The longstanding disagreement over how Entergy once equalized production costs among its operating companies was at the center of two FERC decisions last week, with the commission upholding opinions from two administrative law judges pertaining to a seven-month period of bandwidth calculations from 2005.
The allocation of production costs from 2005 to 2015 among Entergy’s half-dozen operating companies under its multistate system agreement has been a source of disagreement for a decade. Before 2015, the companies functioned as one system, although each had different operating costs. Under the arrangement, Entergy’s low-cost operating companies made payments to the highest-cost company in the system using a “bandwidth” remedy that ensured no operating company had production costs more than 11% above or below the system average.
Regulators in each state where Entergy operates have regularly challenged the annual bandwidth filings, with the Louisiana Public Service Commission long contending that the company’s bandwidth payment calculation was plagued by inconsistencies. (See FERC Affirms Ruling Favoring Entergy Bandwidth Calculation.)
In the first order issued Thursday, FERC affirmed a presiding ALJ’s 2016 finding that interest on the 2005 bandwidth period should begin to accrue starting on June 1, 2006, instead of on June 1, 2005, the first day of a test period, as the Louisiana Public Service Commission had argued (EL01-88-015).
The commission also sided with the judge that Entergy Louisiana should exclude most of its net operating loss accumulated deferred income tax (ADIT) from the bandwidth calculation because it stems from a $1.8 billion tax deduction associated with above-market value energy purchases from a long-term contract with the Vidalia hydroelectric power station ending in 2031. The Vidalia tax deduction was properly excluded from the bandwidth formula to “avoid shifting tax burdens and benefits” to other Entergy operating companies, FERC said. The Louisiana PSC had argued that Entergy Louisiana’s net operating loss ADIT is not a tax savings and should be included in the bandwidth formula.
Hydroelectric station in Vidalia | Brookfield Renewable Power
FERC also agreed that Entergy did not properly account for three regulatory asset deferrals in the 2005 bandwidth calculation and ordered the company to make corrections by switching the deferrals to bandwidth-eligible accounts. The commission confirmed that Entergy should calculate the impact of those accounting changes and make a new compliance filing within 60 days.
In the second order Thursday, FERC affirmed another ALJ’s ruling that Entergy had already addressed the question of how 2005 bandwidth calculations should be handled. The commission said Entergy can use its 2006 compliance filing on bandwidth calculations, which FERC accepted in 2007 (EL01-88-017).
Entergy had questioned whether it could apply its 2006 filing for the bandwidth formula calculation to the seven-month period of bandwidth calculations in 2005 after the Louisiana PSC argued that the 2006 filing was not the properly filed rate for 2005 and could not accommodate a seven-month remedy, as it was designed for an annual calculation. FERC said the Louisiana PSC’s argument amounted to a “collateral attack” on its prior rulings in the Entergy bandwidth calculations.
However, FERC disagreed with the judge that the bandwidth formula used for 2005 must “contain all amendments that have been made to the formula in subsequent years.”
FERC ruled last week that a Michigan soybean farm operating two small biomass plants is not excused from a requirement to file as a qualifying facility under the Public Utility Regulatory Policies Act, but it reduced the consequences of the farm’s yearslong failure to do so.
The commission on Thursday said Zeeland Farm Services had a responsibility to file for QF status, even though the company claimed it was unaware of its filing obligation for 10 years. The order partially waived the filing requirement so the two facilities could be largely treated as QFs for the time they operated out-of-compliance (EL17-70, et al.).
The farm owns two 1.6-MW landfill gas-fueled facilities located at its soybean processing facility in Zeeland, Mich. Under a FERC rule enacted in 2006, generating facilities larger than 1 MW must file for QF status.
Zeeland Farm Services | Google Maps
One of Zeeland Farm’s biomass facilities began operating in late 2005, with the other following in 2008. The farm had sold the output to Consumers Energy under two, seven-year power purchase agreements.
FERC did not shield Zeeland from Sections 205 and 206 of the Federal Power Act, leaving the farm facing refunds for “the time value of the revenues collected … for the entire period that the rate was collected without commission authorization.” The farm has already filed a report approved by FERC earlier this month establishing that over the course of the PPAs, it lost money on fuel expenses and operations and maintenance costs, which totaled about $7.9 million (QF17-935). Zeeland collected a total $7.6 million for energy and capacity sold to Consumers, and the commission agreed a refund report should not be required because the farm was unable to recover some variable costs.
