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August 24, 2017March 26, 2025

Nuclear, Hydro Help New York Offset Higher Gas Prices in Q2

By Michael Kuser

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.

August 24, 2017

Perry Grid Study Seeks to Aid Coal, Nuclear Generation

By Rich Heidorn Jr.

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.

rick perry grid study baseload power negative pricing — | *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.”

‘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.”

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.”

“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.”

August 23, 2017

MISO Wins OK for Cleco Plant SSR

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.

FERC Cleco Energy SSR MISO — 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.

— Rich Heidorn Jr.

August 23, 2017

PJM Markets and Reliability Committee Preview: Aug. 24, 2017

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)

Members will be asked to endorse a problem/opportunity statement and issue charge regarding items related to market participation by seasonal resources. The matters were discussed in the task force but ultimately not addressed in the FERC-approved enhanced aggregation proposal. (See PJM Outlines Aggregation Rules for Upcoming Capacity Auction.)

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.)

— Rory D. Sweeney

August 23, 2017

UPDATED: Trader Agrees to Pay $2.7M in Win for FERC

By Rich Heidorn Jr.

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.”

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.

August 23, 2017

Power Sellers Urge Action on CAISO Flex Capacity

By Jason Fordney

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.

caiso flexible capacity — 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.

August 22, 2017

Grid Operators Manage Solar Eclipse

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.

solar eclipse grid operators RTOs — 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.

grid operators solar eclipse — California Energy Commission Chair Robert Weisenmiller and CAISO CEO Steve Berberich study generation output during the eclipse. | © *RTO Insider*

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.

FERC CAISO uplift intermittent resources — (L-R) CAISO Executive Director of Operations Nancy Traweek, CAISO Vice President of Operations Eric Schmitt, and California Energy Commission Chair Robert Weisenmiller brief reporters at CAISO | © *RTO Insider*

“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.”

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 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 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.

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.

August 22, 2017

Sempra Outmuscles Berkshire for Oncor

By Tom Kleckner

Stepping in where others have failed, San Diego’s Sempra Energy on Monday announced a $9.45 billion cash deal to acquire bankrupt Energy Future Holdings and its 80% interest in Texas utility Oncor.

Sempra’s move short-circuited a looming battle between Berkshire Hathaway Energy and hedge fund Elliott Management, the largest holder of EFH bonds, which had opposed as too low BHE’s $9 billion all-cash offer in July. Elliott said it was working on a competing bid totaling $9.3 billion. (See PUCT Staff Welcomes Buffett’s Oncor Bid; Debtor Miffed.)

Elliott spokesperson Michael O’Looney said the investment fund is “supportive” of Sempra’s proposed transaction, “which provides substantially greater recoveries to all creditors of Energy Future than the proposed Berkshire transaction.”

sempra ferc cftc oncor bankruptcy — Oncor Headquarters | © *RTO Insider*

Including debt, BHE’s bid valued Oncor at $18 billion, while Sempra’s values the utility at $18.8 billion.

Sempra CEO Debra Reed said the acquisition will “enhance our earnings beginning in 2018 and further expand our regulated earnings base, while serving as a platform for future growth in the Texas energy market and U.S. Gulf Coast region.”

Debt and Equity

The company said it expects to fund the transaction using a combination of its own debt and equity, third-party equity, and $3 billion of expected investment-grade debt at the reorganized EFH. Sempra will hold about a 60% equity ownership of EFH and projects the transaction to be completed in the first half of 2018.

BHE, which had said last week it would not increase its $9 billion all-cash offer for Oncor, announced Monday that EFH had terminated its proposed acquisition. Warren Buffet’s company is renowned for its fiscal discipline and avoids bidding wars.

The Nebraska-based company is eligible for a $270 million breakup fee, but it would have to be approved by the court overseeing EFH’s bankruptcy case in Wilmington, Del.

On late Friday, Berkshire said it had reached a settlement agreement resolving “all issues” with Public Utility Commission of Texas staff, the Texas Office of Public Utility Counsel, the Steering Committee of Cities Served by Oncor, Texas Industrial Energy Consumers and International Brotherhood of Electrical Workers Local 69.

Oncor CEO Bob Shapard praised Sempra as a “well-respected and experienced utility operator with a quality workforce and management team.”

“The announcement today is just another example of how our 3,900 employees have made Oncor one of the most sought-after companies in the energy sector today.”

At a previously scheduled bankruptcy court hearing Monday, EFH creditors expressed their support for the Sempra deal. Judge Christopher Sontchi set a Sept. 6 date for an expedited hearing on Sempra’s merger agreement. The deadline for filing objections is Aug. 31.

