Future Outlookfor the

Power Sector

David Owens Executive Vice President

Changing Electric Utility Landscape

Utility industry has embarked on a major investment cycle, driven by the need to address: Generation, Transmission, and Distribution to ensure reliability Energy Efficiency and deploying new technologies (SG,

renewables) Significant Environmental CAPEX

Increasing concerns about the Environment has Changed our Power Supply Mix Short –term: Rely on Energy Efficiency, Renewables, and Natural

Gas Medium-term: Targets should be harmonized with the

development and commercial deployment of advanced technologies and measures (e.g., Nuclear Energy, Advanced Coal Technologies with Carbon Capture and Storage, Plug-in Electric Vehicles, and Smart Grid)

We are no longer a declining cost industry

Changing Electric Utility Landscape (2)

An Increasing Amount of Rate Cases to Pay for Investments

Our Workforce is Aging and our Children are Less Educated

The Utility Role for Driving New Technology has become increasingly complicated Current combination of low economic growth, flat

electricity demand growth, deficit concerns and sustained high unemployment is slowing down the deployment of smart technologies including Smart Grid

New Congress with vastly different priorities

Electricity Game Changers

Public Policy Public Policy EnvironmentalEnvironmental

Energy Source Energy Source Shale GasShale Gas

TechnologyTechnologySmart Grid Smart Grid

Japan Nuclear Disaster?

Divergent Forces

Markets/

Technology

Public

Sales/Economic

Recovery

Environmental

Regulations

Congress/States/

FERC

Overview of the Federal Political Landscape

August 10, 2011Brian Wolff

Senior Vice President

2012 Election

2012 election features both the Presidential race and races for control of the Senate

Current Senate ratio: 51 Democrats, 47 Republicans, and 2 Independents who usually vote with Democrats

2012 Election

Democrats must defend 23 seats 15 are solid, likely , or lean Democrat; 8 are toss-ups or

likely Republican

Republicans must defend 10 seats 8 are solid or likely Republican; 2 are toss-ups

Key issues remain the economy and jobs

Political Environment

Jockeying for 2012 election = partisan gridlock in Congress

Public response to Congress:

6% of likely voters rate Congress’ job performance as good or excellent

61% of likely voters think Congress is doing a poor job

(7/26/11 Rasmussen poll )

Political Environment

Public response to President Obama:

23% strongly approve of President Obama’s performance

42% strongly disapprove

Overall, 44% at least somewhat approve and 55% at least somewhat disapprove

(8/1/11 Rasmussen poll)

Debt Ceiling Package

House passed debt ceiling bill by 269-161 vote on August 1; Senate passed bill by 74-26 vote on August 2

Raises debt limit by $400 billion initially; establishes procedures for additional increases (limit eventually raised by at least $2.1 trillion)

Establishes caps on discretionary spending through 2021

Requires House and Senate to vote on balanced budget amendment by end of year

Debt Ceiling Package (cont’d)

Creates a congressional joint committee to propose additional budget savings of at least $1.5 trillion over 10 years

Establishes automatic procedures for reducing spending by as much as $1.2 trillion if legislation by joint committee does not achieve sufficient savings by January 15, 2012

Energy Legislation Outlook

Focus on deficit reduction and increased partisanship makes it unlikely this Congress will consider major energy legislation

House passed several controversial environmental provisions to limit EPA authority – but they won’t get 60 votes in Senate

Senate Energy Committee approved several bills on efficiency, EVs, clean energy development, oil and gas development – unclear whether full Senate will consider

Cyber Security Legislation Outlook

Bipartisan support for cyber security legislation – despite gridlocked Congress

President Obama’s proposal in May provided additional guidance and push for Congress to act

Challenges include navigating 14 committees in House and Senate with jurisdiction

House Speaker John Boehner appointed GOP task force to develop a framework for comprehensive, multi-sector bill

Senate Majority Leader Harry Reid will use a draft bill with language from Commerce and Homeland Security Committees as base for new bill - and use President’s proposal to arbitrate differences among other committees involved

