FERC on Friday rejected a bid by New England transmission owners to increase their returns on equity to the levels enjoyed before they were lowered by a 2014 commission order that was vacated by an appellate court earlier this year.
The commission said it would address the actual rate in a later remand order (ER15-414, EL11-66).
The D.C. Circuit Court of Appeals ruled in April that the commission had “failed to provide any reasoned basis” for setting the base ROE for a group of New England TOs at 10.57%, adding that the commission failed to meet its burden of proof in declaring the existing 11.14% rate unjust and unreasonable. (See Court Rejects FERC ROE Order for New England.)
National Grid’s Sandy Pond Substation in Ayer, Mass.
Led by Emera Maine, the TOs requested reinstatement of their previously allowed ROEs in June. Other parties included Central Maine Power, Eversource Energy, National Grid and Avangrid subsidiary United Illuminating.
The TOs claimed that the court’s decision “automatically” restored the parties to the rate in effect prior to the vacated Opinion No. 531. Because the commission lacked a quorum at the time of the filing, the TOs asked to begin collecting at the higher rate 60 days after the commission regained a quorum, which it did on Aug. 9, when new Chairman Neil Chatterjee and Commissioner Robert Powelson joined the commission. (See Quorum Restored, FERC Holds First Open Meeting Since January.)
To reduce the administrative burden on the commission, the TOs said they would leave the question of surcharges for the period before the court’s decision until FERC issued a remand order for Emera.
| ISO-NE
The commission disagreed that the D.C. Circuit decision returned TOs to their previous ROEs: “As the Supreme Court explained in Burlington Northern Inc. v. United States, which involved the substantively similar provisions of the Interstate Commerce Act, a ‘federal court[’s] authority to reject … rate orders for whatever reason extends to the orders alone, and not to the rates themselves.’”
The commission concluded that leaving the current ROEs in place would not make the TOs any worse off following a remand order for Emera because, on remand, the commission will exercise its “broad remedial authority” to make whatever ROE the commission determines to be just and reasonable effective for the refund period and the entire period.”
In addition, the order said an immediate return to the previously allowed ROEs would “significantly complicate the process of implementing the commission’s order on remand.”
In 2014, FERC determined that a discounted cash flow (DCF) analysis of a proxy group of companies comparable to TOs produced a zone of reasonableness of 7.04 to 11.74%. The commission also concluded that TOs’ new just and reasonable ROE should be set at the upper midpoint of the zone of reasonableness — i.e., halfway between the midpoint and the top of the zone of reasonableness.
The D.C. Circuit ruled that the commission had not adequately shown that the existing ROE was unjust and unreasonable. The court explained that the Federal Power Act’s statutory “zone of reasonableness creates a broad range of potentially lawful ROEs rather than a single just and reasonable ROE.”
SPP stakeholders last week briefly discussed a recent American Electric Power complaint filed at FERC against the RTO and MISO related to overlapping congestion charges for pseudo-ties.
The Section 206 complaint (EL17-89) alleges that MISO violated its joint operating agreement with SPP by assessing congestion charges to AEP subsidiary Southwestern Electric Power Co. load that is pseudo-tied out of MISO and into SPP.
In its complaint, AEP said the MISO Tariff and Business Practices Manual are unjust and unreasonable in how they assess the congestion charges.
SPP and MISO have negotiated a memorandum of understanding to address the overlapping charges. The RTOs have said the MOU borrows elements from MISO’s coordination efforts with PJM but won’t result in major changes in coordination. (See MISO Interregional Plans with SPP Echo PJM Efforts.)
Staff said Friday it will file a response at FERC but won’t comment until then.
Light M2M Activity Results in $161K in Payments to SPP
In what staff described as a light month for market-to-market activity between SPP and MISO, the latter paid SPP more than $161,000 in August, reversing two months of payments in the opposite direction.
| SPP
Permanent flowgates accounted for most of the congestion, binding for 37 hours and resulting in $148,794 in M2M settlement charges to MISO. Temporary flowgates were binding for 83 hours, 131 hours less than the month before, giving SPP an additional $12,495.
SPP has collected $20.7 million in payments from MISO as of August. The M2M process between the two RTOs began in March 2015.
AEP’s Jacoby Continues as Chair
The committee approved its recommendation for AEP’s Jim Jacoby to serve a full two-year stint as chairman, effective Jan. 1. Jacoby’s term will expire Dec. 31, 2019.
FERC on Friday rejected SPP’s proposed cost allocation for its seams project with Associated Electric Cooperative Inc. (AECI), a Missouri-based collection of six generation and transmission cooperatives.
The commission ruled SPP had not shown that the proposed allocation on a regionwide, load-ratio share basis was “roughly commensurate” with the project’s benefits (ER17-2256, ER17-2257).
The project includes a new 345/161-kV transformer at AECI’s Morgan substation and uprating a related 161-kV line, both near Springfield, Mo. SPP estimated the project, intended to address persistent thermal and voltage problems, would cost $18.75 million. SPP asked FERC to approve a cost-sharing and usage agreement among the RTO, AECI and City Utilities of Springfield — along with Tariff revisions incorporating SPP’s negotiated share of the revenue requirements — in August.
| AECI
SPP General Counsel Paul Suskie said that although the RTO is disappointed, “we’re undeterred and confident we’ll be able to continue to work … with members to develop an appropriate cost allocation for this and future seams projects.”
