Page 1453 – RTO Insider

April 18, 2016

SPP to Cut Planning Reserve to 12%, Reduce Capacity Needs by 900 MW

By Tom Kleckner

SANTA FE, N.M. — Capitalizing on their $5.6 billion transmission buildout, SPP members voted last week to reduce the RTO’s planning reserve margin to 12% from the current 13.6%.

Mike Wise, Golden Spread Co Op SPP planning reserves capacity needs — Wise © *RTO Insider*

The Markets and Operations Policy Committee approved a recommendation by the Capacity Margin Task Force that members said will reduce SPP’s capacity needs by about 900 MW, saving about $1.35 billion over 40 years. The Strategic Planning Committee endorsed the task force’s recommendations, contained in four white papers, as well.

The culmination of almost two years of work by the task force left SPC Chairman Mike Wise almost giddy with excitement. Wise said the reduced margin was made possible by SPP’s transmission expansion.

“We’ve tied all of the real old legacy balancing authorities together in a substantial way,” said Wise, senior vice president of commercial operations and transmission for Golden Spread Electric Cooperative. “One example of that is the old [Southwestern Public Service] area in SPP. That only had 59 MW [of] import capability. Now that capability is approximately 2,300 to 2,500 MW. … No longer is it an island.”

The white papers captured the task force’s work related to load-responsible entities (LREs), the planning reserve margin (PRM) and PRM assurance policy, and included a deliverability study. (See SPP Capacity Margin Task Force Shares ‘How Low’ Reserve Margin Can Go.)

The MOPC approved the policy package with one no vote and four abstentions. If approved by SPP’s Board of Directors next week, the capacity margin policies would become effective next summer.

“These policies identify who is responsible for resource adequacy, what the resource adequacy requirement is, and how and when the resource adequacy requirement can be and should be met,” said Sunflower Electric Power’s Tom Hestermann, the task force’s chair.

Tom Hestermann, Sunflower Electric SPP planning reserves capacity needs — Hestermann © *RTO Insider*

He said the policies are dependent on each other to balance economic and reliability benefits, and said they should be approved and implemented collectively.

The reserve assurance policy addresses concerns that current mechanisms to ensure sufficient reserve margins are inadequate. The policy incents LREs to correct planning reserve deficiencies.

Hestermann said the deliverability policy recognizes the Integrated Marketplace’s successful performance and the expected adoption of the assurance policy. It would allow SPP to determine the deliverability of generating units within its footprint, enabling entities to purchase capacity on a short-term basis through bilateral contracts to meet the PRM requirement.

The Nebraska Public Power District’s Paul Malone said he couldn’t support the use of non-firm resources in transmission planning.

“You’re putting firm resources on par with non-firm resources,” he said. “I don’t see how you can do that.”

“The task force was very adamant that firm transmission be necessary in order to deliver to resources to serve load,” responded Lanny Nickell, SPP’s vice president of engineering. “You could still use the transmission services process, with the added benefit of getting [transmission congestion rights].”

Malone offered a motion directing staff to evaluate the use of coincident peaks in determining the reserve margin. The motion was amended to add an evaluation of other regions that include non-firm resources in their reserve margin calculations and passed unanimously.

As it has done during every step of the process, Oklahoma Gas and Electric abstained from the vote. Greg McAuley, OG&E’s director of RTO policy and development, said his company wouldn’t stand in the way, but it would voice its concerns.

“The deliverability issue, to us, is a theoretical exercise. It sounds good on paper, but it hasn’t been tested,” he said. “We’re not convinced this has been vetted enough to the extent we’ll be comfortable with it. If this turns out to be a bad decision, it’ll be difficult to go back. We urge caution and a methodical approach to this … we would like to see more thought and more study go into it.”

Changes will need to be made to SPP’s Tariff and planning criteria, as the policies would replace “capacity margin” terminology with “reserve margin” terminology.

The task force will now turn its attention to developing a resource-adequacy workbook and guidelines with SPP staff.

April 15, 2016

MISO’s 4th Capacity Auction Results in Disparity

By Amanda Durish Cook

MISO’s annual capacity auction again produced disparate, roller coaster results, with prices in three zones more than quintupling compared to last year while results in Zone 4 dropped by half.

MISO said unit retirements and capacity exports throughout its Midwest region led to six of the 10 zones clearing at $72/MW-day in the fourth annual Planning Resource Auction. In contrast, the entire MISO South region cleared at just $3/MW-day. Zones 2-7 relied more heavily on imports from other zones, driving an uptick in clearing prices:

Zone 1 cleared at $19.72/MW-day, almost six times last year’s $3.48;
Zones 2, 3, 4, 5, 6 and 7 each cleared at $72/MW-day, a nearly 21-fold increase for zones 2-3 and 5-7, and a 50% drop for southern Illinois’ Zone 4; and
Zones 8, 9 and 10 each cleared at $2.99/MW-day, a 9% drop for zones 8 and 9. This was the first year for Zone 10, which covers Mississippi.

Save for Zone 4, all of the zones cleared below $3.50/MW-day last year.

