FERC on Tuesday cast shade on an attempt by environmentalists and solar proponents to block NorthWestern Energy from cutting the prices for solar qualifying facilities in Montana.
But the commission’s procedural ruling didn’t address the merits of complaints that Montana regulators are attempting to discourage solar developers — a claim it will address in a separate docket.
The complaints were filed in response to the Montana Public Service Commission’s 3-2 ruling in June to suspend NorthWestern’s tariff for solar QFs larger than 100 kW under the Public Utility Regulatory Policies Act pending an updated rate review.
The commission acted after the utility sought emergency action, saying it feared a “flood” of QF filings because the rate — set in 2013 at $53.14/MWh (off-peak) and $92.37/MWh (on-peak) — was now 35% above its avoided costs (Docket No. D2016.5.39).
The change put about 130 MW of planned solar facilities in Montana in limbo. While the commission said solar projects could negotiate rates with NorthWestern while the review is pending, developers say they have no leverage and would be forced to accept the utility’s avoided cost figure.
FERC dismissed a complaint by the Vote Solar Initiative and the Montana Environmental Information Center, saying the PSC is not subject to the general complaint jurisdiction under Section 306 of the Federal Power Act and that the plaintiffs had no standing to file a complaint seeking PURPA enforcement (EL16-117).
“The Montana commission is not an entity that, for purposes of enforcement, [FERC] may, by order, require to take or not take particular actions,” FERC said. “Additionally, Vote Solar is neither a QF nor an electric utility, and as such is not authorized to file a petition for enforcement pursuant to Section 210(h) of PURPA.”
Jenny Harbine, an attorney with Earthjustice, which represented the complainants, called the decision disappointing. “It limits the ability for advocacy groups — including consumer advocates as well as clean energy advocates — to raise issues before FERC that are critical to the future of clean energy development and consumer choice,” she said.
Second Case Pending
But Harbine said the groups would participate as intervenors in a PURPA enforcement petition filed last month by FLS Energy, a North Carolina-based solar developer.
FLS said the Montana PSC’s actions “precluded [it] from continuing with the development of 14 advanced-stage solar QFs” and faces the loss of more than $750,000 that it has invested (EL17-5). The company said the order eliminated NorthWestern’s only PURPA tariff allowing for fixed, long-term payments for solar, which it called an “essential element of a financeable” power purchase agreement.
FLS Solar’s Fairmont Solar Farm in Fairmont, NC | FLS Solar
The developer said the commission’s order — which followed a hearing in which only the utility gave testimony and was not subjected to cross examination — is intended to discourage the development of small solar QFs.
“The Montana PSC performed a back-of-the-envelope calculation and suspended the rates based on an initial conclusion (untested by discovery or opposing testimony),” FLS said.
It said the commissioners’ “hostility towards the goals of PURPA is evident from statements made by a majority of the commissioners” at hearings in the NorthWestern case and in an editorial by Commissioner Brad Johnson, who accused solar developers of using PURPA to finance projects, “cherry picking the states with the highest government-assured rate to do business in.”
“Simply put, it was well past time to put the rate on pause and update it again,” Johnson said, noting that the Montana Consumer Counsel supported NorthWestern’s request for the suspension.
Dissent
In his dissent, Commissioner Travis Kavulla accused his colleagues of flouting the commission’s procedures and precedents.
“The intervention deadline to the proceeding occurred only after a hearing on NorthWestern’s motion was held. Certain parties — or rather, quasi-parties, since the intervention deadline had not arrived — participated in that hearing, but the developers of the projects that would be compensated under the rate schedule did not,” wrote Kavulla, the current president of the National Association of Regulatory Utility Commissioners. “The hearing commenced with the purpose of taking ‘argument’ on NorthWestern’s motion. Then, as a surprise to those in attendance, counsel for NorthWestern alerted the commission that it also wished to offer evidence. No other quasi-party presented evidence at this hearing.”
On Wednesday, FERC granted Montana regulators’ request for more time to respond to the petition, extending the deadline until Nov. 17.
Other States
Utilities in other states also are trying to limit PURPA payouts. Idaho, for instance, has limited such solar QF contracts to two years only in a 2015 ruling. Duke Energy is contemplating a similar move against solar QF rates in North Carolina, according to Vote Solar.
American Electric Power CEO Nick Akins hardly sounded like someone whose company had just taken a $2.3 billion impairment Tuesday, telling investors and analysts he is “very happy with the strategic process” and that “conditions are in place that are conducive to us achieving our objectives.”
Akins’ comments came as he led a panel of AEP executives briefing investors and analysts in New York following the company’s third-quarter earnings release. With the one-time charge, AEP posted a loss of $765.8 million (-$1.56/share) for the quarter, compared with a profit of $518.3 million ($1.06/share) for 2015’s third quarter. Sales were up from $4.4 billion to $4.7 billion, partly because of a warm summer.
“The new story of AEP is one of higher growth, higher dividends, more regulation and more certainty,” Akins said. “When you stop chasing the wrong things, you give the right things the chance to catch you.”
Lower Rio Grande Valley Transmission Project | AEP
The impairment reflects AEP’s ownership share of 2,684 MW of competitive generation in Ohio, including its Cardinal, Conesville, Stuart and Zimmer plants. It also includes the competitive portion of the coal-fired Oklaunion Plant in West Texas, the Desert Sky and Trent Mesa wind farms, also in West Texas, and some coal-related properties.
Akins said the company will spend $17.3 billion in capital investments through 2019 — $9 billion on transmission — an increase of $4.3 billion from plans laid out last year through 2018. The company owns the largest transmission system in the U.S., with 40,000 miles of lines and more 765-kV extra-high voltage than all other transmission systems combined.
