California lawmakers moved forward with several pieces of energy legislation last week, but hotly watched items such as a 100% renewable energy standard and CAISO regionalization seem to be set on simmer.
There has been no movement this year on SB100, former State Senate President Pro Tempore Kevin de Leon’s 100% renewable energy bill that was front and center as the 2017 legislative session drew to a close. (See CAISO Regionalization, 100% Clean Energy Bills Fizzle.) SB100 has seen no votes since the Assembly Appropriations Committee last September.
And AB813, legislation that would regionalize CAISO, sits in committee during this session as other, higher-profile issues heat up. (See Calif. Lawmakers Relaunch CAISO Regionalization.) The regionalization language is currently in the Senate Rules Committee and the next step is a referral to the Energy Committee.
The U.S. Senate Democratic primary between de Leon and longtime Sen. Dianne Feinstein is taking up a great deal of political oxygen and an unrelated series of sexual assault controversies are another major distraction in the Capitol. (See Wildfire Costs Ignite Worry at CPUC, Legislature.)
On Thursday, the Assembly Utilities and Energy Committee, chaired by Assemblyman Chris Holden (D) passed several pieces of legislation, including:
AB2068(Chu), to Appropriations: It would require IOUs to evaluate the feasibility of discounting rates for public schools by at least 15% and for the California Public Utilities Commission to determine whether to adopt the discount. It requires the CPUC to direct IOUs to evaluate and report on the feasibility and economic impact of establishing the discounts. The evaluation must include commercial rate increases for the past five years that affected schools and the economic impact to other ratepayers if all public schools receive the discount. The bill requires the CPUC to submit the report to the legislature by Jan. 1, 2020.
AB2208(Aguiar-Curry) to Natural Resources: The bill requires investor-owned utilities, community choice aggregators, retail energy sellers and publicly owned utilities to procure an unspecified percentage of their resources from geothermal, biogas or biomass facilities. An unspecified amount would have to be procured from the Salton Seageothermal resource area, 10 generating plants producing 327 MW in Southern California’s Imperial Valley. According to an author’s statement, “AB 2208 will make it easier to reliably integrate higher amounts of renewable energy generation into the grid by requiring the procurement of ‘grid-balancing’ renewables, such as geothermal and bioenergy.” It would allow bioenergy facilities open to continue accepting wood waste as a forest fire management measure.
AB2515(Reyes) to Appropriations: The bill requires the CPUC to report to the legislature pending and previously approved changes to IOU revenue requirements over at least the past five years that resulted from requests by IOUs and CPUC decisions and resolutions. It also requires IOUs seeking a rate change to disclose estimated rate and bill impacts on each customer class.
AB2831(Limon) to Appropriations: Requires the CPUC, in consultation with the Office of Small Business Advocate within the governor’s Office of Business and Economic Development, to ensure that adequate marketing, education and outreach are undertaken to enable small business customers to fully participate in demand-side energy management programs.
VANCOUVER, Canada — With three RTOs advancing competing efforts to extend their services into the West, the region’s utility regulators last week took a timely crash course on the legal implications of allowing their utilities to join organized markets.
It was a bracing — and invaluable — session, according to some industry stakeholders attending the spring joint meeting of the Western Interconnection Regional Advisory Body and the Committee on Regional Electric Power Cooperation.
Scott Hempling, an attorney specializing in public utility law, provided a compressed but comprehensive 90-minute primer of the statutes, regulations and case law governing the functioning of RTOs, beginning with their origins in FERC Order 2000, which encouraged — but did not require — utilities to form or join an RTO.
“The primary purpose was to end discrimination by transmission owners,” Hempling said. “One of the methods of discrimination before Order 2000 was to keep secret the availability of transmission.”
Hempling explained the four “minimum characteristics” of RTOs required by FERC: independence; appropriate scope and regional configuration; operational authority; and exclusive authority over short-term reliability.
In addition, RTOs must fulfill eight “required functions,” including tariff design and congestion management. “Understanding those 12 things is crucial to understanding what’s getting turned over to the RTO,” he said.
Hempling clarified that a transmission-owning utility legally becomes a customer of an RTO once it joins the RTO and turns over its transmission assets. It also becomes FERC jurisdictional. “When your utility joins an RTO, it no longer provides transmission service,” he said.
“Let me put it bluntly: you lose jurisdiction over transmission costs” when a utility joins an RTO, Hempling told the audience of commissioners. As a result, any state commission that has approved RTO membership cannot “logically disallow” a utility from including in retail rates the costs of becoming a customer of the RTO.