MISO said 135,483 MW cleared for the planning year June 1 to May 31, 2017, a 1% drop from last year. The cleared resources include 122,379 MW of generation resources, 3,462 MW of behind-the-meter generation, 5,819 MW of demand resources and 3,823 MW of external resources.

The dip in available capacity in the 2016/17 planning year reflected data collected on the 2015 OMS-MISO Survey, the RTO said.

“The generation fleet across MISO is rapidly changing,” said Richard Doying, executive vice president of operations and corporate services in a statement Thursday. “While more generation is retiring, resulting in a tighter supply across the MISO region, the auction results show that there are sufficient resources to maintain reliability for this planning year.”

MISO said the creation of Zone 10 in Mississippi had no impact on capacity auction results.

MISO said the results were affected by FERC’s Dec. 31 order requiring the RTO to make several changes in its auction rules (EL15-70, et al.). (See MISO Seeks Adjustments on Capacity Import Limits.)

MISO’s rules allow mitigation of offers that exceed “conduct thresholds” that indicate potential economic withholding. MISO’s threshold equals 10% of the cost of new entry (CONE) plus the applicable “reference level.” Any resource desiring to offer above the threshold had to convince the RTO’s Independent Market Monitor that it had costs that warranted a higher offer.

Previously, MISO had based its reference level on opportunity costs — what a capacity resource could earn by exporting to PJM. FERC said the $155.79/MW-day maximum bid MISO used in last year’s auction was too high, because transmission constraints and PJM’s heightened Capacity Performance rules meant exporting was not an option for all capacity resources. The order required MISO to set the initial offer reference price level to $0.

In press conference Friday, Doying said most units in this year’s auction offered at prices below the conduct threshold.

The Dec. 31 order also said MISO’s approach to determining capacity import limits didn’t take into account counter-flows. MISO said the changes required “generally expanded import capability” into local resource zones and decreased local clearing requirements for most zones.

“I want to point out that supply is getting much tighter. … We expect to see further reductions in the future, so we may see more volatility in the future,” Doying said.

He also said he didn’t know where prices would have cleared without the new auction rules. “We don’t run ‘if’ scenarios,” he said.

Doying pointed out that Zone 4’s local clearing requirement was not binding this year, which contributed to it clearing uniformly with Zones 2-7. Regional constraints also were not binding, so zones were able to import and export freely with each other, and a single generator was able to set prices in multiple zones, Doying explained. On the other hand, Zone 1 had a limitation on exports, so capacity remained trapped in the zone and kept prices low.

The auction used a transfer limit of 876 MW between MISO South and MISO North/Central regions — down from 1,000 MW — as a result of the RTO’s settlement with SPP over the use of its transmission.

MISO’s Monitor has reviewed the offers and certified that the auction was conducted properly.

In a stakeholder conference call Friday, DTE Energy’s James Czech asked if stakeholders can expect changes to capacity import limits every year. Laura Rauch, MISO’s manager of resource adequacy coordination, said the limits would be recalculated for next year’s auction and were changed this year to include PJM pseudo-ties. At a Thursday Resource Adequacy Subcommittee meeting, MISO said it expects to make a CIL compliance filing by Monday.

David Sapper of Customized Energy Solutions asked MISO to explain the disparity between the pre-auction supply data and what was actually offered in the auction. “I think it’s important to understand the delta there,” he said.

Ron Ryckman, also with Customized Energy Solutions, asked for details on which facilities asked for facility-specific reference levels.

John Harmon, MISO manager of resource adequacy, said those issues would be discussed at the May 5 Resource Adequacy Subcommittee meeting.

The results were released as MISO is proposing rule changes that would result in a separate forward capacity procurement for deregulated areas such as Zone 4 and the addition of seasonality and external zone constructs. (See Stakeholders React to MISO Proposed Auction Design.)

MISO officials had hoped for an unremarkable auction after last year’s nine-fold price increase in Zone 4. Watchdog organization Public Citizen claimed Dynegy improperly withheld capacity in southern Illinois after the company acquired four Zone 4 generators from Ameren. Public Citizen, Illinois Attorney General Lisa Madigan, the Illinois Industrial Energy Consumers and Southwestern Electric Cooperative filed complaints against MISO last May and June.

The issue was also the center of a FERC technical conference in October, and FERC’s Office of Enforcement is conducting a nonpublic investigation into whether last year’s auction clearing prices in southern Illinois were manipulated. Dynegy officials insist they did nothing wrong.

April 11, 2016

FERC’s Artful Balance: Price Formation and Consumer Protection that Works

By Joel Yu and Christopher Hargett

A $1,000/MWh energy market offer cap in organized wholesale electric markets regulated by FERC has served as an effective customer protection for more than 15 years.[1]

Only once has an operational constraint resulted in legitimate energy offer spikes to levels near or above $1,000/MWh in some regions: the polar vortex in winter 2013-14.

In response, regional market operators scrambled to initiate measures modifying the existing cap so that generators could recover legitimate costs if it happened again.

