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D.C. Circuit Rules that FERC May Not Segment Its Evaluation of the Environmental Impact of Related Natural Gas Pipeline Construction Projects, Regardless of Whether They Are Separately Proposed

The D.C. Circuit Court of Appeals recently issued an opinion holding that the Federal Energy Regulatory Commission (FERC) violated the National Environmental Policy Act (NEPA) when it segmented its evaluation of the environmental impact of four separately proposed but connected projects to upgrade the “300 Line” on the Eastern Leg of Tennessee Gas Pipeline Company’s natural gas pipeline system.  Going forward, the court’s ruling will likely compel proponents of interrelated or complimentary pipeline projects to seek their certification on a consolidated basis and will require FERC to evaluate their cumulative impact.

Tennessee Gas’s challenged Northeast Project was the third of four proposed upgrade projects to expand capacity on the existing Eastern Leg of the 300 Line.  The Northeast Project added only 40 miles of pipeline, while the four proposed projects combined to add approximately 200 miles of looped pipeline.  FERC approved Tennessee Gas’s first proposed upgrade, the “300 Line Project,” in May 2010.  While that project was under construction, Tennessee Gas proposed three additional projects to fill gaps left by the 300 Line Project, one of which was the Northeast Project.   As part of its review of the Northeast Project, FERC issued an Environmental Assessment (EA) required by NEPA that recommended a Finding of No Significant Impact.  The EA for the Northeast Project, however, addressed only the Northeast Project’s environmental impact without reviewing the cumulative impact of all four projects.

The D.C. Circuit held that FERC was in error for failing to consider the cumulative impact.  Under NEPA, the D.C. Circuit explained, FERC must consider all connected and cumulative actions.  The D.C. Circuit found no “logical termini,” or rational endpoints to divide the four projects and found the projects were not financially independent.  Rather, the court found the Northeast Project was “inextricably intertwined” with the other three improvement projects that, taken together, upgraded the entire Eastern Leg of the 300 Line.  The court held that FERC must analyze the cumulative impact of the four projects and remanded the case to FERC for consideration.

The Court emphasized that in this case, “FERC was plainly aware of the physical, functional, and financial links between the two projects.”  Regardless of whether an interstate pipeline initially plans to embark on a series of related upgrades, once FERC is aware of the interrelatedness of proposed expansion projects, it must take care to review any cumulative environmental impacts that may arise.

The D.C. Circuit’s decision may also be a warning that FERC must pay greater attention to the NEPA review in pipeline construction projects.  The D.C. Circuit also has before it this term a case alleging that FERC did not sufficiently consider the environmental review of the siting of a new pipeline compressor station in light of less environmentally intrusive alternatives.  See Minisink Residents for Environmental Preservation and Safety v. FERC, Case No. 12-1481.  Both cases take issue with the rigor of FERC’s environmental review under NEPA, and the D.C. Circuit’s decisions may signal a new era of increased focus on the [...]

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Divided Court of Appeals Panel Vacates FERC Order 745 on Compensation of Demand Response

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 [...]

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FERC Defers to Exclusionary State and Local Laws in Transmission Planning

In three separate rehearing orders issued last Thursday, May 15, 2014, the Federal Energy Regulatory Commission reversed course on its decision in Order No. 1000 to prohibit references in transmission tariffs to state laws such as rights of first refusal (ROFR) to build transmission expansions.  The Commission determined on further consideration that excluding such state and local laws from transmission tariffs could lead to inefficiencies and delays in the regional transmission planning process because regions would have to spend time and resources evaluating potential transmission developers that would ultimately be prohibited by state or local law from developing a transmission project.  Commissioner Norris issued a statement opposing the Commission’s orders on the basis that they will exclude non-incumbents from participating in the regional transmission planning process, choking innovation and insulating incumbents from competition.

Order No. 1000 requires public utilities to participate in regional transmission planning and cost allocation planning for new transmission facilities.  In order to allow competitive bidding of projects and developers, Order No. 1000 requires public utility transmission providers to remove provisions in Commission-jurisdictional tariffs that establish a federal ROFR for an incumbent transmission provider with respect to building transmission facilities selected in a regional transmission plan.  Order No. 1000-A stated that it was not “intended to preempt or otherwise conflict with state authority over sitting, permitting, and construction of transmission facilities.”  However, the order also stated that it “would be an impermissible barrier to entry to require, as part of the qualification criteria, that a transmission developer demonstrate that it either has, or can obtain, state approvals necessary . . . to be eligible to propose a transmission facility.”

