Natural Gas Fuel Switching Consequences for Public Power Utilities

2012-2017

Theresa Pugh & J.P. BlackfordApril 27, 2010

APPA Energy & Air QualityTask Force

Retrofit existing fired power plant with Hazardous Air Pollutant Controls (Minimum of Scrubbers or Baghouses Activated Carbon & ESP) and CCS meeting roughly natural gas standard for CO2

Fuel Switch to Natural Gas (and deal with hedging, build new infrastructure & price volatility issues)

Door #1 Door #2 Door #3

Use Clean Air Act’s NSPS for reasonable, available and cost effective energy efficiency (DSM) and renewables [heavy lift]

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Possible Timeline for Environmental Regulatory Requirements for the Utility Industry

Ozone

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

Beginning CAIR Phase I Seasonal NOx Cap

HAPs MACT proposed

rule

Beginning CAIR Phase II Seasonal NOx Cap

Revised Ozone NAAQS

Begin CAIR

Phase I Annual

SO2 Cap

-- adapted from Wegman (EPA 2003) Updated 2.15.10

Beginning CAIR Phase II Annual

SO2 & NOx Caps

Next PM-2.5

NAAQS Revision

Next Ozone NAAQS Revision

SO2 Primary NAAQS

SO2/NO2 Secondary

NAAQS

NO2

Primary NAAQS

SO2/NO2

New PM-2.5 NAAQS Designations

CAMR & Delisting Rule vacated

Hg/HAPS

Final EPA Nonattainment Designations

PM-2.5SIPs due (‘06)

Proposed CAIR Replacement

Rule Expected

HAPS MACT final rule expected

CAIR Vacated

HAPS MACT Compliance 3 yrs

after final rule

CAIR Remanded

CAIR

Begin CAIR

Phase I Annual

NOx Cap

PM-2.5 SIPs due (‘97)

316(b) proposedrule expected

316(b) final ruleexpected

316(b) Compliance3-4 yrs after final rule

Effluent Guidelines

proposed ruleexpected

Water

Effluent GuidelinesFinal rule expected Effluent Guidelines

Compliance 3-5 yrs after final rule

Begin Compliance Requirements

under Final CCB Rule (ground water monitoring, double monitors, closure,

dry ash conversion)

Ash

Proposed Rule for CCBs Management

Final Rule for CCBs Mgmt

Final CAIR Replacement

Rule Expected

Compliance with CAIR

Replacement Rule

CO2

CO2 Regulation

Reconsidered Ozone NAAQS

PM2.5

Retrofit Decisions Driven by HAPs & CAIR Regulations Before CO2

CURRENT CAPITAL COST AND COST-EFFECTIVENESS OF POWER

PLANT EMISSIONS CONTROL TECHNOLOGIES

Prepared by J. Edward Cichanowicz

Prepared for Utility Air Regulatory Group

January 2010

“The capital cost of retrofitting either wet FGD or SCR increased over the recent 4-year period, from about 2005 through 2009, and specifically for a 500 MW plant, by approximately $50-65/kW. This same rate of cost escalation is anticipated to continue for the next 4-6 years, elevating the cost of equipment installed in 2014 and 2015 for a CAIR Phase 2 mandate and the anticipated HAPs MACT rule.”

Update screen shot

Current Natural Gas Pipeline

Current U. S. Natural Gas Storage Maps (no differentiation for storage capacity)

Table 6: Gas Burn by State if Existing Coal-Fired MW Converted to Natural Gas State 2008 Gas