“We’re focusing the proceeds on the [transmission business] we find attractive,” said Akins, who noted AEP already accounts for 14% of the country’s transmission investment. “We’re able to invest in transmission in an order of magnitude not many others have. If you’re looking for a transmission company, AEP is certainly that. We’re well-positioned as a regulatory business.”
The company also plans to increase its renewables through long-term power purchase agreements. AEP expects to add 5,400 MW of wind energy and 3,400 MW of solar power through 2033.
| AEP
Investors didn’t respond positively to the news. AEP shares closed Wednesday at $62.61/share, down 77 cents (-1.21%) on the day.
AEP’s embrace of regulation also allows it to escape the problems it faces in Ohio’s competitive-generation market. Many of the company’s coal plants date back to the 1970s and earlier, making them underperformers against other power units. Coal resources accounted for 71% of AEP’s generation in 2005, but that figure is projected to drop to 47% next year.
“Fortunately, AEP’s balance sheet can withstand this impairment,” CFO Brian Tierney said. “Combined with other sales of generating assets, it puts the Ohio generation debacle behind us. We also have wires companies in the states with very attractive returns.”
Akins said AEP would continue working with legislators to restructure the Ohio market.
Both AEP and FirstEnergy attempted to get relief from the Public Utilities Commission of Ohio with what amounted to a subsidy request for their competitive generation. While what opponents called a “bailout” was approved by PUCO, FERC effectively scotched the deals, saying they needed to undergo a more stringent review.
AEP decided to work to get favorable reregulation legislation approved.
But FirstEnergy — which reported a $1.1 billion loss in the second quarter, much of it related to the closure of five coal-fired units — filed a modified request with PUCO seeking a $558 million-a-year rate stability rider for eight years.
In October, PUCO voted instead to give the company $204 million a year for only three years. FirstEnergy has until Nov. 11 to file for a rehearing on the order, which it called “disappointing.” (See PUCO Rejects FirstEnergy’s $558M Rider, OKs $132.5M.)
The Seattle City Council authorized Seattle City Light to perform “a detailed analysis of costs, benefits and potential risks” of joining the Western Energy Imbalance Market (EIM) to inform the council’s decision on whether to approve the move.
González | Seattle.gov
The unanimous Oct. 31 vote came three weeks after council members Lorena González and Mike O’Brien voiced concern about the upfront costs of exploring membership, leading the council to defer a vote on entering an “exploratory phase” with the CAISO-run EIM. González had expressed concern that authorizing a study created an expectation that “we will invest and carry forward” with the market. (See EBA Speakers Ponder a Western RTO.) With its vote, the council is asking City Light to flesh out the findings of an EIM benefits study performed by consulting firm E3 that showed the utility could earn an additional $4 million to $23 million in yearly revenues from the market.
“City Light’s own evaluation of the E3 study identified a number of deficiencies that call the study’s revenue estimates into question,” González told RTO Insider after the meeting. “Furthermore, the cost estimates were based on those experienced by other utilities entering the market. I think it prudent for City Light to do its own assessment of the costs it is likely to incur.”
González said the council’s ordinance provides the utility with “the time and spending authority necessary to conduct a thorough gap analysis.”
“The council’s vote gives us the opportunity to further investigate participation in the EIM,” said Scott Thomsen, City Light’s senior strategic advisor in communications and public affairs. “This will involve more due diligence to get more details on the areas outlined in the [E3] report.”
Introduced in September, the original ordinance would have greenlit City Light’s membership in the EIM, but it was scaled back ahead of the council’s Oct. 10 meeting to require more analysis before a final decision.
As approved by the council, the ordinance includes a González-sponsored amendment requiring the city-owned utility to report its findings to the council’s Energy & Environment Committee by April 10, 2017.
“This amendment will allow the council to receive and review the results of this analysis within a reasonable timeframe and grant City Light sufficient time to conduct the analysis that is required,” González said.
She said that there are “significant risks that accompany [City Light’s] varying revenue projections,” which needed adequate time for the council to evaluate before the utility could enter “what would be a new line of business.”
With a generating portfolio heavy in hydroelectric resources, City Light stands to benefit from the EIM as an exporter of the flexible ramping capability needed to smooth out intermittent renewables.
The utility’s revenue estimates from the market are dependent in part on water supply conditions. Implementation is projected to ring in at about $8.8 million, while operations costs could run at around $2.8 million annually.
The Pacific Northwest’s ability to export power from surplus hydro can vary significantly based on precipitation.
“While there is a range in the estimated benefits, it is commensurate with the uncertainty in our current hydroelectric generation portfolio because of variable weather and water conditions,” City Light said in a summary and fiscal note to the council.
WILMINGTON, Del. — Still unable to reach consensus on the specifics of what to study, PJM members balked again last week at a request from a coalition of demand-side stakeholders to revisit the Capacity Performance construct.
By the end of the lengthy discussion at the Markets and Reliability Committee meeting Thursday, American Municipal Power’s Ed Tatum, who has represented the coalition in committee discussions, admitted he was at his wit’s end.
“I’m getting ready to curl up on the floor into a ball and roll around,” he said.
But even without the coalition’s initiative, stakeholders had plenty of capacity-related issues to discuss at last week’s MRC meeting, debating underperformance rules, seasonal capacity and pseudo-ties. They also began considering another look at ways to limit capacity auction arbitrage.
Tatum’s coalition continued to struggle with the scope of its proposed issue charge. The current issue charge suggests it is states’ public-policy actions that might upset the delicately balanced CP market. (See Review of PJM Capacity Market Put on Hold.)
