Page 1507 – RTO Insider

October 27, 2015

MISO Stakeholder Process Under Scrutiny

By Rich Heidorn Jr. and Suzanne Herel

WASHINGTON — MISO officials asked FERC staff last week to trust in its stakeholder process and not force capacity market changes that could increase exports, while the RTO’s Market Monitor and other critics called for the commission to force reforms.

FERC staff’s daylong technical conference on MISO’s capacity market — called in response to complaints by Illinois officials, industrial energy users and a consumer group — was dominated by technical discussions on zonal boundaries, capacity import limits and reference levels. But MISO’s stakeholder process also came under scrutiny.

MISO Market Monitor David Patton suggested only a FERC order would prompt the RTO to switch from a vertical to a sloped demand curve.

“For any change that involves large economic value, the stakeholder process can bog down,” Patton said. “And that’s definitely the case with the sloped demand curve.”

Patton suggested a FERC mandate — such as its 2014 order requiring a sloped curve in ISO-NE — might be necessary to prompt change.

“That reorients the stakeholders’ discussion. Folks who were obstructionist become part of the process of discussing how to implement something that would be effective and produce reasonable outcomes,” he said. “So while there is a stakeholder process [on capacity issues], the most important issues are not part of those discussions.”

‘Robust Stakeholder Process’

Patton’s comments came after MISO officials Renuka Chatterjee, executive director of interconnection planning and resource adequacy, and Jeff Bladen, executive director of market design, asked the commission to exercise caution.

Bladen said the commission shouldn’t take any actions that increase the number of MISO-based generators selling capacity into PJM.

Chatterjee said the RTO already plans to make two changes before its 2016 Planning Resource Auction. She asked the commission to allow MISO’s “robust stakeholder process” to develop long-term solutions.

That brought a retort from Tyson Slocum, director of Public Citizen’s Energy Program, who said the RTO’s stakeholder process “is heavily dominated by a few interests and … not reflective of broader stakeholders.”

The commission announced the technical conference Oct. 1 in response to complaints by Public Citizen, Illinois Attorney General Lisa Madigan, Southwestern Electric Cooperative and Illinois industrial energy consumers over MISO’s 2015 PRA in April. The auction saw a nine-fold price increase in Zone 4, which comprises much of Illinois.

FERC said the conference would help it “determine what further action, if any, may be appropriate” to address the complaints (EL15-70, et al).

At the same time, FERC announced a non-public investigation into “whether market manipulation or other potential violations of commission orders, rules and regulations occurred before or during the auction” (IN15-10). (See FERC Launches Probe into MISO Capacity Auction.)

Public Citizen called for an investigation in May into whether Dynegy improperly withheld capacity in Zone 4, an allegation the company has denied. Public Citizen also alleged that MISO brushed aside recommendations by its staff that Zones 4 and 5 be merged due to their concerns about Dynegy’s growing share of capacity in Zone 4 after the company acquired four generators there from Ameren.

Madigan’s complaint said that Dynegy’s increased generation portfolio in Zone 4 made it a “pivotal supplier” in the zone. Madigan also complained that in approving the Dynegy acquisition, FERC declined to look at its effect on competition and prices in Zone 4 and instead only considered a competitive analysis of MISO as a whole.

Lost Opportunity Costs

The April auction saw prices in Zone 4 clear at $150/MW-day, compared with just $16.75 a year earlier.

Dynegy said the results were consistent with its opportunity costs, which Patton had calculated at $155.79/MW-day, reflecting its ability to sell capacity into PJM. The company noted that a PJM Incremental Auction cleared at $163/MW-day less than a month before MISO’s auction. (See Dynegy: No Evidence of Misconduct in Auction.)

MISO relies on the estimated opportunity cost of exporting capacity to a neighboring region in setting the initial “reference level” — a benchmark it uses for identifying economic withholding.

In a complaint June 30, the Illinois Industrial Energy Consumers argued that PJM’s capacity costs should be not be used in setting the reference level because PJM can only accommodate a limited amount of uncommitted MISO capacity (EL15-82).

Representing the industrials, attorney Robert Weishaar told the hearing that the method MISO uses to calculate lost opportunity costs should be changed, saying the RTO’s current practice doesn’t comply with FERC’s requirement, “which is they must be legitimate and verifiable.”

Weishaar said the reference level should be set to zero pending MISO’s development of a new standard that is compliant.

“The other option is for the commission to get very prescriptive about how the LOC provisions of the Tariff should be applied to take into account such things as whether there is excess capacity within the zone; what is the available transfer capacity; what are realistic options for selling into neighboring regions,” he said.

