ALBANY, N.Y. — New York lawmakers last week unanimously passed a measure requiring the state’s Public Service Commission to set targets to increase the adoption of energy storage in the state through 2030.
The new law requires the commission to work with the New York State Energy and Research Development Agency (NYSERDA) and the Long Island Power Authority to set targets and develop a storage deployment program.
“This newly passed bill gives New York’s PSC clear direction: set a storage target and design a deployment program by the end of 2017,” said Anne Reynolds, director of the Alliance for Clean Energy New York. “This is a great signal to the storage industry that New York will be a promising place to invest. But first we need Gov. [Andrew] Cuomo to sign it into law.”
The Energy Storage Deployment Program bill combined Assembly and Senate measures sponsored by Assemblywoman Amy Paulin and Sen. Joseph Griffo.
Both sponsors of the legislation pointed to enhanced reliability of the electric grid as a top benefit of increased use of energy storage, as well as the jobs expected to be created.
A NYSERDA study earlier this year found that about 4,000 workers were employed in the state’s energy storage industry by the end of 2015, up 30% since 2012. The study projected the state’s industry could grow from about $1 billion in revenue to up to $8.7 billion in 2030, with the number of jobs possibly exceeding 25,000.
EOS Energy Storage Project | EOS Energy Storage
“Storage also increases the resiliency of the electric grid by supplying power in the event of an electrical outage. The creation of an energy storage deployment program will increase the installation of energy storage systems throughout the state and accelerate these benefits,” Paulin said in a statement after the bill’s passage.
Setting Targets
Because energy storage is applicable to so many electricity grid functions, a narrow focus on one area fails to capture the complete value of the technology, according to Dr. William Acker, director of the New York Battery and Energy Storage Technology Consortium.
“By analyzing the system as a whole and setting targets, you’re able to create a situation where the energy storage can be adapted into a variety of different applications,” Acker said. “That will open up the markets and lead to penetrations that are far greater than the targets that will have been set. The energy storage industry has made rapid technological advancement over the past few year, but equally important, the costs have dropped dramatically in terms of both the technology and the scale of production.” (See Storage Technology Still Outracing RTO Metrics, Rules.)
Reynolds said her group looks forward to working with the PSC to create a workable program and targets.
Eos Aurora® 1000-4000 Energy Storage | EOS Energy Storage
“Since it is up to the PSC to determine the specific target by the end of December, industry members do not yet know what impact this could have,” Reynolds said. “New York’s ambitious renewable energy mandate is 50% by 2030. Technically speaking, we do not absolutely need storage to get there, but it can be an excellent complement to increasing renewables deployment and boosting overall system efficiency.”
The state’s Clean Energy Standard, part of Cuomo’s Reforming the Energy Vision initiative, mandates that 50% of electricity generation come from renewable resources by 2030.
New Commissioners on PSC
The Senate on June 21 approved NYSERDA CEO John Rhodes to serve on the PSC, along with former state Sen. James Alesi and Philip Wilcox, an official with the International Brotherhood of Electrical Workers, a union that represents power plant workers. Cuomo has named Rhodes as chair of the commission.
The Senate also reconfirmed Diane Burman for a second six-year term as commissioner after her current term ends next February. The term of Gregg Sayre, who has been serving as interim chair of the commission, also ends next year.
BRANSON, Mo. — A proposal to detach the appointment of MISO’s Steering Committee leaders from the election of the RTO’s Advisory Committee has been put on hold until late July.
The RTO’s Stakeholder Governance Guide currently calls for the vice chair of the Advisory Committee to serve as chair of the Steering Committee and vice versa. (See “MISO May End Automatic Steering Committee Leadership Posts,” Organization of MISO States Board of Directors Briefs.)
“Today, the Advisory Committee elects the Advisory Committee chair and vice chair, and then by way of peculiarity, they do a flip-flop” to lead the Steering Committee, Entergy’s Matt Brown said during a June 21 Advisory Committee meeting.
Representing MISO’s Transmission Owners sector, Brown proposed a sector email ballot to change the practice. The motion asks that “nominations be solicited annually for the Steering Committee chair and vice chair positions” and that the posts be open to any interested stakeholders. Elections would be decided by the Advisory Committee via sector vote.
Still, a majority of stakeholders in attendance voted to table the motion until the committee’s next conference call on July 26.
Brown said the current Advisory Committee chair and vice chair ― Manitoba Hydro’s Audrey Penner and NRG Energy’s Tia Elliott ― should be able to fulfill their current Steering Committee terms until the end of the year to avoid a leadership shake-up. The motion asks for elections to begin in 2018.
“It’s not the most important issue facing MISO now,” Brown admitted. “However, it’s important to the MISO Transmission Owners.”
Brown said sectors should vote to end the “unusual” practice of automatic leadership and move to “a more conscious choice.”
“This has absolutely nothing to do with the people that currently hold these roles,” Brown said. He recommended the vote to help the Steering Committee attain a level of independence from the Advisory Committee that is “impossible to achieve today.”
Elliott asked if the proposal was aimed at “fixing” something specific that the Steering Committee failed to address.
“This is not anything specific,” Brown replied. “This is not about any actions or decisions of the Steering Committee or any actions or decisions of its current leadership.”
