# 2014 Long

- Term Reliability Assessment

November 2014

# Table of Co nte nts

Preface

................................ ................................ ................................ ................................ ................. i Executive Summary

................................ ................................ ................................ .............................. 1 Key Reliabil ity Findings

................................ ................................ ................................ ........................ 2

1. Reserve Margins in Several Assessment Areas Trend Downward, Despite Low Load Growth

................................ ........... 2
2. Environmental Regulations Create Uncertainty and Require Assessment

................................ ................................ ......... 8
3. A Changing Resource Mix Requires New Approaches for Assessing Reliability

................................ ............................... 18 Other Reliability Issues

................................ ................................ ................................ ................................ .............................. 30 

### Assessment Area Reliability Findings

................................ ................................ ................................ .. 33
FRCC

................................ ................................ ................................ ................................ .................. 36
MISO

................................ ................................ ................................ ................................ .................. 38
MRO

- Manitoba Hydro

................................ ................................ ................................ ........................ 42
MRO

- MAPP

................................ ................................ ................................ ................................ ........ 45
MRO

- SaskPower

................................ ................................ ................................ ................................ 47
NPCC

- Maritimes

................................ ................................ ................................ ................................ . 51
NPCC

- New Engla nd

................................ ................................ ................................ ............................ 54
NPCC

- New York

................................ ................................ ................................ ................................ .. 60
NPCC

- Ontario

................................ ................................ ................................ ................................ ..... 63
NPCC

- Québec

................................ ................................ ................................ ................................ ..... 68
PJM

................................ ................................ ................................ ................................ .................... 72
SERC

................................ ................................ ................................ ................................ .................. 78
SPP

................................ ................................ ................................ ................................ .................... 82

TRE

- ERCOT

................................ ................................ ................................ ................................ ......... 85
WECC

................................ ................................ ................................ ................................ ................. 89 Appendix I: 2014LTRA Reference Case Data Summary

................................ ................................ ........ 96 Appendix II: Reliability Assessment Glossary

................................ ................................ .................... 101 Appendix III: 2014 Polar Vortex Scenario Analysis

................................ ................................ ............ 105

### NERC | 2014 Long

- Term Reliability Assessment | November 201 4
i 

# Preface
The North American Electric Reliability Corporation (NERC) has prepared the following assessment in accordance with the Energy Policy Act of 2005, in which the United States Congress directed NERC to conduct periodic assessments of the reliability and adequacy o f the bulk power system (BPS) in North America. 1 

### NERC operates under similar obligations in many Canadian prov inces, as well as a portion of Baja California Norte, Mexico.

NERC is an international regulatory authority established to evaluate and improve the reliability of the BPS in North America

. NERC develops and enforces Reliability Standards; annually assesses seasonal and long

- term (10

- year) reliability ; monitors
the BP S through system awareness; and educates, trains, and certifies industry personnel. NERC is the electric reliability organization (ERO) for North America, subject to oversight by the U.S. Federal Energy Regulatory Commission (FERC) and governmental authori ties in Canada. 2



### Reliability Standards are the planning and operating rules that electric utilities follow to support and maintain a reliable electric system. These standards are developed by the industry using a balanced, open, fair, and inclusive process accredited by the American National Standards Institute (ANSI). While NERC does not have authority to set Reliability St andards for resource adequacy (e.g., Reserve M argin criteria) or to order the construction of resources or transmission, NERC can indep endently assess where reliability issues may arise and identify emerging risks. This information, along with NERC recommendations, is then made available to policy makers and federal, state, and provincial regulators to support decision making within the e lectric sector.

NERC prepares seasonal and long

- term assessments to examine the current and future reliability, adequacy, and security of the North American BPS. For these assessments, the BPS is divided into 20 assessment areas, 3 

### both within and across the eight Regional Entity boundaries, as shown in the corresponding table and maps below

. 4 

### The preparation of these assessments involves NERC’s collection and consolidation of data from the Regional Entities. Reference case data inc ludes projected on

- peak demand and energy, Demand Response (DR), resource capacity, and transmission projects. Data and information from each NERC Region are also collected and used to identify notable trends, emerging issues, and potential
concerns. This bottom

- up approach captures virtually all electricity supplied in the United States, Canada, and a portion of Baja California Norte, Mexico. NERC’s reliability assessments are developed to inform industry, policy makers, and regulators
and to aid NERC in a chieving its mission

— to ensure the reliability of the North American BPS.

1 H.R. 6 as approved by of the One Hundred Ninth Congress of the United States, the Energy Policy Act of 2005 . The NERC Rules of Procedure, Section 800, further detail the Objectives, Scope, Data and Information requirements, and Reliability Assessment Process requiring annual seasonal and long

- term reliability assessments.

2 As of June 18, 2007, FERC granted NER C the legal authority to enforce Reliability Standards with all U.S. users, owners, and operators of the BPS and made compliance with those standards mandatory and enforceable. Equivalent relationships have been sought and for the most pa rt realized in Can ada and Mexico. Prior to adoption of §215 in the United States, the provinces of Ontario (2002) and New Brunswick (2004) adopted all Reliability Standards that were approved by the NERC Board as mandatory and enforceable within their respective jurisdictio ns through market rules. Reliability legislation is in place or NERC has memoranda of understanding with provincial authorities in Ontario, New Brunswick, Nova Scotia, Québec, M anitoba, Saskatchewan, British Columbia, and Alberta, and with the National Ene rgy Board of Canada (NEB). NERC standards are mandatory and enforceable in Ontario and New Brunswick as a matter of provincial law. Manitoba has adopted legislation, and standards are mandatory there. In addition, NE RC has been designated as the “electric reliability organization” under Alberta’s Transportation Regulation, and certain Reliability Standards have been approved in that jurisdiction; others are pending. NERC standards are now mandatory in British Columbia and Nova Scotia. NERC and the Northeast Power Coordinating Council (NPCC) have been recognized as standards

- setting bodies by the Régie de l’énergie of Québec, and Québec has the framework in place for Reliability Standards to become mandatory. NEB has made Reliability Standards mandatory for i nternational power lines. In Mexico, the Comisión Federal de Electricidad (CFE) has signed WECC’s reliability management system agreement, which only applies to Baja California Norte.

3 The number of assessment areas has been reduced from 26 to 20 since th e release of the 2013LTRA.

4 Maps created using Ventyx Velocity Suite.

### Preface

NERC | 2014 Long

- Term Reliability Assessment | November 201 4
ii NERC Regions and Assessment Areas

5 FRCC Region and Assessment Area boundaries are the same.

6 The MISO footprint is primarily located in the MRO Region, with smaller portions in the SERC and RF Regions. For NERC’s asse ssments, the MRO Region oversees the collection of data and information from MISO.

7 The PJM footprint is primarily located in the RF Region, with smaller portions in the SERC Region. For NERC’s assessments, th e RF Region oversees the collection of data an d information from PJM. FRCC

– Florida Reliability Coordinating Council
FRCC 5
MRO

– Midwest Reliability Organization
MISO 6
MRO

- Manitoba Hydro
MRO

- MAPP MRO

- SaskPower
NPCC

– Northeast Power Coordinating Council
NPCC

- Maritimes:
NPCC

- New England
NPCC

- New York
NPCC

- Ontario
NPCC

- Québec
RF

– Reliability First
PJM 7
SERC

– SERC Reliability Corporation
SERC

- E ast SERC

- N orth
SERC

- Southeast
SPP RE

– Southwest Power Pool Regional Entity
SPP
TRE

– Texas Reliability Entity
TRE

- ERCOT
WECC

– Western Electricity Coordinating Council
WECC

- CA/MX
WECC

- NWPP
WECC

- RMRG
WECC

- SRSG

### Preface

NERC | 2014 Long

- Term Reliability Assessment | November 201 4
iii The North American Electric Reliability Corporation
Atlanta 3353 Peachtree Road NE, Suite 600

– North Tower Atlanta, GA 30326
404

- 446

- 2560
Washington, D.C. 1325 G Street NW, Suite 600 Washington, DC 20005
202‐400‐3000

Assessment Data Questions Please direct all data inquiries to NERC staff ( assessments@nerc.net ). References to the data and/or findings of the assessment are welcome with appropriate attribution of the source to the NERC 2014 Long

- Term Reliability Assessment

. However, extensive reproduct ion of tables and/or charts will require permission from NERC staff.

NERC Reliability Assessment Staff

Name Position Mark Lauby Senior Vice President and Chief Reliability Officer Thomas Burgess Vice President and Director, Reliability Assessment and Performance Analysis John N. Moura Director , Reliability Assessment Ganesh Velummylum Senior Manager , Reliability Assessment Noha Abdel

- Karim Senior Engineer , Reliability Assessment Trinh C. Ly Engineer , Reliability Assessment Michelle Marx Administrative Assistant , Reliability Assessment and Performance Analysis Amir Najafzadeh Engineer , Reliability Assessment Elliott J. Nethercutt Senior Technical Analyst, Reliability Assessment Pooja Shah Senior Engineer , Reliability Assessment


### NERC Reliability Assessment Subcommittee Roster

Name Position R egion/ Organization Name Position Region/Organization Layne Brown Chair WECC* Paul D. Kure Member RF Ryan Westphal Vice Chair MISO James Leigh

- Kendall Member SMUD Mohammed Ahmed Member AEP Ben Lewiski Member MRO Salva R. Andiappan Member MRO Bob Mariotti Member DTE Energy Bagan Bagen Member Manitoba Hydro Joel B. Mathewson Member SERC Richard Becker Member FRCC * John G. Mosier Member NPCC Gary S. Brinkworth Member TVA Maryam Naghsh

- Nilchi Member MISO K.R. Chakravarthi Member SERC/Southern Company Vince Ordax Member FRCC Digaunto Chatterjee Member MISO Paul Roman Member NYISO Lewis De La Rosa Member TRE* John Seidel Member MRO Barbara A. Doland Member SERC* Travis Tate Member SERC Philip A. Fedora Member NPCC* Alan C. Wahlstrom Member SPP RE* Tim FryFogle Member RF* Paul Walter Member MRO*/ATC Chris Haley Member SPP Inc. Peter Warnken Member ERCOT Kevan L. Jefferies Member OPG Ryan Westphal † Member MISO Srinivas Kappagantula Member PJM Peter Wong Member ISO

- NE Esam A.F. Khadr Member PSE&G Brad Woods Member TRE William B. Kunkel Member MRO Hurbert C. Young Member Scana Mark J. Kuras Member PJM Daniel Brooks Observer EPRI Tina G. Ko Observer B PA Micheal Courchesne Observer ISO

- NE Denise Lam Observer FRCC Maria Haney Observer SERC Louise Nutter Observer FERC Maria A. Hanley Observer DOE

- NETL Alan Phung Observer FERC Patricia Hoffman Observer DOE Michael Milligan Observer DOE

- NREL

### Preface

NERC | 2014 Long

- Term Reliability Assessment | November 201 4
iv Assessment Preparation and Design
The 2014 Long

- Term Reliability Assessment (2014LTRA) is based on resource adequacy 8 

### information collected from the eight Regional Entities (Regions) that is used to independently assess the long

- term reliability of the North American BPS while identifying trends, emerging issues, and potential risks. The LTRA is developed annually by NERC in accordance with the ERO’s Rules of Procedure, 9 

### as well as Title 18, § 39.11 10 

### of the Code of Federal Regulations, 11 

### also referred to as Section 215 of the Federal Power Act, which instructs NERC to conduct periodic assessments of the North American BPS. 12



### This assessment is based on data and information collected by NERC from the Regions on an A ssessment A rea

- basis as of September 2014. The Reliability Assessment Subcommittee (RAS)

, at the direction of the Planning Committee (PC)

, supports the LTRA development

. Specifically, NERC and the RAS perform a thorough peer review that leverage s the knowledge and experience of industry subject matter experts while providing a balance to ensure the validity of data and information provided by the Regions . Each Assessment Area section is peer reviewed by members from other Regions to achieve a comprehensive review that is verified by the RAS in open meet ings. The review process ensures the accuracy and completeness of the data and information provided by each Region . This assessment has been reviewed and endorsed by the

PC

. T he NERC Board of Trustees also reviewed and approved this report.

The 2014LTRA reference case does not reflect impacts that may result from the D

. C

. Circuit Court’s mandate to vacate FERC
Order No. 745

, 13 

### nor the impacts that may arise from the EPA’s proposed Clean Power Plan (Clean Air Act

– Section 111(d) )

, currently open for public c omment through December 1, 2014. While NERC provides a summary of the EPA’s proposed Clean Power Plan, quantitative i mpacts from these developments will be considered for inclusion in future NERC assessments.

Data Concepts and Assumptions Guide
The table b elow explains data concepts and important assumptions used throughout this assessment. Data Concepts and Assumptions Guide
General Assumptions The Reserve Margin calculation is an important industry planning metric used to examine future resource adequacy. This deterministic approach examines the forecast peak demand (load) and projected availability of resources to serve the forecast peak demand for the summer and winter of the 10

- year outlook (2015

– 2024). All data in this assessment are based on existing federal, state, and provincial laws and regulations. Demand Assumptions Electricity demand projections, or load forecasts, are provided by each Assessment Area. Load forecasts include peak hourly load, 14 or Total Internal Demand, for the summer and winter of each year. 15
Total Internal D emand projections are based on normal weather (50/50 distribution) 16 and is provided on a coincident basis for most
Assessment Areas. 17

8 Adequacy means having sufficient resources to provide customers with a continuous supply of electricity at the proper voltage and frequency, virtually all of the time. Resources refer to a combination of electricity

- generating and transmission facilities that produce and deliver electricity, and demand

response programs that reduce customer demand for electricity. Adequacy requires System Operators and planners to account for scheduled and reasonably expected unscheduled outages of equipment, while maintaining a constant balance between supply and demand.

9 NERC Rules of Procedure

- Section 803

. 10 Section 39.11(b) of the U.S. FERC’s regulations provide: “The Electric Reliability Organization shall conduct assessments of the adequacy of the Bulk

Power System in North America and report its findings to the Commission, the Secretary of Energy, each Regional Entity, and e ach Regional Advisory Body annually or mor e frequently if so ordered by the Commission.”

11 Title 18, § 39.11 of the Code of Federal Regulations

. 12 BPS reliability, as defined in the How NERC D efines BPS Reliability section of this report, does not include the reliability of the lower

- voltage distribution systems, which systems use to account for 80 percent of all electricity supply interruptions to end

- use customers.

13 United States Court of Appeals for the District of Columbia Circuit

- No.11

- 1486

. 14 Glossar y of Terms Used in NERC Reliability Standards

. 15 The summer season represents June

– September and the winter season represents December

– February.

16 Essentially, this means that there is a 50 percent probability that actual demand will be higher and a 50 percent probability that actual demand will be lower than the value provided for a given season/year.

17 Coincident: The sum of two or more peak loads that occur in the same hour. Noncoincident: The sum of two or more peak loads on individual systems that do not occur in the same time interval. Meaningful only when considering loads within a limited period of time, such as a day, a week, a month, a heat ing or cooling season, and usually for not more than one year. SERC and FRCC calculate Total Internal Demand on a noncoincide ntal basis.

### Preface

NERC | 2014 Long

- Term Reliability Assessment | November 201 4

v Total Internal Demand includes consi derations for reduction in electricity use due to projec ted impacts of energy efficiency and conservation programs.
Ne t Internal Demand, used in all Reserve M argin calculations, is equa l to Total Internal Demand, reduced by the amount of Controllable and Dispatchable Demand Response projected to be available during the peak hour. Resource Assumptions NERC collects projections for the amount of existing and planned capacity, and net capacity transfers (between Assessment Areas) that will be available during the forecast hour of peak demand for the summer and winter seasons of each year. Resource planning methods vary throughout the North American BPS. NERC uses the following categories to provide a consistent approach fo r collecting and presenting resource adequacy: Anticipated Resources

 Existing

- Certain generating capacity: includes operable capacity expected to be available to serve load during the peak hour with
Firm transmission.

 Tier 1 capacity additions: includes capacity that is either under construction or has received approved planning requirements.

 Firm Capacity Transfers (Imports minus Exports): transfers with Firm contracts. Prospective Resources : Includes all Anticipated Resources, plus:

 Existing

- Other capacity: includes operable capacity that could be available to serve load during the peak hour, but lacks Firm transmission and could be unavailable for a number of reasons.

 Tier 2 capacity additions: includes capacity that has been requested, but not received approval for planning requirements. Up to 50 percent of total Tier 2 capacity is counted toward the Prospective Resources category.

 Expected (non

- F irm) Capacity Transfers (Imports minus Exports): transfers without Firm contracts, but a high probability of future implementation. Adjusted

- Potential Resources : Includes all Prospective Resources, plus:

 Tier 3 capacity additions: includes additional resources that do not meet Tier 2 requirements. Up to 10 percent of total Tier 3 capacity is counted toward the Adjusted

- Potential Resources category. Reserve Margins Reserve Margins : the primary metric used to measure resource adequacy, defined as the difference in resources (Anticipated, Prospective, or Adjusted

- Potential) and Net Internal Demand, divided by Net Internal Demand , shown as a percentile.

Anticipated Reserve Margin = (Anticipated Resources

– Net Internal Demand)
Net Internal Demand

Prospective Reserve Margin = (Prospective Resources

– Net Internal Demand)
Net Internal Demand

Adjusted

- Potential Reserve Margin = (Adjusted

- Potential Resources

– Net Internal Demand)
Net Internal Demand Reference Margin Level : the assumptions of this metric var y by Assessment Area . Generally, the Reference Margin Level is typically based on load, generation, and transmission characteristics for each Assessment Area and

, in some cases, the Reference Margin Level is a requirement implemented by the respective state(s), provincial authorities, ISO/RTO, or other regulatory bodies. If such a requirement exists, the respective Assessment Area generally adopts this requirement as the Reference Margin Level. In some cases, the Reference Margin Level will fluctuate over the duration of the assessment period, or may be different for the summer and winter seasons. If one is not provided by a given Assessment Area, NERC applies a 15 percent Reference Margin Level for predominately thermal systems and 10 percent for predominately hydro systems. Fuel Types NERC collects and presents data on the generation mix based on the general fuel type identified for each unit . The fuel type is ba sed on the prime movers and primary fuel type codes identified in the Form EIA

- 860 and provided below : 18
Coal : Anthracite (ANT), Bituminous (BIT), Lignite (LIG), Subbituminous (SUB), Waste/Other (WC), Refined (RC)
Petroleum : Distillate Fuel Oil (DFO), Jet Fuel (JF), Kerosene (KER), Petroleum Coke (PC), Residual Fuel Oil (RFO), Waste/Other Oil (WO)
Natural Gas : Blast Furnace (BFG), Natural (NG), Other (OG), Propane (PG), Synthesis from Petroleum Coke Gas (SGP), Coal

- Derived Synthesis Gas (SGC)
Biomass : Agricultural By

- Products (AB) Municipal Solid Waste (MSW) Other Biomass Solids (OBS), Wood/ Wood Waste Solids (WDS), Other Biomass Liquids (OBL), Sludge Waste (SLW), Black Liquor (BLQ), Wood Waste Liquids (WDL), Landfill Gas (L FG), Other Biomass Gas (OBG) Renewables : Solar (SUN), Wind (WND), Geothermal (GEO), Hydroelectric (fuel type: WAT; primary mover: HY) Pumped Storage : Pumped Storage (fuel type: WAT; primary mover: PS) Nuclear : Nuclear (NUC)

18 Additional information on fuel codes and prime movers are available in the Form EIA

- 860

.

### NERC | 2014 Long

- Term Reliability Assessment | November 201 4

1 

# Executive Summary

The 2014 Long

- Term Reliability Assessment (2014LTRA) is a report that provides a wide

- area perspective on the adequacy of the generation

, demand

- side resources

, and transm ission systems necessary to meet system reliability needs over the next
decade

. This assessment includes NERC ’s independent identi fication of issues that may impact the reliability of the North
American Bulk

- Power System ( BPS ) to provide indust ry, regulators, and policy makers with adequate time to address or otherwise develop plans to mitigate potential reliability impacts caused by these issues

. Th is assessment also documents current industry plans to m aintain reliability during the next decade, advising regulators, policy makers, and the general public of existing and potential challenges, complexities, and interdependencies.

The electricity industry provided NERC with resource adequacy projections for the 201 5

– 2024 assessment period

. NERC independently assessed these projections and identified three key findings that will impact the long

- term reliability of the North American BPS and materially change the way the system is planned and operated. These key findings are:

1. Reserve Margins in s everal Assessment Areas are t rend ing d ownward, d espite l ow l oad g rowth

. 2. Environmental r egulations c reate u ncertainty and r equire a ssessment

. 3. A c hanging r esource m ix r equires n ew a pproaches for a ssess ing r eliability

.

The on

- peak resource mix has recently shifted to be predominately gas fired : now 40 percent
, compared to 28 percent just five years ago. 19 

### This trend is expected to continue, as retiring coal, petroleum, nuclear, and other conventional generation is largely being replaced by gas

- fired capacity and v ariable e nergy r esources (VERs )

. 20 

### Th e fundamental transformation of the
resource mix

— largely driven by environmental regulations

, legislation

, state and provincial incentives for additional VERs, and impacts of fuel prices

, particularly for natural gas

— present s new challenges for the electricity industry.

System planners should ensure S ystem O perators have the tools and resources needed to maintain reliability in the midst of
this transformation . For example, typ ical planning approaches focus on ensuring capacity is procured and available to meet the hour of peak demand for each season, perceived as the highest stress on the system. However, stresses during shoulder periods or off

- peak hours can introduce a differ ent set of challenges , such as the management of over generation periods when generation exceeds demand ; this is generally introduced by an excess of less

- flexible resources

. Additionally, gas generation and other flexible resources need further study to ensure availability to balance load during off

- peak and shoulder periods.

T hese changes also provide opportunities to the industry as more responsive gas

- fired generators can provide S ystem
O perators with needed flexibility to address addi tional VER s , such as wind and solar resources , on the system

. Similarly, the application of energy storage and D emand

- S ide M anagement (DSM) technologies has the potential to offer approaches to meeting demand and balancing it with greater efficiency

. New technologies ( e.g., s mart g rid devices and applications

, p hasor

m easurement u nits (PMU)

, r emedial a ction s chemes, new forecasting capabilities, greater system awareness, etc.) can also advance the industry ’ s ability to dynamically control grid facilities and improve coordination between S ystem O perators, gr id resources, and the consumer.

In preparing this assessment, NERC examined key reliability indicators of resource adequacy projections , including load
forecasts

, projected resource s , and transmission enhancements . Based on these projections and input from the industry

, NERC identified three key reliability findings that each includ e a subset of issues that will impact resource adequacy, transmission adequacy , or sy stem operations during the next decade. T he se findings are cros s

- cutting and interdependent

,
as many of the issues present unique challenges to the electricity industry

.

19 NERC 2009 Long

- Term Reliability Assessment

. 20 NERC IVGTF Reports

.

### NERC | 2014 Long

- Term Reliability Assessment | November 201 4
2 

# Key Reliability Findings

This section provides an overview of each key finding as well as the potential reliability impacts and corresponding importan ce of ERO

- wide coordination in addressing them. Observations and recommendations will also be included for NERC, industry, and poli cy makers.

1. Reserve Margins in Several Assessment Areas Are Trend ing Downward, Despite Low Load Growth
Planning Reserve Margins are the primary metric used in this assessment to consistently examine future resource adequacy and raise industry awareness of potential resource adequacy concerns. 21



### Declining Demand Growth and Projected Capacity Additions According to the 2014LTRA reference case , the NERC

- wide annual demand growth rate is 1.05 percent for the summer and 0.97 percent for the winter

, which are the lowest growth rates on record for both seasons. 22 

### With lower rates of demand growth, the contribution of Demand Response (DR) has also plateaued in recent years, with minimal additional program growth projected in the reference case. 23



### NERC

- Wide Demand: 10

- Year Growth Rates (Summer and Winter) at Lowest Levels on Record

* Prior to the 2011LTRA, t he initial y ear of the 10

- year assessment period is the report year (e.g., the 10

- year assessment period for the 1990LTRA
is 1990

– 1999). The 2011LTRA and subsequent LTRAs examine the initial year of the assessment period as one year out (e.g., the 10

- year assessment period for the 2011LTRA is 2012

– 2023)

. 

### Most Assessment Areas attribute stagnant demand growth to the ongoing projected economic in dicators (typically based on either employment levels or gross domestic product ( GDP ) ) in the residential, commercial, and industrial sectors. Energy

e fficiency and conservation programs

, as well as time

- of

- use rate programs in many areas continue to drive lower energy growth, and in some cases, the correlation between economic growth and load growth is no longer positive. Distributed generation (distributed energy resources) in NPCC

- Ontario (

- 0.09 percent load growth) and WECC

- CA/MX (0.25 percent load

grow th) has also reduced end

- use or grid

- supplied electricity demand. The following map includes peak season demand growth rates for each Assessment Area.

21 Reserve Margin projections are presented in Appendix I.

22 Compound annual growth rate (CAGR) provides the year

- over

- year growth rate over the duration of the assessment p eriod. It is derived as follows: CAGR = (Year 10 / Year 1)^(1 / 9)

– 1.

23 When examining the peak season for each Assessment Area, NERC

- wide Controllable and Dispatchable DR is projected to grow by 1.7 GW (increasing from 38.9 GW in 2015 to 40.6 GW in 2024 ). 0.97% 1.05%

60 70 80 90 100 110 120 130 140 150 160 170 180 190 200

0.0% 0.2% 0.4% 0.6% 0.8% 1.0% 1.2% 1.4% 1.6% 1.8% 2.0% 2.2% 2.4%

Gigawatt Compound Annual Growth Rate (CAGR)

NERC LTRA
10-Year Summer Growth 10-Year Winter Growth Winter CAGR Summer CAGR

### Key Reliability Findings

NERC | 2014 Long

- Term Reliability Assessment | November 201 4
3 10

- Year Compound Annual Growth Rate (Peak Season) Below 2 Percent for Most Assessment Areas

Decline 0

- 1% Growth 1

- 2% Growth >2% Growth 

### Total capacity additions have paralleled the ongoing declines in load growth, with only 99.6 GW ( 66.9 GW on peak) of Tier 1 capacity additions pr ojected during the next decade, compared to 1 50 GW projected in the 2011LTRA r eference c ase

. Additionally, 39 GW of capacity has retired since 2011, with another 44.6 GW 24 

### of retirements projected by 2024.

NERC

- Wide 10

- Year Projected Capacity Additions Declining Since 2011 25



### Considering the ongoing decline in load growth, fewer capacity additions are necessary to maintain adequate planning

reserves. However, Anticipated Reserve Margins for several A ssessment A reas have been showing declining trends

, especially when examining s hort

- term proj ections in the prior three LTRA reference cases

.

24 Includes 21.7 GW of coal, 15.8 GW of natural gas, 4.5 GW of nuclear, 2 GW of petroleum, and 0.5 GW of other capacity retireme nts (summer ratings).

25 2011, 2012, and 2013LTRA data includes Future

- Planned capacity additions. The 2014LTRA data includes T ier 1 capacity additions.

60 65 70 75 80 85 90 95 100 105 110 115 120 125 130 135 140 145 150 155 2014LTRA 2013LTRA 2012LTRA 2011LTRA

Gigawatts
On-Peak Nameplate

### Key Reliability Findings

NERC | 2014 Long

- Term Reliability Assessment | November 201 4

4 Short

- Term (Year 2 Forecast) Anticipated Reserve Margins Show Declining Trends for Some Assessment Areas

* Due to changes to the WECC subregional boundaries, resulting in four subregions instead of nine

, the 2014 Anticipated Reserve Margins are not
shown for WECC

- BASN and WECC

- ROCK for this comparison.


### In recent long

- term assessments, NERC highlighted resource adequacy concerns, particularly in ERCOT , NPCC

- New York, and MISO, as projections continue d to reflect declining Anticipated Reserve M argins that f e ll below each area’s Reference Margin Level during the short term (1

- 5 years).

TRE

- ERCOT: R ecent Capacity Additions Elevate Planning Reserve Margins through 2018
Since ERCOT ini tially identified potential resource adequacy concerns in 2012, the RTO responded by incentivizing additional participati on in Demand Response (DR) and energy efficiency programs. More recently, n ew gas

- fired resources totaling 2,112 MW (summer rating) were added during the 2014 summer, which elevat es ERCOT’s Anticipated Reserve Margin to 14.3 percent in 2015 . It will remain above the Reference Margin Level (13.75 percent) until summer 2018. Assuming the availability
of less

- certain Prospective Resources , including Tier 2 capacity additions, ERCOT will meet the Reference Margin Level for all years of the assessment period.

TRE

- ERCOT Reserve Margins (Left) and Capacity Shortfall below the Reference Margin Level (Right ) 26

26 The Frontera power plant (three natural

- gas

- fired units totaling 524 MW) is assumed to be available to serve peak load for all years in the 2014LTRA Reference Case. However, the plant’s owner recently announced plans to begin ex porting 170 MW of capacity to Mexico as soon as 2015, and the entire 524 MW in 2016 with the completion of certain transmission projects. ERCOT and the Frontera Facility’s owners have agreed on the reliability safeguards for ensuring the plant will be avai lable if needed in an emergency and have filed those conditions with the U.S. Department of Energy as part of the plant’s export authorization. 0% 5% 10% 15% 20% 25% 30% 35% 40%

11 12 13 14 11 12 13 14 11 12 13 14 11 12 13 14 11 12 13 14 11 12 13 14 11 12 13 14 11 12 13 14 11 12 13 14

MISO MAPP NPCC-New England NPCC-New

York NPCC-Ontario SERC-E SERC-N WECC-BASN* WECC-ROCK*

LTRA Year by Assessment Area

0% 3% 6% 9% 12% 15% 18% 21%

2015 2016 2017 2018 2019 2020 2021 2022 2023 2024

Anticipated Prospective Adjusted-Potential Reference Margin Level 0.1

1.9 3.0 3.7 5.0 5.8 6.9

0.00% 13.75%

2015 2016 2017 2018 2019 2020 2021 2022 2023 2024

Anticipated Reserve Margin (%) Capacity Shortfall (GW)

### Key Reliability Findings

NERC | 2014 Long

- Term Reliability Assessment | November 201 4
5 TRE

- ERCOT Capacity Additions and Retirements
Capacity Additions 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 Cumulative Tier 1 Additions 2,801 3,724 4,528 5,410 5,650 5,650 5,650 5,650 5,650 5,650 Cumulative Tier 2 Additions 4,369 14,027 21,360 25,814 25,814 25,814 25,814 25,814 25,814 25,814
Retirements 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 Cumulative Retirements

- 2,311

- 2,430

- 2,430

- 2,430

- 2,430

- 3,270

- 3,270

- 3,270

- 3,270

- 3,270 Net Capacity Change 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024
Tier 1 Additions, Less Retirements 490 1,294 2,098 2,980 3,220 2,380 2,380 2,380 2,380 2,380 Tier 1 & Tier 2 Additions, Less Retirements 4,859 15,320 23,458 28,794 29,034 28,194 28,194 28,194 28,194 28,194


### Additional Tier 1 capacity in TRE

- ERCOT totals over 5.6 GW during the 10

- year outlook, with an additional 25.8 GW of Tier 2 additions, while projected retirements total 2.3 GW (including unit suspensions and mothballs).

It is also important to note the imp acts of recent modifications to ERCOT’s load forecast method

, which incorporates a neural
network mod el to forecast daily energy. Additionally, ERCOT is now incorporating regional growth forecasts for each customer class (residentia l, commercial, and industrial) instead of observing only non

- farm employment as the economic
driver

. These new assumptions result in a compound annual growth rate (CAGR) of 1.29 percent for the 10

- year summer demand projections in the 2014LTRA reference ca se
— substantially lower than the 2.35 and 1.38 percent CAGR s reflected in
the 2012LTRA and 2013LTRA reference cases , respectively

.

MISO : Generator Retirements, Transfer Limitations, and Resource Procurement Contribute to Deficit Margins in 2016
MISO’s A ntic ipated Reserve Margin will drop below the Reference Margin Level ( 14.8 percent) in 2016, declining to 5.23 percent by 2024

. The Reference Margin Level for MISO is based on a 14.8 percent requirement as determined by th e 1

- day

in

- 10

- year Loss of Load Expectation ( LOLE ) ( MISO criteria )

. Accordingly, i n 2016
, MISO projects it will operate at the relia bility level of approximately 2

- days

- in

- 10

- year LOLE , increasing the likelihood that resources will not be sufficient to serve peak
demand. Th e number of expected days

- per

- year of a n LOLE is projected to increase throughout the assessment period. Potential environmental regulations could further exacerbate resource adequacy concerns in the MISO footprint unless additional replacement capacity is built in a timely fashion.

MISO Reserve Margins (Left) and Capacity Shortfall below the Reference Margin Level (Right)

As MISO starts to operate at or near its Reference Margin Level, there is a higher likelihood that System Operator s will call Emergency Operating P rocedure s more frequently to access Emergency

- Only resources , l oad

- modifying resources

, and
b ehind

- the

- m eter generation (BTMG)

. The contributing factors dr iving the projected deficit include:

 Increased retirements and suspensions (temporary mothballing) due to Environmental Protection Agency ( EPA ) regulations and market forces and low natural gas prices

 Exclusion of low

- certainty resources that were identified in the Resource Adequacy survey 0% 3% 6% 9% 12% 15% 18% 21% 24%

2015 2016 2017 2018 2019 2020 2021 2022 2023 2024

Anticipated Prospective Adjusted-Potential Reference Margin Level 2.3 1.5 3.6 4.9 6.0 8.8 10.2 12.3 13.8

0.0% 14.8%

2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 Anticipated Reserve Margin (%) Capacity Shortfall (GW)

### Key Reliability Findings

NERC | 2014 Long

- Term Reliability Assessment | November 201 4
6  Exclusion of surplus of capacity in MISO South above the 1,000 MW transfer from the Planning Reserve Margin requirement ( PRMR ) 27



###  Increased exports to PJM and the removal of non

- F irm imports 28



###  Inadequate Tier 1 capacity additions 29



### C onsidering the 8.6 GW of low

- certainty resources captured in MISO’ s generator survey, the projected 10.8 GW of retirements far exceed Tier 1 capacity additions of 3.6 GW. Even when taking into account Tier 2 capacity additions, more
resources will be needed to address the ongoing load growth of 0.82 percent annually

. MISO Capacity Additions and Retirements
Capacity Additions 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 Cumulative Tier 1 Additions 1,167 1,636 2,982 3,528 3,579 3,579 3,579 3,579 3,579 3,579 Cumulative Tier 2 Additions 626 642 642 642 642 642 642 642 642 642
Retirements 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 Cumulative Retirements

- 3,867

- 4,824

- 6,424

- 6,424

- 7,224

- 7,524

- 9,124

- 9,424

- 10,524

- 10,824 Net Capacity Change 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024
Tier 1 Additions, Less Retirements

- 2,699

- 3,188

- 3,442

- 2,896

- 3,645

- 3,945

- 5,545

- 5,845

- 6,945

- 7,245 Tier 1 & Tier 2 Additions, Less Retirements

- 2,073

- 2,546

- 2,800

- 2,254

- 3,003

- 3,303

- 4,903

- 5,203

- 6,303

- 6,603



### NPCC

- New York : Capacity Retirements and Limited Tier 1 Capacity Additions Result in the Anticipated Reserve Margin

F alling B elow the Reference Margin Level in 2017 The New York Independe nt System Operator (NYISO) current ly has an Installed Reserve Margin (IRM) requirement of 17 percent that extends from May 2014 to April 2015. However, because this requirement expires prior to the 2015 summer, a 15 percent Reference Margin Level is applied for all seasons and years of the assessment period. While the Anticipated

Reserve Margin for NPCC

- New Y ork falls below the 15 percent Reference Margin Level in 2017, the Prospective Reserve Margin remains above for all seasons and years of the assessment period. NYISO reports inadequate capacity concerns in
southeast New York beginning as soon as 2019. 30 

### Fut ure transmission reliability issues were identified in four regions of the

state with ongoing capacity retirements and continued demand growth.

NPCC

- New York Reserve Margins (Left) and Capacity Shortfall below the Reference Margin Level (Right)

Projected Tier 1 capacity additions in New York, based on the NYISO planning criteria, include only one 19 MW biomass unit,

exp ected to be in service by the 2016 summer. As demand continues to grow at an average rate of 0.79 percent each year,

27 For this assessment, 1,000 MW of capacity is transferred from the MISO South to the MISO North/Central Region pending the outcome of regulatory issues currently under FERC review.

28 Capacity sales (imports and exports) in MISO depend on decisions of the respective resource owners, assuming that the tariff requirements are met (including planning of necessary trans mission of both the buying and selling areas). Regarding the removal of non

- Firm imports, the MISO market monitor double

- counted non

- Firm imports in the 2013LTRA reference case. These imports are accounted for in the Reference Margin Level (PRMR).

29 In the MISO footprint, 91 percent of the load is served by utilities with an obligation to serve customers reliably and at a reasona ble cost. Resource planning and investment in resources are part of state and locally jurisdictional integrated resource plans tha t only become certain upon the receipt of a Certificate of Public Convenience and Necessity (CPCN).

30 NYISO 2014 Reliability Needs Assessment

. 0% 3% 6% 9% 12% 15% 18% 21% 24% 27% 30%

2015 2016 2017 2018 2019 2020 2021 2022 2023 2024

Anticipated Prospective Adjusted-Potential Reference Margin Level 0.6 1.0 1.4 1.7 1.9 2.2 2.5 2.7

0.0% 15.0%

2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 Anticipated Reserve Margin (%) Capacity Shortfall (GW)

### Key Reliability Findings

NERC | 2014 Long

- Term Reliability Assessment | November 201 4

7 planned reti rements of natural gas, oil, and coal units during the initial years of the assessment period result in declining margins. The availability of Tier 2 capacity additions (3,688 MW) can help offset declining margins and alleviate resource adequacy concerns.

NPCC

- New York Capacity Additions and Retirements
Capacity Additions 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 Cumulative Tier 1 Additions 0 19 19 19 19 19 19 19 19 19 Cumulative Tier 2 Additions 88 2,002 2,653 3,682 3,688 3,688 3,688 3,688 3,688 3,688
Retirements 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 Cumulative Retirements

- 422

- 422

- 771

- 771

- 771

- 771

- 771

- 771

- 771

- 771 Net Capacity Change 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 Tier 1 Additions, Less Retirements

- 422

- 403

- 752

- 752

- 752

- 752

- 752

- 752

- 752

- 752 Tier 1 & Tier 2 Additions, Less Retirements

- 334 1,599 1,901 2,930 2,936 2,936 2,936 2,936 2,936 2,936



### Key Reliability Finding #1 Reserve Margins in Several Assessment Areas Trend Downward, Despite Low Load Growth

Observations

The near

- term impacts of the Mercury and Air Toxics Standard (MATS) , recently finalized by the EPA, are factored into this assessment. However, uncertainty remains for a large amount of existing conventional generation that may be vulnerable to retirement resu lting from additional pending regulations

— particularly EPA’s recently proposed Clean Power Plan ( se ction 111(d) of the Clean Air Act). These impacts are discussed in detail in Key Reliability Finding #2.

NERC does not have authority to set Reliability Standards for resource adequacy (e.g., reserve margin criteria) or order the
construction of resources or transmission . H owever, NERC has the responsibility to independently assess where BPS reliability issues may arise and to identify emerging risks to resource adequacy

.


### Recommendations

Continued Heightened Awareness : NERC should continue to raise awarenes s of resource adequacy issues by coordinating regularly with involved parties (state regulators and public utility commissions)

, and support ongoing initiatives to effectively address declining reserve margins.

Further Assessment Using Probabilistic Analys is : NERC should leverage the 2014 Probabilistic Assessment (based on 2014LTRA reference case data; scheduled for release in March 2015) to provide further insights on the resource adequacy concerns in MISO, ERCOT, and NPCC

- New York. This probabilistic approach will examine resource adequacy from an energy perspective, offering a more

in

- depth understanding of the interplay between resource availability (with considerations for transmission constraints) and projected hourly demand. Additio nal information on these new approaches is provided in Key Reliability Finding #3.

### Key Reliability Findings

NERC | 2014 Long

- Term Reliability Assessment | November 201 4
8 2. Environmental Regulations Cre at e Uncertainty and Require Assessment

Environmental r egulations at the state, provincial, and federal levels continue to be the primary driv er s of ongoin g retirements

— primarily fossil

- fired capacity . System planners are respond ing by align ing generation portfolios to comply with
lim its on cross

- state air emissions , surface water regulation, and renewable portfolio standards . Accordingly, NERC continues

to examine and report the corresponding resource adequacy implications and potential reliability concerns associated with these developments.

The accelerated retirement of fossil

- fired generation is expected

, due to increasing costs for compliance with environmental regulations. Coal

- fired power plants are especially vulnerable to the impacts of d eclining revenue s due to lower prices of natural gas (i.e., b ecause natural gas often is the marginal fuel and thus sets prices in RTO/ISO markets, and natural gas influences wholesale electricity prices in non

- RTO markets, the current trend of lower natural gas prices tends to reduce electricity prices and corresponding electricity payments received by all generators )

. 31 

### Concurrent increases in the operating

costs of coal plants are often related to the required installation of environmental control technologies. Before these capital
investments are made, plant owners must consider the future life of the unit(s)

, curren t and future fuel costs and revenues compared to other fuel types, and the impacts of additional environmental regulations. Accordingly, 20.2 GW of mostly
smaller coal

- fired units were retired between 2011 and 2013, while an additional 20.8 GW are projecte d to retire by 2024

. 32



### NERC

- wide, 10.3 GW of n atural

- gas

- fired and 5 GW of petroleum

- fired capacity

— primarily less

- efficient units that have reached the end of their lifespan

— were retired between 2011 and 2013 and typically replaced with newer natural gas
combined

- cycle ( NGCC ) power plant s. 33 

### Additionally, f ive nuclear units totaling 4.3 GW have retired since 2011, including four
units in the US and one unit in Canada 34 

### d espite the relatively lower fuel costs of nuclear compared to coal and natural gas,

opera ti ons and maintenance costs

. 35 

### The nuclear fleet in North America is projected to continue providing critical baseload capacity during the next decade , but operations and maintenance costs will continue to impact the economic viability of certain plants

— particularly those that are smaller or older

.
Cumulative Fossil

- Fuel and Nuclear Retirements between 2011 and 2024 Total 83 GW

31 EIA Annual Energy Outlook

- Issues in Focus: Implications of accelerated power plant retirements

. 32 Dat a for actual retirements (from 2011 to 2013) based on EIA Electric Power Monthly

– February 2014 and Ventyx Velocity Suite . Capacity is based on the net summer rating. Projected retirements (2014

- 2024) are based on the 2014LTRA Reference Case.

33 IBID.

34 IB ID.

35 NEI

- Nuclear Energy in 2014: Status and Outlook

. 0 10 20 30 40 50 60 70 80 90

2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024

Actual 2014 LTRA Reference Case Gigawatts

Coal Natural Gas Nuclear Petroleum

### Key Reliability Findings

NERC | 2014 Long

- Term Reliability Assessment | November 201 4
9 According to the 2014LTRA reference case , an additional 44.2 GW of fossil

- fired and nuclear capacity is projected to retire
between 2014 and 2024. 36 

### These projections are based on the assumption that current environmental regulations will remain unchanged ; it does not include potential impacts of EPA’s recently proposed Clean Power Plan (section 111(d) of the Clean Air Act). A n in

- depth examination of the plan is provided in the next section, while the current status of existing environmental regulations is provided below

.
Status of Existing Regulations Mercury and Air Toxics Standards (MATS)
The EPA issued a rule in December 2011 37 

### to reduce emissions of toxic air pollutants from power plants. MATS was designed

to reduce emissions from existing and planned coal

- and oil

- fired generators by requiring the installation of environmental controls. These controls typically involve the addition of dry sorbent injection systems and/or sulfur dioxide ( SO 2 

### ) scrubber s. Other environmental controls (such as fabric filt ers) are also considered as technologies that remove or limit heavy metal particulate emissions. However, t he final rule allows for upgrades to existing electrostatic precipitators

, potentially negating
the need for expensive retrofits.

The MATS rule in it s current form includes important modifications

, such as the ability to apply for a one

- year extension (beyond the 2015 deadline) to alleviate potential impacts to system reliability and to allow generator owners to install needed compliance equipment. Since the rule was implemented, over 107 applications have been submitted, and 98 have been granted. 38 

### In the coming years, affected g eneration owners will continue to comply either by closing plant s or investing in environmental controls and technologies to ensure compliance with all regulations.

Cross

- State Air Pollution Rule (CSAPR) / Clean Air Interstate Rule (CAIR)
CSAPR was vacated in August 2012 by the U.S. Court of Appe als for the District of Columbia Circuit , at which point CAIR was reinstated. CAIR is designed as a cap

- and

- trade program aimed at reducing emissions of SO 2 

### and nitrogen oxides (NO X 

### ) from
fossil

- fired units with capacities greater than 25 MW in 27 eastern states a nd the District of Columbia. The emissions caps
went into effect in 2009 for NO X 

### and in 2010 for SO 2 

### , and b oth caps are scheduled to be tightened in 2015.

The f lue

- gas desulfurization scrubbers or dry sorbe n t injection systems required to comply with MATS will ultimately result
in SO 2 

### emissions falling to levels lower than the CAIR cap. Therefore, power plant emission controls that meet the SO 2 

### emission requirement of MATS will also fall in compliance with the cap established by CAIR

. In April 201 4, t he U.S. Supreme Court reversed the D.C. Circuit ’ s judgment and remanded the case

. In June 2014, t he U.S. government filed a motion with the U.S. Court of Appeals for the D.C. Circuit to lift the stay of the C SAPR , which was accepted on October 23, 2014

. 39



### Clean Water Act (CWA)

– Section 316(b) Cooling water intake operation and structures are regulated under Section 316(b) of the CWA. 40 

### The 316(b) rule is implemented by the state water permitting agencies through the National Pollution Discharge Elimination System (NPDES) permit program of the CWA. EPA provides state permitting agencies with regulatory guidance and standards to determine
the best technology available to protect aquatic life from impingement (being trapped against the intake screen) and entrainment (passing through the screens and into the plant’s cooling water system). Section 316(b) of the federal CWA requires that the l ocation, design, construction, and capacity of cooling water intake structures for facilities reflect the best technology available for minimizing adverse environmental impact. The f inal rule was signed in May 2014 and released i n

36 While the assessment period for the 2014LTRA is 2015

- 2024, projected retirements for 2014 are included in this analysis.