When FERC initiated proceedings to improve price formation in organized electric markets, with due consideration of the $1,000/MWh cap, stakeholders began debating. Almost two years later, they still are, raising numerous concerns over any changes to the existing offer cap.[2]

In a September 2015 “Stakeholder Soapbox,” Consolidated Edison highlighted two principles to consider in reforming this important customer protection. First, the $1,000/MWh energy market offer cap plays a critical role in mitigating potential market power abuse. Second, the markets must also appropriately compensate generators for their performance in extreme conditions.

FERC’s Offer Cap Rulemaking is Responsive to Stakeholder Concerns

In its January 2016 proposed rule, FERC strikes a balance giving careful consideration to customer interests in the pursuit of uniform, transparent and efficient energy market pricing.

The proposed rule allows energy offers in excess of $1,000/MWh to set market clearing prices only when underlying costs have been verified before the start of the market clearing process. Offers not verified before the start of the market clearing process would be ineligible to set market clearing prices, though legitimate costs could be recovered through out-of-market payments based on an after-the-fact review.

Over the past two years, Con Edison has advocated that the $1,000/MWh offer cap is a critical “fail-safe” consumer protection against potential market power abuse when markets may not be functioning competitively, due to either high load or other system conditions.

Likewise, NYISO’s Market Monitor states that “prices are generally more sensitive to withholding and other anticompetitive conduct under high load conditions” due to the scarcity of marginal suppliers.[3] Experience has demonstrated this when both electric and gas systems are experiencing high demand conditions.

FERC addressed this concern by proposing to maintain the $1,000/MWh offer cap on market-based offers. By requiring pre-verification of underlying costs when offers exceed the cap, the proposed rule should help protect consumers against high energy prices due to anti-competitive supplier conduct.

Specifically, this proposal protects consumers from potential attempts to exercise market power in either the electric or natural gas markets. This is especially so because natural gas is an increasingly dominant fuel for electric production and typically marginal when electric demand exceeds base load. With its robust enforcement authority for both commodities, FERC can provide additional customer and market power protection.[4]

Con Edison and others have supported out-of-market payments for generators needing to recover marginal costs in excess of $1,000/MWh, while acknowledging FERC’s goal of making energy market pricing more transparent and efficient.

By allowing cost-based offers to exceed $1,000/MWh subject to verification, FERC provides generators with assurance that even during rare circumstances, such as the polar vortex, costs can be recovered through market clearing prices or out-of-market payments.

Thus, the proposed rule strikes an appropriate balance between customer and supplier interests.

FERC Establishes an Effective Framework for Organized Markets to Develop Regional Implementation Rules

Con Edison, along with numerous other stakeholders, also cautioned against any proposal that would create disparate offer caps among neighboring organized markets given potential unintended and harmful impacts across seams.

Sensitive to this concern, FERC’s proposal will apply the new offer cap construct uniformly across the markets. While specific regional implementation may vary to address regional differences, FERC’s proposed framework provides for regional price differences driven by system constraints, not by variations in regional offer cap rules.

FERC’s proposal sets out clear policy objectives and rationale for the revised offer cap construct. It is a good and fair solution. Con Edison encourages FERC to adopt its proposal without significant alteration or delay.

Christopher Hargett and Joel Yu are senior policy advisors at Con Edison. Subsidiaries Con Edison Company of New York and Orange and Rockland Utilities are transmission owners within NYISO. A subsidiary of Orange and Rockland Utilities, Rockland Electric, is a transmission owner within PJM.

[1] See FERC’s NOPR, Docket RM16-5, 154 FERC 61,038 (January 21, 2016) at p. 55.

[2] Currently, the energy market offer cap does not allow offers exceeding $1,000/MWh to set market clearing prices, except in PJM where the offer cap was recently raised to $2,000/MWh.

[3] 2014 State of the Market Report for the New York ISO Markets, Potomac Economics, May 2015, p.17.

[4] See Energy Policy Act of 2005, Pub. L. No. 109-58, 119 Stat. 594 (2005).

April 11, 2016

Massachusetts Raises Net Metering Cap, Cuts Payments

By William Opalka

Massachusetts Gov. Charlie Baker signed a bill Monday that raises the net metering cap for solar energy systems while cutting payments to some solar owners by 40%.

The caps were raised from 4% to 7% of peak load for privately owned systems and from 5% to 8% for municipally owned installations. Single-phase systems below 10 kW and multiphase systems below 25 kW — such as residential rooftop arrays — will be exempt from the cap and reduced payments. Government systems will continue to receive full payment.

The increase comes as one local distribution company, National Grid, has already met its cap and another, Eversource Energy, was approaching its limit.

The bill grandfathers those systems connected under the lower cap for 25 years. Going forward, owners of new projects will be paid at 60% of the retail rate.

The bill also allows utilities to apply to state regulators for “a monthly minimum reliability contribution” — a fixed charge from the owners of solar systems.

The level of payments has been a sticking point for various stakeholders. (See New England Stakeholders Debate Solar Subsidies.)

The state’s business lobby blasted the compromise, saying it will continue to raise costs and that the exemption for public systems is merely an example of “taking care of your own.”

“The bill will not save ratepayers money and will not bring our program in line with other states. In fact, the bill will add $8 billion to the cost of energy over the next 10 years — 2 cents/kWh for residential customers and 1.6 cents/kWh for commercial and industrial customers,” the Associated Industries of Massachusetts said.

