Managing Gas-Electric Integration: The ISO New England Experience. By Mark Babula and Kevin Petak

Transcription

1 The Cold Truth Managing Gas-Electric Integration: The ISO New England Experience By Mark Babula and Kevin Petak D DURING THE WINTER OF , ISO NEW ENGLAND (ISO-NE), the independent system operator (ISO) bulk electric system operator for the six-state New England region, was confronted with periods of relatively cold weather caused by abnormal southward shifts in the northern polar vortex. As natural gas demand for space heating peaked, so too did the need for electric generation, which tested the ability of gas-fired generators to access fuel supplies. This caused an increase in spot market gas purchases in New England and subsequently resulted in an overall increase in operating and production costs within the electric sector. Electric service reliability was not threatened, however. In the case study described in this article, ISO-NE used some lessons learned from previous years to successfully meet the polar vortex challenge, successfully avoiding service outages. But the winter s gas and electric market dynamics revealed that issues remain involving operational synchronization between natural gas and electricity systems. While robust natural gas supply development (particularly from areas like the Marcellus and Utica shales) is continuing to spur interest in natural gas, questions about natural gas and electricity integration persist. As electric providers increase their use of gas-fired generation, questions about fuel supply adequacy for natural gas fueled resources are becoming a mainstay of the power sector. Our look to the future suggests that the limitations on gas supply in New England that were apparent this past winter are likely to continue, barring significant pipeline capacity expansion, significant 20 ieee power & energy magazine / IEEE IMAGE LICENSED BY INGRAM PUBLISHING Digital Object Identifier /MPE Date of publication: 20 October 2014 november/december 2014

2 november/december 2014 ieee power & energy magazine 21

3 incremental deliveries of liquefied natural gas (LNG) into the market, or expanded oil backup programs. Further, questions remain about how the costs incurred in implementing such options would be recovered and about which organization or organizations would own and manage daily gas capacity release. The challenges faced in New England are unlikely to be limited to that region in the future, and the ISO-NE s polar vortex experience should be seen as a bellwether for other ISOs and regional transmission organizations (RTOs) to carefully consider as gas and electric interdependency increases across the country. Additional study and coordination with gas sector partners will therefore be essential, and a number of important infrastructure and regulatory issues will need to be addressed in order to provide a strong and reliable future for integrated gas and electric markets. Gas Consumption, Average Bcf/d % 15% Percent of Total System Capacity by Fuel Type (2000 Versus 2013) (23,975 MW Versus 31,759 MW) 34% 22% 12% 7% 2001 Power 2001 Nonpower 2013 Power 2013 Nonpower 18% Jan. Feb. Mar. Apr. May June July Aug. Sept. Oct. Nov. Dec. Source: EIA Natural Gas Consumption by End Use 43% Nuclear Oil Coal Natural Gas figure 2. U.S. monthly gas use, 2001 and 2013 (source: EIA). 11% 7% 7% 5% Hydro and Other Renewables figure 1. Capacity allocation in New England, 2000 and Pumped Storage The Changing Nature of the Gas-Electric Interface ISO-NE s experience during the winter revealed the consequences of important changes in the gas and electric sectors. These changes in the nature of electric power generation have posed systemic challenges to the operation of the electric grid that other system operators may need to consider in the near future. Changing Fuel Mix for the Electric Sector Since the beginning of the century, New England s installed generating capacity has shifted gradually from oil, coal, and nuclear to natural gas. Though these shifts have occurred for a number of underlying reasons (e.g., environmental concerns about coal-fired generation and reduced reliance on oil-fired generation due to price considerations), the fundamental resource balance for ISO-NE s power generation shifted dramatically between 2000 and ISO-NE s oil-fueled capacity has dropped from 34% of total system capacity in 2000 to 22% in 2013, whereas its gas-fired capacity has increased from 18% in 2000 to 43% in 2013 (see Figure 1). Moreover, natural gas generation has more than doubled as a share of New England s total generation energy production from 2000 through 2013, so ISO-NE has grown increasingly reliant on the availability and price stability of natural gas to produce electric power. Increased Gas-Fired Generation Led to Increased Gas Use Across the United States, gas-fired generation has grown greatly since the turn of the century, accounting for most of the growth in total gas consumption. In 2001, peak-month (i.e., January) gas use stood at about 85 billion ft 3 per day (see Figure 2). By 2013, peak-month use had grown to well above 90 billion ft 3 per day, with much (if not all) of the growth occurring in gas-fired generation. In addition, gas use has grown throughout the year as the use of natural gas as fuel for base-load generation has increased. These historical trends show that gas used in the power sector has become a much more significant portion of gas markets throughout the United States. Components of Gas Supply There are two components of gas supply to electric generators. The first is the wellhead supply of the gas commodity. The United States is well supplied with natural gas resources, largely due to the development of shale gas resources. The second component is the infrastructure to deliver the gas 22 ieee power & energy magazine november/december 2014