“The ability to develop necessary and beneficial transmission improvements along our seams remains a high priority for SPP and its members,” Suskie added.
SPP had proposed to regionally fund the projects, as they solved congestion issues on its side of the seam. The RTO agreed to cover 89.1% of the $13.75 million transformer and 97% of the $5 million uprate, with AECI covering the remainder and being responsible for the projects’ construction, operations and maintenance.
The RTO said it planned to allocate its share of the two projects by inserting their revenue requirements into the annual transmission revenue requirement of its highway/byway regional cost allocation methodology. Highway/byway funding considers facilities of 300 kV or above as highway facilities, with their costs allocated on a regionwide, postage-stamp basis; facilities between 100 and 300 kV are categorized as byway facilities, with two-thirds of the costs assigned to the host zone and one-third allocated regionwide.
Projects below 100 kV are allocated entirely to the host zone, while upgrades that operate at two difference levels — such as transformers — are allocated based on the facilities’ lower operating voltage.
Xcel Energy and Westar Energy protested the RTO’s filing.
Xcel opposed the Morgan transformer’s cost allocation, contending that SPP provided insufficient evidence that the proposed cost allocation reflects its benefits. The company said there is no “default rule” that customers in SPP’s 19 transmission zones “should bear the costs of a transmission facility in cases where the owner of the facility is located outside [the footprint].”
| SPP
The company also said SPP failed to provide information on the project’s benefits to transmission owners or loads in the Southeastern Regional Transmission Planning (SERTP) region that would justify a broader cost allocation to AECI’s fellow SERTP members.
FERC sided with Xcel’s argument that SPP had not provided specific information on the transformer project’s regionwide benefits and had not offered “sufficient evidence to demonstrate that these claimed economic benefits accrue throughout the SPP footprint.” The commission said the RTO’s own analysis indicated the project does not provide economic benefits to at least 11 of the 19 transmission zones.
Because SPP failed to support its cost allocation, FERC said it did not need to address Westar’s allegation of a lack of transparency regarding SPP’s negotiations with AECI. The utility had argued all affected parties have a right “to analyze the methodology and rationale by which SPP and AECI negotiated and substantiated the cost allocation ratios proposed in the filings.”
The commission said its rejection does not preclude the RTO from proposing an alternative allocation or making another filing that demonstrates the project provides regional benefits.
SPP stakeholders in July reiterated their support of the project, despite a nearly 50% cost increase due to additional work to upgrade the 161-kV line. (See “Board Reaffirms Seams Project with AECI,” SPP Board of Directors/Members Committee Briefs: July 25, 2017.)
The commission in 2015 rejected SPP’s attempt to create a new class of seams transmission projects, saying its plan to identify projects outside the Order 1000 interregional planning process was “too broadly drawn” (ER15-2705). FERC did allow SPP to make filings on a project-by-project basis for non-Order 1000 facilities. (See FERC Rejects SPP Proposal for Seams Transmission Projects.)
BOSTON — The transmission projects proposed to bring renewable energy to New England all promise fixed-cost contracts, hundreds of jobs, big cuts in CO2 emissions, and millions in consumers savings and tax revenues.
How to choose? That was the question Friday at Raab Associates’ New England Electricity Restructuring Roundtable.
Representatives of five transmission projects proposed in July in response to the Massachusetts solicitation for 9.45 TWh/year of hydro and Class I renewables (wind, solar or energy storage) tried to explain why their projects should be among those selected in January. Contracts awarded under the MA 83D request for proposals are to be submitted in late April. (See Hydro-Québec Dominates Mass. Clean Energy Bids.)
The solicitation is a collaborative effort by the Massachusetts Department of Energy Resources and the state’s distribution utilities: Eversource Energy, National Grid and Unitil. DOER Commissioner Judith Judson attended the session, as did Angela M. O’Connor, chair of the Massachusetts Department of Public Utilities, along with 225 others in person and more streaming the event online.
William Hazelip, National Grid vice president of business development, said only his company’s projects meet the key goals set out in the state’s Global Warming Solutions Act of 2008 and the 2016 Act to Promote Energy Diversity, namely to facilitate the financing of new clean energy resources and to minimize “leakage.”
National Grid partnered with Citizens Energy on the Granite State Power Link, an HVDC transmission line from northern Vermont to New Hampshire to deliver 1,200 MW of new wind power from Canada, and the Northeast Renewable Link, a 23-mile AC line from Rensselaer County, N.Y., to Hinsdale, Mass., to deliver 600 MW of new wind, solar and small hydro into the New England grid.
Proposals | National Grid
“The intent of the Diversity Act is clear: It’s about adding new resources to reduce emissions,” Hazelip said. He said leakage — cutting the state’s emissions while increasing them in neighboring regions — would be pronounced with the proposals that rely mostly on existing hydro resources in Quebec.