In response to questions from staff, Patton opposed the use of a zero reference level. Patton and consultant Roy Shanker, speaking on behalf of the Electric Power Supply Association, also opposed using estimated going-forward costs by resource type in setting the reference level.

“It’s a suspension of reality,” Shanker said. “You should definitely not do it.”

Weishaar said MISO also should reflect counterflows in the calculation of local clearing requirements.

He said the two changes should be made in time for the 2016 PRA. “What we’ve learned today is that there is a high-level imprecision in the existing Tariff provisions and that some change needs to be made on both of those issues. Our view is both of those issues need to be addressed in the next six to eight months.”

Sloped Demand Curve

Henry D. Jones, executive vice president and chief commercial officer for Dynegy, joined Patton in calling for MISO to adopt a sloped demand curve.

“The vertical demand curve construct suggests that any megawatts over the planning reserve margin receive zero capacity dollars,” he said. “… Any capacity that’s not going to clear is going to be an [independent power producer] in Zone 4 and that’s not a sustainable model in terms of a capital investment in existing assets or attracting investment for new build.”

Patton said MISO’s current method separates “the representation of demand from reliability,” making it impossible to “get a market outcome that is going to produce just and reasonable prices.”

Under current rules, the last megawatt needed to meet the requirements is “worth a ton. You go one megawatt further, that megawatt is worth nothing. But if you do any sort of loss-of-load expectation — any conventional reliability analysis — it would tell you those two megawatts are delivering almost the same reliability value,” Patton said.

Patton has been unable to get any traction within MISO for changing the construct. (See MISO Monitor Debates Capacity Rules with Board.)

Jones acknowledged that such a change would face opposition from MISO’s traditionally regulated states. “I think it’s a fight worth having,” he said.

Jones also said that while MISO’s traditionally regulated states can ensure construction of new generation, Illinois — a retail choice state that does not use integrated resource planning — could find itself deserted.

“The concern we have is that over a very short period of time assets will retire or become less reliable in Southern Illinois and they will be replaced in surrounding states in [the] regulated rate base. And the southern part of Illinois will wake up with less capacity and an aging coal and nuclear fleet that’s being replaced in other states, where jobs and tax base are being shifted.”

Jones also argued that MISO should implement a minimum offer price rule (MOPR) and change its auction schedule. “It’s truly nonsensical to imagine that people can plan with an auction that occurs eight weeks before the planning year,” he said. “We need more lead time if we’re going to be thoughtful about this and provide incentive for capital expenditure and/or new build. There needs to be a longer runway for that.”

‘Swiss Cheese’ Effect

In addition to reiterating his call for a change in the demand curve, Patton said MISO also needs to “rationalize how capacity is delivered in real time.” He said MISO is being hampered by PJM’s requirement that capacity resources serving it from outside its footprint be pseudo-tied.

The PJM requirement is “creating effectively a Swiss cheese effect, where they’re taking dispatch control over units that are critical to control constraints that they don’t see in their model — and that demonstrably harms reliability,” he said.

Patton said PJM’s requirement should be replaced with operating procedures in which MISO guarantees delivery of the energy PJM has purchased “so that they [PJM] have what they need without having to effectively reconfigure the RTOs in ways that are really hard to undo from an efficiency standpoint.”

The change would help PJM’s reliability as well, Patton said.

“If MISO’s delivering energy on a firm basis, they’ll dispatch around constraints, whereas [under current procedures] a particular resource — if it hits a constraint — may have to be curtailed.”

Patton wasn’t optimistic that the two RTOs would reach agreement any time soon, however. “It’s going to take time, if my experience is a guide. To get PJM and MISO to agree on something takes a long time.”

MISO: Changes Planned

MISO’s Chatterjee said the RTO expects to make changes in time for the 2016 PRA regarding how it treats generation retirements and suspensions and how it allocates zonal deliverability benefits.

She said MISO staff will be attending a Nov. 19 conference with the Illinois Commerce Commission to hear more about the state’s concerns.

“’What problem are we trying to solve?’ is an important question to ask ourselves,” she said.

Bladen said FERC should not eliminate MISO’s opportunity cost provisions, which he said would mean that generators could “capture the opportunity cost in PJM — or the equivalent value of the opportunity in PJM — only by exporting to PJM.”

FERC will take post-hearing comments until Nov. 4. It has set no timeline for possible actions resulting from the inquiry.

In the meantime, MISO’s executive team is withholding comments on the issue, Clair Moeller told stakeholders at its Oct. 20 Informational Forum.

“What you’ll see [MISO] do is take a breath. We think it’s prudent for us to wait to see how FERC’s action on the section 206 complaints play out,” said Moeller, MISO executive vice president of transmission and technology.

