FERC on Monday denied requests by two Massachusetts municipalities for a stay of its January approval of the Atlantic Bridge Project, a $452 million expansion and upgrade of existing pipeline networks in New York and New England (CP16-9-001; CP16-9-004).
The two Boston-area communities — the town of Weymouth and city of Quincy — alleged that the prospect of construction was harming property values and making it “impossible for owners to sell their residences in the face of uncertainty.”
The commission quoted its own environmental assessment that found the project’s “pipeline segments primarily involve replacements of existing pipeline in the same location and would not require a new permanent pipeline easement. … Existing property values in these areas account for the presence of the existing pipeline and/or compressor station infrastructure.”
| Spectra Energy
The Atlantic Bridge Project would expand Enbridge’s Algonquin Gas Transmission and Maritimes & Northeast Pipeline systems by 132,700 dekatherms/day to serve the New England and Canadian natural gas markets. The project would replace existing pipelines and expand existing compressor stations or build new ones in New York, Connecticut and Massachusetts, including a 7,700-horsepower compressor station to be built in Weymouth. (See Atlantic Bridge Project Approved by FERC.)
While the Weymouth compressor station would be a new facility, it will be built “on a previously disturbed industrial property … between an existing water treatment facility and electric power plant” and will not “result in other impacts that would significantly impact adjacent property values,” the commission said.
Quincy also contended that FERC’s order would cause harm by encouraging investors to back development of the separate Access Northeast pipeline project, which would run through the community. The commission found that contention “purely speculative” and said that the city did not allege what harm it would suffer from development of Access Northeast.
For Whom the Order Tolls
Weymouth additionally requested rehearing of a procedural tolling order issued by FERC Secretary Kimberly Bose in March.
The order stemmed from the commission’s lack of a quorum, which Weymouth argued left the town no recourse, either through the commission or the courts, to halt construction of the project. But FERC rebuked that contention, explaining that the order was only meant to give the commission “additional time for consideration of the matters” raised on rehearing. Weymouth was “free to seek stays from the commission or other relief,” it said.
Weymouth also called the tolling order unconstitutional, premising its argument upon a February 2017 D.C. Circuit Court of Appeals decision in PHH Corp v. Consumer Financial Protection Bureau, which held that “the consolidation of substantive decision-making authority into a single person eliminates ordinary constitutional checks and balances and is, therefore, unconstitutional.”
FERC found Weymouth’s argument inapplicable because the court “agreed to rehear the case en banc and vacated its earlier opinion. Moreover, the panel members differed on the appropriateness or necessity of the separation-of-powers ruling relied upon by Weymouth.”
FERC must consider the impact of greenhouse gas emissions when licensing natural gas pipelines, a split D.C. Circuit Court of Appeals panel ruled Wednesday (16-1329).
The panel’s 2-1 ruling in favor of a petition by the Sierra Club parted with previous D.C. Circuit rulings that found FERC did not have to consider the climate-change effects of exporting natural gas in its licensing of LNG terminals.
The majority — Judges Thomas Griffith, a George W. Bush appointee, and Judith Rogers, a Bill Clinton appointee — remanded FERC’s environmental impact statement (EIS) on the Southeast Market Pipelines Project, ordering the agency to estimate the project’s impact on GHG emissions or explain more fully why it could not do so.
Judge Janice Rogers Brown, also appointed by Bush, dissented, saying the court should have ruled as it did in the LNG cases.
FERC’s ruling affects the Southeast Market Pipelines Project, including the nearly 500-mile Sabal Trail pipeline between Alabama and Florida | Sabal Trail Transmission
The Southeast Market Pipelines Project involve three pipelines, including the nearly 500-mile Sabal Trail, which will connect the other two pipelines between Tallapoosa County, Ala., and Osceola County, Fla., south of Orlando. Scheduled for completion in 2021, the project has a capacity of more than 1 Bcfd.
Existing Pipelines near Capacity
With both of its two major natural gas pipelines near capacity, Florida is at risk of having demand outstrip supply, according to Florida Power & Light and Duke Energy Florida, which have committed to buying nearly all the gas the project can transport.
The project’s developers — Duke Energy, FP&L parent NextEra Energy, Spectra Energy Partners and the Williams Companies — said increased gas supplies will allow utilities to retire old coal-fired power plants, thus providing a net reduction in GHG emissions.
FERC has jurisdiction over licensing interstate gas pipelines under Section 7 of the Natural Gas Act, which requires a finding that the project will serve the public interest before issuance of a certificate of public convenience and necessity. The commission began the EIS on the project in fall 2013 and issued its final report in December 2015, before approving the project in February 2016 (CP14-554, et al.). It rejected rehearing requests on the order in September 2016.
Because some of the pipeline’s gas would be burned by new or existing electric generators, resulting in CO2 emissions, “at a minimum, FERC should have estimated the amount of power-plant carbon emissions that the pipelines will make possible,” Griffith and Rogers ruled.
Prior Rulings
The pipeline developers contended FERC was not obliged to consider emissions, based on the Supreme Court’s 2004 ruling in Department of Transportation v. Public Citizen (541 U.S. 752), in which it said that because the Transportation Department could not exclude Mexican trucks from the U.S., it was not required to gather data about the environmental harms of admitting them.
The D.C. Circuit applied the Public Citizen rule in three challenges to FERC approvals of LNG terminals, siding with the commission in all of them because it is the Energy Department — not the commission — that ultimately decides whether the terminals can export gas (Sierra Club v. FERC, 827 F.3d 36 (D.C. Cir. 2016); Sierra Club v. FERC, 827 F.3d 59 (D.C. Cir. 2016); EarthReports, Inc. v. FERC, 828 F.3d 949 (D.C. Cir. 2016)). FERC’s jurisdiction over LNG, delegated by DOE, is limited to approving the construction of the terminals.