FERC also said Zeeland will not have to refund the difference between a market-based rate and a cost-justified rate, as the FPA prescribes, because rates were negotiated with Consumers.
Zeeland said it only became aware of the filing requirement in late 2016, and it filed notices of self-certification last May after informing Consumers of the mistake and conducting a review to make sure the biomass plants still fit the QF definition. Zeeland said its failure to timely submit notices of self-certification was the result of a “good-faith, inadvertent error by individuals and companies otherwise not engaged in the power business.”
But the commission didn’t express sympathy for the oversight. “Zeeland Farm has not justified its failure to comply with a filing requirement that has been present in the commission’s regulations since 2006,” FERC said. “In similar situations, the commission has not been persuaded by claims that the facility met all other requirements for QF status because that argument improperly minimizes the importance of the filing requirement.”
FERC on Thursday rejected the Edison Electric Institute’s request for rehearing of its 2016 order on handling of Critical Energy Infrastructure Information but offered clarification on several points.
EEI challenged several aspects of Order 833, which implemented the CEII provisions attached to the 2015 Fixing America’s Surface Transportation (FAST) Act. (See FERC OKs Information Security, FOIA Rules.) It said the commission failed to adequately specify the criteria it uses to determine whether a member of the public is eligible to obtain CEII.
The commission responded that it has obtained “vast experience” since instituting the CEII process in 2003, noting it “routinely processes CEII requests from, among others, consultants, academics, landowners and public interest groups.”
However, it clarified that “public safety benefits” are one criterion that it should consider in balancing “the requester’s need for the information against the sensitivity of the information.”
EEI also said the commission should revise its CEII nondisclosure agreement “to mitigate against the risk of a CEII recipient involuntarily sharing CEII with a hostile actor.”
FERC declined to change the minimum requirements for the NDA but said the commission’s CEII coordinator “may consider adding additional provisions to the NDA on a case-by-case basis.”
The commission also rejected EEI’s contention that it erred in not providing a way for entities to comment on the sharing of commission-generated CEII.
“The FAST Act does not require, and EEI identifies no provision in the FAST Act requiring, the commission to provide notice and opportunity for public comment about the prospective release or sharing of commission-generated CEII. Furthermore, the commission is not persuaded that we should establish a requirement for stakeholder input when the commission combines information not filed as CEII with other information and potentially creates CEII,” FERC said.
“We, however, clarify that nothing in the FAST Act or the commission’s CEII regulations prevents the CEII coordinator from exercising discretion in an individual situation to solicit comments from a submitter of CEII or other information when evaluating whether to release a commission-generated CEII document.”
Below is a summary of the issues scheduled to be brought to a vote at Thursday’s PJM Markets and Reliability Committee meeting, which will be held at the PJM Conference and Training Center and not its normal location at the Chase Center in Wilmington, Del. Each item is listed by agenda number, description and projected time of discussion, followed by a summary of the issue and links to prior coverage in RTO Insider.
RTO Insider will be in Valley Forge, Pa., covering the discussions and votes. See next Tuesday’s newsletter for a full report.
Markets and Reliability Committee
2. PJM Manuals (9:10-9:45)
Members will be asked to endorse the following proposed manual changes:
A. Manual 36: System Restoration. Revisions developed as part of the manual’s annual review; includes clarifications regarding synchro-check relays, blocking governors and black start generators.
B. Manual 3: Transmission Operations. Biannual review to update operating procedures. Revisions update remedial action schemes, sectionalizing schemes and definitions for the Cleveland and Eastern interfaces; designates voltage limits for Ohio Valley Electric Corp.’s impending integration; adds language regarding reactive reserve check submittals and clarifies notes on load shed activity.
C. Manual 11: Energy & Ancillary Services Market Operations. Revisions developed to ensure consistency between the manual and Operating Agreement regarding price-based offers of more than $1,000/MWh. The change was necessitated by FERC Order 831, which required RTOs and ISOs to raise their hard caps for verified cost-based incremental energy offers to $2,000/MWh. (See “Offer Cap Resolution,” PJM Market Implementation Committee Briefs: May 2, 2018.) Also includes conforming changes regarding bidding locations for virtual transactions.