Criticism of FERC Response

Public Citizen’s Slocum said he was frustrated that the conference, which was run by staff from FERC’s offices of General Counsel, Energy Market Regulation and Energy Policy and Innovation, failed to resolve some factual issues. (Commissioner Cheryl LaFleur attended part of the afternoon session.)

“The technical conference structure does not appear to be resolving these disputes effectively,” Slocum said. “This morning on the first panel, I [heard] a number of folks from MISO and Dr. Patton say, ‘I didn’t have that table in front of me,’ ‘I don’t have that data,’ ‘I didn’t bring those numbers,’ ‘I don’t have the specific numbers,’ ‘I don’t have the numbers,’ in response to repeated questions from FERC staff on subjects that were given to us ahead of time.”

“What this shows is that this is not an adequate structure to resolve these disputed claims,” he said. “The only adequate structure is an evidentiary hearing, which multiple parties called for.”

Amanda Durish Cook contributed to this article.

October 23, 2015

Ginna Lifeline to End in 2017; Profits After ‘Unlikely’

By William Opalka

The R.E. Ginna nuclear plant and Rochester Gas & Electric have reached an agreement to provide a financial lifeline for the plant through March 2017, 18 months earlier than originally proposed.

The plant’s owner states in an analysis included in the filing that the plant will not be financially viable when the agreement ends.

Under a joint proposal filed late Wednesday with the New York Public Service Commission and FERC, the new reliability support services agreement would end March 31, 2017 (14-E-0270) (ER15-1047). An earlier agreement between Exelon subsidiary Constellation Energy Nuclear Group and RG&E — which was ordered by the PSC but rejected by FERC — ran until Sept. 30, 2018.

Payments to Ginna would not start until FERC approves the agreement, the settlement says.

Ginna’s Market Prospects Dim

The agreement calls for RG&E to apply up to $110 million in existing customer credits toward the costs of the RSSA. Ratepayers will be on the hook for a $2.25 million monthly surcharge beginning Jan. 1, 2016, through at least June 30, 2017. If the customer credits are insufficient to cover the cost of the agreement, the surcharge will continue until the balance is paid off.

Those payments may continue after the plant is shut down.

“Based upon my review of Ginna’s projected operating costs for the 18-month period starting after the RSSA expires and my calculation of how much market prices must increase before Ginna’s re-entry into the market would become economic, it appears highly unlikely that there will be an incentive for Ginna to return to the market after RSSA termination,” Jeanne M. Jones, vice president of nuclear finance for Exelon and CFO of CENG, wrote in an affidavit.

The plant’s prospects are dim because forecasted market prices are lower than a baseline the company set in a 2014 analysis, and insufficient to cover the plant’s operating costs, Jones said. The conclusion of the RSSA also coincides with the need for an 18-month refueling, further weakening the plant’s financial outlook.

The new RSSA retains financial disincentives in the earlier agreement to prevent the plant from toggling between the RSSA and market payments. This mechanism, the capital recovery balance, required Ginna to pay back a portion of RSSA earnings if it reentered the market. In the new agreement, this $20.1 million would have to be repaid in two years, down from the original six or seven years.

The settlement also calls for commissioning a new reliability study by NYISO to determine if RG&E’s proposed transmission alternative is adequate to replace Ginna. A 2014 RG&E-NYISO study concluded the plant would be needed to maintain reliability into 2018.

However, RG&E changed its planning proposal from its Rochester area reliability plan (RARP) to the Ginna retirement transmission alternative (GRTA), which will be completed sooner. The RARP is a $250 million project that includes new transmission lines and new and rebuilt substations, intended to address bottlenecks, with only some components applicable to the loss of Ginna. That project will be phased in, with its completion date extended from 2018 to 2020.

The GRTA is a $150 million project that was devised to access power from other sources and includes some elements of the RARP. It diverts some of the equipment originally intended for the larger project and is expected to be completed before the RSSA expires, RG&E spokesman John Carroll said.

An Improved Deal

The agreement has been endorsed by PSC staff, the New York Utility Intervention Unit and several intervenors. Entergy Nuclear and NRG Energy, which opposed the earlier agreement, said they will not oppose it. Environmental groups oppose the deal while acknowledging it is an improvement over the original proposal.

“The proposed agreement fails to protect consumers and the environment on two accounts. First, the burden for RG&E’s bad planning is being put completely on customers,” said the Alliance for a Green Economy and Citizens’ Environmental Coalition. “Even though RG&E had ample warning since early 2013 of Ginna’s financial challenges, the utility did nothing for a year and half to get alternatives lined up to replace Ginna. The utility’s failure to act proactively will now cost its customers millions of dollars a year, yet RG&E’s shareholders will pay nothing toward the costs of the subsidy.

