New Western EIM Participants on Track to Join Market in October

By Robert Mullin

Arizona Public Service and Puget Sound Energy have met the milestones to participate in the CAISO-run Western Energy Imbalance Market and will begin trading in the market on Oct. 1.

“For APS and PSE, the bulk of the work is behind us,” Janet Morris, CAISO’s program management office director, told the EIM’s governing body during an Aug. 30 meeting.

The ISO last year developed a series of readiness criteria to ensure that new EIM participants are prepared to link up with the market.

Among the requirements: executing necessary agreements, establishing forecasting and balanced scheduling capabilities, producing accurate market settlements, and exchanging sufficient data to allow the ISO to monitor market performance.

The implementation process takes about 18 months and requires a new participant to integrate its network model — essentially a detailed blueprint of the balancing authority area’s operations — with that of the ISO. The process culminates in two months of market simulation, in which the participant operates in real conditions without transactions becoming financially binding. (See Arizona Public Service, Puget Sound Energy Enter EIM Testing Phase.)

Morris pointed out that the go-live date for APS and PSE will coincide with a significant update to the EIM’s market software. All participants, including existing members PacifiCorp and NV Energy, are required to “validate” the new market features. In the future, CAISO plans to schedule new member implementations for spring in order to avoid overlap with fall software releases.

“What’s one or two of the top things you learned from implementations to help others out there” planning to join the EIM? asked governing body member John Prescott.

“I think one of the first challenges in the early part of implementation is organizational change management,” Morris said, referring to the need for utility staff to adapt to the EIM’s operational practices. Those participants “need to understand how all the data fed into the market influences the market’s outcomes.”

Later in the implementation, new participants come to recognize the need for the two months of parallel testing, Morris added.

Governing body member Carl Linvill wondered if new participants have realized any “side benefits” from integrating their network models with the ISO.

“I think there’s a lot of benefits of having that visibility [into another balancing authority area] to enhance reliability,” Morris said. “That’s absolutely another benefit besides those coming out of the market.”

Morris told the governing body that Portland General Electric is on track to join the EIM in October 2017 after completing a scheduling coordinator agreement, identifying all participating resources in its area and providing a full network model ready for CAISO integration.

Idaho Power is also on schedule for an April 2018 start-up. An implementation agreement has been approved by FERC, and the utility plans to file for approval with the Idaho Public Utilities Commission by the end of summer. The company expects to export its network model to the ISO late next month.

Circling back to the upcoming APS and PSE implementation, governing body member Valerie Fong pointed out that it will be the first in which two utilities are integrated into the EIM on the same day — and at opposite ends of the Western Interconnection.

“We’re confident, but with that confidence we rely on a very robust support plan,” Morris said. “We plan for the worst and expect the best.”

September 5, 2016

CES Under Attack on Multiple Fronts in Rehearing Requests

By William Opalka

Numerous stakeholders have called for rehearing of New York’s Clean Energy Standard, raising objections over the subsidy for nuclear power, the elimination of support for some legacy renewable energy plants and the potential loss of renewable energy credits (REC) to adjoining states (15-E-0302).

Most of the requests were filed shortly before the mid-week deadline following the New York Public Service Commission’s Aug. 1 order approving the standard. (See New York Adopts Clean Energy Standard, Nuclear Subsidy.)

The CES is designed to support the state goal of 50% renewables by 2030, with nuclear power seen as a bridge until renewable energy facilities are built at scale.

Nuclear Subsidy Under Attack

The most controversial part of the order created a new “Tier 3” subsidy — zero emission credits (ZECs) — for nuclear power. Critics say the program would cost more than $7 billion over its 12-year lifespan. Without ZECs, nuclear owners said their plants would close, and state officials said carbon reduction goals could not be met.

The Alliance for a Green Economy and a coalition of environmental, anti-nuclear groups and elected officials objected to the subsidy as counter to the goals in the state Energy Plan and the Reforming the Energy Vision initiative.

“The PSC has failed to demonstrate that imposing exorbitant surcharges which inure solely to the benefit of nuclear operator(s) is in the public interest and consistent with existing statute and policy,” the coalition wrote.

Canadian Hydro’s Complaint

Canadian hydropower developer HQ Energy Services said additional resources from Quebec would not be credited for their environmental attributes. “For reasons unexplained, the CES order excludes significant amounts of hydroelectric power, including incremental hydroelectric power relying on new storage impoundment, from inclusion in the CES Tier 1 solicitation and REC process,” it wrote.

Tier 1 establishes the obligation of load-serving entities to invest in new renewable energy resources with an in-service date of Jan. 1, 2015, or later.

Tier 2 in the order is limited to run-of-river hydroelectric facilities of 5 MW or less, wind farms and biomass direct combustion plants that were operating before Jan. 1, 2003.

PSC staff had advocated splitting legacy renewables into two groups: Tier 2a for those resources able to sell their attributes in other states; and Tier 2b, for those unable to sell attributes because of their age or other restrictions imposed by neighboring states.

The order said splitting the “maintenance tier” for existing renewable energy resources was premature. Facilities eligible for these payments would have to demonstrate they would likely close because of their unprofitability without additional support from the state.

Nonprofit renewable energy advocate RENEW Northeast, biomass plant owner ReEnergy Holdings, Alliance for Clean Energy New York, Brookfield Renewable and the Independent Power Producers of New York all said the revision is discriminatory and that New York would likely lose the environmental benefits to other states.

“It is very possible that New York will have to replace the clean attributes of existing facilities that are sold in Massachusetts with clean attributes from new facilities at a higher cost to meet the 50-by-30 goal,” IPPNY wrote. (See Massachusetts Bill Boosts Offshore Wind, Canadian Hydro.)

