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September 13, 2024

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Can 2017 Top 2016 for Breaking Ground in New York?

By William Opalka

Upstate nuclear power plants will start earning additional revenue for their carbon-free attributes in April as New York becomes the first state in the nation to offer the industry a lifeline.

The zero-emission credit program, adopted Aug. 1, was but one of a dizzying blitz of policy initiatives from New York regulators in 2016.

distributed energy resources new york nuclear power
Nine Mile Point | Constellation Energy Nuclear Group

The nuclear supports were included in the Clean Energy Standard, which mandates 50% renewables by 2030. The Public Service Commission also admitted that the retail electric and gas markets have failed and needs to be revamped. And under the path-breaking Reforming the Energy Vision, the PSC began proceedings to develop a new utility revenue model and ways to value distributed energy resources. With NYISO, the PSC also moved forward on $1 billion in transmission projects.

Those are just a few of the initiatives that will continue into 2017 and beyond, many of them under the very large umbrella of REV.

ZECs

The PSC proposed the ZEC program in February to prevent the closure of nuclear plants whose revenues have suffered under low natural gas prices. The additional revenue was crucial to Exelon’s agreement to purchase Entergy’s James A. FitzPatrick plant, which the company had threatened to retire.

The PSC upheld the ZEC and CES programs on rehearing late last month, but the ZECs still face two court challenges. Opponents say the estimated $7.6 billion over 12 years of payments are merely props to save upstate jobs and that the program interferes with the wholesale market. Others contend the money would be better spent on a faster transition to renewable energy. (See NYPSC Rejects Challenge to Clean Energy Standard, Nuke Subsidy.)

Crackdown on ESCOs

The PSC in 2016 continued a crackdown on energy service companies, culminating in a December decision that the retail-choice market couldn’t be reformed on the margins, instead needing a top-to-bottom overhaul. (See NY Regulators Call for Overhaul or End to Mass-Market Retail Choice.)

The proceeding, which will begin with a procedural conference Jan. 26, is an apparent change in strategy for the PSC, which lost a court challenge to its February order requiring retailers to guarantee savings for most mass-market customers. (See New York ESCO Order Vacated by Court.)

The PSC also banned ESCOs in December from signing up low-income customers, upping the ante from a previous order that set a moratorium on sign-ups. The ECSOs have yet to respond to the latest salvo.

PSC staff also released a report that starts a two-phase process to change the way DER are valued. The move is intended to replace the crude instrument of net metering with more sophisticated, granular metrics for weighing the value rooftop solar and other distributed energy resources provide to the system and the costs they impose. (See NYPSC Vision for DER: From Net Metering to ‘Value Stack’.)

The PSC says DER can improve system efficiency if their value is properly reflected in retail and wholesale markets and if utilities are incented to consider them as alternatives to traditional capital investments. NYISO plans to release a “road map” on integrating these resources into the wholesale markets in early January.

And to more fully integrate renewable energy resources into the New York grid, proceedings are underway for two public policy transmission projects under FERC Order 1000.

One, the Western Energy Connection, will add 1,000 MW of transmission capacity for hydro, gas and renewable generation, including the dam at Niagara Falls. In June, NYISO identified 10 proposed upgrades as finalists, submitting their findings to the PSC. (See NYISO Identifies 10 Public Policy Tx Projects.) The commission in October ordered further review and project selection by NYISO.

A second project will expand transmission corridors in central New York and the Lower Hudson Valley to provide easier power flows from the wind energy areas to the load centers near New York City. The PSC just closed a comment period on whether that project should proceed. (See NY Transco Chief: Tx Buildout ‘A Marathon, not a Sprint’.)

NYISO Strategic Plan

NYISO’s Strategic Plan for 2017-2021, released Dec. 15, says the grid operator will integrate the public policy goals of New York state to switch to cleaner and more DER while adding technological innovations to grid operations.

In addition to maintaining reliability, an important focus will be responding to changes resulting from REV, the ISO said.

In addition to the DER “roadmap,” the ISO will pursue greater fuel assurance through gas and electric coordination; capacity market improvements, including reduced reliance on reliability-must-run agreements; the demand curve reset; and improvements to its real-time commitment/real-time dispatch forward horizon coordination.

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PJM Capacity Debates, Angst over State Subsidies to Continue in 2017

By Rory D. Sweeney

After its first full year under new CEO Andy Ott, and the last year of its transition to 100% Capacity Performance, PJM heads into 2017 amid continued ferment over the capacity market and angst over the impact of state subsidies to generators.

markets and reliability
Ott | © RTO Insider

When Mike Kormos — Ott’s main challenger to replace former CEO Terry Boston — left PJM in March, Ott quickly restructured his executive staff, eliminating Kormos’ chief operations officer position and elevating deputy Stu Bresler to control of both the Markets and Operations divisions. The move put Bresler in charge of Kormos’ former deputy, Mike Bryson. Ott also expanded the authority of General Counsel Vince Duane. (See Ott Restructures PJM Divisions, Leadership.)

Ott’s reorganized team faced a series of challenges to the competitive electric model that rules in most PJM states.  While the 20th anniversary of retail choice was celebrated in Pennsylvania, the competitive model came under attack elsewhere. (See Crafters of Pa.’s Deregulation Law Look Back After 20 Years.)

markets and reliability

Public Policy vs. Markets

PJM has long dealt with state mandates and federal tax credits for renewable generation. The newer challenge is subsidies ordered by state policymakers fearful of losing in-state coal and nuclear generation — and their thousands of jobs — that are imperiled by environmental costs and low natural gas prices.

Michigan legislators voted in December to continue its 10% cap on retail choice. (See Michigan Energy Bill Preserves RPS, 10% Retail Choice Cap.) In Ohio, state regulators approved power purchase agreements to subsidize FirstEnergy’s and American Electric Power’s money-losing fossil fuel generation. The deals, which some critics valued as high as $6 billion, collapsed after FERC said they would be subject to its stringent review. FirstEnergy ultimately won state backing for $612 million in state support over eight years and said it would be exiting competitive generation. AEP is hoping to persuade Ohio legislators to reverse customer choice and reregulate the industry. (See PUCO Rejects FirstEnergy’s $558M Rider, OKs $132.5M; AEP Ohio Rate Plan Excludes Merchant Generation.)

