Texas PUC Expresses Doubts over NextEra-Oncor Deal

By Tom Kleckner

NextEra Energy’s bid to acquire Texas’ largest electric utility, which cleared a U.S. bankruptcy court earlier this week, may have to navigate some choppy waters with state regulators.

At the Public Utility Commission’s open meeting Thursday, Chairman Donna Nelson and Commissioner Ken Anderson both expressed concerns with NextEra’s proposed $18.7 billion purchase of Oncor.

Anderson said his concern is with the $275 million termination fee to be paid to NextEra should the company be out-bid by a last-minute competitor, or if the commission rejects the sale or imposes overly “burdensome” conditions. Nelson said she was concerned about the impact on competition.

Anderson said he has no problem with the termination fee itself, but with how it is structured.

“This merger agreement … appears to be an effort to really tie the commission’s hands in the proceeding,” he said. “If I read the merger agreement and if the commission rejects the transaction in its entirety as not in the public interest, subject to some caveats, there’s no termination fee.

“If, on the other hand, the commission purports to approve it, but with what they call burdensome conditions … that could have a material adverse effect on NextEra or its credit rating … the result is they could walk the deal and get $275 million. Now that’s an extraordinary requirement.”

‘Offended’

“I have frankly been offended by [the merger agreement], but it is what it is,” Anderson added. “I don’t know where the $275 million is coming from, but it can’t be from Oncor’s ratepayers.”

Anderson said he wanted to explain his concern “so the potential applicant, if it wants to, can address them.” The commissioner admitted he has not reviewed the merger agreement in detail, but he promised to file a memo “maybe” next week that fully explains his viewpoint (Docket No. 42750).

“Burdensome” conditions sank a previous bid to buy Oncor from its bankrupt parent, Energy Future Holdings, when creditors objected to the PUC’s conditional approval in March of Hunt Consolidated’s offer. One of the commission’s requirements was that the Hunt group share potential tax savings with the utility’s ratepayers. (See Hunt Reopens Oncor Bid in Lawsuit Against PUCT.)

For her part, Nelson said she is concerned with the deal’s tax implications and its effect on ERCOT’s competitive market. The Internal Revenue Service earlier this summer issued a ruling that eliminates a potential $4 billion tax liability for its remaining assets, power generator Luminant and electricity retailer TXU Energy.

Anderson noted that NextEra has “substantial competitive assets” in ERCOT that could give the company an unfair advantage, a position Nelson agreed with. Brandy Marty Marquez, the PUC’s third member, was silent during the discussion.

“As this transaction has progressed, it does feel in many ways like a step backwards … with respect to [Oncor’s] ownership,” Nelson said. “The reason the [ERCOT] market is restructured the way it was with separate and regulated [transmission and distribution providers] was to grant generators and retailers access to customers and a way of serving those customers.”

Oncor is not a separate, unbundled company like most in the ERCOT market. As part of EFH’s leveraged buyout of TXU Corp. in 2007, the commission required Oncor to be ring-fenced from its sister companies with a separate, independent board of directors.

“The utility press says part of the reason NextEra buys Oncor is they continue to invest in generation and take advantage of the production tax credits,” Nelson continued. “I do want to look at those, as well.”

An Oncor spokesman declined to comment on the commissioners’ statements.

OK from Bankruptcy Court

On Sept. 19, NextEra won approval from the U.S. Bankruptcy Court in Delaware of its bid for Oncor after increasing its offer by $300 million in cash. The company said it would also make other changes to satisfy EFH creditors (Docket No. 14-10979).

EFH’s legal counsel told U.S. Bankruptcy Judge Christopher Sontchi during a hearing that unsecured creditors will now receive an additional $450 million. NextEra will pay $4.4 billion in cash for Oncor and assume its debt and other liabilities, including funding $9.5 billion for the repayment of EFH debt. Oncor was valued at $18.4 billion before NextEra added its sweetener.

After the collapse of the Hunt group’s bid, NextEra announced in July it had reached an agreement with EFH to purchase its 80.25% stake in Oncor. The other 19.75% is owned by an investor group led by Borealis Infrastructure Management and Singapore’s GIC Special Investments. (See NextEra Reaches Deal for Oncor.)

NextEra says it expects to file a joint application with the PUC “soon,” and that it expects the transaction to close in the first quarter of next year.

“Our proposed transaction provides Oncor with a financially strong, utility-focused owner that shares Oncor’s commitment to providing customers with affordable, reliable electric delivery service and significant value and certainty for the EFH bankruptcy estate,” NextEra CEO Jim Robo said in a statement.