“Once FERC determines that the rate charged by the RTO to the transmission owner is prudent, the state must pass that cost on” to customers, Hempling said.
And while a transmission-owning utility does receive a pro rata share of the revenues the RTO generates from all transmission customers, the resulting credits don’t always make retail ratepayers whole. “You’d think the retail charges and credits would be a wash, but that’s not necessarily the case,” Hempling said.
One commissioner asked if FERC made distinctions within RTOs between how it treats investor-owned utilities on the one hand and rural cooperatives and municipal power systems on the other.
Hempling noted that the Federal Power Act exempts publicly owned systems from FERC oversight — unless they are TOs and join an RTO. “Co-ops and munis join RTOs by contract. Now if they’re transmission owners, are they subject to FERC jurisdiction? The answer is ‘yes.’” Based on FERC’s reciprocity rule, “if you want to take transmission service and you own transmission, then you’re going to need to provide transmission service,” Hempling said.
FERC ‘Controversies’
Hempling turned to key areas “where FERC finds itself resolving controversies” related to the nation’s RTOs.
Chief among the agency’s concerns: return on equity for transmission investments.
“There is a great deal of controversy over what is the ‘fair return on equity,’ and it’s not just about profiteering,” he said. “We’re talking about hundreds of billions of dollars in necessary transmission investment, and that money is going to have to come from somewhere and get paid off over a certain period of time. So return on equity matters, both from the customer standpoint and the investor standpoint.”
Hempling pointed to the differences between administering general rate cases (FERC’s past approach) and formula rate cases (its current approach).
“A formula rate’s a spreadsheet, and I guess the word is that you ‘populate’ the spreadsheet with the numbers — as opposed to a general rate case, where everybody and their brother and father and mother and sister gets into the case and everybody fights over what the ultimate [regulated rate of return] should be,” Hempling said. “For years, FERC set transmission rates with a general rate case, but now it prefers to set them by formula. But just because it’s a spreadsheet that you populate across doesn’t mean that FERC goes to sleep and just asks that you include whatever you want to put in there.”
Hempling expressed his respect for FERC, calling the agency “very, very professional — even in the current political environment.” But he cautioned state commissioners about the agency’s limitations in judging the reasonableness of transmission project expenditures, another area of focus for the agency.
FERC “does not disallow costs very often. … There is a question whether an agency whose authority is transmission [has] competency in looking at alternatives,” he said, adding that FERC “does not do integrated resource planning.”
Hempling also pointed to FERC’s role in overseeing RTO transmission cost allocation.
“You’re a multistate region — which state’s customers are paying for what? And there are now a variety of court of appeals decisions and FERC decisions that allocate costs among the family members, who at conferences like this are all happy to see each other over pastries, but then they’re happy to hire very expensive lawyers to fight over who’s getting which dollars.”
Power to the States?
Hempling posed a series of hypothetical questions regarding a state’s influence over utilities before and after a decision to join an RTO. His answers, he made clear, were based on his own professional opinion, not settled law.
Can a state order its utility to join an RTO?
Yes, Hempling said. A state commission could find that a utility’s rates “will not be just and reasonable, reliability will be insufficient to satisfy state law unless the utility joins an RTO,” he said. “I also think therefore — and everything I’m saying now is subject to debate — that a state can reject a utility’s request to join, I think for the same reason.”
Can FERC order a utility to join?
“This question, along with all the others, is untested, because if FERC does have the authority to order a utility to join, then that would pre-empt a state that rejects a utility to join. That would be an inconsistency, right? You can’t put a utility between a rock and a hard place,” Hempling said.
“Do I think FERC has the authority to order a utility to join? I think they do. … And in any event, FERC has never said so,” he said. “And that’s why the joining of RTOs by utilities is opportunistic. That’s why they at least get to decide … based on their own self-interest, because FERC has not said it can order a utility to join.” But FERC has conditioned a utility’s request for merger approval on joining an RTO, he noted.
Hempling also posed the possibility of a state requiring a utility to get state permission before proposing to the RTO any new construction of transmission above a particular level. “In my legal opinion, a state can do that, but it has not been tested,” he said.
After the Fact
How can a state pursue its values after a utility joins an RTO?
Hempling noted that legal precedent precludes states from forcing a utility — including an RTO — to submit a tariff change with FERC. Still, a state can circumvent that restriction by persuading the utility or RTO to make a state-sought filing.