However, John Farber of the Delaware Public Service Commission urged that the issue not be framed that way. “The existential threat is not with states, but possibly [to] customers who have to pay the eventual costs,” he said.
Some stakeholders pushed for adding more topics to those listed, while others said they opposed broadening the scope. Susan Bruce, an attorney who represents the PJM Industrial Customer Coalition, said the proposal needs to be broad enough to cover more than just capacity market impacts but narrow to the extent that PJMICC isn’t interested in talking about alternatives to RPM.
“I appreciate the dilemma,” she said.
EnerNOC’s Katie Guerry requested that the proposal’s language be more accommodating toward change rather than defensive. “Why don’t we set up a more productive process where we can work toward solutions?” she asked.
Both Bruce and Exelon’s Jason Barker said they would attempt to edit the proposal into something they could support, but “I’m not sure how to address that or to modify the current statement,” Barker conceded.
“What I’m hearing today is, ‘let’s re-broaden the discussion, at least to start.’ … I don’t understand what people want. Do they want to have a broad discussion and narrow it?” asked Jeff Whitehead, whose Direct Energy is a sponsor of the proposal. “It’s a pretty big ask of this group to have us find the right scope of this discussion before we start the work. One of the main issues here is defining what are these public policies that impact the wholesale market.”
Tatum said his goal is to find the CP version of the Serenity Prayer: a construct that can change what’s within its authority to change, accept what it can’t change and know the difference.
The lack of consensus caused frustration among the proposal’s sponsors. PJM’s Dave Anders, the committee’s secretary, suggested a separate informational meeting on the topic, but none of the sponsors actively supported the idea.
“I personally don’t see a need for an informational meeting,” said Steve Lieberman of Old Dominion Electric Cooperative. He said it would be “surprising” if there were new perspectives on the proposal than the ones that had already spoken up.
“Frankly, if we don’t want to talk about this, let’s stop talking about it,” Whitehead said.
Carl Johnson of the PJM Public Power Coalition, which also sponsored the proposal, reminded everyone that ignoring the issue wouldn’t make it go away. “If we don’t have this conversation, it’s going to happen without us,” he said.
Farber, who had registered the first concern with the proposal, nonetheless expressed support for it, saying the committee was “letting the perfect be the enemy of the good” and that he didn’t want to see it succumb to “paralysis by analysis.”
Stakeholders acknowledged that the current proposal was “substantially different” from past iterations. Tatum said he needed to confer with the coalition before deciding the next step.
Stakeholders not Quite Done with Seasonal Capacity
Stakeholders balked at PJM’s suggestion to sunset the Seasonal Capacity Resources Senior Task Force, saying there is more work to be done despite the RTO’s announcement Oct. 19 that its Board of Managers will file a “facilitated aggregation” proposal with FERC. (See PJM to Seek FERC OK for Seasonal Capacity Proposal.)
While stakeholders praised the job PJM’s Scott Baker has done steering the task force, they derided the RTO’s handling of the issue. PJM’s proposal was one of five voted on by the task force in September, but it received only 32% support.
CPower’s Bruce Campbell said he was “very disappointed in PJM’s actions in … pre-empting a viable discussion.” Guerry explained that the reason some stakeholders were upset is because the RTO’s action was contrary to stakeholders’ “expectation of the rules and how the process was supposed to play out.”
Barker, however, commended PJM’s leadership on the issue. “Let’s sunset it and move on,” he said.
Bruce suggested a “quick hibernation,” as when it announced the planned filing, PJM had noted that there were additional pieces of the structure to work out.
The indignation with PJM transitioned to the next discussion, in which Whitehead presented to the committee his proposal from the task force. His “substantive but simple” proposal would allow base capacity to participate in the auction for another year to allow enough time to fully consider the topic, he said.
“It’s our view that the board decision unfortunately wasn’t informed by some of these critical pieces of the stakeholder process,” he said.
Seasonal resource owners were only able to address the differences between forecasted peak loads in summer and winter “at kind of a cursory level,” he said. PJM has experienced colder periods than the 2014 polar vortex on which much of the capacity decision-making is based, he said. Its top winter peak-load day occurred in February 2015.
“I’m not sure it continues to make sense to continue to make reliability procurement decisions based on one year’s experience,” he said. “It doesn’t make a lot of sense that we would buy capacity to run somebody’s air conditioner in January.”
While Farber said the additional transition year was “critical,” Howard Haas of Monitoring Analytics, PJM’s Independent Market Monitor, objected to the proposed extension. Barker said the polar vortex highlighted issues that further investigation of a new seasonal-capacity construct might not address. “We need to be mindful of the nature of the winter constraints that we saw,” he said.
“I’m not disputing that this needs to be studied. That’s actually what I’m asking,” Whitehead said.
Later in the meeting, James Wilson of Wilson Energy Economics proposed a problem statement and issue charge to review PJM’s procedures for evaluating winter-capacity needs. “I don’t think it calls for a lot of changes, mainly just a few updates,” Wilson said. “It was really never much of a topic. … Winter capacity matters, we’ve learned.”
PJM’s Stu Bresler indicated that the FERC filing will likely occur prior to November’s MRC meeting. Because the task force sunset, the base capacity extension and the winter resource analysis proposals were presented as first reads, none will be voted on until that meeting — presumably after PJM has made its filing.
Underperformance Changes Would Weaken CP, Says PJM, Monitor
Asked to develop proposals for two CP issues, the Underperformance Risk Management Senior Task Force was only able to find consensus to endorse one.
The task force was charged with analyzing PJM’s pseudo-ties and flowgates to determine the impacts of integrating external CP resources. Of the four options proposed, the highest approval that any package reached was 38%. However, 78% preferred a change over the status quo.