NextEra said the deal is subject to bankruptcy court confirmation of EFH’s Chapter 11 reorganization and approval by FERC and the Texas commission, as well as “other customary conditions and approvals.”

NextEra shares have gained $4.72 since Monday, closing at $128.03/share Thursday.

The Hunt group remains unfazed by NextEra’s progress, with spokesperson Jeanne Phillips saying Hunt “will continue to work with all stakeholders to develop a Texas-based solution for the purchase of Oncor.”

EFH has been struggling to emerge from bankruptcy for more than two years now. It has proposed to sell Luminant and TXU to senior creditors owed $24.4 billion. Another hearing is scheduled in bankruptcy court next Monday.

September 23, 2016

FERC Approves GMD Reliability Standard

By Michael Brooks and Rich Heidorn Jr.

WASHINGTON — FERC on Thursday approved a NERC reliability standard requiring grid operators to assess and protect against the threat of geomagnetic disturbances (RM15-11).

The final rule (Order 830), effective 60 days after its publication in the Federal Register, is nearly identical to the commission’s proposed rulemaking issued in May last year. Under the rule, certain transmission owners and planners will be required to assess the vulnerability of their systems to a “benchmark” GMD event, defined as a one-in-100-year occurrence. They would then need to submit plans to mitigate the identified vulnerabilities. (See Questions and Answers on NERC’s Proposed GMD Rules.)

NERC will also need to submit a work plan within six months of the rule’s effective date detailing how it will study GMD events in general, “given the limited historical geomagnetic data and because scientific understanding of such disturbances is still evolving,” FERC said.

“While we recognize that scientific and operational research regarding GMD is ongoing, we believe that the potential threat to the Bulk Electric System warrants commission action at this time, including efforts to conduct critical GMD research,” the commission said.

GMDs, caused by solar events that disrupt the planet’s magnetic sphere, are considered “high-impact, low-frequency” events.

Response to Comments

FERC’s original Notice of Proposed Rulemaking questioned certain aspects of NERC’s proposed standard, TPL-007-1, including its reliance solely on spatial averaging to calculate the size of the impacted area in the benchmark event.

In comments submitted in response to the NOPR, NERC and other industry stakeholders defended the standard’s methodology for the benchmark definition, but FERC said they did not provide any new information.

“NERC and industry comments largely focused on the NOPR’s discussion of one possible example to address the directive” to modify the calculation so that it did not rely solely on spatially averaged data, FERC said. “However, while the method discussed in the NOPR is one possible option, the NOPR did not propose to direct NERC to develop revisions based on that option or any specific option.”

The commission gave NERC 18 months to make those revisions, as well as to modify the standard to require that data from geomagnetically induced current monitors and magnetometers be made public and to establish specific deadlines for mitigation plans.

In a few cases, FERC declined to direct NERC to make revisions it had considered in the NOPR, instead including them as part of NERC’s study homework.

For example, the commission had questioned whether the benchmark definition should also be modified to reflect that GMDs could have pronounced effects on lower geomagnetic latitudes. While it said that commenters who defended the original calculations did not provide any new information, the commission declined to direct NERC to revise the latitude scaling factor, saying it found “sufficient evidence to conclude that lower geomagnetic latitudes are, to some degree, less susceptible to the effects of GMD events.”

The final rule represents the second stage of the commission’s effort to protect against GMD, an effort that began in May 2013 with Order 779. The first stage, approved in June 2014, dealt with developing operating procedures for responding to GMDs and mitigating their effects.

Data Lacking

Commissioner Cheryl LaFleur called last week’s order “a milestone reflecting over five years of work by the commission, our staff, NERC, industry and stakeholders to address the threats posed” to the grid by GMDs. “It’s not the beginning of the end but the end of the beginning. We still have a lot of work to do.”

LaFleur said the rule “appropriately balances the need for action on this important issue with a recognition that our understanding of the science around GMD events and their operational impacts on the grid is still evolving.”

“One of the things we found frustrating in our tech conferences in developing the final rule was that so much of the magnetometer and monitoring data was from Canada or Europe when in fact we have one of the most highly developed electric grids in the world and very little public data on which to base our analysis.”

Situational Awareness Requirements

The commission also gave final approval to reliability standards IRO-018-1 and TOP-010-1, which specify requirements for the real-time reliability monitoring and analysis capabilities of reliability coordinators, balancing authorities and transmission operators (RD16-6).

The standards implement Order 693, which specified operators’ minimum capabilities, as well as the recommendations contained in a 2008 NERC best practices report and the joint FERC-NERC report on the 2011 Arizona-Southern California outage.