“The way the Federal Power Act works is this: If a utility makes a filing at FERC, and that filing satisfies the Federal Power Act standard of ‘just and reasonable’ … FERC is obligated to approve it, even if FERC has a better idea. … It’s a utility-deferential statute,” he said. “Which means if you are a state wanting to say, ‘I’ve got a better idea,’ and so you introduce at FERC a filing, FERC is going to say, ‘I like your idea a lot better, state, but the utility’s idea is just and reasonable.’”
SPP has worked around this situation through the authority granted to its Regional State Committee, which can order SPP to make a filing even if the RTO disagrees with it, Hempling said. “Now SPP can also make its own filing, and they can say, ‘We think the state’s idea is crap,’ but we file it because we agreed to file it. And what happens now is that FERC can actually choose either one. So it puts the states on equal legal footing in terms of the chances of being selected.”
Former California Public Utilities Commissioner Mike Florio, now principal of Florio Consulting, said that California legislators have asked him whether the state can direct an investor-owned utility to leave an RTO.
“My … answer is no, because … it’s a contract that FERC has approved,” Hempling replied. “And that contract is where you go to find out the authority of someone to leave. And because it’s a FERC-jurisdictional contract, a state cannot issue an order that causes a utility to act in violation of the contract. That would be pre-emptive.
“FERC wants the stability about decisions to be in FERC’s hands,” he added.
Utah Public Service Commissioner David Clark said one of his concerns about his state’s utilities joining an RTO is the cost-of-service differential between it and other states in the region — namely, California.
“I know FERC has been concerned that the RTO process maintain status quo benefits and focus on new benefits,” Hempling said. “I think FERC has not had the notion of creating enemies of the RTO process.”
Another commissioner asked: “How do we know we’re protecting our state’s interests?”
Hempling replied with a question: “What is the commonality that we’re trying to pursue through the RTO mechanism when there are so many differences? … Focus on what the commonalities are.
“I was once at a [National Association of Regulatory Utility Commissioners] meeting and there was a Midwestern commissioner who said, ‘Whoa, if we’re not preserving state regulation, what are we here for?’” Hempling said. “And I’m thinking, ‘What you’re here for is something bigger than that. You’re here for efficiencies; you’re here for the customer; you’re here for investors; you’re here for marginal values. You’re here for something. You’re not here for jurisdiction.’
“The mission is not jurisdictional preservation. It’s jurisdictional effectiveness.”
MISO stakeholders are concerned over the RTO’s unit retirement proposal, saying it could result in conflicts over interconnection service rights between suspended units and those in the queue.
“Folks were not comfortable with granting … conflicting interconnection rights,” MISO engineer Patrick Jehring said during an April 17 Planning Subcommittee meeting.
MISO is proposing to model suspended units as offline during the three years of their suspension, then considering them available to participate in local balancing authority dispatch in planning scenarios thereafter. Units that retire during the three-year process by waiving their interconnection rights with MISO will be modeled offline indefinitely in planning models.
Jehring said the modeling plan is like the three-year offline modeling used today but aligns with MISO’s new proposal to have generation owners considering a shutdown enter a catch-all suspension period for three planning years.
Owners would no longer have to decide between a permanent retirement and a temporary shutdown, which requires an estimated return-to-service date. Instead, they would have three full planning years to prepare a return to service or decide on retirement. Suspended generators would lose interconnection service after three planning years if they don’t resume operations. (See MISO Readies Retirement Change.)
Pat Hayes, LS Power transmission policy manager, asked what happens when the owner of a suspended unit returns after the three-year rescission period to find that new generation is poised to assume its interconnection service.
“It’s never happened before,” Jehring said. In such a case, he said, the projects’ local transmission pricing zone would bear the cost risks of the network upgrades necessary to accommodate both the new and existing unit.
“Basically, the stars need to align for this situation to occur. … The likelihood of this occurring is low based on what we’ve seen in the past and what we expect in the future,” Jehring stressed.
Some stakeholders said MISO’s modeling still leaves open the risk that local transmission pricing zones will bear the cost of interconnecting two conflicting units.
“I guess what I would say to that is the possibility for this rift already occurs today. It’s an if-upon-if-upon-if situation to get to that situation,” Jehring said.