4 4,500 4,000 3,500 3,000 Total November Through March Heating Degree Days 6% 7% 3% 4% 2% 2% 1% 2%7% 11% 12% 11% 4% 6% 1% 1% 1% 3% 3% 2% 6% 2% 4% 9% 8% 6% 4% 1% 0% 3% 15% 2,500 2,000 1,500 1, Winter Winter Winter Winter figure 3. U.S. winter heating degree days, where and when it is needed. The United States has an extensive natural gas pipeline network, augmented by LNG import terminals and gas storage facilities that are able to reliably deliver gas to consumers under most conditions, nearly all the time. The key challenge to the increasingly gas-reliant power grid is the set of circumstances that systematically results in an inability to provide gas to electric generators at times of peak demand. Winter Winter Winter Winter Winter Winter Winter Winter Winter Winter Winter Winter Winter Winter Winter Winter Winter Winter Winter Winter Winter Winter Winter Winter Winter Winter Year Normal transportation cost recovery. As a result, most gas-fired ISO and RTO generators rely on capacity release pipeline services, which exposes them to service interruption when gas demand is high. In New England, electric generators are increasingly reliant on natural gas as a primary fuel for power generation. Although the area has roughly 3,700 million ft 3 Regulation and Firm Capacity Pipeline Contracts Under the current Federal Energy Regulatory Commission (FERC) regulatory model, interstate gas pipeline owners only build or increase pipeline capacity in order to meet obligations to shippers holding firm capacity contracts. Absent long-term firm contracts, no new pipeline capacity is built. In vertically integrated power markets, electrical generators often sign such long-term pipeline contracts because they are often permitted to pass the costs of the new transmission capacity through to their customers. But most merchant generators in organized power markets say they cannot afford to pay for firm pipeline capacity over the course of a year because the generators actual gas use may vary from fixed supply agreements, and the ISO and RTO capacity and energy markets currently do not allow for firm-gas Spot Gas Price, US$/MMBtu november/december 2014 ieee power & energy magazine Dec Dec Transco Z6 NY Algonquin Citygate Dominion South Point Henry Hub 16 Dec Dec Dec Jan Jan Jan Jan Feb Feb Feb Feb figure 4. Gas price behavior during the winter of

5 per day (MMft 3 /d) of pipeline capacity firmly contracted for gas delivery, more than 80% of that capacity is held by local gas distribution companies (LDCs) that contract for the maximum capacity required to meet winter peak demand. At other times, they can release some of this capacity to merchant generators on a secondary capacity release basis. The pipeline capacity is augmented by deliveries from an LNG import terminal in Everett, Massachusetts. In addition, New England LDCs rely on LNG peak-shaving and propane-air facilities to meet their peak demand requirements. Such resources are not available to electric power generators, however. On the coldest days, LDCs use all of their contracted pipeline and other delivery capacity to meet space heating demand for natural gas. On those days, generators with subordinate delivery contracts may have no remaining delivery capacity and therefore be unable to operate. MMft 3 4,000 3,800 3,600 3,400 3,200 3,000 2,800 2,600 2,400 2,200 2,000 1 Dec. 8 Dec. 15 Dec. 22 Dec. 29 Dec. 5 Jan. 12 Jan. 19 Jan. 26 Jan. 2 Feb. 9 Feb. 16 Feb. 23 Feb. Sources: Pipeline EBB Data, FERC Index of Customer Data figure 5. Pipeline flows and contracted capability in New England, winter Day-Ahead Energy Market Step Participants Submit Bids to Supply Power ISO Posts Day-Ahead Results Re-Offer Period for Participants to Submit Revisions ISO Completes RAA Process Current Deadline figure 6. A sample DAM schedule. New Deadline 12 p.m. 10 a.m. 4 p.m. 12 1:30 p.m. 4 6 p.m. From Time Results Are Posted to 2 p.m. 10 p.m. 5 p.m. ISO-NE s Experience As we stated above, the winter of saw a significant southward shift in the Earth s north polar vortex within the Northern Hemisphere, which led to prolonged cold fronts over most of the Northeast and Midwest in the United States and Canada. These cold fronts resulted in record low temperatures and conditions that triggered school and business closures around the region. As temperatures dropped, heating demand increased. As measured