Cyber Security Legislation Outlook

If Congress cannot produce a comprehensive bill, a sector-by-sector approach may be taken Most likely to move would be utility-only bill focused on

electric grid security EEI supports a comprehensive approach due to the

interdependent nature of critical infrastructure

Strong cyber security legislation should: Limit scope of any new federal emergency to imminent

threats against truly critical assets Ensure emergency orders come from only one government

entity Include all critical infrastructure sectors in a cyber security

regime Encourage more information-sharing between gov’t and

industry

Generation Update

August 10, 2011Richard McMahon

Vice President, Energy Supply and Finance

Capital Expenditures

August 10, 2011Aaron Trent

Manager, Financial Analysis

Industry Capital Expenditures

p = projected

($ Billions)

Source: SNL Financial, company reports and EEI Finance Department

Investment by Category

Industry committed to reliability, making needed investments in generation, transmission, smart grid/distribution and environmental controls

Prospective EPA rules could increase total capex by 30% annually

2010 Capital Expenditures

41%

6%14%

24%

11%4%

Generation Environment TransmissionDistribution Gas-Related Other

By 2030, the electric utility industry will need to makeinfrastructure investments of $1,830 Billion

This level of investment is nearly triple the US Shareholder –OwnedElectric Utilities’ current net plant value of roughly $650 billion (3/3 1/11 =$748 B)

951

298

582

0

500

1,000

1,500

2,000

2009 Projected

Distribution

Transmission

Generation

$654B

$1,830B

Source: Transforming America’s Power Industry, The Brattle Group, November 2008

Capex - Looking Out 20 Years

Rate Case Volume Remains High

* 2011 includes activity through June 30, 2011.

Awarded ROEs Remain Low

0%

20%

40%

60%

80%

100%

1970 1980 1990 2000 2010

US Electric IOUs Rating History

1970 – 2010

S&P Credit Ratings Distribution, U.S. Shareholder-Owned Electric Utilities

AAA AA+, AA, AA-

A+, A, A- BBB+, BBB BB+, BB, BB-, B+, B, B-, CCC+

BBB-

4%

22%

46%

27%

1%

Source: Standard & Poor’s, Macquarie Capital

Changing M&A Trends

Prior mega mergers focused on increasing scale and scope of competitive generation operations, with a multi-regional focus

Recent merger announcements: Focus on creating a larger regional footprint for regulated utility

operations Upsize the balance sheet to aid with future environmental compliance,

allow for larger capex projects such as nuclear, transmission, etc.

Local economy and Jobs impact remain as key factors

Complementary generation fleets, renewable mandates

Ratings agency reactions will be watched closely

M&A Themes in 2010-11

Feb. 11 – FE-AYE: Improve generation mix, operating performance, transmission growth, financial strength

Apr. 28 – PPL-E.ON U.S.: Increase regulated focus March ’11 – announces purchase of E.ON AG’s U.K. Power Grid

Oct. 18 – NU-NST: Leverage NSTAR’s financial strength into Northeast Utilities’ transmission growth ops

Jan. 10, 2011 – DUK/PGN – greater financial strength for environmental capex, need greater efficiency

Apr. 28, 2011 – EXC/CEG – combine generation and customer-facing businesses; improve generation mix and financial strength

Tax Reform and Electric Utilities

Potential Trade-off – Lower corporate rate with less industry specific tax incentives.

Accelerated Depreciation

Dividend Tax Rates

Expire at end of 2012

Maintaining parity with Capital Gains remains key

FERC Update

James Fama Vice President, Energy Delivery

Overview of Presentation

Transmission Transmission Incentives and Investment Transmission Planning & Cost Allocation

Order

Reliability

Transmission Incentives and Investment

Current Policy Implementing Section 219 of the FPA

Articulated in 2006 in Order No. 679

Companies can seek incentives for projects that improve reliability or reduce congestion

FERC evaluates incentive requests on a case-by-case basis and determines whether resulting rates are J & R

Companies must show that:

Project improves reliability or reduces congestions

That there is a nexus between incentives sought and risks and challenges of the project

EEI Response

Transmission is hard to build and provides societal benefits

Incentive policy has resulted in transmission development which in turn ensures reliability, reduces congestion, facilitates renewable and other generation

Incentives or sufficient ROE are necessary to obtain capital necessary for development