On rehearing of compliance orders for the PJM Interconnection, Midcontinent Independent System Operator and South Carolina Electric & Gas Company, the Commission held that while it will continue to require the elimination of federal ROFRs, regional operators and utilities could recognize exclusionary state and local laws and regulations as a threshold issue in the regional transmission planning process.  Specifically, the rehearing orders provided that tariffs could include state and local laws, giving incumbent utilities ROFRs and provisions excluding projects that alter the transmission providers’ use or control of rights-of-way.  The Commission reasoned that ignoring these state or local laws or regulations at the outset of the regional transmission planning process would be counterproductive and inefficient, and could delay needed transmission facilities.  In a dissenting statement, Commissioner Norris argued that this approach was irreconcilable with Order No. 1000 and condemns consumers to bear the burden of incumbents’ lack of innovation in developing transmission solutions and interest in preserving the status quo.




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Energy Regulators FERC, CFTC Finally Reach Proactive Understanding on Jurisdiction and Information Sharing

Primary regulators of energy transactions, the Federal Energy Regulatory and Commodity Futures Trading Commissions (FERC, CFTC or jointly Participating Agencies) began the new year by entering on January 2 two overdue Memoranda of Understanding (MOU), one on overlapping jurisdictions, the other on sharing of information generated in connection with market surveillance and investigations into suspected market manipulation, fraud or abuse.  Both MOUs became effective immediately.

FERC, with jurisdiction over physical natural gas and power transactions, and the CFTC, with jurisdiction over financially settled products such as energy futures and swaps, had battled in recent years over the reach of each other’s jurisdiction, culminating in a March 2013 decision of the U.S. Court of Appeals for the D.C. Circuit finding that FERC improperly invaded CFTC’s jurisdiction when, under authority of the Energy Policy Act of 2005, it sought to fine Amaranth Advisors trader Brian Hunter for allegedly manipulating  natural gas futures in order to increase the profitability of corresponding physical natural gas transactions.  When the Participating Agencies failed to meet the 2011 deadline of the Dodd-Frank Wall Street Reform Act for reaching the jurisdictional understanding, a troika of western-state senators with energy committee portfolios – Dianne Feinstein (D-CA), Ron Wyden (D-OR) and Lisa Murkowski (R-AK) – expressed concern and called on the two commissions to expedite action on an MOU.

The MOUs put in place procedures that replace a reactive status quo ante in which the two agencies collaborated and shared information, if at all, only upon the request of one or the other, with a proactive framework that obliges the staffs of both agencies to notify each other of requests from within their regulated community for authorizations or exemptions from authorization requirements that may implicate the other’s regulatory responsibilities.  Once so notified, the Notified Agency must promptly inform the Notifying Agency that it (1) has no interest, (2) has an interest, triggering a consultative process between the staffs of the Participating Agencies, or (3) wants to revisit the issue once a regulated company has filed request for an authorization or exemption or the Notifying Agency has instigated sua sponte an authorization or exemption.  If (2) is selected, then the triggered consultative process will seek to determine whether the CFTC has jurisdiction under the Commodity Exchange Act or FERC has jurisdiction under the Federal Power, Natural Gas or Natural Gas Policy Acts, with disputes elevated from staff to directors and ultimately to the respective commissioners.  While the jurisdictional MOU imposes these obligations on the Participating Agencies, it expressly creates no private right of action that could be enforced by a regulated company or other third party.

The MOU on information sharing obligates the Participating Agencies to share information needed in connection with each other’s market surveillance or investigations into suspected manipulation, fraud or market power abuse in markets that the requesting Participating Agency regulates.  FERC is authorized to seek from the CFTC information from (1) designated contract markets, (2) registered swap execution facilities, (3) registered derivatives clearing organizations, [...]

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FERC Imposes Whopping Penalty Against Bank and Traders for Allegedly Manipulating Western Power Prices

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 [...]

