(ER14-1244 (consol.))

Apr 10 Court orders joint proposal for briefing format to be filed by May 11

42 2013/14 Winter Reliability Program(14-1104, 14-1105, 14-1103(consol.))

Apr 15 Final Briefs filed

42 Orders 773 and 773-A(2nd Cir., 13-2316)

Apr 22 2nd Circuit denies petitions for review, concluding proceeding

42 FERC v. EPSA (Orders 745, 745-A)(Supreme Court, 14-840)

Apr 24 Case goes to conference without resolution; case scheduled to go toconference on May 1

* 46 ONEOK, Inc. v. Learjet, Inc.(Supreme Court, 13-271)

Apr 21 Court rules that the Natural Gas Act did not field pre-empt state lawantitrust lawsuits filed against the interstate gas sellers, allowingpurchasers who bought natural gas directly from the gas sellers at retailto maintain their state antitrust suits that claim that the lattermanipulated gas indices used to help set natural gas retail and FERC-regulated wholesale prices


Page 141536280.150

M E M O R A N D U M

TO: NEPOOL Participants Committee Member and Alternates

FROM: Patrick M. Gerity, NEPOOL Counsel

DATE: April 29, 2015

RE: Status Report on Current Regional Wholesale Power and Transmission Arrangements PendingBefore the Regulators, Legislatures, and Courts

We have summarized below the status of key ongoing proceedings relating to NEPOOL mattersbefore the Federal Energy Regulatory Commission (“FERC”), state regulatory commissions, and the FederalCourts and legislatures through April 29, 2015. If you have questions, please contact us.1

I. Complaints

• NRG Canal 2 2015/16 ARA3 Complaint/Waiver Request (EL15-57)

On April 6, 2015, GenOn Energy Management filed an emergency complaint and, alternatively, awaiver request, related to the third annual reconfiguration auction (“ARA”) for the 2015/16 CapacityCommitment Period (“2015/16 ARA3”). Specifically, GenOn requested in its emergency complaint that theFERC find that the ISO violated the Tariff in conducting the 2015/16 ARA by submitting a demand bid intothe March 2015 ARA as if Unit 2 at the Canal Generating Plant (“NRG Canal 2”) was still de-rated (303MW), rather than treating Canal 2 at its full capability (577 MW). Alternatively, should the FERC find thatthe ISO acted in accordance with the Tariff, GenOn requested waiver of all necessary Tariff provisions topermit the ISO to recalculate the results of the 2015/16 ARA3 to reflect NRG Canal 2’s full capability.GenOn requested that the FERC act on this filing on or before May 25, 2015. Comments on, and anyresponses to, this Complaint are due on or before May 6, 2015. Thus far, doc-less interventions were filed byNEPOOL, Calpine, ConEd, Entergy, and NESCOE. If you have any questions concerning this matter, pleasecontact Dave Doot (860-275-0102; [email protected]) or Sebastian Lombardi (860-275-0663;[email protected]).

• NEPGA Peak Energy Rent (PER) Complaint (EL15-25)

Rehearing remains pending of the FERC’s January 30 order denying NEPGA’s PER Complaint.2 Aspreviously reported, the PER Complaint Order found that NEPGA had failed to meet its burden under section206 of the Federal Power Act to demonstrate that the existing ISO Tariff provisions were unjust andunreasonable.3 On March 2, NEPGA and Entergy challenged the PER Complaint Order. NEPGA argued theFERC should “reverse its finding … that NEPGA did not satisfy its Section 206 burden in the Complaint withrespect to the relief sought for Capacity Commitment Periods 5 through 8” and “clarify that the [FERC], notthe complainant, carries the burden under Section 206 of establishing a just and reasonable “replacement”rate”. If rehearing is denied, NEPGA asked the FERC to clarify that it “did not intend to prejudge any future

1 Capitalized terms used but not defined in this filing are intended to have the meanings given to such terms in theSecond Restated New England Power Pool Agreement (the “Second Restated NEPOOL Agreement”), the ParticipantsAgreement, or the ISO New England Inc. (“ISO” or “ISO-NE”) Transmission, Markets and Services Tariff (the “Tariff”).

2 New England Power Generators Assoc., Inc. v. ISO New England Inc., 150 FERC ¶ 61,053 (Jan. 30, 2015) (“PERComplaint Order”), reh’g requested.

3 NEPGA’s Dec. 3, 2014 complaint requested that the ISO be directed (i) to increase the daily PER Strike Price by$250/MWh for Capacity Commitment Periods 5 through 8, and (ii) to eliminate the PER Adjustment for FCA9 and beyond,or, alternatively, to continue the $250 per MWh increase in the PER Strike Price for FCA9. The changes proposed in theComplaint were considered but not supported by the Participants Committee at its Oct. 3, 2014 meeting.


Page 241536280.150

proceeding on the PER Adjustment issue by establishing a required evidentiary standard” in the PERComplaint Order. In its request, Entergy, adopting and incorporating NEPGA’s request, provided additionalbases to support its request for rehearing of the PER Complaint Order. Entergy challenged further theFERC’s reliance on (i) the ISO’s assessment of the PER adjustment’s reliability impacts and, with respect toCapacity Commitment Periods 5-8, (ii) the stakeholder process considering changes to the PER rules. OnApril 1, 2015, the FERC issued a tolling order affording it additional time to consider NEPGA’s andEntergy’s rehearing requests, which remain pending before the FERC. If you have any questions concerningthis matter, please contact Joe Fagan (202-218-3901; [email protected]) or Sebastian Lombardi (860-275-0663; [email protected]).

• New Entry Pricing Rule Complaint (EL15-23)

Exelon and Calpine’s request for rehearing of the FERC’s January 30 order denying the New EntryPricing Rule Complaint4 remains pending. As previously reported, the New Entry Pricing Rule ComplaintOrder found that Exelon and Calpine had failed to show that the existing pricing rules governing lock-incapacity result in unjust, unreasonable or unduly discriminatory price suppression. In their rehearingrequest, Exelon and Calpine assert, among other things, that the New Entry Pricing Rule Complaint Order(i) did not provide a reasoned basis for finding that there is no artificial price suppression in post-entryFCAs; (ii) did not address Exelon/Calpine’s arguments regarding artificial price suppression in the entryFCA; and (iii) ignored arguments regarding the undue discrimination that results from the current MarketRules. On April 1, 2015, the FERC issued a tolling order affording it additional time to consider Exelon’sand Calpine’s rehearing request, which remains pending before the FERC. If you have any questionsconcerning this matter, please contact Dave Doot (860-275-0102; [email protected]) or SebastianLombardi (860-275-0663; [email protected]).

• NEPGA DR Capacity Complaint (EL15-21)

NEPGA’s November 14, 2014 complaint remains pending before the FERC. As previously reported,the complaint requests that (i) Demand Response (“DR”) Capacity Resources be disqualified from FCA9 and(ii) the Tariff be revised to exclude DR from FCM participation going forward (as a result of EPSA v. FERC).Interventions were filed by AEP, Brookfield, Calpine, ConEd, CSG, Direct, Dominion, EEI, ELCON, Emera,EnergyConnect, EnerNOC, Entergy, Exelon, FirstEnergy, Maryland Public Service Commission (“MDPSC”), NextEra, NRG, PPL, and Wal-Mart stores. NEPOOL filed comments on November 26 asking theFERC to reject the NEPGA Complaint without prejudice to a complaint being resubmitted if and asappropriate following consideration of specifically-proposed changes to the Tariff within the ParticipantProcesses. NU and UI jointly protested the complaint on December 3, requesting that the FERC eitherdismiss or hold the Complaint in abeyance. The ISO answered the Complaint on December 4. Also onDecember 4, Advanced Energy Management Alliance, NESCOE, Conn/RI,5 Enerwise, EnvironmentalAdvocates,6 NGrid, Public Systems; and the Sustainable FERC Project opposed the Complaint; EPSA andPSEG supported the Complaint; Genbright submitted comments. On December 15, CT PURA moved tolodge the December 15 DC Circuit Court order extending the stay of the mandate in EPSA v. FERC. OnDecember 19, NEPGA answered the ISO response and the other pleadings submitted in response to itsComplaint. On January 7, just as they had on December 23 in the FirstEnergy Complaint (see Section XI

4 The FERC stated that much of the complainants’ argument rested on the assertion that ISO-NE’s lock-in resourcerequirements differ from PJM’s. The FERC acknowledged that ISO-NE’s and PJM’s differing mechanics may yield differentprices paid to existing resources, but the FERC was not persuaded that the difference itself renders ISO-NE’s rules unjust andunreasonable. Exelon Corp. and Calpine Corp. v. ISO New England Inc., 150 FERC ¶ 61,067 at P 35 (Jan. 30, 2015) (“NewEntry Pricing Rule Complaint Order”), reh’g requested.

5 “Conn/RI” is the Connecticut Public Utilities Regulatory Authority (“CT PURA”), George Jepsen, Att’y Gen. forthe State of Conn. (“CT AG”), the Conn. Department of Energy and Environmental Protection (“CT DEEP”), the Conn.Office of Consumer Counsel (“CT OCC”), and the Rhode Island Div. of Public Utilities and Carriers (“RI PUC”).

6 Environmental Advocates are the Sustainable FERC Project, Sierra Club, Environmental Defense Fund, andAcadia Center.


Page 341536280.150

below), Environmental Advocates moved to lodge the US Solicitor General’s application for an extension oftime in which to file a petition for writ of certiorari, the Supreme Court Clerk’s notice to the DC Circuit thatthe extension had been granted, and the DC Circuit’s order extending the stay of its mandate pending theSupreme Court’s final disposition of the writ of certiorari. As noted, this matter remains pending before theFERC. If you have any questions concerning these matters, please contact Dave Doot (860-275-0102;[email protected]) or Sebastian Lombardi (860-275-0663; [email protected]).

• 206 Proceeding: Importers’ FCA Offers Review/Mitigation (EL14-99; ER15-117)

As previously reported, the FERC initiated this proceeding, on September 16, 2014, pursuant toSection 206 of the Federal Power Act (“FPA”). The FERC directed the ISO to either revise its Tariff toprovide for the review and potential mitigation of importers’ offers prior to each annual Forward CapacityAuction (“FCA”) or show cause why it should not be required to do so.7 The FERC directed the ISO tosubmit those Tariff revisions or support for why Tariff revisions should not be required on or before October16, 2014. September 24, 2014 is the refund effective date.8 On October 16, Public Citizen requested that theFERC expand this proceeding (i) to determine whether the rates produced by FCA8 are just and reasonableand if not, to fix the just and reasonable rates to be charged; and (ii) to include in this proceeding “stakeholderreform and transparency”.

ISO Response to Show Cause Order (ER15-117): On December 15, 2014, the FERC conditionallyaccepted, subject to two additional compliance filings, the ISO’s October 16 Tariff revisions in response tothe Show Cause Order that provided for the review and potential mitigation of importers’ supply offers priorto each annual FCA, which the FERC found “a significant step toward decreasing the opportunity forimporters to exercise market power.”9 The first compliance filing was due on or before January 14, 2015 andneeded to correct an incorrect cross-reference in Section III.13.1.3.5.7 (Qualification DeterminationNotification for New Import Capacity Resources).10 In the second compliance filing, due on or before April1, 2015, ISO-NE must submit tariff revisions in time for implementation for FCA-10 “which allow importersto submit up to five price-quantity pairs, together with any necessary mitigation provisions to address theexercise of market power” (finding implementation for FCA9 not feasible).11 All remaining requests andprotests, including those of Public Citizen, were rejected. Public Citizen requested rehearing of the ImportsMitigation Order on January 14, 2015 (ER15-117-003). On January 26, NEPGA answered Public Citizen’srequest. On February 12, 2015, the FERC issued a tolling order affording it additional time to consider PublicCitizen’s rehearing request, which remains pending before the FERC.

Compliance Filing I (ER15-117-001): On January 14, the ISO submitted the first compliance filingwhich, as directed, corrected the cross-reference in Section III.13.1.3.5.7 (Qualification DeterminationNotification for New Import Capacity Resources). Comments on that filing were due on or before February4; none were filed. Compliance Filing I is pending before the FERC.

Compliance Filing II (ER15-117-004): On April 1, the ISO and NEPOOL submitted Market Rulechanges, in response to the FERC’s directive in the Imports Mitigation Order, to allow New Import CapacityResources to submit up to five price-quantity pairs as part of their FCA offer information. The changes wereunanimously supported by the Participants Committee at its March 6 meeting (Consent Agenda item no. 2).Comments on Compliance Filing II were due on or before April 22; none were filed. Compliance Filing II isalso pending before the FERC.

7 ISO New England Inc., 148 FERC ¶ 61,201 (Sep. 16, 2014) (“September 16 Order”).

8 The Sep. 17 notice of this proceeding was published in the Fed. Reg. on Sep. 24, 2014 (Vol. 79, No. 185) p.57,075.

9 ISO New England Inc., 149 FERC ¶ 61,227 (Dec. 15, 2014) (“Imports Mitigation Order”), reh’g requested.

10 Id. at P 53.

11 Id. at PP 41-45, 64.


Page 441536280.150

If you have any questions concerning these matters, please contact Dave Doot (860-275-0102;[email protected]), Pat Gerity (860-275-0533; [email protected]), or Sebastian Lombardi (860-275-0663; [email protected]).

• Base ROE Complaints (2012 and 2014) Consolidated (EL13-33 and EL14-86)

As previously reported, the FERC issued an order on November 24, 2014, establishing a trial-type,evidentiary hearing, consolidating EL14-8612 with EL13-33,13 and setting a refund effective date for EL14-86of July 31, 2014.14 The FERC found that the Complaint in EL14-86 “raises issues of material fact that cannotbe resolved based upon the record before us and that are more appropriately addressed in the hearing ordered… [b]ecause of the existence of common issues of law and fact, we will consolidate this proceeding with theproceeding in Docket No. EL13-33-000 for purposes of hearing and decision.” In addition, the FERCindicated that “it is appropriate for the parties to litigate a separate ROE for each refund period.”15 The TOsrequested rehearing of the November 24 order on December 24. On January 23, 2015, the FERC issued atolling order affording it additional time to consider the TOs’ rehearing request, which remains pendingbefore the FERC.

Base ROE Complaint (2012) (EL13-33). In response to a December 2012 Complaint byEnvironment Northeast (now known as Acadia Center,“ENE”), Greater Boston Real Estate Board, NationalConsumer Law Center, and the NEPOOL Industrial Customer Coalition (“NICC”, and together, the “2012Complainants”), the FERC, on June 19, 2014, established hearing and settlement judge procedures.16 The2012 Base ROE Complaint challenged the TOs’ 11.14% return on equity (“Base ROE”), and sought areduction of the Base ROE to 8.7%. In the 2012 Base ROE Initial Order, the FERC found that the Complaint“raises issues of material fact that cannot be resolved based upon the record before us and that are moreappropriately addressed in the hearing and settlement judge procedures ordered.”17 The FERC directed theparties to present evidence and any discounted cash flow (“DCF”) analyses in accordance with the guidanceprovided in the 2012 Base ROE Initial Order.18 Settlement judge procedures in this proceeding wereunsuccessful and were terminated October 24, 2014. The TOs July 21 request for rehearing of the 2012 BaseROE Initial Order, remains pending before the FERC pursuant to an August 20, 2014 tolling order issued bythe FERC.

Hearings. Trial Judge Sterner’s most recent, revised procedural was issued on March 16 and nowleads to hearings beginning June 25, 2015 and an initial decision by December 30, 2015. As previouslyreported, the active Participants filed a preliminary joint statement of issues on December 9 and a discovery

12 As previously reported, the Massachusetts Attorney General (“MA AG”), together with a group of StateAdvocates, Publicly Owned Entities, End Users, and End User Organizations (together, the “2014 ROE Complainants”),filed a complaint on July 31, 2014 to reduce the current 11.14% Base ROE to 8.84% (but in any case no more than 9.44%)and to cap the Combined ROE for all rate base components at 12.54%. 2014 ROE Complainants state that they submittedthis Complaint seeking refund protection against payments based on a pre-incentives Base ROE of 11.14%, and a reductionin the Combined ROE, relief as yet not afforded through the prior ROE proceedings.

13 The 2012 Base ROE Complaint challenged the TOs’ 11.14% return on equity, and seeks a reduction of the BaseROE to 8.7%.

14 Mass. Att’y Gen. et al. -v- Bangor Hydro et al., 149 FERC ¶ 61,156 (Nov. 24, 2014), reh’g requested.

15 Id. at P 27 (for the refund period covered by EL13-33 (i.e., Dec. 27, 2012 through Mar. 27, 2014), the ROE forthat particular 15-month refund period should be based on the last six months of that period; the refund period in EL14-86and for the prospective period, on the most recent financial data in the record).

16 Environment Northeast, et al. v. Bangor Hydro-Elec. Co., et al., 147 FERC ¶ 61,235 (June 19, 2014) (“2012 BaseROE Initial Order”), reh’g requested.

17 Id. at P 26.

18 Id.


Page 541536280.150

plan on December 18. On December 19, the Complaint-Aligned Parties,19 EMCOS, TOs, and FERC TrialStaff submitted briefs regarding the appropriate cut-off date for data to be used in filing updates to studies inprior testimony in this proceeding. On December 30, Complaint-Aligned Parties and EMCOS submitted theirdirect testimony, including work sheets and work papers. The TOs filed their Answering Testimony andExhibits (with summaries) on February 2. And, with respect to the data cut-off date, Judge Sterner issued anorder on February 5 setting the updated data cutoff date at May 26, 2015 (the day the Update of Studies inPrior Testimony is due).

Since the last Report, on April 21, the TOs submitted their cross-answering testimony, and a notice ofthe deposition of Mr. Avera was filed by the Complainant-Aligned Parties. If you have any questionsconcerning this matter, please contact Joe Fagan (202-218-3901; [email protected]) or Eric Runge (617-345-4735; [email protected]).

• 206 Investigation: FCM Performance Incentives (Compliance Proceedings) (EL14-52; ER14-2419)

Rehearing remains pending of the FERC’s May 30, 2014 PI Order20 on the FCM PI Jump Ball Filingand its October 2 Order21 on the first compliance filing in response to the PI Order. As previously reported,the FERC instituted this proceeding, pursuant to section 206 of the FPA, in its May 30 PI Order on the FCMPerformance Incentives Jump Ball filing. In the PI Order, the FERC concluded that the ISO’s FCM paymentdesign was “unjust and unreasonable, because it fails to provide adequate incentives for resourceperformance, thereby threatening reliable operation of the system and forcing consumers to pay for capacitywithout receiving commensurate reliability benefits.”22 The FERC directed the ISO to submit “Tariffrevisions reflecting a modified version of its [PFP] proposal and an increase in the Reserve Constraint PenaltyFactors, consistent with NEPOOL’s proposal.”23 The FERC-established refund effective date was June 9,2014.24 Requests for clarification and/or rehearing of the PI Order were filed by: NEPOOL, Connecticut andRhode Island,25 Dominion, MMWEC, Indicated Generators,26 NEPGA, NextEra, Potomac Economics, andPSEG/NRG. On July 28, the FERC issued a tolling order affording it additional time to consider therehearing requests, which remain pending before the FERC.

FCM PI Jump Ball Compliance Filing I (ER14-2419-001). On October 2, 2014, the FERC accepted inpart, subject to condition, and rejected in part, the ISO’s July 14, 2014 compliance filing (“Compliance Filing I”)that, as previously reported, had been filed in response to directives in the PI Order. While accepting nearly all ofthe provisions proposed in Compliance Filing I, the October 2 Order rejected the ISO’s compliance proposalconcerning improper price signals caused by binding intra-zonal transmission constraints.27 The FERC found that

19 “Complaint-Aligned Parties” are the CT AG, CT OCC, CT PURA, ME OPA, MA DPU, MMWEC, NHEC, NHOCA, NH PUC, RI PUC, VT DPS, Acadia Center (formerly Environment Northeast), The Energy Consortium, AssociatedIndustries of Massachusetts (“AIM”), and the Industrial Energy Consumer Group (“IECG”).

20 ISO New England Inc. and New England Power Pool, 147 FERC ¶ 61,172 (May 30, 2014) (“PI Order”), clarif.and reh’g requested.

21 ISO New England Inc., 149 FERC ¶ 61,009 (Oct. 2, 2014) (“October 2 Order”), reh’g requested.

22 PI Order at P 23.

23 Id. at P 1.

24 The June 3 notice of this proceeding was published in the Fed. Reg. on June 9, 2014 (Vol. 79, No. 110) pp.32,937-89.

25 “Connecticut and Rhode Island” are: the CT PURA, CT OCC, CT AG, CT DEEP, the United IlluminatingCompany (“UI”) and the RI PUC.

26 “Indicated Generators” are: Exelon Corp. (“Exelon”), EquiPower Resources Management, LLC (“EquiPower”),Essential Power, LLC (“Essential Power”), and Dynegy Marketing and Trade, LLC and Casco Bay Energy Company, LLC(together, “Dynegy”).

27 October 2 Order at P 56.


Page 641536280.150

an exemption was not necessary for resources on the export side of an intra-zonal transmission constraint during aCapacity Scarcity Condition and directed the ISO to submit a further compliance filing (since filed and accepted)to revise Market Rule Section 13.7 by removing the language that reflected that aspect of the ISO’s July 14compliance proposal and restoring language in Sections III.13.7.2.2(a) and III.13.7.2.2(b) ISO-NE originallyproposed by the ISO in its January 17 Filing. The Tariff sections accepted were accepted effective June 9, 2014,December 3, 2014, and June 1, 2018, as requested.28 Connecticut/Rhode Island29 and Public Systems30 requestedrehearing of the October 2 Order on November 3, 2014. On December 3, 2014, the FERC issued a tolling orderaffording it additional time to consider the rehearing requests, which remain pending before the FERC.

If you have any questions related to these proceedings, please contact Dave Doot (860-275-0102;[email protected]), Pat Gerity (860-275-0533; [email protected]), or Sebastian Lombardi (860-275-0663; [email protected]).

• 206 Investigation: Consistency of ISO-NE (DA) Scheduling Practices with Natural Gas SchedulingPractices to be Adopted in Docket RM14-2 (EL14-23)

As previously reported, on March 20, 2014, the FERC initiated this proceeding, pursuant to Section206 of the FPA, to ensure that the ISO’s scheduling, particularly its Day-Ahead scheduling practices,correlate with any revisions to the natural gas scheduling practices to be ultimately adopted by the FERC inRM14-2 (see Section XIII below).31 Noting its concern about the lack of synchronization between the Day-Ahead scheduling practices of interstate natural gas pipelines and electricity markets, the FERC directed eachISO and RTO, including ISO-NE, within 90 days after publication of a Final Rule in Docket RM14-2 in theFederal Register (or, as discussed in Section XIII below, Thursday, July 23, 2015):

(1) to make a filing that proposes tariff changes to adjust the time at which the results ofits day-ahead energy market and reliability unit commitment process (or equivalent) areposted to a time that is sufficiently in advance of the Timely and Evening NominationCycles, respectively, to allow gas-fired generators to procure natural gas supply andpipeline transportation capacity to serve their obligations, or (2) to show cause why suchchanges are not necessary. In their responses, each ISO and RTO must explain how itsproposed scheduling modifications are sufficient for gas-fired generators to secure naturalgas pipeline capacity prior to the Timely and Evening Nomination Cycles.32

The Commission expects to issue a final order in this section 206 proceeding within 90 days of thefilings required under the March 20 order (or October 21, 2015). If you have any questions concerning thismatter, please contact Dave Doot (860-275-0102; [email protected]), Joe Fagan (202-218-3901;[email protected]), or Sebastian Lombardi (860-275-0663; [email protected]).