Notice of Inquiry

Promoting Transmission Investment Through Pricing Reform NOI issued May 19, 2011

Comments due August 25, 2011 NOI states that FERC has received over 75

applications for incentives for investment in over $50 billion in proposed transmission infrastructure

Purpose of NOI to seek comment on what steps the FERC could take to ensure that incentives encourage development of transmission policy consistent with statutory obligations

Transmission Investment on the Rise

Actual and Planned Transmission InvestmentBy Shareholder-Owned Utilities (2004-2013)

Transmission Projects: At A Glance

Represents $61.2 Billion (nominal dollars) in transmission investment: 2010 - 2021

Highlights 26 EEI Member Companies and over 100 projects

$39.5 Billion in Transmission Supporting the Integration of Renewable Resources

$41.1 Billion in Interstate Transmission

Transmission Planning & Cost Allocation

Final Rule – Order 1000

Issued July 21, 2011

Addresses – Transmission Planning

o Public Policy Considerationo Regional o Inter-regionalo Right of First Refusal Provisions (“ROFR”)o Reliability

Cost Allocation

Highlights

Applies to all regions

Requires regional planning and inter-regional coordination

No requirement for interregional transmission plan

Establishes broad criteria. Allows regions the flexibility to meet the criteria through regionally developed plans

Allows non-incumbents to submit proposals and receive cost recovery on same basis as incumbents if project selected through regional planning process

Highlights – Transmission Planning

Emphasis on regional planning and identifying least cost solutions

Require consideration of public policy goals reflected in state or federal law

Federal ROFR provisions must be removed from tariffs for facilities selected in a regional plan for cost allocation purposes

Protections to assure: Needs met Delays avoided Reliability protected

Highlights – Transmission Planning cont.

Incumbent public utilities retain ROFR for: Local upgrades for which regional cost allocation not

sought Upgrades to existing assets Projects on existing right of way

Requires adoption of “backstop” mechanism to ensure that delays in development of transmission facilities will not prevent incumbents from complying with reliability needs and service obligations.

Not impact state authority (e.g. siting, construction)

Highlights - Cost Allocation

Regional and inter-regional cost allocation method must meet six principles Costs allocated “roughly commensurate” with benefits No involuntary cost allocation to non-beneficiaries If benefit-cost ratio is used, must not be so high to exclude

facilities with significant net benefits Costs allocated solely within region or regions unless those

outside voluntarily assume costs Method and data requirements must be transparent Different method may be chosen for different types of

facilities ( e.g., reliability, congestion relief, public policy)

EEI Thoughts

Support flexibility and emphasis on allowing regions to develop their own plans

Support retention of the ROFR

Avoid making planning process longer

Still evaluating reliability impacts

Reliability

Highlights: NERC and Section 215 implementation

NERC continues to reflect strong industry commitment to bulk power system reliability

Changes in mandatory standards are a significant cost driver

Managing compliance is focus of senior management

Challenging issues ahead Balancing reliability risks and costs to address those risks

Critical Infrastructure Protection standards and implementation

Building effective government-industry relationships

Redesigning compliance and enforcement

Smart Grid and Technology Update

David Owens Executive Vice President

Smart Grid

Why Do We Need A Smarter Grid?

(Grid Modernization)

Smart Grid Implementation Challenges There is tremendous and growing

pushback from customers and regulators to the smart meter. It focuses on Accuracy of meters Health concerns: Radio Frequency Exposure Who decides whether a meter should be installed? Cost of installation Access to information: privacy intrusion Impact “at risk” customers Dynamic pricing Customers are not seeing immediate benefits

Smart Grid Implementation Challenges (Cont’d)

We need to get ahead of the resistance to shape and change the discussion

Collaboration and customer engagement initiatives are crucial Critical Consumer Issue Forum EEI /CenterPoint Member Workshop, “Transforming the

Utility Customer Relationship: The New Paradigm” Smart Grid Communications Campaign Advisory

Committee

Smart Grid Interoperability Standards

Background

Per EISA, Congress and the Administration stress urgent need for interoperability protocols and standards to ensure smart grid functionality and interoperability in interstate transmission and wholesale electricity markets

EISA defined responsibilities for two Federal Agencies:

NIST was directed to coordinate development of communication protocols and standards to achieve an interoperable smart grid; and

FERC was charged with instituting a rulemaking to adopt the standards necessary to ensure smart grid functionality and interoperability once it determined “sufficient consensus” had been achieved in the standards identification and development process

Current Activity

October 2010, NIST identified five families of standards that help to enable efficient and secure exchanges of information within and across smart grid domains.

