Impacts Associated with EPA Regulations and Gas- Electric Infrastructure Analysis

Transcription

1 Impacts Associated with EPA Regulations and Gas- Electric Infrastructure Analysis Platts Transmission Planning & Development Conference, Washington, DC September 11, 2012 John Lawhorn

2 MISO Overview Regional Transmission Operator (RTO) /Independent System Operator (ISO) Reliability Coordinator Energy Markets 2009 Ancillary Services Large Footprint 1,000,000 square kilometers 11,000 MW of Wind Generation 140+ Wind Sites MISO Reliability Coordination Area, January

3 Carmel Indiana Control Room

4 Scope of Operations as of January 1, 2012 Generation Capacity 131,010 MW (market) 142,930 MW (reliability) Historic Peak Load (set July 20, 2011) 103,9750 MW (market) 110,032 MW (reliability) 49,641 miles of transmission 11 states, 1 Canadian province 5-minute dispatch 1,911 pricing nodes 1,242 generating units (market) 5,930 generating units (network model) $23.6 billion gross market charges (2011) 363 market participants serving 40 million people 4

5 Environmental Protection Agency Proposing Four New Regulations Clean Water Act Develop Rule Compliance Prep Period Compliance Coal Combustion Residuals Develop Rule Compliance Prep Period Compliance Clean Air Transport Rule/Cross State Air Pollution Rule Develop Rule Compliance Mercury and Air Toxics Standards Develop Rule Compliance Prep Period State Exten -sion EPA Exten -sion Compliance

6 Overview of Impacts 12.6 GW of coal capacity Identified as at-risk Expected retirement dates to be in the 2014/2015 calendar years 12.6 GW of retirement would erode MISO projected reserve margins by 12 percentage points, dropping system resources 6 to 7 percentage points below required targets. Capital investment of $33.0 Billion will be required to retrofit and/or replace units Average energy prices may increase by $5/MWh 12,652 MW of Retirements Energy Cost Impacts EPA Compliance Retrofit Capital Costs New Capacity Capital Fixed Charges Fixed O&M Capital Costs Transmission Capital Costs $5/MWh $22.5B $9.6B $0.0B $0.9B Total Capital Costs $33.0B 6

7 Key Issues Affecting Compliance (3-5 years) Operational issues associated with the Cross State Air Pollution Rule (CASPR) delayed/mitigated due to Court action MATS related - coordination of outages required to install compliance equipment maintenance margin calculator tool Survey underway to determine outage plans Investigate Reciprocal Internal Combustion Engines (RICE) standards and their impact on Behind the Meter Generation (BMG) Sufficient manufacturing, engineering and other resource availability to meet necessary timelines Supply chain evaluation in process Ability of the natural gas infrastructure to meet the anticipated fuel switching requirements Study completed and report available at: 7

8 Purpose of the Phase 1 and Phase 2 Studies The purpose of Phase 1 of the Gas/Electric Infrastructure Interdependency Analysis is to: Review and analyze current and future natural gas pipelines, storage facilities and related infrastructure, and extrapolate the impact for natural gas-fired electric power generation from in the MISO region. The purpose of Phase 2 of the Gas/Electric Infrastructure Interdependency Analysis is to: Build upon the Phase 1 analysis and incorporate the impacts of lower gas prices; and, correspondingly higher capacity factors on the existing gas fleet, on the existing pipeline infrastructure in the MISO region. 8

9 Overview of MISO Region Major Pipelines 9

10 Results Phase 1 Wellhead Gas supply is not expected to be an issue Additional gas pipeline infrastructure is needed to accommodate fuel switching Additional inter-regional and intra-regional (solely within MISO) main line development needed Lateral pipelines and compressor additions development needed Timing for development of new pipeline infrastructure is the main issue Planning, siting, regulatory and construction of new main line gas pipelines will be on the order of 5-6 years, if started now Compliance with Mercury and Air Toxics Standards is 3-5 years 10