FERC noted that inadequate situational awareness was identified as one of the key causes of the 2003 Northeast blackout.

The joint report on the Arizona-Southern California outage recommended that entities “should take measures to ensure their real-time tools are adequate, operational and run frequently enough to provide their operators the situational awareness necessary to identify and plan for contingencies and reliably operate their systems.”

NERC said the new standards build on existing requirements by requiring applicable entities to provide them with indications of the quality of information being provided by their monitoring and analysis capabilities and notify them of real-time monitoring alarm failures.

Frequency Control Standards

The commission also gave preliminary approval to NERC’s proposed standard BAL-005-1 (Balancing Authority Control) and FAC-001-3 (Facility Interconnection Requirements), which it said would clarify and consolidate existing frequency control requirements (RM16-13).

The commission said the proposed standards “support more accurate and comprehensive calculation of reporting area control error (ACE) by requiring timely reporting of an inability to calculate reporting ACE and by requiring balancing authorities to maintain minimum levels of annual availability of 99.5% for each balancing authority’s system for calculating reporting ACE.”

The NOPR also seeks the retirement of standards FAC-001-2 (Facility Interconnection Requirements) and BAL-006-2 (Inadvertent Interchange).

The commission said it was uncertain whether to support NERC’s proposal to also retire requirement 15 of standard BAL-005-0.2b (Automatic Generation Control), which requires the maintenance and periodic testing of backup power supplies at primary control centers and other critical locations. “Depending on the explanation received in comments, the commission may issue a directive in the final rule to restore the substance of requirement R15 in the reliability standards,” it said.

September 22, 2016

Competitive Power Ventures Lobbyist, Former Cuomo Aides Named in Bribery Indictment

By Ted Caddell

An executive for power plant developer Competitive Power Ventures, two former aides of Gov. Andrew Cuomo and seven others were named in a broad bribery indictment by federal authorities in New York on Thursday.

Peter Galbraith Kelly Jr., CPV’s head of external affairs and government relations, was named in the indictment. CPV is only identified as “the energy company” in the indictment, and the company itself was not a named defendant.

One of the former aides, Todd R. Howe, has already pleaded guilty to several charges, including extortion, wire fraud and conspiracy, and has agreed to testify against the others. According to the indictment and Howe’s plea arrangement, Howe arranged bribes to be paid by CPV and another company, COR Development.

The bribes allegedly came as CPV was arranging to build the 650-MW Valley Energy Center in Orange County, a combined cycle plant that was granted a certificate of public convenience and necessity a little more than two years ago. It is still under construction and is seen as necessary to relieve downstate transmission constraints.

The top target in the indictment is Joseph Percoco, who formerly held a $169,000-a-year post as Cuomo’s executive deputy secretary. He left the state payroll in January, taking a position at Madison Square Garden.

According to the indictments and a release issued by Preet Bharara, the U.S. Attorney for the Southern District of New York, Percoco is accused of taking more than $315,000 in bribes from Kelly and two executives with Syracuse developer COR Development, Steven Aiello and Joseph Gerardi.

Kelly did not return calls for comment by press time.

“CPV takes the charges handed down today very seriously,” the company said in a statement. “We are extremely disappointed in the alleged conduct, which is in direct contradiction to CPV’s core values and expectations of our staff. Braith Kelly is no longer employed at the company. We will continue to cooperate fully with this investigation until a final determination is made.”

The indictment also names Alain Kaloyeros, president of the State University of New York Polytechnic Institute, as being involved in what federal authorities called “two overlapping criminal schemes involving bribery, corruption and fraud in the award of hundreds of millions of dollars in state contracts and other official state benefits.”

According to the statement from Bharara, Percoco was experiencing financial problems at the time that CPV was seeking New York’s approval of the power plant. Kelly gave Percoco “expensive meals and a Hamptons fishing trip” in the beginning. But later, at Percoco’s request, CPV hired Percoco’s wife at about $90,000 a year for a job that didn’t require much work.

In exchange, according to the charging document, Percoco used his official position to help CPV get lower-cost emissions credits from the state for a plant the company was building in New Jersey, and he helped arrange a power purchase agreement with New York. As a result, CPV was expected to save about $100 million in development costs.

cpv — Artist rendition of CPV Valley Energy project *Source: CPV*

The indictment says Kelly hid the monthly payments to Percoco and his wife through a CPV consultant. Percoco is also accused of lying when he told CPV that he had received an ethics opinion from Cuomo’s office approving his wife’s hiring. He also hid the payments he received from CPV, failing to list them on financial disclosure forms.

