2011-04-Natural Gas Demand and Environmental Policies

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Copyright 2011 The Brattle Group, Inc. www.brattle.com

Natural Gas Demand

AndEnvironmental PoliciesPrepared for

Northeast Gas Association

Regional Market Trends Forum

Presented by:Steve Levine

The Brattle Group

44 Brattle StreetCambridge, Massachusetts

April 13, 2011


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Agenda

Introduction: Recent EIA Forecasts, Overview of U.S. Gas Demand

Prospects for Gas Demand

Positive factors

Coal plant retirements due to EPA regulations

Cap and trade programs (carbon price)

Natural Gas Vehicles

Negative factors

Energy efficiency

Industrial demand destruction

Renewables

Availability of other low carbon generation technologies


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Uncertainty in Gas Demand Forecasts

Significant shift in EIA outlook over the past year

More bullish on industrial gas demand (+3 Bcf/d in 2020) and electricsector gas demand (+3 Bcf/d in 2020)relative to prior year forecast

Lower price forecast ($1.50/MMBtu on average 2010-2020)

EIA Forecasted Natural Gas Consumption

56

58

60

62

64

66

68

70

2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020

Bcf/d

Source: EIA.

EIA 2010 Reference Case

(No CO2 Policy)

EIA 2011 Reference Case

(No CO2 Policy)


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Uncertainty in Northeast Gas Demand Forecast

EIA also more bullish on Northeast gas demand for both New England(+0.5 Bcf/d in 2020) and Mid-Atlantic (+0.8 Bcf/d in 2020) relative toprior year forecast

Current projection forecasts 2010-2020 growth of 0.3 Bcf/d in NewEngland and 0.5 Bcf/d in Mid-Atlantic

EIA Forecasted Natural Gas Consumption

(New England and Middle Atlantic)

2010 AEO Reference

Case

2011 AEO Reference

Case

7.0

7.5

8.0

8.5

9.0

9.5

10.0

10.5

2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020

Bcf/d

Source: EIA.

Middle Atlantic includes NY, NJ, PA.


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Overview of U.S. Gas Demand

2010 demand ~66 Bcf/d, non-electric demand ~40 Bcf/d

Flat demand in past decade

Historically, demand has grown ~1.1% per year (1990-2010)

U.S. Gas Demand

-

10.0

20.0

30.0

40.0

50.0

60.0

70.0

2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010

Bcf/d

Electric

Power

Industrial

Commercial

Residential

Other5.5

20.2

18.0

8.8

13.6

2010 Total Gas Demand =

Source: EIA and Short Term Energy Outlook for 2010.

66.0


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Overview of Northeast Gas Demand

Demand ~ 7 Bcf/d, non-electric demand ~ 4.5 Bcf/d

Flat demand in past decade

Northeast Gas Demand

Residential

Commercial

Industrial

Electric Power

0.0

1.0

2.0

3.0

4.0

5.0

6.0

7.0

8.0

2001 2002 2003 2004 2005 2006 2007 2008 2009

Bcf/d

Source: EIA. States include CT, MA, ME, NH, NJ, NY, RI, VT.

2009 Total NE Demand = 7.0

2.4

0.6

1.6

2.3


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Overview of Environmental Pressures

EPA is in the process of promulgating a series of new regulations tocontrol (or tighten existing controls of) the following effluents:

Criteria air pollutants especially NOx, ozone, SOx, and particulates

Hazardous air pollutants (HAPs), especially mercury

Cooling waterimpacts of intake structures

Coal combustion byproducts ash disposal pathways

Greenhouse gases (GHG) primarily CO2

from new and modifiedsources

Or, potential legislation in the future to implement a federal climate policy

Emerging regulations will require existing coal units to either retrofit(install environmental control equipment) or retire

Near-term compliance with SOx, NOx and mercury regulations

Coal ash and water regulations (316b) may be delayed, and GHG rulesmay be litigated


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EPA Rules and Timelines

Clean Air Transport Rule (CATR) Regulates NOx and SOx emissions frompower plants in 31 states

Proposed in 2010; Final rule June 2011; Implementation starts 1/1/2012

Reduces SOx emissions by 71%, NOx emissions by 52% (relative to 2005 levels) Many existing units will need to add expensive scrubbers and SCRs or retire

Mercury /HAPs Requires oil and coal-fired power plants to install controls:Maximum Achievable Control Technology (MACT)

MACT rule proposed in March 2011; Final Rule November 2011 Compliance 3-4 years after final rule (2014-2015)