The Sierra Club also found fault with the bill, especially the lower payments that will be made to community solar or similar projects meant to benefit lower-income residents. “The bill as it stands sends a clear message that Massachusetts is not a safe place to invest in solar, even though it’s a clean energy resource that has brought increased economic investment and jobs to the state,” it wrote.

The solar industry claims 15,000 employees in Massachusetts, many of whom were laid off after legislators and the governor were unable to agree on a bill at the end of last year.

“The [bill] will put solar workers back on the job and enable more families and communities to save with solar, and for that we thank the hard work and perseverance of House and Senate leadership and all the Conference Committee members. However, we are concerned about some of the tough choices in this short-term compromise and hope to remedy them in future sessions,” said Sean Garren, Northeast regional manager for Vote Solar, an organization that promotes solar power as a way to fight climate change.

Garren and other advocates expect the higher cap to be reached as soon as the end of this year, forcing legislators to address the issue again.

April 11, 2016

Federal Briefs

FERC auditors say Duke Energy improperly classified up to $130 million in costs from its merger with Progress Energy, calling for the company’s wholesale customers to get refunds of up to $1.3 million.

The auditors say the refunds are due only to wholesale customers, including other electric utilities or those that used Duke’s transmission system. Retail customers are not affected, according to the company.

Although the company disputed three of the auditors’ eight findings, it will not challenge the audit. A company official promised a “refund analysis” within 60 days and will then issue the rebates.

More: Greensboro News & Record

Inhofe Calls for NRC Chief To Cut Agency Inefficiencies

Sen. Jim Inhofe invoked 20th century history lessons when he called for Nuclear Regulatory Commission Chairman Stephen Burns to cut waste and inefficiency, just as former Chairman Shirley Ann Jackson did during her reign in the 1990s.

“It appears that many of the inefficiencies that plagued the NRC in the 1990s have returned,” Inhofe said during a hearing on NRC’s fiscal year 2017 budget request. He said Jackson, back in her day, held stakeholder meetings to help identify areas that needed improvement.

“The nuclear industry once again faces challenges in the market place and, once again, the need for the NRC to be an objective, safety-focused and responsive regulator is imperative,” Inhofe said.

More: Morning Consult

McCarthy: Tougher Regs Will Drive Sustainable Development

EPA Director Gina McCathy says that new rules governing methane emissions in the oil and gas industry will help drive development in those sectors and not retard exploration.

“Moving on [methane] will reaffirm our leadership on climate,” she said in a speech in Canada. “It also will happen to make sure that our ability to continue to rely on fossil fuel will be done in a way that is sustainable as well.”

EPA has formulated rules to cut methane emissions by up to 45% from 2012 levels. The new rules covering oil and gas development are due out this spring.

More: The Hill

Virgin Islands AG Subpoenas CEI Records

USVirginIslandAGWalkerSourcegov — Walker

As part of an expanding investigation into whether fossil fuel companies illegally worked to undermine climate change research, the attorney general of the U.S. Virgin Islands is subpoenaing records of the Competitive Enterprise Institute, a conservative think tank.

Attorney General Claude Walker is seeking 10 years’ worth of communications, emails, statements and drafts from 1997 to 2007. Several states and other parties are seeking similar documents from energy companies to determine whether they undermined climate science.

Walker’s subpoena is among the first directed at a third party such as CEI. The institute said it will fight the subpoena.

More: Inside Climate News

Solar Farm Planned for NJ Naval Weapons Station

The U.S. Navy plans to erect 32.8 MW of solar panels on six sites across 227 mostly forested acres at Naval Weapons Station Earle in New Jersey.

Environmentalists oppose the project because trees will need to be cleared. The activists also recently fought a 21-MW solar facility approved for 90 wooded acres at an amusement park in central New Jersey.

The project does not require an environmental impact report, nor does it need to be approved by the local planning board, because it is at a federal military facility. The Navy aims to procure or produce half of its land-based energy from alternative sources by 2020.

More: Asbury Park Press

US Civil Rights Commission To Join NC Coal Ash Fray

civilrightschaircastrosourcegov — Castro

The chairman of the U.S. Commission on Civil Rights told a crowd in Walnut Grove, N.C., that he supports their fight against Duke Energy’s plans to dispose of coal ash.

“It’s happening in North Carolina, it’s happening in Alabama, it’s happening in Waukegan, [Ill.,] it’s happening in Chicago,” Martin Castro said about coal ash storage and disposal issues. “There’s something wrong with the system, and we need to figure out how we can change that system.”

Castro’s comments came during an advisory panel hearing on the possible dangers of coal ash on community water supplies. Walnut Cove is near Duke’s largest coal ash basin, which holds 12 million tons of coal-combustion byproduct.

More: Winston-Salem Journal

April 11, 2016

NRC Backs Indian Point in Dispute with NY

By William Opalka

The Nuclear Regulatory Commission last week approved Entergy’s request to extend the time between leak tests at the Indian Point power plant to 15 years instead of 10.

