On January 8, 2018, the Federal Energy Regulatory Commission (FERC) rejected the Department of Energy’s (DOE) Proposed Rule, which would have required organized wholesale electricity markets run by independent system operators (ISOs) or regional transmission organizations (RTOs) to establish tariff mechanisms for purchasing energy from eligible “reliability and resilience resources” and mandated a recovery of costs plus a return on equity for such resources. Eligible reliability and resilience resources would have to be (1) located within an RTO/ISO, (2) able to provide essential reliability services, and (3) have a 90-day fuel supply on-site. Practically, these requirements would limit participation to coal and nuclear plants. Continue Reading FERC Rejects Department of Energy Proposal Benefitting Coal and Nuclear
The Federal Energy Regulatory Commission’s (FERC) Order No. 1000 mandate that going forward the high-voltage electric transmission grid be planned and fairly financed regionally by all of its operators and beneficiaries, survived myriad challenges from 45 petitioners in the unanimous August 15 decision of a three-judge panel of the U.S. Court of Appeals for the D.C. Circuit in South Carolina Public Service Authority v. FERC. The rigorous 97-page opinion rejected challenges coming from all directions to the 2011 rulemaking entitled “Transmission Planning and Cost Allocation by Transmission Owning and Operating Public Utilities.”
According to the panel, nearly all of the challenges misapprehended Order No. 1000’s regional planning mandate. The court repeatedly emphasized that Order No. 1000’s mandate is nothing new, but rather the next step in evolving efforts under section 206 of the Federal Power Act to combat undue discrimination. That evolution, the panel explained, began in 1996 when Orders No. 888 and No. 889 required that electricity transmission be “unbundled” from sales and offered via the internet pursuant to open-access tariffs, and 11 years later continued in Order No. 890’s directive that a transmission provider standardize how it measures available transmission capacity and open to its customers the process for planning transmission upgrades and expansions.
The panel’s decision affirmed FERC’s authority to require each of the key elements that FERC prescribed for regional transmission planning. Those elements include:
- All public utility transmission providers are required to participate in a regional planning process, and non-public utilities such as cooperative or municipal utilities effectively must also participate pursuant to a reciprocity requirement carried forward from Order No. 888.
- The planning process must include procedures for taking into account federal, state and local laws and regulations affecting transmission, such as federal air quality rules and state or local renewable portfolio standards.
- Transmission tariffs must be amended to remove provisions that confer on the incumbent transmission provider a right of first refusal to construct, own, and operate new regional transmission, thereby opening the regional process to input, innovation, and investment from non-incumbents and new entrants, subject to state and local restrictions on siting and eminent domain.
- A methodology must be added to transmission tariffs for allocating up-front the cost of new regional transmission facilities, consistent with six principles, including a causation principle directing that the allocation be roughly commensurate with the benefits received by those consumers required to pay, and a prohibition on one region allocating costs to its neighbors without their advance consent.
FERC Chairman Cheryl LaFleur promptly praised the panel’s decision upholding Order No. 1000 in its entirety as critical for inducing the “substantial investment in transmission infrastructure [needed] to adapt to changes in its resource mix and environmental policies.” In its decision the panel noted that the electric industry in 2008 estimated the infrastructure investment needed at $298 billion between 2010 and 2030.
Following FERC’s lead, the panel chose not rule at this time on challenges that elements of the regional planning mandate violate the Mobile-Sierra doctrine —eponymously named for two 1956 Supreme Court decisions —which limits FERC’s authority unilaterally to alter the terms of bilateral contractual relationships. FERC explained that it would not rule on these challenges in the context of Order No. 1000, but would instead address them in connection with a transmission provider’s filing of tariff amendments in compliance with the Order. Mobile-Sierra challenges prosecuted at that time are unlikely to succeed since precedents interpreting the doctrine give the Commission much greater leeway when implementing industry-wide changes to tariffs than when seeking to alter individual contracts.