Of the approximate 27 GW of Attachment Y suspension/retirement notices that MISO has received, Jehring said only 6 GW has returned to service. MISO unit owners typically submit Attachment Y when catastrophic equipment failure occurs or the units become uneconomic to operate. “When we think about the magnitude of it, we’re only talking 6,000 MW.”
| MISO
Jehring said including suspended units in the dispatch in modeling after their three-year suspension period doesn’t mean the units would ever be dispatched again. The decision to dispatch is based on the “most economic firm resources being utilized to meet a local balancing area’s firm load and interchange obligations,” according to MISO.
“If a unit goes on suspension for economic reasons, it is unlikely it would be dispatched in the planning models anyway,” Jehring said. “The only real reason that a unit will stay on suspension is they’re on the economic bubble … and they’re truly seeing if they’ll become economic again.”
MISO will accept written stakeholder comments on the modeling proposal through May 4.
WASHINGTON — By now, it sounds like a broken record.
As they have in the past four years, the trends in natural gas dominated the discussion of FERC’s annual State of the Markets report at the commission’s open meeting on Thursday.
The report found that average U.S. natural gas spot prices rose 21% in 2017 from 2016, while average day-ahead on-peak LMPs increased 3 to 13% at pricing nodes in RTO/ISO markets.
While the previous two years were marked by cheap prices driven by warm winters, last year saw cold weather at both its beginning and end, with an especially severe cold snap at the end of December and into January 2018 leading to a sharp spike in prices, especially in ISO-NE. (See FERC, RTOs: Grid Performed Better in Jan. Cold Snap vs. 2014.)
Last year also marked the first since 1958 that the U.S. was a net exporter in gas, propelled by increased LNG export capacity. “The largest increase in demand for natural gas came from LNG exports, which rose from 0.63 Bcfd to 2.19 Bcfd, a 248% increase,” according to the report. Total exports to Mexico, the U.S.’ biggest LNG customer, increased by 0.5 Bcfd to an average 4.2 Bcfd for the year, aided by several new cross-border pipelines.
Gas producers also found new markets within the U.S. About 12 billion Bcfd and 773 miles of new pipeline capacity went into service last year, most of it in the Marcellus and Utica shales. “New pipeline capacity out of the Marcellus and Utica shale plays allowed producers to meet demand in previously inaccessible markets,” the report says. “These shale plays demonstrated the largest U.S. natural gas production growth in 2017, with a 10.3% year-over-year increase for a total production of 22.1 Bcfd by the end of 2017.” Total U.S. gas production rose 1.0%, averaging 73.6 Bcfd.
One of the only metrics to fall significantly was storage inventory. 2017 saw the third lowest weekly storage injection rate since 2010, while the end-of-year cold snap led to the largest withdrawal in history, 359 Bcf. The large winter withdrawals also led to the lowest end-of-winter storage level since 2014: 1.35 Tcf on April 5, 2018.
Commissioners Neil Chatterjee and Robert Powelson both noted the prevalence of gas in the report, focusing their comments on the importance of fuel security and gas-electric coordination to grid reliability.
“Staff’s report indicates that at the beginning of last year, fuel security was already a particular concern within New England and Southern California because of limited natural gas transportation and storage infrastructure, and that by last winter, those concerns had grown into real anxiety,” Chatterjee said. Noting the cold snap in the East and pipeline outages in California, “I look back at 2017 as the year of close calls that underscore the importance of examining fuel-security issues,” he said.
“The analytics … in today’s report are really a testimony to the benefits of organized markets and what they do in terms of providing reliability,” Powelson said.
He said he was concerned about the phaseout of the Aliso Canyon storage facility in California, noting the state’s aggressive renewable portfolio standard, the closure of several nuclear plants there and, in what he called “the “who-would-have-thunk-it moment,” commission-approved reliability-must-run contracts for gas units in CAISO. He called these, along with the high prices in New England, “alarming situations.”
The report was released right after FERC issued a Notice of Inquiry to review its 1999 policy statement on natural gas pipelines. (See related story, FERC Outlines Gas Pipeline Rule Review.)
FERC on Thursday ordered new rules to increase the transparency and timeliness of the generator interconnection process (RM17-8, Order 845).
The order adopts all but four of 14 potential rule changes in the commission’s December 2016 Notice of Proposed Rulemaking revising the pro forma large generator interconnection procedures and large generator interconnection agreement (LGIA). (See FERC Proposes Changes to Interconnection Rules.)
The rulemaking, which was prompted by a complaint by the American Wind Energy Association, applies to generators larger than 20 MW.
