FERC staff offers Q4 2014 update on gas-electric coordination

Federal Energy Regulatory Commission staff on Dec. 18 filed its eighth and final quarterly update on national and regional Gas-Electric Coordination Activities, which is a process that FERC began in 2012 in response to an increasingly high reliance on the transmission grid on highly variable natural gas supplies for power generation.

“In November, the North American Electric Reliability Corporation (NERC) published their 2014-2015 Winter Reliability Assessment,” the report noted. “NERC’s assessment of demand and generation projections for the 2014/2015 winter season indicate adequate resources under normal winter peak demand. However, the assessment states that prolonged and extreme cold weather may prove challenging in parts of North America due to natural gas and coal delivery constraints.

“NERC also highlighted regional challenges in areas where power generators rely on interruptible gas pipeline transportation, natural gas interstate pipelines are constrained to meet demand beyond firm commitments, and gas use for power generation is increasing. With increased reliance on natural gas-fired generation, NERC suggests additional revisions to assessing reliability in the future. For example, following last winter’s Polar Vortex events, NERC developed extreme weather scenarios to assess the potential impacts on reliability. Additionally, going forward, NERC recommends including assessment of fuel availability and deliverability when conducting resource adequacy assessments.”

Around the country, the report said:

  • In the Eastern Interconnection, key stakeholders (including ISOs/RTOs, planning authorities, and the states) continue to work collaboratively on an inter-regional basis to study natural gas-electric coordination issues and assess infrastructure adequacy.
  • The New England States Committee on Electricity (NESCOE) Incremental Gas for Electric Reliability (IGER) proposal is on hold awaiting the completion of study commissioned by the Massachusetts Department of Energy Resources, which is expected to be publicly released on Dec. 23. Specifically, DOER has retained Synapse Energy to conduct a modeling analysis of various gas demand scenarios and to evaluate a range of solutions to meet Massachusetts’ short and long term resource needs, while considering greenhouse gas reductions, economic costs and benefits, and system reliability.
  • On Nov. 20, consultant ICF released the Phase II Report on the assessment of New England’s natural gas pipeline capacity and its capability to satisfy short and near-term (through 2020) generation needs. Similar to the 2011/2012 Phase I study, Phase II analyzed the potential for shortfalls in natural gas supply to electric generators through 2020 given currently available pipeline capacity and expansion projects likely to come online before 2020. For the Phase II study, ICF performed a new review of pipeline contracts, updated the timing and size of pipeline expansions in New England, as well as revised liquefied natural gas (LNG) availability. On the electric side, Phase II provides revised assumptions on power generation retirements and energy efficiency under four generation forecasts. Revised Phase II projections for natural gas supplies available to electric generation throughout the winter 2014/15 average nearly 500 MMcfd lower than projected in Phase I, assuming 2013/14 winter temperatures.
  • PJM Interconnection continues to work with its stakeholders to address a variety of gas-electric coordination issues. For example, since early September, the PJM Operating Committee has provided education and training sessions to stakeholders on existing business rules for intraday cost-based scheduling submissions, procedures for switching between cost and price-based schedules, and PJM rules for cost reimbursement. During these sessions stakeholders and PJM staff discussed proposed additions to the existing information collected by PJM from generation owners, with the goal of providing both dispatch operators and generating units with more accurate information beyond day-ahead market postings, as well as allowing generation owners more opportunities to submit cost schedules that better reflect the costs of cold-weather operations and fuel market volatility. This resulted in proposed new datafields for generators to submit to PJM, including dual-fuel capability, availability, and fuel switching transition times, as well as generators’ operational restrictions.
  • The Midcontinent ISO has taken several steps to learn from last winter’s gas-electric coordination challenges and better prepare for winter 2014/2015, including hosting a Winter Readiness Workshop with stakeholders. As part of its 2014/15 Winter Resource Assessment released in November, MISO found sufficient resources are available to meet electricity demand this winter, highlighted by over 46 GW of capacity from all resource types in excess of projected peak load, a 45% projected reserve margin. MISO learned that 35 GW out of 69 GW of its gas-fired generation lacks firm natural gas transportation service or dual-fuel capability. Finally, MISO is directing generation owners to prepare for winter based on recommendations from NERC.
  • In the Southwest Power Pool (SPP), the Gas Electric Coordination Task Force is finalizing a proposal to amend the SPP day-ahead market timeline to align with the proposed revised NAESB Timely Nomination Cycle deadline of 1:00 pm Central for scheduling interstate natural gas pipeline transportation. The proposed changes to the day-ahead market timeline are aimed at maintaining reliability during fuel constraints and ensuring that the day-ahead market timeline compliments gas markets and dispatch scheduling requirements. SPP completed its 2014/15 winter preparedness plan, and presented the plan to the SPP Balancing Authority Operating Committee on Dec. 4. The 2014/15 winter preparedness plan describes emergency operating procedures for coordination and communication during critical cold weather events, as well as general best-practices for operations during the winter season.
  • In the West, Phase 2 of the Western Interstate Energy Board’s (WIEB) Natural Gas–Electric and System Flexibility Assessment was finalized last quarter and the Assessment is now complete. The State Provincial Steering Committee (SPSC) directed WIEB Staff to further develop scopes of work for a potential Phase 3 of the Gas-Electric Interdependency Study, focusing on the use of wind and solar forecasts in gas nominations and in communication with pipelines. A potential study on distribution system issues has also been proposed.
  • ColumbiaGrid is in the process of completing its coal retirement study, which is examining the transmission impacts of replacing coal units with natural gas. The final study report is scheduled for December 2014.
  • On Sept. 16, the California ISO released an issue paper and initiated a new Natural Gas Pipeline Penalty Recovery stakeholder process to discuss circumstances under which market participants may be able to recover natural gas pipeline penalties through the CAISO bid cost recovery mechanism. The proposal was initially discussed in 2012 within the stakeholder process, but CAISO did not file a proposal with FERC at that time. Instead, CAISO undertook an outreach effort with intra-state and interstate pipelines to understand and address any potential reliability issues such a cost recovery mechanism might cause pipeline operators. After conducting outreach, the ISO believes it is not prudent to act now to allow recovery of natural gas pipeline penalty costs given increased gas and electric coordination efforts, as well as Southern California Gas’ filing to implement in the future operational flow orders similar to those in place at Pacific Gas and Electric.