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NYISO the Next Battlefield for Behind-the-Meter Generation Demand Response

by William Friedman

The Federal Energy Regulatory Commission’s (FERC) approval of the New York Independent System Operator’s (NYISO) demand response compensation program left out a mechanism for compensating demand response from behind-the-meter generation, which prompted the latest outcry from demand response providers.   The demand response providers filed a complaint with FERC claiming discrimination between methods of demand response and seeking to compel the NYISO to compensate behind-the-meter generation demand response.  On the other side of the controversy are power producers who fear that compensating behind-the-meter generation would take money from power generation on the other side of the meter.

Demand response is a reduction in electricity consumption by customers from their expected consumption in response to an increase in the price of electricity or incentive payments designed to induce lower consumption.  In Order No. 745, FERC established a compensation approach for demand response resources by requiring that each regional transmission organization (RTO) and independent system operator (ISO) pay a demand response resource the market price for energy when the resource has the capability to balance supply and demand and when doing so would provide a net economic benefit to consumers.

The NYISO’s Order No. 745 compliance filing was approved by FERC without providing for compensation to behind-the-meter generation.  In other words, consumers with behind-the-meter generation, usually large industrial facilities, will not be compensated for relying on their own generators as an alternative to purchasing power from the market, while other demand response resources that do not generate power will be compensated solely for decreasing consumption.  In response, a number of facilities and aggregators that provide demand response recently complained to FERC seeking an order compelling the NYISO to compensate behind-the-meter generation as part of its demand response program.  The complainants point to neighboring RTOs/ISOs, including ISO-NE, PJM and MISO, which do compensate behind-the-meter generation and argue that excluding behind-the-meter generation violates FERC policy and constitutes undue discrimination.

The demand response providers are opposed by a consortium of independent power producers who argue that including behind-the-meter generation is economically inefficient and creates an improper incentive to move generation behind the meter where it is outside the reach of the RTO/ISO.  The NYISO also filed an answer to the complaint, arguing that forcing the ISO to compensate behind-the-meter generation as a demand response resource raises grid reliability and monitoring concerns.  The NYISO states in its pleading that it is already exploring revisions to its demand response program and the ISO’s internal stakeholder process should be allowed to run its course.  Answers to the complaint were filed last week.  A FERC ruling should be handed down in two to three months.




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Inter-regional Plans for the Nation’s High-Voltage Transmission Grid Land on FERC’s Doorstep

by Christopher S. Bloom

Jurisdictional Public Utility Transmission Providers (TP) filed earlier this week with the Federal Energy Regulatory Commission (FERC) inter-regional plans for the efficient and economical coordination of the construction and financing of high-voltage electricity transmission lines pursuant to FERC Order 1000. The inter-regional plans are to address state and regional needs and policies, such as renewable portfolio standards, and are sure to determine how transmission is financed and how both transmission lines and new electric generation are sited.  Once approved by FERC the plans are to be incorporated in the open-access transmission tariffs (OATT) of the plan’s author —either the public utility or, in regions where they exist, the regional transmission organization or independent system operator. 

TPs submitted regional plans to FERC last October.  In the new inter-regional plans, neighboring TPs in separate regions are required to detail in their plans and procedures for coordinating transmission siting.  In particular, Order 1000 demands procedures for:

  • Coordinating and sharing the results of each region’s regional transmission plans to identify possible inter-regional transmission facilities that could address transmission needs more efficiently or cost-effectively than separate regional transmission facilities;
  • Identifying and jointly evaluating transmission facilities that are proposed to be located in neighboring transmission planning regions;
  • Exchanging annually planning data and information;
  • Disseminating to the public information on inter-regional transmission coordination procedures by maintaining a website or email list;
  • Adding to each TP’s OATT language describing the inter-regional transmission coordination procedures; and
  • Adopting inter-regional cost allocation of the costs of new inter-regional transmission. 

Order 1000 instructs that the inter-regional cost allocation methodology allocate costs only to regions hosting the transmission and do so only in amounts “roughly commensurate” with the estimated benefits each transmission planning region receives from the lines.  Insofar as a benefit-to-cost threshold is used to determine regional allocation, Order 1000 directs that the threshold not exceed a ratio of 1.25 without Commission approval.