D. Manual 14A: New Services Request Process. Annual review. Revisions developed to introduce the Queue Point software for submitting data for feasibility and system impact studies.
E. Manual 7: Protection Standards. Revisions developed by the Relay Subcommittee to add clarity, update terms and add reliability requirements.
Members will be asked to vote on proposals to include consideration of cost-containment commitments in PJM’s analysis of transmission construction bids. This is the continuation of a discussion that was tabled for four months as stakeholders attempted to find consensus. PJM has two proposals it plans to offer, but LS Power’s proposal will be considered first since a vote on it was deferred at the January MRC. (See Cost Containment Proposal Survives; Headed to MRC.)
Members will be asked to vote on proposals to change rules on submitting variable operations and maintenance (VOM) costs for recovery. Two proposals were endorsed at April’s Market Implementation Committee meeting:
The PJM package, which was supported by a 75% vote, would allow only actual maintenance costs directly tied to electric production can be included in a unit’s incremental energy offer.
The default VOM package, which won an 81% endorsement, would allow resources to choose between filing actual costs under the PJM package or a default value no greater than the new build data published by the U.S. Energy Information Administration.
Members will be asked to endorse OA revisions allowing PJM to share member confidential information with the Eastern Interconnect Data Sharing Network (EIDSN) in addition to NERC and other reliability entities. EIDSN was created in 2014 to develop industry tools that NERC has decided it no longer wants to create and maintain.
MISO last week announced that it will hold its second Market Symposium in downtown Indianapolis on Aug. 15-16.
This year’s theme is “Markets in 3D: Preparing for Digitalization, De-marginalization and Decentralization,” and the two-day event includes industry experts discussing how wholesale market design and technology may change with increasing use of connected devices, distributed energy resources and renewable generation with near-zero marginal costs.
“The MISO team is working to create a forum for industry leaders at the forefront of future market design to explore longer-term challenges and opportunities,” MISO CEO John Bear said in a statement. “The symposium will provide a venue to interact with thought-leaders, explore emerging technologies and build relations with decision-makers and innovators who are at the helm of a changing industry.”
The symposium will feature FERC Commissioner Richard Glick as special guest speaker, and MISO has again partnered with the Department of Energy’s Advanced Research Projects Agency-Energy (ARPA-E) to host the event.
This year’s symposium also includes an emerging technology and market solution showcase. MISO is currently accepting applications for booth exhibits and five-minute presentations on industry innovations on the main stage.
“We know our industry is transforming,” said MISO Research and Development Director Jessica Harrison. “We want to foster thought-provoking discussions so that the industry can meet future challenges with innovative solutions that ultimately improve service and value for consumers.”
CAISO’s Board of Governors on Wednesday approved new provisions to account for errors in load forecasts by allowing grid operators to manually update the forecasts to deal with changing conditions on the grid.
At its May 16 meeting in Folsom, Calif., the board also heard from CEO Steve Berberich about the tight supply conditions the ISO foresees this summer, as well as what he called “a very serious issue” regarding inverters that caused an 860-MW loss of solar resources on April 20.
The board approved the new “imbalance conformance” rules that allow the ISO to account for errors in renewable energy forecasts or instances when generators deviate from their dispatch orders. The Energy Imbalance Market Governing Body approved the rules last month. (See EIM Body Approves Imbalance Conformance Rules.)
The board also approved alterations to the Imbalance Conformance Limiter, an ISO software tool designed to prevent price spikes caused by imbalance conformance adjustments. The limiter keeps the market from trying to dispatch more supply than is available in a particular dispatch interval to account for imprecision in the adjustments.
CAISO Department of Market Monitoring Director Eric Hildebrandt told the board that while the department supports the changes, the magnitude of load adjustments has increased dramatically, doubling between 2016 and 2017. The adjustments should be more random in nature and not used as systematically as they have been, he said.
In his presentation, Hildebrandt said “the ISO appears to use load conformance as means to procure additional imports in the hour-ahead process to ensure more ramping capacity is available in the 15-minute and five-minute markets.”
The Monitor recommends the ISO focus on how it can reduce the need for operators to make manual adjustments in real time.