Illinois followed New York’s lead in approving zero-emission credits to support Exelon’s two ailing nuclear plants in the state. (See Illinois Lawmakers Clear Nuke Subsidy.)

“The future of PJM markets is at issue,” Independent Market Monitor Joe Bowring said. “The PJM capacity markets cannot work with significant new subsidies. Subsidies suppress both the capacity price and the energy price. Both capacity market and energy market revenues are essential to providing incentives for new entry and for maintaining existing resources.”

FirstEnergy Wants Out of Competitive Generation
Sammis Power Plant | Bechtel

PJM outlined its concerns and defended its performance with a 45-page report in May. (See PJM Study Defends Markets, Warns State Policies can Harm Competition.)

In an interview with RTO Insider last month, Ott said he didn’t see the state initiatives as existential threats to competition. “I don’t see a concern being raised within PJM [about whether] it delivered value,” he said. “There has been a lot of benefit to competition. [It] seems to be more the question: How do we manage the entry and exit to make sure it’s being done in a reliable manner?”

Ott pointed out that between 4,000 and 5,000 MW of new generation has entered each of the past four capacity auctions. It’s “not only a swap in fuel, but a swap in technology,” he said, that is driving down costs and forcing legacy assets to consider retirement.

The tension between state policymakers and federally regulated wholesale markets is but one of the issues of 2016 likely to continue making news in 2017.

Planned transmission upgrades to the Artificial Island nuclear complex were put on hold in August after rising costs and complaints over cost allocation, another frustrating delay in what was to be PJM’s first competitive project under FERC Order 1000. (See PJM Board Halts Artificial Island Project, Orders Staff Analysis.)

Following a technical conference in February, FERC ordered changes to PJM’s rules on financial transmission rights and auction revenue rights and rejected the RTO’s first attempt at a fix. (See FERC Finds PJM ARR/FTR Market Design Flawed; Rejects Proposed Fix.)

It all sets up for an eventful 2017. Here’s some of the issues likely to dominate PJM stakeholder meetings in the new year:

The Case for Capacity Performance

No issue is likely to consume more stakeholder attention than continued debate over PJM’s new CP rules. After acquiring 80% CP resources in the 2015 and 2016 Base Residual Auctions, PJM will be requiring 100% CP for the 2017 auction, eliminating base capacity.

Ott defends the need for the increased performance requirements and nonperformance penalties under CP, although he conceded that changes to the market — such as what the minimum offer price should be — need to be considered. “[We were] seeing a lot of new units coming in, but not every one of them was coming in with firm fuel,” he said, referring to the previous rules, under which forced outage rates peaked at 25% during the 2014 polar vortex — the event that led to the tougher rules.

A coalition of cooperatives and municipal utilities has been campaigning for several months for a holistic review of the capacity construct, questioning whether the current model is sufficiently flexible to respond to state initiatives. (See “Stakeholders Remain Skeptical of Campaign to Revisit CP,” PJM Markets and Reliability Committee Briefs.)

Others have called for more specific rule changes, including extending the life of base capacity, incorporating seasonal capacity products and relaxing some of the construct’s strict performance rules. (See FERC Wants More Detail on PJM’s Seasonal Capacity Plan.)

Bowring | © RTO Insider

Bowring has continued his call to eliminate demand response as a capacity resource, saying PJM should limit its role to the demand side of the capacity calculations.

Security in All its Forms

A major focus for PJM in the coming year will be analyzing its security. It has completed a multiyear effort to develop a security strategy focused on cyber and physical protections, Ott said. “We’re already one of the leaders in the space, but continuous [improvement] is important to provide value to our customers,” he said. (See “Preview of Security Committee Receives Tepid Response,” PJM Markets and Reliability and Members Committees Briefs.)

The transition in fuel sources for generating units is receiving consideration as well. The rapid expansion of gas-fired and retreat of coal-fired generation has made PJM “more diverse than we’ve ever been,” Ott said, but he added, “Is there a point where we become concerned about being over dependent” on gas? The RTO has undertaken a fuel-security study to find out, the results of which are scheduled to be released by the end of the first quarter, Ott said.

Fixing FTRs and ARRs

FERC’s order requiring changes in PJM’s FTR/ARR market design and rejecting the RTO’s proposed correction sent PJM back to devise a new strategy, which it submitted in a Nov. 14 compliance filing (EL16-6, ER16-121). The order called for shifting the costs of balancing congestion onto load and allocating ARRs in a way that doesn’t consider extinct generators.

PJM filed for the changes to be implemented by June 1 while the Monitor requested rehearing, saying the commission erred in requiring load to shoulder the congestion costs. (See Monitor Says FERC Erred in PJM FTR Ruling, Seeks Rehearing.)

Renewed Turf Battle

Last year also saw a renewal of tensions between the Monitor and PJM management as Bowring took exception to the RTO’s attempt to constrain his unit’s role in the review of cost-based offers. (See PJM Attempting to Usurp Market Mitigation Role, Monitor Says.)

The disagreement is part of a larger dispute over fuel-cost policies, which Bowring defends as a major part of the Monitor’s role. “Fuel-cost policies are core to defining and evaluating competitive offers, which equal short-run marginal costs,” he said.

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FERC OKs New CAISO Load-Serving Entity Definition

By Robert Mullin

FERC approved a CAISO Tariff revision expanding the definition of a “load-serving entity” to include organizations that purchase wholesale electricity to serve their own needs (ER17-218).