PJM’s Rebecca Carroll said feedback is being collected from stakeholders through a new nonbinding poll, the results of which will be available this week. The group expects to review results and determine next steps at its Nov. 10 meeting.
The task force was also assigned to review underperformance rules. The endorsed package — which received nearly 55% approval — will be put up for a sector-weighted vote at the November MRC.
It would make several changes to Manual 18: PJM Capacity Market and Attachment DD of the Tariff including:
Basing the nonperformance penalty on the highest Base Residual Auction clearing price in any locational deliverability area instead of net cost of new entry;
Allowing underperforming units to find replacement megawatts from over-performing units in the same performance assessment hour area. Under current rules, such transfers are allowed only within the same capacity account with PJM;
Adding a new mechanism for transferring the replacement megawatts; and
Adjusting the stop-loss provision from annual to monthly.
Howard Haas of Monitoring Analytics, PJM’s Independent Market Monitor, was quick to register his objection to the proposal. “We think it’s going to weaken the product to the point where it no longer incents performance,” he said.
Others agreed, including Barker, PJM Public Power Coalition’s Johnson and the RTO itself.
“PJM cannot find itself in a position to support this package” Bresler said, explaining that it’s “too far down” the slope of not requiring CP units to perform at the exact time they’re needed, which the existing construct was specifically designed to do.
The proposal did have some champions, though, including Talen Energy’s Tom Hyzinski and John Horstmann of the Dayton Power and Light Company. Horstmann said adding a monthly stop-loss provides protections for the supplier and ultimately reliability because a monthly limit would provide generators with incentives to perform throughout the delivery year. Additionally, basing penalties on net CONE creates inconsistent penalty rates across differing LDAs, he said, and disproportionately penalizes the lowest-priced capacity with the highest percentage loss of revenue for a PAH penalty. Hyzinski said there are many other incentives to perform that keep the proposed changes from diluting CP.
Later in the meeting, Barry Trayers of CitiGroup Energy proposed another Manual 18 revision to eliminate a prohibition on how early a capacity obligation replacement can be made. Trayers’ proposal was followed by a friendly amendment from PJM that refined the language of the proposed rule change. The proposal will be brought back at November’s MRC for a vote. No one voiced any concerns about how the separate replacement changes would integrate.
Buy High, Sell Low?
Stakeholders would consider anew the price differences between the BRA and incremental auctions under a problem statement proposed by Whitehead.
Whitehead said the stark differences between the BRA clearing prices and the lower IA prices raises the potential for abuse. Noting that load is receiving cents on the dollar on excess capacity released by PJM in the later auctions, he proposed investigating whether IA prices yield reasonable and accurate results and revise policies if they don’t.
Citing results from recent auctions, Whitehead highlighted the disparity that creates an incentive to sell during the BRA and buy back during the IA at much lower prices.
Other stakeholders agreed. Calpine’s David “Scarp” Scarpignato said the structural issues between the two auctions “[create] a lot of speculation.”
For all but one delivery year between 2012/13 and 2016/17, the third IA auction clearing price has been a fraction — between 8 and 20% — of the BRA price.
The only time the IA price exceeded the BRA was 2015/16, when PJM did not sell back excess capacity in the IA.
Whitehead also noted that PJM’s excess sales have resulted in much larger reductions in the capacity acquired than in the cost savings to load. “In essence, load gets a lot less reliability in exchange for a negligible reduction in capacity cost,” the problem statement says. “Load should be appropriately compensated for the resulting reliability reduction, in consideration of the fact that, among other benefits, capacity in excess of the PJM’s planning targets can have value in a tail reliability event.”
Because prices in PJM’s Base Residual Auction are much higher than those for Incremental Auctions in which the RTO sells excess capacity, load has recognized little savings for the reliability benefits it has forgone. | PJM
The issue is not a new one. In 2013-14, stakeholders wrestled with ways to eliminate what some called “arbitrage opportunities” between the BRA and IAs. The effort ended in May 2014, after FERC rejected a plan to curb speculation in the auction, saying it created undue barriers to entry. (See PJM Wins on DR, Loses on Arbitrage Fix in Late FERC Rulings.)
The commission ordered a Section 206 proceeding and technical conference to explore the issue further (EL14-48) but did not schedule the conference after PJM asked the commission to defer action while it developed CP.
FERC on Thursday rejected rehearing requests by a generator and a utility workers union on its order accepting the results of ISO-NE’s 10th Forward Capacity Auction (ER16-1041-001).
Dominion Resources challenged the auction results over ISO-NE’s exclusion of a capacity increase at its Providence, R.I., generating plant. The commission had rejected the company’s complaint in a parallel proceeding Oct. 20. “Dominion’s instant rehearing request does not raise any issues that are new to this proceeding or that were not already addressed in the order denying rehearing,” FERC wrote. (See FERC Again Rejects Dominion Bid for ISO-NE Auction Resettlement.)
Brayton Point
The Utility Workers Union of America said the auction should be voided because the slated-for-closure Brayton Point station, whose workers it represents, has been withheld from the past three FCAs. FERC has repeatedly dismissed those complaints. (See FERC Again Rebuffs Brayton Point Union.)
Rehearing Denied on Gas Pipeline Subsidies
Separately, the commission denied a rehearing request by Algonquin Gas Transmission over ratepayer subsidies for the same reason it rejected complaints by Public Service Enterprise Group and NextEra Energy (EL16-93-001).