In reviewing pipelines, “FERC is not so limited,” the court said in this week’s order. “Congress broadly instructed the agency to consider ‘the public convenience and necessity’ when evaluating applications to construct and operate interstate pipelines.” Thus, FERC could deny a pipeline certificate by concluding that the environmental harm posed by the project outweighed its public benefits, making the commission a “legally relevant cause” of environmental effects of pipelines it approves, the judges said.
FERC: Impact Unknown
FERC contended that the impact of the pipelines on GHG emissions was unknowable, dependent on variables including the operating decisions of individual plants and regional power demand. But the court said the National Environmental Policy Act — which mandates an EIS for each “major federal action significantly affecting the quality of the human environment” — requires some “reasonable forecasting.”
“The EIS gave no reason why [the pipeline’s capacity] could not be used to estimate greenhouse gas emissions from the power plants, and even cited a Department of Energy report that gives emissions estimates per unit of energy generated for various types of plant,” the court said. It said FERC “should have either given a quantitative estimate of the downstream greenhouse emissions that will result from burning the natural gas that the pipelines will transport or explained more specifically why it could not have done so.”
Without comparing the emissions from this project to other projects or to total emissions from the state or the region, “it is difficult to see how FERC could engage in ‘informed decision making,’” the judges said.
The court said FERC also must explain in the revised EIS its position on whether it should use the Social Cost of Carbon in its evaluations. The commission has argued previously against using the measure, saying that some of its components are subject to dispute and that not every harm it accounts for is “significant” under NEPA.
Dissent, Reaction
In her dissent, Brown said the pipeline case presented “virtually identical circumstances” to the LNG cases that the court said did not require GHG impact analyses. Because the Florida power plant Siting Board has the sole power to approve or deny new power plants in the state, “this breaks the chain of causation,” Brown said.
FERC declined to comment on the ruling.
The American Petroleum Institute, which absorbed America’s Natural Gas Alliance in 2015, said it believes FERC acted properly and is evaluating the ruling. “Regulatory certainty is critical to ensuring that infrastructure is constructed efficiently. Further delays due to needless regulatory hurdles will slow consumer access to reliable, affordable natural gas and opportunities for job creation,” it said.
The Natural Gas Supply Association, which represents 14 large gas producers and marketers, said it was “disappointed” by the order but had no other immediate comment.
MISO will resume discussion on possible cost recovery for participant-funded transmission projects under 345 kV after two wind industry organizations called on a stakeholder committee to revisit the issue.
The MISO Advisory Committee will take up the subject at a Sept. 20 meeting during Board of Directors week in St. Paul, Minn., where stakeholder sectors can offer opinions on the matter.
EDF and Indianapolis Power and Light’s Hoosier Wind Farm | Mortenson
Wind developer EDF Renewable Energy and nonprofit Wind on the Wires approached the Advisory Committee during an Aug. 23 conference call to once again appeal for cost recovery on customer-funded transmission upgrades under a proposed “non-[MISO Transmission Expansion Plan] upgrades” category. The RTO’s Steering Committee last month declined to rehear the issue after determining it had been fully considered in the stakeholder process even if supporters of the change were disappointed with the outcome. Some stakeholders pointed out that customers accept the risks of funding their own upgrades performed outside the MTEP process, and an after-the-fact cost allocation would be too complex to introduce.
“We don’t think the discussion was robust enough,” said Bruce Grabow, an attorney representing EDF.
Grabow said the discussion in the MISO Regional Expansion Criteria and Benefits Working Group (RECBWG) demonstrated a “fundamental misunderstanding of the need and request.” The group had failed to discuss the current “gap” in congestion management or why participant-funded upgrades should be excluded from cost allocation, he said. There had also been no discussion of the possible unreasonableness of the status quo and no “exploration of how the proposal could work or be adjusted to address stakeholder concerns.”
Grabow argued that there should be a “simple” one-time return of installed costs imposed on new interconnection requests. MISO’s status quo of leaving the cost of customer-funded upgrades solely to the customer is “proving to be an insufficient means,” as no such projects were brought forward in MTEPs 14, 15 or 16 despite the need for sub-345-kV projects that relieve congestion, he said.
“One of the biggest challenges facing wind generators today is congestion in various areas that cause curtailment,” Wind on the Wires Executive Director Beth Soholt told Advisory Committee members. She said that customer-funded transmission upgrades meant to relieve congestion often become heavily trafficked with non-firm use themselves, diminishing the benefit that the project financier envisioned.
Grabow rebutted the RECBWG’s opinion that allowing cost recovery on customer-funded upgrades would equate to buyer’s remorse.
“If new customers are coming in and couldn’t get transmission service but for the upgrade, it’s not buyer’s remorse. It was done for a particular reason: to relieve congestion,” he said.
Grabow also argued that financial transmission rights are not adequate to ensure a fair payout.
“If new customers are relying on that transmission, they should pay their fair share,” he said.
New York energy markets performed competitively during the second quarter, with changes in fuel prices, demand and supply availability driving variations in wholesale prices, according to the NYISO Market Monitoring Unit’s second-quarter State of the Market report, released Monday.
Gas prices rose 20 to 60% in eastern New York and 65% in the western part of the state. But much of the impact on locational-based marginal prices (LBMPs) was offset by higher output of approximately 950 MW from nuclear, internal hydro and imports from Quebec and Ontario.
| Potomac Economics
All-in prices averaged from $21/MWh in the North Zone to $57/MWh in New York City. The range was primarily because of congestion on power flowing from the North Zone to central New York, Central East congestion, and capacity price differences. Zone-level LBMPs increased in most regions by 7 to 25%.