“Today, the existing hydro is being exported to New York and Ontario,” Hazelip said. “That reduces the use of thermal units and reduces greenhouse gas emissions. Using the Mass. RFP to contract for those resources will only redirect the energy to Massachusetts and raise emissions in New York and Ontario.”
Chris Huskilson, CEO of Nova Scotia-based Emera, made a pitch for his company’s proposed Atlantic Link project, a 375-mile submarine HVDC transmission line extending from New Brunswick to Plymouth, Mass., near the retiring Pilgrim nuclear plant and close to the Boston load center.
“For us, the primary word is ‘diversity.’ [Atlantic Link] provides diversity of supply and allows you to access wind in Maine, wind in the Maritimes, hydro from Newfoundland and potentially hydro from Quebec.”
The project would become operational in December 2022 and deliver 5.69 TWh of clean energy per year to Massachusetts at a fixed price for 20 years.
At 5.7 TWh, Emera’s project would fulfill only half of the RFP, leaving room for another project that can provide supply diversity, Huskilson said.
Atlantic Link Project | Emera Energy
In addition, Atlantic Link terminating “in the southern part of Massachusetts means that it supports the system in the location that really needs that support,” Huskilson said. “The loss of the Pilgrim nuclear plant is going to be something that the system will have to find ways to recover from and the opportunity to connect with this transmission project directly to that location … is a very good opportunity.”
Certainty is Best
Transmission Developers Inc. partnered with Hydro-Québec on the New England Clean Power Link, which includes a submarine cable under Lake Champlain and an overland section to a proposed converter station in Ludlow, Vt., to connect to the existing Coolidge substation. It would bring 1,000 MW of hydropower, solar and wind from Canada.
“The one word for us as we differentiate our project from other projects is ‘certainty’ — on price, on construction, on support, and the certainty of our ability to execute and execute with support, from the governor’s office on down,” TDI CEO Donald Jessome said.
In addition to having all the permits needed for the project, Jessome said TDI also has reserved slots at the manufacturing facilities for production of the cable, which will take a year to produce.
“We know exactly what our project costs and how long it will take and have mapped out every step,” Jessome said. “We know who’s going to be maintaining our project, [Vermont Electric Power Co.] and ABB, once it’s up and running. And of course, we have very good financial backing through the Blackstone Group.”
Focus and Options
Avangrid subsidiary Central Maine Power partnered with Hydro-Québec on the New England Clean Energy Connect, a 145-mile, 320-kV HVDC line that would carry 1,200 MW of hydro and wind energy from Canada to Maine. The company also teamed with NextEra Energy on the Maine Clean Power Connection, a new 345-kV connection from western Maine to the New England grid with capacity options of 460 to 1,110 MW, allowing varying combinations of wind, solar and storage facilities in eastern Canada and far western Maine.
CEO Sara Burns said CMP “focused on the route, focused on the costs and focused on responding with a strong case that we can deliver. … We focused on giving Massachusetts ratepayers a cafeteria plan to choose from.”
Burns said the company is controlling costs by developing lines mostly on a route that the company controls.
“These cost conversations do not have to be too complicated,” Burns said. “If you’re on the route, it drops the prices. We have the route, have the team, have the support.”
Patrick Smith, vice president for transmission business development at Eversource, said the RFP “did specifically contemplate the use of hydroelectric power as qualifying for participation.”
Eversource is partnered with Hydro-Québec on Northern Pass, a 192-mile line to bring 1,090 MW of hydropower to New England — up to 9.4 TWh/year for 20 years starting in December 2020. Hydro-Québec’s proposals with TDI, Eversource and Avangrid all include two proposals each, one pure hydro and one with a wind energy component.
“Has the cost been compared to the current ISO clearing price for power plus transmission, and are these cost savings below that?” asked Steve Cowell, president of E4TheFuture, which advocates for “clean, efficient energy” for residential customers.
“There are additional benefits beyond the clearing price of the energy,” Jessome responded. “There’s the capacity benefit these projects are going to bring to the marketplace. There’s diversity, there’s the fact that you’re now displacing gas during winter peak periods, so you’ve got a gas price benefit. So, you have to look at [it as] a basket. If you look at it in isolation, it’s not as good a story as it is when you look at it terms of the totality of all these benefits.”
Two California Energy Commissioners are recommending the agency deny a permit to construct NRG Energy’s proposed Puente Power Project natural gas-fired plant in Oxnard, casting into doubt the chances that the facility will be built.
Commissioners Janea Scott and Karen Douglas, who are preparing a proposed decision on the 260-MW project, last week said they intend to issue a notice recommending denial of the project, which is opposed by some on environmental grounds.
“It is clear to us that the project will be inconsistent with several laws, ordinances, regulations or standards and will create significant unmitigable environmental effects,” the commissioners said. This requires study of feasible alternatives, they said, referencing Sept. 29 comments filed by CAISO in which it said a new, expedited request for offer (RFO) process would need to be launched to ensure that current facilities slated for retirement are closed in accordance with environmental laws.
| NRG
About 2,000 MW of generation in the area is due to retire by 2020 because of once-through-cooling regulations, and Puente is intended to replace NRG’s retiring Mandalay and Ormond Beach plants.