The inter-regional plans, requiring all potential stakeholders to participate in evaluating future infrastructure additions to more efficiently site expansion, continue a decade of FERC policy initiatives aimed at creating an inclusive electricity grid.  Not every TP has yet submitted its inter-regional plans, as FERC granted 120 day extensions to the Southwest Power Pool, Inc. (SPP), the Midcontinent Independent System Operator, Inc. (MISO), and NorthWestern Corporation.  Upcoming blog posts will focus on specific inter-regional plans.




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Southwest Power Pool to Finalize New Integrated Marketplace

by Christopher S. Bloom

The Southwest Power Pool’s (SPP) deadline for revising its tariff to add day-ahead and real-time energy to its Integrated Marketplace is this Friday, February 15.  Federal Energy Regulatory Commission (FERC) granted conditional acceptance of SPP’s revised tariff in October, contingent upon SPP submitting various complying revisions.

The Integrated Marketplace is a change of course from the Energy Imbalance Service (EIS) market that SPP launched in 2007. The EIS market has served as a real-time platform for generators to sell excess energy and for load servers to purchase that energy. EIS reduced dependence on bilateral contracts, and enabled competition between generators to provide the lowest-priced energy, using locational imbalance pricing. The new Integrated Marketplace revamps the EIS by creating a day-ahead market along with a real-time energy and operating reserve market. To reduce energy and transaction costs, the new marketplace will consolidate 16 balancing authorities into a single SPP-operated balancing authority. The Integrated Marketplace will also utilize locational-marginal pricing and will include virtual transactions, auction revenue rights, and a market for transmission congestion rights.

The new day-ahead market will allow generators to submit offers to sell energy and operating reserves, and load-servers to submit bids to purchase energy. After the day-ahead submissions, SPP will clear the offers and bids via security-constrained unit commitment and security-constrained economic dispatch algorithms. The end product will be a financially binding schedule that matches sale offers with demand bids and satisfies operating reserve requirements. For day-of energy sales, settlement will be based on the differences between quantities cleared in the Real-Time Balancing Market and the day-ahead market clearing.

The Integrated Marketplace will also bring virtual bidding to the SPP. For a fee and subject to meeting credit requirements, market participants can enter into transactions that essentially short the price of the day-ahead market. Should those virtual transactions clear, the market participant will be obligated to purchase or sell the energy at the real-time locational marginal price, at a profit or loss. The benefit of virtual transactions is that they allow for convergence of day-ahead and real-time prices, allowing a more accurate reflection of the true value and price of the energy. Market participants will be limited to a single offer or bid per hour at each settlement location for each asset owner it represents.

An additional feature of the Integrated Marketplace is its incorporation of auction revenue rights (ARR) and the related transmission congestion rights (TCR) auction. ARRs are awarded to market participants based on firm transmission rights on the SPP grid. ARR holders can choose to retain their rights and receive a share of the revenue generated in the TCR auction, or ARR holders can convert their ARRs to TCRs. TCRs are tradable and TCR holders are entitled to revenue streams or charges based on the cost of congestion in the hourly day-ahead market associated with the TCRs.

In its October 18 order in Docket No ER12-1179, FERC addressed a number of issues raised in protests to SPP’s proposed Tariff Revisions, conditionally approving the Integrated Marketplace, subject to SPP submitting a compliance filing incorporating [...]

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Very Strict Liability for False or Materially Incomplete Representations: Forfeiture of FERC Market Pricing Authority

by Dan Watkiss and William Friedman

“No showing of the respondent’s intent or mindset is necessary to show a violation of [18 CFR § 35.41(b)] has occurred,” explained a divided (4-1) Federal Energy Regulatory Commission (FERC) last week in an order suspending for six-months the authority of J.P. Morgan Ventures Energy (JPM) to sell power at market-based rates (MBR).  FERC did so based on its findings that JPM had submitted inaccurate information and omitted material information in three filings with the Commission. Ironically, the section 35.41(b) violation that cost JPM its MBR authority arose in connection with JPM’s alleged resistance to discovery, and not in connection with the underlying California ISO referral to FERC enforcement staff of suspicions that JPM may have manipulated the California power markets.