Use Additional Use If Coal Converted

Coal Use As % of Current Gas Use

Alabama 0.404 0.533 132%

Alaska 0.342 0.005 1%

Arizona 0.4 0.246 62%

Arkansas 0.235 0.166 71%

California 2.45 0.018 1%

Colorado 0.505 0.223 44%

Connecticut 0.167 0.026 15%

Delaware 0.048 0.045 94%

Florida 0.943 0.479 51%

Georgia 0.425 0.614 144%

Hawaii 0.003 0.009 316%

Idaho 0.089 0.001 1%

Illinois 1.001 0.739 74%

Indiana 0.551 0.906 164%

Iowa 0.32 0.274 85%

Kansas 0.283 0.23 81%

Kentucky 0.225 0.694 308%

Louisiana 1.239 0.158 13%

Maine 0.061 0.004 7%

Maryland 0.196 0.22 112%

Massachusetts 0.374 0.075 20%

Michigan 0.779 0.542 70%

Minnesota 0.401 0.238 59%

Additional Use If Coal Use As % of

State 2008 Gas Use Coal Converted Current Gas Use

Mississippi 0.355 0.113 32%

Missouri 0.296 0.497 168%

Montana 0.076 0.107 140%

Nebraska 0.168 0.134 80%

Nevada 0.265 0.116 44%

New Hampshire 0.071 0.026 36%

New Jersey 0.615 0.094 15%

New Mexico 0.247 0.184 75%

New York 1.18 0.18 15%

North Carolina 0.243 0.558 230%

North Dakota 0.063 0.179 283%

Ohio 0.792 1.002 126%

Oklahoma 0.67 0.241 36%

Oregon 0.268 0.025 9%

Pennsylvania 0.75 0.861 115%

Rhode Island 0.089 0 0%

South Carolina 0.17 0.272 160%

South Dakota 0.064 0.02 31%

Tennessee 0.23 0.433 188%

Texas 3.546 0.893 25%

Utah 0.224 0.214 95%

Vermont 0.009 0 0%

Virginia 0.299 0.261 87%

Washington 0.298 0.061 21%

West Virginia 0.111 0.646 580%

Wisconsin 0.409 0.299 73%

Wyoming 0.143 0.259 182%

Map of States Requiring more than 100% of their current NG consumption to replace coal fired capacity with natural gas

Natural Gas Price Volatility

Source: EIA Report “An Analysis of Price Volatility in Natural Gas Markets” (2007)http://www.eia.doe.gov/pub/oil_gas/natural_gas/feature_articles/2007/ngprivolatility/ngprivolatility.pdf

Switching from Coal to Natural Gas: Understanding the Environmental and Operational Impacts

At APPA National Conference, June 19-23, 2010, Orlando, FLCost to Members: $375; Cost to Non-Members: $750

Sunday, June 20, 2010 - Full day • 8:30 a.m. – 4:30 p.m.The U. S. Environmental Protection Agency’s “perfect storm” of new environmental regulations (air, climate, water and waste) may lead many utilities to switch from coal to natural gas for base load energy production to reduce carbon dioxide, sulfur dioxide and fine particulate matter. While natural gas may be an easier environmental choice, the utility’s operational issues may grow far more complex when producing electricity with natural gas. Operational issues range from anticipating how much gas to use in lieu of coal, the purchasing (“nomination”) process, natural gas transportation issues, and local storage when the gas is not used within 24 hours. The speaker will address all aspects of natural gas use, from nomination, to setting up procurement operations, to re-sale of natural gas in the market if storage is not available.

Instructors: Ted Chapman, Director, Standard & Poor's, Dallas, Texas; Catherine Elder, Senior Associate, Aspen Environmental Group, Sacramento, Calif.; Doug Hunter, General Manager, Utah Associated Municipal Power Systems, Salt Lake City, Utah; and Joanie Teofilo, Vice President, Risk Control & CRO, The Energy Authority, Jacksonville, Fla.

http://www.appanet.org/events/annualeventdetail.cfm?ItemNumber=26074&sn.ItemNumber=0

Overview* • Cumulative impacts of air, water, and waste rules will require coal

plants to make significant environmental control investments to continue operating.

• Size and timing of these expenditures could result in many retirements.

• Three major adverse impacts could result:– Regional reliability and reserve margin requirement shortfalls– Misallocation of financial resources and stranded investments– Likely very large increases in use of natural gas by the power sector

• Timing, sequencing, and other regulatory parameters are critical.– HAPs, water, CCBs, and CO2 are significant issues; juggling and sequencing these

regulatory tracks may be the most important challenge.

• EPA’s analysis can take specific steps to reflect these issues

The cumulative impact to power plants from overlapping regulations around 2015-2017

* These slides excerpted from a presentation by a group of utilities to EPA on 2/10/10

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Multi-Media Compliance Challenges over the Next Decade*2010 2020

HAPs (MACT): Coal and oil units – ACI/FGD/SCR/BH (capital plus O&M)

Air Quality (new CATR, NAAQS, Visibility): All fossil plants – FGD/SCR (capital plus O&M)

Water (New Effluent Guidelines): All plants/coal focused – Treatment/dry ash disposal (capital plus O&M)

Cooling Water Intake Structures (316(b)): All plants – Fine screens/cooling towers (capital plus O&M)

Ash Management: All coal units – Monitoring/dry ash disposal/new landfills/liners (capital plus O&M)

Climate Change, Renewables and End Use Efficiency: All fossil units – Gas or biomass conversion; retirements; demand loss (capital + conversion cost + O&M + retire & replace + RECs or ACPs + CO 2 allowances)

Rulemakings & Implementation Compliance Required Maintaining Compliance & New Standards

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• Need final rules to commit to a specific technology or compliance strategy. Retrofit technologies, selection and cost, are dependent on unit design, fuels, age, & location. Technologies to reduce GHGs (e.g., CCS) are in early development.