37 MATS was challenged in the U.S. Court of Appeals for the District of Columbia Circuit in White Stallion Energy Center et al. v. U.S. EPA. The case was heard in December 2013, and a decision was made in April 2014 to uphold the rule.

38 As of September 2014.

39 CSAPR

- Motion to Lif t Stay

40 33 U.S.C. section 1326

.

### Key Reliability Findings

NERC | 2014 Long

- Term Reliability Assessment | November 201 4
10 August 2014 in the Federa l Register

. 41 

### Section 316(b) and resulting impacts to existing and future re sources will depend on how the rule is implemented in each state.

Coal Combustion Residuals (CCRs) The CCRs proposed EPA rule would regulate coal ash to address the disposal risks f rom waste generated by electric utilities and independent power producers. The EPA is considering two possible options for public comment regarding the management of coal ash . Under the first proposal, the EPA would list these residuals as special wastes s ubject to regulation under subtitle C of the Resource Conservation and Recovery Act (RCRA) when destined for disposal in landfills or surface impoundments. Under the second proposal, the EPA would regulate coal ash under subtitle D of RCRA, the section for
nonhazardous wastes. 42



### Canadian Provincial Regulations Canadian regulations for CO 2 

### emissions were finalized in September 2012, establishing regulations to reduce emissions by requiring stringent performance standard s for new coal

- fired electricity generation units and to coal

- fired units that have
reached the end of their economic life. Additional impacts are expected as the rule come s into effect in July 2015 , and units commissioned prior to 1975 will have reached the end life after 50 years, or by 2019 (whichever comes first, depending on
whether some units adopt carbon capture and sequestration technology )

. Other p rovincial regulations have been or continue to be developed with coordination between the provincial and f ederal governments

.

Saskatch ewan ( MRO

- SaskPower) is seeking greater flexibility to meet GHG regulations by working with the provincial and
federal government s to develop an equivalency agreement. Development and finalization of federal regulations to limit CO 2 

### from natural

- gas

- based electricity generation could cause Saskatchewan to modify operational use of existing gas units in
orde r to remain compliant. Pending f ederal natural gas rules for electricity generation will impact the timing and nature of capital projects and potential r etirements, and of replacement/new energy decisions. These regulations are constantly
monitored and are included in resource adequacy assessments. Saskatchewan plans to include sufficient time to perform retrofits or replacement s to meet required regulatio ns. Saskatchewan has not yet experienced any reliability issues related

to GHG regulations and is expected to effectively mitigate any that arise

.

Ontario (NPCC

- Ontario) was the first Canadian province to phase out coal

- fired capacity in 2014, while adding replacement capacity including nuclear, natural

- gas , and variety of renewable resources. Similarly, MRO

- Manitoba Hydro , which is predominately hydro, has one smaller coal unit remaining that will be impacted by the Manitoba Climate Change and
Emissions Reduction Act and the Reduction of Carbon Dioxide Emissions from Coal

- F ired Generation of Electricity Regulations

. 43 

### This unit is already regulated such that it can only be operated to pr ovide for emergency operations.

Overview of EPA ’s Proposed Clean P ower Plan 44


### The EPA proposed draft rule released in June 2014 is aimed at reducing carbon dioxide emission from power plants to 30
percent below the 2005 levels by 2030

. 45 

### According to the EPA a nalysis of the proposed plan, between 108 and 134 GW of
fossil

- fired and nuclear retirements would occur by 2020 (depending on the state of regional implementations of Options 1 or 2)

. 46 

### The proposed plan would apply to all fossil

- fired generating units that meet four combined qualification criteria: ( 1)

41 Federal Register Notice

- August 1 5, 2014

. 42 EPA: Coal Combustion Residuals

- Proposed Rule

. 43 Reduction of C arbon Dioxide Emissions from Coal

- Fired Generation of Electricity Regulations

. 44 Additional information and analysis of the proposed CPP was performed by Energy Ventures Analysis, Inc. (EVA) and provided to NERC in September 2014 for use in this assessmen t.

45 EPA: Clean Power Plan Overview

. 46 Regional implementation of Option 2 assumes 108 GW of retirements (includes CC, Coal, CT, Nuclear, O/G, and IGCC) by 2020. State implementation of Option 1 assumes 134 GW of retirements (includes CC, Coal, CT, Nuclear, O/G, and IGCC) by 2020. For additional information, s ee Regulatory Impacts Analysis for the Proposed Carbon Pollution Guidelines for Existing Power Plants and Emission Standards for Modified and Reconstructed Power Plants (June 2014) and supporting IPM Model documentation and data.

### Key Reliability Findings

NERC | 2014 Long

- Term Reliability Assessment | November 201 4

11 units that commenced construction prior to January 8, 2014; 47 

### (2) units with design heat input of more than 250 MMBtu/hour, (3) units that supply over one

- third of their potential output onto the power grid

, and (4) units that supply more than 219,000 MWh/year on a three

- year rolling average to the power grid

. 48 

### Given these criteria, NERC estimates that nearly all U

. S

. fossil

fired power plants will be subject to the rule. The timeline of the proposed plan is provided below

. EPA Proposed Clean Power Plan Timeline

Within one year of finalizing the rule

— expected in June 2015

— state environmental agencies must submit implementation plan s to the EPA for approval

. Submitted state

- specific plans , due in June 2016

, must outline requirements and enforceable limitations for affected generating units to meet the rule’s average CO 2 

### emission rate goal for each state within two compliance periods: (1) an initial 10

- year average interim emission rate limit for the period 2 020

– 2029, and (2) a final annual emission rate limit starting in 2030.

The EPA provides states with an option to convert CO 2 

### emission rate limitation into an annual mass

- based limitation. It is likely that most states will elect to pursue this option due to the challenges state permitting agenc ies have in develop ing unit

specific emission rate limitations

. The simpler mass

- based

CO 2 

### emission cap program also negates the need for state legislative action to authorize agencies to limit plant output
and enact a n enforceable program for compliance with average emission rates

. The EPA would have one year to review and approve implementat ion plans for each state in June 2017 . Under this schedule, impacted generating units would have two
and a half years to develop respective compliance strategies
and potentially permit, finance, and build needed replacement capacity and transmission. In its current form, this implementation schedule would be a challenge for states to implement and for affected sources to comply
with

, especially given the expected legal challenges to both the EPA and state rules. In recognition of these challenges, the EPA would provide states with a one

- year compliance
extension to June 2017 if justification is provided and a two

year extension (June 2018) for states that elect to devel op

47 All sources starting construction after January 8, 2014, would be subject to new source performance standards and exempt from the EPA Clean Power Plan requirements.

48 Federal Register Proposed Rule

- June 18, 2014. 

### EPA’s Proposed Clean Power Plan: Options 1 & 2

The EPA is propo sing a best system of emission r eduction (BSER) goal approach

, referred to as Option 1

, and is taking comment

on a second ap proach referred to as Option 2.

Option 1 : involves higher deployment of emission reduction but allows a longer time frame t o comply (2030).

Option 2 : has a lower deployment of emission reductions over a shorter time frame (2025) by each state. The proposed guidelines would also allow states to collaborate and to demonstrate emission performance on a multi

- state basis, in recognition that electricity is transmitted across state lines.

The BSER is not intended to impact resource planning and does

not dictate retirements, additions, or operating practices for individual units. Instead, it would provide state emission rate limits that would shape the future resource mix through state and market processes in subsequent years as SIPs and multi

state plans are developed and implemented.

### Key Reliability Findings

NERC | 2014 Long

- Term Reliability Assessment | November 201 4
12 multi

- sta te (regional) program s ( e.g., Regional Greenhouse Gas Initiative (RGGI)). W hile the EPA extensions apply to state plan submissions, the January 1, 2020

, program start date for affected sources would not be extended . Therefore, the impacted fossil

- fired units may be left with a s little as six months to develop and implement compliance plans

. C onsidering the number and variety of outcomes for each of the proposed rule scenarios , the industry should initiate planning immediately upon approval o f the final rule.

B ased on EPA analysis of historical data about emissions and the power sector

, the proposed Clean Power Plan is to create a consistent national formula for reductions

, reflect ing the ir building block assumption s. The formula applies the f our b uilding blocks to each state’s specific information, yielding a carbon intensity rate for each state. 49



### Reliability Considerations for EPA ’s Proposed Clean Power Plan To comply with the proposed Clean Power Plan, states are expected to select the mass

- based limitation approach over the emission rate approach due to its greater flexibility and ease to enforce and implement. While the power industry has been successful in complying with prior mass

- based emission cap and trade p rograms (e.g.

, Acid Rain program, Clean Air Interstate Rule, and RGGI) without creating major electric grid reliability problems, the proposed Clean Power Plan impacts a larger amount of capacity (over 700 ,000 M W) in a relatively short time frame, potentia l ly posing greater grid reliability impacts compared to prior environmental compliance programs. Changes in generation resources, dispatch

, and delivery require comprehensive local and regional reliability assessments

. These assessments are needed to identify necessary transmission system enhancement s to provide for reliable delivery, system stability, voltage support, and other system reliability needs. Accordingly, t he following reliability challenges warrant further consideration by policy makers :

E PA Assumptions Require Accelerated C oal

- F ired Reduction b eyond the 2014LTRA Reference Case Although the Clean Power Plan may not become enforceable until 2020, its effect may overshadow and change large retrofit capital decisions needed to comply with earl ier EPA regulations

— primarily the Mercury and Air Toxics Standards (MATS).

EPA ’s base case projections, with existing regulations, indicate that total coal

- fired capacity will decline rapidly from approximately 310 GW in 201 2 to just 245 GW by 2016 and 243 GW by 2025

. T he EPA’s base case

— including existing

49 EPA Fact Sheet: Clean Power Plan

- National Framework for States

. 

### EPA’s Proposed Clean Power Plan: Four Building Blocks

The EPA projects that by 2030, compliance with the objectives will reduce U.S. power industry CO 2 emissions to 30 percent below 2005 levels. The EPA developed state

- specific CO 2 emission rates by applying the following four “best system of emission reduction” approaches and assumptions:

Make fossil fuel power plants more efficient by imple menting a 6 percent (on average) unit heat rate improvement for all affected coal

- fired units. The EPA suggests that some plants could further improve process efficiency by 4 percent through the adoption of best operational practices, and an additional 2 p ercent through capital upgrade investments.

Use low

- emitting power sources more by re

- dispatching existing NGCC units before the coal and older oil/gas steam units. EPA draft rate limitations include CO 2 reduction assumptions from the ongoing increases in the use of NGCC capacity (with up to a 70 percent capacity factor). This additional NGCC capacity (440 TWh/year) displaces coal (376 TWh/year) and oil/gas steam generation (64 TWh/year) by 2020, compared to 2012 levels.

Use more zero

- and low

- emitting power sources through building capacity by adding both non

- hydro renewable generation and five planned nuclear units. EPA calculations assume qualifying non

- hydro renewable generation can grow rapidly from 2 18 TWh/year in 2012 to 281 TWh/year by 2020, to reach 523 TWh/year by 2030.

Use electricity more efficiently by significantly expanding state

- driven Energy Efficiency programs to improve annual electricity savings by up to 1.5 percent of retail sales per y ear. The calculation assumes the states and industry can rapidly expand Energy Efficiency programs to increase savings from 22 TWh/year in 2012, to 108 TWh/year in 2020, and to 380 TWh/year by 2029. Ultimately, EPA energy efficiency assumptions suggest tha t electric power savings will outpace electricity demand growth, resulting
in declining electricity usage from 2020 through 2030.

### Key Reliability Findings

NERC | 2014 Long

- Term Reliability Assessment | November 201 4
13 regulations, but excluding potential impacts of the proposed Clean Power Plan

— assumes a significant reduction in coal

- fired capacity by 2016 : 27 .2 GW beyond what is projected in the 2014LTRA refer ence case

.

T he EPA released a report titled Regulatory Impacts Analysis for the Proposed Carbon Pollution Guidelines for Existing Power Plants and Emission Standards for Modified and Reconstructed Power Plants . According to this analysis, the state implementation of Option 1 would result in the largest reduction in coal to 193 GW by 2025 , while the regional implementation of Option 2 would result in the smallest reduction in coal to 214 GW by 2025

. 50 

### These two options are shown
in the table and chart below , alon g with the 2014LTRA reference case (total on

- peak contribution for all coal

- fired units in the United States)

. Coal Projections: 2014LTRA Reference Case & EPA Clean Power Plan Assumptions

NERC 2014LTRA Reference Case

- Total On

- Peak Capacity (GW) 2016 2018 2020 2025* Total Coal (Existing

- Certain and Tier 1 Capacity Additions) 271.8 266.4 264.9 261.3 EPA Analysis of the Proposed Clean Power Plan

- Total Coal Generating Capacity (GW) 2016 2018 2020 2025
Base Case 244.6 243.3 243.6 243.3 Option 1 (Regional Implementation) 217.5 207.8 198.0 197.2 Option 1 (State Implementation) 219.7 210.4 195.1 193.1 Option 2 (Regional Implementation) 225.0 217.3 214.3 214.3 Option 2 (State Implementation) 227.8 219.6 210.6 210.6 EPA Assumed Coal Reduction Beyond NERC 2014LTRA Reference Case (GW) 2016 2018 2020 2025
Base Case 27.2 23.1 21.3 18.0 Option 1 (Regional Implementation) 54.3 58.6 66.9 64.1 Option 1 (State Implementation) 52.1 56.0 69.8 68.2 Option 2 (Regional Implementation) 46.8 49.1 50.6 47.0 Option 2 (State Implementation) 44.0 46.8 54.3 50.7

* The 2014LTRA Reference Case includes data projections through 2024. 2024 projections were applied for 2025.


### Ongoing Coal Retirements Contribute to I ncreased D ependence on Natural Gas

T he EPA ’s proposed Clean Power Plan will accelerate the shift in the generation mix from coal to natural gas. T he EPA projects that the natural gas market portion of total U

. S

. power generation will grow from 29 percent ( energy ) in 2013 to 33

– 34
percent between 2020 and 2030. A recent study conducted by Energy Ventures Analysis (EVA) indicates that natural gas generation will increase by an additional 400

– 450 TWh /year due to impacts of the proposed Clean Power Plan. This will result

50 Regulatory Impacts Analysis for the Proposed Carbon Pollution Guidelines for Existing Power Plants and Emission Standards for Modified and Reconstructed Power Plants (June 2014) and supporting IPM Model documentation and data. 190 200 210 220 230 240 250 260 270 280 290 300 310

2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 Gigawatts

2014LTRA Reference Case* EPA Base Case Option 1 (State Implementation) Option 2 (Regional Implementation)

### Key Reliability Findings

NERC | 2014 Long

- Term Reliability Assessment | November 201 4

14 in an increase in the contribution of gas

- fired gener ation in the energy market to a share of 35 percent in 2020, 39 percent in
2030
, and 49 percent in 2040

. 51



### With this shift toward more natural g as consumption in the power sector, the power industry will become increasingly
vulnerable to risks from natural gas supply and transportation issues

. Impacts due to extreme conditions should be integrated in planning scenarios to ensure a suitable generat ing fleet is available to maintain BPS reliability. Adverse winter weather

, such as the 2014 polar vortex

, provided an example of the potential impacts to s upply and transportation

. 52 

### While several gas pipeline construction projects are underway to address deliverability issues in the Northeast, the shift toward additional natural gas consumption , as outlined in the proposed Clean Power Plan

, would create additional pipeline needs . S uff icient
lead time s ( more than three years) will be needed to plan and build new pipelines . This calls for a careful and deliberate review of the way in which natural gas is currently delivered and used by the electricity industry , so adjustments can be made to support enhanced reliability of both the gas and electric systems

.

Increases in V

ariable G eneration Are Creating Operational and Planning C hallenges The EPA Clean Power Program would provide states and developers additional incentives to rapidly expand their non

- hydro renewable capacity to displace existing coal generation. The incremental increases in renewable generation would consist primarily of ne w wind and solar capacity.

To support such variable generating capacity increases, the power industry would need to invest heavily to expand transmission capacity to access more remote areas with high

- quality wind resources . This further highlight s the nee d for a resource mix with sufficient essential reliability services 53 

### that support integration and reliable operation. Given the natural wind variability in remote locations, these incremental wind project resources would have relatively low capacity factor s that would require substantial new transmission.

Large penetration of VERs will also require maintaining a sufficient amount of reactive support, and ramping capability

. More frequent r amping needed to provide this capability could increase cycling on conventional generation . This could contribute

to increased maintenance hours and/ or higher forced outage rates , potentially increasing the reserve requirements. S torage technologies can also support ramping needs and allow VERs to be more easily dispatche d. While l arge

- scale energy storage is not yet commercially viable

, 54 

### the development of these technologies will enhance the industry’s ability to balance load
and resources as more VERs are added to the system.

Based on industry studies and prior NERC assessments
, 55 

### as the penetration of variable generation increases, maintaining
system voltage stability can become more challenging. Additional studies will be needed to further understand potential challenges that may indirectly result from the proposed C lean Power Plan. Additional info rmation on the integration of VERs is included in the next section of this report.

Higher Retail Electricity Prices Could Cause a Sharp Increase in Distributed Energy Resources (DERs)
The EPA project s that retail electr icity prices will increase by $1/MWh to $18 /MWh under the Clean Power Plan 56 

### resulting
from a combination of higher natural gas prices and the implementation of new carbon penalties on impacted fossil

- fired

51 Energy Ventures Analysis: FuelCast

– The Long

- Term Outlook 2014, October 2014. Some information and analysis of the proposed CPP was per formed by Energy Ventures Analysis, Inc. (EVA) and provided to NERC in September 2014 for use in this assessment.

52 NERC Polar Vo rtex Review (September 2014)

. 53 For additional information, see the NERC Essential Reliability Services Task Force

. 54 Pumped storage offers tremendo us ramping capabilities to the BPS; however, increases in this technology are not likely, due to land restrictions, permitting limitations, and environmental opposition. Less than 1 GW of new pumped storage capacity is projected over the nex t 10 years.

55 NERC

- CAISO Joint Report: Maintaining Bulk Power System Reliability While Integrating Variable Energy Resources

– CAISO Approach ; other industry reports include those developed by the Integration of Variable Generation Task Force (IVGTF) ; Integrating Variable Renewable Energ y in Electric Power Markets: Best Practices from International Experience (Appendix D)

. 56 Regulatory Impacts Analysis for the Proposed Carbon Pollution Guidelines for Existing Power Plants and Emission Standards for Modified and Reconstructed Power Plants (June 2014) and supporting IPM Model documentation and data.

### Key Reliability Findings

NERC | 2014 Long

- Term Reliability Assessment | November 201 4
15 generators. 57 

### As retail power prices rise, some existing customers may resort to the installation of renewable DERs , when economically advantageous

— especially in locations with prominent solar and wind resources. Depending on the price advantage, the market penetration of DER s could be substantial

, creating pot ential reliability impacts for grid operator s that
don’t have d irect control of these resources . In some cases, resources without the direct control of the System Operator fall outside the jurisdiction of state utility regulators

. A potential risk in additional DERs is the temporary displacement of utility

provided service, which could create additional planning challenges

, considering utilities must act as a secondary supplier of electricity . This is particularly the case during p eriods when variable DERs are experiencing high levels of intermittency. This
issue does not exist for utility

- scale wind energy , which offers ride

- through capabilities and other essential reliability services

. Generation variability over different periods (seconds, minutes, hours) and the uncertainty associated with forecasting errors are operational characteristics of wind and solar resources. Similarly, large onsets of non

- dispatchable resources have been
shown to create the potential for operational challenges i n California (particularly for solar), 58 

### as well as Germany (particularly for wind)

. Additional information on DERs is included in the Other Reliability Issues section of this report.

EPA’s Assumed Substantial Increases in Energy Efficiency P rog rams Exceed Recent Trends and Projections
The EPA assumes up to a 1.5 percent annual retail sales goal for its increm ental growth in energy efficiency savings in its rate calculation for best practices by state that will be triggered by the carbon regulation. The EPA assumes that the states and industry would rapidly expand energy efficiency savings programs from 22 TWh /year in 2012, to 1 0 8 TWh /year in 2020
, and
reach 380 TWh/year by 2029. With such aggressive en ergy efficiency expansion, the EPA assumes that energy efficiency will grow faster than electricity demand, with total electricity demand shrinking beyond 2020. The implications of this assumption

are complex. If the EPA

- assumed energy efficiency growth rates cannot be attained, additional carbon reduction measures would be required

, primarily through reduced fossil

- fired generation in applicable states. More low

- emitting and/or new generating capacity (not regulated under EPA Clean Power Plan) would need to be built. Construction of new replacement capacity would take time to plan, permit, finance

, and build. If these needs are not identified at an early enough stage, either grid reliability or state CO 2 

### emission goals could be compromised.

NERC collects on

- peak energy efficiency data with reductions that are already reflected in the load forecast s for each

Assessment Area. Based on the EPA’s projections for energy efficiency growth , a 1.5 percent annual increase is substantially
above what has been examined in current and prior LTRA reference cases. P rojected (on

- peak) annual energy efficiency growth as a portion of Total Internal Demand since 2011 has ranged from only 0. 12 to 0.1 5 percent , as shown in the table
below

.

2011

- 2014 LTRA Energy Efficiency Growth

LTRA 10

- Year Growth of

E nergy E fficiency (%) Portion of Total Internal Demand (%) Annual Growth in Relation to Total Internal Demand (%) Year 1 Year 10
2011 10.7 0.59 1.63 0.12
2012 12.2 0.72 1.88 0.13
2013 11.6 0.92 2.02 0.12
2014 13.4 0.87 2.25 0.15

57 According to EIA’s 201 4 Annual Energy Outlook , closing coal plants will drive up natural gas prices by 150 percent over 2012 levels by 2040. This cost increase will cause electricity prices to jump 7 percent by 2025 and 22 percent by 2040. This is because natural gas prices a re a key determinant of wholesale electricity prices, which in turn are a significant component of retail electricity prices. Accordingly, the cases with the highest delivered natural gas prices also show the highest retail electricity prices.

58 NERC

- CAISO Joint Report: Maintaining Bulk Power System Reliability While Integrating Variable Energy Resources

– CAISO Approach ; other industry reports inc lude those developed by the Integration of Variable Generation Task Force (IVGTF) ; Integrating Variable Renewable Energy in Electr ic Power Markets: Best Practices from International Experience (Appendix D)

.

### Key Reliability Findings

NERC | 2014 Long

- Term Reliability Assessment | November 201 4
16 Transmission Considerations
The EPA assumes that adequate transmission capacity will be available to deliver any resources located in or transferred to a given area

. 59 

### However, g iven the significant changes occurring in the resource mix, it is likely that additional new transmission,
or enhancements to existing transmission
, will be needed in some areas
, particularly those with existing and planned resource additions that include higher penetration of renewable generation

. Ad ditionally, as replacement generation is constructed,
new transmission will be needed to interconnect this capacity. The designing, engineering, and contracting requirements for
these new lines, as well as siting, permitting, and various federal, state, pr ovincial, and municipal approvals often require more than five years to complete. Thus, industry should consider the l ong lead times required for new transmission

.

59 Regulatory Impacts Analysis for the Proposed Carbon Pollution Guidelines for Existing Power Plants and Emission Standards for Modified and Reconstructed Power Plants (June 2014) and supporting IPM Model documentation and data.

### Key Reliability Findings

NERC | 2014 Long

- Term Reliability Assessment | November 201 4

17 Key Reliability Finding #2 Environmental Regulations Create Uncertainty and Require Assessment

Recommendations and Next Steps

NERC Board of Trustees Endorsed Assessment Plan : The NERC Board of Trustees endorsed a plan to review and assess the reliability impacts of the EPA proposal at its August 2014 Board meeting. This plan include d a pr eliminary review of the assumptions and potential major reliability impacts resulting from the implementation of the EPA’s notice of proposed rulemaking under Section 111(d). With the EPA scheduled to finalize its rule by June 2015, NERC will develop a rel iability assessment that will focus on a more detailed analysis of the respective reliability impacts

.
Phased Approach : An initial review of the EPA’s proposed Clean Power Plan is included within this assessment. NERC will release an initial high

- level reliability review based on the assumptions used in the proposed rule in November 2014. Subsequently, NERC will conduct a special reliability assessment to be released in phases . The first phase, expected to be released in April 2015

, will be a detailed assessment to evaluate generation and transmission adequacy and leverage i ndustry studies, prior to rule finalization . The second phase , with a target release date in December 2015, will incorporate the final rule prior to state s submi t ting implementation plans to the EPA in June 2016

. Additionally, a Phase III approach is tentatively planned for December 2016, which will examine finalized state implementation plans. A proposed timeline of these activities is provided below. Additionall y, NERC will address reliability constraints identified and incorporated into transmission expansion plans for future long

- term and seasonal assessments.

The NERC S teering G roup s and Ongoing Stakeholder Involvement : Industry members should participate in steering group s to provide ongoing input on the EPA’s proposed Clean Power Plan. NERC will also utilize its stakeholder process through the MRC and

PC to solicit input and collaborate to identify and address potential reliability impact s due to the proposed rul e.

### Key Reliability Findings

NERC | 2014 Long

- Term Reliability Assessment | November 201 4
18 3. A Changing Resource Mix Requires New Approaches for Assess ing Reliability
North America’s resource mix is undergoing a significant transformation at an accelerated pace with ongoing retirements of
fossil

- fired and nuclear capac ity and growth in natural gas, wind, and solar resources

. This shift is caused by several drivers

, primarily existing and proposed federal, state, and provincial environmental regulations

. Other drivers include l ower natural gas prices due to abundant supply

, along with policies incentivizing the movement from conventional energy resources
toward ongoing integration of both distributed and utility

- scale renewable resources

. The convergence of these resource mix changes is directly impacting the be havior of the North American BPS

. These developments will have important implications

on industry planning and operations

, as well as how NERC assesses reliability.

NERC

- W ide Tier 1 and 2 Additions (2015

– 2024) 60



### Increased Dependence on Natural Gas Due to Ongoing Decline in Coal

- Fired Capacity

N atural

- gas

- fired capacity continues to be the replace ment capacity of choice for resource planners as other fossil

- fired units are retired. This trend is expected to continue with the addition of 44.6 GW of g as

- fired capacity, accounting for nearly half
of all Tier 1 nameplate capacity ad ditions during the next decade

. By 2024
, natural gas will contribute 4 2 percent of the on

peak resource mix
, compared to 40 percent in 2015

.

A variety of drivers make s natural

- gas

- fired capacity an attractive resource

. Most impactful is the price of natural gas , which is projected to remain low ( relative to other fuels ) , with abundant supplies from shale formations throughout North
America. 61 

### Additionally , t he em ergence of more efficient NGCC generating technology requires lower engineering, procurement, and construction costs

. The shorter buil d times for NGCC plants can help resource planners avoid procurement challenges that exist with other options. Perhaps the most impactful benefit is the environmental advantage of lower carbon emissions when compared to coal

- fired power plants without carbon capture and sequestration. Finally, natural

- gas

- fired
units can provide System Operator s with needed flexibility to address additional variability as VERs account for a larger portion of the resource mix in certain areas.

60 Tier 1 includes capacity additions that are either under construction or have received approved planning requirements. Tier 2 includes capacity additions that have requested but not received approval for planning requirements.

61 EIA Annual Energy Outlook 2014

.

0 10 20 30 40 50 60 70 80 90 100 110 120 130 140 Geothermal Pumped Storage Biomass Coal Solar Hydro Nuclear Wind Natural Gas

Gigawatts

Tier 1 Tier 2

### Key Reliability Findings

NERC | 2014 Long

- Term Reliability Assessment | November 201 4
19 2008

– 2014 LTRA 10

- Year Net Change Indicates Ongoing Declines in Coal and Growth in Gas

As planners rely more on natural gas for both baseload and on

- peak capacity , i t is important to also examine potential risks associated with increased dependence on a single fuel type. Currently, natural

- gas

- fired capacity account s for large portions
of both the total and on

- peak generation mix in several Assessment Areas for both e xisting capacity and planned additions.

Assessment Areas with Natural

- Gas

- Fired Capacity Accounting for Over One

- Third of Existing Nameplate Capacity Nameplate Capacity (GW) On

- Peak Capacity (GW) 10

- Year Nameplate Capacity Additions (GW)
Assessment Area Gas

- Fired Portion of Total Gas

- Fired Portion of Total Tier 1 Tier 2 Tier 3
FRCC 40.2 64% 33.9 63% 10.1 0.0 0.0 MISO 69.0 39% 58.7 41% 2.8 0.0 10.0 NPCC

- New England 18.6 54% 13.3 43% 1.1 3.3 0.0 NPCC

- New York 21.0 55% 14.2 40% 0.0 3.5 0.0
PJM 80.0 43% 56.5 32% 10.0 47.5 0.0 SERC

- SE 31.2 47% 28.4 46% 0.0 0.0 2.6 SPP 32.3 40% 30.2 47% 1.1 0.7 5.7
TRE

- ERCOT 48.4 54% 45.2 63% 4.9 21.5 0.0 WECC

- CA/MX 47.7 61% 43.9 70% 5.5 6.2 0.9 WECC

- RMRG 7.2 36% 6.2 41% 1.2 0.0 0.0 WECC

- SRSG 19.5 47% 16.3 50% 0.6 1.0 3.0


### Higher Reliance on Natural Gas Further Exposes BPS to Impacts from Fuel Transportation Disruptions The electricity sector’s growing reliance on natural gas raises concerns regarding the electricity infrastructure’s ability t o maintain BPS reliability when facing constraints on the natural gas pipeline system

. The extent of these concerns from Independen t System Operators (ISOs), Regional Transmission Organizations (RTOs), electricity market participants, industrial consumers, national and regional regulatory bodies, and other government officials var ies throughout North America ; however, concerns are mos t acute in areas where power generators rely on non

- F irm pipeline transportation as natural gas

use d for power generation continues to rapidly grow

.

N atural gas supply and transportation infrastructure adequacy concerns, particularly in certain parts of No rth America, are causing NERC, industry

, and policymakers to r efocus attention on the interdependency between n atural gas and electricity
industries

. System Operator s and resource planners continue to make considerable progress to consider fuel supply and transportation adequacy as a formal part of reliability assessment

. Under average annual operating conditions, most pipelines have some level of capacity that is not used by F irm customers
and is therefore available for non

- Firm (interruptible) loads, including natural gas generators with non

- Firm contracts. If the requirements for non

- Firm deliveries are communicated to the pipeline within the nomination cycle timeline, the pipeline
can use facilities to enable delivery of natur al gas requested up to its allowed physical capabilities. This is the normal procedure for interruptible transportation service or capacity release from Firm shippers. In some power markets or areas 225 250 275 300 325 350 375 400 425 450 475

2008 2009 2010 2011 2012 2013 2014 Gigawatts

Gas (Year 1) Gas (Year 10) Coal (Year 1) Coal (Year 10)

### Key Reliability Findings

NERC | 2014 Long

- Term Reliability Assessment | November 201 4
20 where there is excess natural gas pipeline capacity avail able, these low

- capacity

- factor units can rely upon interruptible service with a reasonable degree of certainty that service will be available.

However, as growth in natural gas demand increases, pipeline transportation constraints will have a greater impa ct on
natural

- gas

- fired generation , making units with non

- Firm service vulnerable to more frequent interruption . If a generator served by interruptible service has no secondary fuel source , then that generating capacity could be unavailable during peak

per iods. While coordination efforts between the gas and electric industries continue to improve, the potential still exists for a mismatch between the availability of natural gas delivery and natural gas demand for electricity generation

. This can be particularly challenging in areas where a significant amount of the capacity

— or more importantly

, reserve capacity

— is susceptible to natural gas transportation interruptions , potentially resulting in more frequent generator outages.

What Does the 2014 Polar Vortex Tell Us a bout the Future? As more generating capacity is natural gas fired, additional
assessment of F irm pipeline transportation is needed to ensure sufficient gas is availab le during both normal operation and periods of hi gh stress, as exemplified by the

p olar v ortex event. 62



### Overdependence on a single fuel type increases the risk of

common

- mode disruptions as experienced during recent
extreme weather events . Disruptions in natural gas transportation to power generators have prompted the gas and electric industr ies to further examine reliability implications associated with increasing natural

- gas

- fired generation.

As highlighted in this assessment, most new capacity
addi tions are natural gas fired. Over the past two years, both industries have made significant progress to better link the operations of these vastly different industries.

The gas and electric industries operate under different regulatory structures and rule s that affect how infrastructure is planned, built, maintained, and ultimately operated. As the dependence on natural

- gas

- fired generation increases in North America, the natural gas and electricity industries
continue coordination efforts. T he relationshi p between
natural

- gas

- fired generation availability and low temperatures further challenges the industry’s ability to manage extreme weather conditions, particularly when conditions affect a wide area and there is less support
available from within an inte rconnection. T hese extreme
weather events should serve as early indicator s of more frequent impacts i f natural gas supply and transportation is outstripped by the demand from new natural

- gas

- fired units continue to rely on interruptible gas.

62 For additional information, see NERC’s Polar Vortex Review (September 2014). 

### 2014 Po lar Vortex NERC Scenario: Considerations for Long

- Term Planning

The 2014 p olar v ortex, impacting a majority of the m idwest ern and northeastern United States and southern Canada, tested the resilience of the North American BPS. This event served as

an examp le of how extended periods of cold temperatures have direct impacts on fuel availability, especially for natural

- gas

fired capacity. Higher

- than

- expected forced outage s were observed during the p olar v ortex
, particularly for natural

- gas

fired generators

, as well as higher

- than

- forecast peak demand. The following impacts were caused by fuel delivery challenges and extended periods of low temperatures:

Fuel Delivery

 Natural gas interruptions: supply injection, compressor outages, and one pipeline explosion

 O il delivery problems

 Inability to procure gas

 Fuel oil gelling

Low Temperatures

 L ow temperature limits for wind turbines

 Icing on h ydro units

 Failed auxiliary equipment

 Stress of extended run times

 Frozen instrumentation (drum level sensors, control valves, and flow and pressure sensors
To examine the potential impacts of a similar event in the future, N ERC ran scenarios on select Assessment Areas ( SERC

- E, PJM, MISO
, and TRE

- ERCOT) that experienced significant loss of generation during the 2014 p olar v ortex event. Actual forced outage data were applied as derates to existing and projected (Tier 1) capacity projections using the 2014LTRA reference case. Load was assumed to be consistent with the extreme loads that were observed.

Based on this NERC scena rio, projected reserve margins combined with the projected increased dependence on natural
gas will increase the adverse impacts to BPS reliability if similar extreme weather events occur in the future.

The complete scenario is included as Appendix III.

### Key Reliability Findings

NERC | 2014 Long

- Term Reliability Assessment | November 201 4
21 Summer Conside rations for Natural Gas While gas

- electric supply and transportation issues are especially important during the winter season, the summer season
presents a separate set of potential reliability impacts that require s ongoing attention . Specifically, the ele ctricity industry
must be aware of pipeline maintenance schedules and promote ongoing coordination to ensure individual generators do not
face supply shortages

— principally those that can be resolved through coordination

— during peak conditions.

Recent and Planned Industry Initiatives to Address Increasing Dependence on Natural Gas for Electric Power
The gas and electric industries have recently made substantial progress to enhance coordination and develop new strategies

to address system reliability due to fuel supply and transportation concerns

. These efforts helped to reduce the severity of impacts experienced during the 2014 polar vortex event. These developments are presented below for Assessment Areas
with gas

- fired capacity that accounts for over one

- t hird of their existing generation mix.

FRCC FRCC p erforms an annual review of natural gas infrastructure and maintains a Generating Capacity Shortage Plan that outlines communications, environmental, and political procedures in the event of a fuel shortage

.

MISO
MISO d eveloped procedures to facilitate communication between power plant operators and natural gas transportation service providers under which MISO is notified of all operational flow orders and other information to raise awareness of potential issues that may impact generation capacity.

The MISO Electric and Natural Gas Coordination Task Force (ENGCTF) 63 

### has also developed comprehensive examinations of three key gas

- electric coordination challenges: (1) addressing gas

- electric scheduling and market timeline misalignment

, (2) capturing fuel risk in the resource adequacy construct

, and (3) strengthening gas

- electric communications. Recent ENGCTF developments include:

 Natural gas infrastructure displays in control rooms

 An online platform to cons olidate natural gas pipeline operational flow orders and critical notices

 A database linking natural gas generators to their fuel supply sources, as well as to operational flow orders and
critical notices

 A preliminary LOL E study , focusing on the concern o f increased probability of load loss resulting from gas

- fired
generators ’ inability to access fuel during peak energy operating conditions

Additional topics are currently being explored by the ENGCTF:

 Polar v ortex experiences (natural gas availability and enhance d RTO/pipeline communications)

 P otential competition between generator demand and upcoming gas storage injection

 P rocess and timeline considerations for natural gas infrastructure build

- out

NPCC

- New England

A fter the “ c old

- sna p ” of January 20 0 4 , ISO New England and the Northeast Gas Association (NGA) established the Electric

Gas Operations Committee (EGOC), 64 

### which meets quarterly to discuss issues common to both gas and electric sectors. ISO

NE also participates in the following activities : (1) coordinate d studies with NYISO, PJM, Ontario, TVA, and MISO; (2) multi

regional static/transient hydraulic natural gas analyses ; (3) NERC/NPCC natural gas assessment s ; and (4) the Eastern Interconnection Planning Collaborative (EIPC) Gas

- Electric System Interface St udy. 65 

### ISO

- NE has also performed internal studies to evaluate regional pipeline capacity and local distribution company ( LDC ) operations, dual

- fuel capability, environmental issues of generators, liquid fuel availability

, and regional storage capability. Recent operational changes
include : (1) moving forward the schedule d timelines of participant bid submittals; (2) processing and publishing the day

-

63 MISO Electric and Natural Gas Coordination Task Force

. 64 ISO

- New England Electric/Gas Operations Committee

. 65 EIPC Gas

- Electric Study

.

### Key Reliability Findings

NERC | 2014 Long

- Term Reliability Assessment | November 201 4
22 ahead market results; (3) i mplementing a participa n t re

- offer period ; and (4) complet ing the resource adequacy assessm ent in order to provide startup notification to long

- lead time resources that are needed to operate the next day to ensure system
or sub

- area reliability or transmission security.

NPCC

- New York

NPCC

- New York d eveloped a cold weather procedure to monitor ga s nominations, oil inventories, and expected oil replenishment schedules for all dual

- fuel, gas

- fired, and oil

- fired generators prior to each cold day. NPCC

- New York also conducts an annual survey each fall that requests information on gas transportation a rrangements, oil inventory, and oil replenishment capability from the same generators and uses this fuel information to monitor a generator ’ s capability to meet the day

- ahead electricity schedules. NYISO is also working to increase awareness of the gas sys tem in the control room in order to provide greater visibility into gas pipeline system condition s and generator fuel capability. This includes the ability to monitor the actual fuel capability of units. This will provide additional real

- time information t o help operations maintain electric system reliability

— particularly during periods of the more restrictive hourly operational flow orders. Finally, NYISO is coordinating efforts with the interstate, intrastate, and LDC pipelines to incorporate gas pipeline outage scheduling with electric system outage scheduling.

PJM
PJM recently formed the Gas Electric Senior Task Force (GESTF) 66 

### to help identify and examine gas

- electric issues and develop solutions. PJM continues to participate in both the EIPC Gas Electric System Interface study and the North American Energy
Standards Board ( NAESB ) process to explore consensus development with the gas industry on market coordination issues.

PJM also coordinates with other ISO/RTOs to improve and st andardize communication practices with the gas pipelines.
Increased coordination betw een gas pipelines and generator owners is a priority to ensure suffic ient availability of resources, particularly during the 2014 p olar v ortex

. PJM is addressing differenc es between the timing of generators’ required natural gas purchase commitments and PJM’s day

- ahead energy market commitment.

SERC
In SE RC, many plants are covered by tolling agreement s that include F irm pipeline transportation. The entity identified in the tolling agreement performs planning and operational procedures and coordination activities. Several entities individually perform these activities . Entities also coordinate activities surrounding facility startups and shutdowns , pipeline warnings,
and pipeline outages or restrictions. Larger entities in SERC have a centralized unit commitment planning function that includes gas trading and power trading functions, as well as the generation dispatch function. Entities are also co mmunicating with the pipeline operators to determine any potential issues in the develop ment of contingency plans as required, including the acquisition of additional F irm transport ation and storage capacity to meet projected demands.

SERC entities contin ue to work closely with FERC and NAESB from both a policy and business standards perspective on gas

electric coordination. Larger entities address gas supply and transportation issues during extreme weather events through
conference calls. These c all s are held to coordinate real

- time contingency plans with key stakeholders including generat or operators , transmission operators
, and fuel providers

. Firm natural gas pipeline agreements, Firm delivered fuel agreements, investments in gas storage, enabling agreements with multiple gas suppliers, and back

- up fuel sources are all in place to ensure reliable fuel delivery in extreme weather events. Many entities within SERC use natural gas only fo r boiler startup, typically only a few times per year or for any forced outages that may occur.

SPP

I n 2013
, SPP formed the Gas Electric Coordination Task F orce (GECTF) 67 

### to provide a greater operational awareness of the gas fuel supply. T he GECTF recent ly created the Weather Operational Plan to improve communication between major gas suppliers and SPP grid operations (this plan was executed four times during the 2013

– 2014 winter season).

66 PJM Gas Electric Senior Task Force

. 67 SPP Gas Electri c Coordination Task Force

.

### Key Reliability Findings

NERC | 2014 Long

- Term Reliability Assessment | November 201 4
23 TRE

- ERCOT In ERCOT, the Black Start Working Group (BSWG) 68 

### coordinates efforts with the natural gas industry (the supply of gas to blackstart units in ERCOT is particularly important in the event of a total system restoration, which has been made evident
after an examination of ERCOT’s restoration system plans). The BSWG (including major gas pipeline operators and the electric transmission operators within ERCOT) is working to identify priority loads that need to be restored for gas facilities to continue to transport gas in the event of a total system restoration . Currently, the transmission operators are working to include these priority loads in their respective restoration plans. Initiatives continue with major pipelines to improve communications between the gas and electric industries and develop confidentiali ty agreements with involved entities. This will allow for the exchange of operational information to facilitate improved real

- time decision making by informing parties of unit commitment and overall operations in times of stress on either system.

WECC WECC subregions are involved in the FERC NOPR (RM14

- 2

- 000) process to better coordinate the scheduling of natural gas and electricity markets in light of increased reliance on natural gas for electric generation. During extreme weather events, daily calls occur between the generating resources and gas supply and transportation companies. These calls are done so that the generating units know the status of both gas supply and deliverability with the end goal of maintaining overall reliable operations of the BPS

.

68 ERCOT Black Start Working Group

.

### Key Reliability Findings

NERC | 2014 Long

- Term Reliability Assessment | November 201 4
24 Ongoing Growth in Wind and Solar Resources Require s More System Flexibility

NERC

- wide, 32 continental states and the District of Columbia have implemented renewable portfolio standards ( RPS s )

, 69 

### with similar policies in several Canadian provinc es

. These policies mandate or otherwise establish goals for electricity producers to supply a specified portion of electricity from eligible renewable energy sources (typically w ind, solar, biomass, geothermal, and some hydroelectric). 70 

### Additionally, greenhou se gas emission regulations (notably CO 2 

### ) and continually declining costs of renewable resources further incentivize construction of renewable resource s throughout North America. The continued growth of renewable generation offers benefits such as newer generation resources, fuel diversification, and greenhouse gas reductions. However, to maintain BPS reliability, challenges presented by additional variab le resources as a
result of renewable energy policies need to be properly addressed.

NERC

- Wide 10

- Year Additions of Wind and Solar

W in d and solar will account for a large portion of Tier 1 nameplate capacity additions during the next decade , with 29 GW (1.7 GW on

- peak) and 4.4 GW (3.2 GW on

- peak) , respectively. When examining Tier 1 and 2 capacity additions, up to 74.2
GW of wind additio ns and 14.3 GW of solar additions are projected by 2024. While VERs account for a growing portion of the total energy contribution, resource planners are relying on smaller amounts of wind and solar when examining resource availability during the hour s of peak demand.

Nameplate additions of over 11 GW were projected in the

2013LTRA , primarily in the s outheastern subregions of the
WECC Interconnection. In the 2014LTRA reference case, 3.3
GW of Tier 1 and 8.5 GW of Tier 2 additions are planned by

2024.

High levels of wind and solar resources can create challenge s for grid operators due to the inherent swings, or ramps, in power output. In certain Assessment A reas
— particularly WECC

- CA/MX and WECC

- RMRG

— the on

- peak portion of VERs is projected to supply up to 9.7 and 6.7 percent of the 2015 Total Internal Demand

. Sy stem planners in areas with h igh er concentrations of VERs must accommodate added variability by increasing the amount of available regulating reserves and carrying additional operating reserves. B ecause weather plays a key factor in determining wind and solar output, enhancing regional forecasting systems can provide more accurate generation projections. Other methods include curtailment and limitation procedures used when generation exceeds the

69 Also referred to as renewable electricity standard or a renewable energy standard.

70 Database of State Incentives for Renewables & Efficiency

.

0 10 20 30 40 50 60 70 80 Solar Tier 1 & Tier 2 Wind Tier 1 & Tier 2 Solar Tier 1 Wind Tier 1

Gigawatts On-Peak Wind Derated Wind On-Peak Solar Derated Solar



### Transmission Considerations with Additional VERs

Reliably integrating t he projected 30.8 GW of addition al wind and solar resources will require additional transmission. VERs are often built in parts of North America that are distant from the point of interconnection to the transmission system. In many cases, the location of these variable resources only meets the minimum vo ltage support requirements. According to the
2014LTRA r eference c ase, 16 percent of new transmission projects (under construction, planned, or conceptual) identify variable resource integration as a primary driver.



### New Transmission Project Drivers

Other
Drivers 84% Variable Integration 16%

### Key Reliability Findings

NERC | 2014 Long

- Term Reliability Assessment | November 201 4
25 av ailable regulating resources. In this respect, operating criteria, forecasting, commitment, scheduling, dispatch and balancing practices, procedures, and tools must be enhanced to assist operators in maintaining BPS reliability.