Blue Canyon wind farm | EDP Renewables
Commission staff said the revisions acknowledge the inefficiencies that have resulted from changes to the generation industry since the commission issued the pro forma interconnection procedures and agreement in 2003 (Order 2003).
“These inefficiencies include backlogs in interconnection queues, long timelines to process interconnection requests and late-stage withdrawals of interconnection requests that can lead to cascading interconnection restudies, which can lead to even more withdrawals,” staff said in a presentation at the commission’s open meeting.
It also seeks to address transmission providers’ concerns that the interconnection study process has become difficult to manage because they have been flooded with requests for new facilities that have little chance of reaching commercial operation.
The final rule removes a limitation on an interconnection customer’s ability to construct interconnection facilities and standalone network upgrades and requires transmission providers to improve their dispute resolution procedures.
To improve transparency and efficiency, the rule:
requires transmission providers to make public their methods for determining contingent facilities and to list the processes and assumptions used for network models employed in interconnection studies;
revises the definition of “generating facility” to explicitly include electric storage;
sets requirements for reporting on aggregate interconnection study performance;
allows an interconnection customer to request a level of service lower than its generating facility capacity;
requires transmission providers to allow provisional interconnection agreements that offer limited operation of a generator before completing the interconnection process;
requires transmission providers to offer the use of surplus interconnection service; and
requires transmission providers to consider changes in an interconnection customer’s proposed technology that occur during the interconnection process to determine if they constitute a material modification.
“The transparency reforms make information more timely and accessible to transmission customers, thereby potentially reducing the number of interconnection requests for projects that are unlikely to reach commercial operation,” staff said. “The efficiency and enhancement reforms facilitate the use of existing interconnection, mitigate the likelihood of unnecessary upgrades and related costs, provide paths to bring generation online more quickly, and allow for the incorporation of technological advancements into an interconnection request.”
Stakeholder comments persuaded FERC not to adopt four other rule changes requiring periodic restudies, self-funding of network upgrades, the posting of congestion and curtailment information and the modeling of electric storage.
The commission also took no action on two other issues on which the NOPR sought comment but for which no proposals were made: cost caps for network upgrades and affected-system coordination, the latter of which was the subject of a two-day technical conference in early April. (See Renewable Gens Face Off with RTOs at Seams Tech Conference.)
The American Council on Renewable Energy (ACORE) issued a statement praising the order. “While the reforms cover interconnection for all types of energy generators, we believe the final rule is an important recognition of a fundamental shift in the U.S. electric sector as we continue to diversify our electricity supply. Going forward, we are optimistic the rule will improve and expedite critical interconnection procedures for solar, wind and other renewable technologies, while also expanding access to energy storage resources.”
The rule will be effective 75 days after publication in the Federal Register.
FERC on Thursday approved rules to prevent malware from infecting “low impact” computer systems through transient electronic devices such as laptops and thumb drives (RM17-11, Order 843).
The order approves a requirement outlined in the commission’s October Notice of Proposed Rulemaking directing NERC to modify reliability standard CIP-003-7 to mitigate the risk of malicious code that could result from third-party devices that frequently connect to and disconnect from low-impact systems. (See FERC Seeks Cyber Controls on Portable Devices; Sets GMD Plans.)
The commission reiterated the concerns it raised in the NOPR that the NERC standard “lacks a clear requirement to mitigate the risk of malicious code” that could result from third-party transient devices. “Accordingly, we direct NERC to develop a modification to the reliability standard to provide the needed clarity. Such modification will better ensure that registered entities clearly understand their mitigation obligations and, thus, improve individual entity mitigation plans,” the commission said.
However, the commission declined to adopt a proposal requiring NERC to “provide clear, objective criteria for electronic access controls” for low-impact systems. NERC tiers its cybersecurity requirements based on classifications of high-, medium- and low-impact Bulk Electric System (BES) cyber systems.
The commission said comments from NERC and others convinced it that the reliability standard already “provides a clear security objective that establishes compliance expectations.”
Instead, FERC ordered NERC to conduct a study within 18 months to assess the implementation of the standard to determine whether the electronic access controls adopted by responsible entities “provide adequate security.” The study was proposed in a joint filing by the American Public Power Association, Edison Electric Institute and National Rural Electric Cooperative Association, identified in the order as “trade associations.”
Reversal
NERC said that the standard requires responsible entities to “document the necessity of its inbound and outbound electronic access permissions and provide justification of the need for such access.”