News of the investigation broke earlier this year. (See CPV Power Plant Ensnared in Federal Corruption Probe.) At the time, CPV was named as a company that made payments to Percoco, but it wasn’t identified as a target of criminal charges.

Thursday’s indictment identifies Kelly as a co-conspirator, saying he “willfully and knowingly did corruptly give” Percoco bribes “in order for Percoco to influence regulatory approvals and funding related to the development of a power plant in Orange County, N.Y., and take other official action to benefit” CPV.

The rest of the indictment has to do with other attempts to subvert the state regulatory process, according to the release. The primary focus of the investigation is the so-called Buffalo Billion economic development program championed by Cuomo. Bharara’s probe began last fall. A centerpiece of that program is $750 million in direct state aid and tax credits to SolarCity, which is building a 1-GW solar panel factory, the largest of its kind in the Western Hemisphere, according to the state.

September 21, 2016

ERCOT Finds No Alternatives to Greens Bayou; RMR Rule Changes Advance

By Tom Kleckner

ERCOT will continue its reliability-must-run agreement with NRG Energy’s Greens Bayou Unit 5 after a solicitation produced no viable alternatives.

The Texas grid operator had solicited proposals for must-run alternatives (MRAs) after it entered an RMR contract with NRG Texas Power for its Houston-area unit, a 371-MW gas-fired plant, on June 2. (See ERCOT Seeks Alternatives to Houston-Area RMR Unit.) The contract is projected to cost the market $60 million.

ERCOT said the proposed MRAs it received by the Aug. 24 deadline would not “adequately meet the reliability need served by the Greens Bayou 5 unit.” The ISO received eight offers from four qualified scheduling entities (QSEs) with a combined capacity of 385.9 MW for most of the contract months, but it said some of those offers did not qualify as eligible MRA resources and the others did not provide an “acceptable solution to the reliability concern” necessary to replace Greens Bayou.

greens bayou, ercot — Greens Bayou *Source: NRG Energy*

The Greens Bayou RMR agreement addresses reliability concerns on a Houston-area transmission line. Under the agreement, the unit will remain available during summer peak demand periods through June 2018 to support system reliability under certain critical operating conditions.

ERCOT has said the $590 million Houston Import Project, scheduled to be completed by summer 2018, will solve the reliability concern.

RMR Rule Changes Proposed

Meanwhile, the Protocol Revision Subcommittee last week advanced three nodal protocol revision requests (NPRRs) related to ERCOT’s RMR procedures. They will be taken up next week by the Technical Advisory Committee, which in July rejected an NRG request to allow the economic dispatch of RMR units. (See “Pricing Change on RMR Units Rejected, Appealed to ERCOT Board,” ERCOT Technical Advisory Committee Briefs.)

NPRR788 modifies the RMR planning studies to include forecasted peak loads and introduces a new requirement that a potential RMR unit must have “a meaningful impact on the expected transmission overload” to be considered for an agreement.
NPRR795 creates a mechanism to refund capital expenditures funded by ERCOT under an RMR agreement, if the agreement is terminated. The refund would be based on the expenditures’ depreciated book value if the resource returns to commercial operations; otherwise, it would be based on the salvage value.
NPRR793 would clarify the reliability unit commitment process to ensure RMR units are not accidentally committed as a reliability unit before other resources. The revision request adds several responsibilities for RMR unit owners, revises RMR formulas and adds further clarifications.

Luminant, Calpine Notices

ERCOT, which already has more than 81,000 MW of capacity to meet the fall and winter’s expected peak demand of less than 59,000 MW, recently got news of an additional resource.

Luminant notified ERCOT on Sept. 14 that its 805-MW coal unit at Martin Lake in East Texas, which had been running only from May to late September, will now be available for year-round dispatch. The status change is effective Oct. 1.

The Texas grid operator has also reviewed Calpine’s notice that it would be suspending operations at its 400-MW, gas-fired Clear Lake Power Plant and determined the five steam and gas turbines are needed to support transmission system reliability. ERCOT will issue a final determination by Oct. 10.

September 19, 2016

Farm Family Wins Long Fight over Substation, Tx Lines

By William Opalka

ALBANY, N.Y. — A Rochester-area farm family scored unusual concessions on Thursday when state regulators approved a plan for a substation and power lines that removed previously approved facilities from their property (11-T-0534).

The New York Public Service Commission approved a modified Certificate of Environmental Compatibility and Public Need for the Rochester Area Reliability Project south of the city. The original plan approved by the PSC in 2013 would have taken arable land out of production from the Krenzer family farm, according to the family’s rehearing petition.