PSEG and NextEra alleged that the New England states’ effort to expand natural gas capacity with electric ratepayer subsidies was an attempt to suppress power prices. FERC dismissed that complaint on procedural grounds in August, saying the companies’ concerns were “speculative and unsupported.” (See “Access Northeast Complaint Dismissed,” FERC Rejects Capacity Release Exemption for NE Gas Generators.)
Algonquin sought rehearing so the commission would dismiss that case on the merits, saying the procedural dismissal left open the possibility that NextEra and PSEG could “continue their troubling delay tactics.”
FERC demurred, saying the Federal Power Act allows rehearing only for those “aggrieved” by a commission order. “Here, the Aug. 31 order dismissed the complaint, which was the end result advocated by Algonquin,” FERC said.
“The commission is not obligated to reach the merits of a case when it can be decided on procedural grounds. Administrative economy concerns are particularly acute where, as here, the facts are in flux and the record before the commission may be incomplete.”
FERC on Wednesday denied San Diego Gas & Electric’s request for rehearing of an order that limited the amount the utility can be reimbursed if its South Orange County Reliability Enhancement (SOCRE) transmission upgrade project is canceled (EL15-103).
| SDG&E
SDG&E is seeking approval from the California Public Utilities Commission to construct the $400-million project, which involves rebuilding two substations in the cities of San Juan Capistrano and San Clemente and replacing the current single-circuit 138-kV transmission line with a double-circuit 230-kV line.
The project, which was included in CAISO’s 2010-2011 Transmission Plan to address reliability in southern Orange County, has been mired in the PUC’s review process. The utility filed for approval in May 2012; the PUC issued it final environmental impact report in April.
In September 2015, SD&E asked FERC for an abandonment incentive under Order 679, which allows recovery of 100% of all “prudently incurred” costs if the project is canceled for reasons beyond the company’s control.
On March 2, FERC granted the utility’s request, but only for those costs incurred after the date of the order. For the more than $31 million SDG&E spent prior to then, FERC ruled the utility could only recover 50%.
South Orange County Reliability Enhancement project | SDG&E
SDG&E protested, saying the order went against commission precedent. FERC summarily dismissed this claim.
“It is commission policy that a public utility may only recover up to 50% of prudently incurred abandonment costs for costs that are incurred before the date of the order granting the incentives,” FERC said. “While SDG&E refers to this precedent as ‘outlier cases,’ they are in fact the only cases that speak in some way to the issue of retroactive application of an abandonment incentive under Order No. 679.”
FERC’s order came a day before the California PUC delayed a final decision on the project until its Dec. 15 meeting.
CAISO’s Board of Governors voted Thursday to expand the definition of a “load-serving entity” to include the San Francisco Bay Area Rapid Transit District (BART) and other organizations that buy wholesale power to serve their own needs.
CAISO proposed to expand the Tariff definition of a load-serving entity to allow San Francisco’s Bay Area Rapid Transit agency to obtain congestion revenue rights once its transmission contract rights expire. | BART
“This was really sparked by BART rolling off of a [Pacific Gas and Electric] contract and wanting to serve their own load,” Greg Cook, the ISO’s director of market and infrastructure policy, told board members. (See CAISO Issues Revised Proposal to Expand LSE Definition.)
CAISO’s Tariff currently defines LSEs as entities that serve load or sell electricity to end users, which includes utilities, federal power marketing agencies and community choice aggregators. A special Tariff provision was made for the State Water Project (SWP), a California agency that trades in the wholesale market to cover its own energy requirements.
Like the SWP, BART already serves its own load, doing so through transmission contract rights that precede the existence of the ISO. That contract is scheduled to expire at the end of this year, exposing the agency to congestion charges without the ability to acquire an allocation of congestion revenue rights (CRR) available to recognized LSEs.
The definition change would permit entities such as BART to receive a free CRR allocation in the ISO’s annual process, but it will also subject them to resource adequacy requirements.
That second point had prompted worry among stakeholders who thought the original proposal — which would have broadened the definition to include any entity granted the authority to serve its own load — would subject transmission contract holders to capacity requirements.
CAISO responded to that concern by tightening the language to specify that an organization would have to elect to serve its load to be subject to capacity requirements.
“We didn’t want to unintentionally include existing transmission contract rights holders,” Cook said.
HERSHEY, Pa. — One of the hoariest clichés about legislating is that there are two things no one wants to see get made: laws and sausage.
But on Friday, participants in drafting the bill that brought competitive power generation to Pennsylvania reminisced about the experience as enthusiastically as if they were biting into Lebanon bologna.
The people doing the reminiscing were on one of the panels in a two-day celebration of the 1996 Electricity Generation Customer Choice and Competition Act’s 20th anniversary, which made the Keystone State one of the first in the nation to embrace retail choice.
The conference was put on by the consulting firm of John Hanger, one of the architects of the state’s introduction of competition as a member of the Pennsylvania Public Utility Commission.
Joining Hanger on the panel were former state Sen. David Brightbill, who helped craft the law; Sonny Popowsky, Pennsylvania’s long-time consumer advocate, now retired; and former PUC and FERC Commissioner Nora Mead Brownell, who helped implement the law.
Brightbill remembered how Hanger helped lay the groundwork for the law, which had strong support from energy-intensive industrial customers.
Popowsky said one thing that people tried but failed to get into the law was a provision requiring utilities to divest their generation assets or put them in separate companies. That, he said, turned out to be moot, as the utilities chose to do that anyway.
So that all the parties that would be affected by the law could have a say in crafting it, they agreed to press for only what they needed to be in it, not what they wanted to be in it, the panelists recalled. Even so, at the last minute, someone brought up possible amendments, causing great consternation for Hanger because the law had been put together so carefully that he was convinced any changes to it would cause it to fall apart.