“Second, the agreement contains no commitments from Constellation in regards to responsibly decommissioning the Ginna reactor. Since closure is imminent, it’s critically important for New York’s leadership to get an agreement from the owners that it will begin an immediate, careful and thorough decommissioning process upon shutting down Ginna,” the groups continued.

The PSC and FERC said decommissioning is outside the scope of this proceeding.

Ratepayers will see slightly higher bills than they have been paying. An average customer would see a monthly increase of $2.20, Carroll said. However, customers have already been paying an extra $1.85 since Sept. 1 under a PSC order that authorized a surcharge to mitigate rate compression. In effect, the average customer will pay an additional 35 cents per month. (See NYPSC Approves 5.2% Ginna Rate Surcharge.)

The earlier agreement called for payments to the plant of $17.5 million per month, subject to some adjustments. FERC rejected that agreement in part and directed settlement proceedings that culminated in this week’s agreement. The new agreement would pay Ginna $15.4 million per month.

Other terms of the agreement include:

Ginna’s share of revenues from sales into the NYISO energy and capacity markets would be doubled to 30% from the current 15%.
The settlement cap for Ginna’s full cost of service has been set at $510 million, with a floor of $425 million.
Ginna will not seek a reliability-must-run agreement from FERC.

Ginna spokesman Maria Hudson said the plant owners are still looking for a long-term solution.

“While we are pleased that the negotiated RSSA will allow Ginna to continue powering the grid and the local economy until 2017, it’s only a temporary solution to a long-term problem,” she said. “Single-unit nuclear facilities like Ginna face significant economic challenges brought on by poor market conditions and a lack of energy policies that properly value the clean and reliable energy that nuclear provides.”

If the latest ISO and RG&E reliability study shows Ginna’s energy is needed beyond 2017, it will bid in to the state’s capacity auction in 2017.

October 20, 2015

FERC: More Transparency for MISO Voltage Fixes

By Amanda Durish Cook

FERC last week approved a MISO compliance filing regarding its cost allocation method for resources committed for voltage or local reliability (VLR) requirements but required the RTO to make its study process on “commercially significant” voltage problems more transparent (ER12-678-005).

“Although we find that MISO has complied with most of the directives in the June 2014 order, we agree with the protesters that MISO did not adequately comply with other directives; as a result, the Tariff needs further clarification,” FERC wrote.

The ruling originates from two filings MISO made in December 2011. One proposed that the local balancing authority (LBA) area shoulder more of the costs resulting from VLR requirements. The second proposed a mechanism to mitigate the ability of resources needed for voltage support to exercise market power. After holding a technical conference, FERC conditionally accepted the proposals.

In a June 30, 2014, order, the commission put limits on the discretion of transmission owners to determine if a VLR commitment is commercially significant and put more emphasis on stakeholder participation in the determination.

The determination of whether a VLR issue is commercially significant is based on the frequency of occurrence and monetary impact. The costs of those judged commercially significant are spread more broadly among LBAs than those determined to be local.

NRG, TDUs Complain

NRG Energy and four transmission-dependent utilities — Midwest Madison Gas and Electric, Missouri Joint Municipal Electric Utility Commission, Missouri River Energy Services and WPPI Energy — protested last year’s compliance filing, saying MISO should be required to conduct regular meetings with stakeholders and share information used to perform studies.

The commission rejected on procedural grounds NRG’s request that MISO be required to provide the study model. But it agreed with the complainants that MISO had not done enough to make the study process open and transparent.

“We agree with Midwest TDUs that language added by MISO in the compliance filing … would limit the participation in the study process of local BAAs and interested market participants to merely requesting a study. If these requests will be rolled into the quarterly study process that MISO would normally do anyway, it is unclear how MISO’s additional language would provide an open and transparent study process,” the commission said.

It ordered MISO to add new language permitting LBAs and market participants to participate in the studies and request that reoccurring VLR commitments be studied.

It also directed the RTO to hold regular meetings with stakeholders similar to those conducted when identifying system support resources under the Tariff, saying it “will provide more meaningful participation and opportunity to provide feedback.”

“With regard to a market participant’s access to data during the study process, we agree with Midwest TDUs that MISO’s proposal to limit access to such data to those parties that request the study has not been shown to be in compliance with the June 2014 order,” FERC continued.

It required MISO to provide all the assumptions and outputs of the model to any party that is liable for VLR-related charges that signs a non-disclosure agreement.