Several Assessment Areas with High Existing VER Penetration (Nameplate) as a Portion of the 2015 Generation Mix

Assessment Area Existing Nameplate ( M W) Existing On

- Peak

Contribution ( M W) Existing On

- Peak

Contribution (%) Existing

Nameplate (M W) Existing On

- Peak

Contribution (M W) Existing On

- Peak

Contribution (%)
FRCC 0 0 0.0% 56 7 0.0% MISO 16,383 1,060 6.5% 0 0 0.0% MRO

- Manitoba Hydro 259 0 0.0% 0 0 0.0% MRO

- MAPP 1,1 14 260 23.6% 0 0 0.0% MRO

- SaskPower 198 40 19.8% 0 0 0.0%
NPCC

- Maritimes 1,10 1 271 24.7% 0 0 0.0%
NPCC

- New England 788 101 12.7% 0 99 0.0%
NPCC

- New York 1,70 8 249 14.6% 212 11 5.2%
NPCC

- Ontario 1,695 270 15.9% 32 0 0.0%
NPCC

- Québec 2,400 0 0.0% 0 689 0.0%
PJM 5,8 24 908 15.7% 238 92 38.4% SERC

- E 0 0 0.0% 29 28 98.9% SERC

- N 1 79 28 15.3% 0 0 0.0% SERC

- SE 0 0 0.0% 4 4 100.0% SPP 6986 242 3.5% 50 5 10.0%
TRE

- ERCOT 11, 093 996 8.7% 123 123 100.0%
WECC

- CAMX 6,4 22 2,345 36.6% 4,297 1,565 36.4%
WECC

- NWPP 11 ,167 3,258 29.1% 378 0 0.0%
WECC

- RMRG 2,4 2 0 718 29.9% 127 54 42.8% WECC

- SRSG 7 8 9 155 19.3% 1,004 361 35.9%
NERC TOTAL 70,540 10,901 15.5% 6,551 3,037 46.4%

### Key Reliability Findings

NERC | 2014 Long

- Term Reliability Assessment | November 201 4
26 Planning Considerations for VERs in Long

- Term Planning Most Assessment Areas account for a small portion the total nameplate capacity of wind and solar resources when planning. MISO and ERCOT, for example, use a probabilistic basis for determining this factor. The Effective Load Carrying Capability (ELCC) establishes a percentage of total nameplate wind or solar capacity that is relied on for planning purposes. ERCOT currently employs an ELCC of 8. 7 percent for all wind resources, meaning that 8.7 percent of the approximately 11 GW of wind is applied toward the Existing

- Certain capacity category and included in the Anticipated Resources and Reserve Margin.

According to the 2014LTRA reference case, N ERC

- wide Tier 1 nameplate wind and solar additions amount to 29 GW and 4 GW, respectively, during the next decade. However, the on

- peak contribution will increase by only 1.4 GW for wind and 0.4 GW for solar, based on current methods and assumptions values for planning variable capacity additions.

NERC

- W ide 10

- Year Wind (Left) and Solar (Right) Tier 1 Capacity Additions

0 3 6 9 12 15 18 21 24 27 30

2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 Gigawatts

On-Peak Derate 0.0 0.5 1.0 1.5 2.0 2.5 3.0 3.5 4.0 4.5

2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 Gigawatts

On-Peak Derate

### Key Reliability Findings

NERC | 2014 Long

- Term Reliability Assessment | November 201 4
27 Key Reliability Finding #3 A Changing Resource Mix Requires New Approaches for Assessing Reliability

Observations

Effects of environmental regulations, a less diverse resource mix, and an increase in VERs will result in greater dependence on natural gas for electric power generation in the future. With the demand for natural gas for power generation increasing, greate r engagement among both sectors is needed to ensure sufficient resource allocation for reliable operation of the electric syste m.



### Recommendations

Expanded Gas

- Electric Planning and Coordination : Thorough harmonized efforts between electric and gas sectors are needed in
order to m eet future infrastructure needs to supply and transport fuel. System planners in certain areas (with high levels of natural

gas

- fired resources) should examine system reliability needs to determine if more Firm fuel transportation o r units with dual

- fuel capability are needed. Additionally, fuel availability and deliverability should be specifically considered and integrated in to resource adequacy and other planning assessments.

Operational Coordination Strategies between Gas and Ele ctric Industries : System Operators should develop or enhance
coordination strategies to address potential fuel interruptions , especially prior to anticipated extreme weather events

. Generator owners should consider securing on

- site secondary fuel in the ev ent that non

- Firm gas service is curtailed.

Variable Energy Resource Considerations : Because each system within the North American BPS is unique, detailed studies and investigations must be completed to understand how changes to the resource mix in certain areas , particularly those with a large onset of VERs, will impact their system s , particularly essential reliability services. The Essential Reliability Services Task Force (ERSTF) recently developed a concept paper that examines three building blocks that system planners should consider for maintaining reliability in the ongoing shift to systems with more variable resources:

 Balance of Load and Resources: T he BPS should be planned and operated with the continued ability to raise and lower

genera tion or load automatically or manually under normal and post

- contingency conditions (i.e., ramping capabilities).

 Voltage Support: This is required to maintain system level voltages on the BPS within established limits, under pre

- and
post

- contingency situ ations, thus preventing voltage collapse or system instability.

 Frequency Support: This is required to maintain stable frequency on the synchronized BPS by employing automatic response functions of a resource in response to deviations from normal operating frequency.

Essential Reliability Services : NERC urges the continued efforts of the ERSTF to develop additional metrics for measuring the reliability impacts of a resource mix that is increasingly dependent on variable resources.

The N eed for Flexibility : Based on previ ous NERC assessments and analyse s, as the level of VERs increase s , more flexibility will be needed from the system

. In the past decade, manufacturers have made significant advancements in control methods that can make

VER power output more re sponsive to grid

- level controls, including frequency response and down regulation. I ndustry should
continue to examine how wind and solar plants can contribute to frequency response and work toward interconnection requirements that ensure System Operator s will continue to maintain essential reliability service s

.

The Need for N ew R eliability Assessment A pproaches: As part of its assessment of long

- term reliability, NERC should consider using new approaches to evaluate the changing behavior of the BPS. These additional approaches should consider ERS, probabilistic, and transmission adequacy assessments

— in conjunction with the existing Reserve Margin metric

— to address and evaluate potential reliability issues in the future. Additional detail on these efforts c an be found in the next section.

### Key Reliability Findings

NERC | 2014 Long

- Term Reliability Assessment | November 201 4
28 New Approaches for Assessing Reliability

T he North America n generation mix is primarily comprised of conventional generation (hydroelectric, coal, petroleum, nuclear, and natural gas). With this generation mix, the use of a Reserve M argin continues to b e an effective approach for assessing resource adequacy. Reserve Margins measure the amount of generation capacity avai lable to meet expected demand during the planning horizon and have been a surrogate metric for examining and planning for resource adequa cy and system reliability. B ased on the premise of this metric, a system should be able to supply resources to meet the projected
normal weather electricity demand (given some expl icit amount of reserve capacity ) , with a high degree of certainty that the system can manage generator outages and modest
deviations from the annual demand forecast. The Reference Margin Level guideline do es not evaluate the effects of unit size or performance, the size of the system

, or the s trength
of its interconnections in each A ssessment A rea . In North America, given the static measure of generation reliability, Reference Margin Levels are reviewed and, if necessary, revised as significant system changes occur.

The one

- event

- in

- ten

- year (0 .1 events per year) LOLE is produced from this type of analysis. This industry guideline requires an electric system to maintain sufficient generation
and Demand Response resources such that system peak load is likely to exceed available supply once in a t en

- year period. Utilities, System Operator s, and regulators across
North Ame rica rely on variations of the one

- event

- in

- ten

year guideline for ensuring and maintaining resource adequacy.

Although Reserve M argins offer insight into the relative ability of a system to serve load based on existing and planned

resources, this metric does not fully capture important reliability attributes essential for ensur ing BPS reliability. T he Reference Margin Level assumes that various types of operating reserv es are available (e.g., regulating reserves, spinning

reserves, non

- spinning reserves, and load

- following reserves ) to balance load and supply in real time and enable System Operator s to quick ly and reliably respond to a system contingency

. 71 

### In contrast to an operating reserve requirement , which applies during real

- time system operations ( irrespective of load le vels or generator availability ), the Reserve M argin metric is developed to ensure that sufficient resources are available to address reliability challenges due to differences between : (1)
short

- term or medium

- term peak load forecasts ( reflecting normal weather) and typical generation outages; and (2) actual peak loads (which can exceed reflected weather

- related discrepancies in load) an d spikes in generation outages.

In addition, the Reserve M argin metric assumes that generator fuel availability is not correlated with load levels or weather

. However, recent extreme weather events have caused an increased number of forced ou tages due to fuel un availa bility, particularly natural gas . Assumptions of the Reserve Margin metric may be understating these risks. For VERs , a proxy for fuel availability is used to adjust installed or seasonally rated capacity values

— with i nstalled or nameplate capacity derat ed in

R eserve M argin calculations . This approach fails to provide an evaluation of the reliability of VERs during off

- peak hours or during extreme weather events.

71 Defined as a sudden failure of an electrical facility, such as a transmission line, breaker, transformer, or generation unit.



### Current Reserve Margin Method

The Reserve Margin and LOLE statistics are related. As shown the example below, as the reserve margin decreases, the likelihood of a supply deficit

— or "reliability event"

— increases.

### Key Reliability Findings

NERC | 2014 Long

- Term Reliability Assessment | November 201 4
29 Essential Reliability Services In June 2014, N ERC commissioned ERSTF to reconcile a collection of analytical approaches for understanding potential reliability impacts as a result of increasing variable resources and how these impacts can affect system configuration, composition, operation and the need for increased ERS s

. The ERSTF identified three reliability attributes or building blocks to help define ERS s

. T hese services represent the operating characteristics and reliability functions that are vital to ensuring BPS reliability. The ERS building blocks have three components : ( 1) load and resource balance, ( 2) voltage support, and ( 3) frequency support. In order to maintain reliability, the BPS must maintain sufficient levels of ERS s

. While ERS s are technology neutral and must be provided regardless of the resource mix composition, g aps in ERS s can lead to adverse impacts on reliability. ERS s can be addressed with appropriate policies and standards.

While some VERs are capable of providing components of ERS s, the variability of these weather

- dependent resources make s them difficult for System Operator s to depend on

. O ne of the reliability concerns presented by higher percentages of variable resources is the displacement of resources that have the ability to arrest and stabilize system frequency following a grid
distur bance or the sudden loss of a large generator . Photovoltaic solar resources offer no inertia or frequency response. W ind resources can offer inertia and frequency response, depending on the design attributes of a given wind plant. However, by causing conve ntional generators to have their output dispatched down, wind and solar generation can increase generator
headroom and

, therefore

, the amount of total frequency response being provided. Other potential approaches include the
use of probabilistic methods to more accurately quantify the potential for challenges balancing resources with load.

Probabilistic Assessments Reliability outcomes depend on a host of complex and interdependent factors

, such as the projected resource mix, generat or availa bility, and weather uncertainty. Evaluating these factors require s a probabilistic approach to provide a more robust understanding of resource adequacy. This requires statistical ly characterizing the following: (1) uncertainty in load forecast s ; (2) output of the generation fleet ; (3) inclusion of variable resources; (4) availability of imports; and a number of other factors that may impact the ability of a system ’ s resources to contribute to reliability. Accordingly, NERC started conducting biann ual probabilistic assessment s to supplement the Long

- Term Reliability Assessment

. 72 

### The se supplemental reports are released on even years, typically in March

, to provide a common set of probabilistic reliability indic es and recommend ation s

. Probabilistic metrics us ed in the assessment include: (1 ) annua l Loss

- of Load Hours (LOLH), (2 ) Expected Unserved Energy (EUE), and ( 3 ) Expected Unserved Energy as a percentage of Net Energy for Load (normalized EUE) for two common forecast

years ( year 2 and year 5 of t he LTRA assessment projections ) . Scenario analysis is also performed to help identify sensitivities
and off

- normal circumstances.

Additional Consideration for Transmission Adequacy
Because of t he downward trend in the Reserve M argin s for several Assessment Areas, combined with ongoing changes to the characteristics of the system

, resources planners should consider more comprehensive assessments of transfer capabilities with neighboring areas. These assessments should include future plans for resources and t ransmission, such as potential unit retirements and capacity additions

, particularly for wind and solar. Integrating these plans into operations and planning models will yield more accurate powerflow and dynamic studies. The results of these improved studi es should also be shared
between neighboring systems.

New approaches for assessing reliability should include a dequate collaboration between two or more BAs to support reliable BPS planning . Depending on the unique characteristics of each BA , transmission adequacy studies should include the following : (1) t he use of p owerflow models that contain a common economic generator d ispatch that all parties accept ; (2)

t he evaluation of non

- BES elements that could potentially impact the BPS ; and (3) t he projection and evaluation of the potential system impacts from external contingencies on their systems. I f contingencies are identified that would impact neighboring systems, the adequacy studies should be shared among all impacted parties.

72 The 2014 Probabilisti c Assessment uses 2014LTRA reference case data. NERC’s Probabilistic Assessments are released biannually (even years).

### Key Reliability Findings

NERC | 2014 Long

- Term Reliability Assessment | November 201 4
30 Other Reliability Issues In addition to the three key findings above, NERC also continues to examine the ongoing impacts of s everal other issues

. NERC will continue to monitor these issues to determine if additional evaluation or special assessment s are needed

.
Load Forecasting Uncertainties Despite slower load growth projections, t he electric industry continues to face several challenges in forecasting electricity
demand

. Specifically, conservation programs, smart grid technologies, and DERs have complicated traditional load forecasting
methods that were traditionally functions of weather conditions, economic cycles, and population growth.

In addition to other variables, t here is sufficient empirical evidence to suggest that correlations between load growth and
economic outlook

— a critical input for most load forecasts

— have diminished. As new variables are introduced to load forecasting models, further analysis will be necessary to gain a better understanding of the actual impacts and appr opriately integrate them into short‐ and long‐term load forecasting methods. N ew technologies, like advanced metering infrastructure

, plug

- in hybrid electric vehicle s , and real‐time pricing, may provide better quality load data to utilities. However, in th e near term (one

- to

- five years), these technologies may further contribute to the uncertainty

, due to changing residential customer behavior. Moreover, the benefits of these new technologies will not be realized until several year s of baseline data has bee n collected and used to establish accurate residential profiles that can be reli ed upon for future forecasting.

Energy Efficiency and Conservation Programs The recent growth of energy efficiency and conservation programs has had a substantial i mpact on the rate of load growth. Incorporating the impact of these programs into the load forecast requires special attention to consumer behavior, impacts of current and future economic conditions, and the overall effectiveness of a given program

— all three of wh ich are difficult

to measure. The growth of energy efficiency programs depends on the behavioral response of participants (or consumers)

, which is impacted by a variety of circumstances, including the program’s structure and t he overall economic conditions

. Ultimately, overestimating the impacts of these programs could result in inaccurate load forecasts, pot entially impacting reliability.

System Behavior Impacts Due to Changing System Resource Mix and Load Compositions

Resource M ix : This includ es generation characteristics, frequency response, and inertia requirements. Robust and risk

oriented planning and modeling approaches will be needed to address transmission and operating reliability. Incorrect assumptions and methods can lead to incorrect d ecision making for system reinforcement, resources, transmission, flexibility, and operational needs.

Load C omposition : Continued increases in energy

- efficient products (including newer air conditioners, compact fluorescent and LED lighting, plasma, LCD an d LED televisions, and other electronically coupled loads) are significantly changing the characteristics and behavior of system load

, particularly during system disturbances. Preliminary studies indicate that such changes may exacerbate emerging problems

, such as fault

- induced delayed voltage recovery (FIDVR). An immediate gap is the inability of current load

- modeling methods to predict system behavior with the integration of new electronically coupled loads. The changing nature of the load requires immedi ate improvements and additional sophistication in load modeling to properly analyze potential system performance issues.

High Levels of Distributed Energy Resources Create New Operational and Planning Challenges

L arge amount s of DERs on the system could result in under

- v oltage o r under

- frequency tripping due to contingencies that could potentially impact BPS stability. Because frequency is a wide

- area phenomena, resources set to allow minimal tolerance for frequency deviations (i.e., current solar PV units connected at the distribution level) can significantly impact BPS reliability, particularly when sharing identical trip points.

### Key Reliability Findings

NERC | 2014 Long

- Term Reliability Assessment | November 201 4
31 As an example, Germany has an installed capacity of over 10,000 MW of distributed PV a nd has recognized the need to integrate DERs into the ir network’s dynamic support; they have proposed the following:

1. Prevent DERs from disconnecting from the system due to faults on the system;
2. Require DERs to support the network voltage during faults by p roviding reactive power into the system; and
3. Require DERs to consume the same or less reactive power after the fault clearance as prior to the fault.
Distributing generation resources throughout the power system can also have a beneficial effect if the gen eration has the ability to supply reactive power and is coordinated by the System Operator . Without this ability to control reactive power output, performance of the transmission and distribution system can be degraded. Given the growing penetration of
dis tribution

- connected variable generation, there is an increasing need to understand its characteristics and overall
contribution to ERS s

. Potential Operational Risks Associated with Interaction of Special Protection Systems and Remedial Action Schemes Speci al Protection Systems (SPS s ) and Remedial Action Schemes (RAS s ) provide alternatives to the addition of new
transmission facilities. System Operator s need to be aware and informed of SPS and RAS devices in service, as well as the corresponding impacts associated with these devices. The lack of modeling requirements and real

- time analysis capabilities of an SPS/RAS reduces the planners’ and operators’ capability to evaluate the reliability impact of installing these tools on the system. These tools also had important implications during the Southwest outage in September 2011. 73



### Regional/Interconnection

- W ide Modeling Examining interconnection

- wide phenomena is necessary for industry to more effective ly address frequency response, inertial response, small

- signal stability, extreme contingency impacts, and geomagnetic disturbances. To support improved system performance and planning, validated models should accurately represent actual equipment performa nce in simulations. All devices and equipment attached to the electric grid must be modeled to accurately capture how that equipment performs under static and system disturbance conditions. Models provided for equipment must be open

- source and shareable ac ross the industry to support reliability.

System modeling issues have been identified in several significant system events during the past two decades (the latest being the Arizona

- Southern California Outages 74 

### ). Issues cover the full range of system s (i.e. , transmission, generation, loads

, and protection) and, more importantly, the interaction between all components. NERC has advanced the development of appropriate modeling standards, and the industry as a whole has begun addressing various pieces and parts of the modeling
issues.

While the in dustry has made significant improvements in modeling practices, it continues to address issues and future system modeling needs, such as the following:

 Standardized component models ( to gain consistency in static and dynamic models used for power system

st udies )

.

 Consistency in model parameters ( to eliminate discrepancies between real

- time contingency analysis and planning
models )

.

 Benchmarking static and dynamic models ( to close the gap between study results with real

- world behavior of the
power system net work )

.

 Modeling a greater array of system components ( to ensure greater accuracy in real

- time and off

- line studies ).

Transmission Siting, Permitting, and Other Right

- of

- Way Issues According to the 2014LTRA reference case, t ransmission additions during the 10

- year period include 7,400 circuit miles of lines currently under construction, 20,622 circuit miles of planned lines, and 7,360 miles of conceptual lines. NERC continues

73 NERC Southwest Blackout Event Reports

. 74 Arizona

- Southern California Outages

.

### Key Reliability Findings

NERC | 2014 Long

- Term Reliability Assessment | November 201 4
32 to monitor the progress of transmission projects a cross North America

, and w hile transmission planning is dynamic (i.e., a planned project can later be deemed unnecessary due to reasons such as a reduction in load growth), resource planners
should recognize the typical planning periods required to build transmission

.
Workforce Transformation Projected retirements in the electricity industry during the next decade will require a well

- trained industry workforce (primarily engineers ) . Workers entering the power industry will be tasked with understanding and implementing a variety of new technologies with smarter systems and devices as the BPS continues to rapidly evolve . The electric power industry is addressing this issue by creating p artnership s between academia and the industry through internship and train ing programs.

Aging Infrastructure Reliable operation of the electric system relies on an interconnected system of generation transmission and local distributio n elements. The North America n BPS was built over the course of a century and therefore, the age of the infrastructure var ies widely

. Maintaining t he transmission system has many challenges, such as the un availability of spare parts, the obsolescence of older equipment, the potential in ability to maintain system reliability due to outage scheduling restrictions, as well as reliably integrating new technologies . Investment in new transmission infrastructure in the United States by investor

- owned utilities has increased substantially over the past 15 years but varies significantly acr oss NERC R egions

. 75 

### The i mplementation of any replacement strategy and in

- depth training programs requires additional capital investment, engineering and design resources, and construction labor resources, all of which are in relatively short supply. The el ectric ity industry is committed to continual upgrade and maintenance of the electric ity infrastructure.

75 EIA: Today in Energy

- Electricity Transmission Investments Vary by Region

.

### Key Reliability Findings

NERC | 2014 Long

- Term Reliability Assessment | November 201 4
33 

# Assessment Area Reliability Findings

FRCC Localized Gas Supply Reduction in Extreme Events
Weather events in the Gulf of Mexico could potentially have an impact on the availability and transportation of natural gas

. H owever, dual

- fuel capability and on

- shore gas resources (with the use of fracking technologies) would mitigate a ny natural gas transportation and supply issues in extreme weather events

, such as hurricanes.

MISO
Risks Associated with Potential Generation Retirements and Addition of Natural Gas Resources
Studies have shown that with EPA MATS regulations

, MISO could lose 23,000 MW of coal capacity and subsequently increase
their natural gas generation with in MISO’s footprint. MISO has a number of available tools as an ISO/RTO to minimize the potential long

- term reliability impacts of fuel supply and transp ortation constraints. If necessary

, MISO may need to modify
their tariff to minimize potential reliability impacts of growing demand and supply/transportation constraints of natural gas.

MRO

- Manitoba Hydro Increase in Variable Resource (Decrease in System Inertia) in Neighboring Systems Manitoba Hydro is monitoring potential changes to renewable portfolio standards in neighboring areas, especially Minnesota

. R enewable portfolio standards have the potential to cause a reduction in system inertia

, which can impact the operation of Manitoba’s HVdc converters or cause other potential reliability concerns

, like activation of under

- frequency load shed ding relays for single contingencies. Southern Manitoba is quite sensitive to inertia changes due to th e relatively large amount of
HVdc converters connecte d and sensitive UFLS settings.

MRO

- MAPP High Load G rowth Projections MAPP’s projection of 2.77 percent load growth is partially due to localized growth in northwestern North Dakota and in Rochester, Minn esota

. The potential for minor instability issues is currently being studie d ; however, the MAPP Assessment

A rea does not foresee any reliability or resource adequacy issues during the assessment period.

MRO

- SaskPower Impacts of Retirement of Thermal Genera tion and Addition of Variable Resources The requirement to reduce emissions for thermal generating facilities will require ongoing resource planning to ensure that retrofitting or the addition of new emission control equipment is done in a timely manner. S askatchewan is working with
both the p rovincial and f ederal governments on emission regulations and equivalency agreements. Saskatchewan will have an increase in wind integration in the near

- term and long

- term planning horizons. The inclusion of more intermittent resources may have operational impacts that need to be studied to determine the power system effects to both Saskatchewan and neighboring jurisdictions. Depending on the make

- up of the future generation resources, intermittent

resources may ne ed to be curtailed

, or other generation sources may be required before coming on

- line to allow for the sudden changes in output.

NPCC

- Maritimes
Increase in Renewable Resources with Retirement of Coal

- Fired Generation
Parts of the Maritimes Area are seeking to displace significant amounts of fossil

- fueled generation with renewable resources. Increasing amounts of renewable resources could affect BPS reliability if variable

- or low

- mass slow

- speed units are added without considering (1) the impact of frequenc y response after system contingencies

, or (2) the need for transmission
enhancements to address and prevent the potential for voltage or overload problems.

### Key Reliability Findings

NERC | 2014 Long

- Term Reliability Assessment | November 201 4
34 NPCC

- New England
Increase in PV Resources In New England, there has been significant growth of DERs

, especially PV resources that constitute the largest portion throughout the area. Therefore, ISO

- NE’s analysis of DERs focuses exclusively on the impact of projected PV. To help address the interrelated questions of exactly how much additional PV is expect ed in the ISO’s 10

- year planning horizon and what impact this future PV could have on the regional power grid, the ISO, in conjunction with stakeholders, endeavored to create
a forecast of all future PV resources.

NPCC

- New York Environmental Regulations State and federal regulatory initiatives cumulatively will require considerable investment by the owners of New York’s existi ng thermal power plants

, and as much as 33,200 MW in the existing fleet will have some level of exposure to the new regulations.

NP CC

- Ontario Aging Infrastructure Asset renewal is a systematic approach for the continuous modernization of aging energy infrastructure. Much of the current power system infrastructure in generation, transmission, or distribution equipment is aging and need s to be refurbished, replaced, or upgraded to comply with new standards and meet demand. A long

- term energy plan has been developed to coordinate the renewal of infrastructure to manage reliability, environmental, and cost impacts.

NPCC

- Québec
Increase in Wind G eneration With the increasing amount of wind on the system, the re is a potential for impacts on system management. Main t opics under study include: (1) wind generation variability on system load and interconnection ramping, (2) frequency and voltage regulation, (3) increase of start

- ups/shutdowns of hydroelectric units due to load following coupled with wind variability, (4) efficiency losses in generating units

, and (5) reduction of low

- load operation flexibility due to low inertia response of wind generation coupled with must

- run hydroelectric generation.

PJM Extreme Weather Natural Gas Supply/Transportation PJM is investigating gas supply and transportation risk by considering the potential correlation with extreme weather (and hig h winter loads) and the potential for the loss of multiple units due to gas transportation disruptions. Gas supply and transportation risks are captured in PJM ’s resource planning studies to the extent they impact generator forced outage rates

. All forced outages, whether outside management control or not, are included in the calculations used in planning studies

. PJM currently assumes all forced outage rates are random across all seasons and independent of each other

. SERC RTO Integration Operational Mana gement Challenges Within this expanded MISO Balancing Area, market dispatches that result in power transfers between the m idwest and s outh portions of the system can result in significant unscheduled power flows through neighboring systems ( Tennessee Vall ey Authority (TVA), Associated Electric Cooperative, Inc. (AECI), Louisville Gas & Electric Company and Kentucky Utilities Company (LG&E/KU), Power South, Southwest Power Pool, Inc. (SPP), and Southern Company )

. To date

, no long

- term joint planning studies have been conducted to determine long

- term transmission system impacts and any consequent reliability impacts

. MISO and the neighboring systems have initiated discuss ions surrounding coordinated long

- term planning studies. In addition, SERC regional stud y groups are assessing and refining SERC modeling and reliability assessments to better reflect the expanded MISO BA in regional long

- term planning and operational planning assessments.

### Key Reliability Findings

NERC | 2014 Long

- Term Reliability Assessment | November 201 4
35 SPP RTO Integration Operational Management Challenges SPP, along with other j oint p arties in the R egion and MISO, is currently managing reliability concerns from MISO’s recent operational changes under the provisions of the Operations Reliability Coordination Agreement (ORCA). SPP and MISO have recently agreed to improvement s to the method for accounting for the flow impacts of import and export transactions used in the congestion management process . B oth parties are continuing to discuss additional improvements to ensure all sources of flows are properly accounted for within and between RTOs

.
TRE

- ERCOT
Weather

- Related Resource Adequacy
Multi

- year droughts in Texas continue to represent a reliability concern. Much of central Texas and the panhandle are currently under “exceptional” or “extreme” drought conditions. If drought c onditions extend into 2015, there is the risk of multiple resources being taken off

- line due to the lack of cooling water, with resource adequacy becoming an issue if operational restrictions extend over peak load periods.

WECC Impacts of Retirement of The rmal Generation and Addition of Variable Resources and Natural Gas Units

In 2013
, more than 4,700 MW of thermal generation (2,250 MW of nuclear, 909 MW of coal

- fired, and 1,588 MW of gas

fired) was retired, and 9,500 MW was added (including 5,200 MW of variable resources such as wind and solar, and 3,162 MW of gas

- fired). WECC is studying the impacts of potential planning and operational reliability impacts associated with the retirement of large thermal generating units alongside the impacts from higher levels of variable resources and natural gas supply and transportation conditions.

### NERC | 2014 Long

- Term Reliability Assessment | November 201 4
36 

# FRCC

Assessment Area Overview The Florida Reliability Coordinating Council’s (FRCC) membership includes 30 Regional Entity Division m embers and 23 Member Services Division members composed of investor

- owned utilities (IOUs), cooperative systems, municipal utilities, power marketers, and independent power producers. FRCC is divided into 10 Balancing Authorities with 70 registered entitie s (both members and nonmembers) performing the functions identified in the NERC Reliability Functional Model and defined in the NERC Reliability Standards. T he Region contains a population of over 16 million people and has a geographic coverage of about 50 ,000 square miles over Florida.


### Summary of Methods and Assumptions Assessment Area Footprint Reference Margin Level The Florida Public Service Commission’s 15 percent reserve margin criteria for non

- IOUs is applied as the Reference Margin Level. Load Forecast Method
Non c oincident, based on individual LSE forecasts Peak Season
Summer Planning Considerations for Wind Resources No wind capacity; no formalized method Planning Considerations for Solar Resources Small amount of solar capacity; no formalized method Footprint Changes Region is the Assessment Area footprint ; no recent changes



### Peak Season Demand , Resources , and Reserve Margins 76
Demand (MW) 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 Total Internal Demand 46,719 47,615 48,501 49,147 49,852 50,554 51,263 52,049 52,981 52,981 Demand Response 3,140 3,173 3,242 3,288 3,373 3,427 3,461 3,491 3,523 3,523 Net Internal Demand 43,579 44,442 45,259 45,859 46,479 47,127 47,802 48,558 49,458 49,458 Resources (MW) 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 Anticipated 55,520 55,858 56,022 56,081 57,312 57,638 58,783 60,214 61,370 60,794 Prospective 57,311 57,827 58,036 58,110 59,874 60,202 61,806 63,237 64,393 63,988 Adjusted

- Potential 57,311 57,827 58,036 58,110 59,874 60,202 61,806 63,237 64,393 63,988 Reserve Margins (%) 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 Anticipated 27.40% 25.69% 23.78% 22.29% 23.31% 22.30% 22.97% 24.00% 24.09% 22.92% Prospective 31.51% 30.12% 28.23% 26.71% 28.82% 27.74% 29.30% 30.23% 30.20% 29.38% Adjusted

- Potential 31.51% 30.12% 28.23% 26.71% 28.82% 27.74% 29.30% 30.23% 30.20% 29.38% Reference Margin Level 15.00% 15.00% 15.00% 15.00% 15.00% 15.00% 15.00% 15.00% 15.00% 15.00% Excess/Shortfall (MW) 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 Anticipated 5,404 4,750 3,974 3,343 3,861 3,442 3,811 4,372 4,493 3,917 Prospective 7,195 6,718 5,988 5,372 6,423 6,006 6,833 7,395 7,516 7,111 Adjusted

- Potential 7,195 6,718 5,988 5,372 6,423 6,006 6,833 7,395 7,516 7,111



### Peak Season Reserve Margins Peak Season Projected Generation Mix (Cumulative Change)

76 The FRCC plans through 2023. 10% 15% 20% 25% 30% 35%

2015 2016 2017 2018 2019 2020 2021 2022 2023 2024

Anticipated Prospective Adjusted-Potential Reference Margin Level -2 -1 0 1 2 3 4 5 6 7 8 9 10

2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 Gigawatts

Coal Petroleum Natural Gas Nuclear Renewables

### FRCC

NERC | 2014 Long

- Term Reliability Assessment | November 201 4
37 Demand, Resources, and Planning Reserve Margins Based on the expected load and generation capacity, all th ree the Anticipated, Prospective, or Adjusted

- P otential Reserve Margins are above 22 percent for the FRCC Assessment Area for all seasons during the assessment period. Compared to the

2013LTRA
, FRCC projects a small decrease in the 2015 summer net peak demand ; it then return s to historical weather

normalized demand growth levels similar to last year’s projections for the same time period. The winter net peak demands are projected to be approximately 3.9 percent lower compared to the 2013 projections for the same time period. T his is
attributed to revisions to the winter peak projection s that remov e the overestimation of the impact of past c old weather.

Demand Response (DR) from interruptible and load management programs within FRCC is treated as a l oad modifier and is projecte d to be relatively constant at approximately 6.6 percent of the summer and winter total peak demands for all years of the planning horizon. In 2014, Florida is setti ng DSM goals for the years 2015

– 2024 in the Demand

- Side Management g oals
docket with the Fl orida Public Service Commission

, which is held every five years . New DSM goals for both DR and energy efficiency will be set in this docket ; a decision is expected in the fourth q uarter of 2014. A key reason for the proposed reduction is a significant decr ease in the cost

- effectiveness of DSM. Since the DSM goals were set in 2009, fuel price forecasts have dropped by approximately 50 percent
, and projected environmental compliance costs

, particularly for CO 2 

### emissions
, have dropped. These changes result in a significant lowering of the projected DSM benefits from kWh reductions. These factors result in both fewer DSM options being cost

- effective

, and a lowering of incentive payments to DSM participants for other DSM options for them to remain cost

- effective, which reduces the number of DSM participating customers. In addition, the projected impact of federal and state energy efficiency codes and standards has deferred a number of utility DSM

programs that would have address ed the electrical equipment affected by these codes and standards , effectively reducing market potential for utility DSM programs. However, the projected impact of these codes and standards is accounted for in the utilities’ load forecasts, thus reducing pro jected resource needs in an identical way as would occur if these impacts were delivered by utility DSM programs.

FRCC project s 12,61 3 MW ( summer ) and 13,60 8 MW ( winter ) of additional generation to com e on

- line during the assessment period. The proposed ge neration additions are studied by the Interconnecting Transmission Owner, as well as by the FRCC Transmission Working Group (TWG) through the FRCC’s Transmission Service and Generator Interconnection Service Request Regional Deliverability Evaluation Proce ss

. FRCC project s 3,39 1 MW ( summer ) and 3,61 9 MW ( winter ) generation to be retired through the assessment period. FRCC is not anticipating any reliability impacts resulting from these unit retirements.
The unit retirements are being studied as part of the FRCC Long

- Range Study process performed annually by the TWG and the Resource Working Group (RWG) to mitigate potential reliability impacts to the g rid and the FRCC r eserve m argin criteria.

Entities within FRCC have generation under Firm contract available to be imported into the Assessment Area from SERC. In addition, approximately 840 MW of FRCC member

- owned generation is dynamically dispatched out of the SERC Assessment Area. These purchases have Firm transmission service to ensure deliverability into the FRCC Assessment Area.

In 2013, FRCC conducted a study identifying the impacts of the retirement of two coal

- generating units (915 MW) starting April 2015 as an option to comply with MATS. These two units, combined with the recent retirement of an 825 MW unit at the same site, result in a total generation reduction of 1,740 MW from this site. The Assessment Area study determined that the proposed retirements of the two coal plants would have an impact on the BES transmission system; however, the plants
hav e received an extension of the retirement date. The extension provides sufficient time to modify the plants, then construct transmission projects and the replacement of natural

- gas

- fired units to maintain the reliability of the BES within FRCC.

The FRCC Fu el Reliability Working Group (FRWG) has recently completed a natural gas pipeline study evaluating the loss of key compressor stations in the Assessment Area and the gas supply impact s resulting from an offshore hurricane. The results
of these studies indi cated that the FRCC Assessment Area would not have a large

- scale impact from extreme events. Some
loca lized gas reduction could occur; however, dual

- fuel capability could be utilized if additional generation is required. Because of the expanded use of frac king technology, more gas is coming from on

- shore sources rather than offshore sources, further reducing potential impacts from hurricanes in the Gulf of Mexico.

### NERC | 2014 Long

- Term Reliability Assessment | November 201 4
38 

# MISO

Assessment Area Overview The Midcontinent Independent System Operator, Inc. (MISO) is a not

- for

- profit, member

- based organization administering wholesale electricity markets that provide customers with valued service, reliable, cost

- effective systems and operations, dependable and transparent prices, open access to markets, and planning for long

- term efficiency. MISO manages energy, reliability, and operating reserves markets that consist of 36 local Balancing Authorities and 394 market participant s , serving approximately 42 millio n customers. The MAPP portion of the MISO Reliability Coordination Area is reported separately in the MRO

- MAPP section of this report. Although parts of the MISO fall in three NERC Regions, MRO is responsible for coordinating data and information submitted for NERC’s reliability assessments.


### Summary of Methods and Assumptions Assessment Area Footprint Reference Margin Level For planning year 2014

– 2015, MISO’s System

- Installed Generation Planning Reserve Margin requirement (PRMR) is 14.8 percent

, which is applied as the Reference Margin Level for all 10 years. Load Forecast Method Coincident Peak Season
Summer Planning Considerations for Wind Resources Effective Load

- Carrying Capability (ELCC) ; varies by wind node Planning Considerations for Solar Resources No utility

- scale solar resources in MISO Footprint Changes December 2013: I ntegration of the MISO S outh resulted in an expanded footprint

. 77



### Peak Season Demand , Resources , and Reserve Margins
Demand (MW) 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 Total Internal Demand 128,571 130,101 131,242 132,376 133,470 134,509 135,526 136,460 137,377 138,433 Demand Response 4,743 4,755 4,766 4,779 4,791 4,803 4,815 4,827 4,839 4,851 Net Internal Demand 123,828 125,345 126,475 127,598 128,679 129,707 130,711 131,633 132,538 133,582 Resources (MW) 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 Anticipated 144,893 141,510 143,669 143,225 142,852 142,889 141,221 140,921 139,821 139,521 Prospective 150,055 147,380 149,538 150,694 151,121 153,246 153,178 153,178 153,178 153,178 Adjusted

- Potential 150,258 147,754 150,075 151,374 151,917 154,134 154,086 154,181 154,317 154,317 Reserve Margins (%) 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 Anticipated 17.01% 12.90% 13.59% 12.25% 11.01% 10.16% 8.04% 7.06% 5.50% 4.45% Prospective 21.18% 17.58% 18.23% 18.10% 17.44% 18.15% 17.19% 16.37% 15.57% 14.67% Adjusted

- Potential 21.34% 17.88% 18.66% 18.63% 18.06% 18.83% 17.88% 17.13% 16.43% 15.52% Reference Margin Level 14.80% 14.80% 14.80% 14.80% 14.80% 14.80% 14.80% 14.80% 14.80% 14.80% Excess/Shortfall (MW) 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 Anticipated 2,739 (2,387) (1,525) (3,258) (4,871) (6,014) (8,835) (10,193) (12,332) (13,831) Prospective 7,901 3,484 4,344 4,211 3,398 4,343 3,122 2,064 1,025 (174) Adjusted

- Potential 8,104 3,857 4,882 4,892 4,193 5,231 4,030 3,066 2,164 965 

### Peak Season Reserve Margins Peak Season Projected Generation Mix (Cumulative Change)

77 Includes Entergy Arkansas, Inc., Entergy Texas, Inc., Entergy Mississippi, Inc., Entergy Louisiana, LLC, Entergy Gulf States Louisiana, L.L.C., Entergy New Orleans, Inc., Cleco Power LLC, Lafayette Utilities System, Louisian a Energy & Power Authority, South Mississippi Electric Power Authority, and Louisiana Generating, LLC. 0% 3% 6% 9% 12% 15% 18% 21% 24%

2015 2016 2017 2018 2019 2020 2021 2022 2023 2024

Anticipated Prospective Adjusted-Potential Reference Margin Level -6 -5 -4 -3 -2 -1 0 1 2 3 4

2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 Gigawatts

Coal Petroleum Natural Gas Renewables Pumped Storage Hydro

### MISO

NERC | 2014 Long

- Term Reliability Assessment | November 201 4
39 Demand, Resources, and Planning Reserve Margins For planning year 2014

– 2015, MISO’s System

- Installed Generation Planning Reserve Margin requirement (PRMR) on a MISO coincident load basis is 14.8 percent

, 0.6 percentage points higher than the 2013

– 2014 requirement . However, the PRMR for zone 8 (primarily covering the state of Arkansas ) was set by the Local Clearing Requirement for z one 8
, because the local 1

- day

- in

- 10 reliability criteria was higher than the system requirement. This resulted in a higher PRMR for zone 8. The major drivers of the change include: the MISO South integration

, the adjustment to the amount of external suppo rt that can be
used in time of need

, and the ongoing improvement of MISO’s load forecast uncertainty values. MISO performs out

- year LOLE
studies but only has a PRMR for the current planning year. For this assessment, the current planning year PRMR of 14.8 percent is used for the entire 10

- year period.

MISO projects that the A nticipated Reserve M argin will drop below the 14.8 requirement in 2016 and stay below the Reference Margin Level for the remainder of the assessment period. The 14.8 re quirement is dete rmined by the 1

- day

- in

- 10

- year LOLE criteria. Dropping below the Reference Margin L evel (planning reserve margin requirement) means that the MISO system will have an increase d chance of a n LOL E; in 2016
, MISO projects it will operate at the reliability lev el of approximately

2

- days

- in

- 10

- year LOLE

. As MISO starts to operate at or near the Reference Margin Level, there is a higher likelihood that System Operator s will call Emergency Operating P rocedure s more frequently to access Emergency

- Only resources

, load

modifying resources , and BTMG

. The contributing factors dr iving the projected deficit include:

 Increased retirements and suspensions (temporary mothballing) due to Environmental Protection Agency ( EPA ) regulations and market forces and low natural gas prices

 Exclusion of low

- certainty resources that were identified in the Resource Adequacy survey

 Exclusion of surplus of capacity in MISO South above the 1,000 MW transfer from the Planning Reserve Margin requirement ( PRMR ) 78



###  Increased exports to PJM and the removal of non

- F irm imports 79



###  Inadequate Tier 1 capacity additions 80



### MISO recently completed a Resource Adequacy survey in 2014 with assistance from load

- serving entities (LSEs) and the Organization of MI SO States (OMS). This survey provided additional visibility on the r esource a dequacy outlook to help
address falling below the Reference Margin Level

. 81 

### The survey also identified resources that had a low certainty of being available for each planning year. This assessment excludes t he se low

- certainty resources from the A nticipated Resources and corresponding R eserve M argin. 82



### As a result of the risk associated with falling below the Reference Margin Level

, MISO is conducting a study o f the unused capacity that do es not currently qualify as planning resource s in MISO’s planning resource a uction. 83 

### The unused capacity comes from two places : (1) generators with generator

- verification

- tested capacity that is high er than the Total

Interconnect ion Service ; and (2) e nergy

- only portions of generators. W ith the completion of this study, projects will be identified that would allow those resources to qualify as a planning resource , eli gible for participation in the plan ning resource

a u ction

.

78 For this assessment, 1,000 MW of capacity is transferred from the MISO South to the MISO North/Central Region pending the out come of regulatory issues currently under FERC review.

79 Capacity sales (imports and exports) in MISO depend on decisions of the r espective resource owners, assuming that the tariff requirements are met (including planning of necessary transmission of both the buying and selling areas). Regarding the removal of non

- Firm imports, the MISO market monitor double

- counted non

- Firm imports in the 2013LTRA reference case. These imports are accounted for in the Reference Margin Level (PRMR).

80 In the MISO footprint, 91 percent of the load is served by utilities with an obligation to serve customers reliably and at a reasonable cost. Resource planning and investment in resources are part of state and locally jurisdictional integrated resource plans that only become certain upon the receipt of a Certificate of Public Convenience and Necessity (CPCN).

81 Synonymous with the MISO term, “Planning Re serve Margin Requirement.”

82 Low

- certainty resources identified in the survey are included in the Prospective Resources and corresponding reserve margin.

83 MIS O Resource Adequacy

.

### MISO

NERC | 2014 Long

- Term Reliability Assessment | November 201 4
40 T he P rospective and A djusted

- P otential Reserve Margins remain above the 14.8 percent Reference Margin Level for the entire assessment period. P rospective R esources include low

- certain ty resources identified in the r es ource adequacy s urvey, Existing

- Other capacity, and 50 percent of all Tier 2 capacity additions, 84 

### while t h e Adjusted

- P otential resources includes 10 percent of additional Tier 3 capacity additions. 85 

### Although the A nticipated Reserve M argin is projected to fall below the

Re ference Margin Level in 2016
, MISO fully expects that the Reference Margin Level shor tfall will change significantly once

LSE s and state commissions within the footprint solidify future capacity plans, as reflected in the Prospective and A djusted

P otential Margins.

MISO forecasts the coincident Total Internal Demand to peak at 128,571 MW during the 2015 summer season

. The major
driver for the increase d demand, compared to the 2013LTRA r eference c ase , is the integration of the MISO South entities.

MI SO projects the summer coincident peak demand to grow at an average annual rate of 0.85 percent.

MISO projects between 4 ,743 MW and 4,851 MW of DR 86 

### to be available during the 10

- year outlook. Additionally, 4,300 MW
of BTMG is assumed to be available throughout the assessment period, included as Existing

- Certain capacity . No growth in BTMG is projected at this time.

Firm imports into the MISO footprint amount to 3,157 MW. These imports are unable to be recalled by the source
Transmission Service Provid er (TSP) and were designated to serve load within MISO through the Module E process for summer 2014. The 3,157 MW of imports apply for the entire assessment period. MISO also assumes 2,044 MW of F irm exports to the PJM footprint for 2015, based on the clea red results of the PJM Base Residual Auction. Exports are projected to increase to 4,135 MW in 2016 and remain at that level for the remainder of the assessment period.

For this assessment

, transfers between MISO South and MISO North/Central are limited to 1,00 0 MW, pending the resolution
of the ongoing dispute regarding the MISO

- SPP J oint Operating A greement
, which is currently under review at FERC. Any surplus capacity in MISO South beyond the 1,000 MW transfer and the MISO South PRMR is treated as Transmission

- Limited Resources (TLR) for the purpose of this assessment

. T he amount of TLRs declines each year until reaching zero in the summer
of 2021 due to a combination of load growth in MISO South, increasing capacity exports, and minimal capacity re tirements.
Transmission Outlook and System Enhancements The MISO Transmission Expansi on Plan proposes transmission projects to maintain a reliable electric grid and deliver the
lowest

- cost energy to customers in the footprint . As part of the 2013 MISO Tran smission Expansion Plan

, 87 

### MISO staff recommends $1.48 billion of new transmission expansion expenses through 2023, as described in Appendix A, to the MISO Board of Directors for review, approval

, and subsequent construction. The table below shows notable t ransmission projects approved as part of the 2013 MISO Transmission Expansion Plan :

 Petersburg

– Francis Creek

– Hanna Line 345 kV Line Rating Increase (Indianapolis Power and Light): May 2014

 Overton Transformer Replacement (Ameren Missouri): June 2014

 Straits Power Flow Control (American Transmission Company): July 2014

 Lafayette 230kV Substation Bus Modernization

– Phase 1 (Duke Indiana): December 2014

 Stone Lake

– Edgewater 161 kV (Xcel Energy): December 2014

 Pottawattamie County Substation and Po. Co unty

– Sub 701 161kV (MidAmerican Energy): December 2014

 Monroe County

– Council Creek 161 kV (American Transmission Company): March 2015

 Lenawee 345/138 kV station (Michigan Electric Transmission Company): April 2015

 Turkey Hill

– Cahokia and Cahokia Subs tation Upgrade (Ameren Illinois): June 2015

 Kokomo Highland Park to Tipton West 230 kV Line Rebuild (Duke Indiana): June 2015

84 Resources currently under study in the MISO interconnection queue awaiting signed Interconnection Agreements.

85 Resources that were identified in the Resource Adequacy survey but are not currently in the MISO interconnection queue.

