Monthly Archives: January 2023

Climate Choices Part II — Session Law 2021-165 (Carbon Reduction Plan)

January 22, 2023.  A 2021 North Carolina  law requires the N.C. Utilities Commission (NCUC) to “take all reasonable steps” to achieve a 70% reduction in carbon dioxide (CO2)  emissions from electric generating units (EGUs) by 2030 and achieve carbon neutrality for the utility generation system by 2050.   More below on the requirements of  Session Law 2021-165  (also referred to as House Bill 951) and NCUC action in response. The next post will look at the potential overlap of the S.L. 2021-165 carbon reduction plan with draft rules (described in the previous post) under consideration by the N.C. Environmental Management Commission.

The Reduction Goal.  Session Law 2021-165  set a goal of reducing CO2 emissions from EGUs 70%  (from a 2005 baseline of 75,865,188 short tons) by 2030 and achieving carbon neutrality by 2050. Under the law, “carbon neutrality” means that for every ton of CO2 emitted in the state by a regulated EGU an equivalent amount of CO2 must be reduced, removed, prevented, or offset. The law limits offsets to 5%. The NCUC can extend the CO2 reduction timelines by two years — or longer if necessary to allow for completion of a  new nuclear or wind energy facility essential to the carbon reduction plan.

The reduction goals apply to electric utilities that are: 1. regulated by the Utilities Commission;  and 2. served at least 150,000 North Carolina retail jurisdictional customers as of January 1, 2021. The law does not apply to EGUs operated by  local government utilities; electric membership co-ops; industrial facilities; or other institutions since the Utilities Commission doesn’t regulate those facilities.  As a result, the carbon reduction plan will only affect EGUs at power plants owned  by the two investor-owned utilities operating in North Carolina — Duke Energy Carolinas and Duke Energy Progress.  As a practical matter, however, those two utilities account for over 80% of the total CO2  emissions from electric power generation in the state.

A few other things to understand about S.L. 2021-165.  First, the law is directed to the Utilities Commission rather than the electric utilities.  It authorizes the Utilities Commission to take  “all reasonable steps” to achieve the CO2 reduction goals and adopt a plan by December 31, 2022 to do so. The law does not directly mandate that the utilities meet the reduction goals; create penalties for a utility’s  failure  to meet the goals; or address  how emissions levels will be monitored and reported to show  whether the goals have been met.  Instead, the law relies on the NCUCs  existing authority to approve/disapprove utility-owned generation facilities and related authority to allow the utilities to recover the cost of facilities and operations through rates charged to customers.  

In developing the plan, the law directs  the Utilities Commission to follow existing state law with respect to least-cost generation of power and maintain system reliability.  So the law requires a balancing of consumer costs/system reliability and reduction of greenhouse gas emissions. 

The law also requires “new generation facilities or other resources” selected by the Utilities Commission  as part of the plan  must be owned by the utility. There is an exception for solar; the law provides that 45% of new solar included in the reduction plan must be supplied by third parties through power purchase agreements. The Utilities Commission has interpreted the statute language to mean that power purchase agreements cannot be used to acquire other energy resources (such as wind energy) to meet the reduction goals even though that may be a lower cost alternative to new energy project development.

Carbon Reduction Plan. As a first step, the Utilities Commission required Duke Energy to submit a proposed carbon reduction plan in May 2022.  Instead of a single proposed plan,   Duke Energy submitted four alternative plans for the Utilities Commission to consider. All four plans proposed to phase-out all of the state’s remaining coal-fired power plants although   closure  dates varied. The plans differed in the mix of new energy sources (natural gas, solar, battery storage, nuclear and wind) to replace coal and the timelines for bringing those new sources on line. Duke Energy projected that only one of its four portfolios of energy resources  would meet the 70% interim reduction goal by 2030; others met the interim goal two to four years later.

NCUC Order. On December 30, 2022, the NCUC issued an order that put a number on the 70% reduction target for 2030 (22,759,556 short tons of CO2), but the Commission did not adopt any of the four plans proposed by Duke Energy to meet the reduction goals. The NCUC declined to endorse a specific energy portfolio capable of meeting the interim and final CO2 reduction goals at all. Instead, the Utilities Commission authorized Duke Energy to take a number of near-term actions in 2023-2024 and created a process for  reviewing the  electric generation portfolio every two years.

An existing NCUC rule, R8-60-1,  already required electric utilities to submit an integrated resource plan (IRP) to the Utilities Commission every two years. The IRP forecasts electric power demand over a 15 year period and  describes how the utility will meet projected demand through a combination of electric generation; power purchase; demand-side management (such as programs to reduce peak use); and energy efficiency. The NCUC’s order basically repurposes the  IRP as a vehicle for identifying the most cost-effective and reliable mix of energy sources to meet the CO2 reduction goals.