October 20, 2015

FERC Rejects Rehearing Requests on IS

By Tom Kleckner

FERC last week denied multiple requests for rehearing and clarification of its 2014 order that conditionally approved the core Integrated System entities’ SPP membership (ER14-2850).

The November 2014 order approved Western Area Power Administration–Upper Great Plains (WAPA-UGP), Basin Electric Power Cooperative and Heartland Consumers Power District’s membership into SPP, which became official Oct. 1. The order also granted a federal service exemption to WAPA, which allowed the federal agency to become the first such entity to join an RTO.

At the same time, the order established hearing and settlement judge procedures for SPP’s proposed Tariff revisions to allow the entities’ membership.

The 2014 order also set several seams issues for settlement procedures but found the perpetuation of pancaked transmission rates between the Integrated System and MISO and between SPP and MISO to be beyond the proceeding’s scope. FERC also declined to include issues connected to Corn Belt Power Cooperative and Central Power Electric Cooperative, as neither had yet transferred their facilities to SPP (the two co-ops will join the RTO on Jan. 1, 2016).

MISO, Kansas’ State Corporation Commission and Otter Tail Power all filed rehearing requests.

FERC denied the Kansas SCC’s request for a rehearing over WAPA’s federal exemption and claims that it ignored the latter commission’s expert testimony. FERC said its acceptance of the exemption was based on its policy of promoting RTO membership, and that Kansas’ expert testimony used SPP’s analysis as a baseline in doing its own study of the integration’s stakeholder benefits.

The Kansas commission also joined with MISO and Otter Tail in asking for a rehearing on FERC’s acceptance of SPP’s base-plan upgrade and regional cost-sharing proposal. That request was denied, with the commission finding SPP “crafted a reasonable transition proposal for integrating the current SPP and Integrated System transmission systems.”

FERC also denied MISO’s argument that the five-year transition proposal for the MISO-Entergy integration should have served as a model for the SPP-IS proposal. The commission said the MISO-Entergy transition proposal was developed, in part, “to prevent unfair subsidization of [project costs] required to make Entergy’s transmission infrastructure comparable to MISO’s footprint,” and that no parties in the SPP-IS proceeding had alleged deficiencies.

The commission rejected another Kansas commission rehearing request regarding the integrated entities’ responsibility for SPP’s regionally funded legacy facilities. FERC found SPP and the Integrated System “crafted a practical, reciprocal cost allocation approach for facilities in service before the integration date that is consistent with commission precedent.”

October 20, 2015

SCOTUS Agrees to Hear Md.-FERC Subsidy Case

By Ted Caddell

The Supreme Court announced yesterday that it will rule on two federal-state jurisdictional cases pitting Maryland regulators against FERC.

The court said it would consider orders by the 4th U.S. Circuit Court of Appeals that upheld lower court rulings throwing out contracts in which generation developers won state-issued subsidies to build plants in the two states.

Competitive Power Ventures and state regulators have argued that the subsidies are legal. The courts ruled with PPL and other plaintiffs in saying the subsidies violated FERC jurisdiction over the wholesale electric market.

The cases revolve around a 660-MW combined-cycle plant in Maryland. CPV won a solicitation from the Maryland Public Service Commission to build a plant in the Southwest MAAC zone. PPL was joined in its challenge of the contract by Calpine, Essential Power and Lakewood Cogeneration.

CPV and the regulators are asking the high court to reinstate the contracts. CPV has gone ahead with its construction plans, despite losing a subsequent ruling by FERC. (See CPV Md. Plant Goes Forward Despite FERC Ruling.)

In Hughes v. PPL EnergyPlus (14-614), the court will consider the following questions:

When a seller offers to build generation and sell wholesale power on a fixed rate contract basis, does the [Federal Power Act] field-preempt a state order directing retail utilities to enter into the contract?
Does FERC’s acceptance of an annual regional capacity auction preempt states from requiring retail utilities to contract at fixed rates with sellers who are willing to commit to sell into the auction on a long-term basis?

In CPV Maryland v. PPL EnergyPlus (14-623), the court will answer two additional questions:

Where, as a result of a state-directed procurement, the contract price to build and operate a power plant is the developer’s bid price, and may result in payments beyond what the developer earns selling the plant’s capacity in the FERC-supervised auction, is the program “field preempted” as a State’s attempt to set interstate wholesale rates?
Is a state-directed contract to support construction of a power plant “conflict preempted” because its long-term pricing structure provides incentives different from the incentives provided by prices generated in the FERC-supervised yearly capacity auction?

The Supreme Court declined to hear two related cases in New Jersey decided by the 3rd Circuit Court.

(An earlier version of this story erroneously stated that the court would also hear arguments in the New Jersey cases.)