in heating degree days (reflecting the difference in temperature below 65 F), the winter was the third-coldest winter in the past 30 years (see Figure 3). During this period, spot market natural gas prices in some areas spiked to historically high levels (see Figure 4), as consumers relied on natural gas to heat homes and businesses and the gas needs of power generators increased as electric demand similarly rose. On a number of days throughout the winter, Northeast gas prices increased to well above US$20 per million British thermal units (MMBtu) in response to the high gas use. For example, Algonquin Citygate prices commonly used to represent New England gas prices spiked to well above US$20 per MMBtu on roughly 30 different days from December through February. Some of the price spikes were quite extreme, with Algonquin prices peaking at more than US$70 per MMBtu in late January and early February. Such price levels are well above prices observed in recent years. In New England, the convergence of extremely high demand for electricity and natural gas has led to substantial challenges to electric sector providers that are increasingly reliant on natural gas as a primary fuel for power generation. LDCs needed all of their contracted pipeline capacity during peak days that winter. Nominations of gas pipeline capacity were therefore very high on those extremely cold days, and subordinate contracts for gas transport were generally not available to power providers (see Figure 5). As mentioned above, the regional pipeline capacity is augmented by deliveries from the LNG import terminal in Everett, Massachusetts; these averaged about 30 MMft 3 this winter. All things considered, utilization of regional gas infrastructure was very high on a number of days throughout the winter, leaving very little unutilized pipeline capacity for use by power providers. While this could have led to shortages of electric power and the potential for brownouts and blackouts, ISO-NE avoided this outcome through a variety of programs. How ISO New England Successfully Managed the Challenge ISO-NE was ultimately able to successfully weather the hardships created during the winter largely because the ISO 1) had already implemented some operational lessons learned from previous crises, 2) instituted an oil supply program to boost the reliability and sustainability of the oil fleet, and 3) strengthened its understanding of and 24 ieee power & energy magazine november/december 2014

6 The experience of the winter exposed some potentially serious challenges related to gas-electric integration. cooperation with gas sector providers throughout the region in order to develop more robust communications and gas demand forecasting models. Lessons Learned and the Electric/Gas Operations Committee The New England gas-electric nexus in the year 2000 was nearly nonexistent, at least from an operational planning perspective. Most of New England s electricity at that time was generated by a combination of nuclear, coal, oil, and hydroelectric resources. Small nonutility generation or special qualifying facilities also accounted for a relatively small portion of total summer capacity. A few of these units were older combined-cycle facilities or gas turbines located directly off the interstate pipeline system. In addition, there were some oil-fired steam generators that were dual-fuelcapable units, burning either heavy or light oil while cofiring with gas. As a result of this limited operational intersection, ISO-NE had only a limited knowledge of the regional natural gas system, and there was very little contact or communication between the regional gas sector representatives and industry groups. That changed shortly after the severe cold snap of January 2004, which alerted ISO-NE to operational awareness gaps. By that time, gas-fired generation capacity in New England had begun to increase, and initial planning studies had identified early signs of gas supply constraints that stress-tested the bulk electric system. In response to the challenges of that period, ISO-NE and the Northeast Gas Association cofounded the Electric/Gas Operations Committee (EGOC) to improve cross-sector awareness and to discuss common issues, such as maintenance schedules, preand postseasonal assessments, and training opportunities. The EGOC typically meets quarterly and is open to representatives from regional pipelines, LDCs, LNG and liquid fuel suppliers, other regional ISOs and RTOs, regulatory bodies, and industry associations. Operational Changes In 2013, ISO-NE implemented changes in how it plans and schedules its generation resources. It moved the day-ahead market (DAM) schedule timelines to accommodate longlead-time generating resources and modified its resource adequacy assessment (RAA) process to better align with the natural gas evening nomination and confirmation cycles (see Figure 6). It also subscribed to a number of gas sector services to improve fuel price forecasts and overall situational awareness of the gas sector. These included Platts Gas Daily (for national and regional gas sector news and