FERC last week approved a settlement agreement granting five municipalities belonging to Missouri River Energy Services a 9.6% base return on equity, with a 50-basis-point adder for SPP membership (ER15-2324).
The settlement revises SPP’s Tariff, adding formula rates that allow Moorhead, Minn.; Orange City and Sioux Center, Iowa; and Pierre and Watertown, S.D., to recover annual transmission revenue requirements for facilities that moved under the RTO’s functional control.
| MRES
FERC trial staff opposed the settlement, saying its discounted cash flow (DCF) analysis indicated the municipalities should have an 8.42% base ROE. Staff also said the capital structures of four of the five MRES members have abnormally high equity ratios and that hypothetical capital structures should be used for them instead.
Nebraska Public Power District filed comments expressing concern over the ROE but did not oppose certification of the settlement.
FERC approved the settlement despite staff’s concerns because, the commission said, it “reaches compromises on issues other than the ROE and capital structure issues raised by trial staff, and rejecting the settlement because of these components would upset the negotiated agreement reached by the settling parties on many other issues.”
The commission said the base ROE of 9.6% is a rate reduction from what MRES originally proposed and “is consistent” with FERC-approved ROEs in other recent uncontested settlements in the SPP transmission zone.
“Trial staff’s DCF analysis would not go unchallenged by the parties during litigation,” the commission added. “A contested hearing might not produce an ROE appreciably lower than the settlement’s base ROE and could produce one that is even higher. Moreover, the settlement includes a rate moratorium providing customers with rate certainty for the future.”
The RTO was given 30 days to file revised Tariff records.
ERCOT said Monday that conditions remained stable on its system, despite the loss of two 345-kV transmission lines and other major high-voltage outages that cut power to more than 300,000 customers following Hurricane Harvey’s landfall in Texas on Friday night.
Downed power lines | ERCOT
The two 345-kV lines serve the Texas Gulf Coast near Corpus Christi and Victoria, at the center of the storm’s landfall. More than 6,700 MW of generation capacity were offline for storm-related reasons, including a very small volume of renewables.
ERCOT said electricity demand has been about 20,000 MW below normal since Harvey came ashore, peaking at less than 44,000 MW because of structural damage along the coast and cooler temperatures. System restoration times will vary depending on the extent of damage, outage locations and weather conditions, the ISO said.
The ISO issued an emergency notice Friday and brought on extra engineering staff throughout the weekend to support efforts in its Taylor operations center for Harvey, the first Category 4 storm to hit Texas since 1971.
ERCOT spokesperson Robbie Searcy said the day-ahead market cleared on time over the weekend.
Harvey was downgraded to a tropical storm Saturday afternoon, but it has spawned tornadoes and continues to drench much of the Texas Gulf Coast with torrential rains. The downpours are expected to continue well into the week.
Harvey’s after-effects in Corpus Christi | Frances Hale Hall
The number of consumers without power peaked at just more than 300,000 early Saturday afternoon, based on reports from transmission providers in the affected areas. As many as 157 circuits were out of service at one point, with outages heaviest near Corpus Christi and Victoria.
ERCOT said extended outages are likely in most of those areas, and the outage numbers will fluctuate as transmission providers work to restore power.
The ISO has created a special page on its website to provide the latest updates on restoration efforts.
Houston’s two major airports — William P. Hobby and George Bush Intercontinental — were both closed over the weekend. They may be reopened as soon as Wednesday.
The U.S. Coast Guard closed multiple ports along the Texas Gulf Coast, including those at Houston, Galveston, Texas City, Freeport and Corpus Christi.
ERCOT is responsible for about 90% of Texas’ load, including Houston and much of the affected coastal region. MISO is responsible for Southeast Texas, which includes the cities of Beaumont, Port Arthur and The Woodlands.
MISO also manages parts of Arkansas, Louisiana and Mississippi, where the National Weather Service was forecasting as much as 4 inches of rain over the next five days.
MISO South Region Operations Director Tag Short said the RTO was activating its “established protocols” to maintain grid reliability and had additional operators and support staff in place and on call.
Spokesman Mark A. Brown said Sunday night that the MISO transmission grid remained stable, but that the RTO remained in a severe weather alert.
“Our region could still face significant amounts of rainfall and potential flooding,” he said. “We will be carefully monitoring those conditions and will be prepared to take the appropriate steps to maintain the reliability of the transmission grid across the MISO footprint.”
Projected rainfaill totals | NOAA
Entergy Texas reported more than 7,600 customers were without power as of 8:30 a.m. Sunday. “Crews are safely restoring power as quickly as possible, but the storm’s continued wind, rain, flooding and falling trees could make it difficult to access Entergy’s equipment and slow restoration,” the company said. It serves more than 440,000 customers in 27 counties.
The nine states comprising the Regional Greenhouse Gas Initiative have agreed to accelerate reductions in power sector carbon dioxide emissions by lowering the cap-and-trade program’s annual allowances by 30% over 10 years.
The changes to the program, announced Wednesday, also include the addition of an Emissions Containment Reserve (ECR), in which the participating states — Connecticut, Delaware, Maine, Maryland, Massachusetts, New Hampshire, New York, Rhode Island and Vermont — can withhold emission allowances from the quarterly auctions if prices fall below a certain threshold.
“The RGGI states are demonstrating our commitment to a strengthened RGGI program that will utilize innovative new mechanisms to secure significant carbon reductions at a reasonable price on into the next decade, working in concert with our competitive energy markets and reliability goals,” Connecticut Public Utilities Regulatory Authority Chair Katie Dykes, who serves as chair of the RGGI board of directors, said in a statement.
RGGI currently reduces the emissions cap by 2.5% annually, targeting 78.2 million tons in 2020. The changes set the 2021 cap at about 75.1 million tons and reduces it by 2.275 million tons (3%) annually after.
RGGI auction clearing prices fell over the course of 2016, spurring calls for reforms to the cap-and-trade program. | Potomac Economics
Environmentalists and Massachusetts officials last year called for doubling the current rate of reduction, but Maryland Environment Secretary Ben Grumbles balked at the proposal, arguing that the state would be at a disadvantage because its coal-fired power plants must compete in PJM, while most states in the program are in the ISO-NE footprint. (See Md. Balks at Proposed Emission Cuts as RGGI States Ponder Future.)
Grumbles said such an aggressive rate could cause Gov. Larry Hogan to withdraw the state from the program, as New Jersey Gov. Chris Christie did in 2011.
“Maryland is proud of the teamwork among states to achieve consensus for a stronger and broader, balanced and sustainable RGGI,” Grumbles, who serves as the RGGI board secretary and treasurer, said about the agreement.
“Maryland is committed to finding real bipartisan, common sense solutions to protect our environment, combat climate change and improve our air quality,” Hogan said in a statement. “By working together, we are showing that it is possible to find consensus to protect our natural resources, promote clean