Coal Ash Regulates coal ash disposal Final rule in 2011 Implementation 2014-2018

Clean Water Act Regulates cooling water intake structures Proposed March 2011; Final Rule July 2012 Compliance possibly up to eight years after final rule (2020)


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Announced Coal Plant Retirements

Several coal plant owners have announced retirement of coal units between2010-2020

Retirements offset by new coal units coming on-line between 2009-2012

(approximately 16 GW) Few retirement announcements in Northeast Salem Harbor (MA) may retire in

2014; AES Thames (CT) has declared bankruptcy (but has not retired)

Announced Coal Plant Retirements

Owner Capacity (MW)

Exelon 732

TVA 1,142

Duke 1,000 - 2,000

Progress 1,485

Black Hills 42

Xcel 1,059

PGE 585

APS 560

Total 6,605 - 7,605


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Brattle Coal Plant Retirement Study Key

ConclusionsA requirement to install scrubbers and SCRs on coal units by 2015 would result in 40-55GW of economic retirements beyond the 6 GW projected without new mandates

Another 11-12 GW of coal units would retire ifcooling towers (@ $200/kW) are also mandated

Higher-end of range based on doubling the retrofit costs due to potentially increasing demand for labor and controlequipment or due to site-specific constraints

$70-130 billion investment on scrubbers and SCRs (for 187 GW coal capacity) would beneeded to comply with the EPA mandates

An additional $30-50 billion compliance investment would be needed ifcooling towers are also mandated.

Most of the economic retirements are with merchant units (which rely on marketrevenues), in contrast to regulated units whose retirement decisions are based on the

cost of replacement power

U.S. COAL PLANT CAPACITY VULNERABLE TO RETIREMENT BY 2020

Percentage of

Coal

Capacity

Total

CapacityGW GW GW Billion

Nationwide Total 40-55 11-12 50-66 16-21% 5-7% $101-181

Merchant 37-48 8-10 47-56 64-76% 11-14% $5-7

Regulated 3-6 1-4 3-10 1-4% 1-2% $94-177

RetrofitCapital

Costs for

Compliance

Retirementswith Scrubber

& SCR

Mandate

AdditionalRetirementswith Cooling

Tower Mandate

Total

Retirements


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Potential Coal Plant Retirements under EPA Regulations

A mandate by EPA to install scrubbers and SCRs by 2015 could resultin 40-55 GW of coal plant retirements nationwide. Most of theretirements would be in NERC regions RFC, SERC and TRE (ERCOT)

1-2 GW

12-19 GW

2-3 GW

1 GW

9-12 GW

2-3 GW

10-11 GW3-4 GW


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Potential Gas Demand Impacts of EPA Regulations

A mandate by EPA to install scrubbers and SCRs by 2015 could resultin a 5.8 Bcf/d increase in gas demand nationwide (less withrenewables)

0.3 Bcf/d

1.5 Bcf/d

0.5 Bcf/d

0.1 Bcf/d

0.7 Bcf/d

0.1 Bcf/d

2.3 Bcf/d0.4 Bcf/d


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Potential Impact of CO2 Price on Coal and

Gas Dispatch Uncertainty with respect to climate policies creates additional risks for coal plantsa CO2

price under cap and trade would put additional pressure on coal plant economics

$1/ton CO2 $1/MWh of coal-fired, $0.40/MWh of gas-fired power cost

Dispatch switching takes place between gas and coal starting around $10/ton CO2 (at $6

gas price) and eliminates conventional coal by ~$80/ton

Efficient Gasdisplaces

Inefficient Coal

Efficient Gasdisplaces Efficient

Coal

Ranked byGeneration

Cost

Inefficient Gasdisplaces Efficient

Coal

Efficient Coal

Inefficient Coal

Efficient Gas

Inefficient Gas

0

20

40

60

80

100

120

140

160

180

200

0 10 20 30 40 50 60 70 80 90 100 110 120

CO2 Price ($/ton)

DispatchCost($/MWh)

Gas price: $6/MMBtu

Coal price: $1.7/MMBtu

Efficient Coal Heat Rate: 9,000 Btu/kWh

Inefficient Coal Heat Rate: 14,000 Btu/kWh

Efficient Gas Heat Rate: 7,000 Btu/kWh

Inefficient Gas Heat Rate: 9,000 Btu/kWh

Dispatch Switching between Existing Coal and Gas Power Plants


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$70/ton CO2 priceincreases gas useby 155% (coaldecreases by

44%)16

18

20

22

$30/ton CO2increases gas useby 65% (coaldecreases 22%)

Electric sector gas demand could increase significantly with CO2 price, depending on thegas price

With $5 gas, a $30/ton CO2 price (2020) increases electric gas use by about 65%, from 7to 11.5 Bcf/day

With $7 gas, no significant change in gas use at $30/ton CO2

Coal-to-Gas Dispatch Switching Under CO2 Price

ISO regionscover 60% of

U.S. gas (411GW) and coal(317 GW)generationcapacity.