prices), Genscape gas pipeline flow information (used to execute nomination reports for the current and future gas day), and the Intercontinental Gas Exchange, used for next- and intraday bid and ask gas pricing information. Improvements in the Forecast Department In 2013, ISO-NE expanded its forecasting department to improve information sharing and gas sector coordination. In addition, ISO-NE developed new tools for scheduling and operational planning of gas-fired resources and increased coordination with the gas control centers of all the regional pipelines. The Forecast Department assesses the DAM results and prepares information for delivery to each of the five gas pipelines serving the region. This process consists of computing hourly gas consumption by applying unit-specific heat rates, combining the hourly gas consumption for each unit on the same pipeline, and subsequently transmitting both unit-specific and combined-fuel consumption to each pipeline. If there are any perceived issues with the reliable delivery of the next day s fuel requirements, the Forecast Department contacts the gas control department of each pipeline to verify whether the electric sector fuel consumption can be accommodated (in addition to the core gas sector deliveries) and, based on those discussions, may choose to revise or supplement the next-day operating plan. Gas Users Tool ISO-NE s Forecast Office uses its Gas Users Tool to improve estimates of gas pipeline capacity and identify any potential shortfalls or overages. Developed internally by the ISO-NE Operations Support Team, the Gas Users Tool scrapes the five electronic bulletin boards (EBBs) of the interstate gas pipelines serving New England and aggregates scheduled deliveries of gas for each gas LDC (citygate meters), all regional commercial and industrial loads, and all nonelectric sector delivery points. It then estimates the remaining gas pipeline capacity by individual pipe for use by the electric power sector and overlays the daily, 14-h (10 a.m. midnight) burn profiles of all gas-fired generators by pipeline to see if the electric sector demand can be accommodated. The Forecast Office can then identify any potential underscheduling of gas and modify the next-day operating plan if warranted. november/december 2014 ieee power & energy magazine 25

7 ISO Peak Load Total Lost Generation (Forced Outages and Derates) Generation Lost Due To Fuel Supply Issues PJM 141,312 41,366 9,718 MISO 107,770 32,813 6,666 SPP 36,602 3,185 2,412 NYISO 25,738 4,135 2,235 ISO-NE 21,334 2,700 1,189 figure 7. Electric loads and outages (MW), 6 7 January Greater Schedule Coordination with the Gas Sector Recognizing the need to build stronger cross-sector relationships and improve information sharing, ISO-NE increased its coordination with gas sector representatives. It now holds annual faceto-face meetings with regional gas control (pipeline) entities to review each pipeline s maintenance schedules and to understand the unavailable gas pipeline capacity and the resulting impacts on gas-fired generation. ISO-NE also provides the pipelines with its most recent gas-fired generator maintenance schedules, identifies any gas-fired generation deemed must run to support local area needs or transmission security, and seeks to coordinate both pipeline and generator maintenance to minimize any potential conflicts or service disruptions. Improved Planning Studies Since 2000, ISO-NE has commissioned more than 25 studies of the natural gas sector and related topics, including studies of regional pipeline capacity and LDC operations, dual-fuel capability, the environmental impacts of generators (which are linked to air, water, and fuel permits), and analyses of liquid fuels and regional storage capabilities. It has also partnered with other electric sector organizations such as the New York Independent System Operator (NYISO), PJM Interconnection, Ontario Independent Electricity System Operator, the Tennessee Valley Authority, and the Midcontinent Independent System Operator (MISO) to conduct additional studies, such as multiregional, steady-state and transient hydraulic natural gas studies, North American Electric Reliability Corporation and Northeast Power Coordinating Council natural gas assessments, and the current Eastern Interconnection Planning Collaborative Gas- Electric System Interface Study. These efforts have strengthened ISO-NE s understanding of gas supply and transportation issues and have driven additional operational and business intelligence improvements across the organization. Winter Reliability Program Perhaps the most critical factor in preventing disruptions during the winter was the Winter Reliability Program (WRP) established by ISO-NE to protect electric system reliability. The WRP was established to encourage oil-fired generators to procure additional fuel oil and for additional winter-period demand response (DR). It allocated approximately US$75 million to oil and dual-fuel participants to store an additional 3 million barrels of in-region oil reserves to support generation when and if gas could not be delivered to merchant