Page 1655 – RTO Insider

April 25, 2016

FERC Affirms Entergy Refund Order on Off-System Sales

By Tom Kleckner

FERC last week affirmed its 2012 ruling requiring Entergy to make refunds to ratepayers because of an improper allocation of the sources of off-system energy sales between 2000 and 2009.

The commission denied in part and granted in part requests for rehearing by Entergy Services and the Louisiana Public Service Commission (EL09-61-003).

The PSC set the proceedings in motion with a 2009 complaint alleging Entergy and its affiliates violated their system agreement and engaged in “imprudent utility conduct” when Entergy Arkansas sold excess electric energy to third-party power marketers and other non-agreement members. Entergy’s system agreement is a 1982 contract between the companies and Entergy Services that governs the planning and operation of the companies’ generation and bulk transmission facilities on a single-system basis.

An administrative law judge’s initial decision found Entergy Arkansas had violated the system, ordering refunds. FERC affirmed part of the decision, finding that although the agreement’s relevant provisions are “ambiguous,” it does provide authority for the individual companies to make opportunity sales for their own accounts.

The PSC and Entergy requested a rehearing of the decision based on four issues:

Was the commission correct in finding the system agreement permitted the opportunity sales?
Did Entergy violate the agreement in accounting for the sales?
Was FERC correct in ordering refunds?
Did the commission err in reducing the refund amount as a result of the PSC’s delay in approving a power purchase agreement between Entergy Louisiana and Entergy Arkansas?

FERC rejected Entergy and the PSC’s arguments on each of the first three matters, affirming its previous decision.

“Although the Louisiana commission argues that the system agreement prohibits opportunity sales through its provisions concerning the powers of the operating committee … it is notable that the Louisiana commission can point to no specific provisions that make such a prohibition,” FERC said.

Over-Recovery

However, the commission also rejected Entergy’s contention that no refunds were due to ratepayers because the matter involved a misallocation of costs among different companies rather than an over-recovery. “Entergy Arkansas’ off-system sales of low-cost energy from system resources had the effect of forcing up the rates of captive customers of other operating companies by precluding their purchase of the low-cost energy,” the commission said. “Those captive customers were essentially over-charged as a result of Entergy’s improper accounting under the system agreement and thus are due refunds.”

The commission also clarified that interest on refunds should be included in the payments, consistent with the commission’s general policy.

And it agreed with the PSC’s argument that the refunds should not be reduced by a 12-month period in which the Louisiana regulators delayed approval of a PPA between Entergy Louisiana and Entergy Arkansas. FERC said a more equitable approach would be to reinstate refunds for the 12-month period at issue, saying it could not “necessarily conclude” the PSC’s delay in processing the PPAs was so excessive the refund amounts should be reduced.

In a separate order, FERC set further hearing procedures to determine the final allocation of refunds, which the Louisiana commission has estimated at $77.5 million (EL09-61-002). Entergy contends the amount should be less than $25 million.

The commission agreed with the ALJ that a full re-run of Entergy’s intra-system bill was necessary to provide a fair accounting of damages. FERC found the damages should be altered to reflect adjustments to service schedules and other provisions in the system agreement, including for bandwidth payments.

Entergy’s companies essentially operate as one system, although each has different operating costs. Low-cost companies make annual payments to the highest-cost company, using a “bandwidth” remedy that ensures no operating company has production costs more than 11% above or below the system average. Regulators in Entergy’s states have regularly challenged the annual bandwidth filings, which began in 2007.

April 23, 2016

New York Environmental Department Rejects Constitution Pipeline

By William Opalka

New York environmental officials on Friday denied a water quality permit for a 124-mile pipeline that would have delivered shale gas from Pennsylvania to markets in eastern New York and New England.

The New York Department of Environmental Conservation said developers of the Constitution Pipeline failed to address regulators’ concerns during a yearlong review.

The water quality permit, which is required under Section 401 of the federal Clean Water Act, was the last regulatory approval needed by Williams Partners and its co-developers, Cabot Oil & Gas, Piedmont Natural Gas, and WGL Holdings, for the pipeline through northeastern Pennsylvania and New York.

FERC approved the pipeline in December 2014, but developers lost the 2016 construction season when FERC would not allow limited tree cutting along the project route after New York officials protested because of the lack of the Section 401 permit. (See Constitution Pipeline Delayed Nearly a Year.)

Failed to Address Environmental Concerns

The DEC said Constitution’s “application fails in a meaningful way to address the significant water resource impacts that could occur from this project and has failed to provide sufficient information to demonstrate compliance with New York state water quality standards.”