The NCUC order allows Duke Energy to take initial steps common to most of  Duke’s alternative energy portfolios in the next two years, but defers decisions about the energy mix needed beyond 2023-2024 to meet the reduction goals.  Actions authorized in the near term tend to be low risk (in terms of cost and reliability) and avoid commitments to more complex  long-term projects. The  order also directs Duke Energy to address a number of cost and feasibility questions in the first carbon reduction IRP.  For example, the NCUC has asked for information on the impact of federal subsidies and tax incentives  (such as those in the Inflation Reduction Act) that may reduce some renewable energy costs. The order also directs Duke Energy to further evaluate both onshore and offshore wind projects. The NCUC report notes questions about the practicality of developing an onshore wind project by 2029 and costs related to connecting both onshore and offshore wind projects. Duke Energy’s  first carbon reduction IRP will be due in September 2023 and the NCUC will take action on that IRP in 2024.

This incremental approach  gives the Utilities Commission more time to evaluate alternative  energy projects before committing to a plan, but also leaves a significant gap between actions allowed under the December 30, 2022 order and those needed to meet the CO2 reduction goals. For example, Duke Energy projects that 5,980- 7,930 MW  of additional solar will be needed to meet the emission reduction goals, but the December 31, 2022 order only authorizes Duke to procure an additional 2350 MW of solar over a two year period  (2023-2024). The order also defers authorization for any wind energy projects as part of the plan although all four Duke Energy plans included onshore wind resources and three of the four also relied on offshore wind generation.

It is not clear how long the NCUC can continue to allow the carbon reduction plan to evolve,  since  Duke Energy will need to make investments in facilities and enter contractual agreements to bring new energy sources on line. The window for flexibility will close soon for financial and contractual commitments needed to meet the 2030 reduction goal. Realistically,  the first carbon reduction IRP  (2024) will need to  result in a much firmer plan to achieve a 70% reduction in CO2 emissions to have any possibility of meeting the 2030 goal. The 2024  plan will also need to lay the foundation for meeting  the goal of carbon neutrality by 2050.

In short,  the December 30, 2022 NCUC order does not deliver the step by step plan to meet the reduction goals set in S.L, 2021-165  many in the public (and perhaps the legislature) expected. It effectively defers approval of a plan to meet even the interim goal until the 2024 IRP at the earliest. The order takes a conservative approach to acquisition of additional solar generation, authorizing only the amount of solar generation proposed for 2023-2024 out of concern about the cost of connecting more solar more quickly.  It  also withholds authorization for  onshore and offshore wind projects pending additional information on cost; per Duke Energy’s proposed plans, wind projects will be necessary to achieve the 70% reduction goal by 2030-2032.

Among the  near term steps authorized in the NCUC order:

♦  Pursuit of closure plans for existing coal-fired units.  Although timing varied,  all four Duke Energy carbon reduction plans assumed closure of all existing coal fired units by  2036.

♦ Planning for additional natural gas generation (combined cycle units and combustion turbines) to offset lost coal-fired generation. All four Duke Energy carbon plans proposed to add natural gas generation for an extended period of time. The approach has been controversial since natural gas also produces CO2 emissions although at lower levels than coal combustion.  The Utilities Commission accepted Duke Energy’s justification for increased natural gas generation, but requires the first carbon plan IRP to model the cost and assumptions for natural gas units proposed to operate beyond 2050. Any new natural gas generating units will require individual NCUC approval before construction and the order directs Duke Energy to address natural gas availability in those project proposals.

♦ Pursue extension of federal licenses for existing nuclear power plants serving North Carolina.

♦ Target procurement of 2,350 MW of new solar during the 2023-2024 period.

♦ Begin initial development and procurement activities for 1,000 MW of standalone battery storage and 600 MW of Solar Plus Storage.

♦ Meet with onshore wind stakeholders; explore the potential for a successful request for proposals to develop an onshore wind project;  and consider onshore wind as an additional source in the first carbon reduction IRP if that is supported by modeling.

♦ Take the preliminary steps identified in Duke Energy’s 2022 proposed carbon plan toward development of small modular and advance nuclear reactors.

♦ Further study offshore wind energy leases off the North Carolina coast and report back to the NCUC on the feasibility of including an offshore wind generation project in the  carbon reduction plan. Duke Energy had proposed to acquire a wind lease in the Carolina Long Bay lease area (Cape Fear) currently held by Duke Energy Renewables. The NCUC declined to authorize transfer of the lease, citing questions about the cost of bringing power onshore and creating interconnections with the transmission system. The scope of the study is to include all three areas off the N.C. coast where the federal Bureau of Ocean Energy Management has approved wind energy leases.