86 MISO’s Demand Response Programs consist of Direct Control Load Management (DCLM) and Interruptible Load (IL).

87 The MISO Transmission Expansion Plan for 20 13

.

### MISO

NERC | 2014 Long

- Term Reliability Assessment | November 201 4

41  Bland 345/138 kV Substation (Ameren Missouri): December 2015

 Battle Creek

– Island Road 138 kV Rebuild (Michigan Electric Transmission Company): December, 2015

 Five Points 230kV Substation Upgrade

– Phase I (Duke Indiana): December 2015

 Marshall

– Blackstone 138 kV Rebuild (Michigan Electric Transmission Company): December 2015

 Toll Road (ITC Transmission): December 2015

 Lafa yette 230kV Substation Bus Modernization

– Phase 2 (Duke Indiana): December 2016

 North Appleton

– M organ 345+138 kV, Holmes

– 18th Road 138 kV (American Transmission Company): December

2016
Long

- Term Reliability Issues There continues to be significant risk associated with potential retirements during the assessment period. Previous studies have shown that considering all EPA regulations

, MISO would potentially retire 23 GW of coal

- fired capacity . Without final regulatio ns, excluding MATS, final retirement decisions continue to be far below the 23 GW of potential retirements.

The early

- 2014 polar vortex brought extreme weather conditions to the MISO Region that introduced significant challenges to the reliable operation o f the power grid. The effects were far reaching, spanning from the Canadian province of Manitoba
to the Gulf Coast. MISO will perform a comprehensive review of this event and identify any lessons learned. Initial findings
include the realized benefits of i mproved coordination with the gas pipeline operators

, as well as the risk mitigation efforts achieved by proactive staff planning. The substantial variation in DSM availability between seasons was also noted, which MISO will study further with continued ef forts targeted at improving the visibility and management of these resources.

To maximize preparedness for repeated extreme weather events
, MISO will continue efforts to improve coordination between the electric and gas industries through the Electric

- Nat ural Gas Coordination Task Force (ENGCTF)

. 88 

### Ongoing efforts
include the continuation of field trial s with the pipelines to identify improvement opportunities and establish best practices.

MISO has a number of available tools as an ISO/RTO to minimize the potential long

- term reliability impacts of fuel supply and/or transportation constraints. Tools include modifying the MISO tariff. The extent that MISO will need to use these tools, ( i.e.
, will need to modify m arket

, p lanning

, and o perational constructs ) i s an ongoing conversation with our stakeholders. To address this question in the context of growing demand for natural gas, MISO ’s ENGCTF focused on the following objectives : ( 1) e ducate and build a common knowledge base between the gas and electric indust ries; ( 2) identify gas

- electric coordination challenges and issues; ( 3) educate MISO entities on this issue ; ( 4) d evelop potential solutions to these issues; and ( 5)

t horoughly evaluate how all stakeholder groups could be impacted by these solutions. Before implementing any initiatives
, MISO considers potential costs and benefits, as well as the reliable and efficient operation of the transmission system.

Specific initiatives from the ENGCTF include : (1) e nhancing system awareness through c ontrol room improvements , such as
the introduction of an overlay display for natural gas and transmission, an online platform for notices from all pipelines in the MISO footprint, and a database linking generators to their fuel sources; (2) improving cross

- industry co mmunications through
MISO’s six

- month Coordination Field Trial with two major interstate pipeline companies , which has been extended through 2014; (3) scheduling monthly and as

- needed conference calls between MISO Op eration and Planning staff and natural g as pipeline operations staff ; and (4) examining system impacts of interdependency

. 89

88 MISO Electric and Natural Gas Coordination Task Force

. 89 For example, the 2014 Issue Summary Papers on the impacts of the polar vortex and the potential for competition between NG storage injection and power burn demand.

### NERC | 2014 Long

- Term Reliability Assessment | November 201 4
42 

# MRO

- Manitoba Hydro

Assessment Area Overview Manitoba Hydro is a Provincial Crown Corporation that provid es electricity to 548,000 customers throughout Manitoba and natural gas service to 270,000 customers in various communities throughout southern Manitoba. The Province of Manitoba is 250,946 square miles. Manitoba Hydro is winter peaking. No change in the foo tprint area is expected during the assessment period. Manitoba Hydro is its own Planning Coordinator and Balancing Authority and is a coordinating member of the Midcontinent Independent System Operator (MISO). MISO is the Reliability Coordinator for Manito ba Hydro.


### Summary of Methods and Assumptions Assessment Area Footprint Reference Margin Level The capacity criterion, as determined by Manitoba Hydro, requires a minimum 12 percent Planning Reserve Margin, applied as the Reference Margin Level in this assessment. Load Forecast Method Coincident Peak Season
Winter Planning Considerations for Wind Resources Effective Load

- Carrying Capability (ELCC) of 14.1 percent for the summer; wind is derated entirely for the winter season. Planning Considerations for Solar Resources No utility

- scale solar resources Footprint Changes N/A


### Peak Season Demand, Resources
, and Reserve Margins
Demand (MW) 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 Total Internal Demand 4,652 4,713 4,663 4,705 4,761 4,854 4,931 4,997 5,066 5,136 Demand Response 243 244 244 244 244 244 244 244 244 244 Net Internal Demand 4,409 4,469 4,419 4,461 4,517 4,610 4,687 4,753 4,822 4,892 Resources (MW) 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 Anticipated 5,637 5,521 5,521 5,671 5,847 6,257 6,365 6,365 6,365 6,365 Prospective 5,901 5,785 5,785 5,935 6,111 6,271 6,154 6,179 6,179 6,179 Adjusted

- Potential 5,901 5,785 5,785 5,935 6,111 6,271 6,154 6,179 6,179 6,179 Reserve Margins (%) 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 Anticipated 27.85% 23.54% 24.93% 27.14% 29.44% 35.71% 35.78% 33.91% 32.00% 30.11% Prospective 33.83% 29.44% 30.90% 33.05% 35.28% 36.01% 31.28% 29.99% 28.13% 26.30% Adjusted

- Potential 33.83% 29.44% 30.90% 33.05% 35.28% 36.01% 31.28% 29.99% 28.13% 26.30% Reference Margin Level 12.00% 12.00% 12.00% 12.00% 12.00% 12.00% 12.00% 12.00% 12.00% 12.00% Excess/Shortfall (MW) 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 Anticipated 699 516 572 675 788 1,093 1,115 1,041 964 886 Prospective 963 780 835 939 1,051 1,107 904 855 778 700 Adjusted

- Potential 963 780 835 939 1,051 1,107 904 855 778 700 

### Peak Season Reserve Margins Peak Season Projected Generation Mix (Cumulative Change)

9% 12% 15% 18% 21% 24% 27% 30% 33% 36% 39%

2015 2016 2017 2018 2019 2020 2021 2022 2023 2024

Anticipated Prospective Adjusted-Potential Reference Margin Level -0.2 -0.1 0.0 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8

2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 Gigawatts

Coal Hydro

### MRO

- Manitoba Hydro

NERC | 2014 Long

- Term Reliability Assessment | November 201 4
43 Demand, Resources, and Reserve Margins As a predominately hydro assessment area, Manitoba Hydro has both an energy criterion and a capacity criterion. Manitoba Hydro is projecting Anticipated, Prospective, and Adjusted

- Potential Reserve Margins to remain above the Reference Margin
Level for the entire period of the assessment.

At this time, Manitoba Hydro’s long

- term resource plans do not include operation of the sole coal generating unit in the Manitoba Hydro system (Unit 5, approximately 95 MW and located in Brandon, Manitoba) beyond 2019. Man itoba Hydro plan s to mothball the unit in 2020 unless directed by the Province of Manitoba to retire the unit at that time. As new generating resources are expected to be in service in the 2019 time frame, discontinued operation of Brandon Unit 5 is not

ex pected to have a reliability impact.

Manitoba Hydro also anticipat es that the first units (270 MW) of the total 630 MW of net capacity addition from the Keeyask

H ydro electric G enerating S tation will begin com ing into service in late 2019. This projected in

- service date is several years ahead of projected needs within Manitoba and allows for flexibility

, should there be regulatory or construction delays in the project.

Manitoba Hydro has recently updated its energy efficiency and c onservation plan. The 201 4 Power Smart Plan includes higher forecast energy and demand savings as compared with the 2013 Power Smart Plan. These 15

- year savings from the 2014 Power Smart Plan are approximately 2.3 times higher for demand savings and 2.6 times higher for energy sav ings. The increased savings are the result of enhancements to existing programs and the addition of new programs based on opportunities identified in the market. Energy efficiency and c onservation from the 2013 Power Smart Plan is used in this

assessment
, which is consistent with the values included in the current long

- term resource plans.

All of Manitoba Hydro’s dependable exports and imports are backed by contracts. Mani toba Hydro has up to 825 MW of Firm

or E xpected on

- peak transfers ( capacity exports ) during the w inter, up to 550 MW of Firm or E xpected on

- peak transfers ( capacity imports ) during the winter, and up to 1,425 MW of F irm or E xpected on

- peak exports in the summer, and associated

F irm transmission reservations over the 2015

– 2024 assessment period. Manitoba Hydro does not have any capacity imports during the summer. These contractual agreements have Firm transmission reservations with staggered terms associated with them. Manitoba Hydro does not have any capacity transactions beyond the contract terms. Some Expected Transfers (Exports are contingent upon additional resources being built within the assessment time frame.
Long

- Term Reliability Issues Severe weather events can include tornados and ice storms, for example. These ev ents can occur at any time
, but the consequence is most severe at or near the system peak load in winter. Loss of a major station or corridor can impact delivery of generation from hydro generation located in the northern portion of the area , which will im pact resource adequacy. Manitoba Hydro is planning on adding a major new 500 kV HVdc transmission line and new Riel switching station in order to mitigate the loss of the Dorsey converter station and the loss of the Bipole I/II transmission corridor. These facilities are planned to be in service by 2017 and are included in the reference case. Transmission siting and permitting issues have the potential to delay the in

- service date, which will increase Ma nitoba Hydro’s exposure to the l oss of l oad risk.

Mani toba Hydro is not anticipating any reliability impacts from increased variable resources in Manitoba. However, Manitoba is monitoring potential changes to renewable portfolio standards in neighboring areas , especially Minnesota. R enewable portfolio standa rds , resulting in additional VERs, have the potential to cause a reduction in system inertia, which can impact the operation of Manitoba’s HVdc converters or cause other potential reliability concerns , including activation of under

frequency load shed relays for single contingencies. Southern Manitoba is quite sensitive to inertia changes due to the relatively large amount of HVdc converters connected and sensitive UFLS settings. Manitoba does not have a legislated,
renewable mandate such as an RPS

, and no legislation is currently anticipated. The resource mix in Manitoba is already over 95 percent renewable under typical inflow conditions.

### MRO

- Manitoba Hydro

NERC | 2014 Long

- Term Reliability Assessment | November 201 4

44 Manitoba Hydro is not planning to increase or decrease Demand Response programs and does not foresee any reliabilit y impacts associated with the Demand Response loads. There are not significant levels of distributed and BTMG in Manitoba

, and this is not expected to change over the next 10 years. Therefore

, no reliability impacts are expected from distributed and

BTMG

. Manitoba Hydro’s system is predominately hydro, and the operating flexibility of the hydro resource is adequate to meet operating requirements during the shoulder (off

- peak) periods.

The only remaining coal unit, Brandon Unit 5 (95 MW), is impacted by the Manitoba Climate Change and Emissions Reduction
Act and the Canadian Federal Coal

- Fired Electricity Regulations. This unit is regulated such that it can only be operated to provide for emergency operations. At this time, no pending regulations are expected to impact existing gas and hydro generation in Manitoba.

The Manitoba Hydro system is predominately hydro and is desi gned and operated to serve all Firm load requirements under the worst inflow conditions on record coincident with high winter load conditi ons. Manitoba Hydro also accounts for the possibility of a drought in its operations planning processes. The largest gas generators in Manitoba, the Brandon Unit 6 and 7 combustion turbines (119 MW and 118 MW

, respectively), are dual fueled natural gas fir ed with diesel backup.

The adequacy o f natural gas pipeline capacity and natural gas generator performance in the Midwest during extreme events, and the resulting impact on Manitoba, is being monitored. At this time, no short

- or long

- term impacts on resource adequacy in Manitoba are anticipated.

### NPCC

- Québec

NERC | 2014 Long

- Term Reliability Assessment | November 201 4
45 

# MRO

- MAPP

Assessment Area Overview
The Mid

- Continent Area Power Pool (MAPP) is an association of electric utilities and other electric industry participants operating i n all or parts of Iowa, Mi nnesota, Montana, North Dakota, and South Dakota. Currently, the MAPP Planning Coordinator includes entities in two BAs and 13 LSEs. The MAPP covers an area of approximately 200,000 square miles and serves a population of about 3.5 million. MAPP typically experiences its annual peak demand in summer, but recently started projecting peak internal demand during the winter seasons. For this long

- term outlook, MAPP is considered a summer

- peaking area. However, depending on the load forecasts, MAPP may shift to a winter

- peaking area in future long

- term assessments. There have not been any changes to the MAPP Assessment Area footprint in the last two years, and no changes are expected in the future.


### Summary of Methods and Assumptions Assessment Area Footprint Reference Margin Level MAPP members use a range of reserve margin targets depending on each individual member’s system . However, MAPP provides a 15 percent Reference Margin Level. Load Forecast Method Coincident; normal weather (50/50)
Peak Season Summer; however, recent projections indicate higher T otal
I nternal D emand during the winter seasons. Planning Considerations for Wind Resources Historical data Planning Considerations for Solar Resources No utility

- scale solar resources Footprint Changes The Minnesota Municipal Utilities Association (MMUA) and Ames Municipal Utilities (AMES) are now reported in the MISO footprint.


### Peak Season Demand, Resources
, and Reserve Margins
Demand (MW) 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 Total Internal Demand 5,028 5,374 5,500 5,690 5,810 5,927 6,038 6,145 6,257 6,427 Demand Response 96 98 94 96 98 100 102 104 106 108 Net Internal Demand 4,932 5,276 5,406 5,594 5,712 5,827 5,936 6,041 6,150 6,319 Resources (MW) 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 Anticipated 6,379 6,505 6,598 6,607 6,599 6,612 6,599 6,621 6,628 6,661 Prospective 6,379 6,535 6,628 6,642 6,599 6,612 6,599 6,621 6,628 6,661 Adjusted

- Potential 6,379 6,535 6,628 6,642 6,599 6,612 6,599 6,621 6,628 6,661 Reserve Margins (%) 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 Anticipated 29.35% 23.30% 22.05% 18.11% 15.52% 13.48% 11.17% 9.60% 7.76% 5.41% Prospective 29.35% 23.86% 22.61% 18.74% 15.52% 13.48% 11.17% 9.60% 7.76% 5.41% Adjusted

- Potential 29.35% 23.86% 22.61% 18.74% 15.52% 13.48% 11.17% 9.60% 7.76% 5.41% Reference Margin Level 15.00% 15.00% 15.00% 15.00% 15.00% 15.00% 15.00% 15.00% 15.00% 15.00% Excess/Shortfall (MW) 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 Anticipated 708 438 381 174 30 (89) (227) (326) (445) (606) Prospective 708 468 411 209 30 (89) (227) (326) (445) (606) Adjusted

- Potential 708 468 411 209 30 (89) (227) (326) (445) (606) 

### Peak Season Reserve Margins Peak Season Projected Generation Mix (Cumulative Change)

0% 3% 6% 9% 12% 15% 18% 21% 24% 27% 30%

2015 2016 2017 2018 2019 2020 2021 2022 2023 2024

Anticipated Prospective Adjusted-Potential Reference Margin Level -0.2 -0.1 0.0 0.1 0.2

2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 Gigawatts

Coal Natural Gas Renewables

### MRO

- MAPP

NERC | 2014 Long

- Term Reliability Assessment | November 201 4
46 Demand, Resources, and Reserve Margins The Anticipated, Prospective , and Adjusted

- Potential Reserve Margins for MAPP are below the Reference Margin Level of 15
percent beginning in 202 0 and remain below it through 2024. MAPP has traditionally always met its target reserve margin through the mid

- term planning horizon, and beyond that time frame, F irm contracts or capacity additions may be currently
unknown

. The long

- term resource adequacy outlook for MAPP will be updated with load projections and the execution of long

- term contracts, and new capacity additions are planned

. High forecast load growth in Rochester and Minnesota, as well as the ongoing growth of oil and gas development in the
Bakken Formation in western North Dakota and e astern Montana
, has contributed to a T otal In ternal D emand annual growth rate of nearly 3 pe rcent. With Minnesota Municipa l Utilities Association (MMUA) and Ames Municipal Utilities (AMES) now submitting data through MISO, MAPP demand growth is expected to be lower in the near term
, compared to what was forecast in the 2013LTRA

.
Since the 2013 LTRA, the Rochester Public Utilities’ (RPU) Silver Lake Plant (85.2 MW) was decommissioned, while 226 MW of capacity was added

, of which 146 MW were wind resources. MAPP is projecting 349 MW of imports and 1,289 MW of exports, retaining the status of a net exporting Assessment Area with a net export of 940 MW. For these transfers

, Firm contracts exist for both the capacity and the transmission service. MAPP forecasts meet the various reserve margin targets without needing to include energy

- only, uncertain, or transmission

- limited resources.
Transmission Outlook and System Enhancements

S everal transmission projects are projected to be completed during the assessment period, all of which are intended to increase the reliability of the MAPP transmission system. RPU is a joint owner of the Hampton

– North Rochester

– LaCrosse portion of the CAPX2020 project ; this portion is expected to be in service by 2016. Although it has experienced some delays, Minnkota Power Cooperative’s Center

– Grand Forks line was scheduled to be completed by July 2014

, which will improve reliability with additional wind resources coming online.
Long

- Term Reliability Issues The integration of variable resources presents new challenges in the Assessment Area , changing the nature of how the BPS is operated. There is expected high load growth in the northwestern North Dakota area and greater load growth projected in Rochester, Minnesota . There is some minor instability that is currently being studied

, and the MAPP assessment area does not foresee any reliability or capacity issues becoming problematic during the long

- term assessment period.

### NERC | 2014 Long

- Term Reliability Assessment | November 201 4

47 

# MRO

- SaskPower

Assessment Area Overview Saskatchewan is a province of Canada and comprises a geographic area of 651,900 square kilometers with approximately 1.1 million people. Peak demand is experienced in the winter. The Saskatchewan Power Corporation (SaskPower) is the Planning Coordinator an d Reliability Coordinator for the province of Saskatchewan and is the principal supplier of electricity in the province. SaskPower is a P rovincial Crown C orporation and under provincial legislation is responsible for the reliability oversight of the Saskat chewan bulk electric system and its
interconnections.


### Summary of Methods and Assumptions Assessment Area Footprint Reference Margin Level Saskatchewan uses an Expected Unserved Energy (EUE) analysis to project its Planning Reserve Margins and as the criterion for adding new generation resources. This 11 percent margin is applied as the Reference Margin Level for this assessment. Load Forecast Method Coincident, 50/50 forecast
Peak Season
Winter Planning Considerations for Wind Resources 10 percent of nameplate (summer); 20 percent of nameplate ( winter ) Planning Considerations for Solar Resources No utility

- scale solar resources Footprint Changes N/A


### Peak Season Demand, Resources
, and Reserve Margins
Demand (MW) 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 Total Internal Demand 3,557 3,647 3,722 3,846 3,957 3,984 4,029 4,077 4,116 4,141 Demand Response 86 86 86 86 86 86 86 86 86 86 Net Internal Demand 3,471 3,561 3,636 3,760 3,871 3,898 3,943 3,991 4,030 4,055 Resources (MW) 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 Anticipated 4,309 4,383 4,387 4,437 4,737 4,659 4,540 4,779 4,829 4,829 Prospective 4,309 4,383 4,387 4,437 4,737 4,659 4,540 4,779 4,829 4,829 Adjusted

- Potential 4,309 4,383 4,387 4,437 4,737 4,659 4,540 4,779 4,829 4,829 Reserve Margins (%) 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 Anticipated 24.15% 23.08% 20.65% 18.00% 22.36% 19.52% 15.14% 19.74% 19.82% 19.08% Prospective 24.15% 23.08% 20.65% 18.00% 22.36% 19.52% 15.14% 19.74% 19.82% 19.08% Adjusted

- Potential 24.15% 23.08% 20.65% 18.00% 22.36% 19.52% 15.14% 19.74% 19.82% 19.08% Reference Margin Level 11.00% 11.00% 11.00% 11.00% 11.00% 11.00% 11.00% 11.00% 11.00% 11.00% Excess/Shortfall (MW) 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 Anticipated 457 430 351 263 440 332 163 349 355 328 Prospective 457 430 351 263 440 332 163 349 355 328 Adjusted

- Potential 457 430 351 263 440 332 163 349 355 328 

### Peak Season Reserve Margins Peak Season Projected Generation Mix (Cumulative Change)

8% 10% 12% 14% 16% 18% 20% 22% 24% 26%

2015 2016 2017 2018 2019 2020 2021 2022 2023 2024

Anticipated Prospective Adjusted-Potential Reference Margin Level -0.2 -0.1 0.0 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9

2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 Gigawatts

Coal Natural Gas Renewables Hydro

### MRO

- SaskPower

NERC | 2014 Long

- Term Reliability Assessment | November 201 4
48 Demand, Resources, and Reserve Margins Saskatchewan plans to meet projected load with Anticipated Resources throughout the assessment period. Based on the deterministic calculation made within this assessment, Saskatchewan’s A nticipated R eserve M argin ranges between 13 and 24 percent , remaining above the Reference Margin Level of 11 percent throughout the assessment period

.
Saskatchewan does not anticipate any challenges that would lead to significant detractions of its Planning Reserve Margin projections. Greenhouse gas regulations are expected to become an issue as specific federal and provincial regulations are introduced and clarified. The consequence of such regulations is expected to have a low impact on reliability, because it is expected that sufficient lead time will be given to allow for appropriate mitigation.

The forecast growth rate for Total Internal Demand is 1.7 percent during the winter seasons of the assessment period. Since last year’s assessment, the forecast growth in interna l demand has decreased slightly

, primarily due to reduced economic growth forecast.

An upswing in the economy could lead to an increase in electricity usage and cause a spike to the overall demand. Saskatchewan has plans in place to meet resource reliabili ty requirements
, should a sudden economic change cause a need for new capacity. Load growth in Saskatchewan is primarily due to economic growth in the industrial sector and in general is spread throughout the province.

It is expected that 170 MW of DSM wil l be available during the first year of the assessment and 253 MW of DSM will be available during year 10 of the assessment period

. Projected annual growth in energy efficiency and co nservation declines throughout the assessment period, ranging from 12 per cent per year in year 1 to 6 percent growth in year 10

. The primary driver for DSM programs in Saskatchewan is the economic incentive or the difference in cost between providing the DSM program and the cost of serving the load. Increases in DSM will come f rom growth of existing and new programs. DSM savings
are counted as a load modifier and are netted from the load forecast. Saskatchewan considers DR to be a capacity resource used for peak shaving and has energy

- limited contracts in place with a number of customers to provide this service. Saskatchewan will continue to initiate new economically viable DSM programs and will monitor and expand (if required) the

DR programs.

The primary sources of fuel in Saskatchewan are coal, hydro, and natural gas. Througho ut the assessment period, a total capacity of 1,631 MW (nameplate) of Future‐Planned resources are projected to come on‐line. This total consists of 250 MW of refurbished coal, 765 MW of gas, 530 MW (nameplate) of wind, 36 MW of biomass resources, and 50 M W of additional hydro resources. Projected unit retirements during the l ong

- t erm p lanning h orizon include a 79 MW natural gas facility, two 139 MW coal facilities, an 11 MW wind facility, and a 95 MW natural gas facility. Saskatchewan manages unit retireme nts and negative impacts to capacity within its resource planning process and allows adequate time for new supply resources to be put in service to meet the reliability requirements during the assessment period.

Saskatchewan plans for 10 percent of wind na meplate capacity to be available to meet summer peak demand and 20 percent of wind nameplate capacity to be available to meet winter peak demand. The wind available to meet peak requirements is based on the historical actual wind generation over a four‐hou r period during the peak for each day for the entire year. Historical data was used for each wind installation from the time it was first in service. On‐peak expected values for hydro assume nameplate net generation less expected seasonal derates due to wa ter conditions. Saskatchewan plans for 100 percent of biomass nameplate capacity to be available to meet demand

, based on a base‐load contract.

Saskatchewan has not identified any impacts on operational procedures due to integrating variable resources ove r the assessment period. Saskatchewan performs reviews of operational procedures when planning to integrate variable resources.
The addition of VERs in the future may require System Operator s to be able to curtail the se resource s , or to have additional
fast

- ramping capacity available from other resources to follow the intermittency of the variable resource.

### MRO

- SaskPower

NERC | 2014 Long

- Term Reliability Assessment | November 201 4
49 Saskatchewan does not rely on capacity transactions for reliability assessments unless there is a Firm contract for both the supply source and trans mission. Sas katchewan anticipates having a Firm i mport contract for 25 MW from winter 2015 to spring 2022. There are no F irm exports planned for the assessment period. Saskatchewan does not rely on emergency imports
to meet its demand.

Transmission Outlook and System Enhancements The following are the top transmission projects that relate to the maintenance of or enhance ment to reliability during the

near

- term p lanning h orizon of the assessment period for Saskatchewan :

 Approximately 300 km of 138 kV transmission line in the n orthern r egion of Saskatchewan.

 Approximately 110 km of 230 kV transmission line in the e ast

- c entral r egion of Saskatchewan.

 Approximately 225 km of 230 kV transmission, 225 km of 138 kV transmission , and salvage of 135 km of 138 kV line
in the s outhwest r egion of Saskatchewan.

 Approximately 100 km of 230 kV transmission line in the s outheast r egion of Saskatchewan

.

 Seven new 230

- 138 kV auto

- transformers in the s outheast r egion of Saskatchewan.

These projects are heavily dependent on load growth. Delays are assessed when indicated

, and interim measures (if required) are implemented to ensure system reliability is not impacted

For the assessment period, Saskpower has been identified that the local Swift Current area ( s outhwest region of Saskatchewan) is reactive power

- limited in the long term. To address this, a s tatic v ar s ystem (SVS) is planned in the near

term planning h orizon.

One under

- voltage load shedding ( UVLS) scheme is planned in the near

- term p lanning h orizon, in the Tantallon area in the

s outheast ern r egion of the province. This scheme will be installed to mitigate potential low voltages under certain generation dispatch scenarios caused by local N

- 1 outages (until planned transmission reinfor cements into Tantallon are in place) and a
few local N

- 2 outages in the s outheast ern r egion of the province. The planned UVLS scheme targets less than 100 MVA of load to be shed in stages. A new 230 kV transm ission line is proposed in the near

- term plannin g h orizon that will reinforce
the Tantallon

- area voltage. The UVLS scheme will then be used to mitigate potential low voltages for N

- 1

- 1 and N

- 2 outages under certain generation dispatch scenarios.

T he following conceptual Special Protection Systems (SPS) in Saskatchewan address potential generation deliverability
concerns in the near

- term planning h orizon in the local area caused by N

- 2 outages. Once local area system reinforcements
are installed to mitigate the N

- 2 contingency concerns, these protection systems may still remain installed to address more extreme operating scenarios:

 Estevan Area ( s outheastern r egion ) : This protection system is planned to be temporary until projected industrial load gr owth in the region materializes.

 Nipawin Area ( e ast

- c entral r egion ) : This protection system is planned to be permanent for the assessment period.

 Melfort Area ( e ast

- c entral r egion ) : This protection system is planned to be temporary until a planned 110 km, 230 kV transmission line is in service in the region.
Long

- Term Reliability Issues Resource adequacy and operational concerns can apply for various reasons

, including extreme weather events, hydro conditions, standards, Demand Response programs, variable g eneration
, and other unit conditions.

Operation of the Saskatchewan system would be performed on a best

- effort basis under extreme weather events. Demand would be offset by planning reserves and external markets. If necessary, operational measures include Demand Response

, Interruptible L oad contracts, public appeals, and rotating outages.

### MRO

- SaskPower

NERC | 2014 Long

- Term Reliability Assessment | November 201 4
50 Saskatchewan hydro resource planning is based on median flow conditions utilizing historical data. Most of Saskatchewan’s hydro facilities have some form of storage and a re capable of achieving near

- full

- load output for some period of time un der most operating conditions.

Demand R esponse (DR) programs are contracted on an as

- needed basis. If additional DR programs are required, Saskatchewan will actively solicit additional DR customers.

One of the largest factors for operational concerns is the addition of variable resources

, such as wind and solar. Saskatchewan performs wind integration studies and is in the process of developing a 10

- year wind power strategy. The amount o f load that is offset by DER s or BTMG is reflected in the load forecast used for reliability assessments. I t is not anticipated that Saskatchewan will encounter any long

- term reliability impacts due to DERs or BTMG

.
Typically, a significant amount of unit maintenance (partial and total unit outages) is planned for the shoulder periods in
Saskatchewan. If reliability issues are identified during a shoulder period, unit maintenance will be rescheduled. Fuel disruptions are minimized as much as possible by sys tem design practices

, and Saskatchewan has a diverse energy mix of

resources. Coal resources have F irm contracts and are mine

- to

- mouth, and stockpiles are maintained at each facility in the event that mine operations are unable to meet the required demand of the generating facility. Natural gas resources have

F irm transportation contracts with large natural gas storage facilities located within the province backing those contracts up. Hydro facilities/reservoirs are fully controlled by Saskatchewan, and long

- term hydrological conditions are monitored.

Canadian f ederal regulations for CO 2 

### emissions have been finalized and lay out the requirements and timelines for existing
coal

- fired generation for the reduction of GHG. These regulations could impact the direction taken on carbon capture and storage technology and new natural gas generation. These impacts will have a casca d ing effect on many other significant

areas , including current and projected contracts for future supply of coal and natural gas. Provincial regulations are currently being developed

, and an equivalency agreement between the provincial and f ederal governments may be created to allow greater flexibility to meet GHG regulations. Saskatchewan is working with the provincial government in developing the equivalency agreement.

Development and finalization of federal regulations to limit CO 2 

### from natural

- g as

- based electricity generation could cause Saskatchewan to modify operational use of existing gas units in order to remain compliant. Pending f ederal natural gas rules for electricity generation will impact the timing and nature of capital projects, poten tial retirements, or new energy decisions. These regulations are constantly monitored and are included in resource adequacy assessments. Saskatchewan plans to include sufficient time to perform retrofits or replacement to meet required regulations. Saskatc hewan has not yet experienced any reliability issues related to GHG regulations and is expected to effectively mitigate any future issues related

to them

.
The requirement to reduce NO x, SO 2 

### , and CO 2 

### emissions for both coal and natural gas facilities will r equire ongoing resource planning to ensure that retrofitting or the addition of new emission control equipment is done in a timely manner. The parasitic load for emission equipment is substantial . It must be included in determining net outputs from generation facilities and is dependent on the intensity limits for emission reductions. Saskatchewan is working with both the p rovincial and f ederal governments on emission regulations and equivalency agree ments.

Saskatchewan will have approximately 8.5 percent ( capacity) of wind integration by 2017 and is looking at adding more in
the l ong t erm. The addition of VERs may have operational impacts that need to be studied to determine the power system
effects t o both Saskatchewan and neighboring jurisdictions. Depending on the makeup of the future generation resources,
variable resources may need to be curtailed

, or other generation sources may need to come on

- line to allow for the sudden changes in output.

### NERC | 2014 Long

- Term Reliability Assessment | November 201 4
51 

# NPCC

- Maritimes

Assessment Area Overview
The Maritimes Assessment Area is a winter

- peaking NPCC subregion that contains two BAs. It is comprised of the Canadian provinces of New Brunswick, Nova Scotia, and Prince Edward Island, and the northern portion of Maine, which is radially connected to the New Brunswick power system. The area covers 58,000 square miles

, with a total population of 1.9 million people.


### Summary of Methods and Assumptions Assessment Area Footprint Reference Margin Level 20 percent Load Forecast Method Coincident; 50/50 forecast
Peak Season
Winter Planning Considerations for Wind Resources Estimated capacity is derived from a combination of mandated capacity factors and reliability impacts

. Planning Considerations for Solar Resources N/A Footprint Changes
A conceptual tie line to the Canadian province of Newfoundland and Labrador could potentially impact the Maritimes footprint.


### Peak Season Demand, Resources
, and Reserve Margins
Demand (MW) 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 Total Internal Demand 5,477 5,513 5,508 5,493 5,466 5,434 5,421 5,420 5,425 5,427 Demand Response 247 252 252 252 251 251 251 251 251 251 Net Internal Demand 5,230 5,261 5,256 5,241 5,214 5,183 5,170 5,169 5,174 5,176 Resources (MW) 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 Anticipated 6,676 6,680 6,527 6,527 6,527 6,527 6,527 6,527 6,527 6,527 Prospective 6,820 6,824 6,671 6,824 6,824 6,824 6,824 6,824 6,824 6,824 Adjusted

- Potential 6,820 6,824 6,671 6,824 6,824 6,824 6,824 6,824 6,824 6,824 Reserve Margins (%) 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 Anticipated 27.66% 26.97% 24.19% 24.53% 25.18% 25.93% 26.25% 26.28% 26.16% 26.11% Prospective 30.42% 29.71% 26.93% 30.20% 30.88% 31.67% 32.00% 32.03% 31.90% 31.85% Adjusted

- Potential 30.42% 29.71% 26.93% 30.20% 30.88% 31.67% 32.00% 32.03% 31.90% 31.85% Reference Margin Level 20.00% 20.00% 20.00% 20.00% 20.00% 20.00% 20.00% 20.00% 20.00% 20.00% Excess/Shortfall (MW) 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 Anticipated 401 366 220 238 270 308 323 325 319 316 Prospective 545 511 364 535 567 605 620 622 616 613 Adjusted

- Potential 545 511 364 535 567 605 620 622 616 613 

### Peak Season Reserve Margins Peak Season Projected Generation Mix (Cumulative Change)

10% 15% 20% 25% 30% 35%

2015 2016 2017 2018 2019 2020 2021 2022 2023 2024

Anticipated Prospective Adjusted-Potential Reference Margin Level -0.20 -0.15 -0.10 -0.05 0.00 0.05

2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 Gigawatts

Coal Renewables

### NPCC

- Maritimes

NERC | 2014 Long

- Term Reliability Assessment | November 201 4
52 Demand, Resources, and Reserve Margins
The Referen ce Margin L evel for the Maritimes Area is 20 percent and has not changed since the 2013LTRA . During summer and winter peak load periods, the Anticipated, Prospective, and Adjusted Potential Reserve M argins remain above the Reference Margin Level during the assessment period

. Compared to the 2013LTRA, t he aggregated load growth rate for the combined sub

- areas is practically unchanged for both the summer and winter seasonal peak load periods. Overall, the Maritimes Area’s 3

, 500 MW summer peak and 5

, 500 MW winter peak loads are both expected to decline slightly during the 10

- year assessment period. Current and projected effects
of energy efficiency are incorporated directly into the load forecast for each of the areas. Direct Control Load Management ( DCLM) in New Brunswick (NB) is intended to shift peak load into lower load periods and this program is directly embedded

in the load forecast ( reported as energy efficiency )

. 90 

### DCLM in NB is expected to rise from approximately 20 MW in 2015 to
about 240 MW by the end of the assessment period. The amount of Interruptible L oad in 2015 will be approximately 335 MW during the summer and 240 MW during the winter , increasing by about 10 MW /year over the assessment period.

Planned capacity additions include 231 MW (28 MW during the peak) of wind capacity , along with a 10 MW biomass plant,
both in Nova Scotia (NS). These additions will have virtually no reliability impact s, due to their smaller size . A 153 MW generator in NS is expected to be retired in October 2017

. This retirement depends on the planned construction of an
undersea HVDC cable between NS and the Canadian P rovince of Newfoundland and Labrador as part of the Muskrat Falls hydro

- electric generation development. NS plans to offset the retirement of the th ermal unit with a 153 MW import of hydro capacity from Muskrat Falls.

Currently there are no F irm capacity contracts between the Maritimes Area and neighboring areas. While the Maritimes Area includes 300 MW of tie benefits in its resource adequacy analyse s, it is not dependent on these capacity transactions or emergency imports from neighboring areas to meet its Reference Margin Level

. Any such transactions are coordinated through NPCC working groups

, which include members from all neighboring areas.

Tran smission Outlook and System Enhancements One major new transmission line addition in the Maritimes Area is planned for 2017. Development of the aforementioned Muskrat Falls Generation Project in the Canadian P rovince of Newfoundland and Labrador in 2017 wi ll see the installation of

a H igh

- Voltage Direct Current (HVdc ) undersea cable link (Maritime Link) between that province and NS.

The Eel River, NB HV dc i nterconnection w ith the Canadian Province of Qué bec will be refurbished during 2014. This interface

pr ovides import and export capability up to 350 MW with the Province of Qu é bec and contributes to frequency response in the Maritimes Area. An additional 230 kV breaker installation will allow the separation of supplies to two 230/138 kV
transformers in the substation at Eel River.

The construction periods for the planned projec ts mentioned above are all short and can be scheduled during times that will not significantly affect the reliability of the area. Capacity imports associated with the Maritime Link Project and the retirement of a comparable

- sized unit will be timed to coi ncide so that the p roject will not have an impact on overall reliability.
Long

- Term Reliability Issues The hydro electric power supply system in the Maritimes Area

, with a capacity of approximately 1

, 330 MW
, is predominantly

run

- of

- the

- river as opposed to s torage based. Large quantities of energy cannot be held in reserve to stave off drought
conditions. If such conditions occur, the hydro system would still be used to follow load in the a rea and respond to sudden
short

- term capacity requirements. Thermal un its would be used to keep the small storage capability of the hyd ro systems usable only for load

- following or peak supply. The Maritimes A rea is not overly reliant on wind capacity to meet resource adequacy requirements. Neither (1) t he lack of wind during peaks

, (2) very high wind speeds

, n or (3) icing conditions that

90 DCLM for the Maritimes area is in the early stages of development. Future effects are included in Energy Efficiency until the y can be clearly ident ified and itemized i n forecasts

.

### NPCC

- Maritimes

NERC | 2014 Long

- Term Reliability Assessment | November 201 4
53 would cause wind farms to suddenly shut down should affect the dependability of supply to the area

, as ample spinning
reserve is available to cov er the loss of the largest baseload generator in the area. The latter situation is mitigated further by wide geographic dispersal of wind resources across the a rea

.

RPSs have led to the development of substantially more wind generation capacity than any other type of renewable generation. Reduced frequency response associated with wind generation may, with increasing levels of wind generation in the future, require displacement with conventional generation during light load periods. With the significant amount of large

scale wind energy cur rently being balanced on the NB system, the next phase of renewable energy development in NB will
focus on smaller

- scale projects with a partic ular emphasis on non

- variable forms of generation, such as wood

- based biomass. In NS, the Maritimes Link project will displace several conceptual wind farm installations with renewable hydro resources and should help mitigate potential and related frequency response issues.

The Maritimes Area has a diversified mix of capacity resources fueled by oil, coal, hydro, nuc lear, natural gas, wind (derated),
dual

- fuel oil/gas, tie benefits, and biomass

, with no one type feeding more than 26 percent of the total capacity in the area. There is not a high degree of reliance upon any one type or source of fuel. Resource planners in the Maritimes Area do not anticipate that fuel disruptions will pose significant challenges to resource adequacy during the assessment period. This resource diversification also provides flexibility to respond to any future environmental issues, such as potential restrictions

to GHG emissions.

Load growth in the southeastern corner of the NB sub

- area, though not specifically identified in the load projections, has outpaced the rest of that sub

- area. Planners are monitoring transmission loads and voltages in the area to ensure reliability is not affected. No reinforcements have been planned at this time. DSM programs aimed at reducing and shifting peak demands and any future potential imports to NB from NS could reduce transmission loads in the southeaster n NB area. On the whole, the NB sub

- area expects a slight dec line in load during the assessment period. The impact on th e resource adequacy LOLE value is captured by modeling a reduction in tie transfer capabilities between sub

- areas. The NPCC

- 2013
Marit imes Area Comprehensive Review of Resource Adequacy 91 

### showed that after transfer levels were reduced from 300 MW to 150 MW, LOLE values do not exceed the NPCC target limit of 0.1 days per year of resource inadequacy. The Reference Margin L evels will not be affected by this issue.

The a ddition of renewable resources

, particularly in NS

, is an emerging issue in the Maritimes Area within the assessment period. Nova Scotia’s Renewable Electricity Standard (RES) is seeking to displac e significant amounts of foss il

- fired generation with renewable resources. By 2015, 25 percent of the province ’ s electricity sales (energy) will be supplied by renew able

energy sources , and by 2020 this number increases to 40 percent . Increasing amounts of renewable resources could affect

BPS reliability if variable or low

- mass slow speed units are added without considering the reduction of frequency response after system contingencies or transmission enhancements to prevent voltage o r overload problems. The process of completing s ystem i mpact s tudies prior to interconnecting new generation should identify whether the emergence of any of
these issues could limit the operation of or amount of new renewable generation added to the system on a case

- by

- case basis.

Because of the relative size of the largest generating unit in the Maritimes Area compared to its aggregated load, the area carries substantial reserve capacity. Generators use a diverse mix of fuel types with the re sult that the Maritimes Area is not overly reliant on any particular fuel to meet its load. The area is strongly interconnected with neighboring areas via high

capacity transmission lines but is not dependent on these areas to supply area load. As a result , LOLE analysis suggests that even with reasonable foreseeable contingencies

— including load forecast uncertainty, extreme weather, fuel disruptions, and generator and transmission interruptions

— the Maritimes Area load will be reliably supplied for the 10 y ears covered in this
report.

91 NPCC

- 2013 Maritimes Area Comprehensive Review of Resource Adequacy

.

### NERC | 2014 Long

- Term Reliability Assessment | November 201 4
54 

# NPCC

- New England

Assessment Area Overview ISO New England (ISO

- NE) Inc. is a regional transmission organization (RTO) serving Connecticut, Maine, Massachusetts, New Hampshire, Rhode Island, and Vermont. It is responsible for the reliable day

- to

- day operation of New England’s bulk power generation and transmission system and also administers the region’s wholesale electricity markets and manages the comprehensive planning of the regional BPS. The New England regional electric power system serves approximately 14.5 million people over 68,000 square m iles

. 

### Summary of Methods and Assumptions Assessment Area Footprint Reference Margin Level The Installed Capacity Requirement (ICR) results in a Reference Margin Level of 15.7 percent in 2015, declining to 14.3 percent in 2017 and remaining at that leve l for the duration of the period. Load Forecast Method Coincident; normal weather (50/50)
Peak Season
Summer Planning Considerations for Wind Resources 5 percent of the total Planning Considerations for Solar Resources Seasonal claimed capability Footprint Changes N/A


### Peak Season Demand, Resources
, and Reserve Margins
Demand (MW) 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 Total Internal Demand 26,930 27,291 27,521 27,677 27,782 27,911 28,028 28,167 28,298 28,430 Demand Response 1,167 944 994 994 994 994 994 994 994 994 Net Internal Demand 25,763 26,347 26,527 26,683 26,788 26,917 27,034 27,173 27,304 27,436 Resources (MW) 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 Anticipated 31,880 33,052 31,529 31,529 31,529 31,529 31,529 31,529 31,529 31,529 Prospective 31,887 33,286 31,904 32,446 32,463 32,463 32,463 32,463 32,463 32,463 Adjusted

- Potential 31,887 33,286 31,904 32,446 32,463 32,463 32,463 32,463 32,463 32,463 Reserve Margins (%) 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 Anticipated 23.75% 25.45% 18.85% 18.16% 17.70% 17.13% 16.63% 16.03% 15.47% 14.92% Prospective 23.77% 26.34% 20.27% 21.60% 21.18% 20.60% 20.08% 19.47% 18.89% 18.32% Adjusted

- Potential 23.77% 26.34% 20.27% 21.60% 21.18% 20.60% 20.08% 19.47% 18.89% 18.32% Reference Margin Level 15.70% 15.10% 14.30% 14.30% 14.30% 14.30% 14.30% 14.30% 14.30% 14.30% Excess/Shortfall (MW) 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 Anticipated 2,073 2,727 1,208 1,030 910 762 629 470 320 169 Prospective 2,080 2,961 1,583 1,947 1,844 1,697 1,563 1,404 1,254 1,103 Adjusted

- Potential 2,080 2,961 1,583 1,947 1,844 1,697 1,563 1,404 1,254 1,103 

### Peak Season Reserve Margins Peak Season Projected Generation Mix (Cumulative Change)

10% 12% 14% 16% 18% 20% 22% 24% 26% 28% 30%

2015 2016 2017 2018 2019 2020 2021 2022 2023 2024

Anticipated Prospective Adjusted-Potential Reference Margin Level -2.5 -2.0 -1.5 -1.0 -0.5 0.0 0.5 1.0 1.5

2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 Gigawatts

Coal Petroleum Natural Gas Renewables Hydro Pumped Storage

### NPCC

- New England

NERC | 2014 Long

- Term Reliability Assessment | November 201 4
55 Demand, Resources, and Planning Reserve Margins New England’s (ISO

- NE) Reference Margin Level is based on the capacity needed to meet the NPCC one

- da y

- in

- 10

- years LOLE

re source planning reliability criterion. The amount of capacity needed

— referred to as the Instal led Capacity Requirement (ICR)

— varies from year to year depending on expected system conditions. The ICR, which is calculated three years in advance
for each Forw ard Capacity Market (FCM) auction, results in a Reference Margin Level of 15.7 percent in 2015, 15.1 percent in 2016, and 14.3 percent in 2017. In this assessment, the last calculated Reference Margin Level (14.3 percent) is applied f or the remaining years

.

ISO

- NE’s Anticipated Reserve Margin during the annual peak reflects the Seasonal Claimed Capability of all ISO

- NE generators, as well as demand resources and imports that have Capacity Supply Obligations (CSOs ) as a result of the FCM auctions. In the

201 5 summer, ISO

- NE’s Anticipated Resources amount to 31,880 MW, which results in an Anticipated Reserve Margin of 23.8 percent of the Net Internal Demand of 25,763 MW. The Anticipated Reserve Margin remains above the 14.3 percent Reference Margin Level throu gh the entire assessment period.