Constitution said it “will pursue all available options to challenge the legality” of the decision. The project was intended to deliver 650,000 dekatherms of natural gas per day to the Wright, N.Y., compressor station for transport farther east.

“In spite of NYSDEC’s unprecedented decision, we remain absolutely committed to building this important energy infrastructure project, which will create an important connection between consumers and reliable supplies of clean, affordable natural gas. We believe NYSDEC’s stated rationale for the denial includes flagrant misstatements and inaccurate allegations, and appears to be driven more by New York state politics than by environmental science,” the company said in a statement released Monday.

The department blamed the company for failing to adequately address its concerns about the project’s impact on 251 streams and 500 acres of forest. The denial also cited the short- and long-term effects of trenching during construction, the loss of shade critical to stream health and the impact the loss of vegetation would have on potential flooding.

“Although the department repeatedly asked Constitution to analyze alternative routes that could have avoided or minimized impacts to an extensive group of water resources, as well as to address other potential impacts to these resources, Constitution failed to substantively address these concerns,” the DEC wrote.

Constitution said it “voluntarily agreed” to incorporate re-routes, adopt trenchless construction methods, commit to trout stream restoration and spend $18 million for wetland mitigation and $8.6 million for migratory bird habitat restoration and preservation.

Tree Cutting

The department was also annoyed that it received reports that landowners, “possibly with Constitution’s knowledge, clear cut old-growth trees along the right of way for the pipeline, including trees near streams and water bodies, even after the FERC ruled that Constitution could not cut trees in the right of way.”

New York, Constitution Pipeline — First sections of Constitution Pipeline arrive in New York *Source: Constitution Pipeline*

Constitution said that allegation is “completely inaccurate and contradicts the third-party environmental monitors working on behalf of FERC.”

The DEC said it conducted a “rigorous review,” including receipt of 15,000 public comments.

Environmentalists lauded the decision.

“Gov. [Andrew] Cuomo’s rejection of the Constitution Pipeline represents a turning of the tide, where states across the nation that have been pressured into accepting harmful gas infrastructure projects by FERC may now feel emboldened to push back,” said Roger Downs, conservation director for the Sierra Club’s Atlantic Chapter. “Cuomo’s leadership could inspire a domino effect of related pipeline rejections as other states begin to put the protection of water and our climate before flawed energy projects that do not serve the public interest.”

Constitution’s rejection came two days after Kinder Morgan announced it was shelving its Northeast Energy Direct pipeline, which was to deliver Pennsylvania shale gas through New York, Massachusetts and New Hampshire. It cited an uncertain regulatory climate for the project as well as a lack of commitments from electric utility customers. (See Kinder Morgan Suspends Northeast Energy Direct Pipeline.)

April 21, 2016

Kinder Morgan Board Suspends Work on Northeast Energy Direct Pipeline

By William Opalka

Kinder Morgan said Wednesday it has suspended work on the Northeast Energy Direct pipeline, citing an uncertain regulatory climate and a lack of commitments from New England power generators to reserve capacity.

The $3.3 billion project, being developed by subsidiary Tennessee Gas Pipeline, was to deliver shale gas from Pennsylvania into New York, with a line also running through Massachusetts and New Hampshire. The Kinder Morgan board approved the project last summer and it sought federal approval late last year (CP16-21). (See Northeast Energy Direct Files for FERC Certificate.)

“The board’s initial approval was based on existing contractual commitments at the time by local gas distribution companies to purchase natural gas from the project, as well as expected commitments from additional LDCs, electric distribution companies and other market participants in New England,” the company said in a statement. “Unfortunately, despite working for more than two years and expending substantial shareholder resources, TGP did not receive the additional commitments it expected. As a result, there are currently neither sufficient volumes, nor a reasonable expectation of securing them, to proceed with the project as it is currently configured.”

The company conducted an open season last year to engage potential customers and received commitments for only 751,650 dekatherms per day of the pipeline’s 1.3 million dekatherms per day capacity.

A controversial aspect of the project, and that of another proposed pipeline, Access Northeast, is the proposal to have EDC ratepayers foot some of the project costs through their utility bills. (See Massachusetts Regulators Endorse Pipeline Contracts.) Massachusetts Attorney General Maura Healey has opposed the move, and similar proposals in other New England states have yet to be enacted.

“The New England states have not yet established regulatory procedures to facilitate binding EDC commitments, that the process in each state for establishing such procedures is open-ended and that the ultimate success of those processes is not assured,” Kinder Morgan added in its statement.

Project opponents were elated.