Capacity costs were impacted by changes in net cost of new entry from the recent demand curve adjustment process. (See “ICAP Manual Changes for Demand Curve Reset Updates,” NYISO Business Issues Committee Briefs: Aug. 9, 2017.)
Congestion Management
Congestion costs from priced and unpriced constraints rose from 2016, with day-ahead congestion revenue up 24% from the same period a year ago to $117 million. Congestion increased into the city, across the Central East interface and along paths from western and northern New York, where priced congestion declined.
Unpriced congestion in the western and northern parts of the state became more prevalent because of improved hydro conditions within the state and low prices in the adjacent Canadian markets, as well as from transmission upgrades completed last year, which reduced priced congestion on 230-kV facilities in the west but shifted more flows onto parallel 115-kV circuits.
Sir Adam Beck Generating Complex in Niagara Falls, Ontario, the largest source of hydroelectric power in the province.
The Monitor found that “actions used to manage 115-kV congestion in western and northern New York led to import limitations from Ontario and Quebec as well as congestion on the 200-kV system in other parts of the state … management [which] could be performed more efficiently through the [day-ahead] and [real-time] market systems.”
PAR Operations with PJM
Real-time congestion costs for the Valley Stream load pocket on Long Island fell from a year ago because of improved modeling of lines between New York City and Long Island. Congestion increased through Millwood and into the city, but the ABC and JK lines were operated more efficiently.
The market-to-market phase angle regulator (PAR) coordination process with PJM expanded to include the ABC and JK lines in May after the 1,000-MW Con Ed-PSEG wheel expired. New coordinated flowgates were added mostly in New York City and the West Zone. For all PARs, actual flows typically exceeded their M2M targets toward New York, resulting in a small amount of M2M payments from PJM to NYISO in the second quarter.
The Monitor did find instances of efficient M2M coordination as PARs were moved in the correct direction to reduce overall congestion costs in a relatively timely manner. However, it cited “many instances” when PAR adjustments may have been available and would have reduced congestion but no adjustments were made.
“We observe that these PARs were often not utilized to help manage congestion, being adjusted only two to five times per day on average,” the report said.
PAR adjustments were not taken in some cases because of difficulty in predicting the effects of PAR movements under uncertain conditions or when adjustment would have pushed actual or post-contingent flows close to a line limit — or because of the transient nature of congestion or mechanical failures, such as stuck PARs.
The Ramapo PARs have provided significant benefits to NYISO in managing congestion on coordinated flowgates. Balancing congestion surpluses have resulted from relief of transmission paths from central to east New York, indicating that they reduced production costs and congestion.
“Nonetheless, comparable benefits have not been observed from the operation of ABC and JK PARs in the second quarter of 2017,” the report said. “We observed potential opportunities for increased utilization of M2M PARs.”
| Potomac Economics
The normal limit for each PAR-controlled line was more than 500 MW, but flows were generally well below that level. On average, each PAR was adjusted two to five times per day, well below the operational limits of 20 taps/day and 400 taps/month. This was also below the average five to six 30-minute blocks of time per day when the congestion differential between PJM and NYISO exceeded $10/MWh across these PAR-controlled lines.
Reserve Market Performance
Day-ahead 30-minute reserve prices have been substantially elevated since a market rule change in November 2015, driven primarily by the new limitation on scheduling reserves on Long Island (down 250 to 300 MW), an increased 30-minute reserve requirement (up 655 MW) and higher reserve offer prices from some units.
The Monitor found that many units that offer above the standard competitive benchmark — or the estimated marginal cost — in part because of the difficulty in accurately estimating the marginal cost of providing operating reserves.
According to the Monitor, day-ahead offer prices may fall as suppliers gain more experience, which was evident in the second quarter as a large amount of reserve capacity reduced its offer prices from previous years, helping reduce price averages.
The Monitor will consider potential rule changes, including whether to modify the existing $5/MWh “safe harbor” for reserve offers in the market power mitigation measures.
Uplift and Revenue Shortfalls
Guarantee payments were $11.2 million during the quarter, comparable to a year earlier. Those payments rose in New York City and fell in Western New York because of higher gas prices that increased the commitment costs of gas-fired units and supplemental commitment for reliability in the city, and decreased out-of-merit dispatch and commitment of the AES Cayuga coal-fired units in the west.
Congestion shortfalls were $21 million in the day-ahead market and $11 million in the real-time, higher and lower, respectively, than in the same period in 2016.
Transmission outages accounted for roughly 80% of day-ahead market shortfalls in the second quarter, and $17 million were allocated to the responsible transmission owner.
Nearly all the real-time market shortfalls were associated with the North Zone lines, the West Zone lines and the Capital to Hudson Valley lines, with North Zone shortfalls accruing almost entirely because of transmission outages on two days in early April, totaling $4.6 million.
Capacity Market
Second-quarter capacity spot prices ranged from $1.99/kW-month in Rest-of-State to $8.02/kW-month in New York City. The average price includes one month of winter pricing (April) and two months of summer pricing (May and June).
Compared to the previous year, average spot prices fell 21 to 45% in New York City and the New York Control Area (NYCA) and rose 9% to 17% in the G-J Locality and Long Island.
Price changes in all regions were driven largely by changes to the installed reserve margin and net CONE of the proxy unit from the demand curve reset process. Net CONE values rose substantially in both the G-J Locality and on Long Island, while falling in the city and NYCA.