FERC’s Order No. 745 requiring independent regional grid operators (RTOs and ISOs) in limited circumstances to compensate providers of state-authorized demand response services in the same amounts that they compensate electricity generators was vacated in a May 23, 2014 decision by the majority of a three-judge panel of the U.S. Court of Appeals for the D.C. Circuit in Electric Power Supply Association v. FERC. Siding with challengers — principally electricity generators — Judge Brown writing for the two-judge majority held that FERC exceeded its Federal Power Act (FPA) jurisdiction over electricity wholesales and intruded impermissibly on retail jurisdiction reserved to states by “lur[ing]” retail customers into the wholesale markets of regional grid operators with “rich” incentives to reduce retail purchases and consumption whenever a net benefit accrues to the wholesale market in the form of lower market-clearing prices in the wholesale market. Even if it had not vacated the rule based on this jurisdictional conclusion, the majority said it would have reversed the rule on an alternative ground urged by challengers. According to those challengers, the rule also was arbitrary and capricious by requiring that demand response providers under limited circumstances be compensated at the same locational marginal price or LMP paid to electricity generators.
In a forceful dissent (running nearly twice as long as the majority opinion), Senior Circuit Judge Edwards disagreed with both the jurisdictional vacatur and the threatened reversal of the rule prescribing LMP payments in some circumstances on arbitrary and capricious grounds. Demand response services at least arguably did not fall under the FPA reservation to states of all sales other than wholesales since demand response involves no sale at all, but rather a foregone sale or “negawatt.” The court therefore, according to the dissent, should have deferred to FERC rather than presume greater expertise in interpreting the agency’s jurisdictional statute. In addition, the dissent agreed with FERC that direct participation of demand response resources in wholesale markets entrusted to FERC improves the functioning of those markets in three ways: (1) by reducing peak demand and system imbalances, it lowers clearing prices; (2) it mitigates the market power of generators (particularly pivotal suppliers); and (3) enhances system reliability by lowering demand in response to system emergencies. Incentivizing demand response that offers net benefits to wholesale markets through LMP payments is not unlike the capacity payments that the court found FERC could regulate in Connecticut Dept. of Public Utility Control v. FERC, even though ensuring adequate capacity in wholesale markets could incentivize, among other investments, investments in generation, which is regulated by the states. Therefore, FERC was acting well within the parameters of its wholesale jurisdiction and the court’s precedents.
The disagreement between the majority and dissent on the LMP payments was even more pronounced. Long the preferred method of pricing electricity in organized electricity markets, LMP is the marginal value of an increase in supply or a reduction in consumption at each notional location (node) within an organized RTO or ISO market at a given interval of time. The majority (siding with FERC Commissioner Moeller, who dissented below from Order No. 745) objected to paying a demand response provider the same LMP as an electricity generator since the demand response provider does not incur the cost of generating or purchasing electricity, while a generator or other supplier does. The dissent, in contrast, sided with the FERC majority in concluding that demand response providers incur other costs that generators and other suppliers do not incur and more importantly FERC, with judicial approval, ceased cost-based ratemaking in favor of market pricing (in the absence of market power) over a decade ago for all organized RTO and ISO markets. Therefore, respective costs should not be a controlling consideration.
Because of the undisputed value of demand response in both wholesale and retail electricity markets and the sharp division on the court, FERC can be expected to petition for rehearing of the majority’s decision.
by Dan Watkiss
In a July 16 order, the Federal Energy Regulatory Commission (FERC) assessed civil penalties of $453 million against a British banking conglomerate (BCL) and four of its power traders for manipulating western electricity markets from from November 2006 to December 2008 in violation of the Federal Power Act (FPA) and Commission regulation 1c.2. The bank has 30 days to pay its $435 million penalty and disgorge $34.9 million in profits plus interest from its manipulative trades; likewise, the traders have 30 days to pay penalties ranging from $1 million to $15 million each. The bank announced that it will not pay and instead will contest the finding of market manipulation in federal court. The penalties are among the highest FERC has ever assessed under the authority Congress conferred on it in 2005 to police market manipulation.
FERC’s Office of Enforcement launched its investigation of BCL in July 2007, culminating in an October 2012 FERC order directing the bank and its traders to show cause why they should not be found guilty of market manipulation and assessed penalties. Following the investigation, FERC concluded that the bank and traders traded fixed price products not to profit from the relationship between the market fundamentals of supply and demand, but rather to move the daily Index Price in favor of BCL’s long or short financial swap positions at the four most liquid western trading locations: Mid-Columbia, Palo Verde, North Path 15 and South Path 15. According to FERC’s July 16 order, Enforcement Staff’s investigation unearthed a trove of communications among the BCL’s traders describing the allegedly manipulative scheme and affirming their intent to effectuate it, including so-called “speaking” documents in which traders describe their efforts “to drive price,” “move” the Index and “protect” their swap positions.