“It’s a rare thing to see a fossil fuel company admit there simply isn’t enough need for what they’re selling,” Conservation Law Foundation President Bradley Campbell said. “It is increasingly apparent that free market forces are rapidly driving us toward a clean energy future, and today’s decision by Kinder Morgan is a telling sign of things to come. Our environment, our economy and the health of our communities depend on continuing to see fossil fuels out the door.”

April 19, 2016January 23, 2024

Supreme Court Rejects MD Subsidy for CPV Plant

By Rich Heidorn Jr.

WASHINGTON — The U.S. Supreme Court today unanimously rejected Maryland regulators’ attempt to subsidize Competitive Power Ventures’ combined cycle plant in Charles County, saying it interfered with FERC’s jurisdiction over wholesale electric markets.

The court upheld a ruling by the 4th Circuit Court of Appeals, which found that Maryland’s contract for differences with CPV could distort price signals in PJM’s annual capacity auctions (Hughes v. Talen, 14-614, 14-623).

“We agree with the 4th Circuit’s judgment that Maryland’s program sets an interstate wholesale rate, contravening the [Federal Power Act’s] division of authority between state and federal regulators,” Justice Ruth Bader Ginsburg wrote for the court. She said the contract also violated the Constitution’s Supremacy Clause, which establishes that federal law preempts contrary state law.

In April 2012, the Maryland Public Service Commission ordered Baltimore Gas and Electric, Potomac Electric Power Co. (PEPCO) and Delmarva Power and Light to enter into a contract that guaranteed CPV — winner of a PSC competitive solicitation — an income stream so that it could finance the facility.

Contract for Differences

Under the contract for differences, CPV St. Charles’ revenues for the sale of 661 MW of energy and capacity would be compared to what the company would have received had the contract prices been controlling. If the contract prices were higher than the market prices, the three electric distribution companies would pay the difference to CPV; if market prices were higher than the contract, CPV would make payments to the EDCs.

The contract was challenged by Talen Energy’s predecessor, PPL, and other generators. The opponents said Maryland’s action would suppress capacity prices and that allowing the contract to stand would mean that eventually only subsidized units would enter the auction because those without support could not compete.

“FERC has approved the PJM capacity auction as the sole rate setting mechanism for sales of capacity to PJM and has deemed the clearing price per se just and reasonable,” the court said. “By adjusting an interstate wholesale rate, Maryland’s program invades FERC’s regulatory turf.”

Maryland and CPV contended the contract for differences was no different than traditional bilateral contracts for capacity, which FERC allows.

But the court said Maryland’s contract with CPV “does not transfer ownership of capacity from one party to another outside the auction. Instead, the contract for differences operates within the auction; it mandates that [load-serving entities] and CPV exchange money based on the cost of CPV’s capacity sales to PJM.”

The Supreme Court had declined to review a ruling by the 3rd Circuit Court of Appeals finding New Jersey regulators’ subsidy of a CPV generating plant also in violation of the Constitution’s Supremacy Clause (PPL EnergyPlus LLC, et al. v. Hanna, 11-0745).

Guidance for States

But the court did provide state regulators’ guidance for crafting their programs in the future, saying it rejected Maryland’s initiative only because it disregards FERC’s wholesale rate.

“We therefore need not and do not address the permissibility of various other measures states might employ to encourage development of new or clean generation, including tax incentives, land grants, direct subsidies, construction of state-owned generation facilities or re-regulation of the energy sector,” it said. “So long as a state does not condition payment of funds on capacity clearing the auction, the state’s program would not suffer from the fatal defect that renders Maryland’s program unacceptable.”

Justice Clarence Thomas concurred in the judgment but said the court did not need to cite “implied preemption” under the Supremacy Clause.

“To resolve these cases, it is enough to conclude that Maryland’s program invades FERC’s exclusive jurisdiction” under the Federal Power Act’s division of federal (wholesale) and state (retail) jurisdiction, Thomas wrote.

The court’s ruling was unsurprising. At oral arguments in February, none of the justices showed any support for Maryland’s stance. (See Supreme Court Offers Little Support to CPV, Md.)

EPSA, APPA, NARUC React

The Electric Power Supply Association, which had filed amicus briefs in support of federal preemption of the Maryland and New Jersey subsidy programs, called the ruling “a victory for the economic integrity and viability of wholesale power markets. The unanimous decision strengthens FERC’s hand at a critical time when it comes to properly defining the appropriate roles for federal and state actions impacting wholesale power markets.”

The American Public Power Association (APPA) called the decision “another regrettable setback for restructured states in Regional Transmission Organization regions that take seriously their obligations to ensure that their state’s retail customers have reliable, affordable and environmentally responsible electric service.”