“This is a big change, clearly a change to the benefit of the estate and the creditors,” said Sontchi, thanking the parties for “freeing up his day.” The judge had scheduled up to eight hours of testimony and arguments on Elliott Management’s opposition to the Berkshire offer.

Oncor is the sixth largest transmission and distribution utility in the nation, serving more than 10 million Texans through more than 122,000 miles of wires and 3.4 million meters. It has been the subject of a tug-of-war since parent EFH, saddled with almost $50 billion in debt after poor bets on energy prices, declared bankruptcy in April 2014.

Dallas’ Hunt Consolidated and Florida-based NextEra Energy had separate bids fall apart in the face of the Texas PUC’s strict ring-fencing measures and demands that Oncor be run by a “truly independent” board with control over decisions on capital expenditures and operating expenses. (See NextEra-Oncor Deal Meets Third Denial.)

PUC Concerns

Although it was rejected by Elliott Management, Berkshire’s offer was received positively by PUC staff.

During the PUC’s open meeting Thursday, Commissioner Ken Anderson restated his insistence that Oncor be protected from incurring any additional debt from EFH’s bankruptcy proceeding. Anderson’s focus is on the billions in debt owed by Oncor stemming from the 2007 leveraged buyout of EFH’s predecessor, TXU.

That debt “was all incurred either in connection with the original [leveraged buyout] or refinancing the 2007 leveraged buyout,” Anderson said. “None of it ever was, nor can it be, an obligation, directly or indirectly, or legally implied of Oncor. None of either the principal or interest can go into rates.”

Anderson alleged that the suitors before BHE intended to use Oncor’s profits to pay off what he viewed as “imprudently incurred debt” by the utility’s holding company.

“The continued existence of any material amount of debt above Oncor will be a concern,” Anderson said. “One of the most important aspects is the cash flow generated out of Oncor must be protected. It needs to be available to Oncor’s management and to Oncor’s board to put it back into the business.”

The debt “is not Oncor’s problem. It is the problem of the commission now, but when the dust settles, I don’t want it to be the problem of either this commission or future commissions.”

Sempra has committed to support Oncor’s plan to invest $7.5 billion of capital over a five-year period to expand and reinforce its existing system.

New CEO

When the transaction is completed, Shapard will become executive chairman of the utility’s board of directors. Allen Nye, currently the utility’s general counsel, will succeed Shapard as CEO. Both have been asked to serve on the board, which will consist of 13 directors, including seven independent directors from Texas, two from existing equity holders and two from the new Sempra-led holding company.

The transaction is subject to customary closing conditions, including the approval of the PUC, FERC, the bankruptcy court and antitrust regulators at the U.S. Justice Department.

“It is important for Oncor to remain financially strong,” Sempra’s Reed said. “Our proposal will help bring a satisfactory resolution to Energy Future’s bankruptcy case, keep Oncor financially strong and protect Oncor customers, while addressing the needs of Texas regulators, creditors and the U.S. bankruptcy court.”

The deal would allow Sempra to regain a foothold in Texas, where it once owned and operated 10 power plants and currently maintains a 200-person office in Houston to support marketing and development activities. A Fortune 500 corporation that includes San Diego Gas & Electric and Southern California Gas, Sempra had 2016 revenues of more than $10 billion.

Sempra’s announcement was not a complete surprise. Word began leaking out last week that a mystery bidder had emerged to take on BHE’s offer. During a bankruptcy hearing Friday, legal counsel for Elliott identified the new competitor for Oncor as “a large investment-grade utility.”

Elliott’s representative also told the court that EFH was considering pursuing talks with the new competitor. EFH’s board met Friday and Sunday before accepting Sempra’s offer.

Rory Sweeney reported from Wilmington, Del.

August 22, 2017

GridLiance Gets OK to Acquire Valley Electric Tx Assets

By Robert Mullin

FERC last week approved GridLiance West’s acquisition of Valley Electric Association’s 230-kV transmission network in a deal valued at about $200 million (EC17-49).

The deal will provide GridLiance with a strategic foothold in an area that bridges the CAISO market with the interior West. (See Valley Electric Board Approves Sale of 230-kV Network to GridLiance.)

The commission also granted GridLiance’s request for incentive rate treatment for operating the network. And while FERC accepted the company’s formula rate template for filing, those rates will be subject to a further evidentiary hearing before a settlement judge to determine the reasonableness of proposed rate inputs, return on equity and income tax allowance (ER17-706).

The decision to approve the transaction came despite objections from some CAISO members who contended that the transaction would result in increased in costs to ISO stakeholders.