Indian Point Source NRC — Indian Point Nuclear Plant *Source: NRC*

NRC on Tuesday affirmed a decision by the federal Atomic Safety and Licensing Board to extend the time between tests of the containment buildings surrounding Indian Point’s reactors. The commission approved a methodology for such extensions in 2008.

Entergy requested an extension for Indian Point’s Unit 2 in December 2014, prompting the state to intervene in May 2015.

The state had said Entergy’s petition “should be denied because it involves a significant safety and environmental hazard … and fails to demonstrate that it will provide reasonable assurance of adequate protection for the public health and safety as required by … the Atomic Energy Act.”

The ASLB denied New York’s petition, saying the state had failed to demonstrate that the commission ignored its own safety requirements. “We find that New York has not demonstrated that the board either made an error of law or abused its discretion in declining to admit New York’s contentions,” NRC wrote.

The last test at Unit 2 was done in 2006 and, under prior NRC schedules, was to be performed last month. However, following the NRC ruling, the test will now be done in 2021.

New York Gov. Andrew Cuomo has said the plant should be closed due to its proximity to New York City. He has also ordered multi-department investigation of the plant after a series of incidents in recent months, including two unplanned outages and the discovery of elevated levels of tritium in test wells at the plant. (See NRC: No Further Leakage at Indian Point.)

April 11, 2016

SPP Briefs

The wind energy records continue to fall in the Southwest, with SPP setting a new wind penetration peak of 48.32% at 2:02 a.m. April 5. That led the RTO to tweet it had set “a new record for all North American ISO/RTOs,” as the mark bettered ERCOT’s wind penetration high of 48.28%, set March 23.
Last week’s record came when SPP’s load was approximately 21,600 MW, with wind accounting for about 10,430 MW. The RTO’s wind peak remains 10,783 MW, set March 21. SPP’s previous wind penetration high was recorded March 7 at 45.1%.

SPP’s vice president of operations, Bruce Rew, has said he expects SPP to cross the 50% threshold this year. He noted the RTO has added 5,130 MW of wind energy to its footprint over the last year — 900 MW coming from the Integrated System — and that SPP is now seeing the full impact during the low-load, high-wind spring months.

Rew told the Board of Directors in January that SPP can handle wind-penetration levels of up to 60% with additional transmission and monitoring tools. (See “Wind Study, Capacity Margin Work Nears Completion,” SPP Board of Directors/Members Committee Briefs.)

The RTO has about 12,400 MW of installed wind capacity, with another 33,800 MW in development.

Z2 Task Force to Present Final Recommendations

The Z2 Payment Plan Task Force will present two options for resolving the oft-delayed Z2 crediting issue during this week’s Markets and Operations Policy Committee meeting in Santa Fe, N.M.

The Z2 project dates back to 2008 as a result of years of incorrect credits for transmission upgrades.

SPP CEO Nick Brown acknowledged stakeholder frustrations over their inability to get an idea of their liabilities or credits during January’s board meeting, telling members, “Z2 will be the focus of the organization this year.” (See “Brown: Finishing Z2 Crediting Project RTO’s Top Priority,” SPP Board of Directors/Members Committee Briefs.)

The Z2 task force has developed two plans for market participants to pay off their liabilities: a level-payment option and a staggered-billing option.

The task force and the Regional Tariff Working Group both voted to recommend the level-payment option in February. Xcel Energy and Western Farmers Electric Cooperative opposed the RTWG recommendation, and and Tenaska Power Services abstained.

Under the level-payment plan, each entity with a net payable will be given the option to pay the entire amount at once or in equal installments every three months, beginning in November, with the final installment due in August 2017. FERC’s interest rate will apply to the outstanding balances.

Under the staggered-billing option, SPP would bill all entities incrementally based upon subsets of the historical period, with settlement statements issued every three months until the entire period is billed. For example, SPP could charge and credit 2008-2010 amounts in Month 1, 2011-2012 amounts in Month 4, 2013-2014 amounts in Month 7 and 2015-2016 amounts in Month 10.

Oklahoma Gas & Electric’s David Kays, chair of the RTWG, said during an April 7 teleconference that the incremental periods would be selected to “smooth out” the invoiced amounts. No interest would be included in the amounts charged.

The Z2 task force estimated last summer the total at stake is $750 million; lead regulatory analyst Charles Locke estimates it is now “north of $800 million.” Locke said SPP expects to release a final amount to stakeholders in September.

“By that time, we will have worked through the settlements and be able to identify those amounts at a fairly accurate level,” he said.

Seams Steering Committee Seeks ‘Targeted’ MISO Seam Study

The Seams Steering Committee last week agreed to pursue a targeted joint transmission study with MISO.

Kelley,-David,-SPP-Director-Interrgional-Relations-web — Kelley *© RTO Insider*

David Kelley, SPP’s director of interregional relations, said the RTO could improve the process by focusing on targeted areas. Although last year’s comprehensive joint study identified 67 possible interregional transmission projects, SPP and MISO were unable to reach agreement on any. (See MISO, SPP Considering Second Joint Tx Study.)