The group said it was pleased, however, that the ruling was narrowly drafted “and does not impair the ability of public power utilities to serve their own retail customers with owned and contracted-for generation resources.”

Travis Kavulla, president of the National Association of Regulatory Utility Commissioners, said “the line between the federal and state jurisdictions appears largely unaltered” by the ruling.

“Following the Supreme Court’s logic, it seems possible that the state of Maryland could have accomplished substantially the same result of obtaining new generating capacity in the state, just so long as it did not condition the generator’s compensation on the wholesale market’s clearing price for capacity,” he said in a statement.

But Kavulla said the ruling will “inevitably will result in further litigation of these issues by leaving many open questions.”

“Someday soon, consumers, utilities, power generators, and regulators alike will need greater certainty about what is and is not permissible on the part of federal and state regulators. But today is not that day.”

April 18, 2016

FERC Approves Changes to ISO-NE Retirement Rules

By William Opalka

FERC last week accepted rule changes meant to prevent generation owners in ISO-NE from exercising market power by retiring resources that are still economic (ER16-551).

The commission approved revised Forward Capacity Market rules that will require retiring generators to declare their intention with de-list bids in March rather than October, while moving the “show of interest” deadline for new capacity market entrants from February to April.

The order also gives the Internal Market Monitor greater leeway in determining whether an economic generation resource is being retired to raise capacity prices.

“ISO-NE’s proposal includes several changes to the FCM timeline, which will benefit the market,” FERC wrote. “By requiring retirement bids to be submitted in March and by requiring ISO-NE to post shortly afterwards information regarding the amount of existing capacity that may exit the FCM, project sponsors that are considering developing new resources will have better and more timely information about when and where new capacity may be needed.

“By moving the show of interest window to a date after the retirement bid deadline, new entrants will be able to use the information about potential retirements to inform their decision on whether to enter the FCM in the next auction,” the commission said.

The rules will take effect with the 11th Forward Capacity Auction next year for the 2020/21 commitment period.

Generators submit de-list bids that specify a price below which an existing resource would not provide capacity. A static de-list bid signifies a one-year absence from the capacity market; a permanent de-list bid means the resource will exit the market. A capacity supplier wishing to permanently retire an existing resource regardless of price would submit a non-price retirement request.

IMM Review

The order also approved rule changes to address premature retirements of economic resources, a need ISO-NE said was identified by both its IMM and External Market Monitor. The RTO defines “uneconomic” retirement as the retirement of a capacity resource that would be expected to remain profitable if it continued running.

ISO-NE proposed that its IMM issue a determination on the reasonableness of generators’ cost assumptions and the appropriateness of their proposed bids. Based on that, the RTO will file with the commission either the supplier’s original bid or a mitigated bid.

Generators objected, saying the IMM should not be given such discretion, but FERC was not persuaded.

“The proposed reforms permit flexibility in the submitted forecasts and inputs of a retirement bid, so long as a supplier can show that those forecasts and inputs are reasonable,” FERC said. “We find that this process will not result in an undue preference for the IMM’s estimates of a supplier’s retirement costs, but rather will initiate a dialogue whereby suppliers would have the opportunity to demonstrate that their proposed inputs to their retirement bids are reasonable.”

Generators also contended there was no evidence of market power abuses in New England. But the commission said such proof was unnecessary.

“It is irrelevant whether suppliers have previously used physical withholding through retirement as a means to exercise market power. Our review here is limited to whether ISO-NE’s proposal is just and reasonable and not preferential or unduly discriminatory,” FERC wrote.

Brayton Point Allegations

The backdrop for the rule changes is the Utility Workers Union of America’s contention that the 1,517-MW Brayton Point plant in Massachusetts is being closed to raise capacity prices.

Energy Capital Partners did not offer the plant in capacity auctions for 2017/18 and 2018/19 after announcing the plant would close in 2017. Brayton Point was sold last year to Dynegy, which said it would close the plant as scheduled.

The commission has repeatedly denied union complaints seeking to have the results of FCAs 8 and 9 voided. (See FERC Again Rebuffs Brayton Point Union.)

On April 14, the union filed a new challenge, citing ISO-NE’s retirement rule changes to bolster its case for throwing out the results of FCA 10 (ER16-1041).

“As both ISO-NE and the commission have recently recognized … omitting ‘retiring’ capacity entirely from the calculation of the Forward Capacity Auction price, as has occurred here, rather than including it at a ‘proxy’ or other price which represents its true costs, results in the auction being non-competitive and the resulting prices not just and reasonable,” the union wrote.