The ISO’s rules previously recognized as LSEs only those entities that sell electricity or serve load to end users, a description that covers utilities, federal power marketing agencies and community-choice aggregators.

ferc caiso load-serving entity
CAISO’s LSE definition refinement eliminates a subcategory that previously covered California’s State Water Project, which will now fall under the newly expanded definition. |  CDWR

The original definition also made a special provision for the State Water Project (SWP), a California agency that directly engages the wholesale market to cover its own energy requirements. The revision eliminates that subcategory, with SWP now covered under the newly expanded definition.

The ISO sought to broaden the definition to accommodate the San Francisco Bay Area Rapid Transit District (BART), which, like the SWP, serves its own load but did not meet the standard definition of an LSE. (See CAISO Issues Revised Proposal to Expand LSE Definition.)

BART’s transmission contract rights on Pacific Gas and Electric’s network, which predate the existence of the ISO, expire at the end of 2016. When those rights automatically convert to CAISO service, the agency will be exposed to congestion charges.

The definition change will permit BART to receive a free congestion revenue rights allocation in the ISO’s annual process in order to hedge the transmission costs of serving its load. The revised Tariff language also makes clear that BART — and any other entity choosing to serve its own load — will be subject to resource adequacy obligations.

caiso load-serving entity ferc
| BART

“We find that the revised definition is a reasonable approach to encompass entities, such as BART, that are currently excluded but that nonetheless should be considered a load-serving entity, and avoids the need for CAISO to add carve-outs to the definition, as it initially did for State Water Project,” the commission said in its Dec. 30 ruling.

The revision also alters a provision requiring that any LSE must be authorized to serve load under California state or local law — deleting the reference to California. The change was intended to acknowledge the current membership of Nevada-based Valley Electric Association and to prepare the ISO for additional out-of-state members through regional expansion.

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ERCOT Looks to Incorporate DG, Improve Ancillary Services in 2017

By Tom Kleckner

Fifteen years after it first opened, ERCOT’s competitive electric market is pretty much running on cruise control. It has ample low-cost electricity to meet Texas’ growing demand and continues to add renewable resources. And 2016 will go on record as having the lowest prices ever.

ERCOT ancillary services RMR 2017
ERCOT’s distributed generation portfolio (Shell Energy)

Sure, protocols always need tweaking, the ISO’s reliability-must-run practices still draw stakeholder complaints and there are congestion concerns in Houston, West Texas and the Rio Grande Valley. But otherwise, ERCOT enters 2017 with a grid those in power see as the envy of others.

“Nobody has a competitive market like ours,” Texas Public Utility Commission Chair Donna Nelson said during a July meeting. The PUC has regulatory oversight of ERCOT, and Nelson often trades quips during open meetings with her two fellow commissioners over the market’s success.

Load-weighted average wholesale prices for 2016 were less than $25/MWh, far below the 2008 high of $77.19/MWh. Average prices have stayed below $41/MWh in seven of the last eight years. Not surprisingly, customer complaints to the PUC fell to 4,835 complaints, down from 6,973 the previous year, according to the Texas Coalition for Affordable Power.

The ISO, which boasts more than 18,000 MW of installed wind capacity, set a new record for wind energy production Christmas morning with 16,022 MW.

With 7 million smart meters, the Texas Interconnection is also one of the more advanced grids around. “We’ve got a retail market that offers customers choice in a way that’s more mature and more fulfilled than any other retail market in the world,” ERCOT CEO Bill Magness said in November.

DER Focus

Much of the focus in 2017 will be on accommodating distributed energy resources and determining how those smaller power sources can be aggregated to predictably meet demand.

In preparation for the new year, ERCOT staff have been working to map the system’s smaller (greater than 1 MW that inject to the grid) registered distributed generation units and on a white paper addressing DER’s reliability. Both efforts are picking up on the work of the Distributed Resource Energy and Ancillaries Market (DREAM) Task Force, a two-year effort that ended last year with a report that made eight recommendations.

The ISO estimates it has 900 MW of DG in its competitive areas (which doesn’t include the cities of Austin or San Antonio). It expects DG to grow at 10% annually, which is why staff wants to account for the DER on the system in both competitive and noncompetitive areas.

“With an 80,000-MW system, that’s not a huge penetration at this point,” Magness said. “These resources don’t raise a long-term reliability issue — they’re not waving a red flag — but we expect to see a lot more, whether for environmental reasons or people wanting energy independence. If you don’t know you have a large cluster of DG, your load forecasts are not going to be right.”

Magness likes to joke about the Austin moving company that has the motto, “If we can get it loose, we can move it.”

“If we can see it, we can integrate it,” he says.

Ancillary Services

ERCOT is also looking to improve its visibility into ancillary services and inertia data. Its existing ancillary services framework was lifted from a market design developed in the 1990s, and staff and stakeholders have been working since 2013 to unbundle the services and improve the market’s ability to handle DG, fast-acting storage devices, smart-grid technologies and other new developments.

A staff proposal to separate responsive reserve service into fast-frequency response, primary frequency response and contingency reserve service categories did not receive sufficient stakeholder support to move forward. A Brattle Group report on these “future” ancillary services determined they would offer economic benefits “on the order of 10 times the [estimated $12 million to $15 million in] implementation costs.”

ERCOT currently spends about $500 million annually on these services.

The ISO could also face an RMR rulemaking (Project No. 46369) in 2017 from the PUC. The commission held a workshop on the practice in December, gathering feedback from market participants on how it might limit a practice that even Magness has acknowledged can be a “blunt instrument.”

Reliant Energy’s Bill Barnes, who failed to gain enough support this summer for a protocol change that would price RMR units at the end of the dispatch queue, said during the workshop that the process “indicates the market has failed to retain and attract sufficient resources to meet ERCOT’s reliability criteria. The best solution to RMR is to not have any.” (See “Board Rejects RMR Mitigated-Offer Appeal, Lets Stakeholder Process Move Forward,” ERCOT Board of Directors Briefs.)

Barnes, the PUC staff and other stakeholders discussed modifying the RMR-evaluation timeline, the ERCOT board’s approval of RMR agreements potential changes to the review methodology.

Currently, RMR units are subject to the same offer mitigation as other units.