The 2015 su mmer peak Total Internal Demand , which takes into account 1,685 MW of passive demand resources, or energy efficiency , is 26,930 MW. There has been no substantial change in the forecast since last year.

DSM in the ISO

- NE BPS includes both active and passive demand resources. Active demand resources consist of real

- time DR
and r eal

- time emergency g eneration, which can be activated with the implementation of ISO

- NE Operating Procedure No. 4

– Action during a Capacity Deficiency (OP

- 4). Active demand resources are based on the CSOs obtained through ISO

- NE’s FCM three years in advance. The CSOs decrease slightly from 1,167 MW in 2015 to 944 MW in 2016 and then increase to 994 MW
in 2017. Since there are no further aucti on results, the CSOs are assumed to remain at the same level through the end of the reporting period.

Passive demand resources (i.e., energy efficiency and conservation) include installed measures (e.g., products, equipment, systems, services, practices, a nd strategies) on end

- use customer facilities that result in additional and verifiable reductions in the total amount of electrical energy used during on

- peak hours. Passive DR is also secured by means of the FCM. However,

ISO

- NE has developed an energy ef ficiency forecasting method that takes into account the potential impact of growing energy efficiency and conservation initiatives in the region to project the amount of energy efficiency beyond the years when the FCM CSOs have already been procured. Energ y efficiency has generally been increasing and is projected to continue growing throughout the study period. The amount of energy efficiency in 2015 is 1,685 MW and is projected to increase to nearly 3,500 MW by 2024.

Active demand resources are treated li ke generating resources in ISO New England and are dispatched by ISO operators when they are needed to meet load and operating reserve requirements. A number of retirements are expected to take place in the region within the next three years. Salem Harbor Units 3 and 4, which are coal

- and oil

- fired units with a combined capacity of 587 MW, were scheduled to retire by June 1, 2014. Salem Harbor Units 1 and 2, which were coal

- fired units with a total capacity of 158 MW, were previously retired in December 20 11. As a result of these retirement s , upgrades to five transmission
lines in the North Shore area ( northwest of Boston ) were identified as being needed to address immediate reliability concerns. Those transmission upgrades have been placed in service. The capacity lost with the retirement of Salem Harbor is expected to be replaced by the new Footprint Power 674 MW generating plant, which is to be located at the Salem Harbor site.

In August 2013, the Vermont Yankee nuclear plant (619 MW) announced that it w ould be shutting down by the end of 2014. Later in 2013, ISO

- NE was notified that an additional 1,877 MW planned to retire on June 1, 2017. This total consisted of five
coal

- and oil

- fired resources representing 1,535 MW from the Brayton Point Station and three oil

- fired resources representing
342 MW from Norwalk Harbor Station.

Even with these retirements, the reserve margin is not expected to fall below the 14.3 percent Reference Margin Level during the assessment period. However, since new environmental requirements may result in the retirement of additional resources, the ISO is working with stakeholders to identify issues and find the means of meeting future capacity needs.

### NPCC

- New England

NERC | 2014 Long

- Term Reliability Assessment | November 201 4
5 6 Approximately 6,900 MW of proposed generation is in the ISO Generator Interconn ection Queue. Market incentives are under development to increase resource development where and when needed.

By design, the level of the ICR specified for New England could necessitate the use of specific OP

- 4 actions because the ICR
calculation includes capacity and accounts for the load relief these actions provide. Operable capacity study results show that the need for load and capacity relief by OP

- 4 actions will be approximately 2,600 MW during extremely hot and humid summer peak load conditions. This amount is likely achievable through OP

- 4 actions by depleting operating reserves, scheduling emergency transactions with neighboring systems, operating real

- time emergenc y generators, and implementing
five percent voltage reductions.

Preserving the reliab le operation of the system will become increasingly challenging with potential retirements and the need for operating flexibility, particularly in light of the reliance on natural gas resources. These factors are expected to incr ease the need for reliable resources, especially those able to provide operating reserves and ramping capabilities. To begin addressing this need, the ISO has procured additional 10

- minute reserves and replacement operating reserve s

. These challenges will be addressed over the long term through the Strategic Planning Initiative. 92 

### As part of this initiative, the ISO has been actively collaborating with stakeholders on comprehensive near

- and long

- term rule changes across the region’s suite of energy, reserve, and capacity markets. Proposed enhancements to the FCM include modification of the zonal structure used in the capacity market

, flexibility in Energy Market offers

, and a “pay

- for

- performance” mechanism in the FCM that will create stronger financial incentives for capacity supp liers to perform when call ed on during periods of system stress.

New England has witnessed significant growth in the development of solar photovoltaic (PV) resources over the past few years, and continued growth of PV is expected . Solar PV resources instal led in New England are predominantly BTMG
, not visible to ISO Operations in real time. A n estimated one

- third of these projects are registered in ISO’s energy mar ket as
Settlement

- Only Resources. ISO

- NE is not directly involved in the interconnection of mo st of these resources and has therefore not traditionally been aware of when and where they are installed. ISO

- NE recently formed a stakeholder working group to increase its understanding of development trends of PV and other DERs , and to develop a forecas t of PV over the next 10 years. At the end of 2013, 500 MWac of PV was installed in New England, and projections indicate that over 1,800
MWac will be added by 2023.

In January 2014, ISO

- NE began incorporating wind forecasting into its processes, schedulin g, and dispatch services. With wind forecast integration complete, the ISO will be working toward the full economic dispatch of wind resources in phase 2 of this project. The ISO will continue to analyze wind integration issues and work with stakeholders t o address the issues challenging the wind interconnection process and the performance of the system with wind resources in locally constrained areas. New England is applying advanced technologies, including FACTS and HVdc, phasor measurement units (PMU s ), and smart meters, which may be used to provide the regulation and reserve services required to reliably integrate variable renewable resources. Currently there is only 101 MW of on

- peak wind capacity in New England, and only 185 MW (on

- peak capacity) of fu ture planned wind additions during the study period.

Given the embedded nature of most PV development in New England

— projects are interconnected to the distribution system and can neither be directly observed nor dispatched by the regional System Operator

— the influence of increased amounts of PV will introduce increased variability and uncertainty to the system and eventually will have an impact on system operations (e.g., result in the need for increased reserve, regulation, and ramping). As such, new fore casting techniques eventually will be required to account for PV generation appropriately. To prepare for this, ISO

- NE is actively tracking the growth of PV in the region, monitoring its impact on operational load forecasting performance, and researching f orecasting options that may serve as short

- and/or long

- term solutions.

92 ISO

- NE Strategic Planning Initiative Key Project

.

### NPCC

- New England

NERC | 2014 Long

- Term Reliability Assessment | November 201 4
57 Firm summer capacity imports are based on FCM CSOs, which amount to 1,642 MW in 2015 and decrease to 1,267 MW in 2017. Firm transactions beyond 2017 are held const ant at the value in 2 017. Only F irm imports are reported in this assessment. However, in addition to capacity imports that have CSOs, external transactions can participate in the day

- a head
and r eal

- time energy m arkets. In past years, actual imports during the peak have been si gnificantly higher than the CSOs. For example, in 2013 the imports to New England from New York, New Brunswick, and Quebec at the time of the peak demand totaled 3,172 MW, or 1,969 MW more than the CSO of 1,203 MW. During the assessment period, there is a F irm capacity sale to New York (Long Island) of 100 MW that is expected to be delivered via the Cross

- Sound Cable.

In the case of inadequate 10

- minute operating reserves, ISO

- NE can implement an OP

- 4 action to arrange for the purchase of up to 1,000 MW of available emergency capacity and energy, or energy only (if capacity backing is not available), from

m a rket p articipants or neighboring c o ntrol a reas. ISO

- NE coordinates with other Assessment Areas to evaluate changes to the transmission system that would have an impact on import and export capabilities, and to determine a safe and reliable transfer limit if changes are needed. For long

- term studies, ISO

- NE confirms imports and exports through NPCC wor king group
studies.
Transmission Outlook and System Enh ancements
Several future transmission projects coming on

- line during the assessment period are important to the continuation of, or enhancement to, system or sub

- area reliability. The major projects under development in New England include the Maine

Power Reliability Program (MPRP) and the New England East

– West Solution (NEEWS). The new paths that are part of MPRP (many components of which are under construction) will provide the basic infrastructure necessary to increase the ability to move power from New Hampshire into Maine and improve the ability of Maine’s transmission system to move power into the local load pockets as necessary. NEEWS consists of a series of projects that will improve system reliability in areas inc luding Springfield, Massachusetts, a nd Rhode Island, and increase total transfer capability across the New England east

- to

- west and

west

- to

- east interfaces.

New smart grid technologies such as FACTS are being used in New England to improve the electric power system’s performance and operatin g flexibility. In addition, several investor

- owned and municipal utilities in New England are conducting smart grid pilot programs or projects ranging from smart meter deployments to full

- scale direct load control and distribution automation projects. ISO

- NE anticipates that these projects may lead to more significant smart grid assets becoming available for potential utilization during the assessment period.
Long

- Term Reliability Issues If New England experiences extreme summer weather that results in 90/10 peak demands or greater, ISO

- NE still should have enough operable capacity available to reliably manage the BPS

. However, if supply

- side outages diminish New England’s operable capacity to serve these 90/10 peak demands, ISO

- NE will be able to invoke OP

- 4 to meet the demand and maintain the operating reserve requirement.

RPSs mandate that by 2023, energy efficiency and renewable resources such as wind and solar must supply approximately

one

- third of the projected electric energy in New England . Possib le solutions for meeting the regional RPSs include developing the renewable resources already in the ISO generator interconnection queue; importing renewable resources from adjacent balancing authority areas; building new renewable resources in New England not yet in the queue; and using BTMG projects and eligible renewable fuels, such as biomass, at existing generators.

Concerns exist over the resultant impacts from compliance with state RPSs and the potential build

- out of these new
renewable resources. B ecause of concerns over the increasing amounts of wind capacity, ISO

- NE completed a major wind integration study that identified the detailed operational issues of integrating large amounts of wind resources into the New England power grid. The New England Wind Integration Study (NEWIS) found that the large

- scale integration of wind resources is feasible, but resource planners will need to continue addressing a number of issues, including the development of an accurate means of forecasting wind generation o utputs. As a result of that recommendation, ISO

- NE implemented a

### NPCC

- New England

NERC | 2014 Long

- Term Reliability Assessment | November 201 4
58 centralized wind power forecasting service. The addition of variable energy resources, particularly wind and solar, will like ly grow with time, hence increasing the need for flexible resource s to provide operating reserves as well as other ancillary services, such as regulation and ramping.

Since ISO

- NE’s Demand R esponse resources are treated as capacity and are procured three years in advance in its Forward Capacity Auctions, approximately 1 ,000 MW of active DR are expected to be available. As previously noted, active DR can be triggered by ISO

- NE in real time under OP

- 4 to help mitigate a capacity deficiency by reducing the peak demand. Over the past three years, the actual performance of these resources during summer peak period OP

- 4 events has ranged from 95 to 100 percent, and winter response rates have ranged from 75 to 100 percent.

PV resources (and to a lesser extent other types of DG resources) are rapidly developing in New England a nd predominantly are not directly observable or controllable by ISO

- NE. Because of the differences between the state

- jurisdictional interconnection standards that apply to most PV resources and the FERC

- jurisdictional standards that apply to larger

convent ional generators, PV exhibits different electrical characteristics during system conditions typical of grid disturbances.

ISO

- NE is working with the New England states, distribution utilities, IEEE

, and various international experts to ensure that
the futu re interconnection standards for PV (and other inverter

- interfaced DG resources) better coordinate with broader system reliability requirements.

Environmental compliance obligations for generators due to existing and pending state, regional, and federal e nvironmental requirements are likely to impose operational limits on new and existing generators but pose only a limited retirement risk and lower reliability impacts compared to earlier assessments. The lowered retirement risk is due in large part to the flexibility
that the EPA has provided in its cooling water rule and MATS, recognizing the reliability value that low

- capacity

- factor fossil steam generators provide in maintaining system fuel diversity.

U p to 12.1 GW of generating capacity in New England t hat currently utilizes once

- through cooling, including a subset of units with larger withdrawal capacities

, may potentially need to convert closed

- cycle cooling systems.

Approximately 7.9 GW of existing coal

- or oil

- fired capacity in New England is subjec t to MATS. Most affected generators in New England are equipped with required air toxics control devices due to earlier compliance with state air toxics regulations in New England. No retirements have been announced or are expected in New England due to MA TS. However, a one

- year compliance extension request has been sought by a generator for less than 100 MW of affected coal

- fired capacity. Recent revisions to air quality standards limit ambient concentrations of ozone

, and its precursors ( fine particulate matter and sulfur
dioxide ) are expected to require additional emissions reductions from fossil

- fired generators.

New England faces a number of concerns for ensuring the reliability of the fuel supply, particularly the supply of natural gas and oil. Operati ng experience has exposed some vulnerabilities associated with the strategic risks of resource performance and flexibility and the increased reliance on natural

- gas

- fired capacity. During severe winter weather, such as that experienced in winter 2013

– 2014, System Operator s faced challenges due to the combination of high winter loads resulting from cold weather, and limited natural gas and oil used to fuel generating units. In such situations, gas pipelines are often operating at their maximum levels to supply local distribution companies (LDCs) that supply retail natural gas customers. Although oil

- fired generators could compensate for the reduced availability of gas

- fired generation, they may be limited by inadequate oil inventory at the beginning of w inter, and securing midwinter replenishment of oil can be difficult due to challenges with oil transportation and availability.

ISO

- NE had implemented a winter reliability program in 2013

– 2014 and will initiate a modified program for the winter of

2014

– 20 15
, along with scheduled market improvements. The major components of the planned winter reliability program
include annual audits of dual

- fuel resources; additional compensation to offset testing costs associated with restoring or commissioning dual

- fuel capabi lity; additional winter period Demand R esponse; and additional compensation for unused oil inventory at the end of the winter period.

### NPCC

- New England

NERC | 2014 Long

- Term Reliability Assessment | November 201 4
59 Recent and planned improvements to the regional and interregional natural gas infrastructure provide initial steps for expanding the access to natural gas supply sources to meet New England’s increasing demand for natural gas for power generation. More expansion is required, however. Although natural gas production volumes in the n ortheast region are forecast to rise, New England cannot access the full benefit of production because of existing pipeline capacity constraints. The natural gas pipelines serving the region are at or near capacity, but they will n ot expand until customers commit to Firm
service . A study perfo rmed by ICF International found that if one assum es the same weather conditions as winter 2013

– 2014, winter peak

- day gas supplies will be barely adequate or slightly in deficit through 2020. Outages of capacity that is not fueled by natural gas , such as a disruption to a nuclear unit, or unforeseen outages of natural gas infrastructure

, would result in a serious gas supply deficit.

An emerging reliability issue currently being addressed by ISO

- NE is the significant growth of DG resources in New England.

Be cause PV resources constitute the largest segment of DG resources throughout New England, the ISO’s analysis of DG focuses exclusively on the impact of additional distributed PV . To help address the interrelated questions of exactly how much
additional PV is projected in the ISO’s 10

- year planning horizon and what impact this future PV could have on the regional power grid, the ISO, in conjunction with stakeholders, endeavored to create a forecast of all future PV resources. In September 2013, the ISO estab lished the Distributed Generation Forecast Working Group (DGFWG) to assist its development of a DG forecast and provide a forum to discuss DG integration issues.

Due to the complexities associated with creating a PV forecast, the ISO began with an interim PV forecast that was limited to PV that results from state policies. The PV estimates are based on state

- by

- state policy initiatives , with discounts to account
for the uncertainty of existing and future policies

. The ISO is working with the DGFWG to find ways to improve on the forecast in future years.

Results of the forecast will inform various ISO system planning functions. For example, the ISO intends to use data from the DG forecast in transmission studies, new generator interconnection studies, and economic studies. The ISO will work with stakeholders to explore how the DG forecast may potentially be used in these planning analyses and other market

- related assessments. These may include such tasks as the develo pment of the ICR

. The growth in DG presents some challenges for grid operators and planners. Challenges for the ISO include: ( 1) a limited amount of data concerning DG resources, including their size, location, and operational characteristics; ( 2) a curren t inability to observe and control DG resources in real time; ( 3) a need to better understand the impacts of growing DG on system operations, including ramping, reserve, and regulation requirements; and ( 4) potential reliability impacts to the regional

pow er system posed by future amounts of DG resulting from existing state interconnection standards.

Ongoing work between ISO

- NE and the DGFWG will help position New England to best integrate rapidly growing DG resources in a way that maintains reliability an d allows the states to realize the public policy benefits they have identified as the basis for their DG programs.

### NERC | 2014 Long

- Term Reliability Assessment | November 201 4
60 

# NPCC

- New York

Assessment Area Overview The New York Independent System Operator (NYISO) is the only BA within the state of New York (NYBA)

. The NYISO is a single

- state ISO that was formed as the successor to the New York Power Pool

— a consortium of the eight IOUs

— in 1999. The NYISO manages the New York State transmission grid, encompassing approximately 11,000 miles of transmis sion lines over 47,000 square miles and serving the electric needs of 19.5 million New Yorkers. New York experience d its all

- time peak load of 33,956 MW in the summer of 2013.


### Summary of Methods and Assumptions Assessment Area Footprint Reference Margin Level The New York State Reliability Council ( NYSRC ) Installed Reserve Margin (IRM) of 17 percent extends through April 2015. Because this margin will be reassigned in 2015 , NYISO will use the default Reference Margin Level of 15 percent. Load Forecast Method Coincident; normal weather (50/50)
Peak Season
Summer Planning Considerations for Wind Resources Modeled with a 17 percent capacity factor Planning Considerations for Solar Resources Modeled with a 65 percent capacity factor Footprint Changes N/A


### Peak Season Demand, Resources
, and Reserve Margins
Demand (MW) 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 Total Internal Demand 34,066 34,412 34,766 35,111 35,454 35,656 35,890 36,127 36,369 36,580 Demand Response 1,189 1,189 1,189 1,189 1,189 1,189 1,189 1,189 1,189 1,189 Net Internal Demand 32,877 33,223 33,577 33,922 34,265 34,467 34,701 34,938 35,180 35,391 Resources (MW) 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 Anticipated 38,311 38,330 37,980 37,980 37,985 37,985 37,985 37,985 37,985 37,985 Prospective 41,715 42,691 42,702 43,217 43,228 43,228 43,228 43,228 43,228 43,228 Adjusted

- Potential 41,715 42,691 42,702 43,217 43,228 43,228 43,228 43,228 43,228 43,228 Reserve Margins (%) 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 Anticipated 16.53% 15.37% 13.11% 11.96% 10.86% 10.21% 9.46% 8.72% 7.97% 7.33% Prospective 26.88% 28.50% 27.18% 27.40% 26.16% 25.42% 24.57% 23.73% 22.88% 22.14% Adjusted

- Potential 26.88% 28.50% 27.18% 27.40% 26.16% 25.42% 24.57% 23.73% 22.88% 22.14% Reference Margin Level 15.00% 15.00% 15.00% 15.00% 15.00% 15.00% 15.00% 15.00% 15.00% 15.00% Excess/Shortfall (MW) 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 Anticipated 502 123 (633) (1,030) (1,420) (1,652) (1,921) (2,194) (2,472) (2,715) Prospective 3,907 4,485 4,088 4,207 3,823 3,591 3,322 3,049 2,771 2,528 Adjusted

- Potential 3,907 4,485 4,088 4,207 3,823 3,591 3,322 3,049 2,771 2,528 

### Peak Season Reserve Margins Peak Season Projected Generation Mix (Cumulative Change)

0% 3% 6% 9% 12% 15% 18% 21% 24% 27% 30%

2015 2016 2017 2018 2019 2020 2021 2022 2023 2024

Anticipated Prospective Adjusted-Potential Reference Margin Level -0.90 -0.70 -0.50 -0.30 -0.10 0.10

2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 Gigawatts

Natural Gas Coal Petroleum Renewables Hydro

### NPCC

- New York

NERC | 2014 Long

- Term Reliability Assessment | November 201 4
61 Demand, Resources, and Planning Reserve Margins
Th e current Installed Reserve Margin (IRM) requirement for the NYBA that covers the period from May 2014 to April 201 5 (2014 Capability Year) is 17 percent

. T he New York State Reliability Council (NYSRC) sets t his requirement annually based upon an annual st udy conducted by its Installed Capacity Subcommittee (ICS). Because the IRM will be reassigned after April 2015, a 15 percent Reference Margin Level has been used for this long

- term assessment. While the Anticipated Reserve Margin falls below the 15 percent Reference Margin Level in 2017, the Prospective Reserve Margin remains above for all
seasons and years of the assessment period.

The energy forecast for the downstate area is lower than that of last year due to a change in the expected relations hip of energy growth with the economy. Whereas economic growth (based on either employment or metro area GDP) is expected

to increase, some of the zones in the downstate area are projected to have negative energy growth, but continue to expect positive sum mer and winter peak demand growth. This decline in year

- over

- year energy usage is attributed to the continued impact of energy efficiency programs and is reflective of a recent history of negative energy us age on a weather

- adjusted
basis.

FERC approved cha nges to the ICAP/SCR program (Docket No. ER14

- 39) that became effective on March 15, 2014. These changes went through an extensive discussion and review process through the NYISO committees prior to filing a tariff change with FERC. The process to determin e the ICAP value of SCR resources was modified as a result of these changes.

New York State has recently announced new initiative s in DER, BTMG, and customer

- sited solar photo

- voltaic power. The impact of solar PV has been incorporated in this year’s energy efficiency projections. It is still too early to determine the impact of DER on energy and summer peak, as the new policy has not yet been translated into specific targets or goals.

NYBA’s existing generation, Special Case Resources (SCR), and net i mports total 41,307 MW for 2015. There are 4,579 MW of proposed generation included in the 2014 Load and Capacity Data Report. Of this total, 3,461 MW are fossil fuel projects, 1,044 MW are wind turbine projects

, and 22 MW are non

- wind renewable energy pro jects. Additionally, based on publicly available information, 806 MW of summer capacity may be retire d or mothball ed by 2017.

Capacity transactions modeled in NYBA reliability studies are part of the NYBA’s resource mix to meet LOLE criteria. These

transac tions would be expected to perform on peak or any other time as needed to meet the demand. Capacity transactions modeled in NYBA’s assessments have met the requirements as defined in the NYBA’s tariffs. Both the NYBA and the respective neighboring assessme nt areas have agreed upon the terms of the capacity transaction. The NYBA does not rely on emergency imports to meet the assessment area’s Reference Margin Level. However, transfer capability is reserved on the ties with neighboring areas in NYBA’s plannin g studies to allow for emergency imports as one potential emergency operating procedure step in the event of a system emergency.

Transmission Outlook and System Enhancements The Transmission Owner Transmission Solutions (TOTS) consist of three transmission projects in central New York, downstate New York, and New York City. TOTS is part of the Con Edison and the New York Power Authority (NYPA) filing in response to
a November 2012 o rder from the New York Public Service Commission (PSC) that recognized the significant reliability needs
that would occur if the Indian Point Energy Center (IPEC) were retired upon the expiration of IPEC’s existing licenses.
Long

- Term Reliability Issues The 2012 RNA identified new environmental regulatory programs. These state and federal regulatory initiatives cumulatively will require considerable investment by the owners of New York’s existing thermal power plants in order to comply. The NYBA has determined that as much as 33,200 MW in the existing fleet will hav e some level of exposure to the new regulations.

Since the publication of the RNA

, the U.S. Supreme Court has consented to hear an appeal of the Cross State Air Pollution Rule (CSAPR). In July 2011, the EPA replaced the Clean Air Transport Rule (CATR) prop osal with the finalized CSAPR. The rule requires significant additional reductions of SO 2 

### and NO x 

### emissions beyond those previously identified. The CSAPR establishes

### NPCC

- New York

NERC | 2014 Long

- Term Reliability Assessment | November 201 4
62 a new allowance system for units larger than 25 MW of nameplate capacity. Affected generat ors will need one allowance for each ton emitted in a year. In New York, CSAPR will affect 154 units that represent 25,900 MW of capacity. The EPA has estimated New York’s annual allowance costs for 2012 at $65 million. There are multiple scenarios that sh ow that New York’s generation fleet can operate in compliance with the program in the first phase. Compliance actions for the second phase may include emission control retrofits, fuel switching, and new clean

, efficient generation. If the EPA appeal is successful, it may
be reasonable to expect delay s in the implementation of the rule until 2016

, which would place it on a schedule that is nearly
concurrent with MATS.

The EPA finalized a regulation in February 2012 to establish emission rate sta ndards for MATS that will limit emissions through the use of Maximum Achievable Control Technology (MACT) for hazardous air pollutants (HAP) from coal

- and oil

- fueled steam generators with a nameplate capacity greater than 25 MW. The majority of the New Yo rk coal fleet has installed emission control equipment that may place compliance within reach. The heavy oil

- fired units will need to either make significant investments in emission control technology or switch to ( or maintain ) a cleaner mix of fuels in or der to comply with the proposed standards. Given the current outlook for the continued attractiveness of natural gas compared to heavy oil, it is anticipated that compliance will be achieved by dual

- fuel units through the use of natural gas to maintain fue l ratios such that the effective capacity factor on oil is less than 8. Compliance requirements begin in March 2015

.
The EPA has proposed a Section 316 ( b ) rule providing standards for the design and operation of power plant cooling systems.
This rule will be implemented by the New York State Department of Environmental Conservation ( NYSDEC )

, which has finalized a policy for the implementation of th is rule is known as Best Available Technology (B A T) for plant cooling water
intake structures. This policy is activated upon renewal of a plant’s water withdrawal and discharge permit. Based upon a review of current information available from NYSDEC, NYISO has estimated that between 4,400 and 7,300 MW of capacity could be required to retrofit closed

- cycle cooling systems.

The class of steam electric units constructed between 1963 and 1977 is subject to continuing emission reductions required by the Clean Air Act. In New York, 16 units with 8,400 MW of capacity are affected. The owners of these units have submitted their plans for Best Available Retrofit Technology (BART) and have received modified Title V air permits incorporating the final plans. The oil

- fired units are proposing alternatives that include maintaining the status quo, lower sulfur fuels, and low

NO x 

### combustion systems. Two smaller coal plant owners have chosen to retire small boilers. The new permit limitations became effective January 1, 2014. No additional capacity losses are anticipated as a direct result of the implementation of

BART.

The NYSDEC h as promulgated revised regulations for the control of NO x 

### emissions from fossil

- fueled electric generating units. These regulations are known as NO x 

### RACT (Reasonably Available Control Technology) for oxides of nitrogen. In New York, 254 units with 27,800 M W of capacity are affected. Emission reductions required by these revised regulations must be in place by July 2014.

The Regional Greenhouse Gas Initiative (RGGI) established a cap over CO 2 

### emissions from most fossil

- fueled power plants
with more than 25 MW in 2009. In 2012
, the RGGI s tates undertook a program review

, which concluded in February 2013. The program review called for reducing the cap by 45 ,000,000 to 91,000,000 tons for 2014 and then applying annual
reductions of 2.5 percent until 2020. A key provision to keep ing the allowance and electricity markets functioning is the Cost Containment Reserve (CCR). If demand exceeds supply at predetermined trigger prices

, an additional 10,000,000 in
allowances would be added to the market.

The EPA has released a revised rule for final comments that is designed to limit CO 2 

### emissions from new fossil

- fueled steam generators and combined

- cycle units. The rules are generally less stringent than the NYSDEC’s Part 251 that is applicable in

NY. This EP A rule does not apply to simple

- cycle turbines that limit their sales to the g rid to less than one

- third of their potential output.

### NERC | 2014 Long

- Term Reliability Assessment | November 201 4
63 

# NPCC

- Ontario

Assessment Area Overview Ontario’s electrical power system is geographically one of the largest in North America
, covering an area of 415,000 square miles and serving the power needs of more than 13 million people. Ontario is inte rconnected electrically with Qué bec, MRO

- Manitoba, states in MISO (Minnesota and Michigan )

, and NPCC

- New York

. 

### Summary of Methods a nd Assumptions Assessment Area Footprint Reference Margin Level The IESO

- established Reserve Margin Requirement is applied as the Reference Margin Level. 93
Load Forecast Method Coincident; normal weather (50/50)
Peak Season
Summer Planning Considerations for Wind Resources Modeled, based on historic performance and historic weather data Planning Considerations for Solar Resources Modeled, based on historic weather data ; 30 percent for summer Footprint Changes N/A



### Peak Season Demand, Resources
, and Reserve Margins
Demand (MW) 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 Total Internal Demand 22,726 22,535 22,344 22,301 22,272 22,170 22,479 22,609 22,616 22,541 Demand Response 567 621 695 695 695 795 945 1,095 1,295 1,495 Net Internal Demand 22,158 21,914 21,649 21,606 21,576 21,375 21,534 21,514 21,321 21,046 Resources (MW) 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 Anticipated 27,112 26,910 26,497 27,519 26,630 26,345 26,520 26,455 27,169 27,232 Prospective 27,112 26,910 26,497 27,519 26,630 26,345 26,520 26,455 27,169 27,232 Adjusted

- Potential 27,112 26,910 26,497 27,519 26,630 26,345 26,520 26,455 27,169 27,232 Reserve Margins (%) 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 Anticipated 22.36% 22.80% 22.39% 27.36% 23.42% 23.25% 23.16% 22.96% 27.43% 29.39% Prospective 22.36% 22.80% 22.39% 27.36% 23.42% 23.25% 23.16% 22.96% 27.43% 29.39% Adjusted

- Potential 22.36% 22.80% 22.39% 27.36% 23.42% 23.25% 23.16% 22.96% 27.43% 29.39% Reference Margin Level 19.50% 18.78% 19.86% 19.99% 20.00% 20.00% 20.00% 20.00% 20.00% 20.00% Excess/Shortfall (MW) 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 Anticipated 633 880 549 1,593 738 695 680 638 1,583 1,977 Prospective 633 880 549 1,593 738 695 680 638 1,583 1,977 Adjusted

- Potential 633 880 549 1,593 738 695 680 638 1,583 1,977 

### Peak Season Reserve Margins Peak Season Projected Generation Mix (Cumulative Change)

93 Ontario IESO, for its own assessments, treats Demand Response as a resource instead of as a load

- modifier. As a consequence, the Net Internal Demand, Planning Reserve Margins and the Target Reserve Margin numbers differ in IESO reports when compared to NE RC reports. The Ontario reports would report lower reserve margins. 15% 18% 21% 24% 27% 30%

2015 2016 2017 2018 2019 2020 2021 2022 2023 2024

Anticipated Prospective Adjusted-Potential Reference Margin Level -7 -6 -5 -4 -3 -2 -1 0 1 2 3 4 5 6

2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 Gigawatts

Natural Gas Nuclear Renewables Hydro Petroleum

### NPCC

- Ontario

NERC | 2014 Long

- Term Reliability Assessment | November 201 4
64 Demand, Resources, and Planning Reserve Margins Ontario has invested heavily in electricity infras tructure over the past decade. Investments have enabled the phase

- out of
coal

- fired generation in the province and have reduced the carbon intensity of Ontario’s electricity supply mix. Onta rio’s electricity demand growth has been low t o moderate during this period. Growing net supply additions and moderate demand
have resulted in substantial capacity margins. Capacity margins have been reduced to more normal levels with the recent phase

- out of coal

- fired generation in the province. Ontario’s evolving supply mix features increasing and significant penetrati ons of renewable sources.

The Reference Margin Levels for the first four years of the assessment period vary between 1 8.78 and 20 percent t hrough 2020, then remain at 20 percent through 2024

. This variance is necessary to reflect the changes in outages, demand forecast

, and available resources. However, the R eference M argin Levels published in this report have been modified to reflect NERC ’s reserve margin calculation . Previously

, D emand R esponse (DR) was treated as a resource, but now it must be accounted for in the margin calculation as a load modifier for all Assessment Areas . This approach results in a higher percent for both the

R eferenc e M argin Level and the projected Reserve Margins

. Between 2020 and 2024, Ontario will rely on new planned resources of up to 3,640 MW, as per Ontario’s Long

- Term Energy Plan (LTEP), to meet the Reference Margin Level . Ontario possesses a range of option s t o address these needs, inclu ding
market

- based mechanisms. Additional p lanning activities to meet future resource adequacy needs are currently underway.

This year’s forecast of Net Energy for Load (NEL) has an average annual growth rate of

- 0.4 percent during the 10

- year period,
similar to the 2013LTRA forecast of

- 0.2 percent average growth for 2013

– 2023. Although there is increased demand for electricity driven by modest economic expansion and populatio n growth, these increases are being more than offset by three key factors:

1. The growth in embedded generation and BTMG capacity, which has a significant downward impact on grid

- supplied electricity, which is the demand value being considered (r ather than to tal consumption).

2. Conservation impacts that reduce the overall need for both end

- use and grid

- supplied electricity.

3. The increasing impact of price

- sensitive demand through the implementation of time

- of

- use rates
, as well as the
Industrial Conservation Init iative.

In general, distributed ( embedded ) generation (DG) is having the largest impact on grid

- supplied energy demand. Summer peaks are particularly affected by the increased penetration of sola r

- powered DG

. The summer peaks are also being influenced by efficiency changes to air conditioners.

The winter peaks are not significantly impacted by DG , because in Ontario
, most is comprised of solar facilities

, and the peak
occurs after sunset

, when solar DG is no longer generating power

. However, the winter pea k is seeing downward pressure from conservation savings due primarily to lighting efficiencies as end users move to compact fluorescent and LED technology.

While overall demand is expected to decline

, there will be some variation within Ontario

. The Greate r Toronto area (GTA) has the largest share of the Ontario population and economy. The Essa zone

, which lies just north of the GTA

, will see positive growth resulting from ongoing expansion of the GTA . P rimarily due to expected mining growth associated with vast untapped
natural resources in the northern portions of the province

, a rebound is expected during the later years of the forecast

. The

Net Internal Demand forecast in the 2014LTRA r eference c ase is reduced by the amount of DR programs , previously counted as resources in Ontario. For its own provincial assessments, DR programs will continue to be treated as resources.

Over the course of the forecast, the DR program impacts during the summer are expected to increase from just over 500 MW, at present, to less than 1,500 MW by the end of the forecast period

. Starting in 2020, t he increased DR is expected to show significant growth. In the IESO, DR is comprised of three program s: Demand Response 3 ( DR 3 ) , Peak saver PLUS ® (primarily driven by air

- condition ing load), and dispatchable loads. Participation in d ispatchable load programs drops during the peak period

.

### NPCC

- Ontario

NERC | 2014 Long

- Term Reliability Assessment | November 201 4
65 Conservation is expected to yield incremental peak savings of more than 3,000 MW by 2024. The Ontario government’s Long

Term Energy Plan ( LTEP ) est ablished a provincial conservation and demand management target of 30 TWh /year of cumulative savings by 2032. The reference year for the savings is 2005

, with projected milestones of 11 TWh /year by 2015 and 21
TWh /year by the end of 2024. Those savings wil l be achieved through improved building codes, equipment standards, and conservation programs.

LTEP 2013 has also set a goal to use DR to be able to meet 10 percent of net peak demand by 2025, equivalent to approximately 2,400 MW under forecast condition. This includes all DR programs

, such as Time

- of

- Use rates, Industrial Conservation Initiative, market dispatchable load, DR3
, and Peak saver PLUS®

. The responsibility for existing and newly
introduced DR initiatives has been transferred from the Ontario Power Authority (OPA) to the IESO.

In June 2014, the IESO implemented a redesigned framework for activation of the DR3 program through integration into the electricity market. DR3 is a contractual peak load reduction program that encourages businesses to reduce their electricity use during periods of peak demand. The redesigned framework will model DR3 as aggregated resources within IESO market and system tools. In place of activations that are based on a combination of supply cushion and price

- based triggers, DR3 resources are activated when they represent a competitively priced energy resource in the pre

- dispatch time frame ( i.e.
, activated on a price trigger only )

. All coal units in Ontario have been p hased out as of April 2014, in accordance with Ontario government policy. In the years following the coal phase

- out, the province’s next reliability challenge will be to carefully manage th e renewal of its nuclear
fleet. Nuclear units at Pickering Generati ng Station will not be refurbished

, and c urrent plans are to operate these units through approximately 2020.

Supply options for maintaining resource adequacy over this time period are being considered. These options include conservation, re

- contracting Non

- Utility Generator (NUG) facilities as their contracts reach maturity, new gas

- fired generation, and conversion of some or all of the Lambton and Nanticoke coal

- fired units to natural gas, imports, and energy
storage. A bout 1,400 MW of NUG contracts have t he opportunity to be renegotiated as the contracts are expiring within the next decade. The OPA is in the process of renegotiating the NUG contracts.

Over the assessment period, the capacity of embedded generation , such as DERs and BTMG, is expected to in crease significantly. The Feed

- in Tariff (FIT) and microFIT programs drive this growth with renewable generation

. Over the forecast period

, about 2,500 MW of wind and solar DG is projected to be added

— m ost of which is solar

. By 2024 there will be over 4,00 0 MW of DG in Ontario

. In 2014, the IESO issued a request for proposals to procure up to 35 MW of energy storage to explore how new technologies can provide additional flexibility to carry out grid operations. The IESO storage procurement process supports the LTEP , which calls for 50 MW of energy storage in Ontario. Subsequent to the IESO’s procurement process, the OPA will issue a request for proposals for the remaining 15 MW. These procurements are structured to maximize learning about energy storage services and how they can best serve Ontario’s needs. C ontracts were planned to be executed during the summer of 201 4 and become operational sometime in 2017.

About 14 percent of the installed wind capacity is assumed to be available at the time of summer peak, and 33 percent is assumed to be available at the time of winter peak

. Ontario’s solar capacity value is foreca st to be 30 percent of installed capacity for the summer peak and 4 percent for the winter peak

. The assumed capacity contribution for hydroelectric is 71 percent for the summer peak and 76 percent for the winter peak.

To meet the challenge of rapid deploy ment of renewables across the province and help capture the benefits of Ontario’s investment in variable generation, the IESO has adapted power system planning and operations, as well as the IESO

administered markets to accommodate the influx of renewables

. T he IESO implemented the Renewables Integration Initiative (RII) in 2013 to effectively integrate up to 10,700 MW of renewable generation by 2021. RII has already yielded results,

### NPCC

- Ontario

NERC | 2014 Long

- Term Reliability Assessment | November 201 4
66 including the integration of the hourly centralized forecast into IESO sch eduling tools

, and enhanced visibility of renewable output of distributed

- connected variable generation facilities 5 MW or greater

. This was accomplished by providing System Operator s with greater levels of awareness of system conditions

. Improved variable generation forecasting and greater visibility is expected to bring measurable benefits to the maintenance of system reliability and market efficiency. The dispa tch of grid

- connected renewable resources provides increased flexibility from available variabl e generation resources and will allow IESO to operate the system reliably by providing the needed tools to manage issues such as ramp needs and surplus baseload generation (SBG) situations

. Frequency response, short

- term inertial response, voltage ride

- th rough capability

, and voltage support are some of the performance requirements clearly identified during the connection process and validated through tests before the new grid

connected resources complete their facility registration with the IESO. Frequenc y respon se and voltage ride

- through capability requirements also apply to distribution

- connected resources larger than 10 MW. To capture the effects of all DG on the performance of the grid, including those smaller than 10 MW, the IESO periodically conduct s system studies

. I f needed, mitigating measures such as grid

- connected SVCs will be developed and requested to be implemented.

Capacity transfers are not considered in this assessment, as Ontario does not have any F irm contracts with other areas

. E mergency imports are not considered in this assessment. However, for use during daily operation, operating agreements between IESO and neighboring jurisdictions in NPCC, RF, and MRO include contractual provisions for emergency imports into IESO. IESO also participates in a shared activation of reserve group s , including IESO, ISO

- NE, Maritimes, NYISO, and PJM.

Transmission Outlook and System Enhancements Northwestern Ontario is connected to the rest of the province by the double

- circuit, 230 kV East

– West Tie. The primary source of generation within the northwest is hydroelectric. In addition, strong local load growth is forecast

, as mentioned above. Additional capacity is required to maintain reliable supply to this area under the wide range of possible system and water conditions. The expansion of the East

– West Tie with the addition of a new double

- circuit 230 kV transmission line is expected to be in service by 2018 and will provide reliable and cost

- effective long

- term supply to the n orthwe st.
Long

- Term Reliability Issues The renewable resources target for wind, solar, and biomass is 10,700 MW by 2021, which is accommodated through transmission expansion and maximized use of the existing system. Ontario will add a few hundred MW of hydroelec tric capacity to reach a target of 9,300 MW by 2025. A substantial amount of renewable generation is embedded and included in the demand forecast. This level of variable generation will be incorporated into the system through the development of new
facilit ies and significant investments to upgrade existing facilities in Ontario . The operational and adequacy concerns of integrating of new variable generation are addressed through RII and the connection requirements imposed by the IESO on grid

- connected resou rces, and on resources larger than 10 MW connecting to the distribution system.

A reduction of SBG events is expected after the nuclear refurbishment programs begin. The vast majority of SBG is currently managed through normal market mechanisms

, including export scheduling and nuclear maneuvering. The IESO’s variable generation dispatch tools have provided additional flexibility to alleviate most SBG events.

In light of environmental and other concerns, coal

- fired generation has been replaced in Ontario by sources that emit less
carbon

. In the years ahead, natural gas

- fired generation will play an important role in Ontario’s supply mix balance, providing the flexibility to cushion the electricity system when demand and intermittent resources rise or fall.

Al most all of Ontario’s oil and natural gas comes from outside the province

. In addition to the use of these fuels for electricity generation, Ontario relies on oil and natural gas to support basic needs such as heat and transportation. In particular, reli an ce on natural

- gas

- fired generation will grow as this form of generation represents an essential element in the sustainability of a responsive and flexible electricity system. Supply to Ontario’s gas fleet is su pported by significant F irm supply and
transpo rtation contracts

. The IESO is an active participant in the Eastern Interconnection Planning Collaborative effort in the

### NPCC

- Ontario

NERC | 2014 Long

- Term Reliability Assessment | November 201 4
67 ongoing development of the Gas

- Electric System Interface Study

, 94 

### which evaluate s the capability of natural gas systems to satisfy the future needs of the electric sys tem across most of the Eastern I nterconnection.

With the growth in conservation savings and DG , demand forecasting has become more complex. S mart meters and higher

on

- pea k electricity prices has introduced consumer price response previously not seen in Ontario. Traditionally, demand was a function of weather conditions, economic cycles, and population growth. With multiple factors influencing demand, determining the causal ity of demand changes has become increasingly nuanced and requires greater data and analysis.

94 EIPC: Gas

- Electric System Interface Study

.

### NERC | 2014 Long

- Term Reliability Assessment | November 201 4
68 

# NPCC

- Québec

Assessment Area Overview The Québec Assessment Area (Province of Québec) is a winter

- peaking NPCC subregion that covers 595,391 square miles with a population of eight million. Québec is one of the four NERC Interconnections in North America, with ties to Ontario, New York, New Engla nd, and the Maritimes, consisting either of HV dc ties or radial generation or load to and from neighboring systems. 

### Summary of Methods and Assumptions Assessment Area Footprint Reference Margin Level Reference Margin Levels are drawn from the Québec Area 2013 Interim Review of Resource Adequacy, which was approved by NPCC’s Reliability Coordinating Committee in December 2013

. Load Forecast Method Coincident; normal weather (50/50)
Peak Season
Winter Planning Considerations for Wind Resources
On

- peak contribution is approximately 30 percent of the total Planning Considerations for Solar Resources N/A Footprint Changes N/A


### Peak Season Demand, Resources
, and Reserve Margins

Demand (MW) 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 Total Internal Demand 38,316 38,612 38,847 39,168 39,567 40,218 40,558 40,862 41,120 41,373 Demand Response 1,708 1,852 1,902 1,952 2,002 2,202 2,252 2,252 2,252 2,252 Net Internal Demand 36,608 36,760 36,945 37,216 37,565 38,016 38,306 38,610 38,868 39,121 Resources (MW) 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 Anticipated 41,257 41,628 42,421 43,602 43,637 44,028 44,051 44,086 44,121 44,121 Prospective 41,257 41,628 42,421 43,602 43,637 44,028 44,051 44,086 44,121 44,121 Adjusted

- Potential 41,257 41,628 42,421 43,602 43,637 44,028 44,051 44,086 44,121 44,121 Reserve Margins (%) 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 Anticipated 12.70% 13.24% 14.82% 17.16% 16.16% 15.81% 15.00% 14.18% 13.51% 12.78% Prospective 12.70% 13.24% 14.82% 17.16% 16.16% 15.81% 15.00% 14.18% 13.51% 12.78% Adjusted

- Potential 12.70% 13.24% 14.82% 17.16% 16.16% 15.81% 15.00% 14.18% 13.51% 12.78% Reference Margin Level 11.60% 12.10% 12.10% 12.10% 12.10% 12.10% 12.10% 12.10% 12.10% 12.10% Excess/Shortfall (MW) 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 Anticipated 476 384 968 1,845 1,489 1,374 1,071 765 511 226 Prospective 476 384 968 1,845 1,489 1,374 1,071 765 511 226 Adjusted

- Potential 476 384 968 1,845 1,489 1,374 1,071 765 511 226 

### Peak Season Reserve Margins Peak Season Projected Generation Mix (Cumulative Change)

10% 11% 12% 13% 14% 15% 16% 17% 18%

2015 2016 2017 2018 2019 2020 2021 2022 2023 2024

Anticipated Prospective Adjusted-Potential Reference Margin Level 0.0 0.5 1.0 1.5 2.0 2.5 3.0

2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 Gigawatts

Hydro Natural Gas Renewables

### NPCC

- Québec

NERC | 2014 Long

- Term Reliability Assessment | November 201 4
69 Demand, Resources, and Planning Reserve Margins The Reference Margin Levels are drawn from the Québec Area 2013 Interim Review of Resource Adequacy 95 

### and var y between 10 and 12 percent. The A nticipated Reserve Margin varies between 12.8 and 17.2 perc ent, remaining above the Reference Margin Level for all seasons and years during the assessment period.

The Québec Area demand forecast has increased compared to the 2013LTRA report, mainly due to industrial sector growth

. The demand forecast average annual growth is 0.9 percent during the 10

- year perio d, similar to the 1.0 percent forecast in
the 2013LTRA

.

E nergy efficiency and c onservation programs are integrated in the demand forecasts and account for 1,550 MW for the 2015

– 2016 winter peak. These programs are implemented throughout the year by Hydro

- Q uébec Distribution (HQD) and by the provincial government, through its Ministry of Natural Resources. E nergy efficiency will continue to grow during the entire assessment period.