generators and for DR resources to be available during stressed system conditions. This stored fuel proved to be a critical resource during the winter, as ISO-NE used nearly 2.7 million barrels of oil by February ISO-NE plans to implement a similar out-of-market program again for the winter season as well as an LNG program. New England s Experience: No Longer Just a New England Problem The ISO-NE experience during the winter exposed problematic areas common across the power sector and has illustrated some of the challenges for continued gas-electric integration. These areas and challenges are discussed below. Impact of the Polar Vortex on Multiple Regions As noted earlier, the destabilized polar vortex generated powerful cold fronts and low temperatures across large sections of the United States. While there were no major disruptions to gas or electric systems during the winter, an analysis performed by ICF International shows that there were electric supply issues during the coldest days in a number of locations. Further, a substantial portion of the reduction in electric capacity is directly attributed to fuel supply issues. For example, during a relatively cold period occurring on 6 7 January 2014, PJM had almost 10 GW of generation out of service due to inadequate fuel supplies, and it was not alone (see Figure 7). NYISO lost 2.2 GW, MISO lost 6.7 GW, and the Southwestern Power Pool (SPP) lost 2.4 GW of generation due to fuel supply issues. By comparison, ISO-NE lost only 1.2 GW of generation. Shifting Resources Will Increase Gas Demand In addition to the dramatic changes in the mix of power system resources discussed earlier, the electric sector will also see a rash of power plant retirements in the next few years. Approximately 33 GW of U.S. coal, nuclear, and gas-and-oil capacity (made up mostly of older dual-fuel units) is expected to retire by 2016 (see Figure 8). New builds will counterbalance the retired resources; the majority of the new units will perform gas-fired generation, however. This is likely to heighten the importance of gas-electric coordination, suggesting that some of the issues brought into relief during the winter are here to stay. Furthermore, though renewable generation is increasing, some renewables can be intermittent generators that cannot be relied on at all times to meet firm customer demands. More Challenges Ahead? Given the expected continued growth in gas-fired generation, sufficient gas supply and transport is of paramount concern to 26 ieee power & energy magazine november/december 2014

8 To date, FERC initiatives have focused on coordinating real-time gas-electric system operations, not necessarily on longer-term planning. parties focused on gas-electric integration. To investigate the adequacy of gas supply in New England, ISO-NE recently commissioned another natural gas study that focused on benchmarking the winter operations. Conducted by ICF International, the study revealed clear limitations in natural gas supply availability for power generation. The benchmarking study provides an assessment of the balance between nonpower gas loads throughout the winter and gas supply for New England, including operationally available capacity for all pipelines entering New England, LNG imports into the area, and supplies from peak-shaving facilities. It shows that regional gas supplies available to power generators were below 1,000 MMft 3 /d for approximately 45 days during the winter and under 500 MMft 3 /d for roughly 20 days (see Figure 9). This available gas supply provided fuel for between 2 GW and 5 GW of gas generation at applicable heat rates. The supply levels are relatively low versus historical averages for gas used by power providers in New England. The conclusion is therefore that the cold winter weather clearly limited the amount of supply available to power generators. The ICF study also projected gas supplies remaining for electric generators in by using the same study assumptions to arrive at the balance for this past winter and using 20 years worth of historical temperature data. The projected levels of gas supply were compared against the ISO-NE forecast of daily gas use by power providers, and the results of the comparison are summarized in Figure 10. The intent of the comparison is to determine the number of days during which gas demand would exceed available supplies across the different temperature scenarios and identify the amount of the gas deficit. The analysis indicates between five and 51 days of deficit for the electric sector during the winter of , depending on weather conditions. In a very cold winter weather scenario that closely aligns with the winter, there will be roughly 50 days of deficit. In addition, the comparison shows sizable amounts of deficit, averaging between 1 GW and 2 GW of electrical capacity. This look forward suggests that the gas supply Millions of Cubic Feet per Day 2,000 1,800 1,600 1,400 1,200 1, Type Retirements Winter Days 1 December Through 28 Feburary Ordered Coldest to Warmest Day New Builds Net Change Coal Gas/Oil Nuclear Renewables Others Total figure 8. Power