Southern California Edison opposed the changes, saying that the new limiter enhancements should be implemented in addition to the old limiter logic in order to maintain price stability. Powerex also opposed the measures, saying they might suppress scarcity pricing in some situations, according to a presentation from CAISO Vice President of Market Infrastructure Keith Casey. FERC must approve the changes before they take effect.
Warnings of Tight Supply, Inverter Issues
Berberich explained to the board that on April 20, the Mira-Loma-Vincent 500-kV line in the SCE service territory relayed, causing 860 MW of solar to trip off because of voltage fluctuations.
“It’s a really exciting event down in the control room when we lose 860 MW,” Berberich said during his CEO report.
CAISO has been trying to reprogram inverter settings so they can ride through the relays and is working with NERC to create an appropriate industry-wide standard to address the problem. While the ISO has been able to reprogram some inverters, others cannot be reprogrammed, leading it to rely other resources at certain times.
“We are going to keep a close eye on this issue,” Berberich said, adding that the ISO views the new NERC standard as an important goal. He said public calls for demand reductions will be key in managing grid conditions this summer.
“We expect to have very tight conditions this summer,” Berberich said, adding that the gas system is operating at a “bare minimum.”
An ISO presentation showed that after modeling 2,000 scenarios, it was found there is a 50% probability of a Stage 2 emergency for at least one hour this summer. CAISO declares a Stage 2 emergency when it becomes clear that operating reserves will be less than 5% after dispatching all resources, including demand response. The ISO did not include in its modeling the gas supply limitations from restricted use of Aliso Canyon, which it said could represent further reliability risk. (See CPUC OKs Temporary Increase in Aliso Canyon Injections.)
ALBANY, N.Y. — About 194,000 customers in New York were without electric power in the state after a series of thunderstorms hit on May 15, the Public Service Commission heard Thursday.
The outages were mostly in the Lower Hudson Valley, the same area that suffered severe outages in March, said Michael Worden, director of the commission’s Office of Electric, Gas and Water.
“We have about 5,550 [full-time equivalents] of line, tree and service crews there providing support to the area,” Worden said. “That includes on the order of 1,250 out-of-state, out-of-region crews, and also includes a large contingent of New York crews that have been redeployed from, for example, Western New York. So there’s a significant recovery effort going on.”
By Saturday, most customers had had their power restored, with only about 13,600 still out, according to PowerOutage.us, which aggregates utility-reported outage data.
The commission is continuing to investigate the various utilities’ March outages and storm response efforts, Worden said.
Grid Ready for Summer
New York’s bulk electric system is prepared to reliably meet this summer’s load forecast, according to the Department of Public Service.
Department staff based its assessment on a review of utility data and meetings with individual utilities and NYISO, Vijay Puran, DPS senior engineer for electric transmission planning, told the commission.
| NY Department of Public Service
“Utilities will complete all planned major reinforcements, inspections and repairs prior to the start of the summer season, and they have adequate spare equipment on hand to meet unforeseen circumstances,” Puran said during a presentation.
The ISO predicts demand will peak at 32,904 MW this summer. With a total resource capability of 42,169 MW on hand, the grid’s margin of safety comfortably exceeds the 18.2% required installed reserve margin, Puran said.
| NYISO
Peak demand forecasts have dropped by more than 3,000 MW since 2015, which the ISO “attributes to the positive effects of the state’s energy programs and to underlying forecast econometric growth rates,” he said.
Puran said hundreds of megawatts of load reduction are available to Consolidated Edison through its demand response programs, and other utilities have similar load-relief measures they can turn to if needed.
DPS staff expect the cost for electricity this summer to be higher than last year but 9 to 12% below the five-year average.
“I hear this as an outlook that is good news for New Yorkers, giving us comfort that we can confidently expect adequate supply and reasonable costs,” PSC Chair John B. Rhodes said.
National Grid Utilities Audit
In its consent agenda, the commission ordered a management and operations audit of three National Grid USA subsidiaries: Niagara Mohawk Power, Brooklyn Union Gas and KeySpan Gas East (18-M-0195). The effort will focus on construction program planning and operational efficiency.