GridLiance will be taking over 164 miles of 230-kV lines linking Valley Electric’s base in Pahrump, Nev., with both Las Vegas and the Mead substation — a major delivery point for power wheeled into California — as well as substations along the length of the system. The sale will earn Valley Electric 2.4 times its investment in the system, which significantly increased in value when the cooperative joined the ISO in 2013.

In a filing with FERC, GridLiance said that incorporating its revenue requirement into CAISO’s High Voltage Access Charge will increase that charge by about 0.48%, or $10.8 million. The company attributed the rate bump to the differing business structures of Valley Electric, which is a nonprofit rural electric cooperative, and GridLiance, a for-profit startup that will incur greater costs for overhead, administrative costs and taxes.

GridLiance argued that the increased cost would be offset by the benefit of having the transmission network of a well-funded transmission company that would add competition to the CAISO market and be focused on expansion and enhancement of the ISO transmission system.

The Transmission Agency of Northern California (TANC) contended that, although GridLiance had promised not to recover through rates any acquisition premium paid for the Valley Electric network, the $10.8 million increase in the ISO’s transmission revenue requirement (TRR) constituted such a premium. TANC noted that the increase represented a near doubling of the TRR for the network — without GridLiance having incurred any costs for improvements or modifications. The agency also argued that the transaction would not result in any “quantifiable or non-quantifiable” benefits that would offset the increased costs.

valley electric association ferc gridliance — GridLiance West’s acquisition of Valley Electric Association’s 230-kV will provide the company with strategic access to the CAISO market. | *Valley Electric Association*

Southern California Edison (SCE) contended that the initial revenue requirement included in GridLiance’s proposed formula rate may be “unjust and unreasonable” and possibly included “improper and unsubstantiated costs and expenses.” SCE argued that the commission could not decide about the acquisition without fully vetting the impact of GridLiance’s formula rate filing.

The “Six Cities” utilities of Anaheim, Azusa, Banning, Colton, Pasadena and Riverside raised many of the same concerns, asking why the revenue requirement for the transmission facilities will increase just because of a transfer of ownership.

FERC came down firmly on the side of GridLiance, saying the 0.48% increase in the access charge was “not unexpected” given the company’s capital structure, tax obligations and “need to earn a return.” The commission also determined that GridLiance had presented evidence that increased costs would result in offsetting benefits.

“GridLiance West represents that it intends to develop needed upgrades and important transmission projects that will improve system reliability and increase transmission capacity to meet growing demand for renewable resources, including, and in particular, exports out of the Valley Electric area,” the commission said.

Valley Electric said that it would be unable to perform those necessary upgrades in a timely manner.

“Due to its singular focus on developing and owning transmission facilities, GridLiance West will not face the difficult decisions Valley Electric has faced in allocating its limited financial resources among the various infrastructure development needs within its service territory,” the commission said.

August 22, 2017

GRDA Granted 2-Foot Rise in Reservoir Level

By Tom Kleckner

FERC last week granted Grand River Dam Authority’s (GRDA) request for a permanent 2-foot increase in the reservoir level of the 105-MW Pensacola Project in northeastern Oklahoma, despite opposition from a nearby Native American tribe (Project Nos. 1494-437, 1494-441).

The Miami Tribe charged that FERC had not lived up to its obligations under Section 106 of the National Historic Preservation Act, which requires federal agencies to conduct a review to determine how a proposed project may affect historic properties and to seek ways to avoid, minimize or mitigate any “adverse effects.”

Overhead of Pensacola Dam complex including auxiliary spillways | *courtesy of the U.S. Geological Survey*

The tribe asserted the commission never engaged in a Section 106 review with respect to tribal cultural properties in and around the hydropower project, which includes a 5,950-foot-long, 147-foot-high dam and the 46,500-acre Grand Lake reservoir. The review would have included gathering information from tribes, identifying historic properties of relevance to the tribes and assessing the effects that the project has already had on historic tribal properties.

FERC disagreed, saying the Miami Tribe relied on assertions made by Oklahoma agencies “that have since been revised,” and pointed out that the state agencies did not object to the commission’s finding that the reservoir-level change would not affect historic properties.

Grand River Dam Authority FERC GRDA — | *Grand River Dam Authority*

GRDA, an SPP member, last year requested maintaining the reservoir level at the dam on the Grand River at 743 feet between Aug. 16 and Sept. 15, 2 feet above current levels. It also requested a 742-foot level between Sept. 16 and Oct. 31, 1 foot above current levels. The company proposed returning to the project’s existing surface elevation or “rule curve” for the remainder of the calendar year.

The project’s dedicated flood storage is listed at 745 to 755 feet. When reservoir levels are within the flood pool, the U.S. Army Corp of Engineers can direct releases from the dam.