There is a cumulative impact to power plants from multiple regulations.

* These slides excerpted from a presentation by a group of utilities to EPA on 2/10/10

Decision Timelines for Existing Coal Units*

Timeframes vary by unit--Fleet considerations may extend the time needed for any specific unit conversion

Unit

Continue to operate on coal

Convert to gas operation

(if possible)

Convert to biomass (limited controls)

Retire and Replace

Retire

3-5 year FGD/SCR engineer/construction timeline

4 year conversion timeline

3-4 year conversion timeline

3-6 year combined cycle develop/construct timeline

Transmission Implications 5-10 years

5-10 year dry ash conversion timeline

2-5 year cooling tower eng./const timeline

Final rule

Key investment decisions and resource allocations cannot be made until rules are final. Some regulated companies must obtain commission approval for emission control projects. Most must obtain commission approval for new generation. Financing relies on final EPA regulations.

Compliance deadlines preceding the construction/conversion completion could lead to early retirement.

Decisions for a single unit are further complicated as we consider multiple units, plants, fleets, NERC regions and the nation.

* These slides excerpted from a presentation by a group of utilities to EPA on 2/10/10

Cumulative Capital Impacts May Force Retirements*• Financial viability compares the

continuing cost to operate to the replacement cost.

• Continuing cost to operate includes all costs, including capital for:– Air– Water– CCBs (Coal combustion products)– CO2

• Cumulatively, these costs may make many units uneconomic, leading to retirement. Replacement generation would be necessary.

• This type of analysis is not uniform across the industry, with variations in frameworks and risk tolerance.

When the continuing to operate costs exceed the avoided cost of replacement, it is more economic to shut down and replace the unit.

Example for illustrative purposes only

2010

2011

2012

2013

2014

2015

2016

2017

2018

2019

2020

2021

2022

2023

2024

2025

$/kW

Fuel Emissions O&M - Base O&M – Environmental

Recurring Capital Capital - Environ. CO2 Avoided Cost Benefit

* These slides excerpted from a presentation by a group of utilities to EPA on 2/10/10

What is the EPA Thinking?• EPA has convened an unofficial BACT working

group—process largely influenced by the vendors including those selling natural gas, natural gas combined cycle units, gas turbines, and equipment/instruments for IGCC plants.

• EPA is very impressed with natural gas and abundance/low cost—”easy solution for the power sector”

• EPA does not understand that over reliance upon one fuel source is risky—cost & reliability issues

• Sec 116 Waxman-Markey “US CAP”

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Some of the EPA’s BACT Options – None Good

• EPA Workgroup to Advise EPA on GHG BACT (9/09-2/10) TO DIRECT EPA ON NEEDED GUIDANCE

– Phase 1 Report to EPA 2/2/10 – Phase 2 - 8 White Papers on

Unknown Topics by 2/19/10• Phase 1 Report Reflects General

Disagreement Between Stakeholders and Asks EPA for Guidance On:

– Changing the Definition of Source for Purposes of Applying BACT

– Guidance for Determining When Energy Efficiency Constitutes BACT

• To date - BACT applies to the unit at which a physical change occurs

• Must change traditional notion of where BACT applies in order to--– Allow Fuel Switching (require a

coal plant to become a gas plant)– Provide for Energy Efficiency

measures at other plant units– Accommodate Demand Side EE?

• See BACT Determination for 612 MW gas-fired Calpine Hayward, CA– BACT Analysis excludes CCS – BACT = ENERGY EFFICIENCY OF

7,730 Btu/KWH at that unit

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Presentation by CALPINE Feb. 4, 2010

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Could BACT Force Fuel Switching?