“The audit will include an assessment of the utilities’ readiness to respond to the Reforming the Energy Vision initiative and closely examines how the utilities plan for and manage information systems projects,” Rhodes said in a statement. “The audit will also address issues from previous management audits that require follow-up review, such as organizational structure, project estimating processes and work management processes.”
Gov. Andrew Cuomo in 2013 highlighted the importance of management and operations audits of the state’s utilities, and introduced — and subsequently signed — legislation that required utilities to file plans for implementing audit recommendations.
This is the fourth comprehensive audit since 2013, and three additional audits are underway, the commission said.
“To date, these audits have recommended numerous productivity enhancements, better risk mitigation strategies, and improved planning processes, as well as other operational improvements at New York’s utilities,” the commission said. “These process improvements result in savings for customers over time, and those savings are captured in rate cases.”
The House Energy and Commerce Committee last week heard testimony on Republican-backed legislation that could allow power plants and industrial boilers to avoid expensive upgrades under EPA’s New Source Review (NSR) program.
Facilities are subject to NSR if they make non-routine modifications that increase annual emissions; such plants must use the “best available control technology” to minimize the emissions increase.
The bill, written by Rep. Morgan Griffith (R-Va.), would amend the definition of “modification” under Clean Air Act Section 111a to mean any alteration to a facility that increases its hourly pollutant emission rate.
| EPA
The modification clause does not specify how a facility’s emissions should be measured to determine if a change would result in a pollution increase, which has led to multiple lawsuits since the clause was added in 1970. Under the NSR program, EPA has used a projection of annual emissions based on the modification.
“This type of annual emissions projection approach necessitates the consideration of complex factors such as projecting future demand of the product being produced and the selection of baseline emissions to use as a comparison point,” committee Republicans said in a memo ahead of a Environment Subcommittee hearing on the bill Wednesday. “Additionally, in certain instances, this type of emissions projection results in an overestimation of emissions, which is shown by comparing the projected emissions with a source’s true emissions after the fact.”
The bill would also exempt from NSR any modification that “reduces the amount of any air pollutant emitted by the source per unit of output or is designed to restore, maintain or improve the reliability or safety of the source.” Republicans said that NSR has impeded or canceled projects intended to reduce a facility’s pollution. The law already exempts routine maintenance or repair from review.
Support
At Wednesday’s hearing, Bill Wehrum, assistant administrator of EPA’s Office of Air and Radiation, told the subcommittee that the Trump administration does not have an official position on the bill. “Having said that, I strongly support the overall goals of the discussion draft,” he said. “The principal focus of the discussion draft on refining the definition of ‘modification’ in the Clean Air Act would go a long way towards simplifying application of the NSR program.”
Wehrum praised the bill’s exemption of pollution-reducing additions, noting that, “sometimes, the operation of such equipment, while it results in tremendous emissions reductions for some pollutants, may in some instances actually lead to increases in the emissions of other pollutants.” He said EPA had attempted to implement such a provision but was overruled by the D.C. Circuit Court of Appeals.
Kirk Johnson, senior vice president of government relations for the National Rural Electric Cooperative Association, said NSR has “more often served as an impediment, rather than an enhancement, to maintaining and improving efficiency at power plants.”
“One significant obstacle of the NSR permitting program is its application to equipment repair and replacement as well as even routine maintenance activities at existing generating units,” Johnson said. “Although routine maintenance, repair and replacement are supposedly excluded from being considered as ‘major modifications’ — and thus not subject to NSR — what qualifies as these NSR exemptions often changes with shifting EPA interpretations. This has led to utilities performing what they thought qualified as routine maintenance, repair and replacement, only to be cited for NSR violations years after the fact.”
Opposition
Paul D. Baldauf, assistant commissioner of the New Jersey Department of Environmental Protection, however, said Griffith’s bill could increase out-of-state emissions and extend the life of older generators, causing the state to fall out of attainment for the National Ambient Air Quality Standards (NAAQS). Baldauf cited as an example a generator that undergoes changes to increase its efficiency while also increasing the maximum heat input — the amount of fuel burned per hour — to increase electric output.
“This project would decrease the pounds of CO2 and some other pollutants emitted per megawatt-hour but would increase the megawatts generated,” he said. “Without additional controls, such a project would result in both increased hourly and annual emissions of all its pollutants, including CO2, criteria pollutants and air toxics, resulting from the increased fuel use. These increased emissions could likely result in adverse health impacts despite the increase in efficiency of the unit.”