The plan also would have taken the most valuable land on the property used for farm infrastructure, according to the family. The family grows wheat, corn and soybeans on more than 3,000 acres.

$37M Increase

Avangrid, whose Rochester Gas & Electric is building the project, said the delays and changes will increase the project’s cost by $37 million to $291 million. The company said $23 million is related to changes in site costs, routing and structure types, with $14 million linked to the delay and extended construction timeline.

RG&E began eminent domain proceedings in 2011 to route the project through the farm.

The family says it was unaware of the proceedings for about a year, a charge RG&E denied. The family said it had informal meetings with RG&E representatives in their home in November 2011, but no definitive plans were discussed that indicated their property would be condemned.

The utility said it had a series of meetings with family members to discuss the project and produced a June 2011 letter sent to a family member that indicated financial compensation for the acquisition of the substation site.

transmission lines — © *fotokostic / 123RF Stock Photo*

After granting rehearing, the PSC appointed an administrative law judge in 2013 and conducted hearings in 2014, but efforts to negotiate a compromise were unsuccessful.

Negotiations restarted earlier this year, which culminated in a joint proposal filed in July. It was endorsed by the family, RG&E, PSC staff, and the state departments of Environmental Conservation and Agriculture and Markets.

Marie Krenzer told RTO Insider that Thursday’s order prompted “a lot of mixed emotions, but we were pleased with the outcome.” The family spent “well into six figures” on attorneys’ fees and other costs through the process, she said, money that they will not recoup.

“We didn’t know what we were taking on when we started this, but we knew this wasn’t right,” she said.

‘An Example of Government Working’

PSC officials lauded the outcome as an example of regulators responding to competing interests in a difficult case. “This is an example of government working,” PSC Chair Audrey Zibelman said at the meeting. “The commission listened to the Krenzers and took their concerns seriously” while also fulfilling its obligation to preserve system reliability.

“We didn’t really understand the nature of the local opposition,” Commissioner Gregg Sayre, a Rochester-area native, said at the meeting. “But once we did, I think we came up with a good result.”

Several local and state officials became involved, including U.S. Sen. Charles Schumer.

The affected property would have totaled about 670 acres. The substation would have taken 12 acres, while the remaining land would have been used for a “zig-zag” pattern of transmission lines across the farm’s productive fields, which would have cut the farm in half.

The order approved Thursday moves the substation from the Krenzer farm about 1 mile east to vacant land across the Genesee River. The routing of two new 115-kV lines eliminates the zig-zag route through the property and instead will go through land with a U.S. Department of Agriculture conservation easement to reach an existing New York Power Authority line.

The project calls for the construction of approximately 23 miles of new 115-kV transmission lines, reconstruction of 2 miles of an existing 115-kV line, a new 1.9-mile 345-kV line, a new 345 kV/115-kV substation and the improvement of three existing substations.

The new substation site will damage or destroy existing wetlands, so 17 acres of the Krenzers’ property will be used for site mitigation.

September 19, 2016

Maine PUC to Phase Out Net Metering

By William Opalka

Maine regulators last week proposed a 15-year phase-out of net metering for current rooftop solar systems and a 10-year limit for new systems.

The proposal came as a part of a rulemaking process that the Maine Public Utilities Commission hopes to complete by the end of the year and implement in 2017.

“In light of changes in the technology and costs of small renewable generation, particularly solar PV, we felt that opening a rulemaking process to consider changes to the rule was the prudent course of action to ensure that all ratepayers are treated fairly,” Chairman Mark Vannoy said in a statement.

The rulemaking also proposes gradually reducing compensation for new solar customers, increasing the size of an eligible customer facility by more than 50%, from 660 kW to 1 MW, and additional consumer protections.

House of Representatives Assistant Majority Leader Sara Gideon, a solar proponent who helped craft a compromise solar power bill that was vetoed by Gov. Paul LePage in April, blasted the PUC proposal.

“Maine needs a comprehensive solar policy. Unfortunately, the PUC’s narrow focus on a single part of the broader solar policy doesn’t help our state’s ability to open new markets that create jobs and lower costs for homeowners, businesses and communities,” Gideon said. “This past session’s solar bill did not simply look at net metering in isolation but was crafted to help our constituents who are clamoring for access to community, commercial and municipal solar. That responsiveness and broad view is why policymaking should be left to lawmakers.”

The net metering review was automatically triggered by a PUC rule after solar exceeded 1% of Central Maine Power’s installed capacity. The utility reported solar at 1.04% at the end of 2015.