Northern Indiana Public Service Co.’s Paul Kelley said the move was simply a response to a request by MISO Director Thomas Rainwater at the last Advisory Committee meeting to identify attainable stakeholder process improvements.
MISO Stakeholder Relations staffer Alison Lane said the Steering Committee’s dependent leadership posts were created about eight years ago with the Steering Committee itself. At the time, it was viewed as a “cohesive way” to coordinate with the Advisory Committee.
“That’s based on an eight-year-old memory,” Lane said after a beat.
WASHINGTON — A key natural gas trade group released a study Thursday that contends it is not fuel diversity but the presence of “reliability attributes” that policymakers should seek for the good of the grid.
And how does natural gas-fired generation fare on that report card? Very well, thank you.
The study, done by The Brattle Group for the American Petroleum Institute, concludes that gas-fired generation is “relatively advantaged” in all but one of the 12 attributes it identified, which included the ability to provide ancillary services, fuel security and proximity to load. Gas excelled on every measure except for storage capability.
| API/Brattle Group study
The next best alternative source was pumped hydro with 10. Nuclear and coal, the potential beneficiaries of policies favoring traditional “baseload” generation, fared far worse at five and four respectively, as did wind (one) and solar (two).
Ancillary Services’ Growing Importance
The report calls for RTOs and ISOs to further develop markets for ancillary services, which it said are becoming increasingly important because of the rising share of intermittent renewable generation.
“Policy and market design had not focused on ancillary services until relatively recently. After the provision of energy, generation resources historically had the capability to provide more ancillary services than systems required,” the report says. “Renewables increase the uncertainty and variability in net load and make ramps larger, thereby increasing the ancillary service requirements. In addition, higher renewable penetration depresses energy market prices. This reduces margins earned by resources in the energy market and increases the need to compensate resources for the ancillary services they provide.”
In a press briefing, API Chief Economist Erica Bowman said her organization wants “to push back against” state policies that seek to maintain coal and nuclear plants “at any cost.” API absorbed the smaller America’s Natural Gas Alliance (ANGA) in 2015.
API and its affiliates have been “100% against” policies providing state-backed funding streams for nuclear plants, spokesman Mike Tadeo said.
API said the report was not ordered to counter Energy Secretary Rick Perry’s grid reliability study, which critics have said is designed to benefit coal and nuclear generation. Bowman added, however, that she hoped the Energy Department researchers “use [the findings] as a resource.”
Perry told a House Appropriations subcommittee Tuesday that the report would be released by the end of June, but a department spokesperson said later it would not be ready until July.
Beyond the Reserve Margin
Bowman said grid operators’ traditional reliance on reserve margins — the difference between installed capacity and peak load projections — is no longer sufficient.
“In reality — and NERC has also talked about this — that needs to transition to looking at these other attributes as well,” she said.
Most of the grading on the 12 attributes is likely to be uncontroversial. Also included in the list were generation capability; dispatchability; start times; ramp rates; inertia; frequency response; reactive power; minimum load level; black-start capability; and proximity to load.
But Brattle’s description of gas as “relatively advantaged” regarding the security of its fuel supply supply — along with coal, nuclear and pondage hydro — may come as a surprise to officials in PJM and ISO-NE, which have been encouraging gas generators to add dual-fuel capability. Gas generators can lose their access to fuel during winter peaks, when heating load with firm contracts takes precedence.
The study concedes that — unlike coal and nuclear fuel — “natural gas is rarely stored in large quantities on site,” adding “some natural gas-fired plants have the capacity to burn distillate oil stored in tanks on-site in the event of a natural gas supply interruption.”
It also acknowledges that gas supplies “can be interrupted due to a lack of capacity when demand is very high” — singling out New England’s pipeline capacity constraints — but says “firm supplies have very low probability of interruption.”
| PJM
Unmentioned in the study is that many gas-fired plants have interruptible contracts because operators say firm pipeline contracts are too expensive.
In its 10-K report for 2016, Calpine — North America’s largest operator of natural gas-fired power plants — warned investors that pipeline constraints “could interrupt the fuel supply” to its plants in PJM, although “some” have dual-fuel capability.
Brattle defended the omission, saying the paper was about compensating units for their reliability attributes, not about the cost of interruptible contracts. “The authors note that cost and environmental attributes may also affect market design. This paper focuses solely on reliability attributes and on the appropriate principles for compensating resources that provide those reliability attributes.”
‘A Lot of Affordable Gas’
Bowman rejected the idea of maintaining coal and nuclear plants as a price hedge in case gas prices rise from their current lows, insisting that the addition of natural gas and renewables has resulted in the most diverse generation fuel mix in history.
She cited a 2016 study by IHS that said the U.S. has 1,400 Tcf of natural gas recoverable at $4/MMBtu — a two-thirds increase over 2010 estimates. The U.S. consumed 27.5 Tcf in 2016.
“There is a lot of affordable gas out there,” she said. “So I guess the real question is how much are you willing to pay for that hedge? I would argue that that would be a lot higher than looking at where natural gas resource affordability is today.”
Wind, Nuclear, Coal Groups Respond
Two competing trade groups weighed in with responses to the API/Brattle study.