October 20, 2015

New York Sees Winter Prices Moderating

By William Opalka

New York’s winter electricity prices are expected to average about 9% lower than last year’s, the staff of the New York Public Service Commission said on Thursday.

In a presentation to the commission, staffers said market conditions would benefit from better preparation and other practices refined over the past two winters, as well as from lower natural gas prices that have also influenced other eastern U.S. markets.

“We have adequate resources to meet the needs of the utilities … while we’re also looking at lower commodity prices,” said Raj Addepalli, managing director for utility rates and services at the PSC.

For example, at the New York Mercantile Exchange, futures prices for electricity in the New York City, Hudson Valley and Western New York zones range from about $11 to $23/MWh lower than they were a year ago. New York City futures prices averaged $91.06/MWh a year ago, while that same contract now averages $67.94.

The PSC said utilities and the commission have instituted a series of “lessons learned” procedures that grew out of the polar vortex two years ago. Plants have increased their capacity for on-site fuel storage, especially in eastern New York, and state officials have implemented an expedited procedure to obtain permits from the Department of Environmental Conservation to allow fuel-oil burning.

October 20, 2015

PJM Board Welcomes Ott into New Role as CEO

By Suzanne Herel

Andy Ott is officially head of PJM, after spending a six-month transition period at the side of retiring CEO Terry Boston.

Boston will serve as CEO emeritus until his retirement Dec. 31 after eight years at the helm.

The PJM Board of Managers welcomed Ott into his new position as president and CEO at its meeting last week.

pjm — Andy Ott, PJM President & CEO, listening to Terry Boston’s speech at OPSI © RTO Insider

“Terry Boston’s service to PJM and stakeholders has set a high standard,” board Chairman Howard Schneider said. “The board and I are confident that Andy will continue to ensure the stakeholder collaboration and outstanding performance for which PJM is known while establishing his own visionary leadership.”

Since being named Boston’s successor in April, Ott has been meeting with PJM stakeholders, including members, state and federal regulators, employees and industry leaders, the RTO said in a release. (See Incoming PJM CEO Ott Expects Challenges from an Industry in Transition.)

“The smooth and successful transition has resulted in this being the right time for Andy to take the helm,” Schneider said.

Praise for Boston

Boston was feted at the Organization of PJM States Inc. annual meeting in Baltimore last week.

pjm — Brenda and Terry Boston with Terry’s plaque from OPSI © RTO Insider

“There’s a lot of things that make Terry exceptional, not the least his humility,” said FERC Commissioner Cheryl LaFleur, a luncheon speaker at the event Monday. “He has a rare combination of technical expertise — no matter what you’re talking about: everything from transformers to transmission planning to market planning — and people leadership skills.”

Boston was presented with a plaque and a standing ovation the following day. “I could not have picked a better place to end my career than PJM,” said Boston, who joined PJM from the Tennessee Valley Authority. (See Retiring PJM CEO Boston Lauded for Efficiency Improvements, Management Style.)

Ott’s Experience

Ott’s previous role was as PJM’s executive vice president of markets. An 18-year veteran with the RTO, Ott was responsible for implementing LMP, financial transmission rights, the day-ahead energy market and capacity market.

Prior to joining PJM, he worked for GPU Inc. in transmission planning and operations.

He is a board member of both PJM Technologies and PJM Environmental Information Services. He also serves on the board of directors for the Association of Power Exchanges and chairs the Study Committee on Electricity Markets and Regulation for Paris-based CIGRE (International Council on Large Electric Systems).

He received his bachelor’s degree in electrical engineering from Pennsylvania State University and his master’s in applied statistics from Villanova University. Ott is an Institute of Electrical and Electronics Engineers fellow.

– Rich Heidorn Jr. contributed to this article.

October 20, 2015

FERC Rejects Refund on PJM Polar Vortex Charges

By Suzanne Herel

FERC last week denied Champion Energy Marketing’s request for a $3.1 million refund in PJM uplift charges related to the polar vortex of January 2014 (EL15-46).

Texas-based Champion, a load-serving entity, paid about $3.8 million in real-time balancing operating reserve (BOR) charges that it said it should not have been assessed because it had covered nearly 100% of its load for that month through forward contracts. Champion requested a refund of $3.1 million plus interest. The retail energy provider, a Calpine company, operates in Illinois, Pennsylvania, Ohio, New Jersey and Maryland in PJM.

It also asked that Tariff provisions governing BOR charges and allocations be amended, saying they were unjust and unreasonable “because it allocates BOR costs for reliability to all load when these costs should be allocated to market participants that were short supply.”