plant capacity retirements and new builds (GW), constraints for New England that were observed during the winter are likely to continue well into the future, barring significant pipeline capacity expansion, significant incremental deliveries of LNG into the market, or expanded oil backup programs. In Search of Solutions To date, FERC initiatives have focused on coordinating realtime gas-electric system operations, not necessarily on longer-term planning. FERC Order 787 allows interstate natural gas pipelines and electric transmission system operators to share nonpublic operational information with each other to 10,000 8,000 6,000 4,000 2,000 figure 9. Projected gas supplies for power generators for winter Megawatts Equivalent november/december 2014 ieee power & energy magazine 27

9 While robust natural gas supply development is continuing to spur interest in natural gas, questions about natural gas and electricity integration persist. Winter Weather Scenarios Duration of Risk (Number of Days) Total Winter Fuel Supply Deficit (MMcf) Average Daily Generation Deficit (MW Unavailable) Median (50/50) 34 10,680 1,310 Minimum (5/95) make gas and power service more reliable. Additional FERC orders address ISO and RTO system scheduling and how pipelines post information about released capacity. A March 2014 notice of proposed rulemaking (NOPR) issued by FERC proposed shifting the scheduling of the gas day to better align with electric market scheduling and adding two to three intraday nomination cycles to allow more flexibility in scheduling pipeline nominations. Some LDCs and western pipelines, however, expressed concerns that changing gas day scheduling could result in additional costs and potential unintended consequences (e.g., shifting problems westward). Although these changes may help with the near-term coordination of gas and electric system operations, the gas transportation capability issues will remain. The Western Interstate Energy Board, EIPC, Eastern Interconnection States Planning Council (EISPC), and the Electric Reliability Council of Texas have sponsored studies on gas-electric integration. In addition, a project currently being completed for EISPC by ICF is focused on projecting the potential for unmet fuel requirements and assessing multiple options for meeting load, including new pipeline capacity, increased conventional underground storage, addition of high-deliverability underground storage, incremental LNG peak-shaving storage capability and/or addition of compressed gas storage, and incremental fuel-switching capability. ISO-NE s Long-Term Response to Gas-Electric Integration Issues ISO-NE is approaching the gas-electric integration challenges as an availability, reliability, and price issue and is attempting to implement a number of internal and regional market responses to mitigate this risk. In particular, ISO-NE is implementing new approaches to coordination with its gas market partners Maximum (95/5) 51 21,931 1,793 figure 10. The duration of risk analysis for the winter. ISO-NE will allow offers from generators to reflect different onand off-peak hourly prices and will let resources change their offers during the operating day to reflect volatile gas prices. Both of these efforts are targeted to begin in December ISO-NE is also proposing the introduction of forward capacity market (FCM) performance incentives (basically a pay for performance approach) that would enhance incentives within the FCM to strengthen fuel supply arrangements. This proposal has been accepted by FERC (with modification) and is targeted for the 9th Forward Capacity Auction, which procures capacity resources for the period from June 2018 to May The New England States Committee on Electricity recently proposed a new ISO-NE tariff stream to fund regional gas and electric transmission, but this approach is still being developed and raises several questions including FERC approval and the details as to which organization or organizations would own and manage the daily gas capacity release. Conclusion The experience of the winter exposed some potentially serious challenges related to gas-electric integration. Significant questions concerning adequacy of gas transportation infrastructure, intersector coordination, and regulatory reform remain. ISO-NE s experience also illustrates that critical operational and contractual improvements, along with resource adequacy assessments, are key to addressing gas-electric integration questions. For Further Reading ISO New England. (2004, 10 May). Final report on electricity supply conditions in New England during the January 14 16, 2004 Cold snap. [Online]. Available: pubs/spcl_rpts/2004/final_report_jan2004_cold_snap.pdf ISO New England. (2014, 19 June) Regional System Plan. [Online]. Available: rsp/index.html EGOC meeting agendas, minutes, and materials are publically posted on the ISO-NE Web site. [Online]. Available: egoc/index.html Biographies Mark Babula is with ISO New England, Holyoke, Massachusetts. Kevin Petak is with ICF International, Fairfax, Virginia. p&e 28 ieee power & energy magazine november/december 2014