♦ Model a higher rate of energy efficiency as part of the total carbon reduction plan. Duke Energy’s proposed plans assumed energy efficiency improvements at 1% of “eligible” retail sales. A number of commenters pointed out that  “eligible” retail sales leaves out wholesale customers and retail industrial customers that opt out of the EE program.  The NCUC order directs Duke Energy to model both a 1.5% improvement in energy efficiency among eligible retail customers and explore programs to extend energy efficiency improvements among wholesale customers.

The entire Utilities Commission report can be found here.  The report is organized around findings of fact and the basis for those findings (by topic) followed by the order listing near-term actions authorized by the Commission at pages 130-135.

Consumer impacts. It is important to understand the influence of the Utilities Commission Public Staff on any carbon reduction plan. The Public Staff  (entirely independent of the NCUC staff)   exists specifically to represent consumers in matters before the NCUC  — particularly with respect to utility rates. As a consumer advocate, the Public Staff  focuses on cost and reliability of service.  One of the challenges of a major transition from fossil fuel to clean energy can be the tension between cost/reliability in the near term versus the long-term benefits of a carbon neutral electrical system.  In developing its report and December 30, 2022 order, the Utilities Commission was very responsive to cost concerns expressed by the Public Staff. Many of the NCUC requests for additional cost information and modeling in the first carbon reduction IRP reflect issues raised by the Public Staff in review of Duke Energy’s proposed plans. The push/pull between competing goals will be something to watch.

Climate Choices Part I — N.C. and the Regional Greenhouse Gas Initiative

January 4, 2023.  By coincidence rather than design,  two different approaches to reducing greenhouse gas emissions from the electric power sector have been under discussion by North Carolina agencies since 2021. This post will describe draft rules being considered by the N.C. Environmental Management Commission (EMC) in response to a petition for rulemaking submitted by Clean Air Carolina and the N.C. Coastal Federation.  The rulemaking petition asked the EMC to adopt rules requiring units serving electric generators of 25 MW or greater to participate in a market-based program to reduce CO2 emissions.

A later post will cover the North Carolina Utilities Commission (NCUC)  Carbon Reduction Plan.  The two approaches share goals of reducing greenhouse gas emissions 70% by 2030 (from a 2005 baseline) and achieving carbon neutrality by 2050.  The approaches differ in the generating units affected (although there is overlap) and the mechanism relied on to achieve the reductions.

The  Proposed  EMC Rules: The draft rules being considered by the EMC would set the stage for North Carolina to join 11 other states in a  market-based program — the Regional Greenhouse Gas Initiative (RGGI) — to reduce carbon dioxide (CO2)  emissions from electric generators.   RGGI relies on a market concept similar to the “cap and trade” program EPA used to incentivize reductions in sulfur dioxide (SO2) emissions contributing to acid rain.

Background on RGGI.  Seven northeastern states created RGGI in 2005. Over time, RGGI has expanded to include eleven east coast states:  Connecticut, Delaware, Maine, Maryland, Massachusetts, New Hampshire, New Jersey, New York, Rhode Island, Vermont and Virginia.

RGGI uses cost to drive down CO2 emissions from electric generating units (EGUs) by requiring each EGU to buy an “allowance”  for each short ton of carbon dioxide it emits annually. In the RGGI context, an “EGU”  means a unit generating electricity for distribution to customers —  an electric utility. Each participating RGGI state sets an annual emission budget that caps CO2 emissions from those EGUs; the combined state CO2 budgets become a regional budget for the RGGI states.  The CO2 emissions budget gradually declines over time; currently, RGGI has a goal of reducing CO2 emissions by 30% (from a 2020 baseline) by 2030.

RGGI conducts quarterly auctions of available allowances (the number based on the CO2 emissions budget and other factors).  EGUs can also purchase allowances directly from other emission sources.   The net proceeds of the RGGI allowance auction (minus an administrative fee)  go back to the participating state governments in proportion to the  state’s share of the total RGGI  emissions budget. RGGI characterizes itself as a “cap and invest” program  because many of the participating states direct their auction revenue to support renewable energy; energy efficiency; measures to mitigate climate impacts; and assistance to low-income households.

Note:  This is a very simple overview  of the way RGGI operates. The RGGI program includes complex provisions on the conduct of auctions; calculation of emissions; emissions record-keeping and reporting; and measures to prevent allowance prices from going either too high or too low. More detailed information can be found through the RGGI website homepage.

The RGGI rulemaking petition. N.C. General Statute 150B-20 allows anyone to petition a state agency to adopt or amend a rule. In January 2021, Clean Air Carolina and the N.C. Coastal Federation filed a  rulemaking petition requesting the EMC to adopt draft rules (included in the petition)  creating the regulatory framework necessary for North Carolina participation in RGGI.