Likewise, Transmission Developers Inc. seeks rehearing because of this “change in circumstances” since the order was adopted. “Such an initiative by a neighboring state very well could have the effect of siphoning off a significant portion of the renewable energy supply that would otherwise be available to New York state,” it wrote.

Procedural Complaint

The Public Utility Law Project alleged the compressed schedule under which the PSC considered ZECs violated the State Administrative Procedure Act (SAPA). The group contends the law requires 45 days for public comment instead of the 10 that the PSC allowed after the staff proposal that included ZECs was released in early July.

“Nowhere in SAPA, however, is there authorization for ‘add-on’ rules or rules resulting from the ‘logical outgrowth’ of the process since the issuance of a prior notice that did not cover the changes contemplated,” PULP wrote.

Last month, small hydropower owner Ampersand Hydro filed a complaint with the PSC, seeking inclusion in the ZEC tier as a non-emitting resource. (See Hydro Owner Wants in on New York Nuke Subsidy.) A similar request was made last week by Energy Ottawa.

Exelon also sought clarification to protect ZEC payments to its R.E. Ginna and Nine Mile Point nuclear plants in the event its proposed acquisition of the FitzPatrick plant falls through. (See FitzPatrick Sale Filed with New York Regulators.)

September 5, 2016

QA: NEPOOL Chair on Redesigning Market Rules for Low-Carbon Future

By William Opalka

The New England Power Pool (NEPOOL) is considering redesigning its market rules to align them with the region’s efforts to reduce carbon emissions from the generation sector.

Gordon Source: PSEG

The first of six scheduled stakeholder meetings on the Integrating Markets and Public Policy (IMAPP) process was held Aug. 11.

The goal is to provide guidance to ISO-NE on how wholesale markets could be adapted to meet the public policy goals of the New England states. The group hopes to complete its work by the RTO’s annual meeting Dec. 2 with market rule changes filed with FERC beginning next year.

NEPOOL, created in 1971, has more than 440 members (with about 260 voting members), including utilities, independent power producers, marketers, load aggregators, end users and demand response providers.

RTO Insider recently spoke to its chairman, Joel S. Gordon, whose day job is director of market policy at Public Service Enterprise Group’s PSEG Power Connecticut unit. The interview has been edited for clarity.

New England has usually had an active public policy agenda related to energy, but this is a rather different way to approach this topic. So, why now?

“If you look at the New England states, there has been a rather large consensus that the environmental objectives that the individual states have are all heading in the same direction. The states have different means to achieve them, but they are all part of the Regional Greenhouse Gas Initiative, and some of them have even more aggressive targets than RGGI.

“They have outlined means to achieve [decarbonization] through mandates for aggressive carbon reduction and renewable energy goals, so in order to meet those targets that have been legislatively mandated, they needed to take some actions that are outside of the market.

“Right now, the markets, as we’ve designed them, are not designed to drive the [decarbonization] of the generation fleet. It is designed to find the most efficient set of resources and to meet a reliability need, which has been the mission of NEPOOL and ISO-NE throughout the entirety of their existence.

“The recognition of our members has been that over the last couple of years, as we’ve seen more programs come out of the states, we’ve recognized that the markets were not really not going to give them what they needed, so the states took these out-of-market actions. [IMAPP] is a recognition that the states have legitimate public policy goals, so the markets should be designed to help achieve those public policy goals.”

The state RFPs and the Massachusetts legislation mandating hydropower and offshore wind are examples of these out-of-market actions. [See Massachusetts Bill Boosts Offshore Wind, Canadian Hydro.]

“From the states’ perspective, the markets weren’t moving fast enough to get them where they needed to be and that’s where these big RFPs come from, and the Massachusetts legislation. Our goal at NEPOOL and for the region is to create a competitive market signal to get the states what they need so they don’t have to act on their own. If we’re successful, the markets on their own will find the most cost-effective means in meeting those state objectives.”

In remarks to stakeholders, you said, “No other RTO has done this before.” Are you optimistic that you can meet these challenges, or is it a bit frightening that New England is out there a bit alone, perhaps the first region trying to integrate markets to this extent with public policy?

“I’m incredibly optimistic that we can find solutions to the problems that we face, the challenges before us. That’s what NEPOOL is really good at as a stakeholder organization. We have six different governing sections that look at our industry from all different perspectives. This is what the IMAPP initiative is, reaching out to the members as they try to find solutions to the challenges.

“I’m also optimistic that the states have encouraged us to do this. They recognized that in [the multistate requests for clean energy] that there’s potential in what the markets have developed. But recognizing they have objectives mandated in their legislation, we can provide a pathway to achieving their objectives using the discipline of competitive markets.”

You seem to have a pretty aggressive schedule in what seems to be a large task ahead of you. Are you confident you will have a consensus document to present to ISO-NE in December?

“The process that we’ve set up [six meetings over four months] is an aggressive schedule. But it’s also important that we put ourselves in that schedule so when we start out in 2017, that we’ll be in a position to respond to the mandates that are out there legislatively. They have carbon reduction goals, so we have to start the process sooner, rather than later, to go to a market-based solution. It also provides the states with an opportunity to see what NEPOOL is doing. They may see there is less pressure for them to act if they see what we’re doing. Really, it’s our first step. I think we’ll be able to get to a high-level framework document by December.

“We hopefully will have a framework for a suite of solutions that would achieve a set of objectives, then we would get into the traditional NEPOOL process that works with ISO-NE and begins to analyze how it would work with the market rules. Then we would begin to work that into the Tariff revisions that would implement it.”

Do you see this process being informative for other RTOs, or do you see New England’s situation as unique?