Commission found on July 19, 2011 that there was insufficient consensus on the five standards and declined to open a rulemaking.

Smart Grid Interoperability Panel (SPIG) will continue to identify gaps and make recommendations to Standards Development Organizations to ensure any standards utilized to implement the Smart Grid are interoperable.  Regardless of whether the standard impacts the transmission, distribution, consumer or other domains

EEI’s Involvement

Participate in SPIG process to ensure that standards that impact the development and implementation of the Smart Grid are workable. 

 Educate consumers and regulators (both federal and state) on the benefits of implementing Grid modernization technologies and the economic feasibility of enabling Smart Grid applications. 

Investigate, evaluate and implement Grid modernization technologies to ensure the reliability of the Grid that maintains customer satisfaction levels and enables them to be more energy efficiency and to better utilize alternative energy solutions.      

Update on EPA Regulation and

Implications for the Utility Industry

Quinlan Shea Vice President, Environment

and

Daniel ChartierDirector, Environmental Markets and Air Quality

Programs

Outline

I. Overview

II. EPA rules – status and next steps Utility HAPs MACT NAAQS Cross-State Air Pollution Rule 316(b) Coal ash GHGs

III.Implications

Overview

*Includes generation by agricultural waste, landfill gas recovery, municipal solid waste, wood, geothermal, non-wood waste, wind, and solar.

** Includes generation by tires, batteries, chemicals, hydrogen, pitch, purchased steam, sulfur, and miscellaneous technologies.

Sum of components may not add to 100% due to independent rounding.

Source: U.S. Department of Energy, Energy Information Administration, Power Plant Operations Report (EIA-923); 2009 preliminary generation data.

May 2010

© 2010 by the Edison Electric Institute. All rights reserved.

Different Regions of the Country Use Different Fuel Mixes to Generate

Electricity

58

Coal Units by Age, Capacity and Emissions

U.S. Generating Units, 10 Year Increments

Age of Units*

Generating Units

Total Nameplate Capacity

Total Net Generation Year 2008

Total CO2 Emissions Year 2008

Total SO2 EmissionsYear 2008

Total NOX

Emissions Year 2008

#Percent of Total

GWPercent of Total

GWHPercen

t of Total

MTonsPercen

t of Total

TonsPercent of Total

TonsPercent of Total

0-10 Years 16 1.4% 5.3 1.6% 19,788 1.1% 28.7 1.4% 18,083 0.2% 13,779 0.5%

11-20 Years 64 5.8% 14.9 4.5% 78,261 4.2% 78.1 3.8%137,80

31.9%

108,115

3.8%

21-30 Years 186 16.7% 86.1 26.1%541,40

829.0% 615.0 29.6%

1,336,033

18.0%763,20

726.9%

31-40 Years 238 21.4% 122.5 37.1%724,20

638.8% 780.7 37.6%

2,750,025

37.1%1,053,2

5937.1%

41-50 Years 270 24.3% 60.8 18.4%316,02

916.9% 352.2 16.9%

1,879,152

25.4%533,03

818.8%

51-60 Years 304 27.3% 39.3 11.9%187,47

310.0% 220.7 10.6%

1,265,388

17.1%356,90

212.6%

61-70 Years 30 2.7% 0.9 0.3% 1,166 0.1% 2.5 0.1% 19,223 0.3% 6,554 0.2%

> 70 Years 4 0.4% 0.0 0.01% 50.0003

%0.1

0.004%

87 0.001% 484 0.02%

Coal Unit Totals 1,112 100.0% 329.95 100.0%

1,868,336

100.0% 2077.9100.0

%7,405,7

94100.0%

2,835,339

100.0%

Source:  Ventyx, Inc.—EV Suite MTon = million tons * Does not include units that came online in 2009