After issuing the notice, the commission will take comments and hold a public hearing, and all five commissioners can accept, modify or reject the proposed decision.
“We acknowledge that this statement is unusual but observe that it in no way impairs the rights of the applicant or any other party,” Scott and Douglas said. “All procedural requirements will continue to be honored.” They said they made the decision early in the process because of timing considerations raised by CAISO regarding the RFO.
The CEC is reviewing the construction and operating permit for the facility. The California Public Utilities Commission has already authorized Southern California Edison to enter into a long-term resource adequacy contract with NRG for the plant’s capacity.
NRG told RTO Insider on Friday that it is “very disappointed” with the decision. “We believe the record fully supports the approval of Puente. NRG favors California’s move to a carbon-free electrical grid but remains concerned about local reliability during the transition.”
On Aug. 16, CAISO issued a study on Puente saying it could not be affordably substituted with any alternatives. (See Metcalf Reliability-Must-Run Draws Scrutiny.) But in Sept. 29 comments to the CEC, CAISO led off with a different perspective: “The Moorpark [sub-area] study demonstrates that preferred resource alternatives are technologically feasible to meet local capacity requirements.” Under California policy, “preferred” resources refer to non-emitting resources such as energy efficiency, demand response, distributed energy and storage.
CAISO noted that several parties had raised concerns over the resource portfolios it had examined in its study, which included three different combinations of distributed, reactive and storage resources. “But these concerns do not detract from the central finding that a combination of preferred resources and/or reactive power devices can meet the local capacity requirements for the Moorpark sub-area if procured and implemented in a timely manner.”
In comments filed with CEC on Sept. 29, NRG said the project will not have significant environmental impacts, complies with laws and “will result in many reliability, environmental and economic benefits.” It added that alternative resources examined by CAISO “do not exist in sufficient quantities to satisfy the sub-areas [local capacity requirements] need” and could not be deployed in time.
The City of Oxnard in its comments said the plant, proposed for a dune area near the open ocean, would be in a hazardous location and will lead to more pollution. “Puente remains the wrong project in the wrong location,” the city said.
The next CEC Puente Power Project Committee conference is scheduled for Oct. 11 at the commission’s headquarters in Sacramento.
FERC said last week that a proposed revision to the Federal Power Act that would increase the right to appeal rate changes may have only limited effectiveness.
Danly
General Counsel James Danly told the Senate Energy and Natural Resources Committee’s Energy Subcommittee on Tuesday that S. 186, which would allow parties to seek judicial review of rate changes in the case of commission inaction, “only partially advances the interests of an exceedingly narrow category of aggrieved parties in very rare occasions of commission inaction.”
The bill, sponsored by Sen. Ed Markey (D-Mass.), was prompted by the commission’s 2-2 deadlock in September 2014 over whether it should reject the results of ISO-NE’s eighth Forward Capacity Auction because of unchecked market power. The 2017-18 auction results became “effective by operation of law” (ER14-1409). Under the FPA, rates take effect 60 days after they are filed with FERC, absent a commission order to the contrary. (See FERC Commissioners at Odds over ISO-NE Capacity Auction.)
Catch-22
Under Section 313 of the FPA, parties must seek rehearing of FERC orders before filing an appeal in federal court. But in the case of FCA 8, because the commission never issued an order, challengers were blocked from seeking rehearing or challenging the auction results in court — a catch-22 that the legislation intends to address.
Last October, the D.C. Circuit Court of Appeals rejected an effort by Public Citizen and Connecticut officials to force FERC to rule on the legality of the auction. It agreed with the commission that there can be no rehearing or appellate review when there is no order in a Section 205 proceeding. (See Court Asked to Force FERC Action on Disputed ISO-NE Capacity Auction.)
Danly told the subcommittee he knew of only five other instances in which a utility’s filing has taken effect by operation of law under the FPA or the Natural Gas Act without a commission order.
Under S. 186, the absence of commission action that results in a filing taking effect would be considered an order, allowing rehearings and appeals.
“The proposed legislation offers the possibility for aggrieved parties to pursue further administrative and judicial process when a disputed rate goes into effect even though half of the seated commission would not have accepted the rate in an order,” Danly observed. “Oddly, under the current statutory framework, a party who manages to persuade only one of four commissioners, and loses on a 3-1 vote, may request rehearing at the commission and seek redress at a court of appeals. However, a party that is perhaps more persuasive and manages to convince two of four commissioners, resulting in a 2-2 split — and thus no commission order — is currently barred from seeking rehearing and appellate review.”
Danly noted that any party can file a Section 206 challenge alleging rates are unjust and unreasonable — albeit at increased cost and a higher burden of proof than Section 205 filings.
But he said the legislation may not provide the relief its sponsors intend.
“Should the commission’s inaction be the result, as in the ISO-NE case, of a 2-2 split, a similar result could obtain for a later order on rehearing,” Danly said. “In that case, there would be another 2-2 split and no order on rehearing would issue. In such a case, it would be exceedingly unlikely that a court of appeals would entertain a petition for review.