“We are looking to the other regions as well to understand other concepts that are out there that may help to achieve our goals, which are somewhat unique to New England. We see some of this discussion in PJM in their Grid 20/20 process. [See PJM’s Grid 20/20 Ponders Mixing Public Policy, Competitive Markets.] But integrating public policy is not part of their mandate. In New England, we are fortunate in there are six states and they’re pretty much aligned, as opposed to [PJM’s] 13 states [which are not].”

Would it lead to inefficient market outcomes if rules that go into effect 10 years from now run counter to commitments that states make now through long-term power purchase agreements?

“Timing is going to be a challenge, there’s no question. We’ve talked about two timelines that we need to deal with [10-year goals and 30-year goals for emission reductions.] … I think we’re going to have to work on integrating the short-term and the long-term. I’m not sure how that happens. That’s one of the things that this process is going to have to deal with.”

September 5, 2016

MISO Sees Nov. 1 Filing on Forward Auction; Simulation Shows Price Disparities

By Amanda Durish Cook

MISO officials said last week they are still finalizing their forward auction proposal for competitive areas, but the changes won’t be significant and won’t affect a late fall FERC filing. Meanwhile, simulations including the new proposal suggested it could result in large price disparities.

Bladen © <em>RTO Insider</em> — Bladen © RTO Insider

Jeff Bladen, executive director of market services, said MISO is now targeting a Nov. 1 filing, with implementation in the 2018/19 planning year. The RTO plans to release another version of draft Tariff language at a Sept. 19 Resource Adequacy Subcommittee meeting and collect stakeholder feedback by the Oct. 6 RASC meeting. The Brattle Group will also present more forward auction findings at the September meeting. (See MISO Delays Forward Auction Filing; Issues Draft Tariff and Business Rules.)

“At this point, we’re not anticipating any meaningful changes,” Bladen said at a two-day RASC meeting last week.

Bladen said MISO is still working on a materiality clause to determine which retail choice load participates in the forward auction in Michigan and Wisconsin, where the zonal boundaries straddle state lines.

The RTO also is considering changes to its cap on the safe harbor provision that excuses supply from having to offer capacity.

The current cap is based on historical planning reserve margin requirements (PRMR) and an “open-ended” exception process. MISO is considering a cap based on projected PRMR and a “prescriptive” exception process, and one based on projected PRMR plus additional prescriptive adjustments with no exception process.

Based on stakeholder feedback, MISO is reworking transmission modeling compatibility between the forward and prompt Planning Resource Auction and a simultaneous feasibility test, which judges the system’s ability to handle all megawatts of capacity dispatched during a maximum generation event. Bladen said MISO is still refining a possible congestion charge to remedy infeasible capacity delivery through cost allocation.

“We want to make sure that anything that clears in the FRA [Forward Resource Auction] will be feasible with the rest of the footprint,” Bladen said.

Finally, the RTO is mulling over which demand curve shape to pursue. (See MISO Backs Forward Auction Plan, Rejects Prompt Proposal.)

Split with Market Monitor

Mark Volpe, senior director of regulatory affairs for Dynegy, asked if MISO is still working with Independent Market Monitor David Patton on his concerns over price formation.

“We speak with the Market Monitor on a regular basis. While we continue to have a difference of view, we are open to his advice and feedback on how and when to improve the FRA, [but] the price formation concerns that he’s raised are not what we’re seeing,” Bladen said. “I think the nature of his role as an adviser is not in question. But at this point, we have a difference of view in what the data shows, and that’s not uncommon with topics like this.”

When pressed by stakeholders on how much of the Monitor’s advice would be incorporated, Bladen became less conciliatory, suggesting the RTO would rely on Brattle’s suggestions. “There’s nothing [in the Tariff] to suggest that Potomac Economics is the sole [adviser] for MISO,” he said. “And FERC is the ultimate arbiter.”

RASC Chair Gary Mathis asked if MISO could leave certain details out of the filing to work out later. Bladen said he expected the filing to include all relevant details.

“Like most FERC filings, everything is up for grabs once FERC gets its hands on it,” Bladen added.

Michael Chiasson of Potomac Economics asked if MISO would leave any details out of the filing in favor of providing a reference to the accompanying Business Practices Manual. Bladen said MISO would not.

MISO-IPL Analysis Produces Disparities

MISO also collaborated with Indianapolis Power and Light on a forward auction pricing analysis, which used results from last year’s Planning Resource Auction in a forward auction and PRA simulation.

The two simulations yielded disparate results. A first simulation that used a sloped demand curve produced clearing prices of $1.99/MW-day for MISO South, $1/MW-day for Zone 1 and $222/MW-day for the remainder of MISO North in the prompt auction, and $110/MW-day in the forward auction, which will be limited to retail choice areas. IPL said the PRA demand curve moved to the right during its simulation, noting “cleared FRA resources offered at zero … in the PRA are not a direct offset to the shift in demand curve.”

On a second simulation using a demand curve shaped closer to what Brattle used in its analysis, IPL results produced $210.10/MW-day in the forward auction, and a $2.99/MW-day clearing price in MISO South and a $5/MW-day clearing price in MISO North. (See chart.)

IPL analyst Ted Leffler said the outcomes of the auction are “in line with expectations” even though the forward clearing prices were disproportionately higher than PRA prices.

“Should we be concerned that we’re going to be introducing more volatility? I don’t know. It’s something we need to think about,” Leffler said.

Leffler said IPL used the Zone 4 PRMR as a representation for all competitive zones and didn’t change any offers or capacity import or export limits. The analyses only used the most expensive offers in Zones 1, 2, 8 and 10. For the second analysis, he said, IPL assumed just 78% of Zone 4’s resources were offered in the forward auction, as that was the percentage considered competitive.

Leffler also said the simulations’ use of 2015 PRA results was “imperfect” because it was a “sold-out” auction, with all supply megawatts clearing except for some in Zones 4 and 7.