“Decades of engineering experience demonstrates that a reliable electricity system needs a diverse portfolio of generation technologies, including nuclear and natural gas,” said Maria Korsnick, CEO of the Nuclear Energy Institute, in a statement. “A close reading of the Brattle study reinforces the conclusion that grid reliability would be hopelessly compromised without nuclear energy, and we’re at a loss to explain why API is advocating such a risky scheme.”
Michael Goggin, senior director of research for the American Wind Energy Association, the API-Brattle Group report findings are “largely consistent” with those of the Analysis Group in a report recently commissioned by AWEA. “Both reports conclude that the increasingly diverse grid, with the addition of renewable and natural gas generators and the services they provide, is operating reliably and, importantly, that markets are the preferred way to ensure the grid continues to secure the services it needs to remain reliable at the lowest cost to consumers. Notably, neither report finds that ‘baseload’ itself is a grid service necessary for reliability.”
Goggin disputed Brattle’s designation of wind as “relatively disadvantaged” in frequency response, saying wind turbines “can provide frequency response that is an order of magnitude faster than conventional power plants, and today are meeting a large share of ERCOT’s need for frequency response when system frequency is high.” He also said wind and solar plants “have excellent ability” to regulate reactive power — a characteristic Brattle rated as “neutral” — and said the report failed to grade the ability to ride through voltage and frequency disturbances. “Had API examined this, it would have found that wind plants, … thanks to their power electronics, far exceed the capability of conventional power plants to remain online following a grid disturbance,” he said.
“Though the API-Brattle report’s generation assessment downplays the significant reliability capabilities and contributions of modern wind turbines, we believe the commonalities between the reports are more notable,” Goggin said.
Paul Bailey, CEO of the American Coalition for Clean Coal Electricity said “backing up more renewables with new natural gas-fired generation will not solve” the challenges facing the grid. “First, natural gas would have to be available at all times to back up more renewables. However, a significant fraction of natural gas supplies for electricity generation is based on non-firm contracts, which means there is no guarantee that gas will be available all the time. For example, approximately 40% of the gas is supplied under non-firm contracts in PJM and MISO.”
Bailey said increased natural gas could make the grid less resilient. “On the other hand, coal plants are fuel secure because there is a large supply of coal (an average of 90 days) at each plant,” he said. “This is why FERC should adopt regulatory changes that properly value attributes, such as on-site fuel storage, that enhance grid resilience.”
Power producers could temporarily suspend the operations of unprofitable generators not needed for system reliability under a CAISO plan released this week.
The Temporary Suspension of Resource Operations straw proposal, released Wednesday, would allow a plant owner to temporarily take a money-losing generator out of the market short of the “mothball” and retirement procedures already spelled out in the ISO’s Business Practice Manuals. (See CAISO Initiative Could Toss Lifeline to Struggling Generators.)
The proposal stipulates that a resource owner must manage a suspended resource in such a way that it can retain the same megawatt rating and ramping capability as before the shutdown. Any plants denied a request could become eligible for payment under CAISO’s capacity procurement mechanism (CPM), which currently compensates units for specific reliability needs.
While that move would fall far short of establishing a capacity market, it could provide needed financial support to gas-fired generators the ISO identifies as vital for future system needs, particularly in integrating increased amounts of renewable resources. CPM payments would be limited to four-month terms.
The proposal calls for owners to be permitted to shut down a resource for two to four months at a time, with the option to request a subsequent four-month suspension.
A unit approved for shutdown would not be required to respond to “exceptional” — or out-of-market — dispatches issued by the ISO, but it could be recalled for system emergencies, making it eligible for a CPM payment. A suspended unit would be ineligible to be counted in the ISO’s resource adequacy showing during its suspension.
The proposal would allow resources to apply for temporary shutdowns throughout the year, but they must provide notice 60 days in advance of the effective date of the suspension. CAISO, in turn, would be required to notify the resource of an approval or denial of the request eight days before the effective date.
“The ISO will assess requests on the first-come, first-served basis, and there will not be a window that resource owners would need to work around,” CAISO said.
A resource would be required to maintain all environmental operating permits while on shutdown, and it must be fully available for service on its return date, the proposal stipulates. To accommodate “unforeseen circumstances” — such as an expected loss of resources, transmission outages or extreme weather — suspended units must be prepared to return to service within 10 days of being notified by the ISO.
CAISO developed the temporary suspension proposal in response to stakeholder comments filed in a 2016 FERC proceeding over the ISO’s refusal to approve outage requests for three of four units at the 965-MW La Paloma combined cycle plant 140 miles north of Los Angeles (EL16-88).
CAISO’s initiative stems from stakeholder concerns raised during a 2016 FERC proceeding related to the La Paloma generating plant, which filed for bankruptcy late last year after being refused permission to suspend its operations in the ISO market. | Kern County, California Public Health Services Department
FERC last October agreed with the ISO’s decision to reject the plant owners’ requests because they were made for economic — and not physical — reasons.
Because the request was economic, it “did not represent an appropriate use of the outage management system as allowed by the CAISO Tariff,” the ISO said.
CAISO also denied an additional request to compensate the units by designating them as reliability-must-run resources, contending that they were not needed for reliability purposes. At the time, 42 MW of La Paloma Unit 2 were under an RMR agreement.