Power Plants Reduce Emissions Despite Increasing Electricity Demand

Power Sector Objectives

Minimize economic impacts to consumers

Continue environmental improvements

Maintain system reliability

Maintain fuel diversity options

Develop and deploy new technologies

Obtain access to capital and cost recovery

Negotiate myriad political landscapes

Update on EPA Regulations

Possible Timeline for Environmental Regulatory Requirements for the Utility Industry

Ozone (O3)

PM/PM2.5

'08 '09 '10 '11 '12 '13 '14 '15 '16 '17

Begin CAIR Phase I

Seasonal NOx Cap

HAPs MACT Proposed

Rule

Revised Ozone NAAQS

Begin CAIR Phase I Annual

SO2 Cap

-- Adapted from Wegman (EPA 2003) Updated 05-31-2011

Proposed PM-2.5 NAAQS

Revision

PM Transport

Rule

SO2 Primary NAAQS

SOX/NOxSecondary

NAAQS

NO2

Primary NAAQS

SOx/NOx

CAMR & Delisting

Rule vacated

Hg/HAPS

Transport Rule Proposal Issued (CAIR Replacement)

HAPs MACT Final Rule Expected

CAIR Vacated

HAPS MACT Compliance 3 yrs After Final Rule

CAIR Remanded

CAIR/Transport

Begin CAIR Phase I

Annual NOx Cap

316(b) Proposed

Rule

316(b) Final Rule

Expected316(b) Compliance1-8 yrs After Final rule

Effluent Guidelines

Proposed RuleExpected

Water

Effluent GuidelinesFinal Rule Expected

Effluent GuidelinesCompliance 0-5+ yrs

After Final Rule

Begin Compliance Requirements

Under Final CCB Rule (ground

water monitoring, double liners,

closure, dry ash conversion)

Ash

Proposed Rule for CCBs

Management

Final Rule for CCBs

Mgmt

Final Transport Rule Expected

(CAIR Replacement)

CO2

CO2 Regulation

(PSD/BACT)

Ozone NAAQS

Revision

Transport Rule Phase I

Reductions

Transport Rule Phase II

Reductions

Ozone Transport

Rule

GHG NSPS Proposal

GHG NSPS Final

Expected Final PM-2.5

NAAQS Revision

Utility MACT Proposal

Proposed rule published in Federal Register May 3, 2011; comments due August 4

Final rule published by November 16, 2011 (required by consent decree)

Rule will require most coal plants to upgrade existing controls and/or install additional controls: Acid gases: wet or dry scrubbers; DSI (trona, etc.) Mercury: activated carbon injection (ACI) Non-mercury metals: fabric filters (baghouses)

As a result, some plants will close or re-power

Affected Facilities

Approximately 1,350 EGUs at 525 facilities

Approximately 1,200 coal-fired boilers at approximately 450 facilities Coal-fired EGUs include units that burn coal, coal refuse, or a synthetic gas

derived from coal either exclusively, in any combination together, or in any combination with other supplemental fuels (e.g., petroleum coke, tire-derived fuels)

Bituminous coal ~ 50% of coal generation Subbituminous ~45% of coal generation Lignite ~ 5% of coal generation

Approximately 150 oil-based boilers at approximately 75 facilities Approximately 1% of nationwide net generation

EPA expects most facilities would install technologies to comply

Utility MACT Proposal

Normal MACT timing: 3 years after final rule effective date (~January 2015)

EPA Administrator (or approved State Program) can grant 1-year extension if more time “necessary for the installation of controls” Extensions granted on case-by-case basis

Presidential exemption: not more than 2 years if:1) technology to implement standard is not available

and

2) in national security interests to do soo Additional 1-year extensions available

EEI Utility MACT Comments: Key Messages

EEI commends EPA for incorporating some flexibility in the proposal—such as the use of surrogates, work practice standards and emissions averaging—to help companies meet the proposed standards.

There are a number of areas where the proposed standards (including many of the compliance, testing and monitoring requirements) are unduly restrictive or inconsistent with § 112 of the CAA, or could benefit from additional flexibility afforded to EPA under the CAA.

Our overarching concern is the limited timeframe for implementation of, and compliance with, the proposed rule.

EEI Unity MACT Comments: Substantive Concerns

EPA should establish a single, category-wide filterable particulate matter (PM) emissions standard and designate filterable PM—not total PM—as a surrogate for the non-mercury metals standard.