The trade associations, Electric Consumers Resource Council (ELCON) and Transmission Access Policy Study Group said the proposal would be burdensome and ineffective. While it “appreciates the value establishing more tangible criteria for adequate low-impact BES cyber system controls … the additional requirements that the commission proposes would do nothing to harden a low-impact facility against the rapid evolution in cyber warfare,” ELCON said.
The trade associations urged a risk-based approach to allow responsible entities to focus their resources on assets that have a higher impact on reliability.
“Given NERC’s statements, we believe that there will be adequate measures to assess compliance with reliability standard CIP-003-7,” FERC concluded. “We expect responsible entities to be able to provide a technically sound explanation as to how their electronic access controls meet the security objective.”
Mitigation of Malicious Code
The trade associations and ELCON also opposed the NOPR’s proposal to require responsible entities to prevent malicious code from entering their systems via transient electronic devices used by contractors and other third parties. The trade groups said risk mitigation is implicitly required under Section 5 of the standard.
But FERC said the standard doesn’t go far enough. “While commenters agree that, at least implicitly, the mitigation of malicious code is an obligation, the lack of a clear requirement could lead to confusion in both the development of a compliance plan and in the implementation of a compliance plan,” the commission said. “In addition, although NERC contends that the proposed directive may not be necessary, NERC agrees that modifying reliability standard CIP-003-7 to address the mitigation of malicious code explicitly could clarify compliance obligations.”
FERC said the new standard also will improve reliability by requiring responsible entities to have a policy for declaring and responding to “exceptional circumstances” — defined by NERC as a natural disaster, civil unrest or a situation that threatens to impact BES reliability or presents a risk of injury or death.
FERC will open a 60-day comment period on potential changes to its policy statement on the permitting of natural gas pipelines, acknowledging that it may have to reconsider how it balances project benefits against adverse consequences in light of the shale gas revolution, global warming concerns and other changes since it last considered the issue in 1999.
All five commissioners said Thursday they welcomed the Notice of Inquiry (PL18-1), which FERC Chairman Kevin McIntyre had promised at his first meeting in December. (See FERC to Review Gas Pipeline Approval Process.)
But given the increasing contentiousness over pipeline expansions, it’s unlikely the commission will find consensus on all issues on which the NOI seeks comment. (See FERC Whipsawed on Pipeline Policy in House Hearing.)
Flashpoints
The biggest flashpoint may be the debate over how the commission evaluates the greenhouse gas impacts of new pipelines under the Natural Gas Act (NGA) and National Environmental Policy Act (NEPA). The NOI also noted “increased concerns” by landowners and communities affected by proposed projects as the total miles of interstate pipelines approved by the commission annually hit a peak of 2,739 miles last year.
Another point of contention could be calls for speedier pipeline approvals. The NOI says the commission “is committed to carrying out” President Trump’s executive order 13807, which calls for completion of all federal environmental reviews and permitting processes for infrastructure projects within two years.
| National Fuel Gas Co.
“The commission’s aim in this proceeding is the same as in the policy statement: ‘to appropriately consider the enhancement of competitive transportation alternatives, the possibility of over building, the avoidance of unnecessary disruption of the environment and the unneeded exercise of eminent domain,’” FERC said.
McIntyre said the commission’s issuance of the NOI does not mean FERC will ultimately change its current procedures. He said it will apply the current rules to pending applications on a case-by-case basis during the inquiry. “The commission will consider only generic issues and will not consider any comments that refer to open, contested commission proceedings,” the NOI warned.
1999 Policy Statement
The 1999 policy statement followed moves to reduce regulation and increase competition in the industry under the Natural Gas Policy Act of 1978 and FERC Order 436, which allowed local distribution companies and industrial customers to buy gas directly from producers or merchants and transport their gas on interstate pipelines.
The policy statement said the commission will consider whether a proposed project’s anticipated public benefits outweigh its adverse effects on economic interests. If so, the commission then analyzes the project’s environmental impacts in reaching a conclusion on whether a project is required by the public convenience and necessity.
Four Topics of Inquiry
The commission asked for comments on four topics:
The reliance on precedent agreements to demonstrate project need, and how contracts with pipeline affiliates should be treated (e.g., “Should the commission examine whether the proposed project meets market demand, enhances resilience or reliability, promotes competition among natural gas companies, or enhances the functioning of gas markets?”);
Landowner interests and the use of eminent domain (e.g., “Should applicants take additional measures to minimize the use of eminent domain?”);
The evaluation of alternatives and environmental effects under NEPA and the NGA (e.g., “Are there any environmental impacts that the commission does not currently consider in its cumulative impact analysis that could be captured with a broader regional evaluation?”); and
The efficiency and effectiveness of the commission’s certificate processes (e.g., “Should certain aspects of the commission’s application review process (i.e., pre-filing, post-filing and post-order-issuance) be shortened, performed concurrently with other activities or eliminated to make the overall process more efficient?”).