The ISO this year should complete much of its technology “refresh,” a four-year, $48 million initiative updating its computer technology. The final three of the 11 refresh projects — remote access and two telecom efforts — are scheduled to begin in 2017. By the end of 2017, ERCOT will have updated its database servers and core network.

The project has already spent 40% of its budget, Magness said in December, and it is expected to come in under or at the $48 million target.

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MISO Changes to Queue, Auction, Cost Allocation to Dominate 2017

By Amanda Durish Cook

MISO’s 2017 will likely be filled with capacity auction changes, cost allocation debates, an updated interconnection queue and multiple transmission studies.

The RTO filed its proposed forward capacity auction for its retail-choice areas Nov. 1 and requested a March 1 effective date (ER17-284). (See MISO Files Forward Capacity Auction Plan with FERC.)

MISO spent much of 2016 reconciling the forward capacity market with the existing prompt capacity auction and utilities’ forward resource adequacy plans and bilateral contracts. “There was a rush to the finish line to file the Competitive Retail Solution,” Resource Adequacy Subcommittee Chair Gary Mathis said. “We’ll hopefully find out in early springtime” if the proposal passed FERC’s muster.

Assuming FERC approval, work to implement the forward auction alongside the prompt auction will continue through 2017 before the first bifurcated auction in April 2018 for the 2018/19 planning year.

Interconnection Queue Changes

Curran | © RTO Insider

MISO expects a FERC decision any day on its second attempt to reduce uncertainty and the amount of time it takes for projects to clear the interconnection queue. The late October filing proposes fewer restudies, optional “off-ramps” with fee refunds for withdrawing projects, a smaller initial milestone payment and subsequent milestone payments based on a percentage of upgrade costs. “It’s currently a two- to three-year process and is challenged by restudies,” said Jennifer Curran, MISO vice president of system planning and seams coordination.

If all goes as planned, queue changes will take effect in January. Although the new process has yet to be approved, MISO has begun to prepare for the transition, with all projects expected to follow the new rules after February 2017’s batch of interconnection applicants.

FERC rejected MISO’s first proposal in spring, telling the RTO it placed too much blame for the queue’s bottleneck on “speculative” projects and said its proposed milestone payments to move along the queue were prohibitively high (ER16-675).

Cost Allocation

MISO also will set aside some of 2017 to revise its cost allocation formulas for market efficiency projects and sub-345-kV economic projects. The RTO hopes to complete the revisions in 2017 and implement them by 2018, when Entergy’s integration transition period, which limits cost sharing in MISO South, expires. (See MISO Stakeholders Propose Changes to Market Efficiency Cost Allocation Process.)

“We all know cost allocation is a money issue where consensus is not likely to spring up like a flower,” outgoing MISO Director Judy Walsh said at the December Advisory Committee meeting.

“I think we’ve seen a lot of movement; no one is going to get what they want, but we are on a path,” Xcel Energy’s Carolyn Wetterlin replied.

North-South Bottleneck

MISO is also planning a study that will examine the benefits of building new transmission to supplement the constrained transmission interface linking the RTO’s North/Central and South regions. In January, FERC approved a seven-year settlement that stipulates MISO’s north-to-south flows using SPP’s transmission be restricted to 3,000 MW and 2,500 MW south to north. (See MISO Proposes Study to Measure Benefits of New North-South Tx.)

There’s “nothing so stark as the North-South constraint” to MISO system planners, Curran told the Markets Committee of the Board of Directors last spring.

The RTO will also embark on an ambitious long-term transmission overlay study looking at system needs under three future scenarios, with varying assumptions on carbon reduction targets, natural gas prices, coal generator retirements and renewables growth.

Beginning Jan. 31, the Economic Planning Users Group will review an initial set of transmission needs to design preliminary overlays, said Lynn Hecker, MISO manager of expansion planning. Long-term transmission needs are expected to be identified at the end of 2017. (See “Long-Term Overlay Study Scoped; MISO Asks for More Responses,” MISO Planning Advisory Committee Briefs.)

Competitive Transmission Development

Late last month, MISO selected LS Power subsidiary Republic Transmission over 10 other bids to build the Duff-Coleman 345-kV transmission project, the RTO’s first competitive project under FERC Order 1000. The work in Southern Indiana and Western Kentucky includes the construction of two substations and a 28.5-mile line connecting them. Republic will be delivering quarterly updates to MISO throughout 2017 on the $49.8 million project. (See LS Power Unit Wins MISO’s First Competitive Project.)

While that work progresses, the RTO’s stakeholders are expected to spend the first half of 2017 identifying improvements to the RTO’s competitive developer selection process.

IT Refresh Coming

| MISO

MISO, which estimates it will spend about $1.1 billion on information technology between 2015 and 2019, has hired consultants for another study to assess its aging system software. Results of the study will be reveal how well the RTO’s software can accommodate the effects of a changing resource mix, increased intermittent and behind-the-meter generation and increased combined cycle units.

The RTO also plans to begin work on six projects in 2017 to improve its market systems in its ongoing Market Roadmap process. (See MISO to Study Aging Software; Market Improvements Planned for 2017.)

MISO Looks Back at 15

MISO took time last month to reflect on its 15th anniversary of becoming an RTO. At the December board meeting, CEO John Bear noted that the RTO has grown from 21 employees in 2000 to about 900 in 2016.

“The beginning tested our tolerances. Without regular money coming in, it’s hard to see a path forward,” said Steve Kozey, senior vice president of compliance services and one of those hired in 2000. “In February 2002, when FERC approved our Tariff and MISO could start recovering costs on a regular basis, employees let out a sigh of relief because they knew from then on out, they could count on a paycheck each month.”

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SPP Coal Generation Continues Decline; Wind, Load Records Set

By Tom Kleckner

Coal-powered generation continues to decline in SPP’s market, accounting for only half the RTO’s total energy production this fall (September-November), according to the Market Monitoring Unit’s recently released State of the Market report.