Additionally, import levels averaged 430 MW higher in the second quarter compared to 2016, with noticeably higher imports from PJM more than offsetting reduced imports from ISO-NE.
Energy Secretary Rick Perry’s much-awaited grid study calls on the federal government to rescue traditional “baseload” power — coal and nuclear — by addressing renewables’ negative pricing and ending EPA’s New Source Review rule on coal generators.
| Energy Information Administration (EIA) Electric Power Monthly, June 2017
The 187-page study, which was released late Wednesday night, contains little if any new data or analysis. Virtually all the trends it cites and the issues it raises have been under discussion for months or years at FERC, in state legislatures and at RTO/ISO stakeholder meetings. What is new are some of the policy recommendations, which reflect the Trump administration’s support of the coal industry and its rejection of the Obama administration’s Clean Power Plan.
The report cites Executive Order 13783, saying that while the Energy Department is not specifically named in the order, the department “should continue to prioritize energy dominance” and that it and other federal agencies “should accelerate and reduce costs” for licensing “nuclear, hydro, coal, advanced generation technologies and transmission. DOE should review regulatory burdens for siting and permitting for generation and gas and electricity transmission infrastructure and should take actions to accelerate the process and reduce costs.”
| Monitoring Analytics, 2017 Quarterly State of the Market for PJM: January through March 2017
‘Unnecessary Burden’
As one example, it suggests ending the New Source Review rule, administered by EPA under the Clean Air Act, saying coal-fired generators should be allowed “to improve efficiency and reliability without triggering new regulatory approvals and associated costs.”
“The uncertainty stemming from [New Source Review] creates an unnecessary burden that discourages rather than encourages installation of CO2 emission control equipment and investments in efficiency because of the additional expenditures and delays associated with the permitting process,” it said.
It also says FERC should require valuation of “Essential Reliability Services,” in which it includes reliability-must-run generators and ancillary services (frequency and voltage support, and ramping capability).
Perry, who requested the study in an April 14 memo, said it was “long overdue.”
“The industry has experienced massive change in recent years, and government has failed to keep pace,” he said in his cover letter to the report. “This report examines the evolution of markets that has occurred over the last 15 years. Policymakers and regulators should be making decisions based on what the markets look like today, not what they looked like years ago.”
Perry’s memo, which set a 60-day deadline, called for the department to “explore critical issues central to protecting the long-term reliability of the electric grid,” and to analyze “market-distorting effects of federal subsidies that boost one form of energy at the expense of others.” The report arrived two months late.
Vehicle for Trump Policy?
The memo sparked concern among renewable energy advocates that the study would be a vehicle for Trump to deliver on his campaign promises to “save” the coal industry.
Their fears were heightened by the involvement in the study of Travis Fisher, a former FERC economist hired by DOE in January who had written a 2015 report for the conservative Institute for Energy Research that alleged the “single greatest threat to reliable electricity in the U.S. does not come from natural disturbances or human attacks” but federal and state government policies such as renewable subsidies and mandates.
But the politicization appeared to have been tempered by the involvement of career DOE staffers and contractor Alison Silverstein, once senior adviser to former FERC Chair Pat Wood, a Republican appointee of President George W. Bush. Silverstein is board secretary for the American Council for an Energy-Efficient Economy.
Another factor was the leak of a draft of the report in June, which contradicted Perry’s memo by concluding that low natural gas prices rather than renewable-friendly policies were the main cause of coal and nuclear plant retirements.
Changes from Leaked Draft
Joe Romm, a writer for the progressive website ThinkProgress, compared the final version with the draft and concluded that “while Trump officials clearly tried to rewrite the previously leaked staff draft to give the impression that renewable energy sources are a threat to baseload power and grid resilience, they mostly botched the job.”
The draft report found that environmental regulations and renewable energy subsidies “played minor roles compared to the long-standing drop in electricity demand relative to previous expectation and years of low electric prices driven by high natural gas availability.”
The draft also concluded that “the power system is more reliable today due to better planning, market discipline, and better operating rules and standards.”
Both of those conclusions were eliminated from the final report, Romm said.
Instead, the final report concedes that “the biggest contributor … has been the advantaged economics of natural gas-fired generation,” and that “another factor … is low growth in electricity demand.”
The report also substituted the finding that renewable subsidies had a minor impact on baseload plant retirements with the conclusion that “dispatch of VRE [variable renewable energy] has negatively impacted the economics of baseload plants” — a statement that is undermined elsewhere in the report citing data that “do not show a widespread relationship between VRE penetration and baseload retirements.”
| Department of Energy, Staff Report to the Secretary on Electricity Markets and Reliability, August 23, 2017
While the final report notes that “recent severe weather events” have “demonstrated the need to improve system resilience,” it removes the words “climate change,” which many scientists believe is a contributor to the phenomenon.
“Perry and his staff took a perfectly solid report on the grid and added a (surprisingly light, to my eye) coating of political propaganda,” wrote columnist David Roberts on Vox. “The result is a muddy report, with findings in it to please (or enrage) every onlooker.”
Coal, Nuclear Groups Praise Report
In early reaction to the report, many groups seemed to be able to find something they liked — with the coal and nuclear lobbies most effusive. Environmentalists were dismissive, if relieved.
“We commend Secretary Perry and the Department of Energy for studying the challenges facing the electricity grid,” said Paul Bailey, CEO of the American Coalition for Clean Coal Electricity. “One of the biggest challenges is how to preserve the nation’s coal fleet so it can continue supporting a reliable and resilient electricity grid.”