September 19, 2016

MTEP 16 Proposes 394 Projects at $2.8 Billion

By Amanda Durish Cook

ST. PAUL, Minn. — MISO’s 2016 Transmission Expansion Plan recommends 394 projects totaling $2.8 billion.

The preliminary MTEP 16, unveiled at the Sept. 13 System Planning Committee of the Board of Directors, proposes:

114 baseline reliability projects valued at $734 million;
27 generator interconnection projects at $123 million, nine of which will be cost-shared;
One transmission delivery service project at $350,000;
One market efficiency project, the Huntley-Wilmarth 345-kV line project in southern Minnesota projected to cost $81 million; and
251 other projects driven by local needs at $1.8 billion.

Vice President of System Planning and Seams Coordination Jennifer Curran said the top 10 priciest projects in MTEP 16 are evenly distributed between MISO North and MISO South. Spending under MTEP 16 includes more projects than MTEP 15’s 334, but total spending would be $6 million less.

The projects are spread across all MISO quarters, with 33% in MISO South, 39% in MISO West (in parts of northwestern Illinois, Montana, South Dakota and Michigan’s Upper Peninsula and all of North Dakota, Minnesota, Wisconsin and Iowa), 22% in MISO East (in northern Indiana and Michigan’s Upper Peninsula) and the remaining 6% in MISO Central (in parts of Missouri, Illinois, Indiana and Kentucky).

The projects are also varied by type, with 44% of projects dedicated to upgrading substation equipment, 28% dedicated to transmission line upgrades, 20% dedicated to the installation of new transmission lines, 5% dedicated to transformer upgrade and replacement and 3% dedicated to voltage control improvements.

Curran said the lone market efficiency project submitted for approval, the Huntley-Wilmarth 345-kV line, will accommodate wind additions in Iowa and Minnesota. Curran said the cost of the project, which was recommended by North/Central Market Congestion Planning Study and has benefit-to-cost ratio of 2, would be spread 20% across the MISO North and Central regions, with the rest allocated to the local zone. MISO South does not yet share in cost allocations for market efficiency projects.

Board member J. Michael Evans asked why the project wasn’t built 20 years ago if it was meant to handle wind power. Curran said the project will be constructed primarily for new wind buildout.

Board Chair Judy Walsh asked if the MTEP would always involve an expensive bundle of transmission upgrades that chases new generation locations. Vice President of Transmission and Technology Clair Moeller said MISO’s multi-value project category seeks to predict the location where transmission is most needed.

Curran said if approved, MTEP 16 may contain a hitch because the $80.9 million Huntley–Wilmarth line project is located wholly inside Minnesota, which has a right-of-first-refusal statute. Curran said that while the project “by definition is eligible for the competitive transmission process,” Order 1000 and MISO’s Tariff respect state and local laws.

MTEP 16 also includes four economic projects resulting from MISO’s South Market Congestion Planning Study:

An $88 million 230-kV line and substation in southeastern Louisiana with a 1.96 to 3.40 B/C ratio, to be in service by 2022;
The $1.9 million Minden–Sarepta 115-kV line upgrade in northwestern Louisiana with a 1.83 B/C ratio to be in service by 2020;
The $7.6 million Trumann–Trumann West 161-kV line project in northeastern Arkansas with a 13.4 B/C ratio to be in service by 2018; and
The $6.7 million Lakeover 500/230-kV transformer upgrade in southeastern Louisiana with a 1.4 B/C ratio to be in-service by 2020.

Costs for the four projects will be assigned to the local zones that they benefit.

MISO’s Planning Advisory Committee members will vote on the MTEP 2016 report in October. A MISO review of sector feedback will begin in November before the board votes at its December meeting.

“You know, Ernest Hemingway wrote his best novels when he was young, but MTEP keeps getting better. MTEP 16 is better than MTEP 15,” Evans said.

September 19, 2016

Consumer Advocates Challenge Nuclear Subsidy Cost Estimates

By William Opalka

AARP and the Public Utility Law Project want New York regulators to provide more documentation to justify the Clean Energy Standard’s estimated $2/month rate increase for the average consumer.

The groups wrote to the New York Public Service Commission last week, saying the commission’s Aug. 1 CES order did not explain the costs to keep upstate nuclear power plants operating with zero-emission credits. (See New York Adopts Clean Energy Standard, Nuclear Subsidy.)

“AARP and PULP are very concerned that the Clean Energy Standard implementation (particularly the subsidy for power plants) may have costly impacts on New Yorkers already facing among the highest electricity rates in the nation,” the letter states. “The mention of a potential $2/month residential bill impact from the Tier 3 purchase of zero-emission credits in the order was not accompanied by any details or citation to where such an estimate was derived and fails to provide sufficient cost and bill impact information for each customer class, for each utility, or for the entire 12-year commitment to support these power plants.”