Comments will be due within 60 days of the publication of the NOI in the Federal Register.
FERC on Tuesday approved PJM’s proposed rules for implementing restrictions imposed on energy efficiency resources (EERs) by state or local regulators that are authorized by the commission to restrict their sale in the RTO’s markets (ER18-870).
The commission simultaneously denied rehearing of a related order it issued in December that asserted the commission had “exclusive authority” over the participation of energy efficiency in wholesale markets while preserving a carveout it approved earlier for Kentucky utilities (EL17-75-001).
The order was prompted by a June 2017 petition by Advanced Energy Economy for a declaratory order that FERC — and not state or local regulators — has authority over how EERs participate in wholesale markets. FERC sided with AEE in the December order. (See FERC Claims Jurisdiction on EE, OKs Ky. Opt-Out.)
PJM Plan
PJM’s plan creates a verification process to ensure that all EERs offered and cleared in the RTO’s capacity market comply with any restrictions that may be imposed by a relevant electric retail regulatory authority (RERRA). It also helps sellers of EERs that cleared in a prior PJM capacity market auction but are subsequently restricted from participation in the market by a RERRA.
The RTO will post a FERC-authorized notice of a RERRA’s restrictions. Sellers in the capacity market will be required to itemize EERs located within a RERRA’s boundaries and submit the list to PJM, which will distribute lists of EERs to relevant electric distribution companies. The EDCs will be required to proactively affirm compliance with PJM before the EERs can participate.
EERs are different from demand response resources, PJM explained, because they are eligible to participate unless a RERRA restricts them. In contrast, DR is ineligible to participate unless a RERRA affirmatively permits them.
EERs that are made ineligible by RERRA regulations after they’ve cleared an auction may obtain replacement capacity or elect to be relieved of the capacity commitments.
“Such a rule protects sellers of EERs from being assessed deficiency charges or Capacity Performance nonperformance charges,” the commission explained.
Rehearing Denial
Several parties — including FirstEnergy, several public power groups and several Midwestern transmission and distribution utilities — requested rehearing or clarification of the commission’s December ruling on exclusive authority. They alleged that FERC overreached in pre-empting state authority to oversee EERs.
“We find that the commission’s authority to determine which resources are eligible to participate in the wholesale markets is a fundamental component of the regulation of the wholesale markets,” the commission responded, drawing a distinction between state authority to procure renewable energy and FERC’s authority over EERs.
“Our determinations here do not prevent states from regulating retail sales of electricity, even when such regulation incidentally affects areas within the commission’s domain,” the commission said.
However, the commission said it also disagreed with American Municipal Power, the American Public Power Association, National Rural Electric Cooperative Association and Public Power Association of New Jersey “that state and local restrictions on EER participation in wholesale markets is a valid exercise of state and local authority over retail electric service. A provision directly restricting retail customers’ participation in organized wholesale electricity markets, even if contained in the terms of retail service, nonetheless intrudes on the commission’s jurisdiction over the wholesale markets.”
FERC specifically declined to address whether its conclusion is based on the “field pre-emption” or “conflict pre-emption” under the Supremacy Clause of the Constitution.
“Because we conclude that the question of which resources may participate in wholesale markets is fundamental to the regulation thereof, we need not specifically address whether Congress ‘occupied’ the relevant field or whether a state law arrogating that authority to the state merely ‘stands as an obstacle’ to the commission’s responsibilities under the [Federal Power Act],” FERC explained.
FERC on Thursday denied a challenge by Sunflower Electric Power and Mid-Kansas Electric to the commission’s 2017 order allowing SPP to change its regional cost allocation review (RCAR) analysis from at least once every three years to once every six years (ER17-2229).
The commission said Sunflower and Mid-Kansas reiterated arguments they made in protesting the original order, when they said problems with the RCAR’s study assumptions, analysis and results made it unreasonable to decrease its frequency. The commission ruled their concerns as being out of scope. (See FERC Approves 6-Year Cycle for SPP RCAR Review.)