As amended to include an anti-manipulation rule modeled on the Securities and Exchange Commission’s Rule 10b-5, the Federal Power Act and FERC’s implementing regulations prohibit an entity from: (1) using a fraudulent device, scheme or artifice to defraud or to engage in a course of business that operates as a fraud or deceit; (2) with the requisite intent; (3) in connection with the purchase, sale or transmission of electric energy subject to the jurisdiction of the Commission. The Act also empowers FERC to assess a civil penalty of up to $1 million per day, per violation against any person who violates Part II of the FPA (including section 222 of the FPA) or any rule or order thereunder. As it has in other prosecutions for market manipulation, FERC rejected BCL’s defense that “open market” trading is per se not manipulative.
The July 16 order is noteworthy not only for the amount of penalties FERC assessed, but also for the procedural history of the BCL investigation. The bank and traders chose to forego their right to an evidentiary hearing before a FERC judge and instead had the Office of Enforcement’s proposed findings of manipulation submitted directly to the Commission for its determination. The bank’s and traders’ claims that the statute of limitations had run or that Enforcement Staff was equitably estopped from making its allegations were not successful in convincing the government to drop the charges against them.
FERC must now seek to enforce its decision and collect the penalties and disgorgement in federal court.
On April 20, 2012, the Federal Energy Regulatory Commission (FERC) issued an order confirming that it has no jurisdiction under the Federal Power Act (FPA) with respect to sales of state-issued renewable energy credits (RECs) that are not bundled with sales of wholesale energy, but asserted that it does have jurisdiction over sales of RECs that are bundled with wholesale energy.
The ruling was in response to a request by the Western Systems Power Pool (WSPP) for FERC to clarify the scope of its jurisdiction. WSPP administers a standardized contract, called the WSPP Agreement, for the sale of wholesale electric power and physical options between its members. The WSPP Agreement allows a seller to charge market prices in energy transactions if the seller has received market based rate authority from FERC or if the seller is not regulated by FERC. Otherwise, the price is subject to rate caps set forth in the applicable FERC-approved rate schedule to the WSPP Agreement.
On February 22, 2012, WSPP submitted for approval under Section 205 of the FPA a revised service schedule to the WSPP Agreement, Service Schedule R, to address several varieties of bundled and unbundled REC transactions. For bundled REC transactions, the rate caps set forth in the existing service schedules of the WSPP Agreement would apply only to the energy portion of the contract price if the total price was allocated separately between energy and RECs, or to the total contract price if there were no separate allocations. With regard to unbundled REC transactions, the WSPP requested that FERC confirm its lack of jurisdiction.
In its order, FERC approved the incorporation of Service Schedule R into the WSPP Agreement and confirmed that sales of RECs that are not bundled with sales of wholesale energy fall outside FERC’s jurisdiction under Sections 201, 205 and 206 of the FPA. FERC’s rationale was that a REC is simply an instrument of state law certifying that energy has been generated pursuant to certain standards, and that the sale of a REC does not constitute the transmission of electric energy or the sale of energy in interstate commerce. However, when RECs are bundled with sales of energy, the REC transaction falls within FERC’s jurisdiction because the REC sales “affect” and are “in connection with” the wholesale energy sales. Under these circumstances, FERC asserted that it has jurisdiction over both the wholesale energy portion and the REC portion of the bundled transaction, regardless of whether the contract price is allocated separately between the energy and the RECs or whether the energy portion and the REC portion of a bundled transaction are split into two separate contracts.
The practical implications of the order are not yet clear. By extending its jurisdiction to RECs at all, FERC has expanded its reach and now has the authority to create additional requirements relating to the REC portion of a bundled REC transaction, which could increase the administrative and financial burden of selling RECs. For power producers who are selling bundled RECs and already have market based rates, the order will likely not have much of a practical impact, other than perhaps changing how bundled RECs are described in periodic FERC reports, a subject that has not yet been addressed.