Dry sorbent injection (DSI) will be a useful and cost-effective control tool for many units, but it is not a viable option for all coal-based units for compliance with the acid gas standard.

The mercury standard must be recalculated because it was not established as the average of the best-performing 12% of existing sources, but rather was based on an unrepresentative sample group.

EEI Utility MACT Comments: Substantive Concerns (2)

EPA’s approach to basing new unit standards on a hypothetical “ideal” unit that has never operated is inconsistent with CAA § 112(d)(3).

Many of the proposed measures for demonstrating compliance impose unnecessary burdens and excessive costs in contravention of the President’s recent Executive Order No. 13563.

EEI urges EPA to allow work practice standards to apply during periods of startup and shutdown (SS), as the agency has done in the Boiler MACT rule.

EEI Comments: Substantive Concerns (3)

EEI urges EPA to allow broad emissions averaging as an alternative compliance mechanism to provide regulatory flexibility and decrease costs.

Many of EPA’s proposed compliance, testing and monitoring requirements are confusing, inflexible or costly and would yield little benefit.

EEI encourages EPA to recognize investments made for emissions reductions consistent with state HAPs regulations.

National Ambient Air Quality Standards (NAAQS)

NAAQS continually ratcheted down over time Ozone – 1997, 2008, 2011, 2014 PM 2.5 – 1997, 2006, 2012 “Transport Rule” to address 1997 and 2006 standards

New 1-hour NO2 and SO2 standards in 2010 New ozone and PM standards in 2011 and 2012,

respectively, will drive additional new Transport Rules

State Implementation Plans Interstate transport – state SIP revisions & EPA rules In-state sources

Health vs. "secondary” environment/welfare standards

Cross-State Air Pollution Rule (proposed as Transport Rule,

replaces CAIR) Final rule signed by Administrator July 6, 2011

(expected to be published in Federal Register July 21, 2011) Affects power companies in 27 eastern states Emission budgets for NOX and/or SO2 (both for most states)

Supplemental proposal (July 11) to add NOX ozone season requirements for IA, KS, MI, MO, OK, WI (OK = 28th state)

Reduction requirements must be met in 6 and 30 months (January 1, 2012 and January 1, 2014)

Provides only limited long-term certainty Requirements to be superseded by subsequent “Transport Rules”

addressing 2011 ozone standards and 2012 PM standards

Cross-State Air Pollution Rule (2)

Cross-State Air Pollution Rule (3)

Changes for individual states Final rule includes TX in annual NOX and SO2 program Three states removed in final rule: CT, DE, and MA (plus D.C.) FL and LA removed from annual NOX and SO2 program

“Air quality-assured allowance trading” Allows unlimited in-state and limited inter-state trading Limits on inter-state trading reduced Allowances from previous programs not carried over (as proposed)

Most state emissions budgets reduced, some significantly, from proposed rule

Total region-wide SO2 budgets are about 15 percent lower than proposed

Net impact of less restrictive limits on trading and lower emission budgets – most states have lower allowable emissions

Separate SO2 Control Groups

Cooling Water Intake Structures 316(b)

Proposed rule published on April 20, 2011 Comments due on July 19, 2011

EPA is required to finalize the rule by July 27, 2012

Proposed rule sets separate standards for impingement mortality and entrainment mortality Impingement standard is a national numeric standard – must

be met ASAP or in no more than 8 years (~2020); is not be achievable by EPA recommended technology

Entrainment standard delegated to state permit writers; states will set compliance deadline

Cooling Water Intake Structures (2)

Implications Every facility over 2 MGD withdrawal will likely

have to make modifications Approx 890 steam electric generating facilities

affected Fairly prescriptive rule; with aspects of site-specific

decision-making and cost-benefit analysis for entrainment but no flexibility for impingement

Closed-cycle cooling may not meet all requirements

Other water regulations

Power Plants Affected by Proposed 316(b) Rule

Coal Combustion Residuals

EPA proposed 2 options in June 2010: Subtitle C, “Special” hazardous waste listing

o Beneficial use exempt from regulation Subtitle D regulations

Final Rule expected in 2012; EPA not acting under deadline If regulated under Subtitle C, each state has to

adopt the listing in the hazardous waste regulations before effective (2+ years)