• NESCOE FCM Renewables Exemption Complaint (EL13-34)

On April 20, the FERC denied rehearing of its February 12, 2013 order33 denying NESCOE’s FCMRenewable Exemption Complaint.34 The FERC found that, in light of its rulings in ER14-1639,35 which

28 October 2 Order at P 1; Ordering Paragraph (A).

29 “Connecticut/Rhode Island” are the CT PURA, CT AG, CT OCC, CT DEEP, and the RI PUC.

30 “Public Systems” are CMEEC, MMWEC, NHEC, and VEC.

31 Cal. Indep. Sys. Op. Corp. et al., 146 FERC ¶ 61,202 (Mar. 20, 2014). The New England 206 proceeding wasdocketed as EL14-23.

32 Id. at P 19.

33 New England States Comm. on Elec. v. ISO New England Inc., 142 FERC ¶ 61,108 (Feb. 12, 2013), reh’gdenied, 151 FERC ¶ 61,056 (Apr. 20, 2015) (“Renewables Exemption Complaint Order”). As previously reported, theRenewable Exemption Complaint asserted that the ISO’s proposed Minimum Offer Price Rule (“MOPR”) would likelyexclude from the FCM new renewable resources developed pursuant to state statutes and regulations, and thereby result


Page 741536280.150

superseded its rulings in this proceeding, NESCOE’s arguments on rehearing in favor of a renewable resourceexemption were moot.36 Accordingly, the request for rehearing was denied, concluding this proceeding. Ifyou have any questions concerning this matter, please contact Sebastian Lombardi (860-275-0663;[email protected]), Harold Blinderman (860-275-0357; [email protected]) or Dave Doot(860-275-0102; [email protected]).

• Base ROE Complaint (2011) (EL11-66)

On March 3, the FERC issued Opinion 531-B,37 denying rehearing of Opinion 53138 and Opinion531-A.39 Other than the filing of regional and local refund reports, and absent a successful challenge in thefederal courts of appeals or Supreme Court, these proceedings have now been concluded. Challenges, if any,to Opinions 531, 531-A and/or 531-B must be filed in a federal court of appeals on or before May 4, 2015.Any such further developments will be reported on in the federal court section (Section XV) of futureReports.

As previously reported, Opinion 531, affirmed in part, and reversed in part, Judge Cianci’s InitialDecision.40 In Opinion 531, the FERC announced a new approach that it will use for determining publicutilities’ base ROE and a change in its’ practice on post-hearing ROE adjustments. With respect to the NewEngland TOs’, the FERC applied its new that approach to the facts of this proceeding to determine theNETOs’ base ROE (10.57%), and established a paper hearing, addressed in Opinion 531-A, to allow theparticipants a limited opportunity to address application of the new ROE approach in those circumstances.41

Several parties requested rehearing and/or clarification of Opinion 531, including the TOs, EMCOS,American Municipal Power (“AMP”), and NRECA/APPA.42

Opinion 531-A set the Transmission Owners’ base ROE at 10.57%, with a maximum ROE includingincentives not to exceed 11.74%. Opinion 531-A affirmed that the 4.39 % projected long-term growth inGDP was the appropriate long-term growth projection to be used in the two-step DCF methodology fordetermining the TOs’ ROE. The FERC directed the TOs to (i) submit a compliance filing with revised ratesreflecting a 10.57% base ROE and a total ROE (inclusive of transmission incentive ROE adders) notexceeding 11.74%, effective October 16, 2014, and (ii) to provide refunds, with interest, for the 15-monthrefund period in this proceeding (October 1, 2011 through December 31, 2012). On November 6, the TOsrequested an extension of time to issue and file the required regional and local refunds and refund reports.

in customers being forced to purchase more capacity than is necessary for resource adequacy and proposed an alternativerenewables exemption.

34 New England States Comm. on Elec. v. ISO New England Inc., 151 FERC ¶ 61,056 (Apr. 20, 2015).

35 ISO New England Inc. and New England Power Pool Participants Comm., 147 FERC ¶ 61,173 (May 30, 2014)(“Demand Curve Order”), reh’g denied but clarif. granted, 150 FERC ¶ 61,065 (Jan. 30. 2015).

36 Id. at P 21.

37 Martha Coakley, Mass. Att’y Gen. et al., Opinion No. 531-B, 150 FERC ¶ 61,165 (Mar. 3, 2015) (“Opinion 531-B”).

38 Martha Coakley, Mass. Att’y Gen. et al., 147 FERC ¶ 61,234 (June 19, 2014) (“Opinion 531”), order on paperhearing, 149 FERC ¶ 61,032 (2014), reh’g denied, 150 FERC ¶ 61,165 (Mar. 3, 2015).

39 Martha Coakley, Mass. Att’y Gen. et al., 149 FERC ¶ 61,032 (Oct. 16, 2014) (“Opinion 531-A”).

40 Martha Coakley, Mass. Att’y Gen. et al., 144 FERC ¶ 61,012 (July 5, 013) (“Initial Decision”) (finding unjustand unreasonable the TO’s 11.14% ROE and that the ROE should be 10.6% for the Oct. 2011 through Dec. 2012 “lockedin/refund period” and 9.7% from Jan. 2013 forward, subject to further updating or modification by the FERC).

41 Opinion 531 at P 1.

42 In Opinion 531-B, the FERC denied the requests for rehearing of AMP and NRECA/APPA on the basis that theywere not parties to the proceeding (having failed in the first instance to meet their burden of justifying their lateinterventions). Opinion 531-B at P 15.


Page 841536280.150

The FERC granted that request on November 26, 2014, setting the following deadlines: April 30, 2015, forregional refunds; June 30, 2015, for the regional refund report; July 31, 2015, for local refunds; andSeptember 30, 2015, for the local refund report. On March 31, the TOs requested a second extension of time.In light of the changes in the refund calculation resulting from Opinion No. 531-B and additional timerequired by the ISO, the TOs requested that the following deadlines be permitted: August 31, 2015, forregional refunds; October 31, 2015, for the regional refund report; October 31, 2015, for local refunds; andDecember 31, 2015, for the final local refund report. On April 10, the FERC granted an extension of time tocomplete refunds and refund reports to and including November 2, 2015, for local refunds; and to andincluding December 31, 2015, for a final refund report. If you have any questions concerning this matter,please contact Joe Fagan (202-218-3901; [email protected]) or Eric Runge (617-345-4735;[email protected]).


• Opinion 531-A Compliance Filing: TOs (ER15-414)

On November 17, 2014, the New England TOs submitted tariff changes (to both the regional andlocal rates in the ISO OATT) in response to Opinion 531-A. Specifically, Section II.A.2.(a)(iii) of theAttachment F Implementation Rule was revised to reflect an ROE of 11.07% – the 10.57% base ROE directedby the Commission in Opinion 531-A plus the 50 basis point adder for ISO-NE participation. The TOs alsorevised Section II.A.2.(a)(iii) of the Attachment F Implementation Rule to require the PTOs to calculate theirtotal ROE each year under both regional and local rates and to reduce any ROE incentives included inregional rates to the extent necessary to ensure that the PTOs’ total ROE does not exceed 11.74% (the TOs’maximum ROE as identified by the FERC). The TOs also revised a number of provisions of the Attachment FImplementation Rule to include cross-references to Section II.A.2.(a)(iii). An effective date of October 16,2014, consistent with Opinion 531-A, was requested. Interventions were filed by the IECG, Complainant-Aligned Parties, and EMCOS. Protests were filed by EMCOS and the Complainant-Aligned Parties. OnDecember 23, the TOs answered the protests of EMCOS and Complainant-Aligned Parties. Complainant-Aligned Parties answered the TOs’ December 23 answer on January 13.

In light of Opinion 531-B, the TOs indicated in a March 31 motion that further amendments would berequired. The TOs indicated that that the amendments would likely resolve the contested issues raised byEMCOS and Complainant-Aligned Parties in response to the November 17 filing. Accordingly, the TOsrequested that the FERC defer action on the pending November 17 filing until after the amendments havebeen filed and the corresponding period for comments has passed.

On April 22, the TOs submitted their amended Opinion 531-A compliance filing. They indicated thatthe April 22 reflected certain clarifications provided in Opinion 531-B and amends the Attachment F AnnualTransmission Revenue Requirements used for determining RNS rates and the Schedule 21 Local ServiceSchedules for determining revenue requirements applicable to the TOs under the ISO OATT. Comments onthe amended Opinion 531-A compliance filing are due on or before May 13, 2015.

If you have any questions concerning these matters, please contact Joe Fagan (202-218-3901;[email protected]) or Eric Runge (617-345-4735; [email protected]).

• FCA-10 Capacity Zone Boundaries (ER15-1462)

On April 6, the ISO filed a notice identifying two potential new boundaries for Capacity Zones for thetenth Forward Capacity Auction (“FCA-10”): (1) a ‘Southeastern New England (“SENE”) Capacity Zone’ (animport-constrained zone that is a combination of the existing NEMA/Boston and SEMA/RI Capacity Zones) and(2) a ‘Northern New England (“NNE”) Capacity Zone’ (an export-constrained zone that is a combination of theexisting Maine, New Hampshire and Vermont Load Zones). No changes are proposed to the West/Central MA orConnecticut zones. If the FERC approves the identified boundaries, then a determination as to whether the


Page 941536280.150

potential zones will actually be modeled as separate Capacity Zones in FCA-10 will be conducted in accordancewith Section III.12.4(b) of Market Rule 1 and addressed in the FCA-10 information filing to be submitted in earlyNovember 2015. An order accepting this filing on or before May 29, 2015 was requested. The annual assessmentof transmission transfer capability that formed the basis for the identification of the new boundaries was presentedto the PAC on March 24. Additional input on the assessment was solicited at an April 2 Reliability Committeemeeting. At the April 2 meeting, the RC voted 34.25% in favor of recommending to the ISO that theidentification of the zonal boundaries was performed in accordance with Section II, Attachment K and SectionIII.12.5 of the ISO Tariff. This matter was not considered by the Participants Committee. Comments on thisfiling were due on or before April 27, 2015.

Interventions were filed by Champlain VT, ConEd, Dynegy, Emera, Entergy, Eversource, Exelon,Footprint, GDF Suez, MMWEC, NESCOE, NHEC, SunEdison, and Verso. Comments were submitted byNEPOOL on April 21 ((i) seeking confirmation/affirmation that a Reliability Committee vote is a requiredpredicate to material changes to Capacity Zone Boundaries, (ii) summarizing reasons why the new boundarieswere not supported; and (iii) seeking guidance that process improvements to facilitate meaningful engagementbetween the ISO and NEPOOL members on proposed Capacity Zone changes are warranted) and by Calpine onApril 27 (taking no position on the specific boundaries proposed, but expressing concern with the process forestablishing new Capacity Zones that prevent meaningful stakeholder input and potentially create unnecessaryand undesirable price volatility in FCM auctions).

Protests were filed by: Dominion (requesting that the ISO be directed to provide stakeholders with amore robust opportunity to review proposed potential zonal boundaries), NRG (protesting the manner in whichthe technical studies were presented to stakeholders and providing comments on how the system of establishingnew capacity zones should be improved), NEPGA (requesting that the ISO be directed to amend the Tariff torequire the ISO to: (i) identify and evaluate a relatively static set of transmission interfaces in the Step Oneprocess; (ii) model as an import-constrained Capacity Zone any Capacity Zone that has in a recent FCA signaleda need for new resources; (iii) make any other changes necessary to provide greater predictability to thetransmission interfaces that will be evaluated as potential Capacity Zone boundaries; and (iv) providestakeholders with an opportunity to participate in the identification of relevant transmission interfaces earlyenough in the Step One process for that participation to be meaningful), New England Suppliers43 (NNECapacity Zone), and PSEG (urging rejection of the filing and that the ISO be directed to model all of the existingload zones as capacity zones in FCA-10).

This matter is pending before the FERC. If you have any questions concerning this matter, please contactEric Runge (617-345-4735; [email protected]).

• FCA9 Results Filing (ER15-1137)

As previously reported, the ISO filed the results of the ninth FCA (“FCA9”) held February 2, 2015 onFebruary 27, identifying the following highlights:

• FCA9 Capacity Zones were Connecticut (“CT”), Northeastern Massachusetts/Boston(“NEMA/Boston”), Southeastern Massachusetts/Rhode Island (“SEMA/RI”) and Rest-of-Pool(Western/Central Massachusetts, New Hampshire, Vermont and Maine);

• FCA9 commenced with a starting price of $17.728/kW-mo.•Resources will be paid as follows:

♦ In CT, NEMA/Boston, and Rest-of-Pool - $9.551/kW-month♦ New York AC Ties imports - $7.967/kW-month♦ New Brunswick imports - $3.94/kW-month♦ SEMA/RI new resources - $17.728/kW-month♦ SEMA/RI existing resources - $11.08/kW-month

•No de-list bids were rejected for reliability reasons

43 “New England Suppliers” are Essential Power, Granite Ridge and NextEra.


Page 1041536280.150

The ISO asked the FERC to accept the FCA9 rates and results, effective June 27, 2015. Commentson this filing were due on or before April 13, 2015. Interventions were filed by NEPOOL, Calpine, CPVTowantic, Emera, Essential Power Entergy, EPSA, EquiPower, Exelon, HQ US, NEPGA, NESCOE,NextEra, NRG, PSEG, and TransCanada. The sole protest was filed on April 13 by Utility Workers Union ofAmerica Local 464 (“UWUA Local 464”) (alleging the results are the product of continued illegal marketmanipulation and violation of the ISO-NE Tariff). On April 28, NEPGA answered the UWUA Local 464protest. This matter is pending before the FERC. If you have any questions concerning this matter, pleasecontact Sebastian Lombardi (860-275-0663; [email protected]) or Pat Gerity (860-275-0533;[email protected]).

• ISO Securities: Authorization for Future Drawdowns (ES15-15)

On April 15, the ISO requested the necessary continued FERC authorization for drawdowns under itspreviously authorized $20 million Revolving Credit Line and $4 million line of credit supporting the PaymentDefault Shortfall Fund.44 (ISO authorization under the 2012 Order would otherwise terminate on June 30,2015).45 Comments on this filing are due on or before May 6. If you have any questions concerning thismatter, please contact Paul Belval (860-275-0381; [email protected]).

• 2014/2015 Power Year Transmission Rate Filing: Public Representatives’ Protest (ER09-1532;RT04-2)

In a new mater since the last Report, On April 28, 2015, “Public Representatives”46 filed a protest, inpart, of the July 31, 2014 Participating Transmission Owners Administrative Committee (“PTO AC”) filingidentifying adjustments to regional transmission service charges under Section II of the ISO Tariff for theperiod June 1, 2014 through May 31, 2015. Specifically, Public Representatives protest the AnnualTransmission Revenue Requirements calculation and the resulting RNS rates to the extent they includedplanning costs for NHT’s proposed “SeaLink” project, costs they asserted were contrary to the terms of theTOA and should be disallowed from RNS rate recovery. Public Representatives stated that the partial protestwas filed in April 2015, rather than closer to the July 2014 informational filing, due to lengthy, butunsuccessful, discussions between the MA AG’s office and NHT to resolve this dispute. If there arequestions on this proceeding, please contact Eric Runge (617-345-4735; [email protected]).


• DNE Dispatch Changes (ER15-1509)

On April 15, as corrected on April 16, the ISO and NEPOOL jointly submitted revisions to Market Rule 1to provide for the dispatch of certain wind and hydro Intermittent Power Resources using Do Not Exceed(“DNE”) Dispatch Points (“DNE Dispatch Changes”). The changes are designed to result in more efficienteconomic outcomes and better system reliability through the better use of economic dispatch signals to managetransmission system congestion and the minimization of the use of manual curtailment processes. An April 10,2016 effective date was requested. These changes were supported unanimously by the Participants Committee atits March 6, 2015 meeting. Comments on this filing are due on or before May 6. Thus far, interventions havebeen filed by Dominion, Entergy, Exelon, and NESCOE. If you have any questions concerning this matter,please contact Sebastian Lombardi (860-275-0663; [email protected]).

44 See ISO New England Inc., 139 FERC ¶ 62,248 (June 22, 2012) (“2012 Order”).

45 See ISO New England Inc., 147 FERC ¶ 62,091 (May 6, 2014).

46 “Public Representatives” are the MA AG, CT OCC, CT PURA, the RI PUC, the Attorney General of the State ofRhode Island (“RI AG”), the Maine Public Advocate (“MOPA”) and the Vermont Department of Public Service (“VTDPS”).


Page 1141536280.150

• eTariff Corrections (ER15-1455)

On April 6, the ISO submitted corrections to the following sections of the ISO’s eTariff: I.2.2(Definitions); III.2 and III.2 (LMPs, Real-Time Reserve Clearing Prices Calculation; Accounting/Billing);III.13.2(Annual FCA); III.13.7 (Performance, Payments & Charges in the FCM); and MR1 Appendix E2 (LoadResponse Program). The ISO explained that the corrections are needed due to the overlapping timing of the filingand acceptance of various prior Tariff filings. Comments on this filing were due on or before April 27.Interventions were filed by NEPOOL and Exelon; no comments were filed. This matter is pending before theFERC. If you have any questions concerning this matter, please contact Pat Gerity (860-275-0533;[email protected]).

• LMP Calculator Replacement (ER15-1238)

On April 17, the FERC accepted revisions to Market Rule 1 to replace the part of the system dispatchsoftware that calculates prices in the Real-Time Energy Market (the “LMP Calculator”) jointly submitted by theISO and NEPOOL on March 13. Real-Time price calculations will now be based on the same software and inputsused to produce the Dispatch Rates, ensuring that Real-Time Prices and Dispatch Rates are more closely aligned.The changes were accepted as of May 27, 2015, as requested. Unless the April 17 is challenged, this proceedingwill be concluded. If you have any questions concerning this matter, please contact Sebastian Lombardi (860-275-0663; [email protected]).

• PER Mechanism Elimination (FCA-10) (ER15-1184)

On March 6, the ISO and NEPOOL jointly submitted revisions to Market Rule 1 to eliminate the FCMPeak Energy Rent (“PER”) mechanism beginning June 1, 2019, with the commencement of the CapacityCommitment Period associated with the tenth Forward Capacity Auction (“FCA-10”). A May 6, 2015 effectivedate was requested. These changes were supported by the Participants Committee at its March 6, 2015 (AgendaItem #6A). Comments on this filing were due on or before March 27. Interventions were filed by Calpine, CTAG, Dominion, Emera, Exelon, NESCOE, and NRG. Comments supporting the filing were filed by Entergy,GDF Suez and NEPGA. Entergy asked the FERC to accept the proposed changes without change or condition.NEPGA and GDF Suez asked the FERC to accept the proposed changes, but also asked the FERC to “directNEPOOL and ISO-NE to commence a stakeholder consideration of Tariff changes for the period preceding theFCA 10 Capacity Commitment Period necessary to address subjecting resources to a reduction in capacitypayments due to a real-time price the resources did not receive.” On April 13, NEPOOL responded to theNEPGA and GDF Suez pleadings. This matter is pending before the FERC. If you have any questionsconcerning this matter, please contact Sebastian Lombardi (860-275-0663; [email protected]).

• Winter 2014/15 Reliability Program (ER14-2407)

On April 17, as requested by the ISO, the FERC granted rehearing47 of its January 20, 2015 clarification48

of the Winter 2014/15 Reliability Program Order.49 In the Winter Reliability Program Clarification Order, theFERC clarified, as requested by NEPGA, that its directive in the Winter 2014/15 Reliability Program Order“intended that ISO-NE would determine whether a winter reliability solution is necessary for the 2015-2016winter and future winters, and, if so, develop an appropriate market-based solution through the stakeholder

47 ISO New England Inc. and New England Power Pool Participants Comm., 151 FERC ¶ 61,052 (Apr. 17, 2015)(“Winter Reliability Program Clarification Rehearing Order”).

48 ISO New England Inc. and New England Power Pool Participants Comm., 150 FERC ¶ 61,029 (Jan. 20, 2015)(“Winter Reliability Program Clarification Order”), reh’g granted, 151 FERC ¶ 61,052 (Apr. 17, 2015).

49 ISO New England Inc. and New England Power Pool Participants Comm., 148 FERC ¶ 61,179 (Sep. 9, 2014)(“Winter 2014/15 Reliability Program Order”), clarif. granted, 150 FERC ¶ 61,029 (Jan. 20, 2015), reh’g granted, 151FERC ¶ 61,052 (Apr. 17, 2015). The Winter 2014/15 Reliability Program Order conditionally accepted the Tariff revisionsjointly filed by the ISO and NEPOOL intended to maintain reliability through fuel adequacy by creating incentives for dual-fuel resource capability and participation, offsetting the carrying costs of unused firm fuel purchased by generators andproviding compensation for demand response services (“Winter 2014/15 Reliability Program”).


Page 1241536280.150

process that can be implemented beginning with the 2015-2016 winter. While the two-settlement capacity marketdesign could help address winter reliability concerns in the future, that design will not be fully implemented untilthe 2018-2019 Capacity Commitment Period.” The ISO requested rehearing of the Winter Reliability ProgramClarification Order on February 19. On April 17, the FERC granted rehearing, finding “that an expanded versionof the current winter program might better produce the desired results in terms of reliability than the introduction,at this point in time, of the market-based solutions examined by ISO-NE.”50 Accordingly, the FERC will “allowthe possibility that ISO-NE may file additional out-of-market winter reliability programs until the two-settlementcapacity market design becomes effective in 2018.” The FERC noted its expectation that the ISO will “work withstakeholders to expand any future out-of-market winter reliability program to include “all resources that cansupply the region with fuel assurance,” such as nuclear, coal, and hydro resources” and to “provide a detaileddescription of the options it considered to make the program fuel neutral and why those options were ultimatelynot included.”51 Further challenges, if any, will need to be addressed in federal court, and if so challenged, will bereported on in Section XV in future Reports. If you have any questions concerning this proceeding, pleasecontact Sebastian Lombardi (860-275-0663; [email protected]).

• Demand Curve Changes (ER14-1639)

As previously reported, the FERC denied rehearing of the Demand Curve Order,52 but clarified (agreeingwith Exelon and Entergy) that a resource that elects to utilize the renewables minimum offer price rule exemptionshould not also be allowed to utilize the new resource lock-in).53 Accordingly, the FERC directed the ISO tosubmit, on or before March 2, 2015, a compliance filing clarifying that a resource may not utilize both therenewable resource exemption and the new resource price lock-in. On March 30, as reported more fully inSection XV below, NextEra, NRG and PSEG petitioned the DC Circuit Court of Appeals for review of theFERC’s Demand Curve orders. Developments in that proceeding will be reported in Section XV below.