“Moreover, even if a court of appeals accepted the petition, the court would almost certainly remand the case back to the commission for further adjudication. When sitting in review of agency action, courts of appeals review the evidentiary record compiled below and the reasoning the agency employed — as reflected in its orders — to support its decision based on that record. In the case of a serial 2-2 split, no orders would issue and such a review would be impossible. Remand would appear to be the court’s only option.”
FERC Supports $10M Threshold on Merger Approvals
Danly told the committee FERC supports two other bills that would modify FPA Section 203 to set a minimum value threshold of $10 million for mergers of jurisdictional facilities subject to commission approval (H.R. 1109 and S. 1860).
The change would align this provision of the FPA, which currently has a $50,000 threshold, with other sections of the act that already set $10 million as the trigger, he said.
It would also “ease the regulatory burden on industry without impeding the commission’s regulatory responsibilities,” Danly said. “Transactions below the proposed threshold are unlikely to impose a significant negative impact on competition or the rates of utility customers.”
He said the commission has other tools to address market power concerns that could arise from mergers. “For example, if an entity with market-based rates obtained the opportunity to exercise market power as a result of such transactions, the commission could limit or eliminate its ability to engage in transactions at market-based rates. Additionally, the commission has a range of market power mitigation measures that limit market power within the organized wholesale electric markets. Finally, if the exercise of market power involves market manipulation or violation of a commission rule, regulation, order or tariff provision, the commission can bring an enforcement action.”
While MISO is no closer to establishing its version of what constitutes grid “resilience,” the RTO last week said it stands ready to study certain ancillary services to help the U.S. Department of Energy develop its understanding of a concept that is getting increasing industry play through Secretary Rick Perry’s efforts.
“It’s a term I hadn’t heard before,” MISO Director of Market Engineering Kim Sperry said at an Oct. 5 Reliability Subcommittee meeting.
Sperry said that when baseload generators were built, industry officials could not have predicted that natural gas prices would drop so low and that wind and other renewables would receive such heavy investment. From MISO’s perspective, the recent DOE grid study focuses particularly on “premature retirements,” she said. (See Perry Grid Study Seeks to Aid Coal, Nuclear Generation.)
In response to the report, MISO is willing to embark on new studies focusing on frequency control, ramping, voltage support, inertia and inertial response — all to better identify the features of a “resilient” generator, Sperry said.
“There is going to be opportunities for more research, and MISO is willing to assist in that research,” she said.
RSC Chair Tony Jankowski said the subcommittee and MISO should spend more time defining resiliency before attempting to study its aspects.
“We need to make sure when they say ‘resiliency’ that we understand what is meant,” Jankowski said, referring to the Energy Department. “If not, we’ll have to pay for a coal pile or a fuel rod, and that isn’t the end-all of resiliency.”
Gabel Associates attorney Travis Stewart echoed Jankowski’s thoughts. “As we’re walking down the pathway of defining this concept, could we also spend time differentiating between resilience and reliability? While it appears that they’re intrinsically linked items, they’re also distinct,” he said.
“Lights are on today — that’s reliable, but it doesn’t mean it’s resilient,” Jankowski added.
Sperry took down all points to include in future discussions on MISO’s exploration of the topic.
Patrick Clarey, FERC‘s liaison to MISO, said stakeholders have until Oct. 23 to comment on Perry’s Notice of Proposed Rulemaking, which asks FERC to ensure that generators with 90 days of on-site fuel supply receive “full recovery” of their costs (RM18-1). (See FERC’s Independence to be Tested by DOE NOPR.)
Some MISO stakeholders said the proposed rulemaking sounded like a measure to guarantee returns for some independent power producers.
Clarey declined to further explain the NOPR, instead saying he would let it “speak for itself.”
“I’m not going to speculate on what’s behind it. I will say it is unusual. It’s only happened a handful of times,” he said.
AUSTIN, Texas — The Gulf Coast Power Association’s 32nd Annual Fall Conference last week attracted several hundred attendees to the Texas state capital. A panel of CEOs discussed their reactions to the U.S. Department of Energy’s recent Notice of Proposed Rulemaking to FERC, while other panels covered ERCOT market reforms, federal policy issues, industry changes affecting transmission and distribution companies, and the future of the state’s energy markets
Likening himself to the annoying brother “in possibly the industry’s most dysfunctional family,” NRG Energy Director of Regulatory Affairs Bill Barnes explained his company’s push for ERCOT market reforms and the inclusion of marginal losses in LMPs.
Barnes participated in a lively panel discussion on marginal loss pricing, regional reserves and real-time co-optimization, where some attendees likened him to the “outnumbered” man on Fox News’ show by the same name.
But Barnes was happy to discuss recommendations made in a report commissioned by NRG and Calpine entitled “Priorities for the Evolution of an Energy-Only Electricity Market Design in ERCOT.” The report, written by Harvard University’s William Hogan and FTI Consulting’s Susan Pope, was the centerpiece of an August workshop at the Public Utility Commission of Texas. A second workshop is scheduled for Oct. 13. (See ERCOT, Regulators Discuss Need for Pricing Rule Changes.)