EPA’s Dec. 2009 - Feb. 2010 BACT Decisions:• Change in BACT by pushing consideration of IGCC

technologies & asking why natural gas wasn’t considered

• Kentucky CASH Case• Arkansas AEP Case• Rumors of a 3rd BACT case

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U.S. Coal Fleet Demographics*

• Size– Over 75 GW that are <250 MWs

• Age– Over 45 GW >50 years old today– Another 67 GW between 40 and 50 years old

• Environmental Controls– Over 190 GW do not have FGD– Over 190 GW do not have SCR or SNCR– Over 280 GW do not have FF– Only 9 GW have all three installed-- FGD,SCR/SNCR,FF– 38% (275 GW) of fossil fuel fired units at risk of cooling towers

retrofits– 169 GW with wet ash handling/disposal of CCBs1

Notes:*Coal Unit Data: Energy Information Administration (www.eia.doe.gov/cneaf/electricity/page/capacity/existingunitsbs2008.xls)*Air Emission Control Data: EPA Clear Air Markets Division (http://camddataandmaps.epa.gov/gdm/)1EIA 767 data, 2005

Total US coal MW: 333,018MW at Risk**: 137,248

**MW at risk: MW without both an FGD and an SCR.

* These slides excerpted from a presentation by a group of utilities to EPA on 2/10/10

Environmental Control Cost Assumptions*

Retrofits, replacements and investment in low carbon or other technologies will compete for capital.

Required Technology Cost per kW or facility

AIR (coal plants 300 –1,000 MW)

FGD $300 – 500/kw(EPA using $120 – $240/kW)1

SCR $200 – 400/kw (EPA using $110 – 120/kW)1

FF Additional costs

WATER Cooling tower retrofit ~$185/kW (EPA used $58 - $62/kW)2

CCBs Impoundment closure >$50 million/facility

Note: Cost estimates do not include capital for replacement generation or transmission. This table does not include the uncertain costs of carbon regulation/legislation.1 EPA’s CAPA Proposal Analysis, 2009.2 DOE’s comments in Phase II rule, 2002 and EPA, http://www.epa.gov/waterscience/316b/phase2/devdoc/ph2toc.pdf

* These slides excerpted from a presentation by a group of utilities to EPA on 2/10/10

Reliability Concerns: The Issues*

• Numerous and costly compliance requirements for air, water and CCBs could lead to significant number of retirements.

• Timing may result in many units being taken off-line at the same time to complete needed retrofits.

• Regional planning/reliability requirements must be coordinated to maintain the reserve margin (e.g., retirements, outages, etc.).

• For regulated utilities, concentrated rate case hearings coupled with rate shock concerns may prohibit timely resolution by state utility commissions.

• Concerns are applicable to most regions, especially those with significant coal generation.

* These slides excerpted from a presentation by a group of utilities to EPA on 2/10/10

APPA Natural Gas Study• In anticipation of the EPA actions on BACT or

NSPS, or NAAQS regulations, APPA has commissioned a natural gas study with Katie Elder, Aspen Environmental, CA.

• Gas study to demonstrate operational differences from baseload coal to gas

• Study not designed to question value of gas—but to describe nomination/purchase/re-sale and hedging in a volatile market

• Natural gas storage/pipeline issues different from state to state

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Fossil Fuel Based Generation Map – Showing Large Number of Potential Plants

Requiring Access to Natural Gas

Source: NatCarb Atlas 28

Availability of APPA Natural Gas Study?

• Katie Elder, Aspen Environmental• March 2010• APPA Natural Gas Workshop, June 2010 at

National Conference, Orlando, FL

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Source of Map: NatCarb Atlas; Overlay: APPA Optimal Location Criteria Maps without CO2 pipelinesNote: Optimal Locations are for new plants, not retrofit of existing power plants

Existing Fossil Generation & Optimal CCS LocationsWithout Any Drinking Water Resource Location Analysis

Deep Saline Aquifer Locations

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Deep Saline Aquifer Locations & ‘Lenient’ Seismic

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Deep Saline Aquifer Locations & ‘Stringent’ Seismic

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Saline Aquifers, CO2 Pipelines, & ‘Lenient’ Seismic

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Other Considerations – Transmission Lines

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Other Considerations – Railroads

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Optimal Sites – Using Existing CO2 Pipelines

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Optimal Sites – Not Requiring Proximity to CO2 Pipelines

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APPA Contacts

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CO2, EPA liaison, CAA, & new generation (including renewables)Theresa Pugh Director, Environmental Services202-467-2943TPugh@APPAnet.org

GHG Reporting, 316(b), biomass and effluent guidelines

J.P. BlackfordEnvironmental Services Engineer202-467-2956JPBlackford@APPAnet.org