April 18, 2016

Wind Growth Causes SPP to Take 2nd Look at Tx Projects

By Tom Kleckner

SANTA FE, N.M. — With wind energy reaching unprecedented penetration levels, SPP’s Markets and Operations Policy Committee asked staff last week to re-evaluate whether two transmission projects in the windy Texas-Oklahoma Panhandle region should have their need dates accelerated.

Staff had been hoping to receive approval to accelerate the two projects, a recommendation that had already been OK’d by three working groups. However, stakeholder concerns over a lack of technical input, outdated studies of wind energy and going outside normal planning processes caused the MOPC to request further staff analysis.

The motion was unanimously approved. SPP staff will return the recommendation to July’s MOPC meeting and will eventually need approval from the Regional State Committee.

“We can accommodate [the motion] and not impact reliability if we come back in July and make a decision,” said Casey Cathey, SPP’s manager of operations engineering analysis and support.

SPP said it set a new record for North American ISOs and RTOs when it registered a 48.32% wind-penetration peak April 5. (See “SPP Leapfrogs ERCOT with 48.32% Wind Penetration Mark,” SPP Briefs.)

SPP’s 2015 wind integration study recommended 19 transmission projects with notices-to-construct (NTCs) as candidates for acceleration. Ten of the projects have already been voluntarily sped up by transmission owners, four were found to be not feasible for acceleration and three were withdrawn as part of a near-term assessment and will be incorporated into the RTO’s new planning process.

The two remaining NTCs — a 230-kV Southwestern Public Service project in the Texas Panhandle and a 345-kV Oklahoma Gas & Electric project in West Oklahoma — were recommended for acceleration. Cathey said accelerating the projects will reduce existing congestion and ease voltage-collapse fears.

Existing Congestion

“Both [systems] have congestion on them right now. … It’s not wind coming three years from now,” Cathey said. “The longer we delay, the more your benefits are reduced.”

Cathey said SPS could shave half a year off its timeline without a cost to its sponsors, while the OG&E project could reduce its timeline by almost two years, saving $437,000 in the process.

The acceleration recommendation was approved by the Transmission, Economic Studies and Operating Reliability working groups.

Some MOPC members, however, expressed concern about re-evaluating projects outside the Integrated Transmission Planning (ITP) process and a lack of involvement by some of the working groups.

“I do not think the Tariff supports a re-evaluation or acceleration of an NTC outside of the ITP process,” Sunflower Electric Power’s Al Tamimi said in opposing the ESWG recommendation.

“My biggest concern is the lack of involvement, or minimal involvement, with the TWG through this process,” Westar Energy’s John Olsen said. “I get very uncomfortable sitting around this table to be making those kind of calls without having our technical folks review them.”

American Electric Power’s Richard Ross asked whether the re-evaluations could be conducted through SPP’s high-priority study process. The RTO can conduct up to three such studies a year at the stakeholders’ request.

“It seems we’re tying SPP’s hands here,” Ross said. “To me, it makes sense to accelerate these projects, if this is the proper way of doing this. Has legal bought off on sprinkling some high-priority magic dust on this?”

“It may be we need a supplemental analysis to warrant the two accelerations,” SPP Vice President of Engineering Lanny Nickell said. “Now we have to figure out a way legally to justify the acceleration of the projects in accordance with the Tariff. If the two TOs want SPP to direct acceleration, that’s a change in the planning processes.”

Wind Integration Study

The MOPC also unanimously approved staff’s proposed scope for a second phase of a wind integration study, but only after revising the recommendation to ensure the TWG and ESWG are included in the review process.

The study will build on last year’s analysis, with updated models and assumptions looking at wind cases as high as 60%. The results are to be published before next January’s MOPC meeting.

Cathey said the report is intended to be a reliability study rather than a high-priority study and will use 2017 planning models. He said the Electric Power Research Institute will help staff on the report, which will also use data from PowerTech Labs’ voltage security assessment tool.

“Phase II is about what we didn’t have time to assess in Phase I,” he said. “We’re trying to do something that’s [defensible] and accurate. We’d like to get a more dynamic, up-to-date look.”

Cathey noted that with firm transmission rights now part of SPP’s transmission congestion rights market, “We don’t know what firm rights are any more.

spp wind energy texas — Smoky Hills Wind Farm in Kansas *Source: Wikipedia*

“The wind blows, and it’s in the money. We’re backing down coal, and that’s the reality of what’s happening on the system.”

Cathey said he expects the study to recommend policy and procedure changes, but that it “won’t mandate anything.”