The commission disagreed. “Despite the fact that Champion was long on an aggregate daily basis, as a load-serving entity with real-time load, Champion participates with other customers as part of an integrated grid and therefore relies on PJM to assure that its transactions can be delivered as scheduled,” it said.

Commissioner Philip Moeller dissented in part. “Allowing PJM’s current BOR cost allocation to continue harms market participants like Champion and decreases the efficiency of PJM’s markets. Allocating costs broadly to load-serving entities like Champion unfairly frustrates their efforts to hedge their positions; it does not ensure that the market participants who actually caused those uplift costs pay corresponding charges.

“The fact that Champion benefits from grid reliability does not indicate that their actions caused the uplift costs it was forced to bear,” he continued. “Champion and other load-serving entities should only be allocated uplift costs on the basis of those benefits when the parties who caused those costs cannot be identified.”

PJM said its operators responded appropriately to the extreme weather conditions and accompanying outages and that Champion’s charges were consistent with the Tariff and how other LSEs were assessed.

It did note that Champion was allocated $2.8 million in real-time BOR reliability charges in January 2014 incurred as a result of actions taken by PJM’s operators during the operating day that were “uneconomic but nonetheless needed to maintain the reliability of the PJM transmission system because physical, real-time load benefitted from the reliability provided by these operator decisions.”

Uplift payments for all of 2014 totaled $964.7 million, according to the Independent Market Monitor’s State of the Market report.

PJM acknowledged there was room for improvement in reducing uplift but pointed out that it was able to capture 98.1% of all system operating costs in 2014, leaving only 1.9% for BOR charges.

The Independent Market Monitor agreed that Champion’s request should be denied but said the company did have a legitimate grievance that indicated the need for further reform of capacity market rules.

October 20, 2015

FERC Refines Market-Based Rate Rules

By Michael Brooks

WASHINGTON — FERC last week issued a final rule to clarify and streamline its market-based rate (MBR) program, the first major update to the policy since codifying it in Order 697 in 2007 (RM14-14).

The changes are intended to increase transparency by, for example, requiring that asset appendices in MBR filings be submitted electronically so that they are searchable and sortable. MBR sellers will also be required to report all long-term firm purchases of capacity and energy that have associated long-term firm transmission.

FERC, however, eliminated some requirements in an effort to streamline the program. For example, MBR sellers will no longer be required to file quarterly land acquisition information for new generation sites. They will also no longer be required to report behind-the-meter generation in their asset appendices.

The commission issued its Notice of Proposed Rulemaking for the changes in June 2014. The final rule did not adopt the NOPR proposal to relieve MBR sellers in RTOs and ISOs of the obligation to submit horizontal market power screens, but FERC said it might reconsider this in the future. (See FERC to Revamp MBR Rules.) Commissioner Colette Honorable credited this to stakeholder feedback on the NOPR.

FERC Denies PNM MBR Authority

In a related order, FERC rejected Public Service Company of New Mexico’s (PNM’s) request for MBR authority in its balancing authority area (ER10-2302).

The company’s August 2014 request relates to its purchase of Delta Person, the owner of a 132-MW gas-fired power plant in PNM’s balancing authority. PNM sought to reinstate its MBR authority because, it said, market characteristics in its balancing authority area had changed since it relinquished its MBR authority in 2010.

FERC questioned the data with PNM’s application, including the simultaneous transmission import limit (SIL) study values included in its market power analysis. The study is performed by simulating an increase in generator output in one area, the export area, and a decrease in output in the area under study.

FERC found that PNM had improperly decreased output from plants with long-term firm transmission reservations, which are exempt from scaling in the study. As a result, the commission said that PNM’s values were invalid and that its analysis failed to rebut the presumption of horizontal market power in its balancing area.

FERC emphasized in its order that many companies used incorrect information in their market power analyses.

“We take this opportunity to remind applicants seeking initial market-based rate authority or seeking to retain such authority of the type of information and analysis that is useful and appropriate for our consideration of a delivered price test (DPT) and what is not,” the commission said in its order. “We are providing this information not only to PNM but to industry broadly with respect to several issues that arose in our review of the DPT analysis and SIL study prepared by PNM.”

“PNM was just the lucky person we chose to use their order as the vehicle to deliver this guidance,” Commissioner Cheryl LaFleur said at FERC’s open meeting Thursday. “I hope that the guidance will be helpful to applicants to make their application processes smoother and faster in the future.”

Honorable agreed. “Our intention certainly wasn’t to single out PNM,” she said.