Count External Resources Toward Clearing Requirement?

While a seasonal and locational auction filing is also on hold until the 2018/19 planning year, MISO said it could consider implementing pieces of the locational construct in the 2017/18 planning year. Namely, said Executive Director of Resource Adequacy Renuka Chatterjee, MISO could apply external resources toward local clearing requirements in next year’s auction if the RTO can file with FERC and get approval in time.

South-North Limit

Meanwhile, MISO continues to solicit stakeholder opinion on whether the 876-MW South-North transfer limit should be adjusted in planning for next year’s auction. (See “South-North Transfer Limit in 17/18: Higher or Lower? Firm or Non-Firm?” MISO Resource Adequacy Subcommittee Briefs.)

The RTO brought six days’ worth of 2016 summer data to the RASC to illustrate peak usage on the sub-regional transfer. The data showed North-South flow averaging 2,446 MW on June 17 (with a peak of 2,840 MW) when a maximum generation alert was issued in MISO South, and an average 1,618-MW South-North flow (peak 2,225 MW) on July 22 when Midwest load peaked at 88 GW.

Volpe said the results show that MISO should continue to be “somewhat conservative” for constraints on real-time flows between the regions. Dynegy, which independently examined flows during two peak summer days this year, concluded MISO should continue to subtract firm reservations from the 2,500-MW South-North limit.

Other stakeholders agreed, saying MISO should account for all firm reservations across the interface, as only non-firm reservations could be guaranteed after all firm flows were granted, even if the firm flows weren’t in use.

MISO said of the 10 respondents that provided feedback on the regional transfer limit, seven supported using the maximum 2,500-MW limit as a starting point. Two others opted for a 1,000-MW starting limit. The final stakeholder to provide comment asked for a study of firm-flow reservations before a decision is made.

The RTO is expected to present a draft proposal on the 2017/18 sub-regional limit at the Oct. 5 RASC meeting.

September 5, 2016

Federal Briefs

The Omaha Public Power District has notified the Nuclear Regulatory Commission that it will permanently shut down its Fort Calhoun reactor on Oct. 24. The OPPD board unanimously approved a recommended shutdown in June, but officials had not provided a date for when the plant would stop operating, only saying it would by the end of the year.

With the shutdown date set, the plant’s decommissioning will kick into gear. That includes the removal and transfer of nuclear fuel from the reactor into the spent fuel pool, where fuel rods will be placed for about 18 months while they cool to a level that permits transfer into longer-term storage.

The decommissioning process could take up to 60 years and will cost OPPD as much as $1.5 billion. The 43-year-old, 478-MW Fort Calhoun is the smallest nuclear plant in the country, which made it financially untenable to continue operating.

More: Omaha World-Herald

Firm Lands DOE Grant for Flameless Combustion Plant

Southwest Research Institute has received a $3.28 million grant from the Energy Department to develop a project that could eliminate smokestacks and reduce emissions from coal-fired power plants.

The project is described as a “flameless pressurized oxy-combustion plant” by Rep. Joaquin Castro (D-Texas), who announced the grant. The organization also received nearly $900,000 in private industry support for the research.

SwRI, a research and development nonprofit, said the smoke produced from burning coal will be purified in a process that captures carbon dioxide and results in zero emissions. The captured CO₂ will be kept out of the atmosphere by injecting it underground.

More: San Antonio Business Journal

DOE Estimates $1.2B to Retrofit Colstrip Plant

Energy Department representatives said that retrofitting the Colstrip coal-fired power plant in Montana to reduce greenhouse gas emissions would cost at least $1.2 billion, but that price tag could be partially offset by selling captured carbon dioxide for use in oil fields. Colstrip emitted about 16.5 million tons of CO₂ in 2014, two-thirds of the state’s total, according to EPA.

The department presented its analysis of reducing emissions from the Colstrip plant at the request of Montana Gov. Steve Bullock. A Democrat up for re-election in November, Bullock has faced a barrage of Republican criticism for not doing enough to protect the aging plant.

“We need to be saying, what can we do to find solutions?” Bullock said to utility and mining executives gathered at the governor’s office in Helena to hear the Energy Department’s findings. “Those discussions only become more urgent given recent developments at Colstrip.”

More: The Associated Press

FERC Approves Dominion Pipeline Expansion in Md., Va.

FERC has approved an expansion of one of Dominion Transmission’s natural gas pipelines necessary to serve new generating stations in Maryland and in Virginia. Dominion filed to expand the Leidy South Project in May 2015.

The project involves adding compressor stations and other equipment to the pipeline, which crosses Pennsylvania, Maryland and Virginia. Ultimately, it will allow natural gas to be carried to the Panda Stonewall generating station planned for Loudoun County, Va., and the Mattawoman Energy project in Prince George’s County, Md.

Dominion estimates the expansion will cost $209 million.

More: GenerationHub

NRC Cites FirstEnergy for Inaccurate Medical Info

The Nuclear Regulatory Commission cited FirstEnergy for failing to provide accurate medical information after a nuclear operator at the company’s Davis-Besse plant lied about taking his prescribed medication.

The commission found that the operator, who resigned before the investigation began, failed to notify the plant when he stopped taking medicine for diabetes and high blood pressure. As a result, the commission said, the company unknowingly provided it with inaccurate information.

A FirstEnergy spokesperson said the operator’s failure to take his medication did not impact the plant’s operations. The company has agreed to modify its fitness-for-duty procedures as a result of the incident.

More: The Blade

TVA’s Watts Bar 2 Offline After Transformer Fire

A main transformer fault at the Tennessee Valley Authority’s new Watts Bar 2 nuclear station caused a transformer oil fire and tripped the reactor last week. The incident occurred during testing of the unit before it goes into commercial operation.