“There’s a good chance we’ll be at 60% wind penetration in 2017,” said Bruce Rew, SPP’s vice president of operations. “The sooner we can get [the study] done, the sooner we can be prepared for that.”

Staff said the study will cost approximately $145,000, but it is waiting on further information from vendors.

April 18, 2016April 2, 2025

FERC to Examine RTO Rules for Energy Storage

By Michael Brooks

FERC is seeking comment on energy storage’s participation in the wholesale energy markets, questioning whether RTOs’ rules are creating barriers for the resource (AD16-20).

The commission’s Office of Energy Policy and Innovation last week sent identical letters to each of the grid operators under its jurisdiction, requesting data on “the eligibility of electric storage resources to participate in the RTO and ISO markets; the technical qualification and performance requirements for market participants; required bid parameters; and the treatment of electric storage resources when they are receiving electricity for later injection to the grid.”

FERC staff simultaneously issued a request for comments on the same issues. Staff said it expects comments to take into account the RTOs’ responses to their data requests, which are due May 2. Comments are due May 23.

There have “been some key developments in the technology and cost-effectiveness of electric storage resources,” FERC staff said. “In light of these developments, staff is interested in examining whether barriers exist to the participation of electric storage resources in the capacity, energy and ancillary service markets.” The commission also expects to examine whether tariff changes are needed if barriers to participation exist, staff added.

“Many energy storage project developers have experienced difficulty in accessing wholesale markets. Grid operations and markets were not originally designed with energy storage in mind,” Jason Burwen, Energy Storage Association policy and advocacy director, said in a statement. “The Energy Storage Association supports efforts that increase access to wholesale markets for storage and establish market structures to realize energy storage’s full value in lowering system costs and increasing system reliability.”

5 Categories

The commission divided its questions to the RTOs into five categories:

Eligibility: Which types of storage resources are qualified to participate in the markets and which are not? Are there different rules for different types? If so, why?
Requirements: What are the minimum and technical requirements for storage to participate in the markets? What are the bases for these requirements (NERC reliability standards, for example)?
Parameters: What are the required bid parameters for storage resources? Are there any parameters unique to storage?
Distribution: Are there opportunities for aggregate storage resources or those connected at the distribution level to participate at the wholesale level? If so, what are they?
Load: When would storage be considered a buyer of energy in the wholesale markets? What are the requirements when storage resources purchase electricity? Are they required to pay LMPs? Are there circumstances when storage can receive electricity but not be considered load?

Current RTO Discussions

FERC also asked the RTOs if there are any ongoing discussions or pending rule changes concerning energy storage.

Here is a snapshot of where they stand:

CAISO last month asked FERC to approve a new Tariff provision that would allow storage and other distributed energy resources to participate in California’s energy and ancillary services markets. An ongoing stakeholder initiative is focused on refining the ISO’s market model to lower barriers for grid–connected DER. (See CAISO Tariff Change Would Extend Market to DER.)
ERCOT last year created a Distributed Resource Energy and Ancillaries Market (DREAM) Task Force, providing a forum for stakeholders and staff to develop market rules related to DER. The DREAM team has submitted a final report for the Technical Advisory Committee’s consideration at its April 28 meeting. (See “DREAM Task Force Submits Final Report,” ERCOT Technical Advisory Committee Briefs.)
ISO-NE has two large-scale pumped hydro storage facilities that can provide nearly 2,000 MW. The RTO developed a paper in January explaining how storage resources of at least 1 MW can participate in the energy and capacity markets. An updated white paper incorporating stakeholder feedback was released on March 31.
NYISO says it was the first grid operator, in 2009, to establish FERC-approved market rules for limited energy storage resources. Its energy limited resources classification allows a capacity provider to sell a minimum of 1 MW for at least four hours. Several other products participate in the ancillary market. The ISO’s Market Issues Working Group has begun a process to expand storage’s presence. In November, FERC accepted NYISO’s method for compensating Beacon Power’s 20-MW flywheel storage facility for frequency regulation (ER12-1653).
MISO is engaged in stakeholder discussions on incorporating storage into its markets. (See MISO Stakeholders Provide Ideas on Incorporating Storage.)
PJM is studying a way to remove barriers that distributed battery storage systems face when entering the markets. Currently, such resources have two options: interconnect as a generation source through the queue process or register as demand response. The review, prompted by a problem statement approved by stakeholders in February, will be limited to behind-the-meter generation of 20 MW or less. (See “Faster Path to Market for Distributed Resources to be Studied,” PJM MRC & Members Committee Briefs.)
SPP members are considering a staff proposal to create a technology steering committee as a forum for discussions on incorporating storage and other technologies. (See “More Detail Requested on Technology Committee,” Strategic Planning Committee Briefs.)