Kelley said a narrower study could zero in on high-settlement market-to-market flowgates, the Northeast Nebraska-Western Iowa region and the new seam from the Integrated System’s inclusion into SPP.

“We can look at the new footprint closer than we did last time,” Kelley said. “That doesn’t take a lot of time. As long as the scope isn’t too broad, we can spend some time working on process improvements too. That includes staff and stakeholder time.”

“We’ve spent a lot of time and effort and money, and there’s not a lot to show for it,” OG&E’s Jake Langthorn said. “I’m not sure we need to do a [comprehensive study] every year if that’s the case.”

SPP and MISO are still gathering written stakeholder feedback from last month’s Interregional Planning Stakeholder Advisory Committee meeting. MISO’s IPSAC members will vote on a potential joint study April 20.

The Joint Planning Committee, comprising Kelley and MISO’s Eric Thoms, manager of planning coordination and strategy, will consider all written feedback and each party’s IPSAC recommendations before determining whether to begin a second study. The JPC will have 45 days from MISO’s April 20 meeting to make a decision.

Kelley said SPP has also proposed a targeted study along its seam with Associated Electric Cooperative Inc. He said the study’s scope is being revised, with the hope of beginning work in May and completing it by the end of the year. (See “SPP, AECI Begin Biennial Joint-Study Process,” SPP Briefs: State of the Market, Study w/ AECI.)

FERC Approves SPP, MISO Revisions to JOA

FERC last week approved SPP and MISO’s March compliance filings amending their joint operating agreement in accordance with Order 1000’s interregional transmission coordination and cost allocation requirements (ER13-1937). The commission’s April 6 order said SPP and MISO’s revisions met the requirements of FERC’s February compliance order.

– Tom Kleckner

April 11, 2016

MISO Stakeholders Provide Ideas on Incorporating Storage

By Amanda Durish Cook

As MISO contemplates expanding its definition of demand response resources to include medium-term energy storage, some stakeholders are asking the RTO to think more broadly about how storage technologies can participate in its markets.

MISO defines medium-term as any storage technology that can sustain output to the grid for four hours.

The RTO is challenged by how to accommodate four-hour capacity offers in its markets, as well as how to create a system of capacity credits and performance and must-offer obligations, Yonghong Chen, MISO principal advisor of market development and analysis, told the Market Subcommittee last week.

“These issues need to be thought through carefully,” Chen said.

MISO staff are discussing including medium-term storage in the DR resource-type II dispatch model, which facilitates offers into the markets for energy, regulation, spinning and supplemental reserves. Staff say they need more clarification on whether storage can be integrated under current market rules.

‘Formidable Task’

The Minnesota Energy Storage Alliance (MESA) says removing market barriers to energy storage is a “formidable task.”

“Our generation mix in MISO is evolving and energy storage technologies are becoming cost-effective in many applications,” MESA wrote in comments to the RTO. “MISO needs to keep pace with market changes in order to meet its obligation to provide unbiased regional grid management and open access to transmission facilities for [storage] projects.”

MESA contends that storage can cut consumer costs by storing “otherwise curtailed generation.” Storage should not be relegated to ancillary services, the group says, but could be dispatched — then redispatched — to supply grid services for more efficient generation. MESA thinks storage could be classified as both a generation and transmission service, and it encouraged MISO to develop new compensation mechanisms, such as CAISO’s flexible ramping product.

John Fernandes, director of policy and market development for Renewable Energy Systems Americas, also cautioned against strictly classifying storage as either generation, transmission or load.

“Such a practice could risk restricting a single storage plant from providing services across these operational buckets, thereby reducing the benefit realized by the system and limiting the ability to make a sound business case for storage development,” Fernandes said. He said that recognizing the fluidity of storage should not require significant Tariff changes.

Revenue Incentives

Manitoba Hydro said emerging storage technologies will require revenue incentives.

“If wind and solar dominate new resource development, storage will be increasingly needed, but, in the absence of an adequate revenue stream for storage resources, there may well be a market failure to supply them,” the company said.

The Energy Storage Association also sought more detail on how energy storage can participate in the MISO markets.

MISO said it would consider implementing a cost of new entry for storage, “similar to what is done for capacity resources.”

The New Orleans City Council said MISO’s January storage presentation posed several questions. (See MISO: Energy Storage Could Work into Existing Market Structure Next Year.)

“It may be difficult to prioritize actions needed to provide truly technology-agnostic products and operations when stakeholders cannot clearly identify barriers that storage developers and market participants face,” the council noted. Council members asked MISO to draft a storage issues statement.

Invenergy — which operates 68 MW of battery storage in PJM’s frequency regulation market but none in MISO — said the RTO has yet to clearly define the market need for storage. “Energy storage, and more specifically battery storage, is not the same as traditional generation and it should not be modeled or studied in the same way,” wrote Nicole Luckey, Invenergy manager of Midwest regulatory affairs.

Valy Goepfrich, WPPI Energy’s vice president of operations and analytics, said MISO’s suggested timeline on storage policy seemed reasonable and agreed that storage issues should be considered on a cost-benefit analysis.

Broader Discussion Sought

Chen said MISO is debating setting up an energy storage task force.

