Climate change policies at the state and federal levels will have significant impacts on natural gas companies and their customers.  On the one hand, there is pressure on companies to maintain safe and reliable service – on the other, the push for net-zero carbon emissions by 2050.  These competing objectives will have notable effects on how companies conduct their long-term planning to maintain system reliability while avoiding potential stranded costs and safeguarding ratepayers.  This post and subsequent updates will focus on how federal and some state regulators are addressing the issues.

Federal

The Biden Administration’s clean energy plan, which calls for a 100% clean energy economy by 2035 and net-zero emissions economy-wide by no later than 2050, has sparked an increased focus on achieving these goals. To reach net-zero by 2050, the Biden Administration plans to invest $1.7 trillion in federal funds in clean energy research and modernization, deploy zero emission vehicles across the government, and enforce the cost of carbon against polluters. The Biden Administration has also prioritized environmental justice at the government level, creating a White House Environmental Justice Advisory Council and White House Environmental Justice Interagency Council, and directing agencies to address environmental injustices.

FERC

On President Biden’s first full day in office, he promoted Federal Energy Regulatory Commission (“FERC”) Commissioner Richard Glick to FERC Chairman. Chairman Glick has stated that one of his leadership priorities is incorporating climate change impacts into FERC’s decision-making process. In his first two months in charge, Chairman Glick has launched several initiatives to further that goal, including:

• Creating the Office of Environmental Justice, a senior position at FERC to coordinate efforts to incorporate environmental justice and equity concerns into FERC’s decision-making process.

• Reopening the 2018 Notice of Inquiry docket looking into FERC’s Pipeline Certificate Policy Statement, and asking for stakeholder comments regarding how: (i) FERC should deal with a proposed pipeline project’s potential greenhouse gas (“GHG”) emissions, (ii) FERC and applicants should address a proposed project’s impacts on climate change, and (iii) pipeline project proposals may impact environmental justice (Docket No. RM18-1; comments due April 26, 2021).

• Initiating a number of technical conferences related to climate change and the changing resource mix:

  • Technical conference regarding Resource Adequacy in the Evolving Electricity Sector (Docket No. AD21-10)

  • Technical conference to discuss the shift from non-electric to electric sources of energy at the point of final consumption (e.g., to fuel vehicles, heat and cool homes and businesses, and provide process heat at industrial facilities) (Docket No. AD21-12)

  • Technical conference to discuss issues surrounding the threat to electric system reliability posed by climate change and extreme weather events (Docket No. AD21-13)

  • Technical conference to discuss resource adequacy developments in the Western Interconnection (Docket No. AD21-14)

On March 17, 2021, FERC for the first time considered how a proposed pipeline’s GHG emissions would affect climate change (Docket No. CP20-487). FERC voted 3-2 to approve Northern Natural Gas Company’s proposed 87-mile pipeline replacement in South Dakota and Nebraska, finding that the climate impact would not be significant. While Chairman Glick has previously emphasized the need for FERC to address climate impact in its evaluation of pipeline certification, the decision marks a policy shift from the formerly Republican-chaired Commission.

States

Although the Biden Administration’s clean energy plan may accelerate the transition to clean energy nationwide, some states are already ahead of the pack. By mid-2020, at least 15 states and territories had “taken legislative or executive action to move toward a 100 percent clean energy future.”^[1] On the flipside of the momentum toward net-zero emissions is the potential fallout from the decline of resources that do not further, and may actually hinder, achieving net-zero goals. A few states are investigating the effect of the urgent pursuit of climate mandates on the natural gas industry and its customers and developing strategies to mitigate adverse impacts.

Massachusetts

On October 29, 2020, the Massachusetts Department of Public Utilities (“DPU”) opened a proceeding (D.P.U. 20-80) to examine the role of Massachusetts’ natural gas local distribution companies (“LDCs”) in helping the Commonwealth achieve its 2050 climate goals^[2] while safeguarding ratepayer interests, and ensuring safe, reliable, and cost-effective gas service.  The DPU is soliciting utility and stakeholder input to develop a regulatory and policy roadmap to “guide the evolution of the gas distribution industry, while providing ratepayer protection and helping the Commonwealth achieve its goal of net-zero GHG emissions energy.” The DPU has directed the LDCs to initiate a joint Request for Proposals (“RFP”) for an independent consultant to study and prepare a report analyzing the 2050 Decarbonization Roadmap and the 2030 Clean Energy and Climate Plan (the “Roadmaps”)^[3] and potential strategies not addressed in the Roadmaps, and study each LDC for the feasibility of all pathways.