TVA had achieved 99% of maximum output during the test before the fire broke out. It completed construction of the plant this year.

The fire was extinguished and there were no injuries. TVA said it is completing a full examination of the incident and the plant before resuming the testing. It said it didn’t know when it would go back online.

More: POWER Magazine

September 5, 2016

PJM: Regional Plan Cuts Costs, but Gas Prices are Wild Card for CPP Compliance

By Rory D. Sweeney

The Clean Power Plan poses no threat to PJM’s reliability, but compliance costs are highly sensitive to gas prices and whether states go it alone or combine efforts with a regional approach, according to a study released by the RTO last week.

If gas prices remain low, states within PJM’s footprint are likely to meet EPA-mandated emissions reductions simply through the replacement of coal plants with new combined cycle generators. However, compliance costs could more than triple if states decide to meet their CPP targets individually while also regulating emissions from new sources, the RTO’s analysis concludes.

Issued by EPA in August 2015, the CPP requires PJM’s states to reduce carbon dioxide emissions by 36% from 2005 levels by the year 2030. The analysis, requested by the Organization of PJM States Inc., compared seven compliance “pathways” employing mass- and rate-based trading at regional or state levels. Rate-based plans would mandate that generators meet a pounds-per-megawatt-hour target, while mass-based plans cap state emissions in tons per year.

PJM also looked at several sensitivities, including the impact of retirements on resource owners’ exit decisions based on five- and 20-year horizons. Also modeled were the impact of lower natural gas prices, a multistate split of rate- and mass-based compliance within the PJM region and state renewable portfolio standards.

Regardless of the pathway used, the CPP would not have a substantial impact on resource adequacy as “the capacity and energy markets [will be] able to attract sufficient new investment to satisfy PJM’s reliability requirements,” the RTO said.

Regional Compliance Reduces Costs

The analysis found that levelized compliance costs would range from $0.61/MWh (1.1% of the average total wholesale cost) for regional plans and $1.93/MWh (3.3%) for individual state plans that include regulation of both new and existing sources.

“The cost of compliance for the entire PJM region differs according to the compliance pathway chosen, but regional compliance leads to lower costs than does individual state compliance under both mass-based and rate-based compliance pathways,” the report said.

Regional compliance would result in fewer coal generator retirements and less new combined cycle gas plants than individual state compliance “due to the greater flexibility and options for emissions reductions offered across the entire PJM region,” the study said.

As a reference case, PJM also ran a simulation in which the CPP, which has been stayed by the U.S. Supreme Court pending legal challenges by numerous states, is not implemented. The simulations begin in 2018, thelatest that compliance plans can be submitted if the rule survives.

Impact of Gas Prices

The study found that continued low natural gas prices — assuming they remain in the $3 to $4/MMBtu range (in 2018 dollars) over the 20-year study period — “has a greater effect on emissions levels, the retirement of fossil steam resources and new entry of natural gas combined cycle resources than even the most stringent of the studied compliance pathways that also regulate the CO₂ emissions of new natural gas combined cycle resources.”

“Because of accelerated [coal] retirements, there would be no cost to achieve compliance, and the resulting emissions would be below the final Clean Power Plan targets, even without the Clean Power Plan,” PJM said.

Challenges for Nuclear, Boon for Renewables

Compared to the reference and mass-based options, PJM found that rate-based compliance would create lower energy market prices because subsidies for renewable resources would allow them to submit offers below production costs. This would increase capacity prices, however, as resources seek to replace lost energy revenue.

This would drive growth in renewables — which would earn more revenue from emissions rate credits than from the increase in energy market revenues under mass-based compliance — but “results in increased economic challenges for existing nuclear resources,” PJM said.

Mass-based plans, on the other hand, would increase energy market prices by adding costs for allowances. They would allow low-emission resources to depend less on non-market revenue and provide no incentive to price generation below cost. They would also make nuclear facilities more viable by pricing their low-emissions status.

The analysis also evaluated the impact of different time horizons on the nuclear and coal fleets.

If generation owners make retirement decisions based on a five-year horizon from 2018 through 2022 before initial compliance targets take effect, the study predicted up to 6 GW of nuclear retirements (in addition to the already-announced decommissioning of the Oyster Creek nuclear plant) and less than 1 GW of incremental coal-fired retirements. Gas prices would drive the reductions in the short run, but the study found nuclear plants become viable again in 2026 under CPP.

pjm clean power plan — Steam Turbine and Nuclear Units Age 40+, Combined Cycle Units 30+ (As of 2018)

“What the analysis shows is that over a 20-year horizon, the existing nuclear fleet can become economic, but in this near term, they face a lot of stress given the low gas prices and current market prices,” PJM’s Muhsin Abdur-Rahman said during a media briefing on the report Thursday.

The analysis found congestion will decline by 2025 under every compliance pathway compared to the reference scenario. Congestion related to historical west-to-east flows drops because of coal retirements in western PJM, although it is accompanied by more localized congestion.

Energy Efficiency

Rate-based plans would also require precise measurement and verification of energy efficiency to earn emission rate credits. A sensitivity that assumed states can convert only 50% of energy efficiency included in load forecasts into credits resulted in cost increases that were more than double the cost of trade-ready mass-based compliance, although still less than $1.50/MWh.

September 5, 2016

CAISO Board OKs Grid Services Requirements for Renewables

By Robert Mullin

CAISO’s Board of Governors last week approved proposed Tariff revisions that will require new renewable resources be capable of providing grid-stability services as a condition for interconnecting with the ISO’s system.