“Some of these issues are beyond the [Market Subcommittee],” he said. “I think we need a broader policy discussion.”

MISO must also determine whether storage will be used behind-the-meter to offset load, which wouldn’t require the RTO to manage the state of charge — a measure of a battery’s capability, akin to a fuel gauge — or if storage is placed in-front-of-the-meter, injecting into the system and requiring MISO to manage the state of charge.

Beyond incorporating medium-term storage, MISO also needs to decide if storage requires its own resource definition.

Chen said further market enhancements needed to incorporate storage might be recommended for MISO’s Market Roadmap process.

“Nothing’s off the table from my understanding,” said Jeff Bladen, MISO’s executive director of market design. “We just want to understand the implications.”

MISO staff this month will seek MSC advice on near-term clarification and present near-term proposals to the subcommittee. Next month, staff will begin drafting a white paper, which could propose Tariff or Business Practices Manual revisions. MISO hopes to present a final near-term storage proposal to stakeholders in late summer or fall.

April 11, 2016

Enviros Urge Ill. Legislators to Save Nuclear Plants

By Suzanne Herel

A coalition of scientists and environmentalists last week published an open letter to Illinois legislators, urging them to keep all of the state’s nuclear plants operating for their full lifetimes.

Clinton-Nuclear-Plant-(Source-Exelon)-slider-web — Clinton Nuclear Plant *Source: Exelon*

The appeal lent support to legislation that would shore up Exelon’s struggling Byron, Quad Cities and Clinton nuclear plants with $300 million per year that would be paid by Commonwealth Edison and Ameren ratepayers.

“One study found that world nuclear energy has prevented an average of 1.8 million premature deaths from fossil fuel pollution and could prevent up to 7 million additional ones in the future,” said the letter, posted on the site of Environmental Progress Illinois. The group was founded recently by Michael Shellenberger, a former anti-nuclear activist who now is an avid proponent. “Using the same methodology, Clinton and Quad [Cities] prevented 18,640 premature deaths from coal pollution,” it said.

The state’s nuclear plants are at risk, the letter continues, because they are excluded from state and federal clean energy subsidies that are available to wind and solar power. Wind and solar, which make up about 6% of the state’s generation, are intermittent and wouldn’t be able to replace the nuclear facilities, it said.

“One solution might be to expand Illinois’ renewable portfolio standard to include nuclear energy,” it said. “Such a change would allow Illinois to be more ambitious, achieving 70% or more of its electricity from clean energy.”

Among those signing the letter were climate scientist James Hansen, 1976 Nobel Prize winner in physics Burton Richter and Steve McCormick, former CEO of the Nature Conservancy.

Exelon supporters introduced the proposed Low Carbon Portfolio Standard in February 2015, and the company said it would close the three plants unless legislators acted before their summer break (HB3293, SB1585). When the bills languished, Exelon pulled back from the threat, saying, “We remain open to participating in any and all discussions designed to enact a legislative package.”

In late summer, Exelon nuclear units cleared capacity worth $1.6 billion in PJM’s first auctions under its new Capacity Performance model. Among the plants that cleared were Quad Cities, obligated to run through May 2018, and Byron, committed to run through May 2019. Following the auctions, CEO Chris Crane said the company would defer a decision about the plants’ closure for another year.

In November, Crane said that Quad Cities was breaking even, but on a fourth-quarter earnings call in February, he said that it was projected to drop back in the red as a result of low energy price forecasts. It and Clinton are still at risk of being closed, he said.

Exelon supporters introduced the portfolio standard on the heels of a dueling measure, the Clean Energy Jobs Bill (SB1485, HB2607). That bill, which is supported by environmental and consumer advocates and Chicago Mayor Rahm Emanuel, would benefit energy efficiency and wind and solar power.

Exelon’s ComEd also proposed legislation that contains initiatives the company said will “strengthen the security and resiliency of the grid, the construction of microgrids, community solar projects and the expansion of energy efficiency programs” (HB3328, SB1879).

There has been no action on any of the bills since October.

Asked last week about the status of its legislation, Exelon spokesman Paul Adams said, “Exelon, ComEd and [supporters of the Clean Energy Jobs bill] are in the midst of ongoing conversations to drive toward a comprehensive energy policy for the General Assembly to consider. Those conversations have been productive and have focused on common interests among the various groups toward an integrated low carbon energy future that fairly serves all customers, encourages economic growth and creates jobs.”

April 11, 2016

Company Briefs

Westar Energy is the target of a potential acquisition by Ameren and a group of investors, Bloomberg reported last week. Ameren is reportedly working with an investor group that includes Borealis Infrastructure Management and the Canada Pension Plan Investment Board, Bloomberg said, quoting people familiar with the matter.

Westar, Kansas’ largest electric utility, has hired Guggenheim Partners to represent it in talks, Bloomberg said. Initial bids for the utility, which has a market value of about $7 billion, are due this week.

More: Bloomberg

CEO Flexon: AEP Icing Dynegy out of Plant Sales

Dynegy CEO Robert Flexon says that American Electric Power is blocking companies that opposed its controversial power purchase agreement before the Public Utilities Commission of Ohio from bidding on power plants that AEP is trying to sell.