Environmental consultant Bruce C. Buckheit, who served as director of EPA’s Air Enforcement Division during the Clinton and George W. Bush administrations, also opposed the bill. “The draft is not needed by the regulated community for any purpose and would not advance one of the fundamental purposes of the Clean Air Act — to eliminate, over time, the disparate treatment of new and existing sources,” he said. “It would severely impair the ability of the modification rules to effect this purpose and would exacerbate the current barrier to investment in new manufacturing and electric generating facilities created by the difference in the treatment of new and existing facilities.”
Democrats are likely to oppose the bill. “Without a firm requirement that facilities reduce the levels of all the dangerous pollution they emit, they simply will be allowed to pollute more,” Rep. Frank Pallone (D-N.J.), ranking member of the full committee, said in a statement. “That’s what the language in the bill on ‘maximum achievable hourly emission rate’ is all about.”
FERC’s Republican majority on Friday narrowed the circumstances under which it will estimate greenhouse gas emissions from natural gas pipeline projects, sparking dissents by its two Democratic commissioners.
The commission unanimously rejected a rehearing request by conservation organization Otsego 2000, which contended FERC had not conducted a sufficient environmental review in its 2016 approval of Dominion Energy Transmission’s New Market Project. The project includes two new compressor stations and upgrades to three others in upstate New York (CP14-497-001).
Wetland at existing Borger Compressor Station | Dominion Transmission
But Democrats Cheryl LaFleur and Richard Glick dissented from the commission’s declaration that it will no longer prepare upper-bound estimates of GHG emissions when “the upstream production and downstream use of natural gas are not cumulative or indirect impacts of the proposed pipeline project.” They instead contended the decision effectively eliminates any consideration of GHG emissions associated with a project.
Republicans Kevin McIntyre, Neil Chatterjee and Robert Powelson said they were taking the action to “avoid confusion as to the scope of our obligations under [the National Environmental Policy Act] and the factors that we find should be considered” when determining whether a project is in the public convenience and necessity under the Natural Gas Act.
NEPA requires FERC to prepare an environmental impact statement for pipelines that may significantly impact the environment but allows for a less detailed environmental assessment if it determines the project is not likely to have significant adverse effects.
Notice of Inquiry
In separate partial dissents, LaFleur and Glick said they were disappointed that the majority initiated the policy shift just a month after issuing a Notice of Inquiry to reconsider the commission’s 1999 policy statement on gas pipeline permitting (PL18-1). (See FERC Outlines Gas Pipeline Rule Review.)
LaFleur said the new policy reverses the commission’s practice since late 2016 of including more information on upstream and downstream GHG emissions in its pipeline orders. That included “upper-bound” estimates of downstream emissions that assumed all the gas transported by the project would be burned for electric generation, heating and other purposes.
“The commission placed caveats on the information and analysis, stating generally that the downstream impacts do not meet the definition of an indirect impact and are not mandated as part of the commission’s NEPA review,” LaFleur acknowledged. “The commission nonetheless made a full-burn calculation to determine an upper-bound GHG emissions amount, unless it had specific information to calculate net and gross GHG emissions.”
The commission used Department of Energy studies for generic estimates of the impact of projects on upstream natural gas production, including production-related GHG emissions.
LaFleur said the commission’s obligations increased under the D.C. Circuit Court of Appeals’ August 2017 Sabal Trail ruling, which found that the emissions resulting from burning the natural gas transported by a commission-approved project are an indirect impact. (See FERC Must Consider GHG Impact of Pipelines, DC Circuit Rules.)
“Today, however, the majority has changed the commission’s approach for environmental reviews to do the exact opposite. Rather than taking a broader look at upstream and downstream impacts, the majority has decided as a matter of policy to remove, in most instances, any consideration of upstream or downstream impacts associated with a proposed project,” LaFleur wrote. “The majority’s reasoning for excluding the information and calculations is generally that it is inherently speculative and does not meaningfully inform the commission’s project-specific review. I disagree.
“At a time when we are grappling with increasing concern regarding the climate impacts of pipeline infrastructure projects, the commission should not change its policy on upstream and downstream impacts to provide less information and be less responsive,” she added.