Impact
So what’s been the impact of Pennsylvania’s restructuring?
A study funded by the University of Pennsylvania’s Kleinman Center for Energy Policy — and authored by Hanger and Christina Simeone, the center’s director of policy and external affairs — concluded that the law allowed consumers to benefit from the reduced power prices caused by the natural gas boom.
From 1996 to 2014, output from natural gas-fired generation in Pennsylvania grew 26% while output from coal-fired generation dropped 17%.
The report found that the retail price of electricity in Pennsylvania fell from 15% above the national average prior to deregulation to 0.1% below the national average last year.
Had Pennsylvania not changed the law, the report also pointed out, consumers might still be paying power rates based on valuations assigned to power plants by the PUC, rather than rates based on the market cost of generating power. Under that scenario, electricity consumers would have seen much less benefit from low natural gas prices, while coal-fired and nuclear-powered generation plants that were valued decades ago wouldn’t be the drag on their owners’ profits that they are today.
By introducing competition, the law has allowed low natural gas prices to flow through to consumers, Hanger said. “That’s what we wanted to accomplish.”
Although the restructuring law was passed in 1996, most consumers wouldn’t have much incentive to shop for power providers for another 15 years. That was because the utilities agreed to have their distribution subsidiaries cap the rates at which those subsidiaries offered power in exchange for being allowed to recover some of their “stranded costs” — the difference between their generation plants’ book value before deregulation and their market value after. Different utilities had their caps come off at different times, but all were gone by the start of 2011.
Since the rate caps have come off, the electric distribution companies (EDCs) have remained default power providers for customers who don’t want to shop for a generation provider, buying power on the wholesale market and reselling it at no profit to those customers.
Shoppers vs. Default Customers
The report looked at how power customers that shopped for a generation provider did compared to those that continued as default customers. It concluded that retail electricity rates for commercial and industrial customers that shopped for power were generally lower than the same rates for commercial and industrial customers that bought power from their distribution company.
But the report found that the reverse was true for residential customers, with rates for those who shopped for power being higher than the rates for those who bought it from their distribution company.
Bundled bills for residential customers of Duquesne Light, PECO Energy and Penn Power were 16 to 21% lower in 2016 than inflation-adjusted bills for 1996. Ratepayers in some other EDCs saw bills rise as distribution rate increases exceeded generation and transmission savings. Chart shows monthly bill for customer using 500 kWh. | A Case Study of Electric Competition Results in Pennsylvania, Kleinman Center for Energy Policy
Despite that, Popowsky, the former consumer advocate, said that residential consumers have benefited from the law because even the default prices offered by the distribution utilities are the result of competition among generation providers. “One hundred percent [of consumers] are getting competitive generation,” he said.
The study found that residential distribution rates prices for all but one EDC increased faster than inflation from 1996 through 2016, with the increases exceeding generation and transmission savings for some utilities. Distribution rates remain under cost-of-service regulation by the PUC.
Having distribution utilities serve as default power providers for customers that don’t want to shop for a generation provider has proved controversial. There were calls to eliminate having distribution companies serve as default power providers and forcing all electricity customers to shop for generation providers. But the proposals lost favor after the 2014 polar vortex, when many customers who chose competitive suppliers — unaware they were paying spot prices — got socked with huge bills.
The report said it couldn’t conclude why default residential rates were lower than power-shopping residential rates. Competitive suppliers, it said, argue that they provide additional attributes — such as renewable power, discounts and incentives — for which consumers are willing to pay a premium. Default service supporters, the report said, argue that higher retail supplier costs and greater volatility make rates for shoppers higher than default rates.
While residential customers’ savings have been less than those seen by commercial and industrial customers, the Retail Energy Supply Association said that is because residential customers have been less likely to shop.
The report found that 22 to 46% of residential customers are shopping for power suppliers, depending on their distribution company. In contrast, 30 to 50% of commercial customers and more than 80% of industrial customers abandoned their distribution companies.
“The appropriate comparison for residential benefits is to examine available competitive offers that not all consumers take advantage of,” RESA said in a press release. “The lowest-available 12-month fixed-price offers represent more than $314 million in potential annual savings to consumers if all remaining customers switched to these offers.”
RESA called for Pennsylvania to do more to promote competition. It also said the state should consider removing regulated utilities from providing default service, leaving them to focus only on distribution and transmission. “This approach has worked well in Texas, the state widely recognized to have the most robust competitive electricity market,” the group said.
Other Studies
There’s no shortage of opinions on whether competition has been a good thing for consumers.
A 2015 study by the University of California Berkeley concluded that competition had improved power plant efficiency and grid coordination but that falling gas prices had a bigger impact on rates.
A study released in February by the Electric Markets Research Foundation concluded that retail choice has done little for retail consumers. The foundation, whose website does not disclose its funders, has ties to Hunton & Williams, a D.C. law firm that has led utility challenges to EPA clean air regulations. Its 2013 and 2014 tax returns listed its president as Bruce Edelston, a former Southern Co. official who rejoined the company in March as vice president of energy policy.
Research by the Pennsylvania Utility Law Project found that customers enrolled in low-income assistance programs paid more on average with competitive power suppliers than they would had they stayed with their utility’s standard offer. “Competitive markets are bad for poor people,” PULP Executive Director Patrick M. Cicero told The Philadelphia Inquirer.
Renewed Questioning
The 20th anniversary comes at a time of renewed questioning of electric regulation.
Pennsylvania followed shortly behind California in enacting competition, the beginning of a wave that would sweep over almost half of the nation.
California’s 2000-2001 energy crisis, and revelations that Enron and other power traders had manipulated the market, brought that wave to a halt. At the peak of the movement, 22 states and D.C. had or were moving toward competitive generation markets. That number is now 14 states and the district.