Compliance Filing (ER14-1639-004). On March 2, the ISO submitted changes, in response to theDemand Curve Clarification Order, clarifying that a resource, including generation resources and eligible demandresources, cannot utilize both the price lock-in election and the renewable resource exemption. The ISO requesteda March 2 effective date for the changes (beginning with FCA-10), noting that the changes would not apply to thealready-completed qualification process for FCA9. The ISO reported that, in FCA9, resources totaling 12.96 MWutilized both the renewable resource exemption and the price lock-in election. Comments on the ISO’scompliance filing were due on or before March 23. In its comments, NEPOOL reported that the ParticipantsCommittee unanimously supported the compliance changes at its March 6 meeting. The Compliance Filing ispending before the FERC. If you have any questions concerning these matters, please contact SebastianLombardi (860-275-0663; [email protected]).

• FCM Performance Incentives Jump Ball Filing (ER14-1050)

Rehearing of the FCM PI Order remains pending. As previously reported, the ISO and NEPOOLsubmitted on January 17, 2014, two alternative versions of Market Rule changes intended to improve theoperating performance of capacity resources in New England -- the “ISO-NE Proposal” and the “NEPOOLProposal”. As explained above, on May 30, 2014, the FERC issued an order in response to the jump ball filing.54

The FERC concluded that the existing Tariff, specifically the current FCM payment design, “is unjust andunreasonable, because it fails to provide adequate incentives for resource performance, thereby threateningreliable operation of the system and forcing consumers to pay for capacity without receiving commensurate

50 Winter Reliability Program Clarification Rehearing Order at P 17.

51 Id.

52 ISO New England Inc. and New England Power Pool Participants Comm., 147 FERC ¶ 61,173 (May 30, 2014)(“Demand Curve Order”), reh’g denied but clarif. granted, 150 FERC ¶ 61,065 (Jan. 30. 2015).

53 ISO New England Inc. and New England Power Pool Participants Comm., 150 FERC ¶ 61,065, at P 27 (Jan. 30,2015) (“Demand Curve Clarification Order”).

54 See PI Order.


Page 1341536280.150

reliability benefits” and instituted a proceeding under Section 206 of the FPA (see EL14-52 in Section I above).Concluding that neither the ISO-NE Proposal nor the NEPOOL Proposal, standing alone, had been shown to bejust and reasonable, the FERC, drawing features from each Proposal, went on to direct the ISO to submit by July14, 2014 Tariff revisions reflecting a modified version of the ISO-NE Proposal and an increase in the ReserveConstraint Penalty Factors, consistent with NEPOOL’s Proposal. Specifically, the compliance filing was toinclude (1) changes to implement ISO-NE’s proposed two-settlement capacity market design with certainmodifications, and (2) changes to increase the RCPF values for Thirty-Minute Operating Reserves to$1,000/MWh and for Ten-Minute Non-Spinning Operating Reserves to $1,500/MWh. The FERC established aJune 9, 2014 refund effective date. Requests for clarification and/or rehearing of the PI Order were filed by:NEPOOL, Connecticut and Rhode Island, Dominion, MMWEC, Indicated Generators, NEPGA, NextEra,Potomac Economics, and PSEG/NRG. On July 28, 2014, the FERC issued a tolling order affording it additionaltime to consider the requests for clarification and/or rehearing, which remain pending before the FERC.

If you have any questions concerning this matter, please contact Dave Doot (860-275-0102;[email protected]), Harold Blinderman (860-275-0357; [email protected]), Eric Runge(617-345-4735; [email protected]) or Sebastian Lombardi (860-275-0663;[email protected]).

• FCM Redesign Compliance Filing: FCA8 Revisions (ER12-953 et al.)

On April 20, the FERC denied the March 15, 2013 requests for rehearing of the FCA8 Revisions Order.55

As reported previously, the FERC conditionally accepted in part, and rejected in part, revisions to the FCM andFCM-related rules in the Tariff (“FCA8 Revisions”) filed by the ISO and the PTO AC.56 Two requests forrehearing of the FCA8 Revisions Order were filed on March 15, 2013, one by Public Systems,57 the other byEMCOs.58 In denying the requests, the FERC found that no arguments on rehearing were raised by either groupthat had not been previously addressed or that warranted reversal of the earlier rulings. Specifically, the FERCfound that, although the unit-specific review process which EMCOs objected to may impose more proceduralrequirements on resources with costs below the benchmark than on others, those requirements are necessary toensure the correct functioning of the FCM and neither results in nor is motivated by undue discrimination.59

Addressing Public Systems’ arguments, the FERC (i) rejected the jurisdictional arguments; (ii) found that theFCM Market Rules do not prohibit Public Systems’ members, or any other party, from developing capacity oroffering that new capacity into the market; (iii) found that payments that consumer-owned utilities receive fromtheir members are out-of-market payments; and (iv) declined to impose a blanket MOPR exemption for self-supplied resources. Further challenges, if any, will need to be addressed in federal court, and if so challenged,

55 ISO New England Inc., 151 FERC ¶ 61,055 (Apr. 20, 2015) (“FCA8 Revisions Rehearing Order”).

56 ISO New England Inc., 142 FERC ¶ 61,107 (Feb. 12, 2013) (“FCA8 Revisions Order”), reh’g denied, 151FERC ¶ 61,055 (Apr. 20, 2015). The FCA8 Revisions Order accepted the following aspects of the FCA8 Revisions ascompliant with its prior FCM Orders: the ISO’s offer review trigger prices; unit specific offer review; the ISO’sproposal to subject a resource to offer floor mitigation until that resource clears in one FCA; imports’ treatment underMOPR; no exemptions to MOPR for new Self-Supplied Resources; the application of mitigation to all new resourcesoffering into the FCM, including renewables that are procured pursuant to state policy initiatives; $1.00/kW-monthThreshold to trigger IMM review of Dynamic De-List Bids; and a number of other additional revisions. The FCA8Revisions Order rejected: the ISO’s proposed methodology for reducing the offer floor of an uncleared resource that hasalready achieved commercial operation at the time of an FCA (directing the ISO to submit a revised proposal thatsubjects a resource to an offer floor until it has demonstrated that it is needed by the market); and the ISO’s request tomodel only 4 capacity zones for FCA8 (the ISO’s Capacity Zones Changes were accepted in ISO New England Inc., 147FERC ¶ 61,071 (2014)).

57 For purposes of this proceeding “Public Systems” are: MMWEC, NHEC, APPA, Northeast Public PowerAssociation (“NEPPA”), and National Rural Electric Cooperative Association (“NRECA”).

58 For purposes of this proceeding “EMCOS” includes Braintree, Hingham, Reading, and Taunton, together withDanvers.

59 FCA8 Revisions Rehearing Order at P 22.


Page 1441536280.150

will be reported on in Section XV in future Reports. If you have any questions concerning these matters, pleasecontact Sebastian Lombardi (860-275-0663; [email protected]), Eric Runge (617-345-4735;[email protected]) or Dave Doot (860-275-0102; [email protected]).

IV. OATT Amendments / TOAs / Coordination Agreements

• ETU Rule Changes (ER15-1050, -1051)

On April 14, the FERC accepted the changes to the Tariff and TOA to improve the Elective TransmissionUpgrade (“ETU”) process (“ETU Rule Changes”) jointly submitted by the ISO, NEPOOL and PTO AC inFebruary.60 As previously reported, the ETU Rule Changes incorporate into the ISO OATT new Schedule 25 thatwill govern the interconnection of all forms of ETUs to the New England System, defining “InterconnectionService” for ETUs, and introducing two new forms of capacity and energy interconnection service – CapacityNetwork Import Interconnection Service (“CNIIS”) and Network Import Interconnection Service (“NIIS”) – forthe interconnection of all new controllable External ETUs that are classified as Merchant Transmission Facilities(“MTF”) or Other Transmission Facilities (“OT”) to the Administered Transmission System in a manner similarto internal Generating Facilities. The ETU Rule Changes also provide for the allocation of capacityinterconnection service to controllable MTF/OTF External ETUs for the import of capacity into New Englandthrough the FCM, and provide that Internal ETUs may become directly associated with a specific GeneratingFacility seeking CNIIS so that they can be studied together and thereby increase the Generating Facility’s abilityto qualify for the FCM. Other changes necessary to support the revised treatment of EUs include: changes to theTie Benefits calculation to exclude external ETUs eligible for CNIIS and NIIS, inclusion of ETUs in the FCMNetwork Model Assumptions, transition rules for ETU applications, and conforming and other ministerial Tariffrevisions. The changes were accepted as of February 16, 2015, as requested. In accepting the changes, the FERCdeclined, as requested by Champlain VT, to require the ISO to make retroactive determinations of whetherchanges to an ETU project constituted a material modification.61 The FERC found the changes to be just andreasonable, and therefore not required to consider alternative tariff provisions. The FERC noted that the proposalreceived unanimous support in the stakeholder process. Challenges, if any, to the April 14 order will be due on orbefore May 14. If you have any questions concerning this matter, please contact Eric Runge (617-345-4735;[email protected]).

• Order 676-H Compliance: Revisions to Schedule 24 (ER15-519)

As previously reported, the ISO submitted, on December 1, 2014, a compliance filing requesting (i)renewal of waivers previously granted in response to Order 676, 676-C, 676-E, and 890, (ii) waiver of certain newOrder 676-H-approved standards, and (iii) acceptance of Schedule 24 Revisions incorporating by reference theNorth American Energy Standards Board (“NAESB”) Wholesale Electric Quadrant (“WEQ”) v.003 Standards forwhich waiver was not requested. A February 2, 2015 effective date was requested. The Schedule 24 revisionswere unanimously supported by the Participants Committee at its December 5 annual meeting. Interventionswere filed by Exelon and NU. In its comments, NEPOOL reported on that support and requested that the FERCaccept the ISO-NE OATT revisions and grant the requested waivers. This matter remains pending before theFERC. If you have any comments or concerns, please contact Eric Runge (617-345-4735;[email protected]) or Kristin Sullivan (617-345-4657; [email protected]).

• Order 676-H Compliance: PTOs, SSPs, CSC et al. (ER15-517)

Also on December 1, 2014, the PTO Administrative Committee (“PTO AC”), on behalf of theParticipating Transmission Owners (“PTOs”), the Schedule 20A Service Providers (“SSPs”), Cross-Sound CableCompany, LLC (“CSC”), New England Power Company (“NGrid”), Northeast Utilities Service Company(“NUSCO”), Unitil Energy Systems, Inc., Fitchburg Gas and Electric Light Company, and the ISO (collectively,

60 ISO New England Inc., 151 FERC ¶ 61,024 (Apr. 14, 2015).

61 Id. at P 31.


Page 1541536280.150

the “Filing Parties”), jointly submitted a filing to request (continued and new) waiver of, and to adopt, certainVersion 003 WEQ Standards adopted NAESB incorporated by reference into FERC regulations pursuant to Order676-H. Waiver requests included those previously granted for Orders 676-C and 676-E, waiver of WEQ-4(limited in the case of CSC),WEQ-8, WEQ-11, WEQ-15, WEQ-21, the OASIS-related Standards, and variousadditional waivers under the individual Schedule 21 service schedules. Interventions were filed by NEPOOL andNU. Comments on this filing were due on or before December 22; none were filed.

Supplement. On April 14, the Filing Parties supplemented their December 1 compliance filing with arequest for waiver of the Network Integration Transmission Service (“NITS”) and Service Across MultipleTransmission Systems (“SAMTS”) WEQ Standards.62 The Filing Parties sated that the NITS and SAMTS WEQStandards are inapplicable in New England given the nature of the transmission services provided under the ISOOATT, and the failure to request waiver of those Standards in the December 1 filing was an oversight.Comments, if any, on the supplemental filing are due on or before May 5.

If you have any comments or concerns, please contact please contact Eric Runge (617-345-4735;[email protected]) or Kristin Sullivan (617-345-4657; [email protected]).

• Order 1000 Interregional Compliance Filing (ER13-1960; ER13-1957)

On July 10, 2013, the ISO, NEPOOL and the PTO AC jointly filed revisions to Sections I and II of theTariff to comply with the interregional coordination and cost allocation requirements of Orders 1000 and 1000-A(the “Order 1000 Interregional Compliance Changes”) (ER13-1960). In addition, the ISO, on behalf of itself,NYISO and PJM, filed an Amended and Restated Northeastern ISO/RTO Planning Coordination Protocol(“Amended Protocol”) as part of its compliance changes (ER13-1957). The Order 1000 InterregionalCompliance Changes include (i) revisions to Attachment K to add provisions describing the interregionalcoordination provisions included in the Amended Protocol, as well as adding other provisions facilitating theconsideration of interregional solutions to regional needs; (ii) a new Schedule 15 reflecting the methodology forallocation among ISO-NE and NYISO of the costs of approved interregional transmission projects; (iii) revisionsto Schedule 12 describing the regional cost allocation within New England of the costs of approved interregionaltransmission projects; and (iv) conforming changes to Tariff Section I. The Order 1000 Interregional ComplianceChanges and the Amended Protocol were supported by the Participants Committee at its June 27 SummerMeeting. On August 7, the FERC extended the comment deadline on these filings to and including September 9,2013. Doc-less motions to intervene were filed by a number of New England parties in both proceedings,including Dominion, Exelon, PPL, PSEG, and NEPOOL (in the Protocol proceeding (in which it was not a filingparty)). On August 26, 2013, NEPOOL filed comments supporting the Protocol. NEPOOL added that “From astakeholder perspective, stakeholder input into revisions to the Protocol as it evolves over time would be easierand more likely to be taken into account if it were made part of the individual regional tariffs of each of theNortheast ISOs rather than existing solely as a stand-alone three-party agreement”. On September 9, NESCOEsubmitted comments generally supporting the filings, but reserving the right to further comment on these filingsshould the substance of the changes be modified as a result of further FERC (see ER13-193 and ER13-196 below)or federal court proceedings. Public Interest Organizations63 raised concerns that the Protocol and relatedamendments “do not meet certain of the transparency and cost allocation aspects of [Order 1000]’s minimumrequirements.” On September 24, 2013, the ISO answered Public Interest Organizations’ and NEPOOL’scomments. These matters remain pending before the FERC. If you have any comments or concerns, pleasecontact Eric Runge (617-345-4735; [email protected]).

62 The NITS Standards are contained in Version 003 WEQ-000, WEQ001, WEQ-002 and WEQ-003; the SAMTSStandards, Version 003 WEQ-000, WEQ-001, WEQ-002, WEQ-003 and WEQ-013.

63 “Public Interest Organizations” are Conservation Law Foundation, Acadia Center, Natural Resources DefenseCouncil, Pace Energy and Climate Center, and the Sustainable FERC Project.


Page 1641536280.150

• Order 1000 Compliance Filing (ER13-193; ER13-196)

As previously noticed, the FERC issued, on March 19, 2015, its long-awaited Order on Rehearingand Compliance64 of the region’s Order 1000 compliance filing.65 A memo summarizing the 200-page orderin more detail was circulated by NEPOOL Counsel on March 23 and posted on the NEPOOL websiteLitigation Report Updates page. As previously noted, the Order 1000 Compliance Order:

• Affirmed an effective date 60 days from the date of the issuance of the March 19 Order andrequired additional compliance filings within that same time period (i.e. on or before May 18,2015).

• Grandfathered projects that are listed as “Proposed” or “Planned” as of the effective date asexempt from the new transmission development regime, unless the ISO is re-evaluating, orsubsequently determines it necessary to reevaluate, the solution design for such transmissionprojects as of the effective date.

• Required the ISO to make a further compliance filing to provide a list of transmission providersand the enrollment process that defines how transmission providers enroll in the transmissionplanning region.

• Affirmed the finding that the existing framework of the Needs Assessment Study Group isinconsistent with the transparency principle of Order 1000 and accepted use of the PAC in itsplace.

• Affirmed FERC’s prior determination that the ISO and not the States must be the one that selectssolutions that meet transmission needs driven by Public Policy Requirements.

• Affirmed the elimination of the incumbent transmission owners’ right of first refusal (“ROFR”) tobuild and own transmission projects called for by the Regional System Plan.

• Affirmed the exception to the ROFR for reliability projects needed within three years (rather thanfive years).

• Granted rehearing to allow for provisions that recognize the incumbent transmission owners' rightsto build upgrades to their transmission facilities and to retain use and control of their rights-of-way.

• Affirmed the ISO’s proposed mechanism for evaluating the qualifications of transmissiondevelopers to operate and maintain projects.

• Required certain additional compliance changes to the Non-incumbent Agreement for transmissiondevelopment.

• Affirmed elimination of the requirement for prospective transmission developers to providefeasibility studies to demonstrate how their proposed transmission solutions will address theidentified needs.

• Required a further compliance filing providing additional details on the treatment of studydeposits.

• Required a further compliance filing clarifying when project sponsors must submit proposals.• Clarified that in cases where a project is abandoned or not being diligently pursued by the sponsor,

the backstop obligation of the Participating Transmission Owners is to build a solution, not tobuild the selected project.

• Required a further compliance filing providing more clarity on backstop transmission solutions,and limiting the obligation on Participating Transmission Owners.

• Required a further compliance filing for cost allocation of reliability and market efficiencyupgrades to ensure that costs for such upgrades are not imposed involuntarily on parties outsideNew England.

64 ISO New England Inc., 150 FERC ¶ 61,209 (Mar. 19, 2015) (“Order 1000 Compliance Rehearing Order”), clarif.and/or reh’g requested.

65 ISO New England Inc., 143 FERC ¶ 61,150 (May 17, 2013) (“Order 1000 Compliance Order”), order onreh’g 150 FERC ¶ 61,209 (Mar. 19, 2015).


Page 1741536280.150

• Affirmed the prior rejection of the State “opt-in” approach to cost allocation for public policyprojects.

• Accepted the proposal for cost allocation for public policy projects that would allocate 70% of thecosts of Public Policy Transmission Upgrades throughout the region based on load ratio shares andthe remaining 30% of the costs would be allocated on a load ratio basis among those states with apublic policy planning need that a particular project is intended to meet.

• Rejected consumer-owned systems’ request for an opt-out from public policy project costallocation.

Among the requirements to be addressed in the 60-day (May 18) compliance filing are (i) to set forthin the OATT the enrollment process that defines how transmission providers enroll in the transmissionplanning region; (ii) to include a list of enrolled transmission providers in the OATT; (iii) to describe a justand reasonable and not unduly discriminatory process through which each Participating Transmission Ownerwill identify, out of the larger set of potential transmission needs driven by federal public policy requirementsthat may be proposed, those transmission needs for which transmission solutions will be evaluated in the localtransmission planning process; (iv) to restore from the First Compliance Filing the proposed revisions tosection 4.3(a) of the OATT and Schedule 3.09, section 1.1(f) of the TOA dealing with existing rights of way;(v) to revise the definition of non-incumbent transmission developer in the OATT to require that aParticipating Transmission Owner that proposes to develop a transmission facility not located within orconnected to its existing electric system enter into a Non-incumbent Agreement; (vi) to exempt from the holdharmless provision a Participating Transmission Owner’s own ordinary negligence and to remove thereference to FERC penalties; (vii) to modify the study deposit provisions to: (a) provide to each QualifiedSponsor a description of the costs to which the deposit will be applied, how those costs will be calculated, andan accounting of the actual costs, and (b) provide a provision that any disputes arising from this process beaddressed under the ISO’s dispute resolution process; (viii) to clarify when a Qualified Sponsor whose PhaseOne or Stage One Proposal will be considered in Phase Two or Stage Two must submit the requiredinformation regarding its Phase Two or Stage Two Solution; (ix) to create a defined term for a backstoptransmission solution and to use that term consistently in the OATT and TOA; and (x) to remove the newlanguage in section 4.3(k) of Attachment K that would require a Participating Transmission Owner tocontinue developing a backstop transmission solution beyond what was originally proposed and that theCommission accepted in the First Compliance Order. Consideration of the 60-day compliance filing changes,initially scheduled for consideration at the May 1 Participants Committee meeting, have been deferred to asubsequent meeting.

On April 20, the ISO requested clarification and/or re-hearing of the Order 1000 ComplianceRehearing Order. Specifically, the ISO requested clarification (i) that the FERC’s concerns with the non-discriminatory applicability of the “hold harmless” clause contained in the Non-Incumbent TransmissionDeveloper Operating Agreement (“NTDOA”) could be addressed by the inclusion of a similar clause in theTransmission Operating Agreement (“TOA”); and (ii) that no changes are required to comply with RegionalCost Allocation Principle 4 and that language providing that “the costs of any external impacts of NewEngland regional projects will not be borne by New England customers” need not be removed from Schedule15 of the OATT. The ISO’s request for rehearing is pending before the FERC, with FERC action required onor before May 20, 2015, or the request will be deemed denied. However, the ISO asked for expedited FERCaction so that its proposed approaches can be reflected in its compliance filing due on May 18, 2015. If youhave any comments or concerns, please contact Eric Runge (617-345-4735; [email protected]).


• Deposit Account Changes (ER15-1493)

On April 10, the ISO and NEPOOL jointly submitted changes to the collateral requirements for foreignMarket Participants. Specifically, the changes require foreign Market Participants to post a letter of credit to meettheir financial assurance obligations (removing the option to provide cash that would be invested in one of six


Page 1841536280.150

BlackRock Liquidity Funds investment options (“Liquidity Funds”)). The ISO reported that only two Participantswill be required to take action in response to the revisions. In addition, additional clean-up revisions deletingoutdated references to cash collateral were also submitted. These changes were supported by the ParticipantsCommittee at its April 10, 2015 meeting. Comments on this filing are due on or before May 1. Thus far, a doc-less intervention was filed by Exelon. If you have any questions concerning this matter, please contact PaulBelval (860-275-0381; [email protected]).

VI. Schedule 20/21/22/23 Changes

• Schedule 21-NEP: BIPCO and Narragansett TSAs (ER15-1466)

On April 7, New England Power Company d/b/a National Grid filed amendments to two local serviceagreements (“LSA”) under Schedule 21-NEP. The LSAs, one among the ISO, NEP and Block Island PowerCompany (“BIPCO”), and the other with The Narragansett Electric Company (“Narragansett”), were eachamended in order to address a concern raised by the RI PUC that the Block Island Transmission System (“BITS”)Surcharge calculated under the LSAs did not fully conform with Rhode Island General Law Section 39-26.7(f).Accordingly, NGrid modified the BITS Surcharge by adding a collar to the calculation of the BIPCO SharePercentage such that the impact on the typical residential customer in the Town of New Shoreham cannot belower than 120% of the impact on the typical residential customer of Narragansett. A June 7, 2015 effective datewas requested. Comments on this filing are due on or before April 28; none were filed. This mater is pendingbefore the FERC. If there are questions on this matter, please contact Pat Gerity (860-275-0533;[email protected]).

• Schedule 20A-EM and 21-EM Changes (ER15-1434)

On April 1, Emera Maine and the ISO filed changes to Schedule 21-EM (to ensure charges under theschedule reflect only costs of service over Emera Maine's Non-PTF System that is subject to that schedule) and20A-EM (corrections). A June 1, 2015 effective date was requested. Eversource submitted a doc-less motion tointervene on April 22. No comments on this filing were filed. This matter is pending before the FERC. If thereare questions on this matter, please contact Pat Gerity (860-275-0533; [email protected]).