If regulated under Subtitle D, rule goes into effect within 6 months

Coal Combustion Residuals (2)

Once finalized: Have to install groundwater monitors – within 1 year for

existing disposal units; before opening for new units Have 5 years to retrofit surface impoundments with liners or

close pond in 2 years

Must comply by ~2018 if Subtitle D; ~2020 if Subtitle C

Will significantly impact operations: Expedite conversion to dry handling Force closure of older plants where too expensive to comply Facilities with ponds will have to construct wastewater

treatment facilities (which will be impacted by effluent guidelines)

EPA not required to review/revise CCR rule

GHG Regulation

Best Available Control Technology (BACT) reviews Currently in effect for some large sources; EPA issued

guidance in late 2010 Permits issued on case-by-case basis; states are generally

the permitting authority Emission limits based on technologies and efficiency

measures / actions after considering availability, feasibility, cost

Very uncertain as applied for first time to GHGs EPA guidance emphasizes options that improve energy

efficiency

Fuel switching / redefining the source?  

CCS must be considered

GHG Regulation (2)

GHG new source performance standards being developed for fossil power generators, including existing sources

Proposal due in September 2011

New plant standards final by May 2012 Applicable upon proposal

Standards for existing EGU fleet also EPA guidance/procedure for states final by May 2012 States plans due to EPA 9 months later Compliance for EGUs in 2015-16?

Issues: Subcategories (size, type/class), cost, energy efficiency,

CCS, NSR, state programs, etc.

Implications

Clean Air Act & EGUs – Future

The challenge utilities face is unprecedented in terms of: The number of rules

coming due simultaneously The compressed timeframe

for compliance with the near-term rules

The fact that this is continuing – future obligations due to ongoing reviews will result in unknown future reduction obligations

Potential Impacts

Virtually every coal plant will have to be retrofit, retired or repowered Estimates of retirements vary widely Less than half that capacity replaced with new generation Impacts on reserve margins

~34 GW of coal-fired generation retirements have been announced already Take place between 2010 and 2022 Most will be 50-60 years old upon retirement Due to fuel and/or compliance costs, consent decrees,

age, etc. Some will be replaced with natural gas

Potential Impacts (2)

Will require significant amount of investment Impacts on power prices

Key factors and uncertainties: What will final rules look like Litigation Congressional activity Impact of 2012 elections Compliance on or around 2015 Will there be extensions?

What about long-term carbon policy?

Industry’s Predicament

Industry will need to comply with pending EPA regulations on air, water, and coal ash on or around 2015 Will require retrofit, retirement or replacement of substantial

portion of existing coal fleet in short period of time Could impact reliability; need to assess feasibility; regional

differences

Yet, without a long-term carbon policy, industry faces the possibility of uneconomic investments

Need both a satisfactory resolution of the current regulatory challenges and a long-term legislative solution on carbon to allow for the most efficient transition to a cleaner generation fleet

Closing Remarks

David Owens Executive Vice President

Conclusion

THEN… large THEN… large periodic projects periodic projects to support strong to support strong load growth load growth required required infrequent, but infrequent, but major, rate casesmajor, rate cases

NOW… NOW… Ongoing Ongoing investment investment well above well above depreciation depreciation and slower and slower sales growth sales growth requires requires ongoing rate ongoing rate increasesincreases

IllustrativeA Paradigm Shift

CostsCosts

Sales GrowthSales Growth

CostsCosts

Sales GrowthSales Growth

Regulatory LagCapital Investment

Cost of Capital Credit Worthiness

Realized Return

Energy Growth Per Customer

Overview of the Problem

Overview of the Solution:Electric Ratemaking

Innovative regulatory policies and mechanisms: Future test year Tracker/rider mechanisms CWIP in rate base Formula rate plans Decoupling Performance-based rate plans (rate caps, revenue caps)

Strategies to mitigate rate shock, preserve credit worthiness, incent efficient management

Call To Action

New rate regulatory approaches essential to financing needed infrastructure in today’s environment and protecting consumers

There is no standard framework, but there is a fairly standard tool kit of component policies

Rebalancing risk does not mean shifting all the risk to consumers.