0

2

4

6

8

10

12

14

$5 Gas $7 Gas

Bcf/Day

$70 CO2

$30 CO2

$0 CO2

Daily Average Gas Use in All ISO Regions


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U.S. Gas DemandResidential/Commercial

Little growth in residential/commercial demand since 1980

Declining residential use per customer due to improved appliance and buildingefficiencies, and impact of higher prices

Gas energy efficiency budgets more than quadrupled recently, from $250 millionin 2006 to over $1.1 billion in 20103

Gas energy efficiency budgets in New England/NY/NJ ~ $350 million in 2010

3 Source: Consortium for Energy Efficiency

Residential Consumption Per Customer

60.0

65.0

70.0

75.0

80.0

85.0

90.0

95.0

100.0

1990 1995 2000 2007 2009

Mcf/Customer

Source: EIA.

Residential/Commercial Gas Demand Since 1980

0.0

5.0

10.0

15.0

20.0

25.0

1980 1985 1990 1995 2000 2005 2010

Bcf/d

Residential Commercial



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Industrial/Electric Generation Demand Since 1997

-

5.0

10.0

15.0

20.0

25.0

30.0

35.0

40.0

45.0

1997 2000 2003 2006 2009 2010

Bcf/d

U.S. Natural Gas Deliveries to Electric Power ConsumersU.S. Natural Gas Industrial Consumption


U.S. Gas DemandIndustrial/Electric Power

Chemicals 30%

Petroleum/Coal 14%

Primary Metals 10%

Food 11%

Paper 8%

Other 27%

Historically, growth in electric power use of gas has roughly offset the decline in industrial load

EIA now projecting industrial gas demand growth of 4.5 Bcf/d by 2020 due to economicrecovery, growth in combined heat and power, and low gas prices

Low gas price assumption is keywill prices stay low (in a shale gas world) if electric sectordemand increases substantially in next 10 years? How would a CO2 price impact industrialdemand for gas?


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Gas Demand and Renewables/Conservation

29 states have a renewable portfolio standard (7 states with non-binding goals) Renewable energy development starting to reduce gas demand for power generation

Renewables are must-take, pushing out whatever fuel is on the margin In many regions, gas predominantly on the margin (e.g., 90% of the time in ERCOT)

15,000 MW of wind energy added in 2009-2010 (EIA forecasts no wind additions after

2012) Total renewable energy generation (including hydro) expected to grow from 370 billion

kWh in 2010 to 500 billion kWh in 2015 (50 billion kWh ~1 Bcf/d of gas demand) 23 states have energy efficiency resources standards (% reduction targets in energy

use) also reduce gas demand if gas on the margin

Annual Wind Capacity Additions

0.0 0.00.0

8.4

9.9

5.1

4.1

10.0

0.0

2.0

4.0

6.0

8.0

10.0

12.0

2008 2009 2010 2011 2012 2013 2014 2015

GW

Sources: American Wind Association (for 2008-2010), and EIA (for 2010-2013).

Actual Projected

Yearly Growth in Electricity Generation from Renewables

Wind

Hydropower

Other

0.0

10.0

20.0

30.0

40.0

50.0

60.0

2008 2009 2010 2011 2012 2013 2014 2015

Billion

kWh

Source: EIA.Note: In 2010, increased wind generation of 20 billion kWh was offset by hydro declines of 30 billion kWh (hydro declines not depicted).

Actual Projected


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Renewables in New England

Renewables activity in NE/NY/NJ

1.4 GW of wind added over last 5years

3.7 GW of wind capacity in NE ISOQueue, 7.0 GW in NY ISO Queue

Northern Pass project proposes to

access 1.2 GW of excess HQ hydrogeneration

Competition with natural gas

5.2 GW of NGCC capacity in NE ISOQueue, 4.9 GW in NY ISO Queue

Current NPCC reserve margin ~ 23%

Renewable Portfolio Standards and Goals

Connecticut 27% by 2020

Maine 30% by 2010

10% new by 2017

8 GW wind goal by 2030

Massachusetts 15% new by 2020,

then 1% annually

2 GW wind goal by 2020

New Hampshire 23.8% by 2025

New Jersey 22.5% by 2020

New York 30% by 2015

Rhode Island 16% by 2020

Vermont 20% by 2017

Source:

FERC Market Oversight Report, October 2010


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Other Low Carbon Technologies (beyond 2030)

Will there be a nuclear revival in the U.S.? U.S. NRC now actively reviewing 12 license applications for 20 new

nuclear units

Lack of carbon price will hinder development Loan guarantees and subsidies needed for new nucleardevelopment

Impact of recent events in Japan on U.S. nuclear relicensing

Carbon capture and sequestration In the RD&D phasetiming of CCS deployment very uncertain Lack of carbon price will hinder development If focused on coal, would limit gas demand growth But gas CCS also possible

Given these limitationsgreat opportunity for natural gas inthe electric power sector over next 20+ years (and anopportunity to lower CO2 emissions)


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Long-Term Prospects for Gas Demand

Gas demand and prices affected by multiple, sometimesconflicting, pressures resulting from

Regulatory policies related to CO2, renewables, and energy efficiency

Availability of low carbon technologies (CCS and nuclear) CO2 prices (prices for allowances and offsets) Potential for coal plant retirements due to EPA regulations (SO2, NOX, etc.)

Among these positive and negative influences:

(+) Coal plant retirements(+) Coal to gas electric dispatch substitution under cap & trade

(+) Gas back-up for renewables

(-) Renewables displacing gas in electric sector

(-) New generation technologies (nuclear, CCS in outer years)

(-) Non-electric gas demand reaction to increasing prices

(-) Energy efficiency for gas and electricity

Volatility results from opposing pressures at different times


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Summary

Coal plant retirements due to SO2, NOX and other potential EPAregulations could result in substantial gas demand growth thisdecade and result in upward price pressures

Natural gas vehicles boost gas demand only in substantialdeployment scenario with policy intervention

Potential challenges to natural gas demand growth:

Emphasis on renewables and electricity conservation reduces gasdemand in regions where gas is marginal fuel for electricitygeneration

Non-electric gas demand growth likely to be low due to retailconservation programs and price impacts of CO2 policy that may

negatively impact industrial gas demand

High CO2 prices needed for coal to gas switching under cap andtrade may not be forthcoming this decade

Long-term gas demand growth more likely if deployment of

renewables, nuclear and coal w/CCS is limited


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The Brattle Group

The Brattle Group provides consulting and expert testimony in economics,finance, and regulation to corporations, law firms, and governments aroundthe world.

The majority of our engagements are related to energy and utility regulationin such areas as:

Climate Change Policy and Planning

Cost of Capital

Demand Forecasting and WeatherNormalization

Demand Response and EnergyEfficiency

Electricity Market Modeling

Energy Asset Valuation Energy Contract Litigation

Environmental Compliance

Fuel and Power Procurement

Incentive Regulation

Rate Design, Cost Allocation, and RateStructure

Regulatory Strategy and LitigationSupport

Renewables

Resource Planning

Retail Access and Restructuring

Risk Management Market-Based Rates

Market Design and Competitive Analysis

Mergers and Acquisitions

Transmission


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Additional Reading

"Potential Coal Plant Retirements Under Emerging EnvironmentalRegulations, by Metin Celebi and Frank C. Graves, The Brattle Group, Inc.,December 2010.

"Managing Natural Gas Price Volatility: Principles and Practices Across theIndustry," by Steven H. Levine and Frank C. Graves, The Brattle Group, Inc.,

prepared for the American Clean Skies Foundation, forthcoming in Spring

2011.

"Prospects for Natural Gas Under Climate Policy Legislation: Will There Be a

Boom in Gas Demand?," by Steven H. Levine, Frank C. Graves, and MetinCelebi, The Brattle Group, Inc., March 2010.


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Speaker Bio and Contact Information

Steve LevinePrincipalCambridge, Massachusetts

[email protected]

Steve Levine is an expert in the economics of North American natural gasmarkets and global liquefied natural gas (LNG) markets. He has nearly twentyyears of experience as a consultant providing advice, expert testimony, andlitigation support to clients in the natural gas and electric power industries. Hefocuses on matters involving pricing/ratemaking, market manipulation,

procurement and risk management decisions, and damage claims in energycontract disputes. He has submitted expert testimony before the Federal EnergyRegulatory Commission and the California Public Utilities Commission, as wellas in state court. He received his M.B.A. from Columbia University.

The views expressed in this presentation are strictly those of the presenter(s) and do not necessarily state or reflect the views ofThe Brattle Group, Inc.

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