• Opinion 531-A Compliance Filing: CTMEEC (ER15-584)

On December 5, 2014, the ISO submitted on behalf of the Connecticut Transmission MunicipalElectric Energy Cooperative (“CTMEEC”) changes to Attachment B to Schedule-21 CTMEEC to conformSchedule-21 CTMEEC to the holdings in Opinions 531 and 531-A. Comments, if any, on this filing were dueon or before December 26; none were filed and this matter is pending before the FERC. If there are questionson this matter, please contact Pat Gerity (860-275-0533; [email protected]).

• Opinion 531-A Compliance Filing: GMP (ER15-412)

On November 17, 2014, the ISO submitted on behalf of Green Mountain Power (“GMP”) changes toSchedule-21 GMP, in response to Opinion 531-A, to reflect a 10.57% ROE effective as of October 16, 2014.GMP explained that, although it was not a respondent to the complaint in Docket No. EL11-66, GMP agreedin the recently-accepted Settlement Agreement66 to accept the ROE approved by the FERC in Docket No.EL11-66 and to provide refunds for the period of October 1, 2012 through December 31, 2012 (which it hasalso done). Comments, if any, on this filing were due on or before December 8; none were filed and thismatter is pending before the FERC. If there are questions on this matter, please contact Pat Gerity (860-275-0533; [email protected]).

66 ISO New England Inc., et al., 148 FERC ¶ 61,097 (Aug. 4, 2014).


Page 1941536280.150

• LGIA – NU/CPV Towantic (ER15-200)

The FERC conditionally accepted, on December 24, 2014, and set for hearing and settlement judgeprocedures on the issue of the proposed operation, maintenance, and capital cost reimbursement charges, theunexecuted LGIA (LGIA-ISONE/NU-14-02) between CPV Towantic, CL&P and the ISO, governing theinterconnection of CPV Towantic’s 795 MW natural gas-fired plant located in Oxford, Connecticut.67 ChiefJudge Wagner appointed Judge David H. Coffman as the Settlement Judge. Settlement conferences havebeen held on January 8, February 5, and April 10. On April 6, Judge Coffman issued a report recommendingthat the settlement proceedings continue. If there are questions on this matter, please contact Pat Gerity (860-275-0533; [email protected]).




• LFTR Implementation: 26th Quarterly Status Report (ER07-476; RM06-08)

The ISO filed the twenty-sixth of its Quarterly Status Reports regarding LFTR implementation onApril 15. As noted in the business priorities discussions, the ISO reported that it expects to file its proposal(following completion of the Participant Processes) in the first half of 2016. Third party clearing design couldthen be implemented during Q4 2016 for the 2017 annual FTR auction, about six months later (mid-2017) formonthly auctions, and during Q4 2018 for an initial auction of LFTRs. The estimated 18-month LFTRimplementation process, described in previous reports, would be initiated in 2016, presuming the third partyclearing design is accepted and related FAP changes resolved. These status reports are not noticed for publiccomment and no comments have been filed.

• ISO-NE FERC Form 1 (not docketed)

On April 13, the ISO submitted its 2014 Annual Report of Major Electric Utilities, Licensees andOthers. These filings are not noticed for filing.

• ISO-NE FERC Form 582 (not docketed)

On April 15, the ISO submitted a report of its total MWh of transmission service during 2014. Thesefilings are not noticed for filing.


• April 2015 Membership Filing (ER15-1417)

On March 31, NEPOOL requested that the FERC accept (i) the memberships of Evergreen Wind Power II(SunEdison Related Person -- AR Sector, RG Sub-Sector) and Jericho Power (AR Sector, RG Sub-Sector); (ii) thetermination of the Participant status of Lincoln Paper and Tissue (End User Sector); and (iii) the name change ofConstellation Energy Services (f/k/a Integrys Energy Services). Comments on this filing were due on or beforeApril 21; none were filed. This matter is pending before the FERC.

67 ISO New England Inc. and Northeast Utilities Service Co., 149 FERC ¶ 61,274 (Dec. 24, 2014).


Page 2041536280.150

• Suspension Notices (not docketed)

Since the last Report, the ISO filed, pursuant to Section 2.3 of the Information Policy, one notice with theFERC noting that the following Participant was suspended from the New England Markets on the date indicated(at 8:30 a.m.) due to a Payment Default:

Date of Suspension/FERC Notice

Participant Name Date Reinstated

April 15/16 Demansys Energy, LLC Remains suspended

Suspension notices are for the FERC’s information only and are not docketed or noticed for publiccomment.


Questions concerning any of the ERO Reliability Standards or related rule-making proceedings or filingscan be directed to Pat Gerity (860-275-0533; [email protected]).

• FFT Report: March 2015 (NP15-23)

NERC submitted on March 31, 2015 its Find, Fix, Track and Report (“FFT”) informational filing for themonth of March 2015. The March FFT resolves 23 possible violations of 12 Reliability Standards that posed arisk minimal risk to bulk power system (“BPS”) reliability, but which have since been remediated.68 FFT filingsare for information only and are not be noticed for public comment by the FERC.

• Revised Reliability Standards: PRC-001-1.1(ii), PRC-004-2.1(i)a, PRC-004-4; PRC-005-2(i), PRC-005-3(i), PRC-019-2 and PRC-024-2, VAR-002-4 (RD15-3)

On February 6, 2015, NERC filed for approval changes to VAR-002-4 (Generator Operation forMaintaining Network Voltage Schedules), and multiple versions of PRC-004 (Protection System MisoperationIdentification and Correction) and PRC-005 (Protection System and Automatic Reclosing Maintenance), and theassociated VRFs and VSLs (the “Dispersed Generation Resource Changes”).69 NERC stated that the DispersedGeneration Resource Changes tailor the Standards to account for the reliable operations of variable resources.NERC requested that the Dispersed Generation Resource Changes be approved for effectiveness in accordancewith the corresponding Implementation Plans (or immediately upon approval for those Standards in effect, orupon effectiveness of the pending but approved Standards). Comments on the Dispersed Generation ResourceChanges were due on or before March 9, 2015 and were filed by Dominion. On March 13, NERC supplementedits Dispersed Generation Resource Changes with changes to PRC-001-1.1(ii), PRC-019-2 and PRC-024-2.Comments on the supplemental changes, which NERC requested be accepted together with the DispersedGeneration Resource Changes, were due on or before April 9, 2015; none were filed. This matter is pendingbefore the FERC.

• Revised Reliability Standard: PRC-004-3 (RD14-14)

The PRC-004 Changes remain pending before the FERC. As previously reported, NERC filed, onSeptember 15, 2014, changes to PRC-004-3 (Protection System Misoperation Identification and Correction) aswell as a revised definition of “Misoperation” and a new definition of “Composite Protection System” forinclusion in the NERC Glossary of Terms, and the retirement of Reliability Standards PRC-004-2.1a (Analysis

68 Only possible violations that pose a minimal risk to Bulk-Power System reliability are eligible for FFT treatment.See N. Am. Elec. Reliability Corp., 138 FERC ¶ 61,193 (Mar. 15, 2012) at PP 46-56.

69 “Dispersed Generation Resources”, as used in NERC’s petition, are variable generation that depends on a primaryfuel source which varies over time and cannot be stored.


Page 2141536280.150

and Mitigation of Transmission and Generation Protection System Misoperations) and PRC-003-1 (RegionalProcedure for Analysis of Misoperations of Transmission and Generation Protection System) as listed in theImplementation Plan (“PRC-004 Changes”). NERC stated that the PRC-004 Changes address outstanding FERCconcerns and directives related to PRC-004 and PRC-003 and create a single Reliability Standard requiringTransmission Owners, Generator Owners, and Distribution Providers to identify and correct causes ofMisoperations of certain Protection Systems for Bulk Electric System Elements. NERC requested that the PRC-004 Changes be approved, and the existing PRC-004-2.1a and PRC-003-1 be retired, effective on the first day ofthe first calendar quarter that is one year after the date of FERC approval. Comments on the PRC-004 Changeswere due on or before October 20, 2014; none were filed. The PRC-004 Changes are pending before the FERC.

• Revised TOP and IRO Reliability Standards (RM15-16)

On March 18, NERC filed for approval changes reflected in the following Transmission Operations(“TOP”) and Interconnection Reliability Operations and Coordination (“IRO”) Reliability Standards:

TOP-002-4 (Operations Planning);

TOP-003-3 (Operational Reliability Data);

IRO-001-4 (Reliability Coordination – Responsibilities);

IRO-002-4 (Reliability Coordination –Monitoring and Analysis);

IRO-008-2 (Reliability Coordinator Operational Analyses and Real-time Assessments);

IRO-010-2 (Reliability Coordinator Data Specification and Collection);

IRO-014-3 (Coordination Among Reliability Coordinators); and

IRO-017-1 (Outage Coordination).

NERC indicated that the TOP/IRO Standards, which supersede the changes submitted in RM13-15, -14,and -12, but concurrently withdrawn, include improvements over the currently effective TOP and IRO ReliabilityStandards in key areas such as: (1) operating within SOLs and IROLs; (2) outage coordination; (3) situationalawareness; (4) improved clarity and content in foundational definitions; and (5) requirements for operationalreliability data. NERC requested that the TOP/IRO Changes be approved as of the first day of the first calendarquarter that is 12 months after the date that the Standards are approved, with the exception of TOP-003-3 andproposed IRO-010-2, which were requested to be approved 3 months earlier. As of the date of this Report, theFERC has not noticed a proposed rulemaking proceeding or otherwise invited public comment.

• Revised Reliability Standards: CIP-003-6, CIP-004-6, CIP-006-6, CIP-007-6, CIP-009-6, CIP-010-2,CIP-011-2 (RM15-14)

On February 13, NERC filed for approval changes to seven CIP (“Critical Infrastructure Protection”)Reliability Standards to improve the cyber security protections required by the CIP Standards and collectivelyaddress the FERC’s four directives from Order 791 (the “CIP Changes”). NERC stated that the CIP Changes (i)remove the “identify, assess, and correct” language from the 17 requirements in the CIP Version 5 Standards thatincluded such language; (ii) require responsible entities to implement cyber security plans for assets containinglow impact BES Cyber Systems; (iii) include specific requirements applicable to transient devices to furthermitigate the security risks associated with such devices; and (iv) require entities to implement security controls fornon-programmable components of communication networks at Control Centers with high or medium impact BESCyber Systems. NERC requested that the CIP Changes be approved, effective on April 1, 2016. As of the dateof this Report, the FERC has not noticed a proposed rulemaking proceeding or otherwise invited public comment.

• Revised Reliability Standards: Transition to “Remedial Action Scheme” RM15-13)

On February 3, NERC filed for approval proposed revisions to the definition of “Remedial ActionScheme” and changes to nearly 20 Reliability Standard to insert that term in place of the term “Special ProtectionSystem”, which are used interchangeably throughout the Reliability Standards (the “RAS Changes”). NERCrequested that the RAS Changes be approved, effective the first day of the first calendar quarter that is one year


Page 2241536280.150

after the date of FERC approval. As of the date of this Report, the FERC has not noticed a proposed rulemakingproceeding or otherwise invited public comment.

• Revised Reliability Standard: PRC-010-1 (RM15-12)

On February 6, NERC filed for approval PRC-010-1 (Undervoltage Load Shedding), a definition of“Undervoltage Load Shedding Program (UVLS Program)”, and associated VRFs and VSLs (together, the “UVLSChanges”). NERC stated that the purpose of the UVLS Changes is to “establish an integrated and coordinatedapproach to the design, evaluation, and reliable operation of UVLS Programs”. The UVLS Changes consolidaterequirements from four existing Reliability Standards70 into a single Reliability Standard. NERC requested thatthe UVLS Changes be approved, effective the first day of the first calendar quarter that is one year after the dateof FERC approval. As of the date of this Report, the FERC has not noticed a proposed rulemaking proceeding orotherwise invited public comment.

• New Reliability Standard: TPL-007-1 (RM15-11)

On January 21, 2015, NERC filed for approval a new Reliability Standard -- TPL-007-1 (GeomagneticDisturbance Operations) -- and one new definition (Geomagnetic Disturbance Vulnerability Assessment),associated VRFs and VSLs (together, the “GMD Operations Changes”). NERC stated that the GMD OperationsChanges address the FERC’s directive in Order 779 that NERC develop a Reliability Standard that requiresowners and operators of the Bulk-Power System to conduct initial and on-going vulnerability assessments of thepotential impact of benchmark geomagnetic disturbance events on the Bulk-Power System equipment and theBulk-Power System as a whole.71 NERC requested the FERC approve a five-year phased implementation planfor compliance with TPL-007-1. As of the date of this Report, the FERC has not noticed a proposed rulemakingproceeding or otherwise invited public comment.

• NOPR: Revised Reliability Standard: PRC-005-4 (RM15-9)

On April 16, 2015, the FERC issued a NOPR proposing to approve changes to PRC-005-4 (ProtectionSystem, Automatic Reclosing, and Sudden Pressure Relaying Maintenance), one new (Sudden Pressure Relaying)and four revised definitions (Protection System Maintenance Program, Component Type, Component, andCountable Event), and the associated VRFs and VSLs (together, the “PRC-005 Changes”).72 As previouslyreported, NERC stated that the PRC-005 Changes address FERC concerns expressed in the Order 758 proceedingthat NERC’s proposed interpretation of PRC-005-1 may not include all components that serve in some protectivecapacity.73 NERC requested that the PRC-005 Changes be approved, effective on the first day of the firstcalendar quarter following FERC approval. Comments on this NOPR are due on or before June 22, 2015.74

• Revised Reliability Standard: PRC-026-1 (RM15-8)

On December 31, 2014, NERC filed for approval a new Standard, PRC-026-1 (Relay PerformanceDuring Stable Power Swings) and associated VRFs and VSLs (the “PRC-026 Standard”) in response to the

70 The currently effective Standards being replaced are PRC-010-0 (Assessment of the Design and Effectiveness ofUVLS Program); PRC-020-1 (Under-Voltage Load Shedding Program Database); PRC-021-1 (Under-Voltage LoadShedding Program Data); and PRC-022-1 (Under-Voltage Load Shedding Program Performance).

71 Reliability Standards for Geomagnetic Disturbances, Order No. 779, 143 FERC ¶ 61,147 (“Order 779”).

72 Protection System, Automatic Reclosing, and Sudden Pressure Relaying Maintenance Reliability Standard, 151FERC ¶ 61,026 (Apr. 16, 2015) (“Protection System NOPR”).

73 Interpretation of Protection System Reliability Standard, Notice of Proposed Rulemaking, 133 FERC ¶ 61,223(2010) at P 11; Interpretation of Protection System Reliability Standard, Order No. 758, 138 FERC ¶ 61,094 (“Order 758”),order on reh’g, 139 FERC ¶ 61,227 (2012).

74 The Protection System NOPR was published in the Fed. Reg. on Apr. 22, 2015 (Vol. 80, No. 77) pp. 22,444-22,449.


Page 2341536280.150

FERC’s directive in Order 73375 to develop a Reliability Standard addressing undesirable relay operation due tostable power swings. NERC requested that PRC-026 be approved, effective as follows: R1 on the first day of thefirst full calendar year that is 12 months after FERC approval; R2-R4 on the first day of the first full calendar yearthat is 36 months after FERC approval. As of the date of this Report, the FERC has not noticed a proposedrulemaking proceeding or otherwise invited public comment.

• Revised Reliability Standard: EOP-011-1 (RM15-7)

On December 29, 2014, NERC filed for approval a new Standard, EOP-011-1 (Emergency Operations), arevised definition of “Energy Emergency”, and associated VRFs and VSLs (together, the “Emergency OperationsChanges”). NERC stated that the purpose of the Emergency Operations Changes is to address the effects ofoperating Emergencies by ensuring each Transmission Operator and Balancing Authority has developedOperating Plans to mitigate operating Emergencies, and that those plans are coordinated within a ReliabilityCoordinator Area. EOP-011-1 consolidates requirements from three existing Reliability Standards, EOP-001-2.1b, EOP-003.1, and EOP-003-2, into a single new Reliability Standard. NERC stated that the EmergencyOperations Changes address seven FERC directives from Order 693. NERC requested that the EmergencyOperations Changes be approved, effective on the first day of the first calendar quarter that is 12 months afterFERC approval. As of the date of this Report, the FERC has not noticed a proposed rulemaking proceeding orotherwise invited public comment.

• NOPR: Revised Reliability Standard: PRC-002-2 (RM15-4)

On April 16, 2015, the FERC issued a NOPR proposing to approve changes to PRC-002-2 (DisturbanceMonitoring and Reporting Requirements), associated VRFs and VSLs, and the retirement of PRC-002-1 (DefineRegional Disturbance Monitoring and Reporting Requirements) and PRC-018-1 (Disturbance MonitoringEquipment Installation and Data Reporting) (together, the “PRC-002 Changes”).76 As previously reported, NERCstated that the PRC-002 Changes address FERC concerns expressed in Order 69377 with the “fill in the blank”aspects in PRC-002-1 and PRC-018-1.78 NERC requested that the PRC-002 Changes be approved, effective onthe first day of the first calendar quarter six months following FERC approval. Comments on this NOPR are dueon or before June 22, 2015.79

• Order 802: New Reliability Standard: CIP-014-1 (Physical Security) (RM14-15)

On April 23, 2015, the FERC denied rehearing of Order 802.80 As previously reported, the FERCapproved, in Order 802, NERC’s Physical Security Reliability Standard (CIP-014-1).81 CIP-014 is designed toenhance physical security measures for the most critical Bulk-Power System facilities and thereby lessen theoverall vulnerability of the Bulk-Power System to physical attacks. CIP-014 requires Transmission Owners andTransmission Operators to protect those critical Transmission stations and Transmission substations, and their

75 Transmission Relay Loadability Reliability Standard, Order No. 733, 130 FERC ¶ 61,221 (2010); order on reh’gand clarif., Order No. 733-A, 134 FERC ¶ 61,127 (2011); clarified, Order No. 733-B, 136 FERC ¶ 61,185 (2011) (“Order733”).

76 Disturbance Monitoring and Reporting Requirements Reliability Standard, 151 FERC ¶ 61,042 (Apr. 16, 2015)(“PRC-002 NOPR”).

77 Mandatory Reliability Standards for the Bulk-Power System, Order No. 693, 72 FR 16416, FERC Stats. & Regs.¶ 31,242, at PP 1131-1222, order on reh’g, Order No. 693-A, 120 FERC ¶ 61,053 (2007) (“Order 693”).

78 Interpretation of Protection System Reliability Standard, Notice of Proposed Rulemaking, 133 FERC ¶ 61,223(2010) at P 11; Interpretation of Protection System Reliability Standard, Order No. 758, 138 FERC ¶ 61,094 (“Order 758”),order on reh’g, 139 FERC ¶ 61,227 (2012).

79 The PRC-002 NOPR was published in the Fed. Reg. on Apr. 22, 2015 (Vol. 80, No. 77) pp. 22,441-22,444.

80 Physical Security Reliability Standard, 151 FERC ¶ 61,066 (Apr. 23, 2015).

81 Physical Security Reliability Standard, Order No. 802, 149 FERC ¶ 61,140 (Nov. 20, 2014) (“Order 802”), reh’gdenied, 151 FERC ¶ 61,066 (Apr. 23, 2015).


Page 2441536280.150

associated primary control centers that, if rendered inoperable or damaged as a result of a physical attack, couldresult in widespread instability, uncontrolled separation, or cascading within an Interconnection. CIP-014 alsoincludes requirements for: (i) the protection of sensitive or confidential information from public disclosure; (ii)third party verification of the identification of critical facilities as well as third party review of the evaluation ofthreats and vulnerabilities and the security plans; and (iii) the periodic reevaluation and revision of theidentification of critical facilities, the evaluation of threats and vulnerabilities, and the security plans to helpensure their continued effectiveness. CIP-014 will become effective June 1, 2015. In approving CIP-014, theFERC required NERC within six months of the effective date of the Rule,82 to remove the term “widespread”from the Standard or, alternatively, to propose modifications to the Reliability Standard that address the FERC’sconcerns. In addition, the FERC directed NERC to submit, by June 1, 2017, an informational filing that addresseswhether there is a need for consistent treatment of “High Impact” control centers for cyber security and physicalsecurity purposes through the development of Reliability Standards that afford physical protection to all “HighImpact” control centers.83 A request for rehearing of Order 802 was filed by the Foundation for ResilientSocieties (“FRS”), which identified as problematic: (i) exemptions for Reliability Coordinators (“RCs”),Balancing Authorities, and Generator Operators and Generator Owners; (ii) 2-year exemptions for high impactcontrol centers; (iii) FERC’s failure to address FRS’ comments on the critical role of RCs under the Standard; (iv)failure to require modeled contingency planning for physical attack scenarios; (v) lack of requirements forspecific security measures for critical grid facilities; and (vi) failure to address FRS’ cost-effectiveness comments.As noted above, on April 23, the FERC denied the FRS rehearing request.

• Order 808: Revised Reliability Standard: COM-001-2 and COM-002-4 (RM14-13)

On April 16, the FERC approved changes to COM-1 (Communications) and COM-2 (OperatingPersonnel Communications Protocols) (together, “COM Changes”).84 In addition, the FERC directed NERC todevelop a modification to Reliability Standard COM-001-2 that addresses internal communications capabilitiesthat could involve the issuance or receipt of Operating Instructions or other communications that could have animpact on reliability.85 As previously reported, COM-001 establishes a clear set of requirements for whatcommunications capabilities various functional entities must maintain for reliable communications. COM-002improves communications surrounding operating instructions by setting predefined communications protocols,requiring use of the same protocols regardless of the current operating condition (whether normal, alert, andEmergency operating conditions), and requiring entities to reinforce the use of the documented communicationprotocols through training, assessment, and feedback. The COM Changes will become effective as of July 1,2016 (the first day of the first calendar quarter that is 12 months after the date that the COM Changes wereapproved by the FERC). Challenges, if any, to Order 808 will be due on or before May 18, 2015.

• Order 810: Revised Reliability Standard: BAL-001-2 (RM14-10)

Also on April 16, the FERC approved changes to BAL-001-2 (Real Power Balancing ControlPerformance) (“BAL-001 Changes”).86 In addition, the FERC required NERC (i) to submit an informationalfiling addressing the impact of the proposed Reliability Standard on inadvertent interchange and unscheduledpower flows and (ii) to revise the definition of Reporting ACE.87 As previously reported, the BAL-001 Changesadd a frequency component to the measurement of a Balancing Authority’s Area Control Error (“ACE”) andallow for the formation of “Regulation Reserve Sharing Groups.” The BAL-001 Changes will become effectiveJune 1, 2016. Challenges, if any, to Order 810 will be due on or before May 18, 2015.