“We commend Secretary Perry for his leadership in beginning this important but long overdue conversation about the future reliability and resilience of our electric power system,” said National Mining Association President Hal Quinn. “Among other findings, the report notes that ‘regulations and mandates,’ in addition to market forces, have accelerated the closure of a substantial number of baseload power plants. … As the report notes, many states and regions bear an increased risk from the destruction of traditional baseload power and the resulting diminution of grid resilience.”
Nuclear Energy Institute CEO Maria Korsnick said the study “reaffirms our view that nuclear energy is a key and necessary contributor to a clean, reliable and resilient electric grid.”
“In the 10 years since the last comprehensive grid study by our government, electricity markets have changed radically,” she continued. “Today electricity markets do not properly credit nuclear energy for the numerous benefits it delivers, forcing plants to close years before the end of their useful lives and compromising grid reliability and resiliency in the process.”
Kelly Speakes-Backman, CEO of the Energy Storage Association, said the group was “encouraged” by its initial review of the report.
“The report plainly states that advanced energy storage systems are critical to ensuring that electricity is reliable, affordable and secure,” she said. “We also agree with the key findings that better strategies are needed by markets and in resource planning to properly reward the values that energy storage systems provide to the grid, especially increased reliability and resiliency.”
Tom Kiernan, CEO of the American Wind Energy Association, said the group agrees with the department “that it makes sense to determine how a portfolio of domestic energy resources can ensure grid reliability and resilience.”
Kiernan — who noted that the U.S. wind industry is expected to “support” 147,000 jobs by 2020 — said the report “provides a number of valuable policy recommendations.”
“In particular, DOE’s recommendations to value essential reliability services, which wind provides; to minimize regulatory barriers to energy production; and to accelerate infrastructure and transmission development are prudent and will help continue America’s wind power success story,” he said.
Dissenting Voices
The Alliance to Save Energy said the discussion about the report overlooked the role of energy efficiency. “As we look at the portfolio of solutions we can’t just look at supply,” said President Kateri Callahan. “We have to remember that increasing efficiency and productivity is the fastest and cheapest way to reach our goals — and it’s also a tremendous economic opportunity. Already efficiency is the leading job creator in the clean energy sector with some 2.2 million jobs in construction, manufacturing and other fields.”
Graham Richard, CEO of Advanced Energy Economy, a group of clean-energy and technology companies, said he was pleased that the department “recognizes that changes in the grid are primarily the result of low-cost natural gas, not policies supporting renewable energy.”
But he said the report “seriously overstates the challenges associated with new energy resources. It also implies that certain power plants now losing out in the marketplace make an irreplaceable contribution to reliability and resilience, which is not the case.”
| Department of Energy, Staff Report to the Secretary on Electricity Markets and Reliability, August 23, 2017
“Our nation’s grid operators themselves have said they are facing no difficulty in managing an increasingly diverse set of resources, and that they will have no difficulty maintaining reliability as uncompetitive power plants inevitably retire,” he added. “What is happening in our power grid is a natural process of technology progress and market competition. That process should be allowed to continue, not be distorted by this administration’s preference for ‘baseload’ resources over the flexible resources that are modernizing the electric power system.”
Also critical was environmental group Earthjustice, which said the report “shows that science is not safe from manipulation under this administration.”
“Sound findings in the earlier draft of the report have been mysteriously excised, replaced by trumped up claims about the costs of environmental regulations,” said Earthjustice attorney Kim Smaczniak. “And this report says nothing about climate change. By willfully burying its head in the sand on climate change, the administration will make the grid more vulnerable to the next Superstorm Sandy, which left millions without electricity.”
FERC on Tuesday approved MISO’s proposed system support resource (SSR) agreement for Cleco Power’s Teche 3 generating plant in Baldwin, La., effective April 1 (ER17-1227, ER17-1228).
MISO designated the 338-MW natural gas-fired plant as an SSR after Cleco notified the RTO it planned to retire the plant. The RTO said the plant will be needed to prevent severe thermal violations on its transmission system that are not addressed by available mitigation measures until the Terrebonne–Bayou Vista 230-kV line can be put into service in 2018.
Cleco’s Teche Power Station in Baldwin, LA | Google
The RTO said no feasible alternatives to SSR designation were identified in stakeholder meetings.
The commission rejected a protest by Entergy, which said the SSR agreement — which includes hourly compensation for the plant’s production and operating reserve costs — should include a true-up mechanism for the recovery of fixed costs to prevent Cleco from being overpaid. The commission said that issue should be addressed in a separate docket opened by Cleco for obtaining additional compensation to ensure it recovers its full cost of service (ER17-1368).
Teche 3 was built in 1971. Unit 1, completed in 1954, retired last September. Unit 2, completed in 1956, retired in 2011, when Cleco completed Teche 4, a 35-MW gas-fired black start generating unit.
Below is a summary of the issues scheduled to be brought to a vote at the Markets and Reliability Committee on Aug. 24. Each item is listed by agenda number, description and projected time of discussion, followed by a summary of the issue and links to prior coverage in RTO Insider.
RTO Insider will be in Wilmington, Del., covering the discussions and votes. See next Tuesday’s newsletter for a full report. There is no Members Committee meeting scheduled this month.
Markets and Reliability Committee
2. PJM Manuals (9:10-9:25)
Members will be asked to endorse the following proposed manual changes:
A. Manual 11: Energy & Ancillary Services. Revisions developed as part of the implementation of Coordinated Transaction Scheduling, a new real-time energy scheduling product across the PJM-MISO interface. The presentation will include associated revisions with the Regional Transmission and Energy Scheduling Practices document.
3. Governing Document Revisions to the Limitation on Claims (9:25-9:40)
Members will be asked to endorse proposed Tariff and Operating Agreement revisions that clarify the two-year limit on requests for billing adjustments.