Wind production and lower gas prices have combined to reduce the use of coal resources, which accounted for 60% of SPP’s energy production just two years ago. At the same time, wind energy has increased its share of production from 13% in fall 2014 to 20% in 2016.

Not surprisingly, coal resources only set real-time prices 37% of the time this fall, compared to 52% in 2015. Cheaper gas units (combined cycle and simple cycle) were marginal 53% of the time, with wind resources setting the price 9% of the time.

After record low prices in the spring, gas prices rose in the fall, with the average cost of $2.61/MMBtu at the Panhandle Hub, compared to $2.25/MMBtu in 2015. The real-time balancing market’s average LMP was $25.10/MWh, up from $19.98/MWh a year ago; the day-ahead market saw an increase from $20.73/MWh last year to $24.43/MWh this fall.

The report also noted virtual transactions have “steadily increased from year to year,” driven primarily by financial-only market participants. Financial players completed 2.1 million virtuals this fall, with resource and load owners accounting for just over 62,000.

SPP saw “marked” increases of 12.6% and 13.7% of load in October and November, respectively, bettering the previous high month of 10.8% last March. Virtual transactions as a percentage of load have increased from 7.1% two years ago to 11.7% in 2016.

The RTO filed the report with both FERC and the Arkansas Public Service Commission.

SPP Sets New Wind Generation, Winter Load Marks

SPP set a new record for wind generation Friday when the footprint cracked the 12,000-MW threshold for the first time, producing 12,141 MW. The latest record was its sixth in 2016 for wind generation, breaking the previous high of 11,305 MW on Nov. 17.

The RTO also set a new winter load peak of 40,323 MW on Dec. 19, marking the first time its winter load surpassed 40,000 MW.

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CAISO Expansion in Question as EIM Grows

By Robert Mullin

CAISO rang in 2016 with a strong push to expand its operation into PacifiCorp’s sprawling six-state service territory, but the project hit a stumbling block by mid-year as skeptics called on the ISO to slow its regionalization effort.

A 2015 state law requires the grid operator and state energy agencies to explore ISO expansion to help California meet its 50% renewable energy mandate.

The ISO last year kicked off a set of initiatives considered to be “central” policy elements of expanding into a region with dozens of balancing areas subject to multiple state and municipal rules.

Those efforts — still ongoing — dealt with the complex and often contentious issues of allocating transmission costs, maintaining adequate regional resources and accounting for greenhouse gas emissions. (See CAISO Refines Cost Allocation Proposal for Expanded BA and CAISO Kicks Off Effort to Track GHGs Under Regionalization.)

But the most challenging initiative was the effort to develop governing principles that would assuage concerns about California dominating the policies and management of a Western RTO.

Particularly contentious is California’s requirement that the state’s utilities track carbon emissions from generation serving their loads in order to ensure compliance with emissions caps. CAISO’s provision of generation data is key to that effort, which means that every generator in an expanded ISO would be subject greenhouse gas reporting requirements in order to track deliveries to California — regardless of whether the unit is located in a coal-heavy state disinclined to impose such a requirement.

When industry participants across the West expressed concerns that an initial governance proposal threatened to compromise the energy policies of “non-California,” CAISO returned in July with a revised document that emphasized the preservation of state authority. (See Governance Plan Fails to Dispel Western RTO Concerns and Revised Western RTO Governance Plan Highlights State Authority.)

By late July, critics within California — fearing the loss of CAISO as an instrument of the state’s renewable and emissions goals — were calling for a slowdown in regionalization, saying that the ISO was moving too quickly to get a governance plan to the State Legislature before the end of its summer session. (See Governance Plan Critics Urge Slowdown of Western RTO Development.) Gov. Jerry Brown heeded their concerns, directing state agencies to take more time to develop a proposal. (See Governor Delays CAISO Regionalization Effort.)

While the ISO plans to submit a governance plan to lawmakers this winter, President-elect Donald Trump’s vow to cancel the Clean Power Plan is another roadblock for CAISO-led regionalization. Under the CPP, interior West states such as Utah and Wyoming would confront the requirement of sharply reducing carbon emissions from coal-fired generation, an objective made less costly by access to low- and zero-emission electricity made available through a regional market. With the Trump administration likely to pull the rug from under the CPP, coal-heavy interior West states contemplating an RTO will be less motivated to give ground to California’s environmental mandates in order to gain the emissions benefits of membership.

That, in turn, could prevent California legislators from signing off on a governance plan that risks the state’s ability to meet its goals.

“California will want to protect its environmental objectives,” retiring California Public Utilities Commissioner Mike Florio, a strong supporter of regionalization, told RTO Insider.

Ann Rendahl, commissioner with the Washington Utilities and Transportation Commission, said the success of regionalization will depend on how California’s lawmakers deal with the governance issue.

“It’s really in the hands of California,” Rendahl said.

EIM Accelerates Growth

The future looks brighter for the Energy Imbalance Market, the West’s only real-time energy market. Unlike in the ISO, members are not required to turn over control of their transmission and generator day-to-day participation is voluntary.

caiso eim seattle city light

The market last year extended its north-south reach with the integration of Arizona Public Service and Puget Sound Energy, expanding membership to four balancing authority areas, in addition to CAISO. The two utilities began transacting in the market in October after what officials called a largely uneventful implementation. (See Smooth EIM Transition for Arizona Public Service, Puget Sound Energy.)

“I’ve been through three sets of transitions, and I would say that each one is getting smoother,” Mark Rothleder, the ISO’s vice president of market quality and renewable integration, said during an Oct. 5 meeting of the EIM’s governing body.

Another transition is scheduled for October 2017 when Portland General Electric will join the market, the last fall entry before the ISO moves to a spring implementation schedule to avoid overlap with annual market software updates.

The benefits of NV Energy’s December 2015 integration into the EIM became evident in early 2016, after CAISO officials observed that the increased transfer capacity between the ISO and PacifiCorp East unified what had previously been a fractured market; California had found a real-time export market for its surplus solar and avoided curtailing a significant amount of renewable generation. (See CAISO EIM Boosts Market for Renewables in Q1.)