‘Remarkably Narrow’
Glick criticized the majority for what he called a “remarkably narrow view of its responsibilities under NEPA and the NGA’s public interest standard.”
“The principal reason that the commission does not have … ‘meaningful information’ [on GHG impacts] is that the commission does not ask for it,” Glick said, noting that FERC could require pipeline developers to provide information about the source of the gas to be transported and its end use.
“A simple data request would seem to fall easily within what constitutes the commission’s ‘best efforts,’” Glick said. “In the absence of any such efforts, the commission should not be able to rely on the lack of ‘meaningful information’ to satisfy its obligations under NEPA and the NGA to identify the reasonably foreseeable consequences of its actions.”
“There will undoubtedly be some cases where those emissions are, in fact, too speculative to be considered ‘reasonably foreseeable,’” he continued. “But there may also be others, such as Sabal Trail, where an adequate record would provide sufficient information to make those emissions reasonably foreseeable.”
Glick said he was not suggesting that the commission stop approving new pipeline projects. “What I am arguing is that, as a result of the commission’s new policy, we frequently will not know whether the benefits outweigh the costs because the commission is not asking enough questions or doing enough analysis.”
Dissents ‘Mischaracterize’ Shift
The majority said the dissents “mischaracterize” the policy shift as changing the commission’s public interest and environmental review.
“Our decision does not in any way indicate that the commission does not consider, or is not cognizant of, the potentially severe consequences of climate change,” the majority wrote. “We will continue to analyze upstream and downstream environmental effects when those effects are sufficiently causally connected to and are reasonably foreseeable effects of the proposed action.”
They also said the order does not “prejudge or preclude the [commission] from considering the questions on greenhouse gas emissions posed in the Notice of Inquiry.”
The Republicans said that even if the commission presumed a causal relationship between the New Market Project and upstream production, “the scope of the impacts from any such production is too speculative and thus not reasonably foreseeable.”
“Neither the commission nor the applicant generally has sufficient information to determine the origin of the gas that will be transported onto a pipeline. We disagree with the dissent’s assertion that we lack information about specific upstream production or downstream uses simply because we ‘did not ask for it.’ To be clear, the commission only has jurisdiction over the pipeline applicant, whose sole function is to transport gas from and to the contracted for delivery and receipt points. While the shippers might contract with a specific producer for their gas supply, the shipper would not know the source of the producer’s gas, and, for that matter, producers are not required to dedicate supplies to a particular shipper and thus likely will not know in advance the exact source of production. In short, ‘just ask[ing] for it’ would be an exercise in futility.”
FERC on Thursday rejected a second attempt by several Pacific Gas and Electric transmission customers to potentially receive a larger-than-normal refund related to a rate increase the utility submitted in 2016 for its 18th transmission owner tariff filing (TO18) (EL17-59).
But in a separate decision (EL17-95), the commission also ruled that a complaint by the same customers about PG&E’s TO19 rate filing be subject to hearing and settlement judge procedures and consolidated it with the ongoing proceeding covering the TO18 complaint (ER17-2154).
In EL17-59, the complainants — which include the Transmission Agency of Northern California; the city of Santa Clara; M-S-R Public Power Agency; State Water Contractors; the California Public Utilities Commission; Modesto Irrigation District; and Sacramento Municipal Utility District — had requested a rehearing of FERC’s November denial of their initial complaint over TO18.
While the TO18 rate increase is the subject of an ongoing proceeding on tariff revisions PG&E wants approved (ER16-2320), FERC shut down the complaint and an alternative request for consideration of supplemental evidence. It rebuffed the argument that its initial rejection failed to provide the complainants protection to receive the refund that they argued they could proved justifiable if the complaint was accepted.
FERC rejected a second attempt by transmission customers to potentially receive a larger-than-normal refund related to a California TO’s requested rate increase.
The complaint stemmed from PG&E’s request to increase its wholesale base transmission revenue requirement from $1.319 billion, as set in its previous rate case, to $1.705 billion, and boost its retail base transmission revenue requirement from $1.331 billion to $1.718 billion. The complainants had argued that they could show through discovery that PG&E actually required less revenue than it is already approved to collect, that FERC should allow for refunds below the current $1.319 billion revenue requirement and that their complaint should be consolidated with the rate increase proceeding.