At least three competitive states — New York, Ohio and Illinois — have approved or are considering subsidies for fossil and nuclear generators losing money because of cheap natural gas and renewables. Utilities in Ohio are also pushing a partial return to regulation.
Constellation Energy CEO Joseph Nigro made a pitch for nuclear subsidies in a keynote address on the second day of the conference. Constellation is a subsidiary of Exelon, owner of the country’s largest fleet of nuclear power plants.
In addition to promoting the environmental benefits of nuclear power, Nigro talked about how Constellation, Exelon’s competitive energy subsidiary, is responding to consumers’ demands for adaptability, reliability and sustainability.
“We believe that a culture of innovation must exist at every level of the company,” he said.
Nuclear subsidies also came up in another panel discussion on several recent Supreme Court rulings on jurisdictional fights between state and federal regulators.
One of the decisions discussed was the court’s Hughes v. Talen ruling that a Maryland program designed to subsidize new generation facilities infringed on FERC jurisdiction.
That ruling should enable opponents of New York’s nuclear subsidies to prevail in their federal court suit, said Abe Silverman, a counsel for NRG Energy, one of the plaintiffs. (See Federal Suit Challenges NY Nuclear Subsidies.)
AUSTIN, Texas — ERCOT staff told the Technical Advisory Committee last week it is preparing a proposal to map registered distributed generation units and a white paper addressing the reliability of distributed energy resources.
Table: | ERCOT
The work builds partly on that of the Distributed Resource Energy and Ancillaries Market (DREAM) Task Force, which produced a draft report earlier this year before going inactive. (See “DREAM Task Force Submits Final Report,” ERCOT Technical Advisory Committee Briefs.)
“We’re trying to look into what we need for the future … and focus our attention on improving our reporting requirements,” Kenan Ögelman, ERCOT’s vice president of commercial operations, told the TAC on Thursday.
As of late October, 541 MW of DG from competitive and “non-opt-in” entities — those not participating in the market, such as Austin Energy and San Antonio’s CPS Energy — had registered with the Public Utility Commission through their local utilities. The commission has estimated there are more than 7,600 DG locations in competitive areas, with the load expected to grow at a 10% annual rate.
Unregistered DG accounts for another 112 MW in ERCOT’s various load zones. Ögelman said there is no requirement for the ISO to gather data on unregistered DG, but that it occurs “more by happenstance.”
Under current rules, distributed resources injecting to the grid are paid the load zone price, allowing them to deliver energy in real time but giving ERCOT no notification of their intent to deploy.
In addition, distributed resources are compensated by load-zone pricing regardless of their location within the zone or their impact on congested elements. ERCOT says development of a resource node for distributed resources would improve reliability and the ability of DER to participate in its market.
ERCOT defines DG as any generating facility of 10 MW or less located at a customer’s point of delivery and connected at a voltage less than or equal to 60 kV.
Ögelman said ERCOT currently compiles DG data on from a variety of sources:
Load profiles and annual reports to the PUC for resources less than or equal to 50 kW;
Load profiles, PUC reports and unregistered DG reports for resources greater than 50 kW, but less than or equal to 1 MW;
PUC reports and unregistered DG reports for resources greater than 1 MW that are not exporting to the grid; and
ERCOT resource asset registration forms for non-modeled generation, but only from resources greater than 1 MW that export to the grid.
He explained that ERCOT no longer “ratchets down” its reporting of DG resources. Nodal protocol revision request (NPRR) 719, which was approved by the Board of Directors last December, removed a provision that reset DG registration thresholds when the total unregistered capacity of DG greater than 50 kW in any load zone reaches 10 MW. “There was an expectation of, ‘Hey, what’s going on? We have all this DG on the system, but there’s no ratcheting going on?’” Ögelman said.
He said staff is working with stakeholders and other interested parties to find a way to draft NPRR language “that addresses everyone’s concerns.” The white paper, Ögelman said, will “show the concern for reliability outcomes.”
Stakeholders had suggested staff use the annual load data request (ALDR) forms to track distributed resources, but Ögelman said, “The ALDR reports don’t have a very well-defined reporting requirement or change process around them.
“It’s difficult to aggregate and see a very good picture of the submitted load data to ERCOT.”
IT Staff Working to Prevent Further SCED Outages
Steve Daniels, ERCOT’s vice president of application development and IT operations, assured stakeholders that staff is working to prevent a repeat of recent outages of the security constrained economic dispatch (SCED) system.
In July, human error led to a 100-minute outage that affected 20 five-minute dispatch intervals. In October, a software failure with the market-management system’s interface resulted in a 75-minute outage. Two smaller SCED failures related to hardware issues also occurred in August and September. Load frequency control signals were also affected in the first three outages.
Daniels noted while SCED has failed in each of the last four months, the system operated smoothly in his first 16 months on the job. He said staff completed a “very thorough” root-cause analysis after each event, using both internal and external resources.
“I can assure you the attention paid to these [outages] and the amount of effort going into remediation, lessons learned and finding ways to ensure we don’t have this going forward is a very concentrated and focused effort,” Daniels said.
He told stakeholders staff is implementing new monitoring procedures, adding new software and working with its vendors “to make sure we don’t see these same issues pop up again.”
Daniels said additional measures have been added around the SCED system “to give us better visibility when those issues arise and what we can do about them.”
That seemed to satisfy stakeholders, who asked Daniels whether there is a way to avoid future single point-of-failures, where one system affects another. He said staff is continuing to “look at ways where we can make … data available to operate the system effectively and reliably when we have SCED issues.”