Last year also saw announcements from four utilities that said they intend to join the EIM.

In April, Idaho Power signed an implementation agreement that would make it the sixth BAA to join the market in spring 2018. Inclusion of the utility will bring an additional 4,800 miles of transmission into the market while improving trading access to an area of Wyoming that renewable developers — including EIM pioneer PacifiCorp — seek to tap for wind projects intended to serve the West Coast. (See Idaho Power Inks Agreement to Join EIM.)

Seattle City Light is slated to become the first publicly owned utility to join the EIM after signing an implementation agreement in December. (See Seattle City Light Signs EIM Membership Agreement.) City Light’s membership is contingent on satisfying the concerns of the Seattle City Council, which asked the company to flesh out the findings of an EIM benefits study showing the hydropower-rich utility could earn an additional $4 million to $23 million annually as an exporter of the flexible ramping capability needed to smooth out intermittent renewables. (See Council OKs Seattle City Light Bid to Explore Joining the EIM.)

The Sacramento Municipal Utility District said in October that it would begin negotiations to join the EIM, with some of the six other members of the Balancing Authority of Northern California — all publicly owned — to follow, depending on the outcome of cost-benefit assessments. (See Sacramento Utility to Join EIM; Other BANC Members May Follow.)

CAISO and El Centro Nacional de Control de Energía (CENACE), Mexico’s grid operator, announced an agreement in October to explore having the Baja California Norte region join the market as the first non-U.S. participant. (See Mexico’s Grid Operator to Explore Participation in the EIM.) While the region has no transmission connections with the rest of Mexico’s grid, it does boast 800 MW of transfer capacity with California through two 230-kV links at the Imperial Valley and Otay Mesa substations, and also offers promising potential for wind energy development.

2016 also saw the EIM begin to chart a course more independent of the ISO with the appointment of the market’s governing body and a clearer outline of governance. (See CAISO Board Appoints Western Energy Imbalance Market Governing Body.) At the body’s first meeting, Chairwoman Kristine Schmidt noted that a decade ago, nobody in the industry would have believed that the West would produce an organized real-time market.

“We’re now seeing a regional market take shape in the West,” Schmidt said.

In December, EIM and CAISO leaders approved a guidance document that provides solutions to the overlapping authority between the ISO’s Board of Governors and the EIM governing body resulting from the EIM’s delegation of a portion of its authority over Federal Power Act Section 205 filings to CAISO. (See EIM Leaders OK Governance ‘Guidance’ Proposal.)

The document outlines how ISO staff should interact with the EIM, providing a schedule for notifying the governing body about ISO initiatives and laying out the processes by which body members and EIM participants will provide feedback on proposed policy changes.

“I think this is an important step forward,” CAISO board member David Olsen said. “It really helps to clarify the scope of responsibility of the EIM board.”

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SPP Seeks to Manage Wind Riches, Improve Order 1000 Process

By Tom Kleckner

SPP and its stakeholders enter 2017 seeking ways to integrate the massive amounts of renewables in the RTO’s interconnection queue, while also completing the painful Z2 project, improving the Order 1000 competitive transmission process and implementing more sophisticated combined cycle modeling.

Expiring tax credits and reduced costs for renewable energy has led to a rush of generation projects that threaten to overwhelm RTO transmission planners.

Wind Rush

“We’re embarking on an era we’ve never seen before,” Mike Wise, chair of SPP’s Strategic Planning Committee, said during the RTO’s Board of Directors/Members Committee meeting in December. “We’re trying to figure out, one, how do we deal with the issue and, two, how do we take advantage of the issue at the same time?”

order 1000 spp wind power
Wise in the foreground with SPP’s Carl Monroe behind him | © RTO Insider

David Osburn, general manager of the Oklahoma Municipal Power Authority, agreed with Wise, saying, “It wasn’t very long ago we were arguing about how much wind might be on the system, and we’ve already blown through that.”

Whether or not the pun was intended, Osburn made his point. SPP has been able to add more wind to its system than many would have thought possible a few years ago, and now it looks to be facing the same issue with solar power.

SPP currently has 15,728 MW of installed wind energy with another 21,535 MW in the interconnection queue — adding up to more than half of the balancing authority’s coincident peak load (50,622 MW in July). The system set a new record for wind generation Friday with 12,141 MW, and for some hours in April, almost half of the generation came from wind sources. SPP expects to set new records in April 2017, with wind exceeding 60% penetration. (See SPP Coal Generation Continues Decline; Wind, Load Records Set and Wind Growth Causes SPP to Take 2nd Look at Tx Projects.)

3,000 MW of Solar Coming

The RTO currently only has 215 MW of solar energy on the system, but more than 3,000 MW of solar is planned. That has Board Chair Jim Eckelberger sounding the alarm.

“That’s what wind looked like 10 years ago, and solar is getting cheaper and cheaper and cheaper,” he said. “We’re going to have quite a need to refocus on the mechanics of the market to make this work, or negative pricing is really to going to have a long-term change in the way electricity is used in our footprint.”

SPP says all that wind generation has a high impact on system congestion. Wind energy also causes headaches for grid operators by not showing up during high demand — or by providing too much power during periods of low demand. Wind power on the margin resulted in 160 hours of negative clearing prices in 2016. SPP staff notes some wind farms are voluntarily curtailing their production because of low prices.

“We have to figure out a way to either use the wind, control for the wind or figure out a way to allow other folks in this country to get access to this wind,” Wise said. “This is really a dilemma … a growing dilemma.”

The problem is, when the wind picks up in SPP, it’s also picking up in neighboring MISO and ERCOT, dampening demand for imports.

But SPP can point to studies that show UHVAC networks and HVDC links could deliver surplus wind power to markets in the east, helping them meet renewable portfolio standards.