82 Order 802 was published in the Fed. Reg. on Nov. 25, 2014 (Vol. 79, No. 227) pp. 70,069-70,085.

83 Id. at P 57.

84 Communications Rel. Standards, Order No. 808, 151 FERC ¶ 61,039 (Apr. 16, 2015) (“Order 808”).

85 Id. at P .

86 Real Power Balancing Control Performance Rel. Standard, Order No. 810, 151 FERC ¶ 61,048 (“Order 810”).

87 Id. at P 20.


Page 2541536280.150

• NOPR: Revised Reliability Standard: MOD-001-2 (RM14-7)

The MOD-001-2 NOPR remains pending before the FERC. On June 19, 2014, the FERC issued a NOPRproposing to approve changes to MOD-001-2 (Modeling, Data, and Analysis - Available Transmission SystemCapability) (“MOD Changes”) proposed by NERC. The MOD Changes replace, consolidate and improve uponthe Existing MOD Standards in addressing the reliability issues associated with determinations of AvailableTransfer Capability (“ATC”) and Available Flowgate Capability (“AFC”). MOD-001-2 will replace the sixExisting MOD Standards88 to exclusively focus on the reliability aspects of ATC and AFC determinations. NERCrequested that the revised MOD Standard be approved, and the Existing MOD Standards be retired, effective onthe first day of the first calendar quarter that is 18 months after the date that the proposed Reliability Standard isapproved by the FERC. NERC explained that the implementation period is intended to provide NAESB sufficienttime to include in its WEQ Standards, prior to MOD-001-2’s effective date, those elements from the ExistingMOD Standards, if any, that relate to commercial or business practices and are not included in proposed MOD-001-2. The FERC seeks comment from NAESB and others whether 18 months would provide adequate time forNAESB to develop related business practices associated with ATC calculations or whether additional time may beappropriate to better assure synchronization of the effective dates for the proposed Reliability Standard andrelated NAESB practices. The FERC also seeks further elaboration on specific actions NERC could take to assuresynchronization of the effective dates. Comments on this NOPR were due August 25, 2014,89 and were filed byNERC, Bonneville, Duke, MISO, and NAESB. Since the last Report, NAESB supplemented its comments with areport on its efforts to develop WEQ Business Practice Standards that will support and coordinate with the MODStandards proposed in this proceeding. As noted above, the MOD-001-2 NOPR remains pending before theFERC.

• NOPR: BAL-002-1a Interpretation Remand (RM13-6)

This May 16, 2013 NOPR, which proposes to remand NERC’s proposed interpretation of BAL-002(Disturbance Control Performance Reliability Standard) filed February 12, 2013 (which would prevent RegisteredEntities from shedding load to avoid possible violations of BAL-002), remains pending.90 NERC asserted that theproposed interpretation clarifies that BAL-002-1 is intended to be read as an integrated whole and relies in part oninformation in the Compliance section of the Reliability Standard. Specifically, the proposed interpretation wouldclarify that: (1) a Disturbance that exceeds the most severe single Contingency, regardless if it is a simultaneousContingency or non-simultaneous multiple Contingency, would be a reportable event, but would be excludedfrom compliance evaluation; (2) a pre-acknowledged Reserve Sharing Group would be treated in the samemanner as an individual Balancing Authority; however, in a dynamically allocated Reserve Sharing Group,exclusions are only provided on a Balancing Authority member by member basis; and (3) an excludableDisturbance was an event with a magnitude greater than the magnitude of the most severe single Contingency.The FERC, however, proposes to remand the proposed interpretation because it believes the interpretationchanges the requirements of the Reliability Standard, thereby exceeding the permissible scope for interpretations.Comments on the BAL-002-1a Interpretation Remand NOPR were due on or before July 8, 2013,91 and were filedby NERC, EEI, ISO/RTO Council, MISO, NC Balancing Area, Northwest Power Pool Balancing Authorities,NRECA, and WECC. This NOPR remains pending before the FERC.

88 The 6 existing MOD Standards to be replaced by MOD-001-2 are: MOD-001-1, MOD-004-1, MOD-008-1,MOD-028-2, MOD-029-1a and MOD-030-2.

89 The MOD-001-2 NOPR was published in the Fed. Reg. on June 26, 2014, (Vol. 79, No. 123) pp. 36,269-36,273.

90 Electric Reliability Organization Interpretation of Specific Requirements of the Disturbance ControlPerformance Standard, 143 FERC ¶ 61,138 (2013) (“BAL-002-1a Interpretation Remand NOPR”).

91 The BAL-002-1a Interpretation Remand NOPR was published in the Fed. Reg. on May 23, 2013 (Vol. 78, No.99) pp. 30,245-30,810.


Page 2641536280.150

XI. Misc. - of Regional Interest

• 203 Application: CSC/AIA Energy (EC15-122)

On April 15, CSC and AIA Energy North America LLC (“AIA Energy”) requested FERC authorizationfor a transaction whereby CSC will become an indirect, wholly-owned subsidiary of AIA Energy (and no longer aRelated Person of Brookfield Energy Marketing). An order by June 3, 2015 approving the transaction wasrequested. Comments on this filing are due on or before May 6, 2015. If there are questions on this matter,please contact Pat Gerity (860-275-0533; [email protected]).

• 203 Application: Iberdrola/CMP/ Emera (EC15-103)

On March 25, Iberdrola92 and UIL Holdings Corp (“UI”) requested FERC authorization for a transactionwhereby UI will become an indirect, wholly-owned subsidiary of Iberdrola, S.A (and a Related Person of CentralMaine Power Company, Iberdrola Renewables, LLC, and New York State Electric & Gas Corporation).Eversource filed a doc-les intervention; no comments were filed. This matter is pending before the FERC. Ifthere are questions on this matter, please contact Pat Gerity (860-275-0533; [email protected]).

• Riggs v. RI PUC II: Deepwater Wind FPA/PURPA/Supremacy Clause Complaint (EL15-61)

On April 21, Benjamin C. Riggs, Jr. (“Riggs”) filed a second complaint relating to the August 16, 2010approval by the RI PUC of a 20-year Power Purchase Agreement (“PPA”) between Deepwater Wind BlockIsland, LLC (“Deepwater Wind”) and National Grid.93 In the most recent April 21 complaint, Riggs seeks FERCdeclaratory and injunctive relief barring the implementation of the PPA on the grounds that the PPA violates theFPA, PURPA, and the Supremacy Clause of the US Constitution. Responses to, and comments on, this complaintare due on or before May 12, 2015. If there are questions on this proceeding, please contact Pat Gerity (860-275-0533; [email protected]).

• LVA/PSNH IA Complaint (EL15-9)

The complaint filed by Lower Village Hydroelectric Associates (“LVA”) against PSNH requestingFERC direct PSNH to recognize the existing LVA IA, rescind its demand for LVA facility modifications, andclose the air break switch so LVA can complete relay testing and resume generating/ selling electricity,remains pending. As previously reported, PSNH responded to the October 23, 2014 Complaint on December11, 2014, urging the FERC to dismiss the Complaint. LVA answered PSNH’s response on December 26 andPSNH answered LVA’s answer on January 9, 2015. This matter remains pending before the FERC. If youhave any questions concerning this Complaint, please contact Pat Gerity ([email protected]; 860-275-0533).

• FirstEnergy PJM DR Complaint (EL14-55)

On May 23, 2014, the same day that DC Circuit vacated Order 745 (see Section XV below),FirstEnergy filed a complaint against PJM requesting that the FERC require the “removal of all portions ofthe PJM Tariff allowing or requiring PJM to include demand response as suppliers to PJM’s capacitymarkets.” FirstEnergy also requested that the results of the PJM capacity auction due to be released that sameday, to the extent it included and cleared demand response resources, be considered void and legally invalid.PJM’s response, and all comments and interventions were initially due on or before June 12, 2014. However,on June 11, the FERC extended that date to 30 days after the submission by FirstEnergy of an amendedcomplaint. FirstEnergy filed its amended complaint on September 22, 2014.

92 For purposes of this proceeding, “Iberdrola” is Iberdrola, S.A., Iberdrola USA, Inc., Iberdrola USA Networks,Inc., and Green Merger Sub.

93 In the first complaint, filed Aug. 22, 2012 in Docket No. EL12-100 (“Riggs I”), Riggs asserted that the PPAviolated the “avoided cost” provisions of PURPA and would produce rates that are not “just and reasonable” and “in thepublic interest”. On Oct. 18, the FERC issued a notice of intent not to act on Riggs I.


Page 2741536280.150

Comments on the FirstEnergy Complaint were due October 22, 2014. More than 40 parties filedcomments or responses to the FirstEnergy amended complaint. Many parties filed comments supporting thecomplaint (including Calpine, PSEG and PPL), while others opposed the complaint in its entirety (includingDirect Energy and Enerwise). PJM’s response argued that the complaint failed to justify the marketdisruption that would result from recalculating past capacity auction results, PJM was instead more focusedon minimizing “litigation risk.” A number of parties filed supporting comments in favor of removing demandresponse resources from the PJM tariff moving forward, but opposed to recalculating the results of pastcapacity auctions (including Exelon, the PJM IMM and NRG). Comments were also filed by National Gridand NYISO. A number of New England parties intervened, including NEPOOL (stressing that the FERCshould not apply any ruling in this docket to the New England Market), Dominion, Duke Energy, Dynegy,Essential Power, Macquarie Energy, NEPGA, NESCOE, and NextEra. On November 14, FirstEnergy filedan answer to the answers, protests and comments submitted in response to its Complaint and AmendedComplaint. Environmental Advocates94 filed an answer to FirstEnergy’s answer on November 21. Since thelast Report, CPower and Advanced Energy Management Alliance filed answers to the FirstEnergy and otheranswers and pleadings. On December 23, Environmental Advocates moved to lodge the US SolicitorGeneral’s application for an extension of time in which to file a petition for writ of certiorari, the SupremeCourt Clerk’s notice to the DC Circuit that the extension had been granted, and the DC Circuit’s orderextending the stay of its mandate pending the Supreme Court’s final disposition of the writ of certiorari. Thismatter remains pending before the FERC. If you have any questions concerning this matter, please contactJamie Blackburn ([email protected]; 202-218-3905) or Pat Gerity ([email protected]; 860-275-0533).

• IAs – CMP/Brookfield/FPL Energy (ER15-1553 et al.)

On April 22, CMP filed four, non-conforming95 interconnection agreements to replace a single“Continuing Site/Interconnection Agreement” (“CSIA”) originally between CMP and NextEra Energy Maine,LLC. The filings segment currently operating facilities from the CSIA, put in place four new Agreements,between CMP and each of the corresponding owners of the facilities previously covered under the CSIA, andcancel the CSIA. CPM states that the new Agreements are modeled after, and are consistent with, the CSIA.The agreements and notice of cancellation were docketed as follows:

IA - CMP-Brookfield White Pine Hydro (ER15-1549) covering Androscoggin Lower, Bar MillsHydro, Bates Lower/Continental, Bates Upper, Bonny Eagle, Brunswick Hydro, CataractHydro/Factory Island, Lockwood Hydro, Harris Hydro, Hill Mill, Hiram, Monty Hydro, NorthGorham Hydro, Shawmut Hydro, West Buxton Hydro, and Williams Hydro.

IA - CMP-Cape (ER15-1551) covering the Cape Station generating facility located in South Portland,Maine.

IA - CMP-Wyman (ER15-1552) covering Wyman Unit Nos. 1-3 located in Yarmouth, Maine.

IA - CMP-Wyman IV (ER15-1553) covering Wyman Unit No. 4 also located in Yarmouth.

CMP CSIA Notice of Cancellation (ER15-1448).

An April 14, 2015 effective date was requested for the notice of cancellation and each of theagreements, other than the Brookfield White Pine Hydro agreement (which is to have a March 23, 2015effective date). Comments on this matter are due on or before May 13, 2015. If there are questions on thesematters, please contact Pat Gerity (860-275-0533; [email protected]).

94 “Environmental Advocates” are Sustainable FERC Project, Natural Resources Defense Council (“NRDC”),Sierra Club, Environmental Defense Fund, Environmental Law and Policy Center, and Acadia Center (f/k/a EnvironmentNortheast).

95 Because the IAs continue existing interconnection arrangements, the submission of the IAs does not constitute anew “Interconnection Request” or require a new three-party IA (and, as a two-party agreement, is a non-conforming SGIA).


Page 2841536280.150

• Termination of Braintree Participation in REMVEC II Agreement (ER15-1530)

On April 17, National Grid made a filing to reflect Braintree’s termination of its participation in theREMVEC II Agreement, effective as of April 30, 2015. As previously reported, the FERC accepted, inER15-1040, a Local Control Center (“LCC”) Services Agreement between NSTAR and Braintree ElectricLight Department (“Braintree”) that sets the terms pursuant to which NSTAR will operate and maintain aLCC to operate Braintree’s transmission facilities, implement the instructions, orders and directions receivedfrom the ISO related to the Braintree facilities, and perform other central dispatch functions all as delineatedin and required under the TOA. Comments on this filing, if any, are due on or before May 8. If there arequestions on this matter, please contact Pat Gerity (860-275-0533; [email protected]).

• CL&P Amended Wholesale Distribution Service Agreement with CMEEC (ER15-1525)

On April 17, NU, on behalf of The Connecticut Light and Power Company (“CL&P”), filed anamended Wholesale Distribution Service Agreement (“WDSA”) between itself and CMEEC to eliminatecertain delivery points and their associated rates for wholesale distribution service. The amendments are dueto the fact that the Third Taxing District of the City of Norwalk, CT is now directly connected to PTF andtakes RNS Service under the ISO-NE Tariff. A June 16, 2015 effective date was requested. Comments onthis filing are due on or before May 8. If there are questions on this matter, please contact Pat Gerity (860-275-0533; [email protected]).

• EPC Agreement: Blue Sky West & Emera Maine (ER15-1459)

On April 7, Emera Maine filed an executed Engineering, Procurement, and Construction Agreement(“EPC Agreement”) Agreement with Blue Sky West, LLC (“Blue Sky West”) to facilitate the interconnectionof the Blue Sky West’s 191 MW wind farm in Bingham, Mayfield Township and Kingsbury Plantation,Maine. While the Blue Sky West facility will be located in CMP’s service territory, upgrades andmodifications at Orrington Substation, in part owned by Emera Maine, are required and will be covered underthe EPC Agreement. A March 6, 2015 effective date was requested. SunEdison filed a doc-less intervention.No comments on the EPC Agreement filing were submitted before the April 28 comment date. This matter ispending before the FERC. If there are questions on this matter, please contact Pat Gerity (860-275-0533;[email protected]).

• Emera MPD OATT Changes (ER15-1429)

On April 1, Emera Maine filed changes to the Open Access Transmission Tariff (“OATT”) for MainePublic District (“MPD OATT”), including to the rates, terms, and conditions set forth in MPD OATTAttachment J. Emera Maine, as successor to Maine Public Service Company (“Maine Public”), providesopen access to Emera Maine’s transmission facilities in northern Maine (the “MPD Transmission System”)pursuant to the MPD OATT. The changes to the MPD OATT are needed to ensure that, in light of the filingby Emera of consolidated FERC Form 1 data (data comprising both the former Bangor Hydro and MainePublic systems), charges for service under the MPD OATT reflect only the costs of service over the MPDTransmission System. Emera Maine also proposed additional, limited changes to the MPD OATT. A June 1,2015 effective date was requested. On April 9, the “Maine Customer Group”96 filed a motion to reject(“Motion to Reject”) the April 1 Filing, asserting the April 1 Filing was deficient because, rather than actualrates, it included proxy rates that MPD said would be replaced with 2014 Form 1 numbers when MPD’s 2014Form 1 was available. On April 22, the Maine PUC and the Maine Customer Group protested the filing. TheMPUC challenged three aspects of the filing: (i) the proposed increase of ROE from 9.75% to 10.20% basedon anomalous economic conditions; (ii) the change from a measured loss factor calculation to a fixed lossfactor; and (iii) the use of end-of-year account balances, rather than average 13-month account balances, fordetermination of facilities that are included in rate base. In addition to those aspects, the Maine CustomerGroup further challenged: (iv) inclusion of an out-of-period adjustment to rate base for forecasted

96 The “Maine Customer Group is comprised of: the Maine Office of the Public Advocate (“MOPA”), HoultonWater Company (“Houlton”), Van Buren Light and Power District (“Van Buren”), and Eastern Maine Electric Cooperative,Inc. (“EMEC”).


Page 2941536280.150

transmission; (v) the proposed capital structure, which they assert is artificially distorted to accommodate arequirement resulting from the merger of Emera Maine’s predecessor companies; and (vi) the proposed newcost allocation scheme. On April 29, Emera Maine answered the Maine PUC and Customer Group protests.This matter is pending before the FERC.

• Emera Maine MPD OATT Order 676-H Compliance Filing (ER15-1419)

On March 31, Emera Maine submitted an Order 676-H compliance filing, and requested waiver ofcertain standards not applicable to, the Maine Public District OATT. A May 15, 2015 effective date wasrequested. Comments on this filing were due on or before April 21, 2015; none were filed. On April 28,Emera Maine amended its filing to withdraw its request for waiver of NAESB business practice standardWEQ-012. This matter is pending before the FERC.

• NSTAR/HQ US CMEEC Use Rights Transfer Agreement (ER15-1383)

On March 26, NSTAR filed an agreement by which it will transfer CMEEC’s use rights over thePhase I/II HVDC facilities to HQUS (CMEEC itself does not have a mechanism to effectuate the transfer). AMay 26, 2015 effective date was requested. Comments on this filing were due on or before April 16, 2015.On April 16, CMEEC filed comments requesting that the Agreement be accepted as of March 26, 2015, thedate the Agreement was filed, rather than on May 16. CMEEC indicated that the earlier effective date wouldbetter effectuate the intent of CMEEC in entering into the Transfer Agreement with NSTAR in the firstinstance. CMEEC further indicated that NSTAR and HQUS did not object to the earlier effective date. Thismatter is pending before the FERC. If there are questions on this matter, please contact Eric Runge (617-345-4735; [email protected]).

• HG&E Demarcation Agreement (ER15-939)

On January 30, WMECO filed a revised Asset Demarcation Agreement by and between WMECOand Holyoke Gas and Electric Department (“HG&E”). The Agreement established the parties agreement onthe demarcation of ownership of their respective electric transmission facilities, and the revisions reflect therecent construction by HG&E of a new transmission substation. WMECO requested that the Agreement beaccepted for filing as of January 5, 2015. Comments on this filing were due on or before February 20, 2015;none were filed. On March 17, as supplemented on March 18, Eversource filed a complete copy of theRevised Agreement as requested by FERC Staff. Final comments were due on or before April 8; none werefiled. This matter is again pending before the FERC. If there are questions on this matter, please contact PatGerity (860-275-0533; [email protected]).

• Opinion 531-A Compliance Filing: National Grid IFA Amendments (ER15-418)

On April 16, the FERC rejected changes proposed by New England Power’s (“National Grid”) to theformula rates for integrated facilities service (“IFA Amendments”) under Schedule III-B of National Grid’sTariff No. 1.97 The FERC found the IFA Amendments “inconsistent with the Commission’s policy on thecapping of incentive ROE adders and the Commission’s directive in Opinion No. 531-A, on which the relatedROE changes in the ISO-NE OATT will be based.”98 It found the proposed tariff language would allowNational Grid to average the equity returns of various transmission assets in its portfolio for purposes ofapplying the 11.74 percent cap on its incentive ROE adders” and thereby “earn an equity return on certainassets, for which incentive ROE adders have been granted, at a level that exceeds the zone of reasonablenessproduced by the discounted cash flow methodology.” The interpretation of “total ROE” used by NationalGrid was used and rejected in Opinion 531-B.99 National Grid must submit another tariff filing to conformthe ROE components of Schedule III-B of Tariff No. 1 to the ISO-NE OATT, using 2013 data for its Period 1

97 New England Power Co., 151 FERC ¶ 61,028 (Apr. 16, 2015).

98 Id. at P 12.

99 Id. at P 13.


Page 3041536280.150

requirements. If there are questions on this matter, please contact Pat Gerity (860-275-0533;[email protected]).

• MISO Methodology to Involuntarily Allocate Costs to Entities Outside Its Control Area(ER11-1844)

On December 18, 2012, Judge Sterner issued his 374-page initial decision which, following hearingsdescribed in previous reports, found at its core that “it is unjust, unreasonable, and unduly discriminatory toallocate costs of Phase Angle Regulating Transformers (“PARs”) of the International Transmission Company(“ITC”) to NYISO and PJM”,100 which the Midwest ISO (“MISO”) and ITC proposed unilaterally to do(without the support of either PJM or NYISO) in its October 20, 2010 filing initiating this proceeding. For asummary of specific findings, please refer to any of the January to June 2013 Reports.

On January 17, 2013, ITC and MISO challenged the Initial Decision through their Brief onExceptions. Briefs opposing exceptions were filed by the FERC Trial Staff, MISO TOs, NYISO, NY TOs,PJM, and the PJM TOs. On February 25, Joint Applicants moved to strike a portion of the PJM BriefOpposing Exceptions. On March 12, PJM answered Joint Applicants February 25 motion. MISO (nowcalled “Midcontinent Independent System Operator, Inc.”) moved to lodge a NYISO “Broader RegionalMarkets Informational Report” filed March 19, 2014 in ER08-1281 and a related January 16, 2014 “Ontario-Michigan Interface PAR Performance Evaluation Report” (“Evaluation Report”) prepared by MISO, IESOand PJM. Oppositions to that motion to lodge were filed by FERC Staff, NYISO, NY TOs, PJM, and PSEG.This matter remains pending before the FERC. If there are any questions on this matter, please contact EricRunge (617-345-4735; [email protected]).

• FERC Enforcement Action: City Power Marketing and Tsingas (IN15-5)

On March 6, 2015, the FERC issued an order directing City Power Marketing, LLC (“City Power”)and K. Stephen Tsingas (“Tsingas”, and together with City Power, the “City Power Respondents”) to showcause (i) why they should not be found to have violated the FERC’s Anti-Manipulation Rules by engaging infraudulent Up To Congestion (“UTC”) transactions in PJM’s energy markets and (ii) why they should not bejointly and severally required to disgorge unjust profits of $1,278,358 and to be jointly and severally assessed$15 million in civil penalties (City Power ($14 million) and Tsingas ($1 million)).101 As previously reported,Enforcement Staff alleges that (i) City Power and Tsingas violated the FERC’s Anti-Manipulation Rule byengaging in manipulative Up To Congestion trading in PJM during July 2010; and (ii) City Power violatedthe FERC’s market behavior rules (18 C.F.R. § 35.41 (2014)) by making false statements and omittingmaterial information during the investigation. On April 7, City Power Respondents responded to the ShowCause Order and invoked their statutory rights to prompt assessment of a penalty and a de novo review of thatpenalty in federal district court. On April 20, Office of Enforcement Litigation Staff (“Enforcement”) filed amotion to revise the briefing schedule set in the City Power Mktg Show Cause Order. On April 21, the FERCdenied that motion.

On April 1, as it did in the Powhatan proceeding, PJM submitted comments requesting FERCguidance with respect to certain matters should disgorgement be ordered in this proceeding. (See IN15-3below for details.) City Power Respondents responded to PJM’s comments on April 23. This matter ispending before the FERC. If you have any questions concerning this matter, please contact Pat Gerity (860-275-0533; [email protected]).