“Everything that [the report recommends] is in the spirit of maintaining a sustainable energy-only market,” Barnes said. “You structure the market based on competitive principles, and let the market decide who the winners and losers are. We’re not scrapping what we currently have, or throwing the whole thing out and starting over. But if we’re going to be committed to an energy-only market design, you can’t ignore some clear design deficiencies.”
Barnes said the study’s proposed changes are “all about pricing integrity” and must be “price-scarcity appropriate.”
“We have to have the right price signals to reflect proper supply-and-demand decisions, [and] consumption and production decisions systemwide,” he said. “Pricing integrity is what I would consider the first pillar of key energy-only market design.”
The second pillar is marginal pricing, Barnes said.
“Certainty [in ERCOT] is based on marginal-cost pricing principles,” he said. That … just doesn’t work for congestion. There are too many physical properties that affect the value of electricity from one location to another. A megawatt of electricity that is injected 100 miles away from a load has a different value than a megawatt that is injected closer to load. That is an undebatable, economic principle. Why would we not have the locational marginal prices reflect that?”
“That’s a lot to respond to,” said Thompson & Knight’s Katie Coleman, speaking for Texas Industrial Electric Consumers (TIEC), which represents the state’s 50 largest electricity consumers. “Probably the most offensive aspect of the priorities for the energy-only market paper is the locational aspect. You want to send scarcity pricing signals to encourage new investment in ERCOT. Industrials have been very supportive of sending appropriate scarcity-pricing signals. … What we don’t think is appropriate is creating sustained high prices in one area of the state [such as that created by Houston congestion], irrespective of what’s going on statewide.
“That’s concerning to us because from a resource-adequacy standpoint … the minute you get a new transmission line, you’ve just exacerbated your oversupply capacity for the rest of the state, and you’re also suppressing price signals in that area,” Coleman said.
She said TIEC’s other concern is that locational prices won’t result in “very significant” construction of new generation. “Generators understand how to build just to the point where the pricing is maintained. They’re never going to build to the point where pricing collapses, right? That’s sort of self-defeating.”
Amanda Frazier, Vistra Energy’s vice president of regulatory policy, doubled down on the Hogan-Pope paper’s focus on locational losses. She noted that losses only account for about 2.5% of the total LMP cost that loads pay on a load-ratio share.
“Ask yourself, why is NRG clamoring for marginal losses to reduce prices to consumers, create more efficiencies in the market and help the poor consumers who are overpaying for transmission losses? Consumers aren’t clamoring for that,” she said.
Any savings would come “at an incredible expense to generators who don’t have the ability to change their siting decision,” Frazier said, referring to wind farms.
“It’s not just a renewable issue,” she added. “All you’re going to do is penalize those generators for taking advantage of the resources in the state and providing low-cost power to Texans. It just doesn’t make sense to us. We think the fact it’s more economic and efficient is not enough.”
GCPA attendees disagreed, voting 77% in favor of implementing marginal losses in an online poll at the conference.
The Wind Coalition’s Jean Ryall focused on subsidies and their effect on free markets. “One person’s subsidy is another person’s tax incentive, so where does that stop?” she asked, suggesting attendees visit stopthesubsidies.com and sign a pledge to stop the incentives.
“Nearly every type of generation on the ground today in ERCOT has been built with tax incentives or subsidies of some kind,” Ryall said. “It was sited and built, based on the current rules of the market. It’s not like we can change the rules and everybody rush out, pack up your iron and move it to the center of the load in Houston.”
CEO Pans Proposal
Vistra CEO Curt Morgan cautioned against the market reforms being considered, saying the nodal market is working, but that it is “fundamentally overbuilt.” He noted 21 GW of new generation has been built since 2011, the first full year of nodal operations.
“The proposals designed to raise prices inside a load pocket, when the market has sufficient generation, seem wrong-headed,” he said, referring to congestion issues near Houston. “That is a temporary position that will be resolved with transmission buildout.”
Indeed, ERCOT’s $590 million Houston Import Project is designed to address the congestion in and around Houston. Morgan said Vistra thinks the NRG-Calpine proposal is a one-sided solution.
“The proposal helps a few generators in Houston and increases expenses to others in the market,” he said. “It would threaten indispensable generation outside the Houston zone and perpetuates high prices in the Houston zone. It does nothing for renewables and sends the wrong message to those already invested in the current market structure.”
Morgan agreed that subsidized renewable energy is creating price pressure in ERCOT. He suggested an adder be used for real-time pricing when thermal units are needed to serve load but do not set the price.
“Low prices are great when the result of market fundamentals, but distorted when they’re not,” he said. “They’re happening even when traditional generation is needed to serve load. That ignores the real cost those units incur to stay online and serve load. Those resources are not receiving revenues needed to cover the short-term marginal cost.”
Legal Experts: Environmental Rollback no Sure Thing
A panel of legal and regulatory experts agreed that the Trump administration will work to roll back environmental regulations, but it remains to be seen how far those efforts will go.