The Strategic Planning Committee created the Export Pricing Task Force last summer to evaluate the business case for exports and create a rate structure “to address the recovery of the incremental transmission and the underlying facilities necessary” to support exports. The group met twice in 2016 but has scheduled monthly meetings for this year. Its charter calls for making recommendations by the end of July.

If all the pending wind projects are brought online, SPP Manager of Operations Analysis and Support Casey Cathey told the committee, the lack of an export strategy might force the SPP Reliability Coordinator to allow more wind energy to sink within the balancing authority, while at times increasing curtailments.

Cathey’s team is also responsible for the 2017 Variable Generation Integration Study, which stressed the SPP system to a point of instability in analyzing the effect of high-wind/low-load scenarios on reliability. A workshop has been scheduled for Feb. 14-15 in Little Rock to discuss the study’s results.

spp wind power order 1000
Iowa find farm after harvest | Theodore Scott, Creative Commons

“It’s going to fall on SPP to really figure out what we’re doing in the future and how we’re going to resolve this issue,” Wise said to the board and members. “I encourage all the great thinkers at your companies to be attentive to the issue … and help us come up with solutions, because this is not an easy task.”

Z2 Project Lingers

Accommodating and planning for more wind generation is not the only difficult task facing SPP in 2017. Members and stakeholders continue to work on improving the troublesome Z2 crediting process for network upgrades, which was a bone of contention for much of this past year.

Under Attachment Z2 of the SPP Tariff, staff was to assign financial credits and obligations for sponsored upgrades. However, staff had not applied the credits for years dating back to 2008, complicating the task of trying to accurately compensate project sponsors and claw back money from members who owed debts for the upgrades.

Staff and members agreed on a process to compensate everyone properly, but it wasn’t until November that staff was able to compile the historical data from 2008 through August 2016. Members will be invoiced almost $95 million in lump sum payments, with another $15 million billed in 20 installments through August 2021.

SPP CEO Nick Brown said last January that Z2 would be “the focus of the organization this year.” That will still be the case this year, as the Z2 Task Force will meet before January’s Markets and Operations Policy Committee to evaluate staff and stakeholder proposals to improve the process. SPP has proposed using incremental long-term congestion rights as one replacement for Z2 credits.

At the same time, the legal and regulatory battles over Z2 have just begun. In November, the Kansas Electric Power Cooperative became the first SPP member to pursue legal action over the Z2 revenue-crediting process when it filed a complaint with FERC. KEPCo said in its Nov. 22 filing that SPP’s direct cost assignment of approximately $6.2 million to it violated the RTO’s Tariff, the filed rate doctrine and the Federal Power Act. The complaint seeks relief from directly assigned Z2 obligations and a refund for payments already made.

Order 1000

Staff and members are also working to improve the RTO’s competitive bidding process under FERC Order 1000. The first go-round last year resulted in one competitive project being bid out, only to have it pulled for re-evaluation shortly thereafter.

The Competitive Transmission Process Task Force hopes to change that by offering recommendations this year to improve the process. The group has already modified documents and templates while reviewing the entire competitive bidding process. Two Tariff revision requests have already begun to wind their way through the stakeholder-approval process, and more could be on the way if the MOPC and board approve changes to the scoring criteria in January.

Enhanced Combined Cycle Modeling

SPP will see one of its first major projects since the Integrated Marketplace come to a conclusion March 1 when software allowing multiple configurations of combined cycle units goes live. With the new functionality, market participants can register and submit separate offers for each configuration, leading to a more economic commitment and dispatch of the resources.

Participants completed structured testing of the software in December. The technology also played a role in SPP’s successful timeline changes for coordinated gas-electric scheduling practices in September as a result of FERC Order 809.

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FERC OKs MISO Use of PJM Cost Estimates for Mitigation

By Amanda Durish Cook

MISO can use PJM’s technology-specific reference levels for market mitigation in its 2017/18 capacity auction, FERC has decided.

The commission’s Dec. 28 order said MISO’s use of PJM’s numbers “strikes a fair balance between reducing the burden of demonstrating and verifying facility-specific reference levels, and allowing a market participant to select the default technology-specific avoidable costs that best reflect its actual avoidable costs” (ER16-833-003).

Reference levels are intended to represent the non-fuel costs of operating different types of generation resources. Similar to a cost-based offer in the energy market, they will be used as a resource’s capacity offer when a capacity seller fails MISO’s market power tests.

ferc miso pjm market mitigation

MISO’s proposal was in response to FERC’s December 2015 ruling that the RTO’s use of estimated opportunity costs for exporting power into PJM resulted in excessive mitigated cost levels. (See FERC Orders MISO to Change Auction Rules.)

The commission ordered MISO to set the initial reference for offers into the capacity auction at $0/MW-day. Because the commission said the $0 default might generate more requests from capacity suppliers to establish facility-specific reference levels, the commission called for the technology-specific defaults to reduce the need to verify costs on a unit-by-unit basis (EL15-70, et al.).

MISO’s staff and Independent Market Monitor agreed to base the mitigation levels on PJM’s avoided cost numbers because the generation technologies in the two RTOs are similar and PJM’s values are already FERC-approved. (See MISO Moves Forward on Auction Design; Seasonal Filing Delayed Again.)

MISO’s approach diverges from PJM on several points, including use of the monthly Consumer Price Index to update values rather than the Handy-Whitman index. Because PJM’s figures do not include defaults for wind and nuclear generators, MISO developed its cost estimates based on data from the Energy Information Administration and the Nuclear Energy Institute, respectively.

MISO also will not include the 10% “adder” PJM uses to offset the uncertainty of estimating costs three years into the future. The commission rejected NRG Energy’s request that MISO be required to use the adder. Unlike PJM’s three-year forward auction, FERC said, MISO’s prompt auction does not require the same safeguard.

FERC also mandated separate values for multi-unit and single-unit nuclear resources, despite Exelon’s comments that the two values were not materially different.

FERC ordered MISO to review the reference levels every three years, rejecting the RTO’s proposal to update values only after PJM updated its own numbers. FERC said MISO’s review of its avoidable costs “should not be contingent upon the review schedule of another regional transmission organization.”