4. Seasonal Capacity Resources Sr. Task Force (SCRSTF) (9:40-10:10)
5. Dynamic Schedule Pro Forma Agreement (10:10-10:25)
Members will be asked to endorse proposed joint operating agreement and Tariff revisions to develop a pro forma agreement for dynamic scheduling. (See “OC Discusses Pro Forma Agreements for Pseudo-Ties, Dynamic Schedules,” PJM OC Briefs: July 11, 2017.)
Fort Lauderdale-based trader K. Stephen Tsingas agreed to pay $2.7 million in penalties and restitution in a deal with FERC’s Office of Enforcement that will also bar him from trading in commission-jurisdictional markets for three years. The commission approved a consent agreement setting the terms on Aug. 22 (IN5-5).
Tsingas and his company, City Power Marketing, agreed to the settlement without admitting to the commission’s allegation that they violated the Federal Power Act and commission regulations by engaging in market manipulation and later lying to FERC investigators.
City Power also agreed to pay a $9 million civil penalty, but the company is defunct and FERC agreed not to pursue Tsingas for the additional amount. In a filing in 2015, Tsingas said that FERC’s investigation forced him to lay off all his employees and “destroyed” the company. (See UTC Trader: Firm was Ruined by ‘Unfair’ FERC Prosecution.)
Although the $11.7 million in penalties were reduced from the $16.3 million the commission had sought, the case represents a victory for FERC in its crackdown on traders who profited from what the commission called risk-free up-to-congestion (UTC) trades. FERC said the trades were intended to cash in on line-loss rebates in PJM — the same type of trading that gave rise to the commission’s high-profile battle with brothers Kevin and Rich Gates and their Powhatan Energy Fund.
Three Types of Trades
The commission said City Power collected the rebates — or marginal loss surplus allocations (MLSA) — through three types of UTC transactions: “round-trip” trades that canceled each other out; trades between import and export pricing points of the same PJM interface with equivalent prices (SOUTHIMP-SOUTHEXP); and trades between two PJM nodes that historically had a very small price spreads (NCMPAIMP-NCMPAEXP).
The commission concluded that City Power created the false impression that it was trading to arbitrage price differences “when, in fact, it was engaging in trades solely to collect MLSA payments to the detriment of other market participants.”
Tsingas
The commission also accused Tsingas of attempting to mislead investigators by denying the existence of incriminating instant messages between him and a trading colleague.
The commission sued Tsingas after he failed to respond to a July 2015 order demanding the $16.3 million. The two sides reached a settlement in March, after a U.S. district court last August rejected Tsingas’ motion to dismiss and in January denied FERC’s motion for summary judgment. Approval of the settlement was delayed by FERC’s loss of a quorum in February.
Under the consent agreement, Tsingas will pay $1.3 million in disgorged profits to PJM and a $1.42 million penalty to the U.S. Treasury Department. Tsingas must pay $825,000 to PJM within 60 days, paying the balance over 10 years.
Barred from Trading
Tsingas also agreed that neither he, nor any person acting on his behalf, “will engage or participate (whether through consulting, advising, directing or strategizing), directly or indirectly, in any trading transaction (whether physical or financial or virtual) within the commission’s jurisdiction for three years.”
However, the bar “does not apply to any business entity in which Tsingas has an ownership interest, or its employees, so long as Tsingas does not personally engage or participate in, directly or indirectly, or otherwise operate or consult about, any trading transaction within the commission’s jurisdiction.”
“FERC would not have been able to pursue this remedy had the court decided the case on the merits,” observed Matthew Connolly, a senior associate in the litigation department of Nutter McClennen & Fish.
Like Tsingas, the Gates brothers and Coaltrain Energy — a third set of defendants accused of profiting from riskless UTC trades — have sought de novo reviews of FERC’s allegations, in which a federal district court would decide all issues of fact and law. (See Traders Deny FERC Charges; Seek Independent Review.)
The Powhatan case has been stalled in the Eastern District of Virginia, awaiting a judge’s ruling on how the review should proceed. FERC has asked for a short, appellate-style review (3:15-cv-452).
Coaltrain is awaiting a ruling from a judge in the District Court for Southern Ohio on its motion to dismiss (2:16-cv-00732).
PJM Seeks Advice
In April 2015, PJM asked FERC for advice on who should receive the disgorged profits and how they should be calculated. It also sought direction on how refunds should be made to parties who are no longer PJM members and noted that there were six entities alleged to have engaged in sham trades who would also be considered victims of the City Power trades. (See PJM Asks FERC for Direction on Refunds from Illegal Trades.)
In an order in July 2015, the commission told PJM to establish a method to distribute the resettled MLSA payments to market participants that would have received higher rebates if not for the money collected by City Power. The RTO must seek approval of its methodology from the director of the Office of Enforcement within 45 days after receiving the disgorged funds.
Power sellers and utilities in CAISO are urging the grid operator to develop a long-term plan to procure the flexible capacity resources increasingly needed to manage the integration of variable renewable generation.
Market participants commented on a recent stakeholder meeting regarding the ISO’s Flexible Resource Adequacy Criteria and Must Offer Obligation Phase 2 (FRACMOO 2) proposal. The ISO is proposing to introduce new variations in its flexible resource adequacy (RA) capacity product, which is intended to increase the ramp rate of the flexible capacity fleet. (See CAISO Flex Capacity Effort Targets Increased Variability.) CAISO is needing quicker ramping speeds within shorter time cycles as more renewables are brought into the system.