TAC Approves Ancillary Service Change, Tx Element List
The TAC unanimously approved staff’s proposal to make two minor changes to its 2017 ancillary service methodology. The first removes exhaustion-rate feedback from the regulation-procurement analysis, and the second adds solar generation when estimating five-minute net-load variability.
“We have 400, 450 MW of solar, so we think it’s useful to start capturing the effects,” ERCOT’s Nitika Mago said.
No changes were proposed to the methodologies for determining responsive-reserve service and non-spin reserve service.
The committee also endorsed the Reliability and Operations Subcommittee’s recommendation to approve ERCOT’s original list of high-impact transmission elements. The list will be expanded once a working group can be chartered.
NRG Texas abstained from the vote, saying it had been “late to the party” and was unable to get its comments in. The list “seems to be more backward-looking, based on an analysis of historical congestion,” NRG’s Bill Barnes said. “If [an element] didn’t cause congestion in the past, it’s difficult to get on the list.”
11 Revisions Sent to ERCOT Board
The TAC pulled NPRR773 from the list of revision requests up for a vote. Barnes, chair of the Market Credit Working Group, said the revision request includes language that expands the types of financial institutions that can offer letters of credit, but that outside counsel has proposed additional changes that are “more substantial” than those approved by his group.
The committee did approve five NPRRs, two nodal operating guide revisions (NOGRRs) and revisions to the load profiling guide (LPGRR), retail market guide (RMGRR), resource registration glossary (RRGRR) and the Verifiable Cost Manual (VCMRR).
NPRR783: Revises a requirement for an independent audit to confirm the consistency of ERCOT operations models. The change is to comply with NERC reliability standard MOD-033-1 requiring a documented data-validation process for power flow and dynamic models.
NPRR790: Adds phase angle equipment limitations to real-time monitoring, real-time assessments and operational planning analyses, as required by NERC standards. ERCOT will collect this information through the network operations modeling process.
NPRR791: Clarifies the initial estimated liability (IEL) description to specify that it is based on estimated sales between qualified scheduling entities (QSEs); restores the IEL for traders (inadvertently omitted from NPRR741); and corrects errors to the minimum-current exposure formula mistakenly overwritten by NPRR743.
NPRR797: Creates a new report and display for the actual system load by forecast zone, similar to the capability for weather zones.
NPRR801: Revises the physical responsive capability (PRC) calculation to include all load resources and align operating reserve demand curve (ORDC) reserves with the PRC change. It also aligns the ancillary service imbalance settlement with the change to the ORDC reserves.
LPGRR057: Updates the load profiling guide by eliminating language, processes and methodologies no longer necessary within ERCOT’s market.
NOGRR154: Allows a QSE to designate an agent to connect to ERCOT’s wide area network (WAN) and requires the ISO and market participants to use the WAN to exchange resource-specific XML data.
NOGRR159: Modifies the use of the term Texas Reliability Entity to distinguish between references to the NERC Regional Entity and the Texas PUC Reliability Monitor. It also clarifies that the Independent Market Monitor is an included party in several provisions related to the ERCOT stakeholder process.
RMGRR139: Modifies market processes to align with NPRR778’s changes to the protocols’ evaluation window for date changes and cancellations.
RRGRR010: Amends the seasonal net max sustainable rating definitions by including ambient conditions (including temperature and humidity) representative of conditions that exist during peak load periods in which the generation resource operates. The change is intended to correct an overestimation of summer capacity ratings for gas-fired generation. ERCOT discovered the same temperature value had been used for summer and winter seasonal ratings for a significant number of gas-fired units, with resources reporting temperatures of 36 to 110 degrees F for their summer ratings.
VCMRR013: Clarifies the process for appealing ERCOT’s denial of submitted verifiable costs. The changes address timelines and ERCOT representation in the appeal process and align with NPRR769, approved by the board Oct. 11.
FERC last week conditionally approved revisions to the MISO-PJM Joint Operating Agreement on cost allocation for cross-seam transmission projects, while denying rehearing requests from PJM and the RTOs’ transmission owners (ER13-1944, et al.).
In rejecting the rehearing requests, the commission said the grid operators and TOs chose the avoided-cost-only method for allocating the costs of such projects, so any issues that method creates should be addressed within the operators’ stakeholder processes.
In a previous filing, PJM and MISO settled on a cost-allocation method that is based on how much the cross-border project saves each grid operator on regional projects it supplants. The commission, however, said the method didn’t consider regional projects that have already been selected, nor did it explain how it would measure if an interregional project is more efficient or cost effective than a regional one.
Tie lines between MISO and PJM | PJM
MISO’s TOs asked for the rehearing because they were concerned that displacing projects that had already been selected wouldn’t allow them to recover millions of dollars in development costs incurred on those projects prior to them being abandoned. MISO’s Tariff, they noted, does not explicitly provide for such recovery.
“To the extent that MISO transmission owners are requesting that the commission mandate full cost recovery for transmission projects selected in a regional transmission plan but displaced by an interregional transmission project, we reject their request as outside the scope of the Order No. 1000 compliance proceedings,” the commission said.
“If MISO transmission owners continue to believe that these costs are not treated appropriately under MISO’s Tariff, they may pursue changes through the MISO stakeholder process and make a filing to amend the MISO Tariff or else file a complaint with the commission pursuant to [Federal Power Act] Section 206.”
FERC approved portions of the grid operators’ compliance filings, including how projects can be categorized, but it ordered additional changes to eliminate some inconsistencies. (See “MISO Order 1000 Compliance,” MISO Planning Advisory Committees Briefs.)
MISO and PJM have 30 days to make additional filings to fully comply with the order.
