FERC rejected Dominion Resources’ request to recover almost $400,000 in uncompensated costs incurred when it ran four dual-fuel units on fuel oil rather than cheaper natural gas in June.
| Matcor
The commission’s Nov. 30 order said Dominion’s Virginia Electric and Power Co. is not entitled to recover the additional costs because it only submitted to PJM cost-based offers for natural gas operations at its five combustion turbines in Ladysmith, Va. (EL16-109).
The units, totaling 783 MW, primarily operate with natural gas but can also run on fuel oil. They did not clear in the day-ahead market for June 25, and after the rebidding period, VEPCO learned of a pipeline constraint that left the Ladysmith units unable to operate on natural gas.
At 11 a.m. on June 25, PJM ordered the utility to operate four of the units beginning at noon for reliability reasons. The company said it notified PJM of its need to operate on more expensive fuel oil and PJM reiterated its dispatch order. VEPCO said it operated three units for 10 hours and one for 11 hours, spending $387,588 more on fuel than it was paid for.
The company said the commission’s June 2015 ruling that PJM’s Tariff and Operating Agreement were unjust and unreasonable because they did not permit day-ahead offers that vary by hour or allow market sellers to update their offers in real time supported its request for relief. (See Duke, ODEC Denied ‘Stranded’ Gas Compensation.)
Ladysmith Power Station | Dominion
The commission disagreed, saying the company’s “inability to recover its fuel oil costs for the Ladysmith units resulted from its own business decisions regarding which cost-based offers to submit and is not the result of the offer limitations that the commission addressed in the offer flexibility proceeding.”
FERC also rejected the company’s request to make it whole through a waiver of PJM’s rules, saying it would cause harm to load, which “would be assessed unanticipated additional charges inconsistent with the current PJM Tariff and Operating Agreement on file and without adequate prior notice.”
“Granting waiver here would send the wrong signal to market sellers, namely, that a resource can submit an offer that PJM uses to dispatch the resource, and then seek to increase that offer after-the-fact to receive additional compensation,” FERC said.
PJM’s proposed Tariff revisions to increase offer flexibility, filed in August, is pending before the commission (ER16-372-002).
A new report from CAISO’s internal Market Monitor contends that the ISO’s program for auctioning off congestion revenue rights (CRRs) suffers from inherent design flaws that have allowed speculators to reap enormous gains at the expense of outmatched ratepayers.
Skeptics say the Monitor’s conclusions are ill-considered and that more analysis is necessary before the ISO takes any steps to alter the CRR auction process.
The Monitor, headed by Eric Hildebrandt, said that California ratepayers lost $520 million in 2012-2015 through a market that pays $1 to CRR holders for every 45 cents in revenues received from auctions.
Congestion revenue rights (CRR) auction revenues have significantly lagged payments to CRR holders since the system was put in place nearly five years ago. | CAISO
“This consistent underpricing of CRRs calls into question a fundamental assumption of the CRR auction design that competition will drive auction prices to equal the CRR’s expected value,” the Monitor said. “It is unlikely that rules similar to the CRR auction design would emerge in many competitive markets that are not designed by a regulatory process.”
‘No Clear Rationale’
The Monitor contends that there is “no clear rationale” for the ISO to provide a market for price swaps, echoing criticism voiced by PJM Independent Market Monitor Joe Bowring and others. (See Role, Value of Financial Trading Debated by OPSI Panel.)
CAISO’s Monitor says the main beneficiaries of the current system are “purely financial entities” sophisticated enough to identify which CRRs are likely underpriced at auction but stand to pay off handsomely because of a disconnect between how the CRRs are packaged at auction and how they’re compensated at settlement.
To illustrate that disconnection, the Monitor first explicates its view on what exactly a CRR does and doesn’t represent.
“A CRR is not a day-ahead market transmission right,” the Monitor said. “All day-ahead market bidders have access to the transmission system regardless of whether or not they hold a CRR.”
CRRs are not needed to ship power between nodes because the ISO’s centrally cleared LMP market is linked to its transmission operation, meaning that market participants are not responsible for moving power from one location to another.
Rather, a CRR purchased at auction should be understood as a forward contract that allows an auction participant to hedge financial exposure to — or speculate on — day-ahead price differences between two locations, the Monitor explained. The demand for such hedging stems not from the ISO’s own market but from forward power contracting occurring outside the market.
“A supplier may sell a forward power contract at a location different than its generator’s location,” the Monitor said. “When this occurs, the day-ahead price on which the forward contract settles will be different than the day-ahead price the generator receives for selling power into the day-ahead market.”
The differing settlement locations expose the supplier to possible price discrepancies not accounted for in the forward power contract. So it’s the CRR auction that provides for acquiring forward contracts for differences to hedge price differentials between two points.
The problem with this setup?
“Unlike most other forward contract markets, the CRR auction allows participants to take positions without a counterparty offering to take the opposite position,” the Monitor said.
Instead, transmission ratepayers become unwilling counterparties to the CRR contracts because they’re on the hook to provide payment when auction revenues come up short of CRR payouts.
Ratepayers Outgunned
To avoid that outcome, those ratepayers would have to enter the auctions to buy the contracts themselves. This is problematic for a couple reasons, the Monitor points out.
First, the load-serving entities that effectively act on behalf of ratepayers in ISO markets may obtain CRRs to hedge risk, but they are explicitly barred from financial speculation in any transactions. In any case, LSEs would lack the incentive to manage ratepayers’ CRR forward contracts in the auction because they can pass on CRR costs to those ratepayers.
Second, participation in CRR auctions as a speculator requires knowledge of power flow analysis, finance and transmission/generation outages and operations, as well as meeting collateral requirements to engage in the market. In short, ratepayers would be outmatched by the companies that employ electrical engineers and other experts to transact in the highly complex market.
The most fundamental problem with the ISO’s CRR market, the Monitor contends, is its financial structure and lack of a consistent definition for a particular set of CRRs. Although CRRs are auctioned as “a bundle of forward contracts on specific transmission constraints,” they are not settled as the same bundle at day-ahead market prices. That’s because the day-ahead market network model that forms the basis for settlement cannot be known when the auction is run. New transmission constraints can be introduced after the auction,” effectively making the CRR a different product when bought than when it is settled.
“A CRR will only be consistently defined if the bundle in the auction is the same as the implied bundle from the day-ahead market price differences,” the Monitor said. “When the transmission models are different in the auction and day-ahead market, the bundles will not be the same.”
Proposal
As an alternative to the CRR auction, the Monitor proposes a bilateral or exchange market for forward contracts-for-difference for pairs of ISO nodes — otherwise known as locational basis price swaps. The swap buyer would pay the seller a price in the forward market and in return be paid the spot price difference between the two locations.
A key difference from the current CRR market: Price swaps would be traded between willing counterparties. And unlike the inconsistently defined CRR contract, the swap would be consistently defined in both the forward and day-ahead market.
‘Robust’ Analysis Needed
Gary Ackerman, executive director of the Western Power Trading Forum (WPTF), said his organization “strongly” disagrees with the Monitor’s call for ending CRR auctions.
“The CRR platform is a market,” Ackerman said. “Buyers and sellers value risk and opportunity differently. Scrapping it is a FERC question and seems like a radical step when indeed the CAISO makes the rules.”
Ackerman pointed out that FERC requires organized wholesale power markets to provide instruments that allow participants to hedge risk.
“This isn’t about who is getting what money or under-collecting the transmission revenue requirement,” Ackerman said. “It’s about [providing] market value for relieving congestion.”
Carrie Bentley with Resero Consulting, which frequently works on behalf of the WPTF, elaborated on the group’s position.
“If the CAISO had more transparency surrounding the transmission system — and in particular how the CAISO represents the transmission system in both the CRR model and the day-ahead market model — participants would have information at the time of the auction about the expected day-ahead market and any differences between the day-ahead market and the CRR market,” Bentley said.
Increased transparency could incentivize bidders to offer a higher value for CRRs in the auctions, Bentley said, noting that recent improvements in the ISO’s transmission outage reporting might account for the reason that CRR auction revenues exceeded payouts during the third quarter of this year.
Both Ackerman and Bentley dismissed the Monitor’s proposal for a new bilateral market for price swaps.
“There cannot be an effective market without buyers and sellers fluidly engaging in commerce, and there does not appear to be buyer interest in long-term power and power basis hedging,” Ackerman said.
Bentley said the CRR auction process is “invaluable” because it allows market participants to adjust their CRR positions “to get just the right hedge” based on portfolios and risks.
“Because the grid is so complex, achieving this fine tuning of one’s CRR holdings would be nearly impossible if participants had to trade bilaterally,” Bentley said.
Bentley also contends that market participants have not been provided with “robust analyses” on the precise cause for the revenue shortfalls in the auctions.
“It seems to make more sense that [the Monitor] could perform further analysis — or make such analysis public if they have already performed it — and then parties could consider how the CAISO could converge the day-ahead and CRR markets and models as a first step — before jumping to the conclusion the auction simply isn’t useful,” Bentley said.
FERC has granted MISO a waiver of its $1,000/MWh offer cap for winter, providing the RTO relief before the commission’s pre-Thanksgiving order that doubled the hard offer cap for all grid operators takes effect.
FERC’s Nov. 17 ruling setting the offer cap for day-ahead and real-time markets to $2,000/MWh in all RTOs and ISOs won’t take effect until 75 days after publication in the Federal Register (RM16-5). (See New FERC Rule Will Double RTO Offer Caps.)
Thus the commission on Nov. 29 granted MISO’s request that resources with incremental energy costs above the current $1,000/MWh offer cap be allowed to recover costs effective Dec. 1 (ER16-2685). FERC approved similar MISO requests for the winters of 2014/15 and 2015/16.
The waiver and FERC’s new rule require that energy costs that exceed $1,000/MWh must be verified before the offer is used to set LMPs. FERC acknowledged the rule in the order granting the waiver, calling it “a long-term solution.”
| Ohio Power Siting Board
“MISO’s experience during the polar vortex of the 2013/14 winter demonstrates that fuel costs can increase to a level such that the current $1,000/MWh offer cap prevents resources from submitting incremental energy offers that reflect their marginal production costs. If similar weather and natural gas supply conditions materialize in the 2016/17 winter, some resources could face the untenable position of being forced to offer electricity at levels below their actual cost,” the commission said.
As with MISO’s two previous waivers, the order instructs MISO’s Market Monitor to file a report within 30 days after the waiver period ends April 30 with statistics on offers above $1,000/MWh.
AEP Ohio proposed a new retail rate plan that would more than triple residential customers’ fixed charges and shift more costs to customers that do not purchase their power through a competitive supplier.
AEP’s Cardinal Plant | Baker Concrete
But the company’s request for a six-year extension of its “Electric Security Plan” (ESP) lacks the controversial proposals in its last rate case to subsidize the company’s merchant generation — a plan that crumbled after FERC said it would be subject to its review. Instead, the company is hoping Ohio legislators will agree to revamp the state’s deregulation law to allow it to bring its merchant generation back into the rate base.
The utility said it expects the Public Utilities Commission of Ohio to decide on its Nov. 23 request in April (16-1852-EL-SSO).
Rate Impact
The new plan, which would run through May 2024, would increase bills by $1.58/month — a 1.2% increase — for residential customers who use 1,000 kWh and haven’t changed their electricity generator from AEP Ohio’s standard service offer (SSO).
Heavier energy users would see rate cuts, the company said. Residential customers using 2,000 kWh/month would save 1.8%, small businesses with 1,000 kW peak demand and 350,000 kWh usage would save 1.3%, and industrial customers with demands of 20,000 kW or more and using at least 8 million kWh would save more than 4%, according to accompanying testimony by Andrea E. Moore, AEP Ohio’s director of regulatory services.
“The terms of the proposed ESP offer AEP Ohio customers reasonable and stable electricity rates while offering investors some measure of financial stability,” the company said in its filing.
If the extension is not approved, AEP says it will terminate the current plan before its May 2018 expiration, freeing it from its promise to build 900 MW of renewable generation.
AEP Ohio, a subsidiary of American Electric Power, had requested a 2024 expiration date when it applied in 2013 for its third and current ESP, but PUCO in 2015 approved a three-year plan.
Merchant PPAs
In that case, PUCO allowed AEP Ohio to sign power purchase agreements for all of its Ohio merchant generation.
But after FERC ruled in April that the PPAs would be reviewed under the Edgar affiliate abuse test, AEP scaled back its request, asking PUCO for agreements covering only its 440-MW share of the Ohio Valley Electric Corp. (See AEP, FirstEnergy Revise PPA Requests to Avoid FERC Review.)
AEP posted a loss of $765.8 million in the third quarter after taking a $2.3 billion impairment on its share of 2,684 MW of competitive generation in Ohio. (See AEP Turns Away from Generation to Transmission, PPAs.)
The company is currently collecting costs for its share of OVEC through a surcharge on all distribution customers. Under the new proposal, the OVEC generation would supplant power bought through the ESP’s competitive auctions. AEP would recover costs from default customers, with its price blended with that of generators clearing in the auctions.
Riders
The proposal also includes adding or modifying several other riders to customer bills, such as an “alternative energy rider” to recover expenses for renewable energy credits. It also would more than triple the residential customer charge from $5/month to $18.40 by January 2018 while reducing the share of fixed charges included in distribution energy charges.
AEP committed in the last rate case to developing 500 MW of wind generation and 400 MW of solar generation in its stakeholder agreement. The extension proposal includes commitments to install between eight and 10 microgrids, 250 electric-vehicle charging stations and self-dimming street lighting in Franklin and 10 surrounding counties.
It would also commit AEP to installing a faster crew-dispatch system for outages and infrastructure hardening, as well as extend existing commitments to “aggressive tree trimming and vegetation-management programs” and replacing aging infrastructure.
AEP’s proposal also includes a “competition incentive rider” (CIR) that would charge default customers extra for not shopping for an alternate supplier. The company said the rider would “incent shopping and recognize that there may be costs associated with providing retail electric service that are not reflected in SSO bypassable rates.”
AEP said PUCO and other parties were not able to agree on how large the rider should be but that the commission staff “has provided an initial CIR level for inclusion in this filing of $0.62/MWh.”
Although the new proposal lacks the PPAs that drew opposition, Ohio Consumers’ Counsel Bruce Weston said he has found things to dislike about it.
“AEP’s holiday wish list is too long,” he said in a statement. “AEP’s continual requests for state government to approve even more charges on Ohioans’ electric bills show why Ohio’s 2008 energy law [which allowed multiyear rate applications] should be repealed.”
Legislative Change Sought
Ohio deregulated the generation portion of its electricity rates in 1999, allowing customers to shop for their electricity suppliers.
AEP spokeswoman Melissa McHenry said the company is working with lawmakers to restructure the law so that it can reincorporate merchant generation into its rate base. McHenry said the company hopes to have a bill introduced into the legislature by the first quarter of 2017.
The company also is expected to file with PUCO by Dec. 31 a carbon-reduction plan, along with commitments on fuel diversification, grid modernization and battery utilization.
PJM stakeholders are discussing the best way to measure distributed energy resources in integrating them into the grid. The debate over metering in front of or behind the customer’s load was the focus of the Market Implementation Committee’s most recent special session on the topic Nov. 22.
PJM’s Andrew Levitt outlined the differences between measuring DER performance directly at the energy resource before it offsets the customer’s load and measuring it through the main meter at the point of interconnection. The main difference, Levitt said, is whether the DER performance shows up as a reduction of the load baseline like demand response or is measured separately as an injection to the system.
| PJM
The discussion came days after FERC’s Nov. 17 Notice of Proposed Rulemaking, which would require RTOs to allow aggregated DERs and storage resources of 100 kW and above to participate in capacity, energy and ancillary services markets. (See FERC Rule Would Boost Energy Storage, DER.)
Of special concern is whether the baseline-reduction approach would work if the load is completely reduced and becomes a net injection. Levitt also posed the questions on how energy and capacity obligations would be impacted by either approach and how to ensure injections aren’t double counted.
“I think we agree that proper accounting is an important first principle here, and that really means no double counting and … tracking down every step in the accounting chain and figuring out that that comes together correctly,” Levitt said.
More Questions than Answers
FirstEnergy’s Ed Stein asked if PJM has considered how adjustments to an individual customer’s load from DER will be included in zonal load profiles. “I just know all the math we deal with today and trying to manage all of this. I just don’t want these slides to start to look like it’s very simple. It’s very difficult right now,” he said.
Dave Pratzon of GT Power Group questioned whether an energy resource behind a load meter could be considered a “front-of-meter” framework, but Levitt confirmed that many setups are wired that way.
“I acknowledge that the terminology begins to get pushed to its limits when you talk about a front-of-meter resource wired behind a load meter,” Levitt said. “Do they cancel out? Apparently they don’t. You just measure whatever comes out at the point of interconnection and you do all of the performance measurement at the point of interconnection. Submetering in a front-of-meter framework, where you put a meter directly on the resource if it’s wired behind a load meter, is not super easy. Not a lot of people think about a generator wired behind a load meter coming through PJM’s queue and selling wholesale, but in fact that does happen. An example that I’ve been mining a lot is landfill gas generators.”
Pratzon followed up, asking whether customers using that setup are claiming the entire load reduction as Reliability Pricing Model capacity or just the generation that becomes an injection beyond offsetting its load. Levitt said he would research the answer.
By the time the meeting finished, multiple stakeholders had pushed for increased visibility in how DER setups are designed. PJM officials said their plan for the group’s next meeting on Dec. 16 is to identify interests and compile design components that could be included in measurement rules.
PJM’s Dave Anders noted that the group has preliminarily agreed to focus first on DER participation in ancillary services and use the lessons gathered there to inform wider DER participation. PJM staff also suggested beginning with DR-style measurement, but stakeholders warned against limiting the group’s options.
Anders also noted other ongoing efforts to address DER needs, including interconnection-queue changes that are being investigated through the Planning Committee.
By Rory D. Sweeney, Ted Caddell and Amanda Durish Cook
Illinois officials moved closer to a deal to save Exelon’s Clinton and Quad Cities nuclear plants as legislation cleared a House committee and the company reportedly reached agreement with Gov. Bruce Rauner on changes to reduce the bill’s cost.
The House Energy Committee voted 10-1 on Tuesday to send the bill — which would provide Exelon $235 million a year in subsidies for 13 years — to the House floor (SB 2814). Overnight negotiations with Rauner’s office have secured his approval as well, Crain’s Chicago Business reported.
Illinois Statehouse | Illinois Asset Building Group
“While there is still a lot of work to be done, we are pleased to have an understanding with the governor’s office and continue to work with the four leaders and their professional staffs, as well as other stakeholders and the bill’s more than 200 other supporters, to move this bill forward,” Exelon spokesman Paul Adams said Wednesday. “With today’s progress, we are all one step closer to saving thousands of jobs in Illinois.”
The negotiations with Rauner’s office resulted in a statewide cap on rate increases, removing ratepayer funding for two microgrids and a reduction in funding for solar development, Crain’s said. Subsidies for Dynegy coal plants in southern Illinois and a proposed “grid impact rate” — which would have based power bills on peak use instead of overall usage — had already been removed from the bill that cleared the House committee, the Quad-City Times reported.
Dynegy spokesman David Onufer said the company has withdrawn its support as a result of the elimination of aid for generation in the southern part of the state.
“Leaving out this provision leaves behind Illinois residents and communities in central and southern Illinois. The bill now only helps the few and does not protect the downstate jobs and the economy,” Onufer said. “The flawed downstate energy market doesn’t allow plants to recover costs. Nearly 20% of downstate Illinois’ generating capacity has already been retired or mothballed this year.”
Exelon threatened in May to shut down the money-losing Clinton and Quad Cities nuclear plants if the state didn’t provide subsidies, such as the emissions credits proposed in the new bill. (See Bill to Save Coal, Nuclear Plants Introduced in Illinois.)
A variety of organizations, such as the Illinois Manufacturers’ Association, the Illinois attorney general’s office and AARP Illinois, have criticized the proposal for raising customers’ bill too much. They were hoping to find alternative economic tools to keep the nuclear facilities open, the Times reported.
Several environmental groups, including the Illinois Clean Jobs Coalition, the Sierra Club and the Natural Resources Defense Council, are supportive of renewable energy incentives in the bill. The Citizens Utility Board also supports it. It’s unclear, however, whether the changes negotiated with Rauner will cause the bill to lose support.
Lawmakers representing the regions home to the generating plants are also supportive. Republican State Rep. Bill Mitchell had been concerned the bill had become too big to remain stable and was pleased Rauner got involved.
“It’s always been my concern that the bill gets so big, it collapses, just like a gaming bill usually does,” he told Illinois Public Media. “They get so big, they collapse under their own weight. The alternative to have no bill is not good for the state of Illinois.”
Lawmakers have little time to complete their work as the legislature’s current “veto” session is due to end Thursday.
Less than two weeks after setting a wind generation record for grid operators, ERCOT became the first to exceed 15,000 MW when its system generated 15,033 MW of wind energy on Nov. 27.
Roscoe Wind Farm | Wikimedia
ERCOT set its latest record at 12:35 p.m., when wind energy represented about 45% of the system’s total demand. The Texas grid operator said more than 8,800 MW came from facilities in West and North Texas, nearly 3,800 MW came from South Texas and about 2,300 MW came from the Panhandle.
Wind generation accounted for 11.7% of ERCOT’s energy production in 2015 but has provided 14.7% in 2016.
ERCOT said it recorded high wind outputs throughout the day, with just more than 10,000 MW at night into the noon hour. Its previous record of 14,122 MW came on Nov. 17.
The ISO has more than 17,000 MW of installed wind capacity, which is expected to top 19,000 MW by the end of 2016.
FERC approved CAISO’s plan to extend the temporary Tariff provisions the ISO implemented last June in response to natural gas pipeline restrictions stemming from last year’s closure of the Aliso Canyon natural gas storage facility.
The measures — which are intended to reduce the potential for blackouts through improved gas-electric coordination — now remain effective until Nov. 30, 2017, a year after the original sunset date.
“We find that continuation of the interim measures for an additional year should improve scheduling coordinators’ ability to manage their gas procurement and enhance their ability to recover gas procurement costs, while also providing CAISO with flexible tools to maintain reliability and avoid adverse market outcomes related to the limited operability of Aliso Canyon,” the commission wrote in its Nov. 28 decision (ER17-110).
With no timetable set for the reopening of the Aliso Canyon natural gas storage facility, CAISO sought to extend for another year interim market measures designed to deal with gas supply restrictions this past summer. | California Governor’s Office of Emergency Services
In a separate ruling Nov. 21, the commission also approved the ISO’s request to make permanent three other related “bidding enhancement measures” approved by FERC on June 1 that also would have expired Nov. 30. (See below.)
No Timetable for Return
The ISO sought expedited approval to extend the Alison Canyon measures to head off concerns about potential natural gas shortages during the coming winter, a second peak season for Southern California gas consumption because of increased residential heating. (See CAISO Seeks to Extend Aliso Canyon Gas Rules Through Winter.)
While Aliso Canyon owner Southern California Gas has been testing the storage facility for leaks, the California Public Utilities Commission has not yet set a timetable for reopening the facility. State regulators have instead signaled that they expect utilities to implement winter-specific measures for electricity consumers that would mirror the state’s successful summer response to constrained gas supplies. (See Sandoval: Nuke Shutdown, Auto-DR Aided Aliso Canyon Response.)
For its part, CAISO is preparing for the facility to remain out of service for most of 2017.
The commission’s decision enables the ISO to extend provisions that provide scheduling coordinators with two-day ahead advisory schedules and allow gas-fired generating units to incorporate more timely fuel prices into their market offers. It also continues use of an after-the-fact cost recovery mechanism for generators that includes pipeline penalties and is based on same-day gas prices rather than day-ahead gas indices.
The ISO will also retain its authority to override its “dynamic competitive path” assessment when it determines that the transmission path is no longer competitive in the face of a gas constraint, as well as to suspend virtual bidding to prevent market manipulation.
The commission also approved CAISO’s request to refine a provision that allows the ISO to enforce a market constraint that limits the minimum and maximum amount of gas that can be burned by generators in the affected area during periods of restricted supply. The refinement will set a limit on the maximum burn only, given that generators this summer demonstrated they could regulate their minimum burns simply by lowering the price of their bids into the real-time electricity market.
‘Objective Standard’ Rejected
FERC rejected a request by the Western Power Trading Forum (WPTF) to require CAISO to establish standards for deeming when a constrained transmission path has become uncompetitive or suspending convergence bidding. Reprising a statement from its decision authorizing the original Aliso Canyon measures, the commission said “the impact of the natural gas constraint on the assessment of competitive paths can only be assessed based on actual system conditions once the constraint is in place.”
Requiring CAISO “to develop objective standards for when and how these measures may be implemented is not feasible,” the commission concluded.
However, the commission did agree to a WPTF request that the ISO be required to publish a market notice for any revisions made to generator gas adders — rather than just during instances when the adder is increased.
The commission also said it agreed with market participants who filed comments contending that the interim measures should not become substitutes for permanent market reforms that could become necessary in the future.
“We find that the Tariff revisions proposed here are appropriate for mitigating the risks resulting from the limited operability of Aliso Canyon but expect CAISO to honor its commitment to consider other types of longer-term market enhancements,” the commission said. It encouraged the ISO to begin a stakeholder process to address the potential need for additional measures dealing with exceptional — or out-of-market — dispatches related to the facility’s closure.
The Tariff revisions allow scheduling coordinators to rebid commitment costs in the real-time market if they were not committed in the day-ahead market or residual unit commitment process; ensure that the ISO’s short-term unit commitment process does not commit resources that did not submit bids into the real-time market unless they were scheduled or committed in the day-ahead market or had a real-time must-offer obligation; and allow scheduling coordinators to seek after-the-fact recovery of unrecovered commitment costs that exceed the commitment cost bid cap as a result of actual fuel procurement costs.
CAISO told FERC that the Tariff provisions were developed independently of the concern over Aliso Canyon as part of a stakeholder effort approved by the ISO’s Board of Governors in March 2016.
Although the changes were not intended to be temporary, the ISO said it included them in the package of interim revisions accepted in the June 1 order because it believed they would help it manage the transmission system and market operations during the summer.
The commission said the Tariff revisions “should provide more accurate prices in the real-time market and help avoid the inefficient dispatch of resources in the real-time market based upon bids that may not reflect current fuel prices.”
Monitor Seeks Sunset
The ISO’s internal Department of Market Monitoring told FERC the language permitting the real-time rebidding of commitment costs should only be extended until the end of summer 2017 pending a review of how limitations on rebidding commitment costs could be directly enforced through the ISO’s market software. The Monitor said it opposed continued reliance on non-automated, after-the-fact monitoring and enforcement to protect against the potential for excessive bid cost recovery payments.
The commission rejected the Monitor’s request to sunset the real-time rebidding rules but ordered CAISO to submit an informational report by Oct. 1, 2017, “detailing its assessment of the effectiveness of the rebidding process and its efforts to automate the monitoring and enforcement process.”
FERC approved a settlement over Constellation Power Source Generation’s reactive service payments that was initially opposed by PJM’s Independent Market Monitor (ER16-746, EL16-57).
The Nov. 21 order requires Constellation to file a revised reactive service revenue requirement no later than Jan. 16, 2017, and to make refunds if the resulting requirement for Constellation’s units in the Baltimore Gas and Electric zone is less than $1.24 million per year.
Constellation’s Gould Street generator is one of the resources providing reactive power in PJM’s BGE zone. | Creative Commons – DeanLaw
The Monitor initially asked FERC to add a list of conditions to the settlement, including updated power factor tests and eliminating the recovery of heating losses. The Monitor said the commission should end the practice of allowing cost of service rates for reactive capability and said if the practice is not discontinued the costs eligible for recovery should include only fixed costs incurred solely for providing reactive service.
On Oct. 4, the Monitor withdrew its opposition to the settlement, “because the settlement ‘establishes no principles and no precedent with respect to any issue in this proceeding’” and because Constellation must make a new filing.
The settlement resulted from a review ordered by FERC in May, when the commission reduced Constellation’s reactive payments by almost $225,000 to reflect the retirements of three generators. (See “Constellation’s Reactive Payments Cut Due to Retirements,” FERC Rulings in Brief.)
Duke Energy ROE Reduced
FERC on Nov. 21 approved an uncontested settlement reducing Duke Energy’s return on equity for transmission to 10%, down from 10.2% (Duke Energy Carolinas) and 10.8% (Duke Energy Progress) (EL16-29, EL16-30).
The settlement also terminates the amortization of Duke Energy Carolinas’ expenses on the aborted GridSouth RTO effective Dec. 31, 2015, caps common equity ratios and a sets a moratorium on changes in the ROE and equity cap through Dec. 31, 2019.
Connecticut has selected 25 small clean energy and energy efficiency projects totaling 402 MW to negotiate power purchase agreements with the state’s two electric distribution companies.
The Class I projects, all less than 20 MW each, responded to a request for proposals earlier this year. They will negotiate PPAs with Eversource Energy and United Illuminating as part of Connecticut’s legislative mandate to decarbonize its electric generation resources.
Wind Turbine | CTEWD – Get Into Energy CT
“The response to the RFP for small-scale clean energy projects was robust and competitive — giving us the welcome challenge of carefully considering more than 100 projects and evaluating them against our established criteria,” Department of Energy and Environmental Protection Commissioner Robert Klee said in a statement Nov. 28.
Included among the 25 projects are 11 totaling 170 MW within the state: nine solar, one wind and 34 MW of energy efficiency offered by Eversource, making it both a resource supplier and the EDC negotiating procurement.
“DEEP and the state Attorney General’s office will play a role in development of the efficiency contract,” DEEP spokesman Dennis Schain told RTO Insider. “Also, all contracts have to be reviewed and approved by our utility regulatory body, so there are protections for ratepayers in this project from Eversource having been selected.”
Besides the 11 Connecticut projects, seven have been selected in Vermont, two each in Maine, Massachusetts and New York, and one in New Hampshire. The projects range in size from 3.5 MW of wind in Connecticut to two solar projects of 19.99 MW in New York.
Final contracts will be submitted to the Public Utilities Regulatory Authority for approval, which is expected in early 2017.
Connecticut also is part of a separate procurement with Massachusetts and Rhode Island for large-scale projects of 20 MW or greater. The states selected seven projects totaling 460 MW for contract negotiations. However, those negotiations have been stayed by the Second Circuit Court of Appeals following a challenge by Allco Renewable Finance, a developer of small-scale renewable projects. Oral arguments in that case are scheduled for Dec. 9 (Allco Finance Limited v. Klee, 16-2946). (See Court Halts New England Clean Energy Contracts.)
FERC Declines PURPA Case
In a related matter, FERC ruled Nov. 22 against initiating an enforcement action against Connecticut regulators over Allco Finance’s claims that the state was not abiding by the mandatory purchase requirements of the Public Utility Regulatory Policies Act (EL16-115, QF16-362, et al.).
The commission’s action means Allco and its unit Windham Solar may file their own enforcement action against the PURA “in the appropriate court,” FERC said.
Allco contends the state regulators improperly concluded that Windham is not entitled to a legally enforceable obligation at a forecasted avoided cost rate and that Eversource has no need for capacity.