Demand forecasts also take into account the load shaving that result s from th e residential dual

- energy space

- heating program. The impact of this program on peak load demand is estimated to be around 650 MW during the assessment period

Demand Response ( DR ) programs in the Québec Area are specifically designed for peak load reduction during winter operating periods and are mostly interruptible demand programs (for large industrial customers), totaling 1,458 MW for the

2015

– 2016 winter period. DR is usually used in situations when load is expected to reach high levels

, or when resources are not expected to be sufficient to meet load during peak periods. DR remains relatively stable during the assessment period,
with a maximum of 2,252 MW reached during 2021

– 2022 winter season

.
The Qué bec A rea is currently developing new D R programs , including Direct Control Load Management (DCLM)

, which could provide an additional 300 MW of DR by 2021

– 2022. T otal on

- peak DSM (including energy efficiency and conservation programs) for the 2024

– 2025 winter period is projected to be approximately 5,250 MW.

A total of 1,560 MW of new hydro generation is expected to be in service by 2021. Additional updates to existing hydro generation will add an additional 400 MW of capacity during the assessment period. With regard to other renewable resources (biomass and wind), a total of 1,900 MW is expected to be in service by 2021. At this time, all projects are expect ed
to be on time and there are no cancellations or deferments.

Biomass a nd wind resources are owned by I ndependent Power Producer s (IPPs). These IPPs have signed contractual agreements with Hydro

- Québec. Therefore, for biomass resources, maximum capacity and expected on

- peak capacity are equal to contractual capacity, representing almost 100 percent of nameplate capacity. For wind r esources, capacity contribution at peak is estimated at 30 percent of contractual capacity, representing 970 MW and 1,220 MW

, respectively

, for the 2015

– 2016 and 2024

– 2025 winter periods. Maximum wind capacity is set equal to contractual capacity, which

ge nerally equals nameplate capacity. For summer peak period calculations, the expected on

- peak wind capacity is set to zero as wind resources are derated by 100 percent. BTMG is negligible and is embedded in the load forecast.

Expected t ransfer (capacity) pu rchases are planned by Hydro

- Québec Distribution as needed to meet the Québec internal demand. These purchases are set at 1,100 MW throughout the assessment period and may be supplied by resources located in Québec or in neighboring markets. In this regard , Hydro

- Québec Distribution has designated the Massena

– Châteauguay (1,000 MW) and Dennison

– Langlois (100 MW) interconnections’ transfer capacity to meet its resource requirements during winter peak periods. These purchases are not backed by Firm long

- term contracts. However, on a yearly basis, Hydro

- Québec Distribution proceeds with short

- term capacity purchases of Unforced Capacity (UCAP) as needed in order to meet its capacity requirements for the upcoming winter . The Québec Area does not rely on any emer gency capacity imports to meet its
Reference Margin Level. The Québec Area will support Firm capacity sales totaling 974 MW to New England and Ontario

95 Québec Area 2013 Interim Review of Resource Adequacy , approved by NPCC’s Reliability Coordinating Committee on December 3, 2013.

### NPCC

- Québec

NERC | 2014 Long

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70 (Cornwall) during the 2015

– 2016 winter peak period . This capacity is backed by Firm contracts for bo th generation and
transmission and declines to 145 MW in 2020.

Transmission Outlook and System Enhancements TransÉnergie’s system consists of an extensive 735 kV network underlain with 315 kV, 230 kV , 120 kV

, and 69 kV subsystems totaling 20,886 line miles ( 33,613 km ) . The system uses telecommunications and advanced protection and control applications to ensure its reliability and improve its performance. This will continue into the future. The system is planned according to NPCC and NERC Planning Standards

, but with additional criteria that (1) consider system topology and substation characteristics particular to TransÉnergie’s system ( c omplementary contingencies) and (2) address voltage sensitivity to load variation and interconnection ramping.

Romaine Riv er Hydro Complex Integration Construction of the first phase of transmission for the Romaine River Hydro Complex project is presently underway. T he t otal capacity will be 1,550 MW. The g enerating s tations will be integrated on a 735 kV infrastructure initially operated at 315 kV.
Romaine

- 2 (640 MW) and Romaine

- 1 (270 MW) will be integrated between 2014 and 2016 at Arnaud 735/315 /161 kV substation. One 315/161 kV, 500 MVA transformer is required at Arnaud for this project. Romaine

- 3 (395 MW) and Romaine

4 (245 MW) will be integrated between 2017 and 2020 at Montagnais 735/315 kV substation.

The m ain system upgrades for this project require construction in 2014 of a new 735 kV switching station to be named Aux
Outardes . It will be located between the existing Micoua and Manicouagan t ransformer substations. Two 735 kV lines will be
redirected into the new station

, and one new 3 mile (5 km) 735 kV line w ill be built between Aux Outardes and Micoua.

Bout

- de

- l’Île 735 kV Section In 2013, TransÉnergie added a new 735 kV section at Bout

- de

- l’Île substation located at the east end of Montréal Island. The

Boucherville

– Duvernay line (Line 7009) has been looped into this substation

, and the first of two ±300 MV ar Static V ar Compensators (SVC) has been added to the 735 kV section.

The second SVC will be added in 2014, as well as two 735/315 kV 1,650

- MVA transformers banks. This new 735 kV source will allow redistribution of load around the Greater Montréal area and will accommodate load growth in the eastern part of Montréal. This project will enable future major modifications to the Montréal area regional sub

- system. Many of the present

1 20 kV distribution substations will be rebuilt into 315 kV substations

, and the Montréal regional network will be converted

to 315 kV

.
Chamouchouane

– Montréal 735 kV Line Planning studies have shown the need to reinforce the transmission system with a new 735 kV line in the near future. The
line will extend from the Chamouchouane substation on the eastern James Bay subsystem to a substation in Montréal (255
miles (410 km) ). It will reduce transfers on other parallel lines on the 735 kV Southern Interface, thus optimizing operation flexibility and reducing losses.

Planning, permitting

, and construction delays are such that the line is scheduled with an on

- line date of 2018

– 2019 winter peak period. Public information meetings have begun on this project. The f inal line route has not completely been determined
yet
, and authorization processes are ongoing.

The Northern Pass Transmission Project This project to increase transfer capability betwe en Québec and New England by 1,2 00 MW is currently under study. It
involves construction of a ±300 kV dc transmission line about 75 km (47 miles) long from Des Cantons 735/230 kV substation
to the Canada

– U nited States border. This line will be extended into the United States to a substation to be built in Franklin,

New Ha mpshire.

The project in Québec also includes the construction of two 600 MW converters at Des Cantons and a 300 kV dc switchyard. The planned in

- service date has been re

- evaluated to winter 2018

– 2019.

### NPCC

- Québec

NERC | 2014 Long

- Term Reliability Assessment | November 201 4

71 The Champlain

- Hudson Power Express Project This project to increase transfer capability between Québec and New York by 1,000 MW is currently under study

. 96 

### The project
involves the construction of a ±320 kV dc underground transmission line about 50 km (31 miles) long from the Hertel 735/315
kV substation just south of Montréal to the Canada

– U nited States border. This line will be extended underground and underwater (Lake Champlain and Hudson River) to Astoria station in New York City. The project in Québec also includes the
construction of one 1,000 MW converter at Hertel. The planned in

- service date is fall 2017.

Other regional substation and line projects are in the planning or permitting stages. There are about a dozen regional transmission projects in the Montréal and Québec City areas and another dozen in other areas with in

- service dates from

201 4 to 2020, consisting mostly of 315/25 kV and 230/25 kV distribution substations to replace 120 kV and 69 kV
infrastructures.
Long

- Term Reliability Issues Given the importance of hydroelectric resources within the Québec Area, an energy criterion has been developed to assess energy reliability. The criterion states that sufficient resources should be available to go through sequences of two or four consecutive years of low water inflows totaling 64 TWh and 98 TWh

, respectively

, with a 2 percent probability of occurrence. These assessments are presented three times a year to the Régie de l'énergie du Québec (Québec Energy Board). Normal hydro conditions are projected during the assessment period

, and reservoir levels are expected to be sufficient to meet both peak demands and daily energy demand.

However, w hile technical developments in recent years have contributed to creating a more reliable system, sustainable system reliability may be challenged by several issues. For example

, w ind generation integration has not significantly impacted day

- to

- day operation of the system, and the actual level of wind generation does not require particular operating procedures. However, with the increasing amount of wind o n the system, the re is a potential for impact s on system management . Accordingly, the following issues are currently under study:

 W ind genera tion variability on system load and interconnection ramping

 F requency and vo ltage regulation

 I ncr ease of start

- ups/shutdowns of hydroelectric units due to load following coupled with wind variability

 Efficiency l osses in generating units and /or reduction of low

- load operation flexibility due to the low inertia response of wind generation coupled with must

- run hydroelectric generation

In addition to these issues

, there are occasions during recent summers when several 735 kV lines in the southern part of the system became heavily loaded due to the hot temperatures in southern Québec. Although this is a new issue for the Québec Area, it is expected to occur again with increased air conditioning load s and growing exports to other summer

- peaking systems. More recently, s tudies have been performed and the rmal limits have been optimized with other mitigating measures

to address the potential for future line overloads following a contingency during periods of hot temp erature s

.

96 Federal Register Notice

– October 1, 2014.

### NERC | 2014 Long

- Term Reliability Assessment | November 201 4
72 

# PJM

Assessment Area Overview PJM Interconnection is a regional transmission organization (RTO) that coordinates the movement of wholesale electricity in a ll or parts of Delaware, Illinois, Indiana, Kentucky, Maryland, Michigan, Ne w Jersey, North Carolina, Ohio, Pennsylvania, Tennessee, Virginia, West Virginia
, and the District of Columbia. PJM companies serve 61 million people and cover 243,417 square miles. PJM is a Balancing Author ity, Planning Coordinator, Transmission Planner, Resource Planner, Interchange Authority, Transmission Operator, Transmission Serv ice Provider

, and Reliability Coordinator.


### Summary of Methods and Assumptions Assessment Area Footprint Reference Margin Level The PJM RTO Reserve Requirement is applied as the Reference Margin Level for this assessment. Load Forecast Method Coincident; normal weather (50/50)
Peak Season
Summer Planning Considerations for Wind Resources
On

- peak contribution of 13 percent of installed capacity Planning Considerations for Solar Resources 38 percent of nameplate capacity Footprint Changes The East Kentucky Power Cooperative (EKPC), which integrated into the PJM RTO on June 1, 2013, is now part of PJM’s load and generation data.


### Peak Season Demand, Resources
, and Reserve Margins
Demand (MW) 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 Total Internal Demand 160,259 162,470 164,195 165,479 166,900 168,593 170,027 171,217 172,542 173,729 Demand Response 14,812 12,402 12,402 12,402 12,402 12,402 12,402 12,402 12,402 12,402 Net Internal Demand 145,447 150,068 151,793 153,077 154,498 156,191 157,625 158,815 160,140 161,327 Resources (MW) 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 Anticipated 183,163 192,850 190,497 185,904 185,928 185,928 185,928 185,928 185,928 187,498 Prospective 186,787 197,909 195,818 195,962 194,767 194,768 194,768 194,768 194,768 196,338 Adjusted

- Potential 186,787 197,909 195,818 195,962 194,767 194,768 194,768 194,768 194,768 196,338 Reserve Margins (%) 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 Anticipated 25.93% 28.51% 25.50% 21.44% 20.34% 19.04% 17.96% 17.07% 16.10% 16.22% Prospective 28.42% 31.88% 29.00% 28.02% 26.06% 24.70% 23.56% 22.64% 21.62% 21.70% Adjusted

- Potential 28.42% 31.88% 29.00% 28.02% 26.06% 24.70% 23.56% 22.64% 21.62% 21.70% Reference Margin Level 15.70% 15.70% 15.70% 15.70% 15.70% 15.70% 15.70% 15.70% 15.70% 15.70% Excess/Shortfall (MW) 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 Anticipated 14,880 19,221 14,873 8,793 7,173 5,215 3,555 2,179 646 842 Prospective 18,504 24,280 20,193 18,852 16,013 14,055 12,395 11,019 9,486 9,682 Adjusted

- Potential 18,504 24,280 20,193 18,852 16,013 14,055 12,395 11,019 9,486 9,682 

### Peak Season Reserve Margins Peak Season Projected Generation Mix (Cumulative Change)

10% 15% 20% 25% 30% 35%

2015 2016 2017 2018 2019 2020 2021 2022 2023 2024

Anticipated Prospective Adjusted-Potential Reference Margin Level -4 -2 0 2 4 6 8 10 12

2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 Gigawatts

Natural Gas Nuclear Renewables

Hydro Coal Petroleum

### PJM

NERC | 2014 Long

- Term Reliability Assessment | November 201 4
73 Demand, Resources, and Planning Reserve Margins The PJM RTO Reserve Requirement as calculated by PJM is 15.7 percent for the 2015

– 2016 planning period

, which runs from

J une 1, 2015
, through May 31, 2016. The PJM RTO Reserve Requirement is 0.5 percentage points lower this year compared
to the 2014

– 2015 value due to the retirement of coal units with high forced outage rates. The 15.7 percent PJM RTO Reserve Requirement (app lied as the Reference Margin Level) is applicable for the entire assessment period. PJM RTO will have an adequate Anticipated Reserve Margin though the entire assessment period. The Prospective and Adjusted

- Potential Reserve Margins are also above the Refe rence Margin Level for the entire assessment period.

Use of more granular historical economic data and the addition of another year of load experience to the load forecasting model resulted in generally lower (approximately 0.5 percent) peak and energy fo recasts this year compared to the forecast done last year. Annualized 10

- year growth rates for individual zones range from 0.4 percent (Rockland Electric) to 1.8 percent (Dominion Virginia Power).

PJM has filed tariff changes with FERC that will require mo re robust reporting of the DR operational capability in real time for Curtailment Service Providers. PJM does not have reliability concerns with DR expansion

, but the additional operational information will help avoid the dispatch of DR that may not be nec essary to meet the need of the emergency conditions. PJM has created three different DR products to address the issue of availability: Limited DR (10 days for 6 hours per day during the summer peak period), Extended Summer DR (unlimited days during the sum mer peak period for 10 hours per day) and Annual DR (unlimited days for 10 hours per day any time of the year)

. These programs require necessary amount s of annual capacity to fulfill the PJM reliability requirements

. The PJM reported transactions are the aggregate of generator

- specific transactions. These transactions include the Firm reservation rights for the generation and Firm transmission rights to transfer the power across the PJM border. Long

- term
Firm capacity transfer contacts exist

, but they are not accepted into PJM installed capacity until the PJM Reliability Planning Model (RPM) three

- year planning window. The impact of transactions is minimal in PJM since they only amount to about two percent of the forecast peak load. PJM previously forecast transactions using the Firm capacity contracts but has recently decided to only show capacity transactions through a three

- year planning window to coordinate with neighboring entities.

E nergy e fficiency programs included in the 2015

– 2017 load forecast are approved for use in the RPM and total 685 MW for
the 2015 summer . This value increases to 918 MW in 2016 and remains constant through the end of the assessment period.

Transmission Outlook and System Enhancements Northeast New Jersey Transmission Enhanceme nt PJM 2013 RTEP process results have validated the need for a solution to identified short circuit duty violations at the Essex

, Kearney
, and New Jersey Transit Meadowlands (NJT Meadows) 230 kV substations. Notably, 2013 short circuit analyses
revealed th at the two 345 kV tie lines connecting PSE&G’s Hudson substation to ConEd’s Farragut substation contribute to short circuit duties at Hudson, Kearney

, and Essex. As a result, the Hudson/ Farragut HVdc alternative was originally recommended in large part for its ability to block this fault current pass

- through to the northern New Jersey PSE&G system. However, circuit breaker short circuit over duties were not the only NERC criteria violations identified. Generator deliverability tests identified thermal violations on lines in northern New Jersey that have required reconsideration of PJM’s initial HVDC solution proposal and the subsequent development o f a more comprehensive solution.

In collaboration with PSE&G planning staff, PJM evaluated two northern New Jersey double

- circuit upgrade solutions: one at 230 kV and one at 345 kV. Additionally, the double

- circuit 345 kV solution also solves the identifie d thermal criteria violations in northern New Jersey.

In parallel with the analytical work performed to compare the double

- circuit 345 kV and HVDC alternatives, PJM also retained an independent engineering consultant to review each project, validate cost e stimates
, and assess the project constructability. From that perspective, the consultant’s findings did not identify any “fatal flaws” that would prevent eith er project from being implemented. Based on the performance of each of the alternatives, the cost of each

, and the findings of

### PJM

NERC | 2014 Long

- Term Reliability Assessment | November 201 4

74 the independent consultant regarding constructability, PJM recommended the double

- circuit 345 kV alternative to address
the short circuit and thermal problems in northern New Jersey. The PJM Board approved the recommendation in December

2013. 97



### Need for Byron

– Wayne Confirmed
PJM reviewed

— as it does every year

— transmission plans developed in earlier years. By doing so

, PJM can determine whether, as a result of changing assumptions, previously approved transmission upgrades are still required. And, if so, PJM

can determine whether they are still required in the year originally identified, as with the Byron

– Wayne 345 kV t ransmission
l ine (Grand Prairie Gateway). As part of its 2012 RTEP process, PJM conducted its annual simultaneous feasibility analysis to assess the transmission system’s ability to accommodate all transmission rights for the next 10

- year period. PJM’s 2 012 transmission rights analysis identified 16 thermal constraints in ComEd and nine PJM

- MISO m arket

- to

- m arket constraints. RTEP analysis in 2013 also identified a number of thermal constraints similar to those identified in 2012, confirming the nee d
for t he Byron

– Wayne 345 kV in 2017.

Artificial Island Order 1000 Proposal Window PJM sought proposals from April 29, 2013

, through June 28, 2013

, to improve operational performance on Bulk Electric System (BES) facilities in the southern New Jersey Artificial Island area, the site of PSE&G’s Salem 1 and 2 and Hope Creek 1 nuclear generating plants. Under certain system conditions, this area’s complexity has presented PJM and PSE&G System Operator s with limited s olutions

, potentially forcing them in some circumstances to remove an Artificial Island unit from service in order to stay within operating limitations to maintain reliability. PJM specified that RTEP proposals improve limi ted stability margins , minimum Ar tificial Island MVar output requirements
, and previously identified high

- voltage reliability
issues.

Seven different sponsors submitted 26 separate proposals. Proposals reflected a diverse range of technologies at both 500
kV and 230 kV

— new transformation, substations and associated equipment, additional circuit breakers, system reconfiguration, dynamic reactive devices, dynamic series compensation and DC technology

— spanning a range of project risk exposure levels and lead

- time requirements. In parallel wit h analytical evaluation, PJM enlisted engineering consultant s in
2013 to evaluate project proposal constructability in terms of physical characteristics, feasibility, cost, design commonalities

, and other challenges associate d with line and river crossings

. Additionally, the consultants examined the ability to expand or reconfigure existing substations and determine required transmission and generation outages.

Market Efficiency Order 1000 Proposal Window During this window, PJM sought proposals to identify transmission projects to relieve internal PJM transmission congestion. The scope of the request encompassed the top 25 congestion events observed in 2013 Market Efficiency Analysis for study years 2017, 2020, and 2023 and for which no reliability

- based RT EP upgrades have been already identified. Proposed enhancements must provide a benefit/cost ratio of at least 1.25 and must not introduce any reliability criteria violations. S ix different sponsors submitted 17 separate proposals during the window to meet the stated requirements. Analysis identified three proposals for further evaluation. All three addressed, either in whole or part, congestion on the Hunterstown 230/115 kV transformer. PJM expects to make a recommendation to the Board in 2014 that comprise s adding a second Hunterstown 230/115 kV transformer and reconduc toring the existing Hunterstown

– Oxford 115 kV line.

AEP/Dominion Transmission Rebuilds PJM’s RTEP includes 500 kV transmission line rebuild projects over the next eight years by AEP and Dominion as shown below

. The towers of all six lines, built in the 1960s, are nearing the end of their useful lives and will soon require rebuild. Now the
Clove rdale

– Lexington and Lexington

– Dooms 500 kV line rebuilds have been identified to solve PJM b aseline reliability
criteria violations.

97 2013 Regional Transmission Expansion Plan Report (see page 7).

### PJM

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75 AEP/Dominion Line Rebuilds

Line Rebuild Driver In

- Service Month, Year
Cloverdale

– Lexington 500 kV NERC Category C3 “ N

- 1

- 1 ” Criteria December 2016 Lexington

– Dooms 500 kV Dominion Reliability Criteria Violation June 2016

Dooms

– Cunningham 500 kV Dominion Supplemental Project December 2018 Cunningham

– Elmont 500 kV Dominion Supplemental Project May 2018

Mt. Storm

– Valley 500 kV Dominion Supplemental Project June 2021 Valley

– Dooms 500 kV Dominion Supplemental Project December 2021



### Cloverdale

– Lexington 500 kV Line RTEP analysis conducted in 2013 identified reliability criteria violations under PJM light

- load criteria tests on the AEP portion
of the Cloverdale

– Lexington 500 kV line. In October 2013, the Board approved PJM’s upgrade recommendation to rebuild the AEP portion of the Cloverdale

– Lexington 500 kV line, including replacement of 11 tower structures. This follows December 2011 PJM Board approval to re conductor the Dominion portion of the Cloverdale

– Lexington 500 kV circuit to solve NERC criteria Category C violations. Jointly owned by Dominion and AEP, coordinated plans are underway to rebuild and/or reconductor their respective portions of the 44 mi le line in order to increase the operational limit of that line to meet PJM’s minimum summer emergency requirement of 3,992 MVA.

### PJM

NERC | 2014 Long

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76 Dooms

– Lexington 500 kV Line PJM 2012 RTEP analysis identified a Dominion reliability criteria violation in 2016 in which the Dooms

– Lexington line would
be overloaded for several N

- 1

- 1 contingencies. In May 2012, the PJM Board approved the recommended solution to reconductor the line, increasing its rating from 2,913 MVA to 4,340 MVA. The project is expected to be completed by
December 2016.

State RPS laws require entities that serve load to do so using various eligible renewable resources including wind, solar

, and other technologies. States in the PJM footprint have a variety of RPS definitions and targets. Overall, approximately 38 GW of renewable energy would be required from renewable resources to meet aggregate RPS targets by 2028 in states in which PJM operates. And, while NERC Reliability Standard violations remain PJM’s principal basis under the RTEP Protocol f or justifying transmission expansion, construction of major transmission infrastructure will likely be necessary to support the achievement of RPS public policy goals.

Wind

- and solar

- powered facilities

— now an expanding percentage of interconnection reques ts

— constitute a growing driver of regional transmission expansion. The emergence of state RPS standards has prompted PJM to further examine the impacts
of extensive penetration of wind reso urces, which could have implications on reliability and market effi ciency. During 2013, both internal scenario studies and interregional studies examined the penetration of renewable

- powered generation to meet state RPS targets. Those studies confirm that significant build

- out of transmission will be needed for PJM to del iver the aggregate wind generation required to meet states’ RPS goals

.

BTMG is not counted as PJM capacity and has no effect on the PJM Reserve Margin. During a hot

- weather event in September 2013, 98 

### PJM called on some BTMG to operate to alleviate specific transmission

- related operating concerns. PJM will establish and document an approach for representing known BTMG in PJM ’s e nergy m anagement s ystems and the related operating
criteria for d ispatchers . Working with the s tate s and the Transmission Owners, PJM will better incorporate BTMG into emergency operations.
Long

- Term Reliability Issues Light

- load system conditions, as low as 30 percent of summer peak for some transmission owners , present system dispatchers
with operational performance issues. Generation dispatch under such conditions differs markedly from that under peak

- load conditions, particularly for units powered by renewable sources such as wind. PJM has begun to experience thermal overloads and high

- voltag e events driven by low demand dispatch patterns and the capacitive effects of lightly loaded transmission
lines. From a 15

- year planning perspective, these light

- load concerns gave rise to the approval of new reliability criteria analysis procedures in 201 0, first implemented and benchmarked in 2011, for both baseline analysis and queued interconnection request studies. Light

- load reliability analysis ensures that the system transmission is capable of delivering generating capacity under such conditions.

As part of its 2013 cycle of RTEP studies, PJM identified six light

- load criteria violations, five of which represented normal and

N

- 1 thermal overloads. The most significant of these is a project to rebuild the AEP portion of the Cloverdale

– Lexington 500 kV line in Virginia that will require $40 million

, expected by June 2015. The remaining four thermal criteria violations will require 138 kV upgrades in AEP and ComEd ; they are much lower in scope and estimated cost and are expected by June of
2017. The si xth criteria violation

, voltage in nature

, requires an upgrade to the 765 kV Cloverdale substation, also in Virginia, and construction of a new 500 kV bus with an estimated project cost of $85 million projected to be in service by the end of

2016.

PJM plan ning staff has initiated efforts with operations staff and individual TOs to examine real

- time high

- voltage events across the RTO. Based on additive power flow studies completed in 2013, PJM collaborated with TOs to develop solutions approved by the PJM Bo ard that ultimately included shunt reactors, SVCs, r eactor breakers, and m odifications to, and

98 PJM Report: Technical Analysis of Operational Events and Market Impacts

.

### PJM

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77 optimization of existing facilities, generator voltage schedule adjustments, transformer tap settings

, and switched shunt capacitor settings.

Planning study results that were reviewed with TOs to determine optimal reactor sizes and locations across PJM to maximize
their effectiven ess at mitigating high voltages were subsequently confirmed by additional power flow analysis . In

- service
dates for t hese projects begin in June 2015.

### NERC | 2014 Long

- Term Reliability Assessment | November 201 4
78 

# SERC

Assessment Area Overview

SERC is a summer

- peaking A ssessment Area that covers approximately 308,900 square miles and serves a population estimated at 39.4 million. SERC is divided into three Assessment Areas: SERC

- E, SERC

- N, and SERC

- SE. The SERC Region includes 11 BAs: Alcoa Power Generating, Inc.

– Yadkin Division (Yadkin), Associated Ele ctric Cooperative, Inc. (AECI) , Duke Energy Carolinas and Duke Energy Progress (Duke), Electric Energy, Inc. (EEI), LG&E and KU Ser vices Company (as agent for Louisville Gas and Electric (LG&E) and Kentucky Utilities (KU) ) , PowerSouth Energy Cooperative (PowerSouth), South Carolina Electric & Gas Company (SCE&G), South Carolina Public Service Authority (Santee Cooper, SCPSA), Southern Company Services, Inc. (Southern), and Tennessee Valley Authority (TVA).


### Summary of Methods and Assumptions Assessment Area Footprints (SERC

- E, SERC

- N, SERC

- SE) Reference Margin Level Entities within the SERC footprint adhere to state

- set targets that vary throughout the footprint . F or this assessment, NERC applies a 15 percent Reference Margin Level for all SERC subregions. Load Forecast Method
Non c oincident; normal weather (50/50)
Peak Season
Summer Planning Considerations for Wind Resources As reported by individual generator owners Planning Considerations for Solar Resources As reported by individual generator owners Footprint Changes East Kentucky Power Cooperative (EKPC) joined PJM on June 1,
2013
, and is no longer rep orted in SERC’s Assessment Area. Additionally, entities within the SERC

- W Assessment Area joined
MISO in December 2013.



### SERC

- East : Peak Season Demand, Resources
, and Reserve Margins
Demand (MW) 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 Total Internal Demand 44,086 44,768 45,398 45,992 46,669 47,289 47,928 48,579 49,251 49,943 Demand Response 1,757 1,819 1,869 1,913 1,934 1,952 1,970 1,986 2,003 2,006 Net Internal Demand 42,329 42,949 43,529 44,079 44,735 45,337 45,958 46,593 47,248 47,937 Resources (MW) 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 Anticipated 50,475 50,396 50,339 51,440 52,363 52,226 52,243 52,666 52,682 52,702 Prospective 53,773 53,694 53,637 54,738 55,661 55,524 55,541 55,964 55,980 56,000 Adjusted

- Potential 53,773 53,694 53,712 54,826 55,918 55,781 55,882 56,429 56,445 56,577 Reserve Margins (%) 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 Anticipated 19.24% 17.34% 15.64% 16.70% 17.05% 15.19% 13.68% 13.03% 11.50% 9.94% Prospective 27.04% 25.02% 23.22% 24.18% 24.42% 22.47% 20.85% 20.11% 18.48% 16.82% Adjusted

- Potential 27.04% 25.02% 23.39% 24.38% 25.00% 23.04% 21.59% 21.11% 19.47% 18.02% Reference Margin Level 15.00% 15.00% 15.00% 15.00% 15.00% 15.00% 15.00% 15.00% 15.00% 15.00% Excess/Shortfall (MW) 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 Anticipated 1,796 1,004 280 749 918 88 (609) (916) (1,653) (2,426) Prospective 5,095 4,303 3,579 4,047 4,216 3,387 2,689 2,382 1,645 873 Adjusted

- Potential 5,095 4,303 3,654 4,135 4,472 3,643 3,030 2,847 2,110 1,450 

### Peak Season Reserve Margins Peak Season Projected Generation Mix (Cumulative Change)

0% 5% 10% 15% 20% 25% 30%

2015 2016 2017 2018 2019 2020 2021 2022 2023 2024

Anticipated Prospective Adjusted-Potential Reference Margin Level -1.0 0.0 1.0 2.0 3.0

2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 Gigawatts

Natural Gas Nuclear Coal

### SERC

NERC | 2014 Long

- Term Reliability Assessment | November 201 4
79 SERC

- North : Peak Season Demand, Resources
, and Reserve Margi ns Demand (MW) 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 Total Internal Demand 42,100 42,571 42,917 43,298 43,677 44,018 44,470 44,908 45,359 45,797 Demand Response 2,117 2,224 2,314 2,437 2,555 2,670 2,786 2,908 3,022 3,105 Net Internal Demand 39,983 40,347 40,603 40,861 41,122 41,348 41,684 42,000 42,337 42,692 Resources (MW) 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 Anticipated 50,585 49,326 49,342 49,212 49,471 49,471 49,471 49,471 48,547 48,547 Prospective 52,478 52,926 52,942 52,812 53,071 53,071 53,071 53,071 53,078 53,078 Adjusted

- Potential 52,478 52,926 52,942 52,878 53,137 53,137 53,137 53,137 53,222 53,222 Reserve Margins (%) 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 Anticipated 26.52% 22.25% 21.52% 20.44% 20.30% 19.65% 18.68% 17.79% 14.67% 13.71% Prospective 31.25% 31.18% 30.39% 29.25% 29.06% 28.35% 27.32% 26.36% 25.37% 24.33% Adjusted

- Potential 31.25% 31.18% 30.39% 29.41% 29.22% 28.51% 27.48% 26.52% 25.71% 24.67% Reference Margin Level 15.00% 15.00% 15.00% 15.00% 15.00% 15.00% 15.00% 15.00% 15.00% 15.00% Excess/Shortfall (MW) 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 Anticipated 4,604 2,927 2,648 2,222 2,181 1,921 1,534 1,171 (141) (549) Prospective 6,498 6,527 6,249 5,822 5,781 5,521 5,135 4,771 4,391 3,983 Adjusted

- Potential 6,498 6,527 6,249 5,888 5,847 5,587 5,200 4,837 4,534 4,126 

### Peak Season Reserve Margins Peak Season Projected Resource Mix (Cumulative Change)

SERC

- Southeast: Peak Season Demand, Resources
, and Reserve Margins
Demand (MW) 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 Total Internal Demand 47,116 48,137 48,931 49,427 50,124 51,135 51,563 52,292 53,046 53,844 Demand Response 2,166 2,190 2,213 2,206 2,215 2,224 2,229 2,233 2,251 2,252 Net Internal Demand 44,950 45,947 46,718 47,221 47,909 48,911 49,334 50,059 50,795 51,592 Resources (MW) 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 Anticipated 60,035 60,461 60,522 62,109 62,978 63,124 63,120 62,943 62,927 63,068 Prospective 60,331 60,757 60,818 62,405 63,274 63,420 63,416 63,239 63,223 63,364 Adjusted

- Potential 60,333 60,852 61,084 62,671 63,540 63,686 63,682 63,505 63,489 63,630 Reserve Margins (%) 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 Anticipated 33.56% 31.59% 29.55% 31.53% 31.45% 29.06% 27.94% 25.74% 23.88% 22.24% Prospective 34.22% 32.23% 30.18% 32.15% 32.07% 29.66% 28.54% 26.33% 24.47% 22.82% Adjusted

- Potential 34.22% 32.44% 30.75% 32.72% 32.63% 30.21% 29.08% 26.86% 24.99% 23.33% Reference Margin Level 15.00% 15.00% 15.00% 15.00% 15.00% 15.00% 15.00% 15.00% 15.00% 15.00% Excess/Shortfall (MW) 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 Anticipated 8,343 7,622 6,796 7,805 7,883 6,877 6,386 5,375 4,512 3,737 Prospective 8,639 7,917 7,092 8,101 8,179 7,173 6,681 5,671 4,808 4,033 Adjusted

- Potential 8,641 8,013 7,358 8,367 8,445 7,439 6,947 5,937 5,074 4,299 

### Peak Season Reserve Margins Peak Season Projected Resource Mix (Cumulative Change) 0% 5% 10% 15% 20% 25% 30% 35%

2015 2016 2017 2018 2019 2020 2021 2022 2023 2024

Anticipated Prospective Adjusted-Potential Reference Margin Level

10% 15% 20% 25% 30% 35%

2015 2016 2017 2018 2019 2020 2021 2022 2023 2024

Anticipated Prospective Adjusted-Potential Reference Margin Level -6 -5 -4 -3 -2 -1 0 1 2 3

2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 Gigawatts

Natural Gas Nuclear Coal Hydro

0.0 0.5 1.0 1.5 2.0 2.5 3.0

2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 Gigawatts

Coal Natural Gas Nuclear Renewables

### SERC

NERC | 2014 Long

- Term Reliability Assessment | November 201 4
80 Demand, Resources, and Planning Reserve Margins
The P rospective R eserve M argins for all three SERC Assessment Areas remain above the Reference Margin Level of 15 percent throughout the assessment period. The Anticipated Reserve Margin for the SERC

- E and SERC

- N subregions fall s below the Reference Margin Level in 2021 and 2023, respectively. The SERC demand forecast is expected to be lower than previous
forecasts due to a number of factors, including lower economic growth.

DR, as well as energy efficiency and c onservation programs
, are projected to grow through 2020, after which some of these programs will plateau.

The SERC Assessment Area expects a number of changes to generation capabilities during the assessment period, includin g additions of the following: (1) Lee Steam Combined

- Cycle power station, (2) V.C. Summers, (3) Watts Bar, and (4) Vogtle
Nuclear Stations. Planned r etirements in SERC’s subregions are not expected to have any adverse impact on reliability;
however

, SERC e ntities continue to plan their system to address reliability needs to interconnect, deliver, and retire generating units.

There is a very limited amount of BTMG
, DG , and variable energy resources (VERs) in SERC. The small existing amount of

BTMG curr ently contracted ( mostly solar ) is incorporated into the load forecast. The impacts from this generation have been incorporated into the long

- term plan as a reduction in the forecast demand

, and it is expected that these types of resources will further reduce pe ak demand through impacts to the daily load shape. Due to the relative capacity and the operational
nature of DG and VERs , expected on

- peak capacity values in SERC are predictable and consistent.

All capacity transfers that are counted as capacity are backed by specific generation designations or transmission service
reservations. SERC entities coordinate with their first

- tier neighbors to ensure sufficient transmission interface capability, and to assess if potential impacts to capacity transfers exist due to any neighbors’ planned system modifications.

Specific areas within the SERC Assessment Area are known to have large penetrations of induction motor loads

, which are
one of the main drivers behind Fault

- Induced Delayed Voltage Recovery (FIDVR). SERC entities perform annual studies to decrease potential FIDVR exposure by ensuring sufficient dynamic reactive sources are available in the potential exposure

area. With current load forecast, SERC entities do not anticipate that any FIDVR

- affected areas wi ll impact system reliability during the long

- term assessment period.

Transmission Outlook and System Enhancements
Several t ransmission projects are in progress to improve reliability within the SERC Assessment Area. To name a few, Southeast Voltage Project involves building a new 115 kV line from Bonifay to Chipley substations, and Gulf Coast Loop Project involves building a new 115 kV line from Southport to Bayou George substation to Gaskin Switching station. In addition, to enhance current carrying capabi lity across the VACAR

- Southern interface, a 230 kV circuit will be built between Purrysburg
and McIntosh substations.

During the assessment period, Southern Company Inc. is planning to add two 100 MVar SVCs, and TVA is adding a [

- 150/+300 MVar] SVC with an additional 250 MVar of caps controlled by this SVC to enhance voltage profile. Southern Company is developing and deploying smart grid technologies, including installing smart meters and an integrated distribution management system. These systems should p rovide better monitoring and enable quicker restoration in the event of storms or other damage. Southern also has several PMUs or the equivalent installed on the system and will add many more in the
future. Several other SERC entities are deploying PMU, sm art grid, and system awareness technology during the coming years. Duke Energy is working to inte grate PMU information into the e nergy m anagement s ystem s. TVA is continuing with a program to install PMUs and GIC detectors across the Tennessee Valley.
Long

- Term Reliability Issues Shoulder (off

- peak) periods, with lower network loading, reduced hydro generation, and significant resource maintenance outages, introduce a variety of challenges. During certain shoulder months and winter midday low

- load perio ds, when solar

### SERC

NERC | 2014 Long

- Term Reliability Assessment | November 201 4
81 output is negatively correlated with load, operational concerns arise during these minimal load conditions. SERC entities are currently studying the impacts of significant levels of potential solar penetration.

Retirements of generation in t he SERC Assessment Area, some of which are caused by environmental regulations, are mitigated by gas

- fired resources, purchase power agreements, and diversification of generation mix. SERC entities are optimistic that they can complete all necessary retrof its and improvements without sacrificing system reliability.

Entergy
, with its six utility operating companies, and South Mississippi Electric Power Association, which previously reported data and information primarily in the SERC

- W Assessment Area , integr ated into MISO in December 2013. This shift added approximately 15,500 miles of transmission, 50,000 MW of generation capacity, and 35,000 MW of peak load to the MISO footprint. MISO now coordinates all RTO activities in the newly combined area, consisting of all or parts of 15 states.

Within this expanded MISO Balancing Area, the contract path capacity is limited to 1000 MW between the original MISO Central/North system and the new MISO South system

. MISO market dispatches that result in power transfers be tween the MISO Central/North and MISO South portions of its system can result in significant unscheduled power flows through neighboring systems Tennessee Valley Authority (TVA), Associated Electric Cooperative, Inc. (AECI), Louisville Gas & Electric Compa ny and Kentucky Utilities Company (LG&E/KU), Power South, Southwest Power Pool, Inc. (SPP), and Southern Company. These neighboring systems have raised concerns regarding these power flows, especially if the market dispatches
exceed the 2
, 000 MW transfer l imit from MISO South to MISO Central/North

. At this time, no long

- term joint planning studies have been conducted to determine long

- term transmission system impacts. MISO and the neighboring systems have begun to establish long

- term arrangements for both r eliable operations and coordinated planning. In addition, SERC regional studies groups are assessing and refining SERC modeling and reliability assessments to better reflect the expanded MISO BA in regional long

- term planning and operational planning asses sments.

Prior to MISO starting merged market operations in December 2013, MISO and the neighboring systems developed an Operations Reliability Coordination Agreement (ORCA) to address reliability concerns during an initial operating transition period. The ORCA is set to expire in April 2015

. MISO and their neighboring systems continue to explore other reliability processes to mitigate any adverse impacts on system reliability in the operational time frame.

Another potential emerging issue is that very long HVDC lines are being considered by independent transmission developers in economic projects such as shipping wind to the southeast. The capacity of a single line is typically greater than the larg est single

- contingency

- generation loss in a system. The cap acity of two poles will probably be larger than that of the largest multi

unit generating plant. On very long lines, the risk of losing both poles may be appreciable, and that risk plus the high powe r level could impact reliability. An emerging issue may b e the ability of present study criteria to adequately model the impact of these lines on a system.

Also, due to the current tax subsidies in North Carolina, a large number of solar qualifying facilities have been requested in
the transmission queue. These projects create uncertainty in planning for various reasons

, including the uncertainty of the projects actuall y coming to fruition (i.e., the c ompanies being able to rely on the capacity and/or generation from these facilities) and the interm ittent nature of solar.

### NERC | 2014 Long

- Term Reliability Assessment | November 201 4
82 

# SPP

Assessment Area Overview Southwest Power Pool (SPP) is a NERC Regional Entity (RE) that covers 370,000 square miles and encompasses all or parts of Ar kansas, Kansas, Louisiana, Mississippi, Missouri, New Mexico, Oklahoma, and Te xas , serving approximately 6.2 million households. The SPP Winter Assessment is reported based on the Planning Coordinator footprint. Along with the SPP RE footprint, it also includes Nebraska Public Power District, Omaha Public Power District, and Lincoln Electric System, which are registered with the Midwest Reliability Organization Regional Entity. The SPP Assessment Area footprint has 48,368 miles of transmission lines, 915 generating plants, and 6,408 t ransmission

class substations.


### Summary of Methods and Assumptions Assessment Area Footprint Reference Margin Level SPP established target of 13.6 percent Load Forecast Method Coincident; normal weather (50/50)
Peak Season
Summer Planning Considerations for Wind Resources
On

- peak contribution of 3 percent of nameplate capacity Planning Considerations for Solar Resources
On

- peak contribution of 10 percent of nameplate capacity Footprint Changes Western Area Power Administration (WAPA) Upper Great Plains,
Basin Electric, and Heartland Consumers Power District (Heartland ) are expected to join the SPP Assessment Area and be fully integrated into SPP on October 1, 2015. The integration of these entities, primarily located in North and South Dakota, will add approxim ately 5,000 MW of load and 9,500 miles of transmission to the SPP RTO footprint.


### Peak Season Demand, Resources
, and Reserve Margins
Demand (MW) 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 Total Internal Demand 49,710 50,993 51,700 52,267 52,849 53,454 53,999 54,817 55,438 56,991 Demand Response 1,284 1,306 1,316 1,323 1,326 1,327 1,326 1,326 1,326 1,327 Net Internal Demand 48,426 49,687 50,384 50,944 51,523 52,128 52,673 53,491 54,112 55,663 Resources (MW) 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 Anticipated 65,942 64,539 65,247 65,258 65,394 64,945 64,949 64,693 64,579 63,634 Prospective 66,241 64,888 65,804 65,815 65,951 65,502 65,507 65,250 65,136 64,299 Adjusted

- Potential 66,426 65,174 66,133 66,230 66,366 65,929 65,938 65,706 65,648 64,877 Reserve Margins (%) 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 Anticipated 36.17% 29.89% 29.50% 28.10% 26.92% 24.59% 23.31% 20.94% 19.34% 14.32% Prospective 36.79% 30.59% 30.60% 29.19% 28.00% 25.66% 24.37% 21.98% 20.37% 15.51% Adjusted

- Potential 37.17% 31.17% 31.26% 30.01% 28.81% 26.48% 25.18% 22.83% 21.32% 16.55% Reference Margin Level 13.60% 13.60% 13.60% 13.60% 13.60% 13.60% 13.60% 13.60% 13.60% 13.60% Excess/Shortfall (MW) 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 Anticipated 10,930 8,094 8,011 7,386 6,864 5,728 5,113 3,927 3,108 400 Prospective 11,228 8,443 8,568 7,943 7,421 6,285 5,670 4,484 3,665 1,066 Adjusted

- Potential 11,414 8,729 8,897 8,358 7,836 6,712 6,101 4,940 4,177 1,644 

### Peak Season Reserve Margins Peak Season Projected Generation Mix (Cumulative Change)

10% 15% 20% 25% 30% 35% 40%

2015 2016 2017 2018 2019 2020 2021 2022 2023 2024

Anticipated Prospective Adjusted-Potential Reference Margin Level -2.5 -2.0 -1.5 -1.0 -0.5 0.0 0.5 1.0 1.5

2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 Gigawatts

Natural Gas Nuclear Renewables

Hydro Coal Petroleum

### SPP

NERC | 2014 Long

- Term Reliability Assessment | November 201 4
83 Demand, Resources, and Planning Reserve Margins
Based on the 2014LTRA reference case , the Reserve Margins for the SPP Assessment Area will remain above the Reference Margin Level of 13.6 percent for all seasons and years of the assessment period

. The SPP Assessment Area is showing approximately an 8 percent dec rease in Total Internal Demand compared with the
2013LTRA. This decrease is primarily due to several SPP members moving to the MISO footprint. Other drivers include a mild
2013 summer and higher projected impacts from both energy efficiency and DR program s . Several SPP members have also reported load forecast s with decreased annual growth percentages , impacted by changing economic conditions during the past several years. The SPP Assessment Area continues to forecast modest average annual growth of approximately 3.5 percent in energy efficiency and DR programs through 2024. DR programs in t he SPP Assessment Area are voluntary and are primarily targeted for summer peak load reduction.

The High

- Priority Incremental Load Study indicated that the SPP Assessment Area is experiencing an increase in oil and gas drilling, causing substantial load gr owth in northern Oklahoma, southwestern Kansas, Texas, and New Mexico. This localized growth has created the need for new transmission projects and generation in specific areas. SPP is working with its stakeholders to ensure that reliability needs are bein g addressed.

Approximately 3,150 MW of nameplate capacity are expected to be retired during the assessment period (with the inclusion of retirements in 2014) . With approximately 7,500 MW of new nameplate capacity projected to come into service during the

a ssessment period, there are no operational or planning concerns at this time.

The expected on

- peak capacity values for variable generation are determined by hi storical performance guidelines

. 99 

### The net capability for wind is determined on a monthly basis using an eight

- step process for establishing net capability. Wind facilities that have been in commercial operation for three years or less must include the most recently available engineering d ata. If MW values are not available, estimates may be used based on wind data that is correlated with reference towers outside a

50

- mile radius of the facility’s location. Such estimates must be approved by the SPP RTO Generation Working Group (GWG).

The n et capability for solar resou rces is determined on a monthly basis using the same eight

- step process as that of wind resources. Solar data that is correlated beyond 200 miles of the reference measuring device must also receive SPP GWG approval

. 100



### The SPP GW G’s proposed revisions to section 12.1.5.3.g of SPP Criteria (SPP Criteria) , the Accreditation for Renewable Resource (Wind and Solar)

, were passed by the SPP Board of Directors at the July Meeting. The GWG’s intention was to ensure the accreditation proce ss meets the SPP Assessment Area’s needs while not being overly cumbersome to the resource

owners

. The SPP GWG performed an analysis using operations data from the SPP footprint and sample data from 17 wind resources (varying wind turbine type, geographical location, and age of the facility). The GWG then applied this data to the existing SPP Criteria, proposed criteria language, and compared the results to a more rigorous ELCC study. The proposed language will now include the 3 percent top load hours, which will occur 60 percent of the time . It allows SPP members to apply more stringent criteria if desi red by their area.