San Gorgonio Pass Wind Farm (Wikipedia) - renewables grid-stability services caiso — CAISO’s Tariff changes will require new and upgraded renewable resources to be capable of providing reactive power and voltage control. *Photo of San Gorgonio Pass Wind Farm source: Wikipedia*

While stakeholders largely support the amendments, some market participants contend they don’t go far enough in guaranteeing adequate compensation for what has become an increasingly important service as more intermittent resources link up with the grid.

The proposed revisions follow FERC’s June issuance of Order 827, which requires that all newly interconnecting non-synchronous generators have reactive power capability. Resources undergoing upgrades would also be subject to the new rules.

“We are pleased to now take this next step, in which clean power resources can contribute to the reliability of the grid,” CAISO CEO Steve Berberich said in a statement. “By providing reactive power, these resources are better suited to help us integrate increasing numbers of renewable resources.”

“It’s really good utility practice to require all resources in the fleet to have reactive power,” Keith Johnson, CAISO manager of infrastructure policy and contracts, told board members during an Aug. 31 meeting.

The ISO’s Tariff changes go beyond FERC’s mandate for reactive power capability by adding a provision requiring that non-synchronous resources also provide voltage regulation.

“Maintaining voltage is very important for how we operate in the West,” Johnson said, explaining the ISO’s rationale for the additional requirement. “The incremental cost of [automatic voltage regulation] equipment is very, very minimal.”

Thermal Generators Seek Raise

Although the new requirements had broad support among stakeholders, a disagreement arose over CAISO’s decision not to use this FERC filing to alter its compensation for reactive power — a move that would especially benefit thermal generators that are steadily losing market share to renewables.

Under current ISO practice, any generator that is dispatched down to provide reactive power is paid its opportunity cost for lost energy revenues. Generators want the ISO to implement a new market provision that would compensate them for the capital cost of installing reactive power equipment — effectively creating a capacity payment for providing reactive power service.

CAISO contends that generators can recover those costs through their power purchase agreements, given the West’s continued reliance on bilateral contracts for the provision of capacity. Any additional market mechanism would run the risk of creating double payments for the service, Johnson said.

“Providing reactive power is a service essential to the operation of the grid,” said Brian Theaker, director of market affairs at NRG Energy. “Today’s disappointing decision doesn’t advance that.”

Theaker said that the current compensation structure does not provide “reliable signals” for generating units that require longer-term guarantees to remain financially viable.

“We feel like there’s been an opportunity missed here,” said Carrie Bentley, a consultant representing the Western Power Trading Forum. “The ability to provide reactive power is not free,” she continued, adding that five other organized markets offer compensation for the service.

“It’s not a secret that renewable power is disrupting the [capacity] and energy market — a lot of thermal generation will not be able to remain in the market,” Bentley continued. “How do you provide a market signal strong enough to keep the thermal generation we need.”

“The ISO did talk about compensation and looked at some of the other ISOs and RTOs across the country,” Johnson responded. “When PJM or MISO was formed, there were legacy arrangements for capacity payments for reactive power. We have no such system of capacity payments — we have bilateral contracts.”

Keith Casey, CAISO vice president for market and infrastructure development, said Bentley’s concerns about the ISO’s thermal fleet were “spot on.” He pointed out that the ISO’s new flexible ramping product — which compensates generators for the ability to rapidly respond to intermittent output from renewables — is one effort to reward “needed” generators.

“We just view the reactive power capability as a fundamental requirement,” Casey said. “The capital cost for that capability should be addressed through bilateral contracts.”

September 5, 2016

State Briefs

ARKANSAS

EPA Finalizes State’s Regional Haze Plan

EPA has finalized a federal implementation plan for compliance with its Regional Haze Rule for the state, but regulators and at least one generator say they may appeal the decision.

The final rule calls for increased emissions control at three coal-fired plants and three natural gas-fired plants, in addition to a paper mill. One of the plant owners, Entergy, said compliance measures could cost it up to $2 billion and that the company is exploring its options. State environmental officials may also appeal the rule.

More: KUAR; ArkansasOnline

CALIFORNIA

Imperial Irrigation District Strikes Net Metering Agreement

Imperial Irrigation District, which generated public backlash after it cut off enrollment in its net metering program earlier this year, will allow as many as 1,300 new rooftop solar customers to sign up for the preferential rate.

The district, which provides electrical service to 150,000 customers, reached a deal with the solar industry and state lawmakers to enable any customers who applied for a solar interconnection permit and received a building permit by April 1 to enroll in the program.

IID struck the compromise in the face of possible passage of legislation that would have expanded the eligibility period to July 19.

More: The Desert Sun

Appeals Court Denies Release Of PUC-San Onofre Emails

A state appeals court last week reversed a lower court decision that would have forced the Public Utilities Commission to disclose its communications related to the agency’s settlement with Southern California Edison over the closure of the San Onofre nuclear generating station.

The appellate court sided with the PUC, which argued that the communications involved privileged information regarding a rate case. San Diego attorney Michael Aguirre had sought to release the emails to determine whether Gov. Jerry Brown was party to ex parte, private negotiations between former PUC President Michael Peevey and the utility ahead of the settlement. Peevey, a former SoCalEd executive, stepped down from the commission after the negotiations were revealed.

Though the court denied disclosure, it recommended Aguirre submit his request to the PUC under the state’s Public Records Act and, if denied, take his case directly to the appeals court. Aguirre said he will appeal to the state Supreme Court.

More: The Sacramento Bee

COLORADO

Co-op to Shutter 2 Plants Under Regional Haze Plan

The Tri-State Generation and Transmission Association said it will retire more than 500 MW of coal-fired generation in the next decade in order to comply with the state’s implementation plan for EPA’s Regional Haze Rule.

The electric cooperative said it plans to shutter the 100-MW Nucla Station in Montrose County by 2022, along with the nearby mine that feeds the plant. It also plans to close the 427-MW Unit 1 at the Yampa Project by 2025, although two other units at the site will continue to operate. It said it is more economical to close the units rather than retrofit them to comply with the regulations.