In a March 1, 2021 update, the LDCs confirmed that they issued their RFP on February 5, 2021 to a list of consultants vetted with the Attorney General’s Office. The LDCs anticipate selection of a consultant by March 17, 2021, and execution of a contract with the consultant by March 26, 2021.

Colorado

On October 7, 2020, the Public Utilities Commission of Colorado (“Colorado PUC”) opened a repository proceeding (Proceeding No. 20M-0439G) seeking comments relating to the Colorado PUC’s investigation of retail natural gas industry greenhouse gas emissions in light of the state’s GHG emission reduction goals adopted in House Bill 19-1261.  The Bill established statewide goals to reduce 2025 GHG emissions by at least 26%, 2030 GHG emissions by at least 50%, and 2050 GHG emissions by at least 90% of the state’s 2005 GHG emission levels. While House Bill 19-1261 did not establish specific requirements for the gas sector, the Colorado PUC intends to investigate whether such changes could help the state satisfy its emission reduction goals. Given the “market uncertainty and the relatively short timeline to make significant progress on the statutory [GHG] emission reduction goals,” the Colorado PUC is seeking information on specific topics, such as:

• Options available to decarbonize retail natural gas and the high-level costs and benefits to gas and electric utilities for these options

• Potential stranded assets and means to minimize stranded assets

• Cost-effective means of maintaining system safety with a decrease in customer base or shift in business model

• Potential for electrification of current natural gas loads, the associated costs, and the possible impacts on natural gas and electric utility operations

• Potential steps the Colorado PUC can take now while long-term technological and regulatory changes are implemented

The Colorado PUC is seeking this information to understand the “potential impacts to utility systems and how those impacts may affect utility investments and the rates utilities charge Colorado customers.”

The settlement of Public Service Company of Colorado’s (“PSCo”) rate case before the Colorado PUC in early 2020 (Proceeding No. 20AL-0049G) addressed PSCo’s natural gas infrastructure and associated emissions. The parties agreed that if, in the future, the Colorado Department of Public Health and Environment or Air Quality Control Commission adopts a rule addressing greenhouse gas emissions from PSCo’s natural gas infrastructure or from the end-use of its gas commodity, the settling parties will take measures to align long-term infrastructure planning with climate goals. To date, neither agency has initiated adoption of such a rule.

New York

New York’s climate mandate^[4] calls for a zero-emission electricity sector by 2040, including 70% renewable energy generation by 2030, reduction of statewide GHG emissions to 40% of 1990 levels by 2030 and 85% by 2050, and a plan to reach economy-wide carbon neutrality.

On March 19, 2020, the New York State Public Service Commission (“NYPSC”) initiated a proceeding to consider issues related to gas utilities’ (“LDCs”) planning procedures (Case No. 20-G-0131). Specifically, the NYPSC seeks to establish “planning and operational practices that best support customer needs and emissions objectives while minimizing infrastructure investments and ensuring the continuation of reliable, safe, and adequate service to existing customers.” The NYPSC also sought to address planning and operational practices to reduce the risk of utility imposed moratoria on new customers.

On February 12, 2021, NYPSC staff submitted both a moratorium management proposal and gas system planning process proposal. The moratorium management proposal sets forth criteria to manage future moratoria, if required. This includes development of comprehensive customer communication plans, reliability metrics to identify the need for a moratorium, prioritization of customer classes, rules that apply during a moratorium, and requirements to lift a moratorium.

NYPSC staff’s gas system planning process proposal seeks to “help guide the LDCs into New York State’s low carbon future and limit unnecessary infrastructure investment and the potential for stranded costs that might result.” The highlights of staff’s proposal are:

• LDCs will make a long-term gas system plan filing on a three-year cycle. Notably, the filing must contain a “no infrastructure option” that includes a mix of utility-sponsored demand reduction measures that will close any gap between the projected load and available supply. This option should include one or more contingency solutions that can be called upon if necessary. The no infrastructure option should also include non-pipeline alternatives (“NPA”) and a corresponding framework that contains: (1) NPA suitability criteria; (2) an NPA cost recovery procedure; and (3) an NPA incentive mechanism. These filings will be subject to stakeholder participation. Other components of this filing include:

  • demand forecast

  • supply forecast

  • reliability standards and anticipated reliability

  • capital projects

  • a comparison of alternatives, including: (i) benefit-cost analyses; (ii) estimated bill impacts and net present value of costs of each alternative; (iii) emissions impacts; and (iv) utility incentive mechanisms

  • a summary investment plan

• LDCs will file annual reports on the LDC’s progress on its most recent long-term gas system plan including any changed circumstances that materially affect gas system planning.