La Paloma filed for bankruptcy late last year, citing $524 million in debt and an “inhospitable regulatory environment.”
Although stakeholders largely agreed with CAISO’s La Paloma response, some asked that FERC direct the grid operator to amend its Tariff to allow for outages based on economic considerations — a request that the commission rejected. The ISO nevertheless committed to establishing a stakeholder process to take up the issue this year.
“Through that process, the CAISO and stakeholders will have sufficient time to consider all pertinent issues, the conditions under which economic outages should be permitted, if at all, and how economic outages would interact with other requirements of the CAISO tariff and with CAISO grid and market operations,” the ISO said.
The ISO has scheduled a June 28 call to discuss the proposal and has asked stakeholders to submit comments by July 13.
A proposed law that would give FERC authority over the licensing of all hydropower projects has advanced to the House Energy and Commerce Committee along with four related bills — but only after a hearing that revealed a partisan divide on much of the legislation.
House Energy Subcommittee Meeting
The Energy Subcommittee on Thursday sent the Hydropower Policy Modernization Act of 2017 — and four other energy infrastructure-related bills dealing with natural gas pipelines, electric transmission and grid security — to the full committee despite complaints from Democrats about the Republican-controlled process for drafting the bills and on the substance of some clauses.
Upton
The hydropower legislation modifies the definition of renewable energy under the Energy Policy Act of 2005 to include hydropower and designates FERC as the lead agency for federal authorizations, granting the commission discretion to extend preliminary permits and the time limits for construction.
“As we always strive to do, these bills have been drafted with bipartisan input, and in large part we’re picking up where we left off with on last year’s energy bill conference,” subcommittee Chair Fred Upton (R-Mich.) said in his opening remarks.
Not a ‘Murmur’
Rush
Ranking member Bobby Rush (D-Ill.) disagreed with Upton’s take on the proceeding.
Rush said that despite coming to negotiate in good faith, two of the bills presented for the markup — the hydropower policy and the Promoting Interagency Coordination for Review of Natural Gas Pipelines Act (H.R. 2910) — “are vastly different from the discussion drafts that had been part of the staff negotiations.”
The two bills did not reflect any of the changes sought by Democrats, such as not allowing aerial surveillance to supplant on-the-ground inspection of proposed project sites. They “instead moved in the opposite direction and are even more problematic for our side to accept,” Rush said. He added that Upton had not responded to the Democrats’ request for a hearing on the hydropower policy legislation with officials from the departments of Interior, Commerce and Agriculture.
“This is yet another instance where once again, Mr. Chairman, our side is left to wonder whether we will ever hear directly from the administration on any bill or topic in our jurisdiction,” Rush said. “Where is the administrator of the EPA, and where is the Secretary of Energy? Six months into the Trump administration and we haven’t heard a murmur from the administrator or the secretary, and it’s high time that we hear from those in the administration who have responsibilities to this subcommittee and to the Congress.”
Minor Amendment
Pallone
The subcommittee also discussed drafts of the Enhancing State Energy Security Planning and Emergency Preparedness Act of 2017; an amendment to the Federal Power Act related to qualifying a conduit hydropower facility (H.R. 2786); and the Promoting Cross-Border Energy Infrastructure Act (H.R. 2883).
The subcommittee agreed to an amendment to H.R. 2786 — offered by the ranking member of the full committee, Rep. Frank Pallone (D-N.J.) — to reduce the public comment period on facilities from 45 days to 30, rather than the 15 days set out in the draft legislation, which Pallone thought insufficient. The proposed law also would lift the 5-MW cap on what constitutes a conduit hydro plant.
Other Democratic-sponsored amendments did not win acceptance, with the subcommittee dividing on party lines. Democrats voted to forward all the bills except for H.R. 2910.
Walden
Rep. Greg Walden (R-Ore.), chair of the full committee, said “We’ve learned that oftentimes dozens of agencies are involved in the permitting process, so it’s time that we address these issues head-on and improve the federal licensing procedures and processes to ensure that we get these projects to market sooner for consumers.”
Castor
The bill to streamline gas pipeline permitting substitutes “safety for expediency,” Rush said. Republican members voted down his proposal to cut a section of the bill, “so that states, tribes and local community stakeholders can continue to play an important role in the pipeline permitting process.”
Rep. Kathy Castor (D-Fla.) proposed another failed amendment that would have the Office of Management and Budget determine if the legislation would duplicate other federal efforts or result in wasteful government spending.
More Dissent
Pallone said he was “deeply concerned” over the process the subcommittee had used for the markup.
“The draft released on Tuesday night [June 20] not only failed to address any of the concerns we raised, but actually went so far as to add new sections taken directly from provisions of last year’s Senate energy bill that we had explicitly rejected,” Pallone said. “And this does not bode well for making this a bipartisan process.”
Pallone added that Upton had marked up changes on legislation on state energy security plans that Democratic members first saw Tuesday night and that was never the subject of a legislative hearing or member-level discussion. And the gas pipeline bill was a “completely new and different bill” from the one discussed in May, he said.
“I hope today’s issues represent an aberration and not a new and unfortunate way of doing business,” Pallone said.