This decision should serve as a cautionary tale: Liability for misrepresentations to FERC or its authorized power market operators can be strict — context doesn’t matter — and can result in forfeiture of MBR authority in addition to monetary penalties.  The FERC majority justified its strict enforcement of section 35.41(b) on the ground that an accurate and complete flow of information is essential to the operation of the Commission’s MBR program.

FERC Commissioner Le Fleur’s dissent accepted JPM’s argument that an alleged violation of section 35.41(b) in discovery associated with litigation over a suspected violation of market rules should not be decided independently of a merits decision on the underlying allegation of a market rules violation.  She worried that the majority decision could have the unintended consequence of discouraging targets from asserting legitimate defenses in enforcement actions.

Section 35.41 of FERC’s rules implementing the Federal Power Act directs that a seller authorized (as was respondent JPM) to sell at MBR “must provide accurate and factual information and not submit false or misleading information, or omit material information, in any communication with the Commission [or] Commission-approved [market monitors] . . . , unless Seller exercises due diligence to prevent such occurrences.”

In a complicated back-and-forth, the California ISO suspected JPM of market manipulation, the ISO referred its suspicion to FERC Office of Enforcement, and FERC Enforcement, with notice to JPM, directed the ISO to continue its investigation while FERC began its own. JPM, on advice of counsel, did not cooperate fully in the investigation because it alleged that the ISO was not authorized to pursue the investigation once it had been referred to FERC. But in two emails and one letter, FERC enforcement staff told JPM that was wrong; FERC apparently had authorized the ISO’s further investigation of JPM.  JPM’s subsequent filing of pleadings with FERC either denying or failing to acknowledge that it had been notified that FERC approved the ISO’s further investigation was therefore deemed to inaccurate and to withheld material information in violation of § 35.41(b).

Notably, there is a due diligence exculpation from § 35.41(b).  JPM defended on the ground that it had hired experienced outside counsel to advise it in connection with the ISO and the FERC submissions found to be false and [...]

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FERC Declares That Proposed Wind Curtailment Violates PURPA

by Melissa Dorn

The Federal Energy Regulatory Commission (FERC) ruled in September that Idaho Power Company’s (Idaho Power) proposed curtailment policy for purchases from qualifying facilities (QF) violates the Public Utility Regulatory Policies Act of 1978 (PURPA) because it allows the utility to curtail its wind power purchases under previously negotiated power purchase agreements when demand is low.

The Idaho Public Utilities Commission (PUC) had directed Idaho Power to lodge with the PUC a new curtailment policy allowing Idaho Power to halt purchases from QFs that it was otherwise contractually obligated to make when demand for power was low, such as during off-peak periods.  The state proceeding is ongoing.  In response to the filed proposal, Idaho Wind Partners 1, LLC (Idaho Wind) petitioned FERC for an order declaring the new policy to violate section 210 of PURPA.  Certain FERC regulations that implement PURPA require electric utilities to purchase energy and capacity made available to the utility from QFs.

While there are allowances in PURPA for curtailment under certain operational circumstances that cause purchases from QFs to result in higher costs, FERC’s determination turned on the interpretation of when the exception in § 304(f) of the Commission’s PURPA regulations applies.  Idaho Power argued that § 304(f) applied to QF contracts generally — fixed avoided-cost contract and those whose avoided-cost rate is determined at the time of delivery — thus it possessed the authority to curtail unilaterally QF purchases under any QF power purchase agreement. To the contrary, Idaho Wind argued that § 304(f) does not apply to fixed avoided-cost contracts, pursuant to which the parties had already accounted for variability and operational challenges.  Consequently, Idaho Power should not be able unilaterally to curtail a fixed avoided-cost purchase based on economic or operational circumstances.

In granting Idaho Wind’s petition, FERC instructed that the purpose of § 304(f) was to preserve, not override, contractual or other legally enforceable obligations that a utility incurs to purchase from a QF.  Therefore, the PUC could not authorize Idaho Power to curtail unilaterally its QF purchases.

Idaho Power has announced its intention to appeal FERC’s order rejecting the proposed new curtailment policy.




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