FERC denied the complaint, saying the complainants failed to show that their proposed rate adjustments would result in a revenue requirement below $1.319 billion, leaving the standard refund protection intact. The complainants responded that not providing them the opportunity to prove their case through discovery in the proceeding “arbitrarily and capriciously deprived” them of protections in the Federal Power Act, but FERC said they must show evidence of the problem as part of the complaint, not ask the commission to trust them to prove it later.
FERC also rejected an alternative request, which asked the commission to consider evidence from PG&E’s ongoing tariff proceeding.
“The commission’s longstanding policy is to not accept additional evidence at the rehearing stage of a proceeding, absent a compelling showing of good cause,” it said. “Because other parties are precluded … from filing answers to requests for rehearing, allowing complainants to introduce new evidence at this stage would raise concerns of fairness and due process for other parties to the proceeding.”
TO19 Complaint
The commission accepted PG&E’s TO19 filing last September but suspended it for five months to become effective on March 1, 2018, subject to refund and the establishment of settlement judge procedures.
In EL17-95, the complainants alleged that PG&E failed to justify the proposed TO19 rate increase, which forecast a retail network transmission revenue requirement of $1.8 billion and a wholesale network transmission revenue requirement of $1.78 billion.
The complainants contended that PG&E overstated its proposed rates with inappropriate expenses, an excessive wholesale network transmission revenue requirement; a return on equity inconsistent with commission precedent; and an excessive composite depreciation rate. They claimed the utility failed to be transparent on expenses and made errors in its capital structure and cost of debt that require adjustment.
They also said that formal discovery should provide for additional adjustments to reduce PG&E’s rates below the last clean rate established in the TO17 settlement.
Complainants alleged that reducing PG&E’s proposed rates by $511.4 million, based on supporting materials, would bring the final rate below the last clean rate.
In addition, the amended complaint alleged the need to reduce PG&E’s federal corporate income tax rate from 35% to 21%, consistent with the recently enacted Tax Cuts and Jobs Act, which it said effectively made PG&E’s TO19 rate unjust and unreasonable.
PG&E countered that the complainants should not be allowed to attack the settled TO17 rate, that granting the complaint will make reaching a settlement in future rate cases more difficult and would be contrary to the policy behind the last clean rate doctrine.
Specifically, PG&E said that the last clean rate doctrine “prevents retroactive ratemaking and avoids penalizing a company for filing a rate increase,” which would happen if the commission granted the complaint.
PG&E also argued that complainants failed to carry their burden of proof under Section 206 of the FPA.
The commission’s May 17 order found “that the complaint raises issues of material fact that cannot be resolved based on the record before us.”
“We are unpersuaded by PG&E’s arguments that complainants have failed to meet their burden under Section 206 of the FPA, and find that complainants’ allegations, as amended, are sufficient to initiate an investigation into PG&E’s rates,” the commission said.
FERC emphasized “that we are not here making a finding on the merits of complainants’ arguments in their amended complaint; rather, we are simply finding that complainants have made a prima facie case warranting further investigation by providing sufficient support for their allegation.”
The commission said it was likewise unpersuaded by PG&E’s policy arguments.
“Specifically, we find that the complaint does not request that the commission reject the settled TO17 rates, nor does it seek to undo the results of any compromise reflected among the parties to the settlement,” it said.
The TO17 rates were in effect from March 1, 2016, through Feb. 28, 2017, when they were superseded by PG&E’s proposed TO18 rates, and therefore remain unaffected by this complaint for that period, the commission said.
“Here, complainants are using new data provided by PG&E in its TO19 rate case to allege that PG&E’s TO19 rates are overstated to such an extent that the final just and reasonable rates will be below those agreed to in the TO17 rate case,” the commission said. “The TO17 rates are thus relevant only to the extent that they establish the last clean rate and the floor below which additional refund protection is necessary.”
Based on its review of the record, the commission expects that the presiding judge should be able to render a decision within approximately 12 months of the commencement of hearing procedures, or May 17, 2019.
“Thus, we estimate that, absent settlement, we would be able to issue our decision within approximately 12 months of the filing of briefs on and opposing exceptions, or by July 17, 2020,” the commission said.