Subcommittee Vice Chairman Pete Olson (R-Texas) mentioned that Tropical Storm Cindy the previous day had hit the nation’s first LNG export terminal, Sabine Pass on the Texas-Louisiana border, and led to the evacuation of several offshore rigs in the Gulf of Mexico.
“These threats are real, and as cyber threats evolve, let’s get this right,” Olson said. While Texas isn’t famous for hydropower, it is an important baseload power and should be developed without hindrance, he said. “Lastly, on pipelines, we need these reforms. We’ve seen time and time and time again that the process takes too long and is way too messy. The better we are at getting infrastructure built, the better our economy is.”
Cross-border or Borderline?
Mullin
Also drawing opposition from Democrats was H.R. 2883, the draft bill authored by Markwayne Mullin (R-Okla.) to “establish a predictable and transparent process to permit the construction of cross-border pipelines and electric transmission facilities.”
Pallone offered an amendment that would not restrict the purview of National Environmental Policy Act reviews to the border area, but have EPA look at environmental impacts across the whole length of such projects. The subcommittee divided 18-12 in rejecting the revision.
Green
Mullin and Rep. Gene Green (D-Texas) said the bill does not impinge on federal environmental reviews necessary under existing law, but heightens the focus on the border-crossing itself.
Rush also opposed H.R. 2883, saying the bill would shift the burden of proof to pipeline opponents to prove that a given project was not in the public interest.
The bill would “allow parties to push projects that are not necessarily in the public interest to move forward in the permitting process,” Rush said. “The new bill would make the process worse, less transparent, less inclusive and ultimately less effective … and lead to greater controversy, increased litigation and longer delays.”
Western U.S. utilities procured three times more wind capacity in 2003-2014 than planned, showing there is a limited relationship between electricity resource planning and procurement, according to a new Department of Energy study.
Actual and planned nameplate capacity additions by resource and contract type for 12 load-serving entities in the West. | Lawrence Berkeley National Laboratory
Expansion of nameplate wind capacity by 2015 was expected to be about 15% but was actually about 50%, likely coming from power purchase agreements, the analysis of 12 Western load-serving entities showed. Changes in load growth, regulation and contracting led to adjustments in resource planning, and differences in resource mix came largely from renewable portfolio standards and demand-side management, as well as fuel price changes.
The study considered what types of economic and regulatory information is used in planning and procurement, and examined the value of the planning process in light of its relationship to actual practice. The analysis compared integrated resource plans filed in the early and mid-2000s to the actual procurement that followed.
Although IRPs are designed to ensure that utility investment decisions are as cost-effective as possible, there had been no previous “empirical assessment on the effectiveness of IRP implementation,” said the study, conducted by the Lawrence Berkeley National Laboratory.
“We find that most information produced in the planning phase is generally disconnected from the procurement phase,” the researchers said.
Western Wind Farm | SPP
After 2008, adoption of less efficient simple cycle combustion turbines correlated with dropping natural gas prices, which might also have been needed to provide balancing power because of higher usage of intermittent renewables. There was also less usage of coal-fired generation than planned, as difficulties in getting coal plants permitted were mentioned by several LSEs in their resource plans; natural gas was likely used as a baseload power substitute.
The researchers said only some of the forecasts, least-cost/risk portfolios and other information produced during the long-term planning processes were used during the procurement processes, and that procurement decisions relied “extensively on the most recent information available for decision making.”
“These findings suggest that states’ IRP rules and regulations mandating long-term planning horizons with the same analytical complexity throughout the planning period may not create useful information for the procurement process,” the study says.
The study found “in aggregate … a general alignment between planned and procured supply-side capacity. However, there are significant differences in the choice of supply-side resources and type of ownership for individual LSEs.”
Avista, Puget Sound Energy, Seattle City Light and Public Service Company of New Mexico procured less capacity than planned, possibly because of lower load growth, while Idaho Power, PacifiCorp and Portland General Electric procured more capacity than was planned. Idaho Power procured two to three times more wind capacity than planned. Although PacifiCorp had not planned for any wind in 2004, more than half of its procured nameplate capacity was wind.
For the Los Angeles Department of Water and Power, Sierra Pacific, Nevada Power and Public Service Company of Colorado, the largest difference between planning and procurement was substituting natural gas units for coal.
There is no formalization of how utilities should use inputs from their IRPs in their procurement, and there is little evidence regarding how sensitivity and risk analyses used in the IRPs are actually applied in procurement decisions, the study says.
It called for a “more careful” definition of the links between IRPs and procurement, calling it “an important problem as energy technologies, markets, and policy and regulatory goals evolve and become more complex.”
CAISO is seeking comment from market participants on three proposed modifications to the Western Energy Imbalance Market (EIM).
The grid operator on Tuesday kicked off the stakeholder process for the proposals, which include allowing third-party transmission providers to receive congestion revenue when they make unused capacity available between EIM balancing authority areas (BAAs).
| CAISO
In response to questions during a call on the initiative, CAISO said transmission owners will not have to turn over control of their transmission facilities to participate and would receive payment only if there is congestion on the system.