“Tri-State has worked tirelessly to preserve our ability to responsibly use coal to produce reliable and affordable power, which makes the decision to retire a coal-fired generating unit all the more difficult,” the company said. “We are not immune to the challenges that face coal-based electricity across the country.”

More: The Denver Post

MICHIGAN

Agencies Approve $89.5M In Energy Assistance

The Agency for Energy and the Department of Health and Human Services approved $89.5 million in Energy Assistance Program grants last week for 14 nonprofits and utilities.

The grants are meant to help low-income residents pay electric bills. Among the organizations and municipalities that received multi-million dollar grants, DTE Energy received $17 million and Consumers Energy received $13.2 million. The Salvation Army also received $13.7 million, while TrueNorth Community Services received $15 million.

More: WSYM

NEW MEXICO

Regulators Promise Decision On PNM Rate Case by Sept. 28

The Public Regulation Commission said it will issue a decision within a month on Public Service Company of New Mexico’s rate-increase request. The PRC’s announcement came after most parties in the case objected to reopening hearings.

PNM proposed a 15.8% rate hike earlier this year to cover its investments in power and energy-efficiency measures. In early August, a PRC hearing examiner recommended a 6% increase, saying PNM hadn’t justified the higher rate.

PRC acting general counsel Michael Smith said that as a result of the nearly “uniform” opposition to holding more hearings, “We are going to make a decision based on the recommended decision that was issued by Carolyn Glick,” the hearing examiner.

More: Santa Fe New Mexican

Regulator Approves ROW for Southline Transmission Project

Land Commissioner Aubrey Dunn last week gave right-of-way approval to the Southline Transmission Project, a proposed 345-kV double-circuit line that would cross into Arizona. Developers must still submit detailed plans about the exact location of structures and roads associated with the line, along with cultural and biological surveys.

Sponsored by Hunt Power subsidiary Southline Transmission, the line will provide up to 1,000 MW of transmission capacity in both directions and connect with as many as 14 existing substation locations.

More: Albuquerque Journal

OKLAHOMA

OCC Orders Fracking Wells Shut down After Earthquake

A magnitude-5.6 earthquake last week spurred state regulators to order 37 fracking waste disposal wells to shut down over a 725-square-mile area.

The order came from the Corporation Commission’s Oil and Gas Division. Gov. Mary Fallin said the commission is coordinating with well operators around the town of Pawnee and that several buildings in the Pawnee Nation had been rendered uninhabitable by the quake. She also said EPA is assessing the region.

The wells will close within 10 days of the order, according to a schedule the commission says is necessary because scientists have warned that a sudden shutdown could provoke another earthquake. A commission spokesperson said the wells were ordered closed because of the link found by the U.S. Geological Survey between wastewater disposal and the increased number of earthquakes in the region, particularly in the state.

More: CNNMoney; Bloomberg News; The Associated Press

Wind Opponent Seeks to End Tax Credits Next Year

WindWaste, an organization opposed to wind power incentives, estimates that future wind developments could force the state to shell out more than $500 million annually in zero-emissions tax credits by 2019.

The subsidy is set to sunset on Jan. 1, 2021, but WindWaste wants lawmakers to end the credit by July 1, 2017. The next legislative session begins in February.

Representatives of the wind industry say WindWaste’s estimates of $5.2 billion in payouts by 2030 is wildly inflated. It argued that the group based its predictions on the amount of generation in SPP’s interconnection queue, which only has a buildout rate of about 15%, it says.

More: The Oklahoman

SOUTH DAKOTA

Developers of Wind Project Withdraw Request for Permit

Developers of the Prevailing Winds project asked state regulators last week to withdraw their application for a permit. The retreat came one week after a raucous, four-hour community meeting near Pierre.

Public Utilities Commission Chair Chris Nelson said the request was “unexpected.” The request came shortly before the commission’s Aug. 30 meeting and could be considered at its Sept. 13 meeting.

Prevailing Winds would produce about 200 MW of electricity. By asking to have its application dismissed without prejudice, developers could again apply for a permit at a later date.

More: Rapid City Journal

TEXAS

Austin City Council Approves Rate Cut

The Austin City Council last week unanimously approved Austin Energy’s request to redo its residential electric rates, but not before the city-owned utility first dropped a controversial proposal for an increase. Under the revised rate structure, the municipal utility’s 400,000 residential customers would see bills cut by about $62/year.

The council also signed off on $42.5 million in annual cuts that Austin Energy and its major customers agreed to earlier this month. Most of those cuts will go toward reducing electric bills for industrial and commercial customers. Major customers, such as data centers and large hospitals, will see their electric rates cut 24%.

The utility’s original proposal came under attack because of Austin Energy’s tiered residential price structure: Customers pay the base rate for their first 500 kWh of electricity and higher rates for subsequent blocks of 500 kWh.

More: Austin American-Statesman

VIRGINIA

SCC Examiner Affirms Right To Third-Party Solar Financing

A State Corporation Commission hearing examiner rejected an argument by Appalachian Power that third-party solar financing was illegal, paving the way for homeowners to sign up for the popular method of paying for residential solar-system installations.

“Today’s decision is an important win for solar rights in Virginia, which has continued to lag behind neighboring states on solar because of outdated policies and utility opposition like we saw from Appalachian Power in this case,” said Will Cleveland, staff attorney at the Southern Environmental Law Center. “The ruling confirms that Virginians have the right to use common sense financial tools to choose solar power without utilities acting as the middle men.”

The utility argued that third-party financing, in which homeowners paid for solar systems through monthly contracts, was legal only under a Dominion Power pilot project. The ruling now goes before the full commission for public comments and final briefs.