At the Gulf Coast Power Association’s spring meeting last week, Allan Stewart, executive director of North American power for PIRA Energy Group, predicted innovations in battery technology will start changing electric market fundamentals as soon as 2020 in California and Hawaii. (See “Energy Storage Ready to Disrupt Industry?”, Overheard at GCPA Annual Meeting.)

Robert Mullin, Suzanne Herel, Tom Kleckner and William Opalka contributed to this article.

April 18, 2016

PSEG Defends Artificial Island Cost Increase

By Suzanne Herel

Public Service Electric & Gas (PSE&G) on Thursday submitted a letter to the PJM Board of Managers defending the cost estimate for its share of the Artificial Island project, which has nearly doubled to $272 million.

pseg pjm Salem-Nuclear-Generating-Station-on-Artificial-Island-(Wikimedia)-for-slider — Salem Nuclear Generating Station on Artificial Island *Source: Wikimedia*

PJM planners, who say the increase could lead to a rebid of the project, expect to update the board on the project when it meets this week. (See Artificial Island Cost Increase Could Lead to Rebid.)

PSE&G told the board it was not involved in determining PJM’s initial cost estimate of $125.9 million, which later grew to $137 million.

‘Unusual’ Project

At the March meeting of the Transmission Expansion Advisory Committee, Vice President of Planning Steve Herling said PJM stood behind its choice of project for a stability fix at the New Jersey complex housing the Hope Creek and Salem nuclear reactors. The work is unusual, so PJM had little to compare it to, and the estimate didn’t reflect a design-level study, he said.

LS Power was chosen for the bulk of the project, which involves building a new 230-kV transmission line from the nuclear complex, under the river and into Delaware. PSE&G and Pepco Holdings Inc. were assigned upgrades necessary for the interconnection. LS Power says it is standing by its $146 million cost cap.

PSE&G said it didn’t begin preparing a detailed cost estimate for the 230-kV line terminating at the Salem substation until July, as its own proposals had the line ending at Hope Creek.

“PSE&G has clearly stated throughout this process that any work required to be done in Salem would be expensive and complicated,” the company said, citing a handful of communications supporting the assertion.

“Any proposal with work at Salem will be very challenging; the location of the switchyard controls and protection are located inside of the nuclear generating station,” it had told the board in July 2014.

In one of its proposals, it had said, “Due to experience with multiple historical baseline projects at Artificial Island, PSE&G can state that [Nuclear Regulatory Commission] governing requirements, critical site power maintenance and outage complexities, as well as known controls expansion limitations, will all contribute to design constraints potentially limiting a Salem expansion. PJM should carefully consider the implications of allowing such risks or costs to be understated or excluded from a total project cost comparison.”

At April’s TEAC meeting, planners said they are now considering alternate configurations, including terminating the new line at Hope Creek instead of Salem — a change in scope that could lead to rebidding for the project.

Tortured History

It was just the latest twist in the tortured history of the project, PJM’s first competitive solicitation under FERC Order 1000.

PJM planners originally recommended awarding the stability fix to PSE&G, but the board reopened bidding to finalists following protests from spurned bidders, state officials and others, leading to awards for LS Power, PSE&G and Pepco.

In November, FERC ruled that PJM’s proposed allocation of virtually all the project’s costs to ratepayers in Delaware and Maryland might not be just and reasonable (EL15-95). At a technical conference in January, commenters said PJM’s solution-based distribution factor cost allocation method was not appropriate for projects such as Artificial Island and the Bergen-Linden Corridor upgrade. (See Commenters: DFAX Cost Allocation Inappropriate.)

April 18, 2016

MISO Fields More Capacity Auction Questions

By Amanda Durish Cook

MISO continues to move forward with modifications to its capacity market even as some stakeholders question the need for the proposed changes and others seek more time to consider their implications.

RTO staff are aiming to file Tariff changes with FERC next month to implement seasonal and locational capacity constructs. MISO also proposed filing in July for the creation of a separate Forward Local Requirements Auction for deregulated regions in 2018.

That timeline sparked concerns for many market participants still skeptical of the proposed auction.

During an April 14 Resource Adequacy Subcommittee meeting, multiple stakeholders urged the RTO to postpone a filing for the FLRA based on the volume of questions regarding its design.

“There were a lot of good questions today, but MISO has essentially said, ‘We’ll consider them,’” said Marka Shaw, Exelon regulatory affairs manager. “I think there’s a lot of work to be done, especially [before] a July filing.”