Monthly Three-hour Generator Ramp-ups are on the Increase in CAISO | CAISO
The current proposal is a set of short-term solutions, and CAISO said it will later develop a “long-term RA roadmap” to integrate system, local and flexible capacity needs, and state renewable portfolio standards.
The bulk of the current proposal represents short-term modifications to the flexible capacity criteria to emphasize start-up and minimum run times. CAISO is exploring the use of intertie resources but does not yet have a specific proposal. It hopes to have a program in place in time for the 2020 RA year.
Southern California Edison (SCE) said it is not a function of the resource adequacy program to optimize resources, as stated in a Brattle Group proposal discussed in the stakeholder call. Brattle included “products to optimally utilize resources” as a goal of flexible capacity, but SCE said that optimal use is the role of the wholesale market. The RA program is meant to ensure that capacity is available via a must-offer obligation. “SCE does not believe that the CAISO has clearly demonstrated where the current three-hour product is failing,” the company said.
Powerex, which markets BC Hydro output, commented that CAISO should examine why flexible capacity needs are causing challenges and how to make “cost-effective resource investments” to achieve environmental goals. Powerex said the ISO should develop additional tools to reduce the magnitude and steepness of net load ramps when they would otherwise exceed available flexible capacity in real time, allowing it to procure additional flexible capacity from existing resources.
The Western Power Trading Forum (WPTF) said that “this initiative does not have to be the end all, be all in incenting flexibility from the CAISO fleet. The CAISO can also enact energy market reforms and, if necessary, procure backstop capacity.” The group urged the ISO to keep the proposal simple and target products that will incentivize load-serving entities to contract with the most flexible resources, and incent interties to economically offer in their capacity.
“This will provide proper market incentives resulting in economically efficient outcomes, including the potential of the retirement of less flexible, unneeded capacity,” WPTF said.
The Alliance for Retail Energy Markets, a group representing competitive suppliers — including Constellation NewEnergy, Direct Energy and Noble Americas Energy Solutions — contended that CAISO should identify the root causes of the reliability needs and develop a market-based solution that properly assigns costs and provides price signals.
FRACMOO 2 is Intended to Reduce Curtailment of Renewables | NextEra Energy’s Altamont Pass Wind Farm Source Wikimedia
“In spite of many years of effort, the CAISO is still seeking to understand the flexible needs on the system,” the group said in its comments. “In addition, the continued focus of the CAISO on specifying prescriptive capacity procurement requirements for load-serving entities (LSEs) is fundamentally misplaced and excessively burdensome.” Meeting flexible capacity needs through ancillary services would provide transparency and investment signals for new resources, the suppliers said.
CAISO plans to have a draft final FRACMOO 2 proposal early next month and approval from the Board of Governors by the second quarter of 2018.
By Jason Fordney, Tom Kleckner, Amanda Durish Cook, Rory D. Sweeney and Michael Kuser
FOLSOM, Calif. — CAISO and other electric grid operators across the country managed large and rapid swings in solar generation output Monday during the first continent-wide total solar eclipse in nearly a century.
ISOs and RTOs were well prepared for the event, especially in solar-heavy California where the obscuration of the sun took thousands of megawatts of utility and rooftop solar off the grid. CAISO had to ramp up hydro and natural gas generation as solar dropped off, then do the reverse more quickly than usual as the sun came back.
Electronic board in CAISO control room displays solar generation (left) and load (right) during and after eclipse | CAISO
“We wanted to make sure we could make it if it was an extremely hot day, or if it was a mild day,” CAISO Executive Director of Operations Nancy Traweek said. She added that the ISO had reached out to solar and hydro operators and asked them to be prepared for the event.
The last total solar eclipse to occur in the continental U.S. was before the growth in solar power in 1979 and was viewable only from the Pacific Northwest, according to NASA. Monday’s was the first total eclipse since 1918 to span the width of the U.S.
As eyes equipped with protective glasses turned upward around the country, CAISO employees excitedly gathered outside the building, some with family members, to view the event.
CAISO said it would not be able to provide precise figures for how much solar generation dropped off its system until later this week.
“We forecasted 4,200 MW of utility-scale solar coming off. We believe that the actual will be more in the 3,000 to 3,500 MW range,” CAISO spokesman Steven Greenlee said.
CAISO data showed that the eclipse took a little more than 3,000 MW offline; in a briefing Monday morning, ISO officials said more than 3,000 MW of utility solar and 1,400 MW of rooftop solar could be lost.
Grid operators had to deal with two solar ramp-ups rather than just one.
About 10:50 a.m. PT, after totality, load was about 30,500 MW and solar generation was about 4,100 MW, with the grid stable. When the sun was nearly clear of the moon about 11:30, CAISO said load was about 29,300 MW and solar generation was about 6,800 MW. By about 1:30 p.m., solar generation in the ISO was back up to about 9,000 MW. There is about 10,000 MW of solar capacity on the ISO system.
CAISO had to manage not only the rapid loss of solar but also a steeper-than-usual climb of that resource compared with a normal day as the sun returned. CAISO predicted it would lose about 51 MW/minute, and as the blockage waned, solar generation came back at a rate of 93 to 100 MW/minute. On a normal morning, solar ramps about 29 MW/minute.
Wholesale prices briefly went negative as solar returned, as they normally do when there is excess generation on the grid. CAISO said that the 1,000-mile East-West span of the Western Energy Imbalance Market (EIM) allowed it to call on available resources as other areas ramped down.
About 860 MW of solar went off the grid in the EIM.
SPP, ERCOT See Little Impact
SPP had anticipated a peak load of approximately 45,000 MW across its system Monday but saw demand about 2,500 MW below that as air conditioning usage dropped and manufacturing facilities closed while employees observed the eclipse.