11 Results Phase 2 Capacity Factors (CF) increase significantly for the existing (embedded) gas fleet under changing regulatory and gas price scenarios Historic CF is based on 20 year averages. No new EPA rules, no retirements and $4.50 gas Phase 1 is based on EPA rules, 12,000 MW of retirements and $4.50 gas price CT CC Phase 2 Expected is based on EPA rule, 12,000 MW of retirements and $2.50 gas price Phase 2 Max based on existing gas units running at same level as new gas units 11

12 Results Phase 2 continued Modified-Backcast analysis based on the existing gas infrastructure with existing and new gas capacity additions running with a $2.50/Mbtu gas price: The analyses were not intended to be a detailed market-area engineering analysis that uses sophisticated forward looking flow analysis. Over 65% of the Pipelines have insufficient capacity at measurement points into their market area to fully meet the needs of the existing (embedded) units operating at expected capacity factors. For the period , almost 90% of the pipelines have insufficient capacity for the existing units plus an incremental 12,000 MW of coal-to-gas retirement. Gas industry participants reviewed the report and provided comments which are contained in Appendix 2. Gas industry participants comments in general are more optimistic than the conclusions in the Phase 2 report. 12

13 Results Phase 2 continued Pipelines sourcing gas supply from the Gulf Coast have significantly higher levels of insufficient capacity compared to the Southwest and Mid-Continent pipeline sources. Additionally, Shale gas supplies in proximity to MISO will need pipeline flow changes and infrastructure build-out. To ensure generator availability, gas storage may be required Storage options need to be addressed further. On site diesel or liquid natural gas (LNG) appear as viable options Tariff changes may be needed to add qualifications to generators Regional coordination of MISO members will produce a better solution than each stakeholder acting alone No obvious venue (except FERC) for that coordination exists, other than MISO 13

14 Pipeline Capacity Assessment New pipeline infrastructure is needed to manage volatility and ensure reliability 21 major pipelines are in the MISO footprint With the advent of shale gas, the pipeline flow usage is in a state of flux Some are essentially fully subscribed and some are not New gas-fired generation will be served off different lines New main lines as well as lateral lines (line from the main line to the power plant) will be needed On-site storage of fuel, either diesel or LNG, may substantially lessen the need for new pipeline capacity. The costs and trade-offs need to be studied going forward 14

15 Next Steps MISO is conducting regional meetings with its Stakeholders to develop a keys issues lists of their concerns. The FERC is holding 5 regional Technical Conferences to take input on Gas/Electric Infrastructure issues. MISO will participate in those Technical Conferences and present our concerns and issues. After the FERC Technical Conferences, MISO and it s stakeholders will hold additional workshops with gas industry participants to continue the dialogue between our two industries, identify infrastructure needs and move forward on solutions. 15

16 Appendix 16

17 INGAA Projected Gas Supply Growth Source: INGAA Foundation's North American Natural Gas Midstream Infrastructure Through 2035: A Secure Energy Future Report 17

18 Major U.S. Shale Basins Source: Energy Information Administration based on data from various published studies. Updated: May 9,

19 MISO Region Major Interstate Pipelines (All pipelines were analyzed) Pipeline Name Principal Supply Source(s) System Configuration 1. Alliance Pipeline LP Canada Trunk 2. ANR Pipeline Company Louisiana, Kansas, Texas Trunk/Grid 3. Bison Pipeline LLC Wyoming, Montana, North Dakota Trunk 4. Mississippi River Trans. Corp. Arkansas, Oklahoma Trunk 5. Crossroads Pipeline Company Interstate System (feeder) Trunk 6. Great Lakes Gas Trans. Ltd Canada/Canada export Trunk 7. Guardian Pipeline Interstate System (feeder) Trunk 8. KO Gas Trans Co (KY-OH) Interstate System (feeder) Trunk 9. Midwestern Gas Trans. Interstate System (feeder) Trunk 10. Northern Border Pipeline Canada, ND (Bakken) and Bison PL Trunk 11. Natural Gas PL Co. of America Kansas, Oklahoma, Louisiana, Texas Trunk 12. Northern Natural Gas Co. Kansas, Oklahoma, Texas Trunk/Grid 13. Panhandle Eastern Pipe Line Co. Kansas, Oklahoma, Texas Trunk 14. Texas Eastern Transmission Louisiana, Texas Trunk 15. Texas Gas Transmission Louisiana, Texas Trunk 16. Trunkline Gas Company Louisiana, Texas Trunk 17. Viking Gas Transmission Canada Trunk 18. Vector Pipeline LP Interstate/export Canada System Trunk 19. Rockies Express Pipeline Co. Wyoming, Colorado Trunk 20. Southern Star Central Pipeline Kansas, Oklahoma, Wyoming Trunk/Grid 21. Williston Basin Interstate PL ND, WY, MT, Canada Trunk/Grid Trunk - systems are large-diameter long-distance trunklines that generally tie supply areas to natural gas market areas. Grid - systems are usually a network of many interconnections and delivery points that operate in and serve major natural gas market areas. Bolded pipelines indicate MISO-identified facilities 19