• Each year, LDCs will also file a report on actual natural gas throughput for the year ending March 31 by customer class, and during the winter period and on the peak day.

A stakeholder forum is scheduled for March 25, 2021, and initial comments on the staff proposal are due by May 3, 2021, with reply comments due on June 4, 2021.

California

On January 27, 2020, the California Public Utilities Commission (“California PUC”) instituted a rulemaking (R. 20-01-007) to respond to “past and prospective events” that together will require changes to “policies, processes, and rules that govern the natural gas utilities in California.”^[5] With respect to future challenges, the California PUC stated “[o]ver the next 25 years, state and municipal laws concerning [GHG] emissions will result in the replacement of gas-fueled technologies, and, in turn, reduce the demand for natural gas.” The proceeding is comprised of three phases, in which the California PUC intends to: (1) develop and adopt updated reliability standards that reflect the current and prospective operational challenges to gas system operators (Track 1A); (2) determine the regulatory changes necessary to improve the coordination between gas utilities and gas-fired electric generators (Track 1B); and (3) implement a long-term planning strategy to manage the state’s transition away from natural gas-fueled technologies to meet California’s decarbonization goals (Track 2).

The state’s Renewable Portfolio Standard (“RPS”) goals require retail sellers of electricity to procure a certain percentage of generation from renewable resources over the next 25 years. The California PUC recognizes that “[a]s retail sellers procure less electricity from gas-fired generators . . . the gas throughput assigned to these customers will also decline, thereby allocating more costs to remaining customers.” The decrease in demand in natural gas will cause the natural gas pipeline system to no longer be “used and useful,” and therefore, ineligible for rate recovery, potentially leaving gas utilities with excessive stranded costs. Customers who remain on the system would then be required to cover the revenue requirement and the remaining pipeline system at higher rates. The California PUC’s goal through the rulemaking is to develop “regulatory solutions and planning strategy . . . to ensure that, as the demand for natural gas declines, gas utilities maintain safe and reliable gas systems at just and reasonable rates, and with minimal or no stranded costs.”

The California PUC plans to evaluate demand scenarios that “materialize from state and local [GHG]-related laws,” and use data provided by the gas utilities on “how forecasted demand scenarios will translate into gas operational gas flows on their systems . . . , accounting for balancing and pressure rating requirements.” Using this information, the California PUC will examine “the extent to which the projected reduction in gas demand will require regulatory changes, such as shortening the useful life of gas assets, to ensure that gas transmission costs are allocated fairly and that stranded costs are mitigated.”

While the first two phases are currently underway, the Track 2 phase of the proceeding, which addresses the long-term natural gas policy and planning issues, is tentatively scheduled to begin in mid-June 2021.

This is the first post in an ongoing series focused on regulatory response to natural gas challenges in a net-zero emission future. 

^[1] Sam Ricketts, et al., States are Laying a Road Map for Climate Leadership, Center for American Progress (Apr. 30, 2020), https://www.americanprogress.org/issues/green/reports/2020/04/30/484163/states-laying-road-map-climate-leadership/.

^[2] In 2008, Massachusetts enacted the Global Warming Solutions Act (“GWSA”) establishing a comprehensive regulatory program to address climate change.

^[3] See Massachusetts 2050 Decarbonization Roadmap, Mass. Exec. Office of Energy and Envir. Affairs (Dec. 2020), available at https://www.mass.gov/doc/ma-2050-decarbonization-roadmap/download; see also Interim Clean Energy and Climate Plan for 2030, Mass. Exec. Office of Energy and Envir. Affairs (Dec. 30, 2020), available at https://www.mass.gov/doc/interim-clean-energy-and-climate-plan-for-2030-december-30-2020/download.

^[4] Climate Leadership and Community Protection Act of 2019, Chapter 106 of the Laws of 2019.

^[5] Order Instituting Rulemaking to Establish Policies, Processes, and Rules to Ensure Safe and Reliable Gas Systems in California and Perform Long-Term Gas System Planning, California Pub. Utils. Comm’n, Rulemaking 20-01-007 (Jan. 27, 2020), available at https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M325/K641/325641802.PDF.