CAISO says the measure would increase transfer capacity among members, which the ISO’s internal Market Monitor has pointed out reduces congestion and limits the ability of any single participant to wield market power within its BAA. (See Increased Transfer Capacity Reducing EIM Congestion.) EIM entities can currently collect congestion revenue through an offset, but that functionality is not extended to third parties.
The ISO plans to use its existing functionality for transmission contributions, known as “energy transfer system resources” that are used to track, tag and settle EIM transfers. It will need to establish a pro forma agreement that enables scheduling coordinators to submit transmission contributions on behalf of a third party, and create a new make-whole mechanism that would guarantee a payment from congestion revenue. The ISO is seeking stakeholder input on what level of interval granularity those payments should be calculated and how their associated costs should be allocated.
CAISO also wants to correct an inequity that occurs when an EIM BAA wheels power between other BAAs. Wheel-through BAAs receive some revenue when congestion occurs but are not compensated if there is no congestion. In that circumstance, only the source and sink BAAs accrue benefits when a wheel-through transfer occurs.
“How should we quantify the benefits of providing EIM transfers through an EIM BAA?” CAISO asked in its meeting materials.
The ISO has also proposed a new policy for situations in which market participants change their bilateral schedules after submitting their hourly base schedules. Under current practice, changes made after submission are exposed to real-time imbalance settlement payments.
Settlement can result in either charges or payments, but there is no way for market participants to know the cost beforehand. Proposed changes would allow them to manage their exposure to imbalance settlement charges, CAISO said.
After the comment period ends June 30, CAISO will post a straw proposal on the initiative by July 27 and hold stakeholder meetings in August and September. The EIM Governing Body is set to review the proposals in October, ahead of a decision by the CAISO Board of Governors in November.
BRANSON, Mo. — MISO wants to spend $130 million over the next five years to construct a new market platform before its existing one becomes outdated, but its Board of Directors is insisting on a thorough stakeholder review of the project’s cost.
Jeff Bladen, MISO executive director of market design, said the upgrade would involve a “piece-by-piece replacement of components” resulting in a “far more modular platform” compared with the rigidity of the current system, which hinders market changes.
Swapping out market software incrementally instead of introducing a new platform all at once is the safer option, Bladen said.
“The risk of a misstep is far less using an incremental process,” he said during a rare June 20 joint meeting of the board’s Markets and Technology committees.
MISO’s current platform is “inflexible,” and even simple market changes require testing and retesting because of possible effects on other software, according to MISO Technology Executive Kevin Caringer. He likened the new design to Microsoft PowerPoint, which can recognize and accept fonts and graphics from other sources.
Looming Obsolescence
The RTO evaluated its market system last year and concluded it had five to seven years before evolving cybersecurity standards and increasing market complexity render the system — designed in the late 1990s — obsolete and no longer able to clear the day-ahead market. (See MISO Reaffirms 2023 End Date for Market Platform.)
“The time is now to begin long-term investment,” Bladen said. “Findings and conclusions drawn from the evaluation resulted in a clear call to immediately initiate a system upgrade.”
Caringer said MISO will spend about $3 million on cybersecurity to extend the life of the current platform for the five years needed for the switch to a new platform.
MISO is asking for an additional 25% contingency budget for unforeseen expenses in addition to the expected $130 million plan. Staff said it will present final cost estimates to the board in September. The board’s Audit and Finance Committee will decide whether to approve the spending in October, and a full board decision on the budget is set for December.
MISO staff predicts the project will yield a 4-to-1 return on investment, with $201 million in benefits, $254 million in cost avoidance and $111 million in risk mitigation.
Director Baljit Dail asked how MISO will prove the benefits and savings to its stakeholders.
Bladen said the RTO can share a recent benefits report once it removes nonpublic information from the document.
“I don’t want this to be jammed into December. At some point, I’m going to ask, has this report been scrubbed and has it been shared with stakeholders? I don’t want that to happen in December,” Dail warned.
Director Paul Bonavia wondered if MISO will give stakeholder groups a chance to collaborate to develop a process for responding to the benefits report.
Bladen responded that MISO expects to follow its normal annual budget process with stakeholder review occurring in the Finance Subcommittee.
“I appreciate that, but the budget process usually doesn’t have $130 million to $160 million in additional spending. One director’s strong counsel to you all is make sure the usual process can handle [this],” Dail said.
Other directors pointed out that the project’s benefits may play second fiddle to the market failure that looms if MISO does not implement a new market platform.
“I’m not too captivated by the benefits. We need to move,” Director Michael Curran said. “I’d love to see the benefits, but we have to spend the money. … It’s a burning platform; it’s a slow burn, but it’s coming.”
“My comment is, however you want to justify the benefit, it needs to be put before the stakeholders,” Dail replied. He suggested that MISO convene a special stakeholder committee to discuss the investment and consequences of not reconstructing the market platform.
“I’d like to see [the stakeholders’] fingerprints all over this,” Curran agreed.
Bladen said MISO could initiate stakeholder workshops to discuss building the platform.
In response to a question from Curran, Caringer said MISO could reach out to developers of its original market platform to help improve the transition. Some longtime MISO employees also have knowledge of the system, he said.
Curran said he wanted to require any potential project vendors to have contact with developers of the original system. CEO John Bear said the board would address that topic in a closed session that immediately followed the meeting.