“In preparation for the relatively sudden and not entirely predictable drop in load, SPP utilized its day-ahead market processes beginning Aug. 20 to commit adequate reserves to accommodate load swings and the resulting impacts to frequency and interchange,” SPP said. The RTO increased its regulation service in preparation. An eclipse also slows wind speed by cooling air, causing a 1,200-MW swing in the RTO’s wind generation that also had to be managed.
“By increasing our regulation requirements, we essentially ‘widened the lanes’ of our system and operated more conservatively than we might have on a normal day to accommodate any unpredictable occurrences during this rare event,” Director of System Operations CJ Brown said.
This was a great learning opportunity for SPP,” said Vice President of Operations Bruce Rew. “And I’m proud that our staff and systems were able to ensure that, despite so many variables and the rarity of the solar eclipse, it was essentially a non-event electrically speaking.”
| GreatAmericanEclipse.com via SPP
Utility-scale solar in the ERCOT system dropped from a peak of 760 MW to a low of 299 MW during the eclipse, while total system load dropped from 60,824 MW to 60,163 MW. The ISO said a number of factors could have contributed to the load decrease, including reduced air-conditioning demand.
Duke Loses 1,700 MW in NC
In North Carolina, Duke Energy reported that it lost about 1,700 MW of capacity during the height of the eclipse. “Given the weather conditions, we should have expected 1,808 MW of solar output during the afternoon. But at the height of the eclipse, we were getting only about 109 MW,” said spokesman Randy Wheeless.
North Carolina is the nation’s No. 2 state for solar capacity, with 2,500 MW connected to the Duke system.
Peak demand for Duke Energy Carolinas and Duke Energy Progress in North Carolina is around 22,500 MW on a typical summer day.
MISO has no Issues
MISO employees watching the eclipse | MISO
MISO said it navigated the eclipse without reliability problems as it crossed its 15-state footprint, but operators did see a significant drop in load.
“Around 1:15 p.m. ET, demand for electricity in the region flattened out and then dropped during a two-hour period as the moon passed in front of the sun. Load began steadily increasing after 3 p.m.,” said spokesman Mark Adrian Brown. “Cooler-than-expected temperatures likely contributed to the drop in load as storms rolled through the Upper Midwest Monday afternoon. Decreased solar generation during the eclipse did not have a major impact on the numbers.”
Currently, MISO has about 180 MW of grid-scale solar and an estimated 350 MW of distributed solar in its footprint.
The RTO said before the event that it would be monitoring its distributed generation and learning lessons for the eclipse on April 8, 2024, when solar will make up more generation in the region.
Clouds in PJM
In the eastern half of the country, cloud cover and rain dampened the eclipse’s effects. At PJM headquarters in Valley Forge, Pa., more than 50 people filtered through an onsite auditorium to try and view the eclipse as it passed across the continent and approached its footprint, the RTO said.
Peak load was expected to be 137,800 MW on Monday, with temperatures near 90 degrees Fahrenheit across much of the Mid-Atlantic.
PJM actual load and forecasts during and after eclipse | PJM
PJM saw grid solar generation drop by about 520 MW from before the eclipse until its peak. Behind-the-meter solar dropped by 1,700 MW. Solar represents less than 1% of PJM’s 185,000 MW of generation capacity.
The RTO had expected the drop in solar production to result in an increase in net load. But “because of a variety of potential factors, including reduced air conditioning, increased cloud cover and changes in human behavior related to the event,” it saw a net decrease in demand of about 5,000 MW during the eclipse.
Temperatures dropped by an average of 2 degrees Fahrenheit, with the Chicago area hit by storms after the eclipse began.
“Substantial cloud cover largely obscured the event at PJM’s offices, but stakeholders and staff gathered outside with special glasses and homemade viewing apparatuses to catch whatever views were available,” PJM said. The grid operator carried about 1,000 MW of regulation service instead of the usual 800 MW.
PJM will use lessons from Monday’s event for April 8, 2024, when the RTO’s footprint will be in the path of a total eclipse between Texas and Maine.
Minimal Effects in New England
ISO-NE had sufficient resources available to meet the rise in electricity demand resulting from a drop in output from the region’s 2,000 MW of solar PV systems during the partial eclipse. New England saw peak obscuration at around 2:45 p.m., when the moon blocked about 65% of the sun. Skies were generally clear across the region during the eclipse.
Eclipse over TVA’s Watts Bar Nuclear Plant | TVA
ISO-NE reported in June that PV generation would face a less extreme reduction in output because the angle of the sun is lower in late August than earlier in the summer, and the eclipse would occur almost two hours after the solar noon peak.
“To precisely balance electricity supply and demand minute-to-minute during the partial eclipse, ISO system operators must consider three major factors that will affect PV output,” said the report: obscuration percentage, angle of the sun and cloud cover.
The grid operator cited human behavior as another factor that could dampen the dip in solar output: “When there’s an eclipse, people typically stop what they’re doing and watch,” which lowers demand for electricity, it said.
New York not Fazed
New York experienced the partial eclipse under clear skies. NYISO said it had minimal impacts on electric load and that it did not need to take any special transmission operating actions.
NYISO Vice President of Operations Wes Yeomans on Friday posted a YouTube video in which he explained that peak totality of roughly 80% would be strongest from 2:30 to 2:45 pm.
New York has approximately 850 MW of rooftop solar, but solar generation peaks at 625 MW because the panels are not aligned in the same direction, Yeomans said. Solar output peaks between noon and 1 p.m. on very sunny days.
The last significant solar eclipse in New York occurred on May 10, 1994, when there were very few solar devices in the state.