• FERC Enforcement Action: Maxim Power and K. Mitton (IN15-4)

On February 2, 2015, the FERC issued an order directing Maxim Power (USA), Inc., Maxim Power(USA) Holding Company Inc., Pawtucket Power Holding Co., LLC, Pittsfield Generating Company, LP, and

100 Midwest Indep. Trans. Sys. Op., Inc., 141 FERC ¶ 63,021 (Dec. 18, 2012) (“MISO Initial Decision”) at P 923.

101 City Power Mkt’g, LLC and K. Stephen Tsingas, 150 FERC ¶ 61,176 (Mar. 6, 2015) (“City Power Mktg ShowCause Order”).


Page 3141536280.150

Kyle Mitton (collectively, “Maxim Respondents”)102 to show cause (i) why they should not be found to haveviolated the FERC’s Anti-Manipulation Rules through a scheme to obtain payments for reliability dispatchesbased on the price of expensive fuel oil when Maxim in fact burned much less costly natural gas; and (ii) whythey should not be assessed civil penalties as follows: Maxim and its affiliates ($5 million civil penalty,jointly and severally); and K. Mitton ($50,000 civil penalty).103 As previously reported, Enforcement Staffalleges that Maxim engaged in three schemes in New England that violated the FERC’s Anti-ManipulationRule. In the first, during 2012-13, Maxim received millions of dollars of inflated make-whole payments fromthe ISO by gaming Market Rules intended to mitigate the market power of generators needed for reliability; inthe second, July-August 2010, staff alleges that Maxim told the ISO it needed to offer based on high oil pricesbecause of supposed gas supply problems, and collected make-whole payments based on those high prices,but in fact burned much less expensive gas. In many cases Maxim had already purchased gas when itsubmitted Day-Ahead offers based on oil prices because of supposed gas supply issues; in the third, 2010-2013, Maxim obtained inflated capacity payments by artificially raising the reported output of three of itsplants by employing extraordinary measures during capacity tests that it did not use, and did not intend to use,during the ordinary operation of the plants. Staff also alleged that Maxim executives John Bobenic and KyleMitton engaged in certain of these schemes, and that Maxim also violated the FERC’s Market Behavior Rulesthrough schemes two and three.

On February 18, Maxim Respondents requested an extension of time, until March 30, 2015, to submittheir answer to the Maxim Show Cause Order, stating that that additional time was needed to prepare aresponse to OE’s report and accompanying documents. On February 20, 2015, Enforcement Staff filed aresponse opposing the Maxim Respondents’ motion. On February 24, the FERC denied the MaximRespondents’ motion for an extension of time. On March 4, 2015, the Maxim Respondents filed answers tothe Maxim Show Cause Order. On March 23, Enforcement Litigation Staff replied to the MaximRespondents’ March 4 answers. The Maxim Respondents replied to the Staff’s reply on April 6. Since thelast Report, Maxim Respondents supplemented, on April 14, their April 6 reply. This matter is pendingbefore the FERC. If you have any questions concerning this matter, please contact Pat Gerity (860-275-0533;[email protected]).

• FERC Enforcement Action: Powhatan Energy, HEEP Fund, CU Fund, and Chen (IN15-3)

On December 17, 2014, the FERC issued an order directing Houlian “Alan” Chen, HEEP Fund, Inc.,CU Fund, Inc., and Powhatan Energy Fund, LLC (together, “Powhatan Respondents”) to show cause (i) whythey should not be found to have violated the FERC’s Anti-Manipulation Rules by engaging in fraudulentUTC transactions in PJM’s energy markets and (ii) why they should not disgorge unjust profits with interestand be assessed civil penalties as follows: Powhatan Energy Fund ($16.8 million civil penalty; $3.47 milliondisgorgement); CU Fund: ($10.08 million civil penalty; $1.08 million disgorgement); HEEP Fund ($1.92million civil penalty; $173,100 disgorgement); H. Chen ($1 million civil penalty for trades executed throughand on behalf of Powhatan and the Funds).104 As previously reported, Enforcement Staff alleges that,between June and August 2010, Powhatan Respondents engaged in manipulative Up To Congestion trading inPJM, trades which amounted to wash trading, long prohibited by the FERC. Specifically, Staff alleges thatthe transactions were designed to falsely appear to be spread trades, as a vehicle for collecting Marginal LossSurplus Allocation (“MLSA”) payments from PJM, by placing millions of megawatt hours of offsettingtrades between the same two trading points, in the same volumes and the same hours—an intentional effort tocancel out the financial consequences from any spread between the two trading points while capturing large

102 Maxim’s Related Person, Pawtucket Power Holding Company, is a member of the Generation Sector GroupSeat. In addition to Pawtucket, Maxim operates units in Pittsfield, MA and Hartford, CT (Capitol District Energy CenterCogeneration Associates).

103 Maxim Power Corp. et al., 150 FERC ¶ 61,068 (Feb. 2, 2015) (“Maxim Show Cause Order”).

104 Houlian Chen, Powhatan Energy Fund, LLC, HEEP Fund, LLC, and CU Fund, Inc., 149 FERC ¶ 61,261 (Dec.17, 2014), as revised, 149 FERC ¶ 61,263 (Dec. 18, 2014) (“Powhatan Show Cause Order”).


Page 3241536280.150

amounts of MLSA payments. On December 31, the answer period was extended by the FERC, so thatPowhatan Respondents’ answers were due on or before February 2, 2015.

On January 12, Powhatan Respondents invoked their statutory rights to prompt assessment of apenalty and a de novo review of that penalty in federal district court. On January 27, Powhatan Respondentsrequested a two-week extension of time for its answers, citing a need to review yet-to-be disclosedexculpatory evidence. On January 29, FERC staff opposed the requested extension, but provided additionalmaterials. On January 30, the FERC denied the requested extension, but indicated that PowhatanRespondents would be permitted to provide by February 9 a supplemental answer in response to the materialsprovided with staff’s Jan 29 motion. Powhatan Respondents submitted their answers to the Powhatan ShowCause Order on February 2. The Powhatan Respondents provided a supplemental answer on February 9,noting that the data that they expected to see was not in what Enforcement produced and, therefore, itsFebruary 2 answers need not be further supplemented. Enforcement Staff responded to the February 2answers on March 2. In addition, on February 19, the Powhatan Respondents submitted a letter to the FERCCommissioners (other than Commissioner Bay, who did not participate in the Powhatan Show Cause Order)highlighting two post-order ex parte concerns. On March 3, Enforcement replied to the answers provided byPowhatan Respondents.

On March 18, Chen replied to OE’s March 3 materials. On April 1, PJM submitted commentsrequesting FERC guidance with respect to certain matters should disgorgement be ordered in this proceeding.Specifically, PJM requested that the FERC:

direct Staff be to provide PJM with a breakdown of the amount to be disgorged on an hourly basis,per Operating Day at issue

provide guidance regarding what PJM should do with refunds owed to entities that are no longerPJM Members

suspend any refund requirement, or direct or allow PJM to hold the disgorgement monies in escrow,until such time as a final order has been received from a court of competent jurisdiction if appealed

indicate the date from which interest should be calculated on the disgorgement, or provide PJM witha specific breakdown of the total amount due including interest, on an hourly basis from each of theRespondents.

specify in its order that any portion of the disgorged funds can be applied to reduce the amount ofany outstanding default

indicate whether the other entities referred to Enforcement in the same referral are entitled toreceive the portion of the disgorged funds or whether they should be excluded from any suchrefunds.

Since the last report, Powhatan Respondents responded to PJM’s April 1 comments on April 14. Inaddition, on April 23, Powhatan Respondents submitted a pleading highlighting portions of the ONEOKdecision (see Section XV below) that they asserted were relevant to their arguments in this proceeding. Thesematters remain pending before the FERC. If you have any questions concerning this matter, please contactPat Gerity (860-275-0533; [email protected]).

XII. Misc. - Administrative & Rulemaking Proceedings

• Technical Conferences on Implications of Environmental Regulations (AD15-4)

The FERC initiated this proceeding, on December 9, 2014, in order to discuss, in a series of technicalconferences, the implications of compliance approaches to the Environmental Protection Agency’s (“EPA”)


Page 3341536280.150

proposed Clean Power Plan issued June 2, 2014.105 A Commissioner-led National Overview technicalconference was held February 19. Three staff-led regional technical conferences, focused on issues related toelectric reliability, wholesale electric markets and operations, and energy infrastructure, were also held.106

Since the last Report, NERC submitted a chapter from its April 21 report entitled “Potential ReliabilityImpacts of EPA’s Proposed Clean Power Plan – Phase 1”. Additional comments were also submitted by AEPand Southern Company.

• Price Formation in RTO/ISO Energy & Ancillary Services Markets (AD14-14)

On June 19, 2014, the FERC initiated a proceeding to evaluate price formation issues in RTO/ISOenergy and ancillary services markets. In its notice, the FERC announced a series of staff workshops tofacilitate a discussion with market operators and their stakeholders on the existing market rules and operationalpractices related to:

use of uplift payments;

offer price mitigation and offer price caps;

scarcity and shortage pricing; and

operator actions that affect price.

Sep 8 Workshop. The FERC held its first workshop on September 8, 2014. The September 8workshop focused on the technical, operational and market issues that give rise to uplift payments and thelevels of transparency. The workshop also previewed the scope of the remaining price formation topics. Thewebcast of the September 8 workshop will be archived and available for 3 months on the FERC’s website athttp://ferc.capitolconnection.org/. Speaker materials have been posted in the FERC’s eLibrary. Also posted ineLibrary is a FERC staff report issued August 21 that analyzes “Uplift in RTO and ISO Markets.”

Oct 28 Workshop. The FERC held its second workshop on October 28, 2014. The October 28workshop focused on the technical, operational, and market issues related to offer price mitigation and offerprice caps, and scarcity and shortage pricing in energy and ancillary services markets operated by RTOs/ISOs.In advance of the workshop, FERC staff posted on October 21 two reports, one on shortage pricing inRTO/ISO markets (http://www.ferc.gov/legal/staff-reports/2014/AD14-14-pricingrto-iso-markets.pdf), theother on energy offer mitigation in RTO/ISO markets (http://www.ferc.gov/legal/staff-reports/2014/AD14-14-mitigation-rto-iso-markets.pdf).

Dec 9 Workshop. The third and final workshop was held on December 9. The December 9 workshopfocused on RTO/ISO operator actions that affect price. New England speakers included, among others, JoelGordon, Tom Kaslow, David Patton, Pete Brandein, and Matt White. Speaker materials are posted in theFERC’s eLibrary.

Post-Technical Workshop Comments. On January 16, the FERC invited all interested to file post-technical workshop comments on any or all of the 12 questions listed in the attachment to its January 16Notice, with any such comments due on or before February 19. A 15-day extension of time to file suchcomments, to and including March 6, was jointly requested by APPA, EPSA and NRECA. CAISO, NYISO,PJM and SPP jointly filed a motion supporting the trade associations’ request. On February 3, ISO-NE alsoasked for an extension of time, but only with respect to questions 5-12, but to and including March 20, 2015.

105 Carbon Pollution Emission Guidelines for Existing Stationary Sources: Electric Utility Generating Units, Noticeof Proposed Rulemaking, 79 Fed. Reg. 34,830 (June 18, 2014).

106 The Mar. 11 Eastern Region (New England, Northern Maine ISA, New York, PJM, SERTP, SCRTP, and theFRCC) conference included discussion of: (1) potential reliability impacts in each region under various complianceapproaches; (2) potential impacts on power system operations and generator dispatch in each region under variouscompliance approaches; and (3) potential impact on each region’s current or expected infrastructure (electric transmission,natural gas pipelines, generation, etc.) to address compliance with the proposed rule, and additional infrastructure that may berequired. Speaker materials and post-conference comments are posted on the FERC’s eLibrary.


Page 3441536280.150

On February 9, the FERC extended the deadline to submit comments to and including March 6, 2015. Sincethe last Report, nearly 40 sets of comments were submitted, including by: ISO-NE, APPA, Brookfield,Calpine, Direct Energy, EEI, EPSA, Exelon, and PSEG.

The FERC web page for this issue is at http://www.ferc.gov/industries/electric/indus-act/rto/energy-price-formation.asp.

• RTO/ISO Winter 2013/14 Operations and Market Performance (AD14-8)

On November 20, the FERC issued an order directing RTOs/ISOs to file reports on or before February18, 2015, on the status of their efforts to address fuel assurance issues.107 While the FERC noted that it “couldtake action to impose solutions, and may need to in the future if the steps RTOs/ISOs have taken or plan totake prove inadequate, [it found] that the appropriate next step is for each RTO/ISO to provide the [FERC]with additional information to explain how its market rules address fuel assurance challenges.”108 Since thelast Report, INGAA submitted comments related to the November 20 order.

On February 18, 2015, the RTOs/ISOs submitted their reports in compliance with the November 20order. In its report, ISO-NE highlighted a number of initiatives to address fuel assurance concerns. The ISOstated that the centerpiece of its efforts is the Pay-For-Performance PCM design, which will take full effect in2018. The ISO described its interim solutions, the two most recent Winter Reliability Programs and the yet-to-be-finally-determined program(s) to be implemented until PFP takes full effect. The ISO also identified thefollowing additional initiatives helping to address fuel assurance and generator performance issues: increasedRCPFs, Energy Market offer flexibility, clarification of generator fuel procurement obligations, Day-AheadEnergy Market timing changes, Replacement Reserves RCPF, information sharing with natural gas pipelines,fuel cost recovery in extraordinary circumstances, expansion of the FCM Shortage Event rigger, increasedfrequency of fuel surveys, and improvements to the ETU process. Comments on the RTO/ISO reports weredue on or before March 20 and were filed by over 15 parties, including by: EPSA, Eversource, Exelon,NESCOE, NHPUC, and UCS. On April 21, the Organization of MISO States submitted comments to addadditional detail on the activities related to fuel assurance that take place within regulatory commissions in theMISO footprint.

• NOPR: Third-Party Provision of Primary Frequency Response Service (RM15-2)

On February 19, the FERC issued a NOPR proposing to foster competition in the sale of primaryfrequency response service109 by permitting its sale at market-based rates by sellers with market-based rateauthority for energy and capacity. The FERC stated that this NOPR is an extension of its policy reforms begunwith Order 784110 and anticipates the potential interest in purchase of primary frequency response servicefrom third-parties as a result of a new reliability standard (BAL-003-1) that requires a Balancing Authority to

107 Winter 2013-2014 Operations and Market Performance in Regional Transmission Organizations andIndependent System Operators, 149 FERC ¶ 61,145 (Nov. 20, 2014). The FERC explained that “fuel assurance” describes“the broad set of issues that have emerged in the RTOs/ISOs with respect to generator access to sufficient fuel supplies andthe firmness of generator fuel arrangements. Fuel assurance is a broad concept that includes a range of generator-specific andsystem-wide issues, including the overall ability of an RTO’s/ISO’s portfolio of resources to access sufficient fuel to meetsystem needs and maintain reliability.” Fuel assurance may also “encompass impacts on fuel availability of any industry inthe supply chain, including contingencies and other risks stemming from those industries.”

108 Id. at P 19.

109 Primary frequency response service would be a reserve product that involves dedicating capacity on a generatoror other resource for autonomous, automatic, and rapid action to change its output (within seconds) to rapidly dampen largechanges in frequency.

110 Third-Party Provision of Ancillary Services; Accounting and Financial Reporting for New Electric StorageTechnologies, Order No. 784, 78 Fed. Reg. 46,178 (July 30, 2013), FERC Stats. & Regs. ¶ 31,349, at PP 6-7 (2013), order onclarif., Order No. 784-A, 146 FERC ¶ 61,114 (2014) (“Order 784”).


Page 3541536280.150

maintain a minimum frequency response obligation. Comments on this NOPR were due on or before April 27,2015111 and were filed by nearly 20 parties.

• NOPR: MBR Authorization Refinements (RM14-14)

On June 19, the FERC issued a NOPR proposing to revise its current standards, and to streamline certainaspects of its filing requirements, for obtaining market-based rates (“MBR”) for sales of electric energy, capacity,and ancillary services.112 In addition, the FERC clarified certain standards for obtaining and retaining MBRauthority. Among other changes, the FERC proposes (i) to permit sellers in RTO/ISO markets with Commission-approved market monitoring and mitigation to include a statement that they are relying on such mitigation toaddress any potential horizontal market power concerns in lieu of submitting the indicative screens; (ii) to permitsellers to explain that their qualified capacity is fully committed in lieu of including indicative screens in theirfilings in order to satisfy the FERC’s horizontal market power tests and to submit a change in status filing whenthere is a net increase of 100 MW or more; (iii) to relieve sellers of their obligation to file quarterly landacquisition reports and of the obligation to provide information on sites for generation capacity development inmarket-based rate applications and triennial updated market power analyses; (iv) to require a change in statusfiling if there is a 100 MW increase in cumulative nameplate capacity added in any relevant geographic market;and (v) require corporate org charts with all MBR applications and notices of change in status. Comments on thisNOPR were due September 23, 2014.113 Over 25 parties filed comments and Berkshire Hathaway, Barrick Mines,and EPSA filed reply comments. This NOPR is pending before the FERC.

• Order 807: Open Access and Priority Rights on ICIF (RM14-11)

On March 19, the FERC issued Order 807,114 which waives the Open Access Transmission Tariff(“OATT”) requirements of 18 CFR 35.28 (2013), the Open Access Same-Time Information System (“OASIS”)requirements of Part 37 of its regulations, 18 CFR 37 (2013), and the Standards of Conduct requirements of Part358 of its regulations, 18 CFR 358 (2013), for any public utility that is subject to such requirements solelybecause it owns, controls, or operates Interconnection Customer’s Interconnection Facilities (“ICIF”),115 in wholeor in part, and sells electric energy from its Generating Facility. Order 807 also finds that those seekinginterconnection and transmission service over ICIF that are subject to the blanket waiver adopted in Order 807may follow procedures applicable to requests for interconnection and transmission service under sections 210,211, and 212 of the FPA, which also allows the contractual flexibility for entities to reach mutually agreeableaccess solutions. Order 807 establishes a modified rebuttable presumption for a 5-year safe harbor period toreduce risks to ICIF owners eligible for the blanket waiver during the critical early years of their projects. Finally,Order 807 modifies several elements of the NOPR, including the entities eligible for the OATT waiver, the dateon which the safe harbor begins, the rebuttable presumption that the ICIF owner should not be required to expandits facilities during the safe harbor, and the facilities covered by Order 807. Order 807 will become effectiveJune 30, 2015.116 Requests for rehearing and/or clarification of Order 807 were filed on April 20 by APPA/TAPSand NRECA. The requests for rehearing are pending before the FERC, with FERC action required on or beforeMay 20, 2015, or the requests will be deemed denied.

111 The NOPR was published in the Fed. Reg. on Feb. 26, 2015 (Vol. 80, No. 38) pp. 10,426-10,432.

112 Refinements to Policies and Procedures for Market-Based Rates for Wholesale Sales of Elec. Energy, Capacityand Ancillary Srvcs. by Public Utils., 147 FERC ¶ 61,232 (June 19, 2014) (“MBR NOPR”).

113 The MBR NOPR was published in the Fed. Reg. on July 25, 2014 (Vol. 79, No. 143) pp. 43,536-43,572.

114 Open Access and Priority Rights on Interconnection Customer’s Interconnection Facilities, Order No. 807, 150FERC ¶ 61,211 (Mar. 19, 2015) (“Order 807”), reh’g requested.

115 ICIF is the term used by the FERC in the NOPR to refer to “generator tie lines”.

116 Order 807 was published in the Fed. Reg. on Apr. 1, 2015 (Vol. 80, No. 62) pp. 17,654-17,682.


Page 3641536280.150

• WIRES Request for Policy Statement on ROE for Electric Transmission (RM13-18)

On June 26, 2013, WIRES117 petitioned the FERC to institute an expedited generic proceeding and toprovide such policy and clarifications as necessary to provide “greater stability and predictability regardingregulated rates of return on equity for existing and future investments in high voltage electric transmissioninfrastructure.” Specifically, WIRES recommended a new policy that (1) standardizes selection of proxygroups; (2) denies complainants a hearing on rates of return for existing facilities unless it is shown thatexisting returns are at the extremes of the zone of reasonableness; (3) allows consideration of competinginfrastructure investments of other industries; (4) permits use of other rate of return methodologies; and (5)supports use of more forward-looking data and modeling. In addition, WIRES urged the FERC to supportconsideration of a project’s actual and anticipated benefits when a complaint is filed against the ROE for anexisting project. Although the WIRES petition has not been noticed for public comments, more than 16 setsof comments have been filed. On October 3, 2013, WIRES submitted a summary of the comments andanalysis filed to that point in the proceeding. On October 16, the Organization of PJM States noted itsposition that the WIRES petition did not present a compelling reason for the FERC to initiate a genericrulemaking proceeding or abandon its Discounted Cash Flow methodology. On November 5, 2013, a letterfrom US Senator Angus King, urging the FERC to establish a more certain regulatory environment thatprovide investors the level of confidence necessary to support and encourage needed infrastructureinvestments, was posted in eLibrary. This matter is pending before the FERC.

• Order 771: Availability of e-Tag Information to FERC Staff (RM11-12)

Rehearing of portions of Order 771 has been requested and remains pending. As previously reported,Order 771,118 issued December 20, 2012, granted the FERC access, on a non-public and ongoing basis, to thecomplete electronic tags (“e-Tags”) used to schedule the transmission of electric power interchange transactionsin wholesale markets. Order 771 requires e-Tag Authors (through their Agent Service) and Balancing Authorities(through their Authority Service) to take steps to ensure FERC access to the e-Tags covered by this Rule bydesignating the FERC as an addressee on the e-Tags. The FERC stated that the information made available underthis Final Rule will bolster its market surveillance and analysis efforts by helping it detect and prevent marketmanipulation and anti-competitive behavior. In addition, Order 771 requires e-Tag information be made availableto RTO/ISOs and their Market Monitoring Units, upon request to e-Tag Authors and Authority Services, subjectto appropriate confidentiality restrictions. Order 771 became effective February 26, 2013.119 In response torequests for clarification and/or rehearing of Order 771 filed by EEI/NRECA, Open Access TechnologyInternational, Inc., NRECA (separately), and Southern Companies (collectively, the “Rehearing Requests”), theFERC issued, on March 8, 2013, Order 771-A.120 Order 771-A addressed only those issues that needed to beanswered on an expedited basis to allow affected entities to comply with the requirement to ensure FERC accessin a timely manner to the e-Tags covered by Order 771.121 The FERC noted that it would issue an additional

117 WIRES, the Working group for Investment in Reliable and Economic Electric Systems, describes itself as anational non-profit association of investor-, member-, and publicly-owned entities dedicated to promoting investment in astrong, well-planned, and environmentally beneficial high voltage electric transmission grid. Information about its principlesand members is available on its website www.wiresgroup.com.

118 Availability of E-Tag Info. to Comm’n Staff, Order No. 771, 141 FERC ¶ 61,235 (Dec. 20, 2012) (“Order 771”),order on reh’g and clarif., 142 FERC ¶ 61,181 (2013).

119 Order 771 was published in the Fed. Reg. on Dec. 28, 2012 (Vol. 77, No. 249) pp. 76,367-76,380.

120 Availability of E-Tag Info. to Comm’n Staff, Order No. 771-A, 142 FERC ¶ 61,181 (Mar. 8, 2013) (“Order 771-A”).

121 Order 771-A clarified that: (1) Balancing Authorities and their Authority Services will have until 60 days afterpublication of this order to implement the validation requirements of Order 771; (2) validation of e-Tags means that the SinkBalancing Authority, through its Authority Service, must reject any e-Tags that do not correctly include the FERC in the CCfield; (3)the requirement for the FERC to be included in the CC field on the e-Tags applies only to e-Tags created on or afterMarch 15, 2013; (4) the FERC will deem all e-Tag information made available to the FERC pursuant to Order 771 as beingsubmitted pursuant to a request for privileged and confidential treatment under 18 CFR 388.112; (5) the FERC is to beafforded access to the Intra-Balancing Authority e-Tags in the same manner as interchange e-Tags; and (6) the requirement


Page 3741536280.150

rehearing order, addressing the remaining issues raised on rehearing and clarification, which therefore remainpending before the FERC.