Flexon told Columbus Business First that Dynegy can’t get its foot in the door to bid on power plants that AEP is selling because Dynegy opposed AEP’s successful campaign to win regulatory approval for the PPA. “The funny thing there is AEP has specifically excluded anybody that dare speak against them in Ohio,” Flexon said.

PUCO recently allowed AEP’s distribution companies to enter into power purchase agreements with several of the company’s power plants, providing them with guaranteed income supported by ratepayers. AEP meanwhile is trying to sell several other plants not included in the PUCO ruling. AEP spokesperson Melissa McHenry said the company wouldn’t comment on plant sale details.

More: Columbus Business First

Southern Co.’s Kemper CCI Plant Costs Up — Again

The price of Southern Co.’s much-delayed Kemper clean coal power plant rose by $18 million in February, the company reported in a Securities and Exchange Commission filing.

The increase puts the total cost of the coal gasification plant in eastern Mississippi at $6.6 billion, three times the original estimate. Southern Co. subsidiary Mississippi Power previously said the Kemper plant would be in service by the third quarter of this year.

More: Atlanta Business Chronicle

KCP&L to Purchase Power From 2 Missouri Wind Farms

Kansas City Power and Light announced it will purchase power from a pair of wind farms that are now under construction in northwest Missouri.

Under the 20-year deal, KCP&L will buy from NextEra Energy’s 200-MW Osborn wind farm, scheduled to be completed by the end of the year, and Tradewind Energy’s 300-MW Rock Creek wind farm, which is expected to be in service by September 2017.

Courtney Hughley, a spokesperson for KCP&L, said the goal is to use wind power and energy storage to eventually replace base load generation from coal-fired plants like Iatan in northwest Missouri.

More: KCUR

US Rating Agencies Give LP&L Positive Reviews for Bonds

Lubbock Power & Light said last week it has received high bond ratings from all three major U.S. financial rating agencies, placing the municipal electric utility in a strong financial position as it moves forward with its transition to the regional grid.

If the utility ties into ERCOT, LP&L will issue bonds to pay for transmission lines needed to connect the city to the larger electrical system. The utility said its capital improvement projects will focus over the next three years primarily on getting its internal system ready to make the transition.

LP&L said Standard & Poor’s Rating Services gave it a “AA-” rating, Moody’s Investor Services assigned an “A1” rating and Fitch Ratings gave an “A+” rating.

More: A-J Media

Luminant Completes Acquisition Of 2 NextEra Gas Plants

Luminant completed its purchase of two combined cycle natural gas plants from NextEra Energy after receiving approval from the Public Utility Commission of Texas.

The Dallas-based generation company announced the $1.3 billion deal late last year. The 1,912-MW Forney Power Plant east of Dallas and the 1,076-MW Lamar Power Plant in northeast Texas are both located in ERCOT.

More: Luminant

AES Settles Dominican Coal Ash Birth Defect Suit

AES has settled a case in which it was accused of allowing a generator in Puerto Rico to dump 57,000 tons of coal ash in the Dominican Republic, where it allegedly caused birth defects in three children who were born without limbs.

Their families sued for about $30 million in damages in Delaware, where AES is incorporated. The terms of the settlement were not disclosed.

AES, which operates in 18 countries, agreed in 2007 to pay $6 million to settle a separate coal ash dumping suit in the Dominican Republic.

More: Bloomberg

SolarCity Hires Ex-FERC Chair as Chief Policy Officer

SolarCity has hired Jon Wellinghoff, former FERC chairman, as the company’s chief policy officer. Wellinghoff will advise the company on state and federal regulatory policy and regulatory affairs.

“I’ve devoted my career to advocating for the electricity consumers,” Wellinghoff said in a company statement. “And from my review there is great benefit to those consumers from distributed solar generation — clearly numerous studies have demonstrated it benefits all ratepayers, even those who don’t install panels on their roof.”

Wellinghoff is replacing John Stanton, who held the position for the past seven years and helped recruit Wellinghoff to the company.

More: Solar Industry Magazine

FirstEnergy Investing $48M In Pa. Substation Upgrades

FirstEnergy said it will spend $48 million to upgrade a substation in Wampum, Pa., as part of a reliability improvement project.

The company will install automated voltage-regulating equipment “designed to respond to real-time electrical conditions, boosting or reducing voltage as needed to maintain consistent levels on the regional transmission network.” The work will also include transformers, capacitor banks, circuit breakers and other equipment.

The new equipment will be installed on a football field-sized parcel next to the existing Hoytdale substation. The work is expected to be done by early June.

More: Crain’s Cleveland Business

Duke Energy Christens 2nd Largest Solar Farm in NC

Duke Energy activated a 65-MW solar farm last week, which it says is just the beginning of an investment of $500 million in solar energy in North Carolina.

The 850,000-panel solar farm in Warsaw, Duplin County, is the second largest in the state and the largest in Duke’s solar fleet, said David Fountain, North Carolina president of Duke Energy.

Fountain said that Duke has several other solar projects in North Carolina that are in the process of being completed.

More: WITN