The groups cite estimates by PSC staff that the ZEC program could cost up to $8 billion over its 12-year term.

They also cite other utility programs that will be borne by ratepayers, including a $1.5 billion smart meter program in the Consolidated Edison territory, cost recovery for distributed energy demonstrations projects and $5 billion for clean energy and energy efficiency programs run by the New York State Energy Research and Development Authority.

These cases and the CES “simply cannot be viewed separately,” the groups add.

The letter comes days after downstate legislators complained that the ZEC program costs were disproportionately burdensome on New York City-area ratepayers. The PSC pushed back in a reply, saying the economic benefits and reduced emissions benefited ratepayers statewide. (See New York Legislators Question Nuclear Subsidy.)

September 19, 2016

PJM Planners Seek Input on Order 1000 Process

By Rory D. Sweeney

VALLEY FORGE, Pa. — PJM’s Planning Committee held a special session last week to begin soliciting stakeholder input on changes to the RTO’s selection process for Order 1000 projects.

The goal of the ongoing sessions is to develop consensus on how decisions are made prior to the opening of the Regional Transmission Expansion Plan’s long-term proposal window Nov. 1, said Steve Herling, PJM’s vice president of planning and chair of the committee. The window, for market efficiency projects, will remain open through March 2017.

Eventually, the rules will be incorporated into PJM’s governing documents and receive FERC approval, but Herling acknowledged “there’s no way in the world that we’re going to have this approved at FERC before Nov. 1.”

At the meeting, PJM staff explained their concepts for the process, outlined a workflow diagram and highlighted a variety of examples to help stakeholders understand how PJM is likely to evaluate proposals.

“We’re trying to lay out our past thinking on this,” Herling said, “but … one of the whole points of this exercise is to start collecting metrics that you think need to be” included.

PJM hopes the input will provide perspectives it hadn’t considered so that proposals receive accurate, fair comparisons. While staff is attempting to be holistic in its evaluations, “we can’t say with absolute certainty that there won’t be a question raised by one of you that [shows] we missed some key benefit of one of your projects,” Herling said.

The RTO’s first Order 1000 project, the stability fix for Artificial Island in New Jersey, has been the subject of years of controversy and delay, both over PJM’s developer selection process and the resulting cost allocation. (See PJM Board Halts Artificial Island Project, Orders Staff Analysis.)

For market efficiency projects, PJM factors net load payment benefits, production cost benefits and overall PJM congestion benefits into its evaluation and requires a benefit-to-cost ratio greater than 1.25 to pass. Proposals that pass the B/C test then get evaluated for congestion reductions and overall changes, load payments, production costs and associated sensitivities, such as gas and renewable penetration, carbon policy and import/export requirements.

Stakeholders asked that development cost be considered and requested as much quantitative guidance as possible. They voiced concern about how carbon dioxide assumptions, forecasted long-term benefits and proposals offering cost caps are factored into the evaluation.

“We can’t have economic thinking thrown out the window here once a project crosses the B/C ratio,” Sharon Segner of LS Power said. PJM’s Suzanne Glatz pointed out that projects estimated to cost more than $50 million require independent cost analyses and constructability analyses.

“We do reserve the right to kind of break [proposals] down and put them back together to create a better, more cost-effective solution,” Herling said.

Further meetings on this topic are scheduled for Oct. 3, Oct. 21 and Nov. 11, during which PJM staff will introduce the regional metric for project selections.

September 19, 2016April 2, 2025

Monitor: NYISO Needs Locational Focus, Flexibility — not Forward Capacity Market

By Rich Heidorn Jr.

SARATOGA SPRINGS, N.Y. — A forward capacity market may have worked for PJM and ISO-NE, but it isn’t the solution for NYISO, the Market Monitor told the Independent Power Producers of New York’s fall conference last week.

PJM and ISO-NE officials told an audience of about 100 that their forward markets have successfully incented new generation to replace retirements in their regions.

But The Analysis Group’s Paul Hibbard said the consulting firm’s 2015 study for the ISO found no compelling benefit to changing from New York’s current monthly prompt auctions. “We couldn’t find in our analysis … a real overwhelming level of support or level of rationale for … going through the effort of moving to a forward capacity market design,” said Hibbard, who moderated the session.

And Pallas LeeVanSchaick of Potomac Economics said instituting a forward market would be a time-consuming distraction from addressing the ISO’s biggest problems.