FERC’s order also approved MISO’s proposal that market participants intending to retire or suspend a unit must use either retirement- or mothball-based default avoidable costs, respectively. FERC said market participants wishing to take advantage of the retirement-specific values must have already submitted a notification of retirement to MISO. However, since MISO only included retirement-based and not mothball-based values for nuclear and wind units, FERC ordered the RTO to provide wind and nuclear mothball-based avoidable costs or explain why they should be exempted.

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New England to Charge Ahead on Clean Energy Makeover in 2017

By William Opalka

New England policymakers hope to reach agreement in 2017 on revised market rules to accommodate state clean energy policies, as three states seek to complete renewable procurements and Massachusetts readies for a new solicitation.

Although Donald Trump’s election threatens federal initiatives to reduce carbon emissions, New England is moving ahead with its plans to decarbonize through power purchase agreements, infrastructure improvements and potentially tighter emission caps under the Regional Greenhouse Gas Initiative.

Massachusetts, Connecticut and Rhode Island, which issued a joint solicitation combining their purchasing power, hope to file PPAs with state regulators in the spring, now that a temporary injunction sought by a small developer who challenged the program has been lifted. (See New England States Move Toward Renewables Contracts.)

While the initial contracts are for a modest 460 MW, Massachusetts is expected to issue another request for proposals for 2,800 MW in the spring. The state’s Energy Diversity law, enacted last summer, directs its electric distribution utilities to enter contracts for 1,600 MW of offshore wind and 1,200 MW of renewables, likely Canadian hydropower, over the next decade. (See Massachusetts Bill Boosts Offshore Wind, Canadian Hydro.)

iso-ne clean energy canadian hydropower 2017
Daniel-Johnson Dam and Manic-5 Generating Station | Hydro-Québec

Separately, Connecticut has selected 25 small clean energy and energy efficiency projects totaling 402 MW to negotiate PPAs with the state’s two electric distribution companies.

Transmission

In December, the region saw the nation’s first offshore wind farm — Deepwater Wind’s 30-MW project off Rhode Island’s Block Island — begin commercial operation. But without other, larger offshore projects to count on, importing Canadian hydropower appears to be the quickest solution for the states seeking to maintain momentum in emissions reductions.

Delivering that power will require major new transmission lines. The New Hampshire Site Evaluation Committee is expected to rule on the application by Northern Pass developer Eversource Energy in September. Opponents want the entire 192-mile route of the 1,090-MW line buried. The developers have proposed only 60 miles underground.

Two other transmission projects would import Canadian hydropower via cable buried under Lake Champlain. TDI New England’s Clean Power Link received a presidential permit in December to allow construction. Anbaric’s 400-MW Vermont Green Line is awaiting approval. All three transmission projects are expected to respond to the Massachusetts solicitation.

IMAPP

Meanwhile, the New England Power Pool’s Integrating Markets with Public Policy (IMAPP) initiative, launched last summer, is trying to find ways wholesale market rules can accommodate state policies without compromising reliability or dramatically increasing costs.

Meeting these goals has proved a daunting challenge. Officials had hoped to develop an action plan by the beginning of December that could be presented to ISO-NE for action in early 2017, but now they don’t expect to do so until late in the first quarter at the earliest.

Proposals within the IMAPP collaborative have included various methods of pricing carbon. A carbon adder would be technology-neutral and provide market signals to both supply and demand while also creating a revenue stream for the states. There is also a proposal for a two-tiered Forward Capacity Market, with one reserved for clean energy resources. (See Markets vs. Climate Goals the Subject at NECA Conference.) Any market rule changes would require FERC approval.

Also considering rule changes is RGGI, which is conducting its quadrennial Program Review. Falling prices in the nine-state compact’s CO2 allowance auctions have renewed calls from environmentalists to tighten emission limits. Allowance prices dropped to $3.55 in December, the lowest in three years and about 53% lower than a year ago. Many stakeholders say the states should reduce the cap on emissions by 5% annually from the current 2.5%. (See RGGI Carbon Auction Prices Drop 22%.)

Although New England has been a national leader in reducing carbon emissions, it would still need an additional 25% cut from 2015 levels to meet the 2030 targets under the federal Clean Power Plan. The CPP would cap emissions from new and existing sources at 29.1 million tons in 2030. In a report by ISO-NE, carbon emissions showed a slight uptick to 40.3 million tons in 2015 compared to 2014, likely caused by the closure of the Vermont Yankee nuclear plant.

Have Capacity Prices Peaked?

One worrisome development that seems to have abated is the concern about steeply rising prices in the capacity market.

Clearing prices in last February’s FCA fell to $7.03/kW-month from 2015’s $9.55/kW-month, a 26% drop and the first decline in four years. (See Prices Down 26% in ISO-NE Capacity Auction.)

ISO-NE is seeking 34,075 MW for delivery year 2020/21. About 34,505 MW of existing and 5,958 MW of new resources are qualified to participate.

Natural Gas Infrastructure

As expected, 2016 proved crucial in efforts to expand the region’s natural gas infrastructure, with two major gas pipelines projects falling by the wayside.

The 342,000-dekatherm Algonquin Incremental Market project was completed in December, but it mostly serves local distribution companies’ heating customers and did little to aid generators.

Kinder Morgan halted its Northeast Energy Direct project in the spring, citing its inability to secure enough commitments from New England power generators to reserve capacity. (See Kinder Morgan Board Suspends Work on Northeast Energy Direct Pipeline.)

The Massachusetts Supreme Judicial Court effectively killed Spectra Energy’s Access Northeast when it ruled against a subsidy by electric ratepayers. (See Mass. Supreme Court Vacates EDC-Pipeline Contract Order.) The state’s legislature appears reluctant to codify the requirement. Other states that were ready to commit to shared costs for infrastructure were dependent on the Bay State taking a leading position.

Without ratepayer-mandated support in Massachusetts, the region’s largest state, major pipeline construction appears to be at a standstill.