20 Historic Longitudinal Flow Patterns Source: U.S. Pipelines Central ANR / Great Lakes 2011 Shippers Meeting August 11, 2011

21 Today s Developing Grid Flow Patterns Source: U.S. Pipelines Central ANR / Great Lakes 2011 Shippers Meeting August 11, Greg Peters, MISO Presentation, 2012

22 Challenges to Moving Forward Acting together as a region will have greater benefits than each stakeholder acting separately Cost allocation, who pays and how are the costs recovered for gas infrastructure Changing regulatory policy creates cost recovery uncertainty Cost to MISO members will be determined based on the level of retirements as well as location of the new gas-fired power plants Costs are allocated to main line pipeline development with a complex cost recovery mechanism and to lateral pipelines, which are generally the responsibility of the power plant owner 22

23 Phase 1 - Cost Impacts MISO looked at multiple retirement scenarios to determine the range of impact on the system At the expected 12,000 MW retirement level, the cost impact associated with pipeline infrastructure development is expected to be in the range of ($2.0 billion for main lines plus $950 million for laterals) For comparison purposes, at a 3,000 MW retirement level the infrastructure development costs are expected to be ($1.0 billion for main lines and $390 million for laterals; while at a 24,000 MW retirement level the costs are expected to be ($2.0 billion for main lines plus $1.0 billion for laterals) 23

24 Is Timing an Issue? The short answer is Yes! Timing needed to get infrastructure built Plan development Coalition development Regulatory approval Design and construction After plan and coalition development the regulatory, design and construction time period is at least 3 years 24

25 Generalized Overview of Pipeline Approval and Construction Sequence 1) Preplanning from 6 months to 1 year 2) Open Season 1 to 2 months 3) FERC approval Minimum 6 months Staff Environmental impact Approvals longer. Year 1 Year 2 Year 3 Year 4 Year 5 Year 6 Start Planning FERC Filing Construction Operations Open Season FERC Approval: Minimum 6 Mos. 4) Construction unknowns for new Greenfield versus existing Right of Way: Greenfield add additional antiquities, archaeological, environmental timing and additional construction issues weather, personnel, materials, etc. 5) Size of Construction and Rural or Urban construction vary significantly in time and cost.

26 Total Estimated Phase 1 Construction Costs for Pipeline Lateral Line to the MISO-identified Facilities Low Range High Range $ Millions $ Millions Pipeline 1 $40.00 $ Pipeline 2 $ $ Pipeline 3 $35.50 $35.50 Pipeline 4 $3.37 $10.35 Pipeline 5 $40.00 $40.00 Pipeline 6 $53.40 $53.40 Pipeline 7 $21.40 $21.40 Pipeline 8 $21.40 $64.00 Pipeline 9 $ $ Pipeline 10 $52.00 $52.00 Pipeline 11 $92.50 $92.50 Pipeline 12 $53.40 $53.40 Pipeline 13 $87.00 $87.00 Pipeline 14 $71.07 $43.65 Pipeline 15 $25.50 $25.50 Total $ $1,097.80

27 Phase 2 Costs Have not been developed at this time. The general magnitude of the Phase 2 costs will be investigated in a separate study. 27