More: The Energy Fix

WISCONSIN

Regulators Approve Enbridge Pipeline Replacement

The Department of Natural Resources has granted a waterway and wetlands permit for Enbridge Energy to replace a section of old oil pipeline.

Ben Callan, a DNR water management specialist, said the permit is for replacing a 14-mile stretch of Line 3, a 1960s-era pipeline. The pipeline had been operating at a diminished capacity after Enbridge recently found issues during integrity tests. The new section will have a 36-inch diameter and be able to carry up to 760,000 barrels per day.

Callan said that the permit requires the hiring of an independent consultant to oversee compliance. Enbridge spokeswoman Shannon Gustafson said the company has not set a timeline for construction.

More: Wisconsin Public Radio

September 5, 2016

ERCOT Expects Adequate Generation for Fall, Winter

By Tom Kleckner

ERCOT’s latest resource adequacy assessments indicate it has 25,000 to 30,000 MW of spare generating capacity for the fall and winter.

ERCOT Control Room (ERCOT) - fall winter ercot generating capacity — ERCOT’s control rom *Source: ERCOT*

The Texas grid operator’s final Seasonal Assessment of Resource Adequacy (SARA) for October and November includes more than 82,000 MW of capacity, more than enough to meet a projected peak demand of about 54,400 MW.

The preliminary winter SARA report is similarly rosy, with more than 81,000 MW of capacity available to meet a forecasted record peak demand just under 59,000 MW. The winter demand record of 57,265 MW was set during February 2011’s record cold.

ERCOT, which operates 90% of the Texas grid, said four gas-fired combustion turbine units and three wind projects have begun operating since its preliminary fall SARA, adding nearly 900 MW of capacity. Three of the gas units are switchable resources and can connect to either ERCOT’s or SPP’s grids. The fall forecast assumes 13,700 to 19,000 MW of planned and unplanned outages.

Another 1,200 MW of new winter-rated capacity is expected to be in service for the winter season (December-February). The final winter SARA report will be released in November.

— Tom Kleckner

September 5, 2016

Monitor OKs PJM Auction; Says Problems Remain Despite CP

By Rich Heidorn Jr.

PJM’s Independent Market Monitor last week gave his blessing to the RTO’s Base Residual Auction for delivery year 2019/20 but called for additional rule changes to build on the tougher standards of Capacity Performance.

The Monitor’s report on the May auction concluded that the results “were competitive, with the caveat that although the Capacity Performance design addressed the most significant issues with the capacity market design, the Capacity Performance design was not fully implemented in the 2019/2020 BRA and there continue to be issues with the capacity market design which have significant consequences for market outcomes.”

PJM will require all capacity to meet CP standards starting with the 2020/21 delivery year.

pjm market monitor capacity auction capacity performance — Bowring © *RTO Insider*

The Monitor called for additional changes concerning the treatment of pseudo-tied generation, demand response and energy efficiency; the calculation of net revenues; and the application of the minimum offer price rule (MOPR).

The Monitor also acknowledged that its call for using the lower of the cost- or price‐based offer in the calculation of net revenues was rejected by FERC in June (EL14-94-001, ER16-1291). (See “FERC Won’t Revisit Cost-Based Energy Offer Cap Ruling,” PJM News Briefs from FERC Open Meeting.)

But he said the FERC-approved approach used in the May auction, which always uses the cost‐based offer, “resulted in an increase of [$43.4 million], or 0.6%, in the cost of capacity in the 2019/20 BRA.”

In addition, the Monitor recommended:

All costs incurred as a result of a pseudo-tied generator be borne by the unit and included in its capacity market offers.
The “electrical proximity” of pseudo-tied resources be “explicitly accounted for” when defining how external resources should be treated during performance assessment hours.
Enforcing “a consistent definition” of capacity resource as a physical resource at the time of the auctions — with a commitment to be physical in the delivery year and moving all DR to the demand side of the market. The Monitor referenced its 2013 report on replacement capacity, in which it warned that “speculative” DR can suppress prices in the BRA and displace physical generation: “Under the current application of the rules, DR providers may not have identified customers, may not have clear plans for implementing DR measures and may not receive commitments from new customers until relatively close to the delivery year and well after the RPM BRA is run for that delivery year. This is not consistent with the rules.”
Ensuring the net revenue calculation used to establish the net cost of new entry “reflect the actual flexibility of units in responding to price signals rather than using assumed fixed operating blocks that are not a result of actual unit limitations.” Reflecting actual flexibility will result in higher net revenues, which affect the demand curve and market outcomes, the Monitor said.
Eliminating the rule requiring that small proposed increases in the capability of a generator be treated as planned for purposes of mitigation and exempted from offer capping.
Changing the MOPR review to require all projects use the same modeling assumptions. “That is the only way to ensure that projects compete on the basis of actual costs rather than on the basis of modeling assumptions,” the Monitor said.
Extending the MOPR to existing units in addition to new units.
Re-evaluating the market mitigation exemption granted DR and energy efficiency resources in 2009. “In 2009, there was one product defined for capacity, and there were no resource constraints defined,” the Monitor said. “Particularly in [locational deliverability areas] with few suppliers, there is now the potential for DR and EE providers to exercise market power and affect the clearing price.”
Changing the RPM solution methodology to explicitly incorporate the cost of make-whole payments in the objective function.
Removing energy efficiency resources from the supply side of the capacity market to reflect the change in PJM’s load forecasts. (See Changes to PJM Load Forecast Cuts Benchmark Peaks.) “If EE is not included on the supply side, there is no reason to have an add-back mechanism,” the Monitor said. “If EE remains on the supply side, the implementation of the EE add-back mechanism should be modified to ensure that market clearing prices are not affected.”