At the outset of 2019, Pennsylvania Governor Tom Wolf set a goal for Pennsylvania to significantly reduce greenhouse gas emissions. Now, Governor Wolf plans to achieve that goal by taking the bold step to establish a carbon dioxide cap-and-trade program through executive action. On October 3, 2019, Governor Wolf issued an Executive Order directing the Pennsylvania Department of Environmental Protection (“DEP”) to begin the process for Pennsylvania to join the Regional Greenhouse Gas Initiative (“RGGI”, pronounced “Reggie”). RGGI is a market-based cap-and-trade program implemented by several Northeast states to reduce power sector CO2 emissions. Governor Wolf’s Executive Order made national headlines because of the potential implications of Pennsylvania—a state known for its coal and natural gas reserves—joining RGGI. But this news is only the start of a long regulatory process, one that could realistically take years to become implemented. At this stage, Pennsylvania fossil-fuel power generators should familiarize themselves with RGGI’s requirements and procedures as well as the rulemaking process by which the Commonwealth might join RGGI.
The RGGI Program
RGGI is a collective effort by its member states to create a Northeast regional cap-and-trade program affecting fossil-fuel power plants greater than 25 megawatts. Member states—currently Connecticut, Delaware, Maine, Maryland, Massachusetts, New Hampshire, New York, Rhode Island, and Vermont, with New Jersey in the process of rejoining—each enact statutory or regulatory programs in their respective states that are RGGI compliant. CO2 emitting power plants then participate in RGGI regional auctions to purchase CO2 emission allowances for usage, or to sell on secondary markets. RGGI caps the total amount of CO2 emission allowances, measured in tons of carbon, with the most recent cap being 80.2 MM-tons. Beginning in 2021, the cap will be set at 75.1 MM-tons, which will then be reduced by 30 percent between 2020 and 2030. Proceeds from the auctions are distributed to the respective states for investment in programs to further reduce CO2 emissions, such as energy efficiency, renewable energy, or consumer benefit programs. Continue reading “Pennsylvania Plans to Join the RGGI CO2 Cap-and-Trade Program”
On August 16, 2019, the Federal Energy Regulatory Commission (“FERC” or “the Commission”) issued an order granting in part and denying in part requests for further clarification of its reform of Large Generator Interconnection Agreements (“LGIA”) and Procedures (“LGIP”). Order No. 845-B affirms FERC’s prior findings that the expansion of an interconnection customer’s option to build does not impede transmission owners’ ability to recover a return of and on network upgrades. The order also reiterates FERC’s determination not to revise the pro forma LGIA’s indemnity provisions.
Order No. 845—FERC’s Final Rule revising the pro forma LGIP and LGIA—made various reforms to “improve certainty for interconnection customers, promote more informed interconnection decisions, and enhance the interconnection process.” Among these changes, the Commission expanded interconnection customers’ ability to exercise the option to build transmission providers’ interconnection facilities and standalone network upgrades beyond instances where the transmission provider is unable to meet the interconnection customer’s preferred construction timeline.
A subsequent decision, Order No. 845-A, among other things, rejected arguments that the option build revisions contradicted the United States Court of Appeals for the District of Columbia Circuit’s (“D.C. Circuit”) decision in Ameren Services Co. v. FERC. According to the Commission, “Ameren stands for the principle that the Commission cannot prohibit a transmission owner from earning a return of, and on, the cost of its network upgrades.” In that case, the D.C. Circuit vacated FERC’s orders requiring the Midcontinent Independent System Operator, Inc. (“MISO”) to remove an option under its tariff allowing transmission owners to unilaterally elect to initially fund network upgrades and to thereafter recover the interconnection customer’s portion of the cost burden through periodic network upgrade charges that included a return on the capital investment (i.e., the “transmission owner initial funding option”). Although the Commission initially found the transmission owner initial funding option unjust and unreasonable, the D. C. Circuit remanded the orders directing the Commission to “explain how investors could be expected to underwrite the prospect of potentially large non-profit appendages with no compensatory incremental return.” The Commission reinstated the transmission-owner initial funding option on remand.
Recently, FERC issued an Order to Show Cause why Vitol Inc. and its co-director of financial transmission rights trading should not be found to have engaged in market manipulation by selling physical power in CAISO at a loss to eliminate expected losses on Vitol’s Congestion Revenue Rights. Within 30 days of the date of the Order, Respondents must show cause why they should not be found to have committed market manipulation, pay civil penalties, and disgorgement, as well as make an election under FPA § 31(d)(1) whether to proceed before an Administrative Law Judge or opt to have FERC assess a penalty and then proceed with de novo review by a federal district court.
On July 10, 2019, the Federal Energy Regulatory Commission (“FERC” or “Commission”) issued an Order to Show Cause and Notice of Proposed Penalty to Vitol Inc. (“Vitol”) and Vitol’s co-head of financial transmission rights (“FTR”) trading, Federico Corteggiano (“Corteggiano”), (together, “Respondents”), directing the Respondents to show cause why they should not be found to have violated the anti-manipulation provisions of the Federal Power Act (“FPA”) and the Commission’s regulations.
The Order arises from allegations by FERC’s Office of Enforcement (“Enforcement”) that Respondents engaged in a “cross-product market manipulation scheme” by selling physical power at a loss in the California Independent System Operator (“CAISO”) day-ahead market to avoid even greater losses on their positions in a separate financial product—congestion revenue rights (“CRRs”). Enforcement’s factual allegations and legal analysis, resulting from an investigation into Respondents’ trading, are detailed in the Enforcement Staff Report and Recommendation included with the Order. The investigation was prompted by a report from a CAISO market participant regarding Vitol’s activity.