• Order 676-H: Incorporation of WEQ Version 003 Standards (RM05-5)

On April 16, 2015, the FERC granted clarification in part, but otherwise denied the EEI and NYISOrequests for rehearing and/or clarification of Order 676-H.122 As previously reported, the FERC issued Order676-H on September 18, 2014.123 Order 676-H amended FERC regulations by incorporating by reference, withcertain enumerated exceptions, Version 003 of the Standards for Business Practices and CommunicationProtocols for Public Utilities adopted by the Wholesale Electric Quadrant (“WEQ”) of the North AmericanEnergy Standards Board (“NAESB”). The Version 003 Standards update earlier versions of these standardspreviously incorporated by reference into FERC regulations at 18 CFR 38.2. The Version 003 standards includemodifications to support Order Nos. 890, 890-A, 890-B and 890-C, including the standards to support NetworkIntegration Transmission Service on an OASIS, Service Across Multiple Transmission Systems (“SAMTS”),standards to support FERC policy regarding rollover rights for redirects on a firm basis, standards that incorporatethe functionality for transmission providers to credit redirect requests with the capacity of the parent reservationand standards modifications to support consistency across the OASIS-related standards. The Version 003Standards also include modifications to the OASIS-related standards that NAESB states support Order Nos. 676,676-A, 676-E and 717 and add consistency. In addition, there are modifications to the Coordinate Interchangestandards to compliment recent updates to e-Tag specifications, modifications to the Gas/Electric Coordinationstandards to provide consistency between the two markets, and re-organized and revised definitions to create astandard set of terms, definitions and acronyms applicable to all NAESB WEQ standards. The Version 003Standards include the Standards addressed in Order 676-G and the recent Smart Grid Standards. Order 676-Hbecame effective October 24, 2014.124 Requests for rehearing of Order 676-H were filed by EEI and the NYISOon October 20, 2014. As noted above, on April 16, 2015, the FERC granted clarification, in part,125 but otherwisedeny requests for rehearing and/or clarification by EEI and the NYISO.

Compliance Deadlines Extended. On January 15, the FERC extended for all entities subject to theserequirements the deadline for compliance with the Version 003 business practice standards, with the exception ofthe OASIS template (for which compliance is required by March 24, 2016), to and including May 15, 2015. Allother compliance obligations set forth in Order 676-H remain in force.

on Balancing Authorities to ensure FERC access to e-Tags pertains to the Sink Balancing Authority and no other BalancingAuthorities that may be listed on an e-Tag.

122 Standards for Bus. Practices and Communication Protocols for Pub. Utils., 151 FERC ¶ 61,046 (Apr. 16, 2015)(“Order 676-h Clarification Order”).

123 Standards for Bus. Practices and Communication Protocols for Pub. Utils., Order No. 676-H, 148 FERC ¶61,205 (Sep. 18, 2014) (“Order 676-H”), reh’g denied, clarification granted in part, 151 FERC ¶ 61,046 (Apr. 16, 2015).

124 Order 676-H was published in the Fed. Reg. on Sep. 24, 2014 (Vol. 79, No. 185) pp. 56,939-56,955.

125 The FERC clarified that, “whenever a standard specifically states on its face that it only applies to certain typesof entities, there is no need for other entities outside of that grouping (i.e., those to whom the requirement is not applicable) toobtain a waiver of that standard to be excused from compliance, as those standards clearly do not apply to them. This beingthe case, we shall hereafter dismiss as unnecessary any requests for waivers of standards that by their terms specifically applyonly to entity groups (e.g., balancing authorities or western utilities or RTOs/ISOs) that the potential waiver requestor doesnot belong to during the time those standards are effective). Order 676-H Clarification Order at p 19.


Page 3841536280.150


For further information on any of the natural gas proceedings, please contact Joe Fagan (202-218-3901;[email protected]), Jennifer Galiette (860-275-0338; [email protected]) or Jamie Blackburn (202-218-3905; [email protected]).

• Inquiry Into Natural Gas Trading, and Proposal to Establish an Electronic Information and TradingPlatform (AD14-19)

On September 18, 2014, Commissioner Moeller convened a meeting to discuss issues related to howtransactions are conducted on the natural gas system and potential transactional improvements to address theneeds of electric generators for natural gas. The meeting included representatives/speakers from varioussectors of the natural gas and electric industries (load, suppliers, marketers, exchanges, gas associations, andISOs) and environmental interests. Representatives from NYISO and PJM were among the speakers on theelectric side (ISO-NE was not present). A summary of that meeting is posted on the Litigation Updates &Reports webpage (http://nepool.com/uploads/Lit_Supp_AD14-19_20140918_Mtg_Summary.pdf ). Writtencomments on issues discussed at the meeting, limited to 5 pages, were due on or before October 1, 2014.Comments were filed by more than 30 parties. There was no published activity in this proceeding since thelast Report.

• Order 809: Coordination of the Scheduling Processes of Interstate Natural Gas Pipelines and PublicUtilities (RM14-2)

On April 16, the FERC issued Order 809,126 which changes the nationwide Timely Nomination Cyclenomination deadline for scheduling natural gas transportation from 11:30 a.m. Central Clock Time (CCT) to 1:00 p.m.CCT and revises the intraday nomination timeline, to include adding an additional intraday scheduling opportunityduring the gas operating day (Gas Day). Order 809 also modifies the scheduling practices used by interstate pipelinesto schedule natural gas transportation service and provides additional contracting flexibility to firm natural gastransportation customers through the use of multi-party transportation contracts. Order 809 DOES NOT change thestart time of the nationwide natural Gas Day (which remains 9:00 a.m. CCT), as had been proposed in the underlyingNOPR.127 In response to Order 809, ISO-NE is required to propose tariff revisions to coordinate the Day-Ahead EnergyMarket with the Order 809 changes or show cause why its existing scheduling practices need not be changed on orbefore Thursday, July 23, 2015128 (to be filed, presumably, in EL14-23; see Section I above).

• Posting of Offers to Purchase Capacity (Section 5 Proceeding) (RP14-442)

Similar to the ISO/RTO 206 Order in EL14-22 et al. (see Section I above), the FERC also instituted aproceeding under Section 5 of the Natural Gas Act to examine whether interstate natural gas pipelines areproviding notice of offers to purchase released pipeline capacity in accordance with section 284.8(d) of theCommission’s regulations.129 On or before May 19, natural gas pipelines were required to either revise theirrespective tariffs to provide for the posting of offers to purchase released capacity, or otherwise demonstrate thatthey are in full compliance with FERC regulations.130 The FERC also requested that NAESB develop businesspractice and communication standards specifying: (1) the information required for requests to acquire capacity;(2) the methods by which such information is to be exchanged; and (3) the location of the information on apipeline’s website. The Show Cause Order required each pipeline to explain in its compliance filing how it will

126 Coordination of the Scheduling Processes of Interstate Natural Gas Pipelines and Public Utilities, Order No.809, 150 FERC ¶ 61,049 (Apr. 16, 2015) (“Order 809”).

127 Coordination of the Scheduling Processes of Interstate Natural Gas Pipelines and Public Utilities, 146 FERC ¶61,201 (Mar. 20, 2014).

128 Order 809 was published in the Fed. Reg. on Apr. 24, 2015 (Vol. 80, No. 79) pp. 23,198-23,227.

129 Posting of Offers to Purchase Capacity, 146 FERC ¶ 61,203 (Mar. 20, 2014).

130 Id. at P 6.


Page 3941536280.150

fully comply with section 284.8(d) until NAESB develops, and the FERC implements, the requested standards,including how the pipeline will provide shippers the ability to post offers to purchase capacity on theInformational Posting section of its Internet website.

In total, the FERC received, and addressed in one omnibus order, 157 compliance filings.131 Of the 157filings, 64 pipelines revised their respective tariffs to provide for the posting of offers to purchase releasedcapacity in a manner that complies with section 284.8(d), and 23 pipelines demonstrated that their tariffs alreadycomply with that section. The FERC found that, and identified in its omnibus order on the compliance filings the,69 compliance filings that did not appear to be in full compliance with that section, and directed furthercompliance filings from those companies as described in the omnibus order.

• Natural Gas-Related Enforcement Actions

The FERC continues to closely monitor and enforce compliance with regulations governing open accesstransportation on interstate natural gas pipelines. Since the last Report, there was a great deal of activity in thefollowing on-going, gas-related enforcement proceeding:

Company Alleged Violation(s) CivilPenalty/Disgorgement

BP America Inc.BP Corp. N. Amer.BP Amer. ProductionBP Energy Co.(together, “BP”)(IN13-15)

The FERC established a hearing to determinewhether BP violated section 4A of the Natural GasAct and the FERC’s Anti-Manipulation Rule asalleged by Enforcement Staff. Enforcement Staffalleged that BP traded physical natural gas atHouston Ship Channel (“HSC”) to increase thevalue of BP’s financial position at HSC,uneconomically using BP’s transportation capacity,making repeated early uneconomic sales at HSC,taking steps to increase BP’s market concentrationat HSC. In doing so, Enforcement staff alleged, BPsuppressed the HSC Gas Daily index with the goalof increasing the value of BP’s financial position atHSC. The activity occurred from mid-September2008 through November 2008.

Show Cause Order132

$28 million (civil penalty)$800,000 (disgorgement)

On October 29, BP and Enforcement Staff agreed to a modified procedural schedule for the hearingprocedures underway. Pursuant to that schedule, hearings before Judge Cintron will begin March 30, 2015, withan Initial Decision due August 14, 2015.

• New England Pipeline Proceedings

The following New England pipeline projects are pending before the FERC:

• Algonquin Incremental Market Project (AIM Project) (CP14-96)

Algonquin Gas Transmission filed for Section 7(b) and 7(c) certificate Feb. 28, 2014

342,000 dekatherms/day of firm capacity to NY, CT, RI and MA.

37.6 miles of take-up, loop and lateral pipeline facilities in NY, CT, and MA and systemmodifications in NY, CT and RI. The system upgrades would also require the removal ofsome facilities.

131 See BR Pipeline Co. et al., 149 FERC ¶ 61,031 (Oct. 16, 2014).

132 BP America Inc. et al., 144 FERC ¶ 61,100 (Aug. 5, 2013).


Page 4041536280.150

10 firm shippers: Yankee Gas, NSTAR, Connecticut Natural Gas, Southern Connecticut,Narragansett Electric, Colonial Gas, Boston Gas, Bay State, Norwich Public Utilities, andMiddleborough Gas and Electric (eight LDCs and two municipal utilities).

Final EIS issued on Jan 23, 2015.

90-day Federal Authorization Decision Deadline April 23, 2015.

Certificate of public convenience and necessity granted Mar 3, 2015 (must be constructedand in service within two years).133

In-service: Nov 2016 (anticipated).

• Connecticut Expansion Project (CP14-529)

Tennessee Gas Pipeline filed for Section 7(c) certificate July 31, 2014.

72,100 dekatherms/day of firm capacity.

13.26 miles of three looping segments and facility upgrades/modifications in NY, MA andCT.

Three firm shippers: Connecticut Natural Gas, Southern Connecticut Gas, and Yankee Gas.

Authorization requested by July 31, 2015.

Construction expected to begin Winter 2015/16.

In-service: Nov 2016 (anticipated).

• Constitution Pipeline (CP13-499) and Wright Interconnection Project (CP13-502)

Constitution Pipeline Company and Iroquois Gas Transmission (Wright Interconnection)concurrently filed for Section 7(c) certificates on June 13, 2013.

650,000 dekatherms/day of firm capacity from Susquehanna County, PA through NY toIroquois/Tennessee interconnection (Wright Interconnection).

New 122-mile interstate pipeline.

Two firm shippers: Cabot Oil & Gas and Southwestern Energy Services.

Final EIS completed on Oct 24, 2014.

Certificates granted Dec 2, 2014 (must be constructed and in service within two years);

Construction expected to begin second-quarter 2015.

• Salem Lateral Project (CP14-522)

Algonquin Gas Transmission filed application Jul 10, 2013.

115,000 dekatherms/day of firm capacity.

1.2 miles of pipeline to 630 MW Salem Harbor Station and other Salem, MA facilities.

Footprint Power sole firm customer.

Authorization requested by Apr 17, 2015.

FERC environmental assessment issued Dec 2, 2014.

In-Service: Nov 2015 (anticipated).


No Activity to Report.

133 Order Issuing Certificate and Approving Abandonment, Algonquin Gas Transmission LLC, 150 FERC ¶ 61,163(Mar. 3, 2015), reh’g requested.


Page 4141536280.150

XV. Federal Courts

The following are matters of interest, including petitions for review of FERC decisions in NEPOOL-relatedproceedings, that are currently pending before the federal courts (unless otherwise noted, the cases are before theU.S. Court of Appeals for the District of Columbia Circuit). An “**” following the Case No. indicates thatNEPOOL has intervened or is a litigant in the appeal. The remaining matters are appeals as to which NEPOOLhas no organizational interest but that may be of interest to Participants. For further information on any of theseproceedings, please contact Pat Gerity (860-275-0533; [email protected]).

• FCM Administrative Pricing Rules Complaint (15-1071**)Underlying FERC Proceedings: EL14-7134

Appellants: NEPGA

On March 31, 2015, NEPGA filed a petition for review of the FERC’s orders on NEPGA’s FCMAdministrative Pricing Rules Complaint. A Docketing Statement Form, Statement of Issues to be Raised, andPetitioners’ Appearances were filed on April 23, 2015. Also on April 23, 2015, NEPGA requested that the casebe held in abeyance pending the FERC’s issuance of an order on rehearing of its initial order in ExelonCorporation v. ISO New England Inc. (EL15-23). Motions for leave to intervene have been filed by NEPOOL,CT PURA, CT OCC, and PSEG.

• Demand Curve Changes (15-1070**)Underlying FERC Proceedings: ER14-1639135

Appellants: NextEra, NRG and PSEG

On March 30, 2015, NextEera, NRG and PSEG filed a petition for review of the FERC’s orders in theDemand Curve Changes proceedings. A Docketing Statement Form, Statement of Issues to be Raised, andAppearances must be filed by Petitioners by April 30, 2015. Motions for leave to intervene have been filed byNEPOOL, the ISO, CT PURA, and NESCOE.

• FCA8 Results (14-1244, 14-1246 (consolidated))Underlying FERC Proceedings: ER14-1409136

Appellants: Public Citizen and CT AG

On November 14, 2014, Public Citizen and the CT AG filed petitions for review of the FERC’s action onthe FCA8 Results Filing, which became effective by operation of law on September 16, 2014. These proceedingshave been consolidated. A Docketing Statement Form and Statement of Issues to be Raised were filed byPetitioners by December 22, 2014. On January 2, 2015, the FERC filed a motion to dismiss the petitions for lackof jurisdiction. The FERC argued that the Court lacks jurisdiction because Petitioners did not challenge a FERC“order” within the meaning of section 313 of the FPA, or “agency action” reviewable under the AdministrativeProcedures Act. On January 15, EPSA and NEPGA jointly filed a motion supporting the FERC’s motion todismiss. On January 26, Connecticut137 and Public Citizen opposed the FERC’s motion to dismiss. On February5, the FERC replied to the Public Citizen and CT AG responses. On April 7, the Court ordered that the motion todismiss be referred to the merits panel and parties were directed to address in their briefs the issues presented inthe motion to dismiss rather than incorporate those arguments by reference. On April 9, the FERC filed an

134 150 FERC ¶ 61,064 (Jan. 30, 2015); 146 FERC ¶ 61,039 (Jan. 24, 2014).

135 150 FERC ¶ 61,065 (Jan. 30, 2015); delegated letter order (Nov. 13, 2014); 147 FERC ¶ 61,173 (May 30, 2014).

136 Notice of Filing Taking Effect by Operation of Law, ISO New England Inc., Docket No. ER14-1409 (Sep. 16,2014); Notice of Dismissal of Pleadings, ISO New England Inc., Docket No. ER14-1409 (Oct. 24, 2014).

137 For purposes of this proceeding, “Connecticut” means the CT AG, CT PURA and CT OCC.


Page 4241536280.150

unopposed motion for a schedule setting a minimum 60-day briefing interval for the FERC. On April 10, theCourt ordered that parties submit proposed formats for the briefing of the consolidated cases by May 11.

• 2013/14 Winter Reliability Program (14-1104, 14-1105, 14-1103 (consolidated))Underlying FERC Proceedings: ER13-1851138 and ER13-2266139

Appellants: TransCanada and RESA

On June 6, 2014, TransCanada and the Retail Energy Supply Association filed petitions for review of theFERC’s orders on the 2013/14 Winter Reliability Program (14-1104 and 14-1105, respectively). Also on June 6,2014, TransCanada filed a petition for review of FERC’s orders on the 2013/14 Winter Reliability Program BidResults Filings (ER14-1103). On July 3, 2014, these proceedings were consolidated. On July 7, the FERCrequested a minimum of 60 days after Petitioners’ opening briefs to file its brief. On July 23, leave to intervenewas granted to ISO-NE, NEPGA, PSEG and Essential Power. On September 29, TransCanada, RESA, FERC,ISO-NE, Essential Power MA, PSEG and NEPGA filed a proposed joint, unopposed briefing format andschedule. A Joint Brief for Petitioners was filed on November 24 (as corrected on December 1). At the FERC’srequest, the Court ordered that a revised briefing schedule be applied in this case (effectively extending the overallbriefing schedule by one month. Briefs for Respondent and Respondent-Intervenors were filed February 13 andMarch 2, respectively. Petitioners’ Joint Reply Brief was filed on March 25; the Deferred Appendix, April 1,2015. Since the last Report, Final Briefs were filed on April 15, 2015.

• Orders 773 and 773-A (2nd Cir., 13-2316)Underlying FERC Proceedings: RM12-6 and RM12-7140

Appellants: NY PSC and People of the State of New York

On April 22, the 2nd Circuit denied the petitions for review of the FERC’s orders on Orders 773 and773-A (Revised “Bulk Electric System” Definition and Procedures) requested by the NY PSC and the Peopleof the State of New York, concluding this proceeding.

• New England’s Order 745 Compliance Filing (12-1306)Underlying FERC Proceedings: ER11-4336141

Appellants: EPSA and NEPGA

On July 16, 2012, EPSA and NEPGA filed a petition for review of FERC’s orders on New England’sOrder 745 (Demand Response Compensation) filings. On August 16, 2012, EPSA and NEPGA filed astatement of issues as well as an unopposed motion to hold case in abeyance pending the final resolution ofCase Nos. 11-1486, et al. (EPSA et al. v. FERC) (see Orders 745 and 745-A below). On August 23, 2012, theCourt granted the motion to hold the case in abeyance. Motions to govern future proceedings will be due 30days following the issuance of the mandate in the Order 745 appeal.

• Orders 745 and 745-A (FERC v. EPSA, Supreme Court, 14-840 and 14-841)Underlying FERC Proceedings: RM10-17-000142

Appellants: FERC and EnerNOC

On January 15, the Solicitor General of the United States, on behalf of the FERC, filed with theSupreme Court a petition for a writ of certiorari seeking review of the District Court’s May 23 Decision.143

Respondents brief in opposition to that writ, pursuant to an order of the Court extending the time for

138 144 FERC ¶ 61,204 (Sep. 16, 2013); 147 FERC ¶ 61,026 (Apr. 8, 2014).

139 145 FERC ¶ 61,023 (Oct. 7, 2013); 147 FERC ¶ 61,027 (Apr. 8, 2014).

140 141 FERC ¶ 61,236 (Dec. 20, 2012); 143 FERC ¶ 61,053 (Apr. 18, 2013).

141 138 FERC ¶ 61,042 (Jan. 19, 2012); 139 FERC ¶ 61,116 (May 17, 2012).

142 134 FERC ¶ 61,187 (Mar. 15, 2011); 137 FERC ¶ 61,215 (Dec. 15, 2011).

143 EPSA v. FERC, 753 F.3d 216 (May 23, 2014).


Page 4341536280.150

responses, was filed on March 19. Petitioner’s reply was filed on April 7. The FERC’s petition and EPSA etal.’s response thereto went to conference on April 24, 2015, and are scheduled to go to conference again onMay 1, 2015.

As previously reported, the DC Circuit vacated Order 745144 in its entirety as impermissiblyencroaching on “states’ exclusive jurisdiction to regulate the retail market” in a 2-1 decision (“Decision”)issued on May 23, 2014. The DC Circuit vacated Order 745 on two separate and independent grounds. First,it held that the FERC does not have jurisdiction to regulate demand response. The Court reasoned that: (i) thestates retain exclusive authority to regulate the retail market; (ii) absent an express statutory grant of authority,the FERC cannot regulate areas left to the states; (iii) the FPA provides the FERC with authority overwholesale sales of electricity, but demand response is not such a sale; (iv) the authority of the FERC toregulate wholesale power rates under the FPA cannot be read so broadly as to allow direct regulation ofdemand response; and (v) demand response, while not necessarily a retail sale, is part of the retail market,involving retail customers, their decision whether to purchase at retail, and the levels of retail electricityconsumption. Therefore, the Court concluded, the FERC has no authority to directly regulate demandresponse. “FERC’s authority over demand response resources is limited: its role is to assist and advise stateand regional programs.”

As an alternative and secondary basis for its decision against Order 745, the Court concluded that theFERC order was “arbitrary, capricious, an abuse of discretion, or otherwise not in accordance with law.” TheCourt found that the FERC failed to reasonably consider and address arguments that Order 745 will result inover-compensation of demand response resources, resulting in unjust and discriminatory rates. The Courtfurther found that the FERC failed to demonstrate how its proposed pricing construct would result in justcompensation. The Decision and preliminary implications of the Decision were summarized in more detail inthe memo included with the supplemental materials circulated and posted for the June 6 meeting.

On July 7, the FERC petitioned the Court for rehearing en banc of the May 23 Decision. On July 18,the Court, on its own motion, directed EPSA, APPA, NRECA, Old Dominion and EEI (“Petitioners”) to file ajoint response to the FERC petition for rehearing. That response was filed on August 4, 2014. The petitionfor rehearing en banc was denied on September 17, 2014. As previously reported, the DC Circuit directed itsclerk to withhold the Court’s mandate pending the Supreme Court’s final disposition.

• CPV Maryland, LLC v. PPL EnergyPlus et al. (Supreme Court, 14-623)

A petition for a writ of certiorari in this case was filed on November 26, 2014 and placed on the SupremeCourt’s docket on November 28, 2014 as No. 14-623. The parties consented to the filing of amicus curiae briefs,and such briefs were filed by NARUC, the State of Connecticut, and APPA. Respondents (PPL EnergyPlus,LLC, et al.) filed a response on February 11. Petitioner CPV Maryland, LLC replied on February 24. On March23, the Court invited the Solicitor General to file a brief in the case expressing the views of the United States.This matter is now before the Court.