Several gas pipeline projects are in the works

The staff report also updated the commission on relevant natural gas and electric filings submitted to or pending before FERC, starting with natural gas pipeline filings. During the fourth quarter the commission received three new filings to expand pipeline capacity serving electric generation, approved one proposed project, approved the start of operations of four projects, and acted on numerous compliance filings concerning interstate natural gas pipeline compliance with the requirement to post offers to purchase released capacity.

  • The first new filing proposing to expand pipeline capacity to serve electricity generation was made by Florida Southeast Connection (FSC), which requested authorization on Sept. 26 to construct facilities spanning from an interconnection with the proposed Sabal Trail Transmission pipeline near Intercession City, Florida, to a delivery point serving the Florida Power & Light‘s solar-thermal Martin Clean Energy Center, near Indiantown, Florida. FSC will have an initial transportation capacity of 640 MMcfd.
  • Turning to commission approvals, Eastern Shore Natural Gas received approval on Sept. 30 to go in-service for its White Oak Lateral Project. The proposed project will provide 55 MMcfd of firm transportation service for Calpine Energy Services LP supporting a new gas-fired generation plant in Kent County, Delaware.
  • On Oct. 1, Southeast Supply Header Pipeline (SESH) received approval to place in-service the 45-MMcfd increase in its design capacity of its mainline system. The added capacity will provide firm pipeline transportation capacity from the beginning of SESH’s system near Delhi, Louisiana, to the end of its system near Coden, Alabama.
  • On Oct. 27, Sierrita Gas Pipeline received approval to place into service its 200-MMcfd facilities located in Pima County, Arizona, while on Oct. 30, NET Mexico Pipeline Partners received approval to place into service its 2.1-Bcfd NET Mexico Pipeline Project located in Starr County, Texas.
  • On Oct. 30, Florida Gas Transmission was granted a certificate of public convenience and necessity to increase the maximum delivery quantity by 25 MMcfd to FPL through increased compression in Broward County, Florida.
  • On Oct. 30, NET Mexico Pipeline Partners received approval to place into service the NET Mexico Pipeline Project located in Starr County, Texas. The facility will have a design capacity of 2.1 Bcfd and will provide supply to the expanding natural gas demand from gas-fired power generation in Mexico.
  • On Dec. 3, Dominion Cove Point LNG LP (DCP) filed an application to construct the St. Charles Transportation Project located in Fairfax County, Virginia, and Charles County, Maryland. DCP states that the project will provide 132 MMcfd of incremental firm transportation service to CPV Maryland LLC which is proposing to build a 725-MW natural gas-fired combined cycle plant in Charles County known as the St. Charles Energy Center. DCP also filed to provide an incremental 107 MMcfd of firm transportation to a proposed 735-MW natural gas-fired combined cycle plant in Prince George’s County, Maryland, known as the Keys Energy Center.
About Barry Cassell 20414 Articles
Barry Cassell is Chief Analyst for GenerationHub covering coal and emission controls issues, projects and policy. He has covered the coal and power generation industry for more than 24 years, beginning in November 2011 at GenerationHub and prior to that as editor of SNL Energy’s Coal Report. He was formerly with Coal Outlook for 15 years as the publication’s editor and contributing writer, and prior to that he was editor of Coal & Synfuels Technology and associate editor of The Energy Report. He has a bachelor’s degree from Central Michigan University.