“It is too soon to predict what the Obama legacy on environmental issues will look like,” said Kathleen Magruder, vice president of U.S. regulatory affairs for BP Energy. “On the one hand, several courts — including the Supreme Court — are reviewing Obama-era regulations, such as the Clean Power Plan. On the other hand, we have a number of states and cities saying they plan to adhere to the goals of the Paris Agreement, even if the United States does withdraw. It will take some time to see how this all lands.”
“Whatever the legal challenge, however they turn out, I think the Obama legacy will have a lasting impact,” said Chris Jones, a partner with Troutman Sanders. “The changes to the fleet nationwide are irreversible. If you have a new federal dictate that coal plants are reliable and resilient … how far does that go? Will investors feel comfortable putting capacity in these coal plants, based on that rule?”
Asked by panel moderator Jimmy Glotfelty, with Clean Line Energy Partners, whether a coal pile is the only way to have a resilient grid, Jones referred to problems caused by last winter’s so-called “polar vortex,” saying: “You need a diverse fleet to manage different challenges. I don’t care how much coal you have on site, when it’s frozen, it ain’t no good.”
Marquez: PUC Relies on Transmission Policies
Texas PUC Commissioner Brandy Marty Marquez sat down with the commission’s director of wholesale market policy, Julia Harvey, for an informal discussion of issues facing the state’s regulators.
Marquez told Harvey the commission may be over-reliant on transmission policy “because it’s the one aspect of the market we can control.”
“We have a really interesting market here in Texas,” Marquez said. “We want it to be free, but boy, the lights better stay on. That’s a tricky balance.”
Asked by an audience member what generation owners should do with their older, out-of-the-market plants, Marquez said that’s a decision market participants need to make.
“It can be argued one of the challenges we have in Texas is that we have too much power,” she said. “Everyone’s waiting for that shoe to drop. If it were me, I’d probably want to hang on for as long as possible. We hear from [market participants] we’re not seeing scarcity pricing, but when there’s not a lot of scarcity, there’s not a lot of scarcity problems. That’s not a bad problem to have, because power is cheap.”
Advanced Technologies: A Boon or a Challenge?
Wires company representatives discussed their learning experiences with advanced technologies such as smart meters, distributed energy resources and microgrids, and the challenges they pose.
“It’s forced us to be more thoughtful about how we’re stepping into the future,” said CPS Energy’s Rudy Garza, vice president of distribution services and operations. “We’re still trying to figure out how we want to position ourselves.”
With its New Energy Economy program, CPS is partnering with renewable developers and businesses that “share [its] vision for clean energy, innovation and energy efficiency.” Garza said the utility has deployed 85% of its smart meters to residential customers.
“I don’t think there’s any utility out there that has figured it out. Those that are out there playing and trying to understand these technologies will get there a little quicker,” Garza said. “Now we have all this information we didn’t have before. We have to match [the data] to know where outages are happening or know where they might happen. That’s the future. That helps save dollars, before the trucks start to roll or the trouble calls start to come.”
Bob Bradish, American Electric Power vice president of grid development, said his company has installed one battery storage system in Texas, with the understanding from the PUC “that this was a one-and-done type of deal.”
“When you look at those technologies as an alternative to transmission solutions, there is a difference to what they bring to table,” Bradish said. “Transmission will bring additional capacity, it will bring permanence. It can be there for 90 to 100 years. How long is a battery, or a DER, going to be there? What is its reliability going to look like? You’re going to have to get comfortable with that.”
“Batteries are coming faster than maybe mankind can appreciate,” CenterPoint Energy’s Kenny Mercado said. “As that demand grows, we’re going to be learning about its behavior. With our regulated responsibility, we have to think about [batteries] differently. We have to be more insightful about their functionality, their capability. Like the advanced meter, it’s owned by the utility, but its [data] is used by the market. The market wins.”
Mercado noted the advanced technologies do have their drawbacks, a point that was driven home when Hurricane Harvey submerged much of CenterPoint’s system.
“When they’re submerged in water, they don’t work. They won’t tell you if they’re drowning,” he said.
ARLINGTON, Va. — Newly appointed FERC Commissioner Robert Powelson, a former Pennsylvania Public Utility Commissioner, seemed at ease last week as he addressed the annual meeting of the Organization of PJM States Inc. He cracked jokes and shared memories with fellow regulators, RTO officials and stakeholders.
But when the subject turned to the Department of Energy’s recent proposal that FERC promulgate rules to support generators that can stockpile 90 days of fuel in deregulated states, he became emphatic.
“I will not support anything that undoes the value of the market,” he said Wednesday. “I remind everybody in this room, we are an independent agency. … FERC does not do politics.
“I give Energy Secretary [Rick] Perry credit. He’s trying to be thoughtful in the approach, but there’s many different approaches to how we can tackle this issue. I did not sign up for blowing up the markets,” he said to a round of applause. “We will not destroy the marketplace.”
The comments were in response to concerns that DOE’s Notice of Proposed Rulemaking would drive large subsidies to nuclear and coal units that would make competition untenable. (See Consumer Advocates Slam Perry NOPR, RTOs, FERC.)