The Monitor called for “more logical local capacity requirements” and predefined capacity zones “so that resources know that if they come into a particular area to meet a reliability need … that there’s an economic signal that they’ll be rewarded for helping to satisfy.”

“Those would be important whether you have a spot market for capacity or a forward capacity market,” he added.

The Monitor made recommendations on those issues in its 2015 State of the Market report in May. (See NYISO Monitor: Modify Capacity Export Planning.)

Reluctant Converts

Robert Ethier, vice president of market operations for ISO-NE, said his RTO was forced to accept the forward capacity model in FERC-moderated settlement talks. “We were actually focused on a monthly market with a sloped demand curve much like you have here in New York,” he recalled.

Despite its origins, and the repeated changes to market rules since then, Ethier said, “it’s working pretty well.” The RTO says it has attracted 4,700 MW of new capacity resources — versus 4,200 MW of retirements — since 2013.

“That’s sort of the bottom line … for a capacity market: Is it getting you new resources to replace the resources that are exiting the market?” he continued. “At that high level, it’s been successful.”

Among the changes ISO-NE made was adjusting the calendar to address a disconnect in the auction timeline.

Retirements had been allowed up to one month before auction, while new resources had to declare their intent to enter the market a year in advance. Because it was impossible for new resources to respond to late-announced retirements, the RTO found itself with capacity shortfalls in Forward Capacity Auctions 8 and 9.

In April, FERC approved rules requiring retiring generators to declare their intention in March rather than October, while moving the “show of interest” deadline for new capacity market entrants from February to April. (See FERC Approves Changes to ISO-NE Retirement Rules.)

‘Not Here to Sell Anything’

Also on last week’s panel was Stu Bresler, PJM’s senior vice president of operations and markets, who responded to LeeVanSchaick’s criticism by making it clear “I’m not here to sell anything” to NYISO. He also acknowledged that PJM’s Reliability Pricing Model is “not immune” to changes, an apparent reference to a call by some stakeholders for an overhaul. (See Proposal to Revisit PJM Capacity Model Receives Tepid Response.)

But he noted that PJM has added almost 17,000 MW of capacity resources in the last five Base Residual Auctions, well in excess of the less than 2,500 MW of retirements announced. “If we didn’t have the forward capacity market, we’d have needed something else” to attract the new supply, he said.

The new resources mean that PJM, unlike NYISO and MISO, has rarely had to rely on reliability-must-run units. “If you define your region and your locational requirements for capacity sufficiently, you may have [only] some extremely localized issues that … will require some minor out-of-market actions.”

Ethier said ISO-NE has never had to invoke “backstop intervention” for reliability and has limited authority to do so. The capacity market, he said, is what ensures reliability.

“It focuses the mind and sharpens the pencil when you’re playing without a net,” he said.

Different Era, Different Needs

LeeVanSchaick said, however, that the concerns that prompted the capacity markers in the neighboring RTOs don’t apply to New York today.

Unlike the rapid load growth eras in which PJM and ISO-NE developed their capacity markets, New York is facing very little load growth, and new renewable resources are entering the market, driven by public subsidies, he said.

LeeVanSchaick also said the one-year commitment with a three-year forward time horizon is a bad fit for existing resources considering making capital investments they expect to pay back in five to 10 years. “And … the time frame in which they would make that decision is not three years ahead; it might be more like one year ahead,” he added. Forward markets don’t “line up well with those investment decisions, certainly not with the time frame in which demand response providers are looking to increase or decrease their position in the market.”

He said the ISO also needs to increase its reliance on the energy and ancillary services markets to recognize the value of more flexible resources needed to supplement intermittent generators.

And he called for tougher rules on buyer-side mitigation and combatting uneconomic retention.

Cost, Time

The Analysis Group’s Hibbard said his firm’s report estimated it would cost $10 million and take three years to create a forward capacity market.

Both Ethier and Bresler said the additional administrative costs of the forward auctions are insignificant given the size of their $3 billion and $7 billion-plus markets, respectively.

Ethier estimated the forward market increased ISO-NE’s administrative costs by about $1 million annually compared to a prompt market. Bresler said seven PJM employees administer the RPM.

But Ethier acknowledged LeeVanSchaick’s concern about the “opportunity cost” of implementing the market.

“It basically slid all our initiatives out a couple of years. We would have had hourly markets much sooner, for example.”

LeeVanSchaick said the rationing of resources to pursue market initiatives suggests “the ISO budgets are lower than maybe the efficient level of funding for an ISO. … There’s often haggling over a small amount of money to develop a new project [even though] any of the projects that we’re talking about could potentially pay for themselves from the social welfare standpoint in a matter of months.”

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