The GWG made these changes after extensive discussions and researching the operations data. The new proposed SPP Criteria covers accreditation for both wind and solar renewable resources, has a less

- stringent confidence interval, and has been benchmarked against solar operational data for the resources and detailed ELCC studies.

The SPP Assessment Area continually evaluates operational procedures to determine if efficiency and reliability improvements can be made. Because of the level of wind resources in the footprint, SPP has included some variable resources

99 Section 12

. 100 Facilities that have been in commercial operation for four years or more must include a minimum of four years or up to 1 0 years of the most recent commercial operation data available, whichever is greater. Metered hourly net power output (MWh) data may be used. After thre e years of commercial operations, if the Load

- Serving Member does not perform or provide the net capabil ity calculations to SPP, then the net capability for the resource will be 0 MW. Net capability calculations are to be updated at least once every three years.

### SPP

NERC | 2014 Long

- Term Reliability Assessment | November 201 4
84 into its automatic, security

- constrained dispatch calculations. This allows the SPP Assessment Area to better manage local congestion issues for which wind is the primary impacting r esource. SPP is now able to better manage system reliability by using quicker and more effective control actions. New wind installations are required to be dispatchable.

SPP Assessment Area members, along with some members of the SERC Region, jointly participate in a Reserve Sharing Group (RSG)

. M embers of the RSG receive contingency reserve assistance from each other and do not require support from generation resources outside the RSG . The SPP Operating Reliability Working Group sets the Minimum Daily C ontingency Reserve Requirement for the RSG

. Long

- Term Reliability Issues Drought and flooding conditions are the most impactful weather events within the SPP Assessment Area. Current drought conditions in the western portion of the SPP Assessment Area ar e projected to continue into the assessment period. Most of the SPP Assessment Area’s heavily water

- dependent resources are located in the eastern half of the footprint, which has also experienced drought conditions in the past. SPP planning staff is study ing the potential impacts of drought conditions in the SPP Assessment Area. The 2015 Integrated Transmission Planning (ITP) 10

- year study includes a future scenario with a decreased baseload capacity in which units susceptib le to drought conditions are de r ated or retired.

SPP’s Operational Planning group performs biannual system planning studies to capture the potential reliability impacts of retirements and retrofits of generation. Any identified reliability concerns are passed to the SPP RTO long

- term pla nning group. This study process consists of the creation of weekly snapshots through the next four years that consider load forecas ts
and known transmission and generation outages. Local issues are reported to the impacted SPP Transmission Operators.
Since the SPP Assessment Area has sufficient capacity, the impacts of long

- term maintenance outages are expected to be more economic in nature. Current studies indicate there will be adequate time to perform generator retrofits necessary to comply with current known environmental regulations. These currently planned retrofits are expected to impact generation supply economics more than the ability to reliably serve load. SPP continues to monitor and evaluate the impacts of generator retirements resulting from en vironmental regulations in its planning studies. SPP’s 2015 ITP 10

- year study included assumptions about generator retirements that were expected at the time the models were built for that study. After the ITP

10

- year study began, the EPA issued its propos ed Clean Power Plan on June 2, 2014. SPP is concerned about the reliability implications of additional generator retirements that could result from new regulations included in that proposed rule. Any additional retirements resulting from these new regulati ons have not yet been included in SPP’s planning processes and will need to be thoroughly studied to ensure that any resulting reliability impacts are properly addressed

. SPP, along with other joint parties in the Region and MISO, are currently managing r eliability concerns from MISO’s recent operational changes under the provisions of the Operations Reliability Coordination Agreement (ORCA). Under Phase 1 of the ORCA, unless otherwise agreed to by the joint parties, MISO transfers between MISO Central/Nor th and MISO South are limited. The joint parties and MISO continue to work to develop, test, and implement subsequent phases of the ORCA that would allow this reliability limit to potentially increase under certain conditions.

SPP will not impede reliabil ity by limiting the exchange of energy between MISO Central/North and MISO South except as required for SPP to maintain its own reliable operations, even if it requires MISO to exceed their current 1,000 MW path. While SPP and MISO are currently in litigat ion over the terms and conditions of the compensation due to SPP when MISO may exceed its 1,000 MW path, the two assessment areas continue to work together to ensure reliable operation.

SPP and MISO have also recently agreed to improvements to the method for accounting for the flow impacts of import and export transactions used in the congestion management process. SPP and MISO continue to discuss additional improvements to ensure all sources of flows are properly accounted for within the Reg ion. SPP is currently working with MISO to implement
a market

- to

- market congestion management process that will serve to enhance reliability by more efficiently responding to congestion that occurs on flowgates impacted by both RTOs. It is expected that th e market

- to

- market process will be in place by March 1, 2015.

### NERC | 2014 Long

- Term Reliability Assessment | November 201 4
85 

# TRE

- ERCOT

Assessment Area Overview The Electric Reliability Council of Texas (ERCOT) is the Independent System Operator (ISO) for the ERCOT Interconnection and is located entirely in the state o f Texas ; it operates as a single BA. ERCOT is a summer

- peaking Region that covers approximately 200,000 square miles, connects 40,530 miles of transmission lines and 566 generation units, and serves 23 million customers. The Texas Relia bility Entity (Texas RE) is responsible for the RE functions described in the Energy Policy Act of 2005 for the ERCOT Region.


### Summary of Methods and Assumptions Assessment Area Footprint Reference Margin Level ERCOT established Reference Margin of 13.75 percent Load Forecast Method Coincident; normal weather ( 50/50 ) Peak Season
Summer Planning Considerations for Wind Resources Effective Load

- Carrying Capability (ELCC) of 8.7 percent Planning Considerations for Solar Resources ERCOT incorporates 100 percent capacity contribution Footprint Changes N/A


### Peak Season Demand, Resources
, and Reserve Margins 101
Demand (MW) 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 Total Internal Demand 69,057 70,014 70,871 71,806 72,859 73,784 74,710 75,631 76,550 77,471 Demand Response 1,917 1,917 1,917 1,917 1,917 1,917 1,917 1,917 1,917 1,917 Net Internal Demand 67,140 68,097 68,954 69,889 70,942 71,867 72,793 73,714 74,634 75,554 Resources (MW) 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 Anticipated 76,751 77,673 78,478 79,360 78,760 78,760 79,060 79,060 79,060 79,060 Prospective 79,574 81,486 82,991 84,361 84,972 85,343 86,014 86,384 86,755 87,126 Adjusted

- Potential 79,574 81,588 83,172 84,580 85,251 85,621 86,292 86,663 87,033 87,404 Reserve Margins (%) 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 Anticipated 14.31% 14.06% 13.81% 13.55% 11.02% 9.59% 8.61% 7.25% 5.93% 4.64% Prospective 18.52% 19.66% 20.36% 20.71% 19.78% 18.75% 18.16% 17.19% 16.24% 15.32% Adjusted

- Potential 18.52% 19.81% 20.62% 21.02% 20.17% 19.14% 18.54% 17.57% 16.61% 15.68% Reference Margin Level 13.75% 13.75% 13.75% 13.75% 13.75% 13.75% 13.75% 13.75% 13.75% 13.75% Excess/Shortfall (MW) 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 Anticipated 379 212 43 (139) (1,937) (2,989) (3,742) (4,790) (5,836) (6,882) Prospective 3,203 4,025 4,556 4,863 4,275 3,594 3,212 2,534 1,859 1,183 Adjusted

- Potential 3,203 4,127 4,737 5,081 4,554 3,873 3,490 2,813 2,138 1,462 

### Peak Season Reserve Margins Projected Peak Season Generation Mix (Cumulative Charge)

101 T he Frontera power plant (three natural

- gas

- fired units totaling 524 MW) is assumed to be avail able to serve peak load for all years in the 2014LTRA Reference Case . However, the plant’s o wner recently announced plans to begin exporting 170 MW of capacity to Mexico as soon as 2015, and the entire 524 MW in 2016 with the completion of certain transmis sion projects. ERCOT and the Frontera Facility’s owners have agreed on the reliability safeguards for ensuring the plant will be available if needed in an emergency and have filed those conditions with the U.S. Department o f Energy as part of the plant’s e xport authorization. 0% 3% 6% 9% 12% 15% 18% 21%

2015 2016 2017 2018 2019 2020 2021 2022 2023 2024

Anticipated Prospective Adjusted-Potential Reference Margin Level -1.0 -0.5 0.0 0.5 1.0 1.5 2.0 2.5 3.0 3.5

2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 Gigawatts

Natural Gas Renewables Coal

### TRE

- ERCOT

NERC | 2014 Long

- Term Reliability Assessment | November 201 4
86 Demand, Resources, and Planning Reserve Margins New gas

- fired resources totaling 2,112 MW (summer rating) being added during the summer of 2014 help elevate the Anticipated Reserve Margin to 14.3 percent in 2015. The Anticipated Reserve Margin is expected to remain above the

R eference M argin L evel of 13.75 percent until 2018, while the Prospective Reserve Margin remain s above the R eference

M argin L evel for the entire assessm ent period. The expected addition of the Panda Temple II combined

- cycle plant (717 MW summer rating) in August 2015 and the FGE Texas 1 combined

- cycle plant (703 MW summer rating) in July 2016 largely offset forecast load growth through 2017. After 2017, t he re is insufficient Anticipated r esource s to keep pace with load growth.

The generation market in ERCOT is unregulated, with generators making resource decisions based on market dynamics as well as administratively applied scarcity pricing mechanisms intended to incentivize the provision of adequate operating

reserves. In an en vironment of continuing economic and load growth, tight reserve margins are expected beyond three to four years in the future

, given the lead time for proposed resources to proceed through ERCOT’s interconnection request process and meet ERCOT’s requiremen ts for inclusion in resource adequacy assessments. If there is a risk of insufficient capacity to meet resource adequacy requirements in the short

- term future, the Public Utility Commission of Texas (PUCT)

, with input from ERCOT and market participants, wo uld be expected to investigate and implement measures to address potential capacity shortages.

As a temporary measure to address system reliability problems stemming from generators that are planned to be taken out of service by their owners, ERCOT can ent er into Reliability Must

- Run (RMR) contracts with those generators or others that would otherwise not operate.

The ERCOT peak demand forecast (Total Internal Demand) for summer 2015 is 69,057 MW and is expected to occur in early August. The 2015 peak deman d forecast is 1.4 percent higher than the forecast for 2014, driven in part by the continued expansion of oil and gas production in the Permian Basin and Eagle Ford Shale areas, but is 3.4 percent lower than the 2015
forecast reported in the 2013 LTRA . This decrease is due to major changes to ERCOT’s load forecast method that better
capture the relationship between economic indicators and electric dem and, as well as the impacts of energy efficiency and
other efforts by industrial and commercial sector custom ers to reduce electricity usage during periods of high demand.

With respect to the TRE

- ERCOT Region’s reliance on DSM programs, significant growth has recently occurred for ERCOT’s Emergency Response Service (ERS). This program, which includes 10

- and 30

- minute Demand R esponse resources as well as distributed generation service, is designed to be deployed in the late stages of a grid emergency, prior to shedding involunt ary Firm load. Procurement of ERS summer peak t ime p eriod procurement grew from 422 MW in 2013 to 626 MW in 2014, nearly a 50 percent increase. The ERS program remains capped at $50 million per year , in accordance with an existing rule implemented by the PUCT. This spending cap is expected to cause the growth rate to flatten during t he next few years. Load

Resourc e capacity providing ancillary s ervices is also expected to increase due to new rules enabling Controllable Load
Resources to bid into the real

- time market for the provision of non

- spin ning reserves. ERCOT also account s for t he peak load impacts of Demand R esponse programs managed by several Transmission Service Providers (TSPs). These TSPs have individual contractual programs with loads that can respond to instructions to reduce total energy usage. These programs are expected to remain flat for the foreseeable future at approximately 240 MW.

A significant amount of generating capacity has been added sinc e 2013
, and more is expected in 2014 and 2015. These additions have entered commercial operations and are listed below:

 Sandy Creek 1 (coal

- fired, 970 MW)

 WA Parish addition (gas

- fired, 74 MW)

 Acacia Solar (solar PV , 10 MW)

 OCI Alamo 1 (solar PV , 39 MW)

 Blue Summit Wind 5 and 6 (135 MW)

 Los Vientos Wind I and II (402 MW)

### TRE

- ERCOT

NERC | 2014 Long

- Term Reliability Assessment | November 201 4
87 ERCOT forecasts 2,801 MW of new summer

- rated capacity t o be available for the 2015 summer peak load. Out of this total, 2,144 MW are gas

- fired, 489 MW are wind, and 168 MW are solar PV facilities.

Natural

- g as

- fired additions in 2014 include: two new combined

- cycle gas

- fired power plants (Panda Sherman and Panda Temple 1) with a combined summer capacity rating of 1,437 MW; the 510 MW Ferguson combined

- cycle plant, which replaced the original 354 MW unit ( reti red in September 2013 ) ; a 165 MW (summer rating) expansion of the Deer Park Energy Center; and two small plant upgrade projects for a total of 32 MW. New renewable resources available for the 2015 summer peak load include three solar PV plants: White Camp Solar 1 (100 MW nameplate), Pecos Barilla Solar (30 MW nameplate), OCI Alamo 4 (38 MW nameplate), and 30 wind plants for a total of 5,625 MW nameplate capacity . The wind plant sizes range
from 68 to 600 MW.

Regarding units planned for retirement or suspen ded operations, NRG recently announced that its five S.R. Bertron gas

- fired units (combined summer rating of 727 MW) will not return from mothball status for summer operation. Additionally, the J.T. Deely coal plant (840 MW) is expected to enter indefinite mothball status at the end of 2018.

The TRE

- ERCOT Region is a separate i nterconnection with only asynchronous ties to SPP and Mexico’s Comisión Federal de Electricidad (CFE). As such, ERCOT does not share reserves with other Regions. There are two asynchr onous ties between ERCOT and SPP with a total of 820 MW of transfer capability, and four asynchronous ties between ERCOT and Mexico with a total of 436 MW of transfer capability ( once the Sharyland Utilities expansion project (150 MW) was expected to be

co mpleted in 2014 ) . For the assessment period, ERCOT assumes that all of the generating capacity of the Tenaska Kiamichi Generating Station (1,246 MW summer rating and 1,330 MW winter rating) located in Pittsburgh County, Oklahoma, is
dedicated to the ERCOT market. Also included in the assessment is 463 MW of import capability determined by analyzing
historical flows across the dc ties during peak hours.

Transmission Outlook and System Enhancements With respect to transmission planning, the recently updated E RCOT future transmission projects list includes the addition or upgrade of 1,602 miles of 138 kV and 345 kV transmission circuits, 7,472 MVA of 345/138 kV autotransformer capacity, and 5,538 MVar of reactive capability projects that are planned in ERCOT be tween 2014 and 2023. Sixty

- four projects were identified as being necessary to meet the system needs in West Texas through 2017. A new Houston Import Project consisting
of a 130

- mile 345 kV double circuit line from Limestone to Gibbons Creek to Zenith is p lanned to be in service before the summer peak of 2018. Other significant projects include a new 345 kV import line and an upgrade of the two existing 345 kV import lines to support load growth in the Lower Rio Grande Valley (LRGV), a new Cross Valley 345 kV , 106

- mile line to support load growth in Brownsville and other cities along the eastern side of the LRGV, and multiple transmission upgrades in the Odessa North area ( w est Texas). ERCOT has received requests to study two projects that would add asynchr onous tie capacity between ERCOT and the Eastern Interconnection. The Southern Cross project would connect on the eastern portion of the ERCOT system and add up to 3,000 MW of tie capacity by 2016. The Tres Amigas project would add 1,500 MW of tie capacity in the Texas Panhandle by 2017. These new lines will provide access to several Regions adjacent to ERCOT. The additional dc tie capacity is being proposed for commercial purposes.
Long

- Term Reliability Issues New and proposed f ederal environmental regulat ions continue to be a concern from a long

- term resource adequacy perspective. ERCOT is monitoring th e impacts of multiple proposed f ederal environmental regulations, including CSAPR and MATS. The U.S. Supreme Court affirmed the U.S. Environmental Protectio n Agency’s authority to promulgate the CSAPR on April 29, 2014. ERCOT is analyzing the implications of the Supreme Court ’ s decision and wi ll work closely with TRE

- ERCOT

R egion generators to assess the impact of CSAPR implementation on resource adequacy and grid reliability once updated proposed regulations are issued. For MATS, survey data collected from ERCOT’s solid fuel generators in mid

- 2013 indicated that while unit retirements are not an immediate concern, a number of generators that are not cu rrently in compliance with
the s tandard, representing about 32 percent of all the capacity covered by the survey, did not have their compliance strategies finalized. As with CSAPR, ERCOT will continue to closely monitor MATS compliance efforts and assess the risk for unit

### TRE

- ERCOT

NERC | 2014 Long

- Term Reliability Assessment | November 201 4
88 retirements. Other proposed regulations being monitored by ERCOT include the Cooling Water Intake Structures Rule (under Section 316(b) of the Clean Water Act), the Coal Ash Disposal Rule ( under the Resource Conservation and Recovery Act (RCRA) )

, the Steam Electric Effluent Limitation Guidelines, and CO 2 

### emission regulations from existing plants. All of these proposed regulations are not expected to have a material impact on reliability for the next two to three years if enacted. However, their co mbined impact on coal plant economic viability further out in the assessment period may become an issue if significant retired coal plant capacity is the resulting outcome.

From an operational perspective, the combination of a large seasonal variance in s ystem load and the high penetration of wind generation has increased challenges for voltage support and frequency control, particularly during large ramp events. Nevertheless, ERCOT has been successfully operating the system with high wind penetration over the past few years. To address these new challenges, ERCOT has proposed the phased implementation of a redesigned a ncillary s ervices framework consisting of new and revised unbundled ancillary services products intended to take advantage of evolving syste m needs and capabilities of existing resources, as well as emerging technologies such as battery storage. New ancillary services products include Synchro nous Inertial Response Service , Fast Frequency Response Service, and Prim ary Frequency Response
Service . To implement the ancillary services framework, a Future Ancillary Services Team (FAST) has been established to facilitate stakeholder input and address substantive implementation issues prior to ERCOT’s development of proposed

m arket p rotocol revisions later in 2014

. 102



### Finally, multi

- year droughts in Texas continue to represent a reliability concern. Much of central Texas and the panhandle are currently under “exceptional” or “extreme” drought conditions, although reservoir levels are not expected to dro p below power plant physical input limits during the remainder of 2014. If drought conditions extend into 2015, there is the risk of multiple resources being taken off

- line due to the lack of cooling water. If operational restrictions extend over peak load periods, resource adequacy then becomes an issue. Depending on the location of the drought, local area transmission congestion can result and must be relieved

. If an extended drought occurs, additional transmission may need to be added to support an affec ted area

. The entire system would be impacted by additional pressure placed on other resources

. The specific location with the outage may have congestion problems to overcome in addition to voltage support issues.

102 Concept Paper: Future Ancillary Services in ERCOT

.

### NERC | 2014 Long

- Term Reliability Assessment | November 201 4
89 

# WECC

Assessment Area Overview The Western Electricity Coordinating Council (WECC) is responsible for coordinating and promoting BES reliability in the Western Interconnection. WECC’s 329 members, which include 38 BAs, represent a wide spectrum of organizations with an interest in the BES

. Serving an area of nearly 1.8 million square miles and approximately 8 2 million people, it is geographically the largest and most diverse of the NERC Region s . WECC’s service territory includes the Canadian provinces of Alberta and British Columbia, the northern portion of Baja California in Mexico, and all or portions of the 14 western states between

. The WECC Assessment Area is divided into four subregions: 103 Northwes t Power Pool (NWPP), Rocky Mountain Reserve Group (RMRG), Southwest Reserve Sharing Group (SRSG), and California/Mexico (CA/MX). These subregional divisions are structured around Reserve Sharing groups that have similar annual demand patterns as well as
si milar operating practices.


### Summary of Methods and Assumptions Assessment Area Footprints (CA / MX, NWPP, RMRG, SRSG ) Reference Margin Level Determined by WECC’s building block method for each subregion. Load Forecast Method Coincident ( Western Interconnection) ; normal weather (50/50)
Peak Season
Summer: CA/MX; RMRG; SRSG Winter: NWPP Planning Considerations for Wind Resources Modeling, primarily based on historic data Planning Considerations for Solar Resources Modeling, primarily based on historic data Footprint Changes In early 2014, the Nevada Power and Sierra Pacific BAs were consolidated into one BA (Nevada Power) and incorporated in to the NWPP subregion, and the old Nevada Power BA was removed from the SRSG subregion

.

103 Northwest Power Pool

, Rocky Mountain Reserve Group

, Southwest Reserve Sharing Group

.

### WECC

NERC | 2014 Long

- Term Reliability Assessment | November 201 4
90 WECC

- CA/MX : Peak Season Demand, Resources
, and Reserve Margins
Demand (MW) 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 Total Internal Demand 57,606 56,767 57,004 57,245 57,580 58,003 58,257 58,542 58,742 58,930 Demand Response 1,996 2,019 2,055 2,081 2,132 2,184 2,236 2,287 2,339 2,389 Net Internal Demand 55,610 54,748 54,949 55,164 55,448 55,819 56,021 56,255 56,403 56,541 Resources (MW) 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 Anticipated 64,102 63,531 63,670 63,675 64,014 64,383 64,576 64,289 64,470 64,106 Prospective 64,126 64,327 65,205 65,951 67,431 68,441 68,744 68,462 68,646 68,285 Adjusted

- Potential 64,126 64,327 65,225 65,998 67,478 68,541 68,847 68,565 68,748 68,387 Reserve Margins (%) 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 Anticipated 15.27% 16.04% 15.87% 15.43% 15.45% 15.34% 15.27% 14.28% 14.30% 13.38% Prospective 15.31% 17.50% 18.66% 19.55% 21.61% 22.61% 22.71% 21.70% 21.71% 20.77% Adjusted

- Potential 15.31% 17.50% 18.70% 19.64% 21.70% 22.79% 22.89% 21.88% 21.89% 20.95% Reference Margin Level 15.02% 15.02% 15.02% 15.02% 15.02% 15.02% 15.02% 15.02% 15.02% 15.02%
E xcess/Shortfall (MW) 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 Anticipated 139 559 467 226 238 180 141 (415) (405) (927) Prospective 164 1,356 2,003 2,501 3,655 4,238 4,309 3,758 3,771 3,251 Adjusted

- Potential 164 1,356 2,022 2,549 3,702 4,338 4,412 3,860 3,874 3,354 

### Peak Season Reserve Margins Peak Season Projected Generation Mix (Cumulative Change)

WECC

- NWPP: Peak Season Demand, Resources and Reserve Margins
Demand (MW) 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 Total Internal Demand 70,778 71,786 73,217 74,430 75,490 76,482 77,422 78,320 79,189 79,912 Demand Response 325 325 325 325 325 325 325 325 325 325 Net Internal Demand 70,453 71,461 72,892 74,105 75,165 76,157 77,097 77,995 78,864 79,587 Resources (MW) 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 Anticipated 82,304 83,592 85,197 86,683 87,910 88,927 90,037 91,090 92,109 93,002 Prospective 83,217 85,075 86,863 88,422 89,660 90,677 91,819 92,898 93,918 93,002 Adjusted

- Potential 83,246 85,191 87,045 88,789 90,106 91,215 92,357 93,437 94,519 93,661 Reserve Margins (%) 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 Anticipated 16.82% 16.98% 16.88% 16.97% 16.96% 16.77% 16.78% 16.79% 16.79% 16.86% Prospective 18.12% 19.05% 19.17% 19.32% 19.28% 19.07% 19.09% 19.11% 19.09% 16.86% Adjusted

- Potential 18.16% 19.21% 19.42% 19.81% 19.88% 19.77% 19.79% 19.80% 19.85% 17.68% Reference Margin Level 11.00% 11.00% 11.00% 11.00% 11.00% 11.00% 11.00% 11.00% 11.00% 11.00% Excess/Shortfall (MW) 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 Anticipated 4,101 4,270 4,287 4,426 4,478 4,393 4,460 4,516 4,570 4,660 Prospective 5,014 5,753 5,953 6,166 6,227 6,143 6,241 6,324 6,379 4,660 Adjusted

- Potential 5,043 5,870 6,135 6,532 6,673 6,681 6,780 6,863 6,980 5,319 

### Peak Season Reserve Margins Peak Season Projected Generation Mix (Cumulative Change) 10% 12% 14% 16% 18% 20% 22% 24%

2015 2016 2017 2018 2019 2020 2021 2022 2023 2024

Anticipated Prospective Adjusted-Potential Reference Margin Level

10% 12% 14% 16% 18% 20%

2015 2016 2017 2018 2019 2020 2021 2022 2023 2024

Anticipated Prospective Adjusted-Potential Reference Margin Level -1 0 1 2 3 4 5

2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 Gigawatts

Natural Gas Renewables

Petroleum Pumped Storage

-1.5 -1.0 -0.5 0.0 0.5 1.0 1.5 2.0 2.5

2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 Gigawatts

Natural Gas Coal Hydro Renewables

### WECC

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- Term Reliability Assessment | November 201 4
91 WECC

- RMRG: Peak Season Demand, Resources
, and Reserve Margins
Demand (MW) 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 Total Internal Demand 9,899 10,100 10,239 10,410 10,558 10,709 10,843 10,901 11,046 11,249 Demand Response 557 567 576 586 592 602 611 620 627 633 Net Internal Demand 9,342 9,533 9,663 9,824 9,966 10,107 10,232 10,281 10,419 10,616 Resources (MW) 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 Anticipated 15,106 15,088 15,814 15,681 15,249 15,002 13,139 11,647 11,820 12,028 Prospective 15,106 15,089 15,856 15,723 15,292 15,045 13,182 11,690 11,863 12,070 Adjusted

- Potential 15,106 15,089 15,856 15,723 15,292 15,045 13,185 11,693 11,866 12,073 Reserve Margins (%) 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 Anticipated 41.71% 58.27% 63.65% 59.62% 53.01% 48.43% 28.41% 13.29% 13.45% 13.30% Prospective 41.71% 58.28% 64.09% 60.05% 53.44% 48.86% 28.83% 13.71% 13.86% 13.70% Adjusted

- Potential 41.71% 58.28% 64.09% 60.05% 53.44% 48.86% 28.86% 13.73% 13.88% 13.73% Reference Margin Level 13.20% 13.20% 13.20% 13.20% 13.20% 13.20% 13.20% 13.20% 13.20% 13.20% Excess/Shortfall (MW) 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 Anticipated 4,531 4,297 4,875 4,560 3,968 3,561 1,556 9 26 10 Prospective 4,531 4,297 4,918 4,603 4,010 3,604 1,599 52 68 53 Adjusted

- Potential 4,531 4,297 4,918 4,603 4,010 3,604 1,602 55 71 56 

### Peak Season Reserve Margins Peak Season Projected Generation Mix (Cumulative Change)

WECC

- SRSG : Peak Season Demand, Resources
, and Reserve Margins
Demand (MW) 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 Total Internal Demand 22,635 22,760 23,282 23,762 24,335 24,707 25,113 25,694 26,193 26,709 Demand Response 418 421 430 372 377 382 382 382 382 383 Net Internal Demand 22,217 22,339 22,852 23,390 23,958 24,325 24,731 25,312 25,811 26,326 Resources (MW) 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 Anticipated 29,289 30,904 29,958 29,992 28,991 28,469 28,459 28,895 28,843 29,536 Prospective 29,413 31,092 30,190 30,223 29,258 28,771 28,846 29,317 29,300 30,066 Adjusted

- Potential 29,473 31,208 30,320 30,405 29,443 28,979 29,098 29,598 29,609 30,448 Reserve Margins (%) 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 Anticipated 31.83% 38.35% 31.10% 28.22% 21.01% 17.03% 15.08% 14.16% 11.75% 12.19% Prospective 32.39% 39.19% 32.11% 29.21% 22.12% 18.27% 16.64% 15.82% 13.51% 14.21% Adjusted

- Potential 32.66% 39.71% 32.68% 29.99% 22.89% 19.13% 17.66% 16.93% 14.72% 15.66% Reference Margin Level 14.06% 14.06% 14.06% 14.06% 14.06% 14.06% 14.06% 14.06% 14.06% 14.06% Excess/Shortfall (MW) 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 Anticipated 3,949 5,425 3,893 3,313 1,665 724 252 24 (597) (492) Prospective 4,072 5,613 4,125 3,544 1,932 1,025 638 446 (141) 38 Adjusted

- Potential 4,133 5,729 4,255 3,726 2,116 1,234 890 727 169 420 

### Peak Season Reserve Margins Peak Season Projected Generation Mix (Cumulative Change) 0% 10% 20% 30% 40% 50% 60% 70%

2015 2016 2017 2018 2019 2020 2021 2022 2023 2024

Anticipated Prospective Adjusted-Potential Reference Margin Level

10% 15% 20% 25% 30% 35% 40% 45%

2015 2016 2017 2018 2019 2020 2021 2022 2023 2024

Anticipated Prospective Adjusted-Potential Reference Margin Level -1.0 -0.8 -0.6 -0.4 -0.2 0.0 0.2 0.4 0.6 0.8 1.0

2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 Gigawatts

Natural Gas Coal Hydro

-1.0 -0.8 -0.6 -0.4 -0.2 0.0 0.2 0.4 0.6 0.8

2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 Gigawatts

Natural Gas Coal Petroleum Renewables

### WECC

NERC | 2014 Long

- Term Reliability Assessment | November 201 4
92 Demand, Resources, and Planning Reserve Margins Throughout the 10

- year assessment period, the Reference Margin Levels ra nge between 11 and 15 percent for the four subregions. The Reference Margin Level s 104 

### for each subregion are calculated using a building block method 105 

### created by WECC’s Reliability Assessment Work Group (RAWG), 106 

### formerly Loads and Resources Subcommittee, for its annual Power Supply Assessment (PSA). 107 

### The elements of the building block margin calculation are consistent from year to year

, but the
calculations may have slight annual variances by region and subregion.

By the summer of 2024, the difference between WECC’s Prospective Resources (198,259 MW) and WECC’s Net Internal Demand (169,314 MW) is calculated as 28,945 MW (17.1 percent margin). As the expected resources exceed the Reference Margin Levels , it is reasonable to assume that only a portion of the reported resource additions will ultimately enter commercial service within the planning horizon.

As de picted in the graphic at the beginning of this section, the r eserve m argins for the WECC subregions remain above the Reference Margin Level s through 2021. Beginning in 2022, individual subregions do dr op below their Reference Margin
Levels , but the potential resource additions that have been reported exceed these possible shortages.

In the resource adequacy process, each BA is responsible for complying with the resource adequacy requirements of the state or provincial areas in which they o perate. Some BAs perform resource ade quacy studies as part of their integrated resource

p lans, which usually provide a 20‐year outlook. Other BAs perform resource adequacy studies that focus on the very short term (i.e., one to two years), but most project ions provide at least a 10‐year outlook. WECC’s PSA uses a study period of 10 years and the same subregional reserve target margins throughout the entire period.

Similar to WECC’s PSA, resources that are energy‐only or energy‐limited (e.g., the portion of wind resources that is not projected to provide generation at the time of peak) are not counted toward meeting resource adequacy in this assessment. Also, resources such as DERs or BTMG that are not monitored by the BA’s energy management systems are excl uded from the resource adequacy calculation.

Total Internal Demand for the summer, the peak season for the entire WECC Region, increased by 1.1 percent from 2012 to 2013, mostly due to warmer than normal temperatures in 2013. The Total Internal Demand for the summer season s during the next 10 years is projected to increase by 1.0 percent per year, which is a decrease from the 1.7 percent projected in the

2013LTRA ( 2014

– 2023 ) . The annual energy load is projected to increase by 1.2 percent per year for the 20 15

– 2024 time frame, which is also a decrease from the 1.5 percent projected in the 2013LTRA

.
The WECC Total Internal D emand forecast includes summer Demand R esponse that varies from 3,878 MW in 2015 to 4,226
MW in 2024. The direct control DSM capability is located mostly in the California/Mexico subregion, totaling 1,996 MW in 2015 and 2,389 MW in 2024. DSM programs in other subregions are also increasing. The most prevalent Demand R esponse programs in WECC involve air conditioner cycling as well as Interru ptible L oad programs that focus on the demand of large

water

- pumping operations and large industrial operations (e.g., mining). Currently, the most significant Demand Response development activity within WECC is taking place in California; the California I SO (CAISO) is actively engaged with stakeholders in developing viable wholesale Demand Response products with direct market participation capability. Also of note is CAISO’s

104 The NERC Reference Margin Level and all reserve margins are for planning purposes. Firm load would not be disrupted to mainta in these margins. Rather, the margins are reference points that indicate areas that have lower reserves and tighter margins. The t ighter margins are not forecasts of resource shortages. However, areas with tighter margins have a higher possibility, although not likelihood, of resource short ages associated with extreme events such as record

- setting temperature deviations.

105 Elements o f the Building Block Target are detailed in the NERC: Long

- Term Assessment

– Methods and Assumptions report.

106 All of the BAs within the Western Interconnection provided the generation data for this assessment, and WECC staff

— under the direction of the WECC
RAWG

— processed the data. The reported generation additions generally reflect extractions from generation queues.

107 WECC's Power Supply Assessments.

### WECC

NERC | 2014 Long

- Term Reliability Assessment | November 201 4
93 Demand Response product implementation that facilitates the participation of exist ing retail demand programs in the CAISO market. Further information regarding these initiatives is available on CAISO’s website. 108



### Overall Demand Response program growth has been rather static and is not expected to increase dramatically during the 10

- year planning horizon. The various DSM programs within WECC are treated as load modifiers that reduce Total Internal Demand when calculating planning margins. In some situations, these programs may be activated by Load

- Serving Entities (LSE s ) during high

- power cost periods but in general are only activated during periods in which local power supply issues arise. Generally, Demand Response programs in WECC have limitations, such as having a limited number of times they can
be activated. 109



### Distributed energy resources, including rooftop solar and BTMG , currently represent a very small portion of both the existing and planned resources. As the load served by BTMG is not included in the actual or forecast peak demands and energy loads, these resources are excluded from the resource adequacy calculation.

A few utilities attributed coal‐fired plant retirements and fuel conversions to existing air emissions regulations. Based on news media accounts and information related to western coal‐fired plant environmental regulation cost exposure, it is expected that future LTRA information will report additional retirements and fuel conversions as more plant owners establish the ir preferred approaches for addressing emission regulations. California regulations essentially specify that existing long

- term
contracts with coal

- fired plants will be allowed to run to expiration, though not be renewed. 110 

### This regulation may result in
the sale, retirement, or repowering of some power plants during the assessment period. Due to the somewhat fluid situation in California regarding retirements associated with once‐through cooling (OTC) regulations, potential associated capacity
reductions have not necessarily been reported for this year’s LTRA for all potentially affected plants. Current information regarding the California OTC is available on the California Energy Commission’s website. 111 

### It is expected that any future capacity reductions will b e offset by new plants that may or may n ot be reflected in the current c onceptual resources data.

The Anticipated R esources projected for the 2015 summer peak period total 188,221 MW and reflect the monthly shaping of variable generation and the seasonal ratings of conventional resources. The e xpected on

- peak c apacity modeling for wind resources is based on curves created using at least five years of actual hourly wind generation data. The data is averaged in to six four

- hour blocks for each day of each wee k of the year. Solar resource energy curves were created using up to five years of actual hourly solar generation data. The data is averaged into three block curves for each day of the week of the year. Hydro generation is dispatched economically, limited by expected annual energy generated during an adverse hydro year. Biomass and geothermal capabilities are based on nominal plant ratings. The individual BAs report 37,410 MW as the total gross future capacity projected to be in service by the end of this a ssessment period.

Greater wind generation has resulted in an increased fluctuation in instantaneous generation and a need for increased operating reserves to compensate for the wind‐induced fluctuations. Improved wind forecasting procedures and reduced

sc heduling intervals are methods that have only partially addressed the wind variability issue. Increased wind generation has also exacerbated high

- generation issues in the Bonneville Power Administration (BPA) area during light load and high hydroelectric g eneration conditions. BPA is working on long‐term solutions to this issue and provides current information on
its website. 112 

### Increased wind penetration is expected to worsen the operating reserve situation. Solar generation may also

108 California ISO Demand Response Initiatives.

109 NERC’s assessment process assum es that Demand Response may be shared among LSEs, BAs, and subregions. However, demand

- side management sharing is not a contractual arrangement. Consequently, reserve margins may be overstated as they do not reflect Demand Respo nse that could potentially b e unavailable to respond to external energy emergencies. Energy efficiency and conservation programs vary by location and are generally offered by the load serving entities. The reduction to demand associated with these programs is reflected in the load fo recasts supplied by the balancing authorities.

110 CEC Emission Performance Standards.

111 CEC Once

- Through Cooling.

112 BPA Wind Activities

.

### WECC

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- Term Reliability Assessment | November 201 4
94 reach a level sufficient to add to the operational issues relative to short

- term (sub

- hourly) load following. A joint NERC/California ISO report addresses this potential operational issue. 113



### WECC does not rely on imports from outside the Region when calculating peak demand reliabi lity margins. The Region also does not model exports to areas outside of WECC. However, imports may be scheduled across three back‐to‐back dc ties with
SPP and five back‐to‐back dc ties with Assessment Areas in MRO

. Inter‐subregional transfers are derived from resource allocation computer simulations that incorporate transmission constraints among various path‐constrained zones within WECC. 114 

### The WECC resource allocation model places conservative transmission limits on paths between 19 load groupings (zones ) when calculating the transfers between these areas. These load zones were developed for WECC’s PSA studies. The aggregation of PSA load zones into WECC subregions may obscure differences in adequacy or deliverability between zones within the subregion.

The resource data for the individual subregions includes transfers between subregions that either are plant‐contingent transfers or reflect projected transfers with a high probability of occurrence. Plant‐contingent transfers represent both joi nt plant own ership and plant‐specific transfers from one subregion to another. Projected transfers reflect the potential use of seasonal demand diversity between the winter‐peaking NWPP and the summer‐peaking SRSG , as well as other economy and short‐term purchases tha t may occur between subregions.

While these transactions may not be contracted, they reflect a reasonable modeling expectation given the history and extensive activity of the western markets, as well as the otherwise underused transmission from the Northw est to the other subregions. 115 

### When examining all Adjusted

- Potential Resources, all subregions maintain adequate reserves (above respective targets) throughout the assessment period.

Transmission Outlook and System Enhancements WECC is spread over a wide ge ographic area, with significant distances between generation and load centers. In addition, the northern portion of the A ssessment A rea is winter peaking, while the southern portion of the assessment area is summer peaking. Consequently, entities within th e Western Interconnection may seasonally exchange significant amounts of surplus electric energy. These conditions result in periodic full utilization of numerous transmission lines, which does not adversel y impact reliability.

To help monitor the impact of new generation resources on the transmission systems, individual entities within the Western Interconnection have established generator interconnection requirements that include power flow and stability studies to identify any adverse impact from propos ed projects. In addition, WECC has established a review procedure that is applied to larger transmission projects that may impact the interconnected system. The details of this review procedure are located in WECC’s Project Coordination and Path Rating Pro cesses. 116 

### These processes identify potential deliverability issues that may result in actions such as the implementation of system protection schemes designed to enhance deliverability and to mitigate possible adverse power system conditions.

The power tra nsfer capabilities of most major subregion transmission interconnections within WECC are limited by system stability constraints rather than by thermal limitations. These stability constraints are sensitive to system conditions and may often be increased s ignificantly at nominal cost by applying Special Protection Systems (SPS) or Remedial Action Schemes

113 Maintaining Bulk Power System Reliability While Integrating Variable Energy Resources

– CAISO Approach

. 114 WECC reports feasible transfers, not contracted transfers. This is done to eliminate double counting of resources. This treat ment is different from the other NERC Assessment Areas.

115 Modeled Transfers: applicable for Assessmen t Areas that model potential feasible transfers (imports/exports) to eliminate potential double counting of capacity. Because of delivery options, the Assessment area does not attempt to align the purchase and sale of contracts. Ins tead, the assessment ar ea, using conservative transfer limits on associated transfer paths, models feasible transfers between areas. Although these tran sfers are not contracts, Firm transmission capacity is held by the importing or exporting entities, and modeling of the existin g transmission, including transfer capability, has been executed to verify these transfers can occur during the peak season.

116 WECC's Project Coordination and Path Rating Process

.

### WECC

NERC | 2014 Long

- Term Reliability Assessment | November 201 4
95 (RAS). In addition, transmission operators may install SPSs or RASs to address localized transmission overloads related to single

- and multiple

- contingency transmission outages. The future use of such relatively inexpensive schemes in lieu of costly transmission facility additions

— and whether they will be permanent or temporary additions

— will depend on as‐yet‐ undetermined system conditions.

LSEs within WECC are rapidly expanding the use of smart meters and the associated interface equipment. The impacts of such facilities relative to power system reliability have not yet been quantified. Area entities are also taking steps to install and interface with equip ment that may morph into full‐fledged smart grid installations. The pace and extent of such changes is presently unknown. CAISO’s website presents its smart grid initiatives, which are typical of activities within the Western

Interconnection. 117



### Long

- Term Re liability Issues In 2013 more than 4,700 MW of thermal generation was retired

, including 2,250 MW of nuclear generation, 909 MW of coal

fired generation, and 1,588 MW of natural

- gas

- fired generation. However, those retirements were replaced by more than 9,500 MW of generation additions

, including 1,206 MW of wind generation, 3,162 MW of natural

- gas

- fired generation, and 3,990 MW of solar generation. WECC continues to track and study the impacts on reliability, as well as other issues, associat ed
with the retirement of large thermal generating units in response to higher air emission and water quality standards. Associated with the retirement of large coal generating units is the increased demand on natural gas supply and transportation as natural gas becom es the primary fuel for new thermal generation. WECC is working with the natural gas industry to study potential impacts to reliability as the Western Interconnection becomes more reliant on natural

- gas

- fired generation.

The joint NERC/ CAISO study addresse s some potential operational impacts from higher levels of variable resources (e.g., ancillary services for ramp rates). WECC studies to date have not identified significant issues relative to inertia and frequ ency
response , but at some as

- yet

- unidentified penetration level, inertia and frequency response may become an issue. WECC
continues to work with entities within the Western I nterconnection to identify and study reliability concerns associated with the increasing levels of variable and BTMG resources

.

117 CAISO Smart Grid Roadmap

.