As previously reported, on June 2, 2014, the 4th Circuit Court of Appeals affirmed the September 30,2013 decision of the United States District Court for the District of Maryland145 which found that a MarylandPublic Service Commission (“MD PSC”) order directing three Maryland distribution utilities to enter into a‘contract for differences’ for capacity and energy in the PJM control area (the “CfD”) with a gas-fired merchantgenerator selected by the MD PSC (the “MD PSC Order”) violated the Supremacy Clause of the United States

144 Order 745 required RTOs and ISOs to include provisions in their tariffs that assured demand response would bepaid at LMP for interrupting their loads when such interruption was cost effective.

145 PPL EnergyPlus, LLC v. Nazarian, 974 F.Supp. 2d 790 (D. Md. Sep. 30, 2013); 2013 U.S. Dist. LEXIS 140210,2013 WL 5432346 (“District Court Decision”). The District Court Decision was summarized in past Litigation Reports.


Page 4441536280.150

Constitution and cannot be enforced.146 In affirming the District Court decision, the 4th Circuit found the MDPSC Order both field147 and conflict pre-empted.148

With respect to field pre-emption, the 4th Circuit stated that a “wealth of case law confirms FERC’sexclusive power to regulate wholesale sales of energy in interstate commerce, including the justness andreasonableness of the rates charged.”149 It found the federal scheme (i.e. the PJM Market) “carefully calibrated toprotect a host of competing interests” (representing “a comprehensive program of regulation that is quite sensitiveto external tampering”),150 and leaving “no room either for direct state regulation of the prices of interstatewholesales of [energy], or for state regulations which would indirectly achieve the same result.” Accordingly, the4th Circuit concluded that the MD PSC Order “field preempted because it functionally sets the rate that CPVreceives for its sales in the PJM auction.”151 The MD PSC Order “compromises the integrity of the federalscheme and intrudes on FERC’s jurisdiction” because the MD PSC Order “effectively supplants the rategenerated by the auction with an alternative rate preferred by the state.” The 4th Circuit rejected arguments thatthe CfD payments “represented a separate supply-side subsidy implemented entirely outside the federalmarket.”152 And, even if the presumption against preemption were to apply, the Court found that that it was“overcome by the text and structure of the FPA, which unambiguously apportions control over wholesale rates toFERC.”153

With respect to conflict pre-emption, the 4th Circuit found that the MD PSC Order “presents a direct andtransparent impediment to the functioning of the PJM markets, and is therefore preempted”.154 Preemption wasappropriate because of the “extensive and disruptive” impact of the MD PSC Order on matters within federalcontrol (the PJM markets). It found that the MD PSC Order had “the potential to seriously distort the PJM’sauction’s price signals, thus ‘interfer[ing] with the method by which the federal statute (i.e. the PJM Markets) wasdesigned to reach its goals.”155 “Maryland’s initiative disrupts [the PJM scheme] by substituting the state’spreferred incentive structure for that approved by FERC.”156 “Maryland has sought to achieve through the

146 PPL EnergyPlus, LLC v. Nazarian, 753 F.3d 467; 2014 U.S. App. LEXIS 10155.

147 “Field preemption” is a doctrine based on the Supremacy Clause of the U.S. Constitution that holds that anyfederal law, including regulations of a federal agency, takes precedence over any conflicting state law. Preemption can beimplied when federal law/regulation “occupies the field” in which the state is attempting to act/regulate. Field preemptionoccurs when there is "no room" left for state regulation. Accordingly, a state may not pass a law or take any action in a field,like the regulation of wholesale power sales, pervasively regulated by federal law/regulation.

148 “Conflict preemption” occurs where there is a conflict between a state law and a federal law. (“[E]ven ifCongress has not occupied the field, state law is naturally preempted to the extent of any conflict with a federal statute.”).Such a conflict occurs when “the challenged state law stands as an obstacle to the accomplishment and execution of the fullpurposes and objectives of Congress. The court must look to 'the entire scheme of the statute' and determine '[i]f the purposeof the [federal] act cannot otherwise be accomplished--if its operation with its chosen field [would] be frustrated and itsprovisions be refused their natural effect. Where a state law conflicts with a federal law, the Court does not balance thecompeting federal and state interests. Any state law, however clearly within a State’s acknowledged power, which interfereswith or is contrary to federal law, must yield.”

149 Slip op. at p. 14.

150 Id. at p. 10.

151 Id. at p. 16.

152 Id. at pp. 18-19.

153 Id. at p. 20. The Court noted the limited scope of its holding, which “is addressed to the specific program atissue” and did not “express an opinion on other state efforts to encourage new generation.” Id. at p. 21.

154 Id. at p. 27.

155 Id. at p. 23.

156 Id. at p. 24. (“Two features of the Order render its likely effect on federal markets particularly problematic.First, as noted, the CfDs are structured to actually set the price received at wholesale. They therefore directly conflict with theauction rates approved by FERC. Second, the duration of the subsidy -- twenty years -- is substantial.”)


Page 4541536280.150

backdoor of its own regulatory process what it could not achieve through the front door of FERC proceedings.Circumventing and displacing federal rules in this fashion is not permissible.”157

Petitions for rehearing en banc were filed by MD PSC and CPV Maryland on June 16, 2014. On June 17,2014, the 4th Circuit stayed the mandate pending the en banc ruling on the Petitions. On June 30, 2014, the 4th

Circuit denied the petitions for rehearing en banc.

• CPV Power Development, Inc., et al. v. PPL EnergyPlus, LLC, et al. (Supreme Court, 14-634, 14-694)

Petitions for a writ of certiorari in this case were filed on November 26, 2014 and December 10, 2014 andplaced on the Supreme Court’s docket as Case Nos. 14-634 and 14-694, respectively. The parties consented to thefiling of amicus curiae briefs, and such briefs were filed by NARUC, the State of Connecticut, APPA, AWEA,and the NY PSC. Since the last Report, Respondents (PPL EnergyPlus, LLC, et al.) filed a brief opposing the writof certiorari on February 11. Petitioners (CPV Power Development, Inc., et al.) replied to that brief on February20. On March 23, the Court invited the Solicitor General to file a brief in the case expressing the views of theUnited States.

As previously reported, on September 11, 2014, the 3rd Circuit Court of Appeals affirmed158 theanalogous October 11, 2013 decision of the United States District Court for the District of New Jersey declaringunconstitutional (and therefore null and void) New Jersey’s Long Term Capacity Agreement Pilot Program Act(“LCAPP”).159 In affirming the New Jersey District Court’s decision, the 3rd Circuit concluded:

LCAPP compels participants in a federally-regulated marketplace to transact capacity atprices other than the price fixed by the marketplace. By legislating capacity prices, NewJersey has intruded into an area reserved exclusively for the federal government.Accordingly, federal statutory and regulatory law preempts and, thereby, invalidatesLCAPP and the Standard Offer Capacity Agreements.160

No petition for rehearing or rehearing en banc was filed on or before September 25, 2014. Accordingly,the mandate was issued on October 3, 2014. As noted above, petitions for certiorari to the U.S. Supreme Courtwere filed and are pending before the Supreme Court.

• Entergy Nuclear Fitzpatrick, LLC et al v. Zibelman et al (NY PSC Commissioners) (N.D.N.Y. 5:15-cv-00230-DNH-TWD)

Entergy161 filed, on February 27, in the United States District Court for the Northern District of NewYork, a Complaint that seeks a declaratory judgment that the NYPSC Commissioners’ order (“Order”) approvingan agreement to keep NRG’s 435 MW Dunkirk facility in the NYISO market, “repowered” as a natural gas-fired(rather than coal-fired) plant (the “Term Sheet”)162 is preempted by the FPA and invalid under the dormant

157 Id. at p. 25.

158 PPL EnergyPlus, LLC v. Hanna, 977 F.Supp.2d 372 (D. NJ. Oct. 11, 2013); 2013 U.S. Dist. LEXIS 147273,(“NJ Order”).

159 PPL EnergyPlus, LLC v. Hanna, 766 F.3d 241; 2014 U.S. App. LEXIS 17557 (Sep. 11, 2014).

160 Id. slip op. at 31.

161 Plaintiffs are Entergy Nuclear FitzPatrick, LLC (“FitzPatrick”); Entergy Nuclear Power Marketing, LLC(“ENPM”); and Entergy Nuclear Operations, Inc. (“ENOI”).

162 The Term Sheet provides that, in exchange for Dunkirk’s commitment to participate in the NYISO energy andcapacity markets through 2025, Dunkirk will receive out-of-market payments of $20.4 million per year from National Gridand a $15 million one-time subsidy from a New York State agency. Entergy asserts that the contract structure will leadDunkirk to bid below its actual costs in the capacity auction, causing the auction market to “clear” at a lower price thanotherwise would have resulted, and resulting in all generators receiving lower capacity revenues than they otherwise wouldhave received.


Page 4641536280.150

Commerce Clause of the U.S. Constitution. Entergy also seeks a permanent injunction requiring the NYPSCCommissioners to withdraw its Order and/or preventing the NYPSC Commissioners from continuing to treat theOrder as valid and binding. This case is noteworthy given the relationship of the issues raised to the Marylandand New Jersey CfD cases summarized above.

• ONEOK, Inc. v. Learjet, Inc. (Supreme Court, 13-271)

On April 21, the Supreme Court ruled in favor of natural gas customers, and against both gas sellers andthe federal government in holding that the Natural Gas Act (“NGA”) did not field pre-empt state law antitrustlawsuits filed against the interstate gas sellers.163 More specifically, the Court held that Congress did not, when itpassed the NGA, intend to be so comprehensive in that legislation as to occupy an entire field of regulation,leaving no room for the States to have any law or regulation in that same field. The Court’s decision in ONEOKallows purchasers who bought natural gas directly from the gas sellers at retail to maintain their state antitrustsuits that claim that the latter manipulated gas indices used to help set natural gas retail prices, even though thosesame indices were also used to set FERC-regulated wholesale prices.

It is unclear how sweeping the Court’s holding is, since the ONEOK decision relates solely to “field” pre-emption, and not a narrower form of pre-emption known as “conflict” pre-emption. Under conflict pre-emption, acause of action, such as the state antitrust claims at issue here, may be subject to pre-emption arguments if itconflicts with the federal rate-setting process. The Court held that such questions, which were not addressed bythe parties in the ONEOK case, were best left “for the lower courts to resolve in the first instance.”

Undoubtedly, some will seek to interpret this case to signal how the Court will decide on pending certpetitions concerning other energy jurisdiction and preemption cases: the D.C. Circuit’s decision in EPSA v.FERC, in which the FERC was found to lack statutory authority to regulate demand response on the basis that it isa matter of state, not federal, jurisdiction; and the dual PPL cases involving the field preemption of New Jerseyand Maryland state laws promoting generation development. There were two justices dissenting in the ONEOKdecision, and the Court in addressing the dissent, emphasized that the enumeration in the NGA of the FERC’spowers is circumscribed by the limitations enumerated in that statute, particularly those that address the powersthat are reserved to the States, explaining that the NGA “was drawn with meticulous regard for the continuedexercise of state power, not to handicap or dilute it in any way.” (Emphasis added). The EPSA case is ajurisdiction case, not one of federal preemption per se, and the PPL Cases are based on both field and conflictpreemption and involve the Federal Power Act, not the NGA, which is a very similar, but different statute.Determinations with respect to the EPSA and PPL cases, and not simply the ONEOK decision, will be needed toprovide the greater certainty sought by the electric industry.

163 ONEOK, Inc. v. Learjet, Inc., 575 U. S. ____ (2015) (“ONEOK”).


Page I-141536280.150

INDEXStatus Report of Current Regulatory and Legal Proceedings

as of April 29, 2015

I. Complaints

206 Investigation: Consistency of ISO-NE (DA) Scheduling Practices withNatural Gas Scheduling Practices to be Adopted in Docket RM14-2 .......................... (EL14-23) ..............................6

206 Investigation: FCM Performance Incentives (Compliance Proceeding)........................ (EL14-52; ER14-2419) ..........5206 Proceeding: Importers’ FCA Offers Review/Mitigation ............................................... (EL14-99; ER15-117) ............3Base ROE Complaint (2011) ................................................................................................ (EL11-66) ..............................7Base ROE Complaints (2012 and 2014) (Consolidated) ...................................................... (EL13-33 and EL14-86).........4LVA/PSNH IA Complaint.................................................................................................... (EL15-9) ..............................26NEPGA DR Capacity Complaint ......................................................................................... (EL15-21) ..............................2NEPGA Peak Energy Rent (PER) Complaint ...................................................................... (EL15-25) ..............................1NESCOE FCM Renewables Exemption Complaint............................................................. (EL13-34) ..............................6New Entry Pricing Rule Complaint ...................................................................................... (EL15-23) ..............................2NRG Canal 2 2015/16 ARA3 Complaint/Waiver Request................................................... (EL15-57) ..............................1


2014/2015 Power Year Transmission Rate Filing: Public Representatives’ Protest ............ (ER09-1532; RT04-2)..........10Base ROE Complaint (2011) ................................................................................................ (EL11-66) ..............................7Base ROE Complaints (2012 and 2014) (Consolidated) ...................................................... (EL13-33 and EL14-86).........4FCA9 Results Filing ............................................................................................................. (ER15-1137) ..........................9FCA-10 Capacity Zone Boundaries ..................................................................................... (ER15-1462) ..........................8ISO Securities: Authorization for Future Drawdowns.......................................................... (ES15-15).............................10Opinion 531-A Compliance Filing: TOs .............................................................................. (ER15-414) ............................8



206 Investigation: FCM Performance Incentives (Compliance Proceeding)........................ (EL14-52; ER14-2419) ..........5206 Proceeding: Importers’ FCA Offers Review/Mitigation ............................................... (EL14-99; ER15-117) ............3Demand Curve Changes ....................................................................................................... (ER14-1639) ........................10DNE Dispatch Changes ........................................................................................................ (ER15-1509) ........................10eTariff Corrections ............................................................................................................... (ER15-1455) ........................11FCM Performance Incentives Jump Ball Filing ................................................................... (ER14-1050) ........................12FCM PI Jump Ball Compliance Filing I .............................................................................. (ER14-2419-001)...................5FCM PI Jump Ball Compliance Filing II ............................................................................. (ER14-2419-002)...................5FCM Redesign Compliance Filing: FCA8 Revisions........................................................... (ER12-953 et al.) .................13ISO Response to Show Cause Order .................................................................................... (ER15-117) ...........................3LMP Calculator Replacement............................................................................................... (ER15-1238) ........................11NEPGA DR Capacity Complaint ......................................................................................... (EL15-21) ..............................2NEPGA Peak Energy Rent (PER) Complaint ...................................................................... (EL15-25) ..............................1NESCOE FCM Renewables Exemption Complaint............................................................. (EL13-34) ..............................6New Entry Pricing Rule Complaint ...................................................................................... (EL15-23) ..............................2NRG Canal 2 2015/16 ARA3 Complaint/Waiver Request................................................... (EL15-57) ..............................1PER Mechanism Elimination (FCA-10)............................................................................... (ER15-1184) ........................11

IV. OATT Amendments/Coordination Agreements

ETU Rule Changes ............................................................................................................... (ER15-1050, -1051).............14Order 676-H Compliance: PTOs, SSPs, CSC et al. ............................................................. (ER15-517) ..........................14Order 676-H Compliance: Revisions to Schedule 24........................................................... (ER15-519) ..........................14Order 1000 Compliance Filing............................................................................................. (ER13-193; ER13-196)........16Order 1000 Interregional Requirements Compliance Filing ................................................ (ER13-1960; ER13-1957)....15Order 1000 November 15 Compliance Order Changes........................................................ (ER13-193; ER13-196)........16


Page I-241536280.150


Deposit Account Changes..................................................................................................... (ER15-1493) ........................17

VI. Schedule 20/21/22/23 Updates

LGIA – NU/CPV Towantic .................................................................................................. (ER15-200) ..........................19Opinion 531-A Compliance Filing: CTMEEC .................................................................... (ER15-584) ..........................18Opinion 531-A Compliance Filing: GMP............................................................................. (ER15-412) ..........................18Schedule 20A-EM and 21-EM Changes............................................................................... (ER15-1434) ........................18Schedule 21-NEP: BIPCO and Narragansett TSAs.............................................................. (ER15-1466) ........................18




ISO-NE FERC Form 582 ..................................................................................................... (not docketed) ......................19ISO-NE FERC Form 1 ........................................................................................................ (not docketed) ......................19LFTR Implementation: 26th Quarterly Status Report .......................................................... (ER07-476; RM06-08).........19


April 2015 Membership Filing ............................................................................................. (ER15-1417) ........................19Suspension Notice (Demansys Energy, LLC) ...................................................................... (not docketed) ......................20


FFT Report: March 2015...................................................................................................... (NP15-23) ............................20New Reliability Standard: EOP-011-1 ................................................................................. (RM15-7) .............................23New Reliability Standard: PRC-026-1 ................................................................................. (RM15-8) .............................22New Reliability Standard: TPL-007-1.................................................................................. (RM15-11) ...........................22NOPR: BAL-002-1a Interpretation Remand ........................................................................ (RM13-6) .............................25NOPR: Revised Rel. Standard: MOD-001-2 ........................................................................ (RM14-7) .............................25NOPR: Revised Rel. Standard: PRC-002-2.......................................................................... (RM15-4) .............................23NOPR: Revised Rel. Standard: PRC-005-4.......................................................................... (RM15-9) .............................22Order 802: New Reliability Standard: CIP-014-1 (Physical Security)................................. (RM14-15) ...........................23Order 808: Revised Rel. Standard: COM-001-2 and COM-002-4....................................... (RM14-13) ...........................24Order 810: Revised Rel. Standard: BAL-001-2 ................................................................... (RM14-10) ...........................24Revised Reliability Standard: PRC-004-3 ............................................................................ (RD14-14)............................20Revised Reliability Standard: PRC-010-1 ............................................................................ (RM15-12) ...........................22Revised Reliability Standards: CIP-003-6, CIP-004-6, CIP-006-6, CIP-007-6,CIP-009-6, CIP-010-2, CIP-011-2 (RM15-14)..................................................................... (RM15-14) ...........................21Revised Reliability Standards: PRC-004-2.1(i)a, PRC-004-4; PRC-005-2(i),PRC-005-3(i), VAR-002-4 (RD15-4)................................................................................... (RD15-3)..............................20Revised TOP and IRO Reliability Standards........................................................................ (RM15-16) ...........................21

XI. Misc. Regional Interest

203 Application: CSC/AIA Energy ...................................................................................... (EC15-122) ..........................26203 Application: Iberdrola/UI .............................................................................................. (EC15-103) ..........................26CL&P Amended Wholesale Distribution Service Agreement with CMEEC ....................... (ER15-1525) ........................28CMP CSIA Notice of Cancellation....................................................................................... (ER15-1448) ........................27Emera MPD OATT Changes................................................................................................ (ER15-1429) ........................28Emera MPD OATT Order 676-H Compliance Filing .......................................................... (ER15-1419) ........................29EPC Agreement: Blue Sky West & Emera Maine............................................................... (ER15-1459) ........................28FERC Enforcement Action: City Power Marketing and Tsingas ......................................... (IN15-5) ...............................30FERC Enforcement Action: Maxim Power and K. Mitton................................................... (IN15-4) ...............................30FERC Enforcement Action: Powhatan Energy, HEEP Fund, CU Fund, and H. Chen ........ (IN15-3) ...............................31FirstEnergy PJM DR Complaint........................................................................................... (EL14-55) ............................26HG&E Demarcation Agreement........................................................................................... (ER15-939) ..........................29IA - CMP-Brookfield White Pine Hydro.............................................................................. (ER15-1549) ........................27


Page I-341536280.150

IA - CMP-Cape..................................................................................................................... (ER15-1551) ........................27IA - CMP-Wyman ................................................................................................................ (ER15-1552) ........................27IA - CMP-Wyman IV ........................................................................................................... (ER15-1553) .......................27LVA/PSNH IA Complaint.................................................................................................... (EL15-9) ..............................26MISO Methodology to Involuntarily Allocate Costs to Entities Outside Its Control Area .. (ER11-1844) ........................30NSTAR/HQ US CMEEC Use Rights Transfer Agreement.................................................. (ER15-1383) ........................29Opinion 531-A Compliance Filing: NGrid IFA Amendments.............................................. (ER15-418) ..........................29Riggs v. RI PUC: Deepwater Wind FPA/PURAP/Supremacy Clause Complaint ............... (EL15-61) ............................26Termination of Braintree Participation in REMVEC II Agreement ..................................... (ER15-1530) ........................28

XII. Misc: Administrative & Rulemaking Proceedings

NOPR: MBR Authorization Refinements ............................................................................ (RM14-14) ...........................35NOPR: Open Access and Priority Rights on ICIF................................................................ (RM14-11) ...........................35NOPR: Third-Party Provision of Primary Frequency Response Service.............................. (RM15-2) .............................34Order 676-H: Incorporation of WEQ Version 003 Standards .............................................. (RM05-5) .............................37Order 771: Availability of E-Tag Information to FERC Staff ............................................. (RM11-12) ...........................36Price Formation in RTO/ISO Energy & Ancillary Services Markets................................... (AD14-14) ...........................33RTO/ISO Winter 2013/14 Operations and Market Performance.......................................... (AD14-8) .............................34Technical Conferences on Implications of Environmental Regulations............................... (AD15-4) .............................32WIRES Request for Policy Statement on ROE for Electric Transmission ........................... (RM13-18) ...........................36



Enforcement Actions: BP ..................................................................................................... (IN13-15) .............................39Inquiry Into Natural Gas Trading, and Proposal to Establish an Electronic Information

and Trading Platform..................................................................................................... (AD14-19) ...........................38New England Pipeline Proceedings...................................................................................... .............................................39Order 809: Coordination of the Scheduling Processes of Interstate Natural Gas Pipelines

and Public Utilities ........................................................................................................ (RM14-2) .............................38Posting of Offers to Purchase Capacity (Section 5 Proceeding)........................................... (RP14-442) ..........................38



XV. Federal Courts

2013/14 Winter Reliability Program and Bid Results ..........................................................14-1104 (DC Cir.)................42CPV Maryland, LLC v. PPL EnergyPlus et al. ....................................................................14-623 (Supreme Court) ......43CPV Power Development, Inc., et al. v. PPL EnergyPlus, LLC, et al. ................................14-634/694 (Supreme Ct) ....45Demand Curve Changes ......................................................................................................15-1070 (DC Cir.)) ..............41Entergy Nuclear Fitzpatrick, LLC et al v. Zibelman et al ....................................................5:15-cv-00230 (N.D.N.Y.)...45FCM Administrative Pricing Rules Complaint ....................................................................15-1071 (DC Cir.)................41FCA8 Results .......................................................................................................................14-1244 (DC Cir.)................41New England’s Order 745 Compliance Filing .....................................................................12-1306 (DC Cir.)................42Orders 745/745-A ................................................................................................................14-840 (Supreme Court) ......42Orders 773/773-A .................................................................................................................13-2316 (2nd Cir.) ...............42

Documents

Summary of ISO New England Board and Committee Meetings May 1, 2015 ... · 01-05-2015 · Commission. Next, the Committee was provided with a review of summer 2014 and a report on