MISO concedes that several design details for the FLRA have yet to be clarified. RTO staff have asked stakeholders for feedback about how congestion costs from the current Planning Resource Auction should be allocated to the FLRA, what the proposed auction’s demand curve should look like and what resource adequacy plan rules should be implemented. MISO is also seeking reactions to the idea of bifurcated capacity procurement — separate auctions covering regulated and deregulated areas.

Price Risks in Bifurcation

Skeptical of bifurcation, independent power producers are instead pushing for a single three-year forward auction for all of MISO.

Consumer advocates urged the RTO to delay auction changes until results from the MISO-Organization of MISO States survey on available capacity are released in July — or until a capacity shortage becomes imminent.

Jim Dauphinais of Illinois Industrial Energy Consumers is among the opponents to the FLRA proposal. During last week’s meeting, he contended that capacity price volatility can be best addressed by self-supply and bilateral contracts, pointing out that more than 65% of capacity in southern Illinois for the 2015/16 was procured by those means.

Dauphinais cautioned that the FLRA’s proposed downward-sloping demand curve could act as a “wedge” to inflate prices before MISO’s predicted capacity shortage in the 2021/22 planning year.

“There’s volatility even if it’s done three years in advance with a sloping demand curve,” Dauphinais said.

Kevin Murray, representing the Coalition of Midwest Transmission Customers, sought clarification on whether load-serving entities in deregulated areas could develop a forwardixed resource adequacy plan and make bilateral agreements to circumvent a forward auction altogether, something MISO says will be possible.

AARP’s Bill Malcolm questioned the need for what he called a PJM-style forward auction.

“We urge more study on the matter,” Malcolm said. “The rate impact on consumers should be fully vetted and be part of the discussion.”

Mark Volpe, Dynegy senior director of regulatory affairs, focused on price volatility risks to the downside. He pointed to what he considered a “fundamental flaw” in the forward capacity auction design: The value of capacity in MISO’s Zone 4 could approach zero as more generation projects come online in southern Illinois.

Jeff Bladen, MISO’s executive director of market design, said Volpe’s comment illustrated why the RTO is seeking feedback on bifurcated procurement.

“This is something we’re acutely aware of, but I can’t predict what the forward zone will look like,” Bladen said, referring to how the auction might clear.

According to Bladen, MISO will not seek a specific price outcome for the forward auction, but it does want results to fall within a target reliability range.

Bladen also said MISO wants stakeholder feedback on the shape of the FLRA demand curve.

Meanwhile, draft Tariff changes for MISO’s proposed seasonal and locational capacity constructs are almost complete, according to Renuka Chatterjee, MISO executive director of resource adequacy and transmission access planning. Still, the RTO could delay an expected July filing with FERC, depending on feedback from the Independent Market Monitor — and an unnamed MISO customer — regarding the creation of external resource zones.

The seasonal construct proposal outlines a single auction with two seasonal offers, while the locational construct sets out external resource zones. (See MISO Delays Seasonal, Locational Capacity Constructs.)

April 18, 2016

Pilgrim to Refuel Next Year, Close in 2019

By William Opalka

Entergy said Thursday it intends to refuel the Pilgrim nuclear plant next year and then cease operations on May 31, 2019.

Pilgrim Entergy Nuclear Power Plant — Pilgrim Nuclear Power Plant *Source: Entergy*

The company announced last year that the plant would close between 2017 and 2019 but deferred a decision on whether to perform one last refueling. (See Entergy Closing Pilgrim Nuclear Power Station.)

“The issue is that we have an obligation to provide the ISO-NE with power until that May 31, 2019, date. After looking at different options to best fulfill that commitment, we determined refueling Pilgrim was the most appropriate way for the company to meet the obligation,” spokesman Patrick O’Brien said.

At the time of the closure announcement, company officials said the plant’s annual revenue was projected to drop by $40 million a year because of low energy prices.

With a poor ranking for operational performance, the plant was also under increased scrutiny from the Nuclear Regulatory Commission. Meeting NRC requirements to continue operating would have required $45 million to $60 million in capital expenditures, the company said.

Cheap natural gas has depressed power prices and stressed nuclear plants throughout the country. Entergy closed its Vermont Yankee plant at the end of 2014. (See New Lifeline for FitzPatrick Nuclear Plant.)

The final refueling will be a brief boon for the local economy. Entergy said Pilgrim’s 2015 refueling outage required a $70 million investment in the plant, including $25 million in new equipment, and employed nearly 2,000 employees, including 1,184 extra contract workers.

Entergy said a team with decommissioning and Pilgrim plant experience will plan for the shutdown.

The 680-MW plant began commercial operations in 1972.