In July 2021, the EMC voted to approve the rulemaking petition. Approval of the  rulemaking petition just means that the EMC has agreed to begin the rulemaking process based on draft rules submitted by the petitioners; it does not commit the EMC to adopt the rules.  The EMC is still in the first stage of the  rule-making process, which requires preparation of a regulatory impact analysis describing the rule’s effects,  including the potential fiscal impact on state government, local government, and others affected by the rule. Once the fiscal analysis has been completed and approved by the Office of State Budget and Management, the  draft rule and the regulatory impact analysis will be released to the public for review and comment.

At this stage of the rulemaking process, the EMC cannot change the draft rule as proposed by the petitioners.  Once the public comment period has closed, the EMC can take one of three actions: 1. adopt the petitioners’ rule draft; 2. adopt the rule with changes to address questions or concerns raised in public comment or EMC discussion; or 3. decline to adopt the rule in any form.

Comparison of the Proposed N.C. Rules to Existing RGGI States. The draft rules submitted to the EMC by Clean Air Carolina and N.C. Coastal Federation use the basic structure of the RGGI program — a state CO2 emissions budget that declines over time and a requirement that each regulated generating unit must purchase an allowance for each short ton of CO2 that it emits. The draft rules differ from those adopted by other RGGI states in some key ways:

♦ The rules apply to a broader set of CO2 emission sources. In the other RGGI states, only electric generating units (EGUs)  associated with electric utilities are required to hold allowances for CO2 emissions.  The proposed N.C. rules would also apply to generating units  of 25 MW or greater that are operated by industries or institutions to generate electricity for their own use. As a result, the N.C. rules refer to “CO2 budget units” rather than EGUs. Under the draft N.C. rules, EGUs are a subset of “CO2 budget units”.

♦ The rules apply to emissions from additional types of fuel. The proposed N.C. rules would apply to CO2 emissions associated with biomass or biofuels as well as fossil fuels.

♦  No North Carolina state agency would directly participate in the RGGI auction process.  Unlike other RGGI states, North Carolina would not allocate the state’s CO2  allowances to the RGGI auction directly. Instead,  the state would develop a state CO2 budget;  create “conditional” allowances based on the budget; and assign those allowances — at no cost — to the regulated generating units in N.C.  The draft rule requires those units to consign their allowances to  RGGI and purchase the allowances back through the RGGI auction before they can be used to comply with the rule.

♦ Net proceeds of the RGGI auction would go back to the CO2 budget units  instead of becoming state revenue.  In other participating RGGI states,  a designated state agency receives the net auction revenues and directs the use of those funds consistent with state law. The draft N.C. rules have the net auction revenues return to the regulated generating units. As a result,  no N.C. state agency would have any direct involvement in the RGGI auction process at either the beginning (consignment of allowances to the auction) or end (receipt of revenues from the auction).

The draft N.C. rules include a provision allowing  CO2 budget units to  use auction proceeds “for public benefit, strategic energy, or other purposes approved by the [N.C. Utilities] Commission”.  Note that a number of the CO2 budget units covered by the draft N.C. rule are not EGUs regulated by the N.C. Utilities Commission;  municipal and co-op systems fall outside the NCUC’s jurisdiction. The Division of Air Quality has determined that the draft N.C. rule would also cover a small number of generating units  operated by an institution or industry to generate power solely for its own use.  In any case, the draft rule language  seems to be sufficiently broad to allow most generating units to use auction revenue just as they use revenue from rates or other sources.  Units that fall under the NCUC jurisdiction would continue to be subject to that commission’s usual oversight with respect to rates and plans to meet electricity demand. 

Since the fiscal analysis of the N.C. rule hasn’t been completed, there is not yet an estimate of the amount of revenue likely to return to the electric generating units covered by the N.C. rule. But the revenues returning to existing RGGI states (reported on the RGGI website ) have been substantial. For example, the state of New York’s revenue  has ranged from  $300,000,000  to $500,000,000 for each 3-year RGGI auction cycle.

♦ The draft rules propose a steeper reduction in CO2 emissions than that required by current RGGI states. The draft N.C. rules require a 70% reduction by 2030 (from a 2005 baseline) and carbon neutrality by 2050. The existing RGGI program has  a goal of 30% reduction in CO2 emissions by 2030, although the participating RGGI states have decided to review the goal given progress to date. The difference would mean a  steeper reduction curve  for N.C. sources compared to those in states currently participating in RGGI.

Next Steps. Before the EMC makes any decision about adoption of the proposed rules, the draft rules will be published for public review and comment along with the regulatory impact/fiscal analysis. The Division of Air Quality originally anticipated that the fiscal analysis would be complete in November 2022, allowing the EMC to receive public comments in early 2023 and make a rulemaking decision in May 2023.   Final approval of the fiscal analysis has been delayed, however,  to allow more time for review by the Office of State Budget and Management. The delay means the EMC may not be able to take any action on the proposed rules until later in the summer of 2023.