October 20, 2015

SPP Task Force Debates CPP Compliance

By Tom Kleckner

LITTLE ROCK, Ark. — SPP and its stakeholders began trying to put their arms around the massive task of Clean Power Plan compliance last week, debating the pros and cons of mass-based versus rate-based compliance, a reliability safety valve and how best to involve themselves in the compliance process.

The goals of SPP’s Clean Power Plan Review Task Force — a name so unwieldy its chairman repeated it slowly to avoid stumbling over the words — are to develop policies and recommendations to SPP’s Strategic Planning Committee, including the development of educational materials for environmental agencies and SPP’s members and Regional State Committee. The task force will also provide comments to the Environmental Protection Agency on its Federal Implementation Plan, which the agency would apply to the states that fail to file their own plans by the 2018 deadline.

Rate vs. Mass

The task force delved into a recent staff survey of members that asked whether they preferred a rate-based or mass-based compliance approach, along with the pros and cons of each. Twelve of the 20 respondents said they preferred a mass-based approach or identified its advantages, with only one preferring a rate-based approach.

SPP Vice President of Engineering Lanny Nickell said the survey identified two ideas that have a broad consensus: 1) a robust emission-trading program is “paramount” no matter which compliance approach a state chooses; and 2) states should develop their own implementation plans, rather than be subject to the FIP, which will have less flexibility.

Those who indicated they favored the mass-based approach said it was due to its flexibility in accommodating various generation technologies, its ease of monitoring and its consistency with other current emission-compliance approaches and mechanisms.

Other comments in favor of a mass-based approach said it would likely lead to a more robust allowance trading program, and that trading between mass-based states could be accomplished using established criteria from similar programs. Emission-allowance prices would be more easily reflected in wholesale energy prices than emission rate credits, they said.

“The survey was good,” Nickell said. It “at least gave us a preliminary feel.”

Nickell, who is leading the RTO’s CPP compliance efforts, said a trading-ready approach is gaining favor as a way to reach compliance.

“But if a few states go one way and the rest go the other way, those few states may have trouble trading,” he said. “It’s my understanding they’re not compatible. If you have a rate-based state, you can’t trade with a mass-based state.”

Reliability Still a Concern

SPP staff also shared a qualitative assessment of the proposed FIP, with Director of System Operations Sam Ellis pointing out that EPA will consider comments about providing for a reliability safety valve for mass-based plans. For example, he said the proposed FIP does not factor generating units’ need to run for reliability reasons when allocating allowances.

Ellis said EPA believes the need for the safety valve is “highly unlikely” but possible for states with “inflexible requirements on specific” generators.

“The EPA believes most events would be short duration and that emissions standards will not require adjustment,” Ellis said.

Xcel Energy’s Lauren Quillian questioned that assumption. “The EPA is essentially making the argument that trading will solve everything,” she said. “But why not have a reliability safety valve?”

Ellis said staff believes that while some form of a reliability backstop would be beneficial, the roles of FERC, EPA and the Energy Department should be clarified in the event of unforeseen disasters.

Regional Compliance

The qualitative assessment not only reiterated that a mass-based approach has more advantages than a rate-based approach (more liquid trading markets, better planning assumptions, easier measurements and verification, etc.). It also indicated consistent plans among SPP’s states would benefit reliability, particularly those that allowed interstate trading of allowances or credits.

Nickell said SPP continues to involve itself as the states in its footprint begin to discuss their approach to CPP compliance. The RTO introduced itself to air regulators last month with a webinar on the plan and its reliability implications, and it has participated in meetings with Missouri, Kansas and Minnesota regulators and legislators. (See SPP to Push Regional Approach in First CPP Webinar.)

“They’re really appreciating the individual nature of how we can help them,” Nickell said. “We want to ensure what the states do doesn’t disrupt the regional energy market.”

There was some disagreement, however, about whether to involve states outside of SPP’s footprint in the compliance process.

“Are there any benefits to working with regions next to ours?” Golden Spread Electric Cooperative’s Mike Wise, the task force chair, asked the group.

“We have a big enough problem already, so no, not at this time,” Richard Ross of American Electric Power replied.

“I think it’s really important to get together with MISO,” said Steve Gaw, SPP policy director for The Wind Coalition. “The states are going to do what’s best for the state. They don’t care whether [the RTOs] are part of one state or the other.”

The task force met after the SPC unanimously approved modifications to the group’s scope, expanding the group’s size from five members to seven (though open participation is welcomed).

The task force is composed of Wise, Burton Crawford (KCP&L Greater Missouri Operations), Dennis Florom (Lincoln Electric), Dale Niezwaag (Basin Electric Cooperative), Wayne Penrod (Sunflower Electric Cooperative), Quillian and Ross. Each of SPP’s 14 states is represented by a member.