### NERC | 2014 Long

- Term Reliability Assessment | November 201 4
96 

# Appendix I : 2014LTRA Reference Case Data Summary

Demand, Resources, and Reserve Margins by Assessment Area: 2015 Summer

Assessment Area /
Interconnection Demand (MW) Resources (MW) Reserve Margins (%) Reference Margin Level Total Internal Net

Internal Anticipated Prospective Adjusted

Potential Anticipated Prospective Adjusted

Potential
FRCC 46,719 43,579 55,520 57,311 57,311 27.40% 31.51% 31.51% 15.00%
MISO 128,571 123,828 144,893 150,055 150,258 17.01% 21.18% 21.34% 14.80%
MRO

- Manitoba Hydro 3,434 3,193 4,552 4,815 4,815 42.57% 50.79% 50.79% 12.00%
MRO

- MAPP 5,028 4,932 6,379 6,379 6,379 29.35% 29.35% 29.35% 15.00%
MRO

- SaskPower 3,208 3,122 3,750 3,750 3,750 20.12% 20.12% 20.12% 11.00%
NPCC

- Maritimes 3,420 3,087 5,808 5,952 5,952 88.17% 92.84% 92.84% 20.00%
NPCC

- New England 26,930 25,763 31,880 31,887 31,887 23.75% 23.77% 23.77% 15.70%
NPCC

- New York 34,066 32,877 38,311 41,715 41,715 16.53% 26.88% 26.88% 15.00%
NPCC

- Ontario 22,726 22,158 27,112 27,112 27,112 22.36% 22.36% 22.36% 19.50%
NPCC

- Québec 21,436 21,436 31,517 30,621 30,621 47.03% 42.85% 42.85% 15.00%
PJM 160,259 145,447 183,163 186,787 186,787 25.93% 28.42% 28.42% 15.70%
SERC

- E 44,086 42,329 50,475 53,773 53,773 19.24% 27.04% 27.04% 15.00%
SERC

- N 42,100 39,983 50,585 52,478 52,478 26.52% 31.25% 31.25% 15.00%
SERC

- SE 47,116 44,950 60,035 60,331 60,333 33.56% 34.22% 34.22% 15.00%
SPP 49,710 48,426 65,942 66,241 66,426 36.17% 36.79% 37.17% 13.60%
TRE

- ERCOT 69,057 67,140 76,751 79,574 79,574 14.31% 18.52% 18.52% 13.75%
WECC

- CAMX 57,606 55,610 64,102 64,126 64,126 15.27% 15.31% 15.31% 15.02%
WECC

- NWPP 66,283 65,467 79,724 80,084 80,113 21.78% 22.33% 22.37% 15.50%
WECC

- RMRG 9,899 9,342 15,106 15,106 15,106 61.70% 61.71% 61.71% 13.20%
WECC

- SWSG 22,635 22,217 29,289 29,413 29,473 31.83% 32.39% 32.66% 14.06%
Eastern Interconnection 617,372 583,673 728,404 748,586 748,977 24.80% 28.25% 28.32%

- Québec Interconnection 21,436 21,436 31,517 30,621 30,621 47.03% 42.85% 42.85% 15.00%
ERCOT Interconnection 69,057 67,140 76,751 79,574 79,574 14.31% 18.52% 18.52% 13.75%
Western Interconnection 156,423 152,636 188,221 188,730 188,819 23.31% 23.65% 23.71%

- TOTAL

- NERC 864,288 824,885 1,024,892 1,047,511 1,047,991 24.25% 26.99% 27.05%

- 

### Demand, Resources, and Reserve Margins by Assessment Area: 2015 Winter

Assessment Area /
Interconnection Demand (MW) Resources (MW) Reserve Margins (%) Reference Margin Level Total Internal Net

Internal Anticipated Prospective Adjusted

Potential Anticipated Prospective Adjusted

Potential
FRCC 45,668 42,668 58,546 60,670 60,670 37.21% 42.19% 42.19% 15.00%
MISO 104,414 99,671 139,972 145,134 145,337 40.43% 45.61% 45.82% 14.80%
MRO

- Manitoba Hydro 4,652 4,409 5,637 5,901 5,901 27.85% 33.83% 33.83% 12.00%
MRO

- MAPP 5,457 5,071 7,163 7,193 7,193 41.26% 41.85% 41.85% 15.00%
MRO

- SaskPower 3,557 3,471 4,309 4,309 4,309 24.15% 24.15% 24.15% 11.00%
NPCC

- Maritimes 5,477 5,230 6,676 6,820 6,820 27.66% 30.4 2% 30.42% 20.00%
NPCC

- New England 22,755 19,963 34,624 34,993 34,993 73.44% 75.29% 75.29% 15.70%
NPCC

- New York 24,795 23,952 39,584 44,026 44,026 65.26% 83.81% 83.81% 15.00%
NPCC

- Ontario 21,901 21,172 29,420 29,420 29,420 38.95% 38.95% 38.95% 19.50%
NPCC

- Québec 38,316 36,608 41,257 41,257 41,257 12.70% 12.70% 12.70% 11.60%
PJM 135,526 135,526 183,163 188,772 188,772 35.15% 39.29% 39.29% 15.70%
SERC

- E 42,466 41,449 55,111 56,676 56,676 32.96% 36.74% 36.74% 15.00%
SERC

- N 40,288 38,312 55,418 57,392 57,392 44.65% 49.80% 49.80% 15.00%
SERC

- SE 44,692 44,634 60,637 60,982 60,984 35.85% 36.63% 36.63% 15.00%
SPP 36,702 35,642 65,224 65,631 65,817 83.00% 84.14% 84.66% 13.60%
TRE

- ERCOT 53,719 52,057 78,277 82,765 82,767 50.37% 58.99% 58.99% 13.75%
WECC

- CAMX 40,189 39,203 51,919 52,772 52,772 32.44% 34.61% 34.61% 11.00%
WECC

- NWPP 70,778 70,453 82,304 83,217 83,246 16.82% 18.12% 18.16% 16.75%
WECC

- RMRG 10,061 9,717 13,995 13,995 13,995 44.03% 44.03% 44.03% 14.98%
WECC

- SWSG 15,650 15,314 30,572 30,735 30,848 99.63% 100.70% 101.44% 14.99%
Eastern Interconnection 538,350 521,171 745,485 767,920 768,312 43.04% 47.35% 47.42%

- Québec Interconnection 38,316 36,608 41,257 41,257 41,257 12.70% 12.70% 12.70% 11.60%
ERCOT Interconnection 53,719 52,057 78,277 82,765 82,767 50.37% 58.99% 58.99% 13.75%
Western Interconnection 136,678 134,687 178,790 180,720 180,861 32.74% 34.18% 34.28%

- TOTAL

- NERC 767,063 744,522 1,043,808 1,072,662 1,073,197 40.20% 44.07% 44.15%

-

### Appendix I: 2014LTRA Reference Case Data Summary

NERC | 2014 Long

- Term Reliability Assessment | November 201 4
97 Demand, Resources, and Reserve Margins by Assessment Area: 2019 Summer

Assessment Area /
Interconnection Demand (MW) Resources (MW) Reserve Margins Reference Margin Level Total Internal Net

Internal Anticipated Prospective Adjusted

Potential Anticipated Prospective Adjusted

Potential
FRCC 49,852 46,479 57,312 59,874 59,874 23.31% 28.82% 28.82% 15.00%
MISO 133,470 128,679 142,852 151,121 151,917 11.01% 17.44% 18.06% 14.80%
MRO

- Manitoba Hydro 3,482 3,238 4,549 4,786 4,786 40.47% 47.80% 47.80% 12.00%
MRO

- MAPP 5,810 5,712 6,599 6,599 6,599 15.52% 15.52% 15.52% 15.00%
MRO

- SaskPower 3,569 3,483 4,330 4,330 4,330 24.33% 24.33% 24.33% 11.00%
NPCC

- Maritimes 3,455 3,114 5,659 5,956 5,956 81.73% 91.27% 91.27% 20.00%
NPCC

- New England 27,782 26,788 31,529 32,463 32,463 17.70% 21.18% 21.18% 14.30%
NPCC

- New York 35,454 34,265 37,985 43,228 43,228 10.86% 26.16% 26.16% 15.00%
NPCC

- Ontario 22,272 21,576 26,630 26,630 26,630 23.42% 23.42% 23.42% 20.00%
NPCC

- Québec 21,471 21,471 33,311 32,415 32,415 55.15% 50.97% 50.97% 15.00%
PJM 166,900 154,498 185,928 194,767 194,767 20.34% 26.06% 26.06% 15.70%
SERC

- E 46,669 44,735 52,363 55,661 55,918 17.05% 24.42% 25.00% 15.00%
SERC

- N 43,677 41,122 49,471 53,071 53,137 20.30% 29.06% 29.22% 15.00%
SERC

- SE 50,124 47,909 62,978 63,274 63,540 31.45% 32.07% 32.63% 15.00%
SPP 52,849 51,523 65,394 65,951 66,366 26.92% 28.00% 28.81% 13.60%
TRE

- ERCOT 72,859 70,942 78,760 84,972 85,251 11.02% 19.78% 20.17% 13.75%
WECC

- CAMX 57,580 55,448 64,014 67,431 67,478 15.45% 21.61% 21.70% 15.02%
WECC

- NWPP 71,799 70,973 82,492 84,361 84,774 16.23% 18.86% 19.45% 15.50%
WECC

- RMRG 10,558 9,966 15,249 15,292 15,292 53.01% 53.44% 53.44% 13.20%
WECC

- SWSG 24,335 23,958 28,991 29,258 29,443 21.01% 22.12% 22.89% 14.06%
Eastern Interconnection 645,365 613,122 733,577 767,711 769,510 19.65% 25.21% 25.51%

- Québec Interconnection 21,471 21,471 33,311 32,415 32,415 55.15% 50.97% 50.97% 15.00%
ERCOT Interconnection 72,859 70,942 78,760 84,972 85,251 11.02% 19.78% 20.17% 13.75%
Western Interconnection 164,272 160,345 190,746 196,342 196,988 18.96% 22.45% 22.85%
TOTAL

- NERC 903,967 865,880 1,036,394 1,081,441 1,084,163 19.69% 24.90% 25.21%

- 

### Demand, Resources, and Reserve Margins by Assessment Area: 2019 Winter

Assessment Area /
Interconnection Demand (MW) Resources (MW) Reserve Margins Reference Margin Level Total Internal Net

Internal Anticipated Prospective Adjusted

Potential Anticipated Prospective Adjusted

Potential
FRCC 48,241 45,051 61,517 64,244 64,244 36.55% 42.60% 42.60% 15.00%
MISO 110,457 105,667 139,590 147,859 148,655 32.10% 39.93% 40.68% 14.80%
MRO

- Manitoba Hydro 4,761 4,517 5,847 6,111 6,111 29.44% 35.28% 35.28% 12.00%
MRO

- MAPP 6,311 5,911 7,079 7,079 7,079 19.76% 19.76% 19.76% 15.00%
MRO

- SaskPower 3,957 3,871 4,737 4,737 4,737 22.36% 22.36% 22.36% 11.00%
NPCC

- Maritimes 5,466 5,214 6,527 6,824 6,824 25.18% 30.88% 30.88% 20.00%
NPCC

- New England 21,062 20,084 34,015 34,948 34,948 69.36% 74.01% 74.01% 14.30%
NPCC

- New York 25,104 24,261 39,280 44,688 44,688 61.91% 84.20% 84.20% 15.00%
NPCC

- Ontario 21,578 20,722 28,392 28,392 28,392 37.01% 37.01% 37.01% 20.00%
NPCC

- Québec 39,567 37,565 43,637 43,637 43,637 16.16% 16.16% 16.16% 12.10%
PJM 139,975 139,975 185,928 194,768 194,768 32.83% 39.14% 39.14% 15.70%
SERC

- E 44,186 43,102 56,881 58,446 58,716 31.97% 35.60% 36.22% 15.00%
SERC

- N 41,955 39,428 53,054 56,844 56,911 34.56% 44.17% 44.34% 15.00%
SERC

- SE 46,997 46,934 63,867 64,212 64,492 36.08% 36.81% 37.41% 15.00%
SPP 39,546 38,493 64,484 65,171 65,586 67.52% 69.30% 70.38% 13.60%
TRE

- ERCOT 56,281 54,619 79,527 85,777 86,055 45.61% 57.05% 57.56% 13.75%
WECC

- CAMX 40,636 39,520 49,913 53,177 53,216 26.30% 34.56% 34.66% 11.00%
WECC

- NWPP 75,490 75,165 87,910 89,660 90,106 16.96% 19.28% 19.88% 16.75%
WECC

- RMRG 10,584 10,241 13,265 13,306 13,306 29.53% 29.93% 29.93% 14.98%
WECC

- SWSG 16,852 16,506 27,398 27,679 27,862 65.99% 67.69% 68.80% 14.99%
Eastern Interconnection 559,596 543,230 751,198 784,321 786,148 38.28% 44.38% 44.72%

- Québec Interconnection 39,567 37,565 43,637 43,637 43,637 16.16% 16.16% 16.16% 12.10%
ERCOT Interconnection 56,281 54,619 79,527 85,777 86,055 45.61% 57.05% 57.56% 13.75%
Western Interconnection 143,562 141,432 178,486 183,822 184,490 26.20% 29.97% 30.44%

- TOTAL

- NERC 799,005 776,845 1,052,848 1,097,557 1,100,331 35.53% 41.28% 41.64%

-

### Appendix I: 2014LTRA Reference Case Data Summary

NERC | 2014 Long

- Term Reliability Assessment | November 201 4
98 Demand, Resources, and Reserve Margins by Assessment Area: 2024 Summer

Assessment Area /
Interconnection Demand (MW) Resources (MW) Reserve Margins Reference Margin Level Total Internal Net

Internal Anticipated Prospective Adjusted

Potential Anticipated Prospective Adjusted

Potential
FRCC 52,981 49,458 60,794 63,988 63,988 22.92% 29.38% 29.38% 15.00%
MISO 138,433 133,582 139,521 153,178 154,317 4.45% 14.67% 15.52% 14.80%
MRO

- Manitoba Hydro 3,753 3,509 5,242 5,029 5,029 49.38% 43.32% 43.32% 12.00%
MRO

- MAPP 6,427 6,319 6,661 6,661 6,661 5.41% 5.41% 5.41% 15.00%
MRO

- SaskPower 3,735 3,649 4,349 4,349 4,349 19.21% 19.21% 19.21% 11.00%
NPCC

- Maritimes 3,421 3,080 5,659 5,956 5,956 83.75% 93.39% 93.39% 20.00%
NPCC

- New England 28,430 27,436 31,529 32,463 32,463 14.92% 18.32% 18.32% 14.30%
NPCC

- New York 36,580 35,391 37,985 43,228 43,228 7.33% 22.14% 22.14% 15.00%
NPCC

- Ontario 22,541 21,046 27,232 27,232 27,232 29.39% 29.39% 29.39% 20.00%
NPCC

- Québec 22,557 22,557 33,770 32,874 32,874 49.71% 45.74% 45.74% 15.00%
PJM 173,729 161,327 187,498 196,338 196,338 16.22% 21.70% 21.70% 15.70%
SERC

- E 49,943 47,937 52,702 56,000 56,577 9.94% 16.82% 18.02% 15.00%
SERC

- N 45,797 42,692 48,547 53,078 53,222 13.71% 24.33% 24.67% 15.00%
SERC

- SE 53,844 51,592 63,068 63,364 63,630 22.24% 22.82% 23.33% 15.00%
SPP 56,991 55,663 63,634 64,299 64,877 14.32% 15.51% 16.55% 13.60%
TRE

- ERCOT 77,471 75,554 79,060 87,126 87,404 4.64% 15.32% 15.68% 13.75%
WECC

- CAMX 58,930 56,541 64,106 68,285 68,387 13.38% 20.77% 20.95% 15.02%
WECC

- NWPP 76,652 75,831 85,828 87,838 88,513 13.18% 15.83% 16.73% 15.50%
WECC

- RMRG 11,249 10,616 12,028 12,070 12,073 13.30% 13.70% 13.73% 13.20%
WECC

- SWSG 26,709 26,326 29,536 30,066 30,448 12.19% 14.21% 15.66% 14.06%
Eastern Interconnection 676,604 642,680 734,419 775,163 777,866 14.27% 20.61% 21.03%

- Québec Interconnection 22,557 22,557 33,770 32,874 32,874 49.71% 45.74% 45.74% 15.00%
ERCOT Interconnection 77,471 75,554 79,060 87,126 87,404 4.64% 15.32% 15.68% 13.75%
Western Interconnection 173,540 169,314 191,497 198,259 199,422 13.10% 17.10% 17.78%
TOTAL

- NERC 950,171 910,105 1,038,746 1,093,421 1,097,566 14.13% 20.14% 20.60%

- 

### Demand, Resources, and Reserve Margins by Assessment Area: 2024 Winter

Assessment Area /
Interconnection Demand (MW) Resources (MW) Reserve Margins Reference Margin Level Total Internal Net

Internal Anticipated Prospective Adjusted

Potential Anticipated Prospective Adjusted

Potential
FRCC 50,584 47,295 65,420 68,866 68,866 38.32% 45.61% 45.61% 15.00%
MISO 115,031 110,180 136,310 149,967 151,106 23.72% 36.11% 37.14% 14.80%
MRO

- Manitoba Hydro 5,136 4,892 6,365 6,179 6,179 30.11% 26.30% 26.30% 12.00%
MRO

- MAPP 7,009 6,584 7,106 7,106 7,106 7.94% 7.94% 7.94% 15.00%
MRO

- SaskPower 4,141 4,055 4,829 4,829 4,829 19.08% 19.08% 19.08% 11.00%
NPCC

- Maritimes 5,427 5,176 6,527 6,824 6,824 26.11% 31.85% 31.85% 20.00%
NPCC

- New England 20,790 19,812 34,015 34,015 34,015 71.69% 71.69% 71.69% 14.30%
NPCC

- New York 25,537 24,694 39,280 42,566 42,566 59.07% 72.37% 72.37% 15.00%
NPCC

- Ontario 21,628 19,972 29,208 29,208 29,208 46.25% 46.25% 46.25% 20.00%
NPCC

- Québec 41,373 39,121 44,121 44,121 44,121 12.78% 12.78% 12.78% 12.10%
PJM 144,913 144,913 187,498 193,012 193,012 29.39% 33.19% 33.19% 15.70%
SERC

- E 47,557 46,451 56,827 58,392 58,993 22.34% 25.71% 27.00% 15.00%
SERC

- N 44,263 41,021 53,102 57,851 58,006 29.45% 41.03% 41.41% 15.00%
SERC

- SE 50,399 50,331 66,238 66,583 66,863 31.61% 32.29% 32.85% 15.00%
SPP 42,064 41,011 62,956 63,146 63,724 53.51% 53.97% 55.38% 13.60%
TRE

- ERCOT 60,480 58,818 79,827 83,013 83,292 35.72% 41.14% 41.61% 13.75%
WECC

- CAMX 41,564 40,198 51,820 51,820 51,914 28.91% 28.91% 29.15% 11.00%
WECC

- NWPP 79,912 79,587 93,002 93,002 93,661 16.86% 16.86% 17.68% 16.75%
WECC

- RMRG 11,251 10,905 14,800 14,800 14,803 35.72% 35.72% 35.74% 14.98%
WECC

- SWSG 18,439 18,090 28,329 28,329 28,697 56.60% 56.60% 58.63% 14.99%
Eastern Interconnection 584,478 566,387 755,681 788,543 791,296 33.42% 39.22% 39.71%

- Québec Interconnection 41,373 39,121 44,121 44,121 44,121 12.78% 12.78% 12.78% 12.10%
ERCOT Interconnection 60,480 58,818 79,827 83,013 83,292 35.72% 41.14% 41.61% 13.75%
Western Interconnection 151,166 148,780 187,950 187,950 189,074 26.33% 26.33% 27.08%

- TOTAL

- NERC 837,497 813,105 1,067,580 1,103,628 1,107,783 31.30% 35.73% 36.24%

-

### Appendix I: 2014LTRA Reference Case Data Summary

NERC | 2014 Long

- Term Reliability Assessment | November 201 4
99 Projected Total Internal Demand by Assessment Area and Interconnection: 2015

– 202 4 Summer Assessment Area /
Interconnection 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 10

- Year CAGR
FRCC 46,719 47,615 48,501 49,147 49,852 50,554 51,263 52,049 52,981 52,981 1.41%
MISO 128,571 130,101 131,242 132,376 133,470 134,509 135,526 136,460 137,377 138,433 0.82%
MRO

- Manitoba Hydro 3,434 3,483 3,424 3,446 3,482 3,555 3,610 3,655 3,703 3,753 0.99%
MRO

- MAPP 5,028 5,374 5,500 5,690 5,810 5,927 6,038 6,145 6,257 6,427 2.77%
MRO

- SaskPower 3,208 3,289 3,357 3,469 3,569 3,593 3,634 3,677 3,712 3,735 1.70%
NPCC

- Maritimes 3,420 3,529 3,497 3,481 3,455 3,444 3,425 3,421 3,418 3,421 0.00%
NPCC

- New England 26,930 27,291 27,521 27,677 27,782 27,911 28,028 28,167 28,298 28,430 0.60%
NPCC

- New York 34,066 34,412 34,766 35,111 35,454 35,656 35,890 36,127 36,369 36,580 0.79%
NPCC

- Ontario 22,726 22,535 22,344 22,301 22,272 22,170 22,479 22,609 22,616 22,541

- 0.09%
NPCC

- Québec 21,436 21,196 21,320 21,335 21,471 21,673 22,110 22,274 22,421 22,557 0.57%
PJM 160,259 162,470 164,195 165,479 166,900 168,593 170,027 171,217 172,542 173,729 0.90%
SERC

- E 44,086 44,768 45,398 45,992 46,669 47,289 47,928 48,579 49,251 49,943 1.40%
SERC

- N 42,100 42,571 42,917 43,298 43,677 44,018 44,470 44,908 45,359 45,797 0.94%
SERC

- SE 47,116 48,137 48,931 49,427 50,124 51,135 51,563 52,292 53,046 53,844 1.49%
SPP 49,710 50,993 51,700 52,267 52,849 53,454 53,999 54,817 55,438 56,991 1.53%
TRE

- ERCOT 69,057 70,014 70,871 71,806 72,859 73,784 74,710 75,631 76,550 77,471 1.29%
WECC

- CAMX 57,606 56,767 57,004 57,245 57,580 58,003 58,257 58,542 58,742 58,930 0.25%
WECC

- NWPP 66,283 67,733 69,233 70,674 71,799 72,745 73,586 74,390 75,364 76,652 1.63%
WECC

- RMRG 9,899 10,100 10,239 10,410 10,558 10,709 10,843 10,901 11,046 11,249 1.43%
WECC

- SWSG 22,635 22,760 23,282 23,762 24,335 24,707 25,113 25,694 26,193 26,709 1.86%
Eastern Interconnection 617,372 626,567 633,293 639,161 645,365 651,809 657,879 664,123 670,366 676,604 1.02% Québec Interconnection 21,436 21,196 21,320 21,335 21,471 21,673 22,110 22,274 22,421 22,557 0.57%
ERCOT Interconnection 69,057 70,014 70,871 71,806 72,859 73,784 74,710 75,631 76,550 77,471 1.29%
Western Interconnection 156,423 157,360 159,758 162,092 164,272 166,165 167,798 169,527 171,345 173,540 1.16%
TOTAL

- NERC 864,288 875,137 885,242 894,393 903,967 913,430 922,497 931,555 940,682 950,171 1.06%



### Projected Total Internal Demand by Assessment Area and Interconnection: 2015

– 202 4 Winter
Assessment Area /
Interconnection 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 10

- Year CAGR
FRCC 45,668 46,415 47,165 47,692 48,241 48,769 49,323 49,934 50,584 50,584 1.14%
MISO 104,414 107,352 108,414 109,506 110,457 111,360 112,219 113,053 113,797 115,031 1.08%
MRO

- Manitoba Hydro 4,652 4,713 4,663 4,705 4,761 4,854 4,931 4,997 5,066 5,136 1.11%
MRO

- MAPP 5,457 5,818 5,949 6,176 6,311 6,440 6,572 6,702 6,832 7,009 2.82%
MRO

- SaskPower 3,557 3,647 3,722 3,846 3,957 3,984 4,029 4,077 4,116 4,141 1.70%
NPCC

- Maritimes 5,477 5,513 5,508 5,493 5,466 5,434 5,421 5,420 5,425 5,427

- 0.10%
NPCC

- New England 22,755 21,274 21,238 21,153 21,062 20,986 20,918 20,865 20,822 20,790

- 1.00%
NPCC

- New York 24,795 24,856 24,906 24,966 25,104 25,177 25,252 25,334 25,427 25,537 0.33%
NPCC

- Ontario 21,901 21,901 21,529 21,592 21,578 21,535 21,646 21,541 21,508 21,628

- 0.14%
NPCC

- Québec 38,316 38,612 38,847 39,168 39,567 40,218 40,558 40,862 41,120 41,373 0.86%
PJM 135,526 137,308 138,314 139,213 139,975 141,369 142,489 143,481 144,359 144,913 0.75%
SERC

- E 42,466 42,560 42,907 43,476 44,186 44,858 45,603 46,300 46,847 47,557 1.27%
SERC

- N 40,288 41,022 41,348 41,639 41,955 42,419 42,902 43,322 43,642 44,263 1.05%
SERC

- SE 44,692 45,292 45,946 46,332 46,997 47,635 48,300 48,996 49,679 50,399 1.34%
SPP 36,702 38,123 38,549 39,181 39,546 40,062 40,664 41,141 41,639 42,064 1.53%
TRE

- ERCOT 53,719 53,719 54,579 55,441 56,281 57,116 57,962 58,804 59,643 60,480 1.33%
WECC

- CAMX 40,189 40,227 40,292 40,432 40,636 40,946 41,209 41,424 41,515 41,564 0.37%
WECC

- NWPP 70,778 71,786 73,217 74,430 75,490 76,482 77,422 78,320 79,189 79,912 1.36%
WECC

- RMRG 10,061 10,205 10,355 10,466 10,584 10,724 10,863 10,994 11,121 11,251 1.25%
WECC

- SWSG 15,650 15,862 16,138 16,443 16,852 17,190 17,492 17,814 18,156 18,439 1.84%
Eastern Interconnection 538,350 545,794 550,157 554,970 559,596 564,883 570,270 575,163 579,742 584,478 0.92% Québec Interconnection 38,316 38,612 38,847 39,168 39,567 40,218 40,558 40,862 41,120 41,373 0.86%
ERCOT Interconnection 53,719 53,719 54,579 55,441 56,281 57,116 57,962 58,804 59,643 60,480 1.33%
Western Interconnection 136,678 138,080 140,002 141,771 143,562 145,341 146,986 148,551 149,981 151,166 1.13%
TOTAL

- NERC 767,063 776,205 783,586 791,350 799,005 807,558 815,776 823,381 830,486 837,497 0.98%

### Appendix I: 2014LTRA Reference Case Data Summary

NERC | 2014 Long

- Term Reliability Assessment | November 201 4
100 Projected Transmission Additions by Assessment Area and Interconnection: 2014

– 202 4 Assessment Area/
Interconnection Under
Construction 10

- Year Planned 10

- Year Conceptual
FRCC 67 513 20 MISO 1,489 4,525 0 MRO

- Manitoba Hydro 1,908 301 0 MRO

- MAPP 379 201 102 MRO

- SaskPower 0 663 220 NPCC

- Maritimes 0 201 50 NPCC

- New England 234 164 261 NPCC

- New York 0 1,217 343 NPCC

- Ontario 0 0 240 NPCC

- Québec 266 689 199
PJM 740 1,694 584 SERC

- E 421 139 0 SERC

- N 45 202 190 SERC

- SE 175 434 12 SPP 1,171 2,006 176
TRE

- ERCOT 85 682 426 WECC

- CAMX 288 652 1,307 WECC

- NWPP 12 4,652 1,343 WECC

- RMRG 2 562 1,169 WECC

- SRSG 172 1,125 719
EASTERN INTERCONNECTION 6,629 12,260 2,198 QUÉBEC INTERCONNECTION 266 689 199
TEXAS INTERCONNECTION 85 682 426
WESTERN INTERCONNECTION 475 6,992 4,538
TOTAL

- NERC 7,454 20,622 7,360

### Appendix II: Reliability Assessment Definitions

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- Term Reliability Assessment | November 201 4
101 

# Appendix I I : Reliability Assessment Glossary

Term Definition

Ancillary Services Those services that are necessary to support the transmission of capacity and energy from resources to loads while maintaining reliable operation of the Transmission Service Provider's transmission system in accordance with good utility practice (Source: NERC Glossary of Terms) Anticipat ed Resources Includes Existing

- Certain Capacity, Net Firm Transfers (Imports

– Exports), and Tier 1 Capacity Additions. Anticipated Reserve Margin Anticipated Resources minus Net Internal Demand, divided by Net Internal Demand, shown as a percentile.

Assessment Area Based on existing ISO/RTO footprints; otherwise, based on individual Planning Coordinator or group of Planning Coordinators. NERC collects data for seasonal and long

- term assessments based on these footprints that align with how the system is planned and operated.

Balancing Authority The responsible entity that integrates resource plans ahead of time, maintains load

- interchange

- generation balance within a Balancing Authority Area, and supports Interconnection frequency in real time. (Source : NERC Glossary of Terms) Bulk Electric System See NERC Glossary of Terms

Bulk

- Power System A) facilities and control systems necessary for operating an interconnected electric energy transmission network (or any portion thereof); and (B) electric energy from generation facilities needed to maintain transmission system reliability. The term does not include facilities used in the local distribution of electric energy. (Source: NERC Glossary of Terms)

Capacity Transfers (Transactions) There are three type s of capacity transfers (transactions):

Firm: “Firm” transfers that require the execution of a contract that is in effect during the projected peak. The net of all Firm transfers (imports minus exports) are applied towards Anticipated Resources.

Model ed: transfers that are applicable for Assessment Areas that model potential feasible transfers (imports/exports). While these transfers do not have Firm contracts, modeling of the existing transmission, including transfer capability, has been executed to verify these transfers can occur during the peak season. The net of all Modeled transfers (imports minus exports) are applied towards Anticipated Resources.

Expected: transfers without the execution of a Firm contract, but with a high expectation that a Firm contract will be executed in the future and will be in effect during the projected peak. The net of all Modeled transfers (imports minus exports) are applied towards Prospective Resources.

Conservation (Energy Conservation) A reduction in energy c onsumption that corresponds with a reduction in service demand. Service demand can include buildings

- sector end uses such as lighting, refrigeration, and heating; industrial processes; or vehicle transportation. Unlike energy efficiency, which is typically a technological measure, conservation is better associated with behavior. Examples of conservation include adjusting the thermostat to reduce the output of a heating unit, using occupancy sensors that turn off lights or appliances, and car

- pooling. (Sourc e: DOE

- EIA)

Critical Peak

- Pricing (CPP) with Load Control Price structure designed to encourage reduced consumption during periods of high wholesale market prices or system contingencies by imposing a pre

- specified high rate or price for a limited number of days or hours. Critical Peak Pricing (CPP) with Direct Load Control combines Direct Load Control with a pre

- specified high price for use during designated critical peak periods triggered by system contingencies or high whol esale market prices. Subset of C ontrollable and D ispatchable Demand Response

. Dispatchable and Controllable Demand

- Side Management that combines direct remote control with a pre

specified high price for use during designated critical peak periods, triggered by system contingencies or high wholesale market prices.

Curtailment A reduction in the scheduled capacity or energy delivery of an Interchange Transaction. (Source: NERC Glossary of Terms)

Demand 1. The rate at which electric energy is delivered to or by a system or part of a system, generally expressed in kilowatts or megawatts, at a given instant or averaged over any designated interval of time. 2. The rate at which energy is being used by the customer.

Demand Response Changes in electric use by Demand

- Side resources from normal consumption patterns in response to changes in the price of electricity, or to incentive payments designed to induce lower electricity use at times of high wholesale market prices, or when required to maintain system reliability. Demand Response can be counted in resource adequacy studies either as a load

- modifier, or as a resource.

Controllable and Dispatchable Demand R esponse requires the System Operator to have physical command of the resources (Controllable) or be able to activate it based on in struction from a co ntrol center. Controllable and
D ispatcha ble Demand R esponse includes four categories: Critical Peak Pricing (CPP) with Load Control; Direct Control Load Management (DCLM); Load as a Capacity Resource (LCR); and Interruptible Load (IL).

### Appendix II: Reliability Assessment Definitions

NERC | 2014 Long

- Term Reliability Assessment | November 201 4
102 Demand

- Side Management All activities or programs undertaken by any applicable entity to achieve a reduction in Demand. (Source: NERC Glossary of Terms)
Derate The amount of capacity that is expected to be unavailable during the seasonal peak.

Designate d Network
Resource Any designated generating resource owned, purchased or leased by a Network Customer under the Network Integration Transmission Service Tariff. Network Resources do not include any resource, or any portion thereof, that is committed for sale to third parties or otherwise cannot be called upon to meet the Network Customer's Network Load on a non

- interruptible basis, except for purposes of fulfilling obligations under a Commission

approved reserve sharing program.
Distributed Energy Resources (DERs) Distributed energy resources (DERs) are smaller power sources that can be aggregated to provide power necessary to meet regular demand. As the electricity grid continues to modernize, DER s such as storage and advanced renewable technologie s can help facilitate the transition to a smarter grid. (Source: EPRI) Distributed Generation See Distributed Energy Resources

Energy Efficiency Refers to programs that are aimed at reducing the energy used by specific end

- use devices and systems, typica lly without affecting the services provided. These programs reduce overall electricity consumption (reported in megawatt

- hours), often without explicit consideration for the timing of program

- induced savings. Such savings are generally achieved by substitu ting technologically more advanced equipment to produce the same level of end

- use services (e.g. lighting, heating, motor drive) with less electricity. Examples include high

- efficiency appliances, efficient lighting programs, high

- efficiency heating, venti lating and air conditioning (HVAC) systems or control modifications, efficient building design, advanced electric motor drives, and heat recovery systems. Results in permanent changes to electricity use by replacement of end

- use devices with more efficient end

- use devices or more effective operation of existing devices. Generally, it results in reduced consumption across all hours rather than event

- driven targeted load reductions. (Source: DOE

- EIA)

Estimated Diversity The electric utility system's load is made up of many individual loads that make demands on the system, with peaks occurring at different times throughout the day. The individual loads within the customer classes follow similar usage patterns, but these classes of service place different deman ds upon the facilities and the system grid. The service requirements of one electrical system can differ from another by time

- of

- day usage, facility usage, and/or demands placed upon the system grid.

Existing

- Certain Capacity



###  Included in this category are existing generator units (expressed in MW), or portions of existing generator units, that are physically located within the assessment area that meet at least one of the following requirements when examining the projected peak for the summer and winter of each year: (1) unit must have a Firm capability (defined as the commitment of generation service to a customer under a contractual agreement to which the parties to the service anticipate no planned interruption (applies to ge neration and transmission), a Power Purchase Agreement (PPA), and Firm transmission; (2) unit must be classified as a Designated Network Resource; (3) where energy

- only markets exist, unit must be a designated market resource eligible to bid into the marke t.

Disturbance An unplanned event that produces an abnormal system condition; any perturbation to the electric system, or the unexpected change in ACE that is caused by the sudden failure of generation or interruption of load. (Source: NERC Glossary of Te rms)

Existing

- Other Capacity Included in this category are existing generator units, or portions of existing generator units, that are physically located within the assessment area that do not qualify as Existing

- Certain when examining the projected peak for the summer and winter of each year. Accordingly, these are the units, or portions of units, may not be available to serve peak demand for each season/year.

Energy

- Only Generating resources that are designated as energy

- only resources or have elected to be classified as energy

- only resources and may include generating capacity that can be delivered within the area but may be recallable to another area. Designated energy

– only resources do not have capacity rights. Firm (Transmission Service) The highe st quality (priority) service offered to customers under a filed rate schedule that anticipates no planned interruption. (Source: NERC Glossary of Terms)

Forced Outage The removal from service availability of a generating unit, transmission line, or other facility for emergency reasons. Also, the condition in which the equipment is unavailable due to unanticipated failure. (Source: NERC Glossary of Terms)

Frequency Regulation The ability of a Balancing Authority to help the Interconnection maintain Schedu led Frequency. This assistance can include both turbine governor response and Automatic Generation Control. (NERC Glossary of Terms)

Frequency Response Equipment: The ability of a system or elements of the system to react or respond to a change in system frequency. System: The sum of the change in demand, plus the change in generation, divided by the change in frequency, expressed in megawatts per 0.1 Hertz (MW/0.1 Hz). (Source: NERC Glossary of Terms) Expected (Provisional) Capacity Transfers Future transfers that do not currently have a Firm contract, but there is a reasonable expectation that a Firm contract will be signed. These transfers are included in the Prospective Resources.

Generator Operator The entity that operates generating unit( s) and performs the functions of supplying energy and Interconnected Operations Services. (NERC Glossary of Terms)
Generator Owner Entity that owns and maintains generating units. (NERC Glossary of Terms)

### Appendix II: Reliability Assessment Definitions

NERC | 2014 Long

- Term Reliability Assessment | November 201 4
103 Independent Power Producer Any entity that owns o r operates an electricity generating facility that is not included in an electric utility’s rate base. This term includes, but is not limited to, cogenerators and small power producers and all other nonutility electricity producers, such as exempt wholesal e generators, who sell electricity. (NERC Glossary of Terms)

Interconnection When capitalized, any one of the four major electric system networks in North America: Eastern, Western, ERCOT and Québec. (NERC Glossary of Terms) Interruptible Load

or Interru ptible Demand Demand that the end

- use customer makes available to its Load

- Serving Entity via contract or agreement for curtailment. (NERC Glossary of Terms)

Load An end

- use device or customer that receives power from the electric system. (NERC Glossary of Terms)

Load

- Serving Entity Secures energy and transmission service (and related Interconnected Operations Services) to serve the electrical demand and energy requirements of its end

- use customers. (NERC Glossary of Terms)

Net Energy for Load (NEL) The amount of energy required by the reported utility or group of utilities' retail customers in the system's service area plus the amount of energy supplied to full and partial requirements utilities (wholesale requirements customers) plus the amount of ener gy losses incurred in the transmission and distribution. (Source: FERC

- 714) Net Balancing Authority Area generation, plus energy received from other Balancing Authority Areas, less energy delivered to Balancing Authority Areas through interchange. It includes Balancing Authority Area losses but excludes energy required for storage at energy storage facilities. (NERC Glossary of Terms) Net Internal Demand Total Internal Demand reduced by dispatchable and controllable Demand Response. (NERC Glossary of Terms)
Non

- Firm Transmission Service Transmission service that is reserved on an as

- available basis and is subject to curtailment or interruption. (NERC Glossary of Terms)

Non

- spinning Reserves The portion of Operating Reserve consisting of (1) generating reserve not connected to the system but capable of serving demand within a specified time; or (2) interruptible load that can be removed from the system in a specified time.(NERC Glossary of Terms)

Off

- Peak Those hours or other periods defined by NAESB business practices, contract, agreements, or guides as periods of lower electrical demand. (NERC Glossary of Terms)

On

- Peak Those hours or other periods defined by NAESB business practices, contract, agreements, or guides as periods of higher el ectrical demand. (NERC Glossary of Terms) Open Access Same Time Information Service An electronic posting system that the Transmission Service Provider maintains for transmission access data and that allows all transmission customers to view the data simu ltaneously. (NERC Glossary of Terms)

Open Access Transmission Tariff Electronic transmission tariff accepted by the U.S. Federal Energy Regulatory Commission requiring the Transmission Service Provider to furnish to all shippers with non

- discriminating service comparable to that provided by Transmission Owners to themselves. (NERC Glossary of Terms)

Operating Reserves The capability above Firm system demand required to provide for regulation, load forecasting error, equipment forced and scheduled outage s and local area protection. It consists of spinning and non

- spinning reserve. Planning Coordinator (Planning Authority ) The responsible entity that coordinates and integrates transmission facility and service plans, resource plans, and protection systems . (NERC Glossary of Terms)

Planning Reserve Margins Anticipated Reserve Margin: Anticipated Resources, less Net Internal Demand, divided by Net Internal Demand. Prospective Reserve Margin: Prospective Resources, less Net Internal Demand, divided by Net In ternal Demand. Adjusted

- Potential Reserve Margin: Adjusted

- Potential Resources, less Net Internal Demand, divided by Net Internal Demand.

Peak Demand The highest hourly integrated Net Energy For Load (or highest instantaneous demand) within a Balancing Authority Area occurring within a given period (e.g., day, month, season, or year). (NERC Glossary of Terms)

Power Purchase Agreement Guarantees a market for power produced by an independent power producer and the price at which it is sold to a purchaser. Such an agreement imposes legal obligations on both the parties to perform previously accepted tasks in a predetermined manner. Prospective Capacity
Resources Anticipated Resources plus Existing

- Other c apacity, plus 50 percent of Tier 2 Capacity, plus ne t Expected t ransfers.

Prospective Capacity Reserve Margin Prospective Capacity Resources minus Net Internal Demand shown divided by Net Internal Demand, shown as a percentile.

Ramp Rate (Ramp) Schedule: the rate, expressed in megawatts per minute, at which the interchange schedule is attained during the ramp period. Generator: the rate, expressed in megawatts per minute, that a generator changes its output. (NERC Glossary of Terms)

Rating The operational limits of a transmission system element under a set of specified conditions. (NERC Glossary of Terms)

Reactive Power The portion of electricity that establishes and sustains the electric and magnetic fields of alternating

- current equipment. Reactive power must be supplied to most types of magnetic eq uipment, such as motors and transformers. It also must supply the reactive losses on transmission facilities. Reactive power is provided by generators, synchronous condensers, or electrostatic equipment such as capacitors and directly influences electric s ystem voltage. It is usually expressed in kilovars (k var) or megavars (MV ar). (NERC Glossary of Terms) Real Power The portion of electricity that supplies energy to the load. (NERC Glossary of Terms)

### Appendix II: Reliability Assessment Definitions

NERC | 2014 Long

- Term Reliability Assessment | November 201 4
104 Reference Margin Level This metric is typically based on the load, generation, and transmission characteristics for each Assessment Area. In some cases, it is a requirement implemented by the respective state(s), provincial authority, ISO/RTO, or other regulatory body. If such a requirement exists, the respec tive Assessment Area generally adopts this requirement as the Reference Margin Level. In some cases, the Reference Margin Level may fluctuate for each season of the assessment period. If a Reference Margin Level is not provided by an Assessment Area, NERC applies a 15 percent Reference Margin Level for predominately thermal systems and 10 percent for predominately hydro systems.

Reliability Coordinator The entity that is the highest level of authority who is responsible for the reliable operation of the Bu lk Electric System, has the Wide Area view of the Bulk Electric System, and has the operating tools, processes and procedures, including the authority to prevent or mitigate emergency operating situations in both next

- day analysis and real

- time operations. The Reliability Coordinator has the purview that is broad enough to enable the calculation of Interconnection Reliability Operating Limits, which may be based on the operating parameters of transmission systems beyond any Transmission Operator’s vision. ( NERC Glossary of Terms)

Renewable Energy (Renewables Energy derived from resources that are regenerative or for all practical purposes cannot be depleted. Types of renewable energy resources include moving water (hydro, tidal and wave power), thermal gradients in ocean water, biomass, geothermal energy, solar energy, and wind energy. Municipal solid waste (MSW) is also considered to be a renewable energy resource. (Source: DOE

- EIA)

Reserve Sharing Group A group whose members consist of two or more Bal ancing Authorities that collectively maintain, allocate, and supply operating reserves required for each Balancing Authority’s use in recovering from contingencies within the group. Scheduling energy from an Adjacent Balancing Authority to aid recovery nee d not constitute reserve sharing provided the transaction is ramped in over a period the supplying party could reasonably be expected to load generation in (e.g., ten minutes). If the transaction is ramped in quicker (e.g., between zero and ten minutes) th en, for the purposes of Disturbance Control Performance, the Areas become a Reserve Sharing Group. (Source: NERC Glossary of Terms) Stand

- by Load under
Contract Demand which is normally served by behind

- the

- meter generation, which has a contract to provid e power if the generator becomes unavailable. Spinning Reserves Unloaded generation that is synchronized and ready to serve additional demand.(NERC Glossary of Terms)

Time

- of

- Use (TOU) Ra te and/or price structures with different unit prices for use duri ng different blocks of time.
Time

- Sensitive Pricing (Non

- dispatchable Demand Response)

— Retail rates and/or price structures designed to reflect time

- varying differences in wholesale electricity costs, and thus provide consumers with an incentive to modif y consumption behavior during high

- cost or peak periods.

Total Internal Demand Projected sum of the metered (net) outputs of all generators within the system and the metered line flows into the system, less the metered line flows out of the system. The demands for station service or auxiliary needs (such as fan motors, pump motors, a nd other equipment essential to the operation of the generating units) are not included. Total Internal Demand should be reduced by indirect D emand

- S ide M anagement programs such as conservation programs, improvements in efficiency of electric energy use, Stand

- by Load under Co ntract, all non

dispatchable Demand R esponse programs (such as Time

- of

- Use, Critical Peak Pricing, Real Time Pricing and System Peak Response Transmis sion Tariffs). Adjustments for controllable Demand R esponse should not be included i n this value. The demand of a metered system, which includes the Firm demand, plus any C ontrollable and D ispatchable DSM load and the load due to the energy losses incurred within the boundary of the metered system. (Source: NERC Glossary of Terms)

Transmission

- Limited
Resources The amount of transmission

- limited generation resources that have deliverability limitations to serve load within the Region. If capacity is limited by both studied transmission limitations and generator derates, the generato r derates takes precedence. Uncertainty The magnitude and timing of variable generation output is less predictable than for conventional generation. Variable Energy
Resources Resources with output that are highly variable subject to weather fluctuations such as wind speed and cloud

cover.
Variability The output of variable generation changes according to the availability of the primary fuel (wind, sunlight and moving water) resulting in fluctuations in the plant output on all time scales.

### Appendix III: 2014 Polar Vortex Scenario Analysis

NERC | 2014 Long

- Term Reliability Assessment | November 201 4
105 

# Appendix I II: 2014 Polar Vortex Scenario Analysis

Overview
The 2014 p olar v ortex involved extended periods of extreme cold weather from January 6

– 8, 2014
, in several parts of North America, presenting challenges for S ystem O perators in both the Eastern and Texas Interconnections. During the event, the BPS was stressed with high periods of demand, establishing new records for several areas. Concurrently, an increased number
of units experienced forced outages amounting to over 10,000 MW, resulting in the use of emergency operating procedures
and calling DR programs in several areas. Despite these extreme conditions, the BPS remained stable and generally perfo rmed reliably throughout the duration of the event, primarily because of preparation efforts prior to the cold snap. Specifically, generator owners took preemptive steps to prepare equipment for the freezing temperatures. These steps included: cancelling s cheduled generator outages, installing additional insulation, and testing dual

- fuel capabilities. Similarly, S ystem
O perators coordinated with neighboring areas to ensure resource availability and share other pertinent information.

Subsequent to a thorough review of the event, NERC released the Polar Vortex Review report in September 2014, based on data and information provided from the NERC Generator Availability Data System (GADS), as well as supplemental support from the impacted Assessment Areas . According to these data, it was concluded that forced outages during the event were primarily caused by the following:

1. Inoperable equipment in extreme low temperatures

, 2. Unavailability of fuel at generating units (due to supply or transportation or a combination of both)

, and

3. Challenges for some dual

- fuel capable units in switching from a primary to a secondary fuel.

Colder temperatures contributed to higher electricity demand while also increasing the demand for natural gas used f or residential heating in some parts of North America. These conditions stressed the ability of pipeline operators and suppliers to deliver natural gas to the power sector, which resulted in a significant amount of gas

- fired generation being unavailable
du e to gas curtailments. This was particularly relevant considering that gas

- fired units accounted for approximately 40 percent of the generation mix during the 2014 p olar v ortex . Accordingly, natural

- gas

- fired units were also the most impacted compared to o ther generators, representing over 55 percent of all forced outages during the event.

Scenario Assumptions and Results
In addition to the Polar Vortex Review , NERC staff also conducted scenarios for MISO, PJM, SERC

- E, and TRE

- ERCOT. Each of
these Assessmen t Areas experienced high forced outage rates during the event. NERC’s scenario assumptions involved applying these actual forced outage rates as derates to existing and projected (Tier 1) capacity data from the 2014LTRA reference case. Similarly, projected load was assumed to be consistent with the extreme loads during the event.

Fuel Derates and Net Internal Demand Assumptions (Based on Actual Forced Outages and Demand)

Assessment Area Applied Derate Assumed Net Internal Demand

Coal Petroleum Natural Gas Nuclear Wind Solar Other Generation
MISO 15% 10% 30% 0% 100% 100% 0% 110%
PJM 30% 10% 20% 20% 100% 100% 0% 105%
SERC

- E 0% 0% 0% 0% 100% 100% 0% 118%
TRE

- ERCOT 15% 0% 25% 0% 100% 100% 0% 110%

### Appendix III: 2014 Polar Vortex Scenario Analysis

NERC | 2014 Long

- Term Reliability Assessment | November 201 4
106 MISO (Right) and PJM (Left)

SERC

- E (Right) and TRE

- ERCOT (Left)

Scenario Observations
This analysis demonstrates that a repeated extreme weather event with conditions similar to those observed during the 2014 polar vortex would result in inadequate Anticipated Resources , based on the 2014LTRA reference case. This highlights the need for system planners to more strongly consider generator performance during extreme weather events

, particularly for
natural

- gas

- fired units

. -10% 0% 10% 20% 30% 40% 50%

2015 2016 2017 2018 2019 2020 2021 2022 2023 2024
Anticipated Margin Scenario Margin Reference Margin Level -10% 0% 10% 20% 30% 40% 50%

2015 2016 2017 2018 2019 2020 2021 2022 2023 2024
Anticipated Margin Scenario Margin Reference Margin Level

-5% 5% 15% 25% 35%

2015 2016 2017 2018 2019 2020 2021 2022 2023 2024
Anticipated Margin Scenario Margin Reference Margin Level -10% 0% 10% 20% 30% 40% 50% 60%

2015 2016 2017 2018 2019 2020 2021 2022 2023 2024
Anticipated Margin Scenario Margin Reference Margin Level

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