The D.C. Circuit Court of Appeals on Tuesday denied eight challenges to PJM’s controversial Capacity Performance market rules, potentially cementing fundamental changes to the RTO’s capacity market that critics believe were hastily enacted and unjustifiably increase costs (16-1234).
CP was implemented following a blackout scare in January 2014 when the polar vortex dipped unusually low across the northern U.S. and created record-low temperatures. As much as 22% of PJM’s fleet failed to operate when dispatched, despite being contracted through the capacity market.
The new rules introduced year-round performance requirements for capacity resources along with incentives to perform and steep penalties for failing to do so.
Critics of the new rules argued they would increase the cost to secure capacity by billions of dollars. After FERC approved the changes in June 2015, challengers petitioned the commission for a rehearing, which the commission denied.
Nine organizations challenged FERC’s denial in court. The ensemble is a somewhat unusual partnership of environmental groups (the Natural Resources Defense Council, Sierra Club and Union of Concerned Scientists), representatives of utilities (the American Public Power Association, the National Rural Electric Cooperative Association and the Public Power Association of New Jersey), the Advanced Energy Management Alliance, which represents demand response resources, American Municipal Power, which represents both utilities and resources, and the New Jersey Board of Public Utilities.
FERC’s Reasoning Upheld
The ruling by Judges A. Raymond Randolph, Janice Rogers Brown and David B. Sentelle was unanimous. The court ordered the clerk to withhold issuance of the mandate resulting from the ruling to give the plaintiffs time to file petitions for rehearing before the three-judge panel or the full court.
Left to right: Judges A. Raymond Randolph, Janice Rogers Brown, David B. Sentelle | U.S. Courts
The court’s decision points out that FERC acknowledged the increased capacity costs but cited a study that estimated the new rules would create an annual net savings of potentially billions of dollars starting in 2016. The fact that the study used a penalty that was higher than FERC approved was immaterial, the court found.
“The savings come from the penalty successfully increasing reliability,” the court said in its decision. “Even with a lower penalty, the net savings may be substantial.”
FERC “does not have to find net savings” to approve proposed changes, the court found, and higher costs can be warranted if they increase reliability. FERC said the revisions would do that and also help avoid energy price spikes.
Year-Round Resource Requirement
PJM’s requirement that all CP resources be year-round attracted opposition from numerous groups.
NRDC, Sierra Club and UCS said that the requirement discriminated against seasonal generation such as wind and solar — despite the RTO’s offer that winter-only resources could aggregate with summer resources — because aggregation imposed “transactional costs.”
Utility Scale Solar in Maryland | Constellation
AMP, meanwhile, said aggregation should also be open to traditional resources.
The judges said none of the challenges persuaded them to question the commission’s judgment. “The commission’s policy decision to assess reliability through a year-round capacity commitment is the type of policy judgment to which we afford deference, and that deference is justified by the record,” they said. “The law provides no basis to claim the commission cannot approve uniform performance requirements simply because those requirements will be easier to satisfy for some generators than for others.”
Demand Response
AEMA had problems with CP’s impact on DR, challenging PJM’s proposal to use separate formulas for calculating expected consumption during summer months and non-summer months.
The group said it supported the “peak load contribution” method for the summer, which is based on a DR customer’s contribution to the five hours of the previous year when systemwide demand peaked. It opposed the “customer baseline load” method for non-summer months, which is based on the customer’s contribution to the system’s load for the four days of peak systemwide load during the most recent 45 days.
“Because it was reasonable for the commission to accept PJM’s proposal to use the recent-peak method for non-summer months and any alleged departure from past practice was adequately explained, we defer to the commission’s determination on this issue,” the court said.
AEMA Executive Director Katherine Hamilton said the court rebuff means consumers will face reduced choices and higher prices because residential DR and renewable resources “could be forced out of the market altogether.”
“In the recent auction, the amount of demand resources — both offered and cleared — fell by thousands of megawatts compared with previous years. PJM has now effectively ceded jurisdiction for monetizing these competitive products in the capacity markets, and it will be up to state commissions located in PJM to determine how these products will be operated going forward,” she said in a statement. “As AEMA considers legal options moving forward, we will continue working within the PJM stakeholder process on wholesale competitive market issues and with state commissions on demand response solutions for consumers.”
Procedural Challenge
The court also rejected challenges by APPA, NRECA and PPANJ to PJM’s filing of proposed changes to the capacity market under Federal Power Act Section 205 and its simultaneous Section 206 complaint proposing replacements for energy market rules it said were no longer just and reasonable.
PJM could not file changes to the Operating Agreement under Section 205 because it did not seek stakeholder approval of the changes.
The public power groups argued that the commission could not accept PJM’s Section 205 filing as just and reasonable while simultaneously finding that the filing rendered the Operating Agreement unjust and unreasonable under Section 206. “In effect, FERC found that PJM had created the factual premise and legal basis for FERC to order a change in rates that PJM could not have unilaterally made,” the groups said. “This bootstrapping of results is impermissible.”
The court said the petitioners failed to “explain why PJM’s Section 205 filings regarding the capacity market necessarily must complement existing energy market agreements to be just and reasonable” and cited “no precedent for their theory that the commission was required to act ‘under Section 206 alone.’”
“We therefore see no reason why the commission was not entitled to approve changes under Section 206 in anticipation of the impacts of the Section 205 filing rather than wait for those impacts to be realized,” the court ruled.
Penalties Too Low
PPANJ and the New Jersey BPU contended the CP penalties for resources that fail to meet their capacity commitments during an emergency hour were too low to ensure performance.
The commission approved a penalty rate equal to one-thirtieth of the net cost of new entry per megawatt-hour of shortage. The petitioners said the 30-hour denominator — based on the number of emergency hours in 2013-2014 — was too high, resulting in a penalty that was too low.
“The commission had good reason to conclude that the formula results in a high enough penalty to encourage resources to meet their capacity commitments,” the judges said. “The commission decided the penalty was also low enough to avoid introducing ‘excessive risk’ into the capacity market. Too high a penalty could discourage even reliable resources from entering the market. We defer to the commission’s balancing of these competing concerns.”
Default Offer Cap
Also rejected was a complaint by the BPU and four organizations representing utilities that PJM’s default offer cap, meant to reflect the CP penalties and bonuses, is too high. PJM would only include an offer above the cap in the capacity auction if it determines it is cost-based.
The court rejected complaints the cap could increase capacity costs, saying “increased capacity prices are necessary” to encourage entry of new, reliable resources. “Resource owners need to be able to offer capacity at a higher price in order to recover the costs of improvements,” it said.
Unit-Specific Constraints
AMP challenged the imposition of penalties on CP resources that fail to perform because of unit-specific constraints, saying it was inconsistent with energy market rules, which require PJM to cover resources’ costs if it schedules the them to run outside of their parameter limits.
“Given the different purposes of the capacity market and the energy market, there is no inconsistency in treating the operating-parameter limitations differently in the two markets,” the court said.
PJM on Monday secured U.S. Department of Energy approval to dispatch Dominion Energy’s recently shuttered Yorktown coal-fired plant to address potential reliability issues on Virginia’s Middle Peninsula.
Dominion, which closed the plant in April to comply with an EPA mandate, said it anticipated the department’s order and is prepared to restart both units at the plant as necessary.
Yorktown Generating Station | Dominion
Energy Secretary Rick Perry granted PJM’s request for a 90-day window to dispatch the units as necessary to “maintain grid reliability,” and the order can be renewed upon request indefinitely if the situation remains unchanged. PJM and Dominion are required to create a dispatch methodology and submit what dates the units are operated, along with estimated emissions and water usage, to the department.
“While this is not a long-term solution to the reliability issues, Dominion Energy supports PJM’s action and the DOE decision, and will work to ensure the units’ availability as required,” Dominion spokesperson Bonita Billingsley Harris said in an emailed statement.
Stalled Project
The order stems from Dominion’s difficulty in gaining approval for the proposed Surry-Skiffes Creek 500-kV transmission line across the James River, which has for years faced opposition from local and environmental activists. Approved by the PJM Board of Managers in 2012, the transmission project remains stalled pending permit approval from the Virginia Marine Resources Commission (VMRC) and a waiver from the state Department of Environmental Quality for water quality certification. The U.S. Army Corps of Engineers issued a conditional permit earlier this month that requires approval from both agencies.
Map of transmission system at Virginia’s middle peninsula | PJM
The project will additionally require a special-use permit from the James City County Board of Supervisors. Members of the public will have the opportunity to weigh in during both the VMRC and county permit hearings, Harris said.
Dominion estimates the line would take at least 18 months to construct after all permits are approved. The company had hoped to complete the project prior to closing the Yorktown units, which are among the few generators able to serve load in the populous but isolated North Hampton region.
While Dominion sought to shutter Yorktown by 2014 to avoid expensive emissions upgrades required by EPA’s Mercury and Air Toxics Standards, PJM required the units to remain operational to maintain reliability on the peninsula in the absence of the proposed line. State and EPA approvals extended the shutdown deadline several years, but applicable extensions finally ran out on April 15 and Dominion closed the doors.
Dominion warned that failure to build the line before shutting down the units could result in blackouts, an assertion opponents dismissed as scare tactics. In February, the company provided PJM a regional remedial action scheme that calls for dropping service to approximately 150,000 customers in the event of an emergency in order to prevent potential voltage collapse from N-1-1 contingencies. (See Opposition to Va. Tx Line May Trigger Unintended Consequences.)
No Surprise
The order didn’t catch Dominion by surprise.
“When it became apparent we would not receive approvals in time to complete the new transmission line before the coal units had to be retired, we pursued an aggressive plan of equipment upgrades, enhanced inspections, maintenance scheduling and contingency preparations to protect energy reliability on the Virginia Peninsula until the permanent solution could be put in place,” Harris said.
While the company was prohibited from running the Yorktown units after April 15, its contingency plans included keeping them in operating condition in case of an emergency, she added.
Despite its potential open-ended approval to run the units, Dominion said it remains committed to shutting them down and building the transmission line.
“This law protects PJM and Dominion from civil or criminal liability or citizen suit, but it is our intention to continue moving forward as quickly as possible to build and energize the transmission project limiting the time these units will operate to ensure the best environmental outcome,” Harris said.