Commissioner Cheryl LaFleur seconded Powelson’s vow “not to destroy” the markets, tweeting, “Great message!”
Perry Defends NOPR
On Friday, Perry defended the NOPR, saying it was not an order to the independent commission, but an effort to begin a “conversation” on the loss of baseload generation.
“I think it’s really important for people to understand, in general terms, there is no free market in the energy industry,” he told a meeting of the group Veterans for Energy, according to an account in The Hill. “And anybody that gets up and says that is lying — is not, with all due respect, educated as to what the reality of the market is.”
Perry said he was attempting to reverse the policies of the Obama administration, which he said, “had their thumb on the scale” to help out renewables to the “detriment … of reliable, baseload industries that are really important for the future security of this country.”
The commission last week issued a notice inviting comments on the NOPR (RM18-1). Comments are due by Oct. 23, with reply comments due Nov. 7.
Other Controversies
In his speech to OPSI, Powelson also referenced several other controversial issues before the commission, without explicitly identifying them.
“Dallas Winslow, do you have a question for me?” he asked the chairman of the Delaware Public Service Commission.
Delaware has been fighting use of the solution-based distribution factor (DFAX) cost-allocation method for Artificial Island upgrades, PJM’s first competitively bid project under FERC Order 1000. The original allocation left the Delmarva Peninsula on the hook for much of the project’s $280 million cost, but PJM has proposed alternative allocations that would shift much of the bill to New Jersey and Pennsylvania. (See PJM: AI Costs Would Shift to NJ, PA Under New Allocations.)
Winslow laughed but did not ask a question.
Powelson also hinted at action on natural gas pipelines, saying, “We love infrastructure, so we’re going to work on infrastructure — New Jersey included.”
The proposed 120-mile PennEast Pipeline — which would transport Marcellus Shale gas from northeast Pennsylvania to central New Jersey — is facing opposition from landowners in both states. In April, FERC staff filed their environmental impact statement on the project, concluding that it would have “less than significant” environmental effects (CP15-558).
MISO last week said it expects to have plenty of reserve capacity to cover upcoming winter operations, even as it announced a review of an emergency declaration made on the first day of fall when a heat wave pushed reserves to their acceptable limits.
The RTO’s preliminary forecast predicts a 28.3 to 37.3% reserve margin this winter, with about 142 GW of capacity on hand to meet an anticipated peak load of 103.4 GW, according to Rob Benbow, MISO senior director of systemwide operations.
“I would say this is a little colder-than-normal winter, but not by much. This is pretty typical of the last few years,” Benbow said during an Oct. 5 Reliability Subcommittee meeting.
MISO’s all-time winter peak of 109.3 GW occurred Jan. 6, 2014, during the so-called “polar vortex.”
Final values for forecasted winter capacity will be presented Nov. 6 at a MISO Winter Readiness Workshop.
| MISO
Benbow reminded stakeholders that MISO’s gas usage profile-sharing program will begin in December. Under the pilot program aimed at improving gas-electric coordination, the RTO will share hourly day-ahead gas usage profiles with a trio of selected gas system operators. (See FERC Approves MISO Plan to Share Generator Gas Data.)
Mark Thomas, electric-gas operations coordinator, said MISO is collecting data for its fourth annual gas-fired generation winter fuel survey, which focuses on generators’ winter preparedness efforts. Thomas said 87% of MISO’s gas-fired capacity participated in last year’s survey.
September Emergency
But even as MISO transitions to colder weather, it plans to review emergency operations spurred by an unexpected late summer/early fall heat wave.
MISO staff will offer a more detailed report on a late September maximum generation event during its Oct. 12 Market Subcommittee meeting, Benbow said.
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The event began to unfold 11 a.m. on Sept. 21 when the RTO initiated conservative operations measures in response to average temperatures reaching nearly 90 F, which produced a peak load approaching 109 GW. Peak load hit 114.7 GW the following day when temperatures climbed to 92 F, prompting MISO to declare a maximum generation event between 2 p.m. and 6:15 p.m. ET. The RTO declared another emergency warning Sept. 23 and finally lifted conservative operations at 8 p.m. on Sept. 26.
Benbow said a mixture of record temperatures, high load, and seasonal and forced generation outages contributed to the “challenging conditions.”
“Typical load this time of year might be 80 GW and even lower on the weekend,” Benbow said. “This heat dome was really caused by hurricanes stalling the [weather] system in our footprint.”
Benbow said the planning model did not forecast such extreme temperatures, and MISO staff are reviewing the RTO’s actions ― along with the outages ― leading up to the event. MISO has considered a possible expanded role in outage coordination since its Independent Market Monitor earlier this year recommended the RTO have a greater say in approving outages to reduced costs and instances of emergency situations. (See MISO in Harmony with IMM State of the Market Report.)
Some stakeholders last month also voiced support for more sophisticated outage planning between generators and transmission owners.
“I don’t believe that anyone had to shed load at any time. … Congratulations for keeping it together,” Indianapolis Power and Light’s Lin Franks said of MISO’s latest emergency declaration.
Benbow confirmed that no load shedding occurred during the five-day event.