In rejecting the request, FERC said SPP’s decision to lengthen the review cycle “is further supported by SPP’s desire to avoid the expense of the RCAR analysis and by the fact that a vast majority of SPP zones have been at or above a 1-to-1 benefit-to-cost ratio.”
Current SPP Transmission Pricing Zones I KCP&L
The commission said the companies failed to back up their claim that SPP’s Regional State Committee would be unresponsive to members facing an imbalance in cost allocation, or that they would need to conduct a study to request relief through the revised Tariff. “Parties could use existing data and studies to support a request,” FERC said.
“Further … SPP has in the past taken action to address stakeholder concerns related to cost allocation, and we expect it will respond in a like manner if presented with evidence the allocation has become inequitable,” the commission said. It noted the RTO had said “no individual transmission owners would be required to conduct a study prior to requesting that SPP perform an RCAR analysis.”
FERC also found no merit to Sunflower and Mid-Kansas’ argument that $7.8 billion in current base plan projects and expected increases in transmission investment suggests that the frequency of the RCAR analysis should remain at three years. The commission said that SPP was able to show that, compared to prior periods, “the overall pace of increase of transmission costs within the SPP footprint has slowed.”
Stakeholders approved a task force’s proposal to institute a six-year planning cycle in April 2017. The task force said the change would save SPP manpower and consulting costs. (See “RSC Approves Six-Year Cost Allocation Review,” SPP Regional State Committee Briefs.)
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SPP’s cost allocation methodology, the “Highway/Byway” method, assigns 100% of all 300-kV+ transmission upgrades to zones on a regional basis.
The most recent regional cost review (RCAR II), released in July 2016, showed an overall 2.46:1 benefit-cost ratio for projects approved since June 2010 under the Highway/Byway methodology — a big increase from RCAR I, which showed a 1.39:1 ratio. Only one transmission zone was below the 0.80 threshold established by the Regional Allocation Review Task Force.
SPP said it took about 2,100 employee hours and more than $417,000 in payments to consultants to complete that review. The two RCARs have cost more than $1.5 million in consulting fees, and each study has taken at least six months to complete, according to the RTO.
FERC has approved a settlement between PJM, Exelon and the Illinois Commerce Commission over abandonment costs for the canceled Mid-Atlantic Power Pathway (MAPP) transmission project.
Under the uncontested settlement accepted by FERC on Thursday, Exelon subsidiary Baltimore Gas and Electric’s pricing zone will bear more costs of the project while the Commonwealth Edison zone’s responsibility will not exceed $75,000 — less than half of the costs it was originally assigned. FERC said PJM must disburse refunds if the ComEd zone has already paid more than $75,000 (ER17-1016-001).
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Proposed more than a decade ago, the $1.05 billion, 500-kV MAPP project would have extended about 230 miles from northeastern Virginia through southern Maryland and Delaware, crossing beneath the Chesapeake Bay and Choptank River to southwestern New Jersey.
In 2009, PJM assigned BGE two baseline upgrades for the project, but the RTO’s Board of Managers canceled the project in 2012, saying it was no longer needed to maintain reliability. The line was originally included in PJM’s 2007 Regional Transmission Expansion Plan.
Early last year, PJM submitted Tariff revisions on BGE’s behalf so the utility could recover about $1.2 million in abandoned plant costs.
The ICC protested, arguing that ComEd should not have to bear the costs of a canceled line that never stood to benefit its Midwestern territory. ComEd’s zone stood to incur 13.43% of the cost of BGE’s upgrades under PJM’s postage stamp cost allocation methodology.
“Given that MAPP is a canceled project, the ComEd zone does not derive any benefits from the MAPP project. … The load in the ComEd zone did not contribute to the reliability factors that caused PJM to add the MAPP project to the RTEP in the first place. The beneficiaries and cost causers of the MAPP project are located on the East Coast and that is where the commission should allocate the costs,” the ICC wrote.
The ICC also pointed to rulings by the 7th U.S. Circuit Court of Appeals, which twice remanded FERC’s approval of PJM’s regionwide postage stamp cost allocation for new 500-kV+ transmission projects (See Despite Lengthy Negotiations, PJM Cost Allocation Settlement Still Finds Detractors.) The 7th Circuit said that PJM’s high-voltage lines are “all located in PJM’s eastern region, primarily benefit that region and should not be allowed to shift a grossly disproportionate share of their costs to western utilities on which the eastern projects will confer only future, speculative and limited benefits.”