With the May 1 order, the Commission reaffirms its view that it has concurrent jurisdiction over debtors’ efforts to reject their FERC-jurisdictional contracts in bankruptcy. Further developments in judicial proceedings in the Sixth and Ninth Circuits are expected.
On May 1, 2019, the Federal Energy Regulatory Commission (“FERC” or “the Commission”) denied Pacific Gas and Electric Company’s (“PG&E”) requests for rehearing of two Commission orders asserting concurrent jurisdiction with bankruptcy courts over the disposition of wholesale power contracts PG&E seeks to reject through bankruptcy.1
In its Rehearing Order, the Commission acknowledged a circuit split regarding the relative authorities of the Commission under the Federal Power Act (“FPA”) and the bankruptcy courts under the Bankruptcy Code as they relate to the review and disposition of FERC-jurisdictional contracts in bankruptcy proceedings. However, the Commission affirmed its prior holdings that that “the way to give effect to both the FPA and the Bankruptcy Code is for a party to a Commission-jurisdictional wholesale power contract to obtain approval from both the Commission and the bankruptcy court to modify the filed rate and reject the contract, respectively.”2Continue reading “In PG&E Bankruptcy, FERC Reasserts Concurrent Jurisdiction over the Disposition of Wholesale Power Contracts”
According to FERC Chairman Chatterjee, the electric transmission incentives NOI and a concurrently released NOI on the Commission’s ROE policy “will be critical to ensuring that the energy revolution we’re currently undergoing results in more reliable services and lower prices for customers.” The electric transmission incentives NOI “asks very important questions about whether the Commission should be focused on incentivizing projects with risks and challenges or thinking more broadly about the reliability and economic benefits that transmission projects can provide.” Comments are due 90 days, and reply comments are due 120 days, after publication in the Federal Register.
On March 21, 2019, the Federal Energy Regulatory Commission (“FERC” or “the Commission”) issued a Notice of Inquiry Regarding the Commission’s Electric Transmission Incentives Policy (the “NOI”) in Docket No. PL19-3-000.1 The NOI seeks comments on the scope and implementation of the Commission’s transmission incentives policy, citing numerous developments in transmission planning and development in the 13 years since FERC first promulgated its electric transmission incentives regulations and the seven years since FERC issued its last policy statement on the topic.
FERC is conducting a comprehensive review of its method for determining the appropriate return on equity in jurisdictional rates across the energy industry. Comments are due no later than 90 days, and reply comments no later than 120 days, after the publication of the NOI in the Federal Register.
In a move that has excited the renewable energy and electric storage industries, the Federal Energy Regulatory Commission (“FERC”) last month voted to remove barriers to the participation of electric storage resources in the capacity, energy, and ancillary service markets operated by Regional Transmission Organizations (“RTO”) and Independent System Operators (“ISO”). Pursuant to Section 206 of the Federal Power Act, which requires “just and reasonable rates,” FERC amended 18 C.F.R. § 35.28 to require RTOs/ISOs to revise their tariffs to establish market rules that recognize the physical and operational characteristics of electric storage resources and to facilitate their participation in the RTO/ISO markets. In the same order, FERC also punted on a decision for distributed energy resource aggregation reforms and called for a technical conference to further study possible reforms for the RTO/ISO markets. Continue reading “FERC Advances the Ball on Electric Storage, Calls for a Huddle on Distributed Energy Resource Aggregation”
The Department of Energy (“DOE”) last Friday rolled out a Notice of Proposed Rulemaking (“NOPR”) with the Federal Energy Regulatory Commission (“FERC”) that amounts to requiring subsidies for nuclear plants and coal plants. The NOPR is made under the authority of Section 403 of the Department of Energy Organization Act, which allows the DOE Secretary to propose rules to FERC.
The Federal Energy Regulatory Commission (“FERC”) weighed in rapidly and decisively on the Sabal Trail (a/k/a Southeast Market Pipelines or “SMP Project”) case that the D.C. Circuit remanded to it on August 22, 2017. As previously discussed in greater detail by Frederick M. Lowther and Frank Tamulonis, the D.C. Circuit ruled that, in approving the SMP Project, FERC did not but should have considered potential “downstream” greenhouse gas (“GHG”) emissions from power plants burning natural gas supplied by the pipeline when preparing the final environmental impact statement (“FEIS”) pursuant to the National Environmental Policy Act (“NEPA”). In vacating and remanding to FERC, the D.C. Circuit concluded that “at a minimum, FERC should have estimated the amount of power plant carbon emissions that the pipelines will make possible” or if FERC was unable to quantify this amount, FERC should have “explained more specifically why it could not have done so.” Continue reading “FERC Responds Quickly and Decisively to D.C. Circuit Remand in Sabal Trail Matter on Downstream GHG Analysis”
On the heels of high-profile solar regulatory decisions in Nevada and Hawaii last year and in California earlier this year, Pennsylvania took center stage last week in the ongoing battle over net metering policy. Pennsylvania’s Independent Regulatory Review Commission (IRRC) disapproved a Pennsylvania Public Utility Commission (PUC) rulemaking that would have imposed additional limitations on the size of systems that qualify for net metering credit. IRRC’s disapproval of the rulemaking means that further attempts to reform net metering policy in Pennsylvania will likely have to come through legislative action. Continue reading “More Obstacles Ahead for Pa. Net Metering Restrictions”