Page 1375 – RTO Insider

December 2, 2016

UPDATE: CAISO Monitor Proposes End to Revenue Rights Auction

By Robert Mullin

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.

Adding to previous calls to reform or eliminate the auction process, the Department of Market Monitoring report spells out flaws in the current system and suggests a possible alternative. (See CAISO Monitor Seeks Congestion Revenue Rights Auction Reforms.)

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 caiso — 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.

December 2, 2016

MISO Granted Winter Waiver on Offer Cap

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 — | *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.

– Amanda Durish Cook

December 2, 2016

AEP Ohio Rate Plan Excludes Merchant Generation

By Rory D. Sweeney and Rich Heidorn Jr.

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 — 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's Conesville Power Station | © Delta Whiskey, Creative Commons — AEP’s Conesville Power Station | © *Delta Whiskey, Creative Commons*

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.

December 1, 2016

PJM Stakeholders Consider Best Way to Measure DER

By Rory D. Sweeney

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.

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.)

PJM has been working on the issue since the summer. (See “Venue for DER Discussions to Change,” PJM Markets and Reliability and Members Committees Briefs.)

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.

Ill. Nuke Bailout Progresses; Exelon Reports Deal with Gov.

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 nuclear power Exelon — 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.

November 30, 2016

ERCOT Tops 15,000 MW in Wind Generation

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.

ercot wind generation — 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.

– Tom Kleckner

November 30, 2016

FERC OKs One-Year Extension for CAISO’s Aliso Canyon Gas Rules

By Robert Mullin

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).

ferc enhancement measures aliso canyon — 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.

Nov. 21 Ruling

In a separate ruling Nov. 21, the commission approved the ISO’s request to make permanent three “bidding enhancement measures” approved by FERC on June 1 to address summer gas supply concerns (ER16-2445). (See FERC Approves CAISO’s Aliso Canyon Response Plan Ahead of Summer.)

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.”

November 30, 2016

FERC OKs Duke, Constellation Settlements

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 settlements duke energy ferc — 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.

– Rich Heidorn Jr.

November 30, 2016

Connecticut Advances Small-Scale Renewables Contracts

By William Opalka

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 — 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.

It is at least the third time this year that declined to act on Allco’s PURPA claims. (See FERC Rejects Enforcement Action in Connecticut PURPA Dispute.)

November 29, 2016

Clean Energy Innovation Requires Collaboration, Researcher Says

By Rory D. Sweeney

PHILADELPHIA — The next wave of clean-energy innovation will require collaboration as well as competition, says a researcher for the Near Zero energy policy advocacy group.

Speaking at a lecture series sponsored by the University of Pennsylvania’s Kleinman Center for Energy Policy last week, Dan Sanchez, a postdoctoral scholar at the Carnegie Institution for Science, said sharing intellectual property and allowing open access to research data are catalysts necessary for growth in the clean energy industry.

“There’s actually some really strong empirical work that shows that connectivity between the private sector and the public sector really does improve innovation outcomes and really does improve the chances that publicly funded research results in commercially successful products,” he said.

Sanchez focused his argument on two initiatives, one an institutional effort and the other creating a roadmap for successful implementation of technology. The technological initiative focused on developments in bio-energy with carbon capture and storage (BECCS).

The institutional effort focused on Mission Innovation, a 23-country commitment established in 2015 to double their annual combined public funding of clean-energy research and development from $15 billion per year to $30 billion per year by 2021.

Consistency is Key

He identified three “waves” of clean-energy investment in the past 70 years that failed to take hold permanently: nuclear energy following World War II; nuclear, renewables and energy efficiency in response to the oil crisis of the 1970s; and renewables, carbon sequestration, efficiency and grid upgrades in the 2000s.

Following each spurt of investment, there was a “dramatic retrenchment” in private funding as projects failed to deliver on their promises, he said.

“I think the lesson of the past two waves of energy innovation is that capricious funding — funding that ramps up and then ramps down very quickly — can really stall the pace of innovation,” he said. “Following World War II, the U.S. and the European Union in particular really focused on research and development of nuclear energy technologies. … We really kind of settled on standardized technology pretty quickly, and then dramatically reduced our R&D funds.”

Sanchez sees Mission Innovation having the potential to spur a fourth investment wave and says a clear, consistent path will be necessary to sustain it. That will include a centralized, independent headquarters, along with public visibility of R&D expenditures and better coordination among countries. For example, the U.S. and China have been collaborating for the past eight years on clean energy research centers, but in the past five years, no joint patents have been filed nor have any projects truly been jointly funded, Sanchez said.

“Essentially, the U.S. funded their technologies; China funded their technologies. They shared a little bit of information, but it really wasn’t joint, collaborative R&D in the way we’d really like to see,” Sanchez said.

BECCS

Sanchez focused on BECCS as a likely candidate for the next investment wave. He pointed out that just one facility in the world — an Archer Daniels Midland corn-to-ethanol plant in Decatur, Ill. — is employing the technology to sequester about 1 million tons of carbon dioxide a year, accounting for about 1/10,000th of the worldwide reductions that are estimated to be necessary.

“It’s fair to say there’s a very large gap between where we want to be and where we are right now,” he said.

Critics have said experimenting with sequestration could delay deployment of emissions technologies and even provide tacit acceptance of additional emissions. But Sanchez said that perspective misses the “market opportunity” that could be created by planning the development and deployment of the technology — essentially creating a roadmap for its successful implementation.

Next Steps

Sanchez said whether researching technologies or getting them deployed deserves more focus is the wrong question. “I think a lot of people frame this as an either/or question, but I think it’s silly … because it’s pretty obvious we really need both,” he said. “There’s not really enough time in the day to really fight those fights.”

He pointed to gasification of coal and biomass as technologies with high commercial potential because of their ability to balance carbon-reduction product costs and scale facilities. However, the necessary research will require collaboration among public and private organizations. He offered as a successful model the National Nanotechnology Initiative, which coordinates the work of 13 federal agencies and industry groups in addition to performing regulatory and public outreach.

Combining lessons learned from the BECCS and Mission Innovation initiatives, Sanchez said, could “fill the gap between our ambitions and where our technologies lie right now.”

‘No Clear Rationale’

Ratepayers Outgunned

Proposal

‘Robust’ Analysis Needed

Rate Impact

Merchant PPAs

Riders

Legislative Change Sought

More Questions than Answers

No Timetable for Return

‘Objective Standard’ Rejected

Nov. 21 Ruling

Monitor Seeks Sunset

Duke Energy ROE Reduced

FERC Declines PURPA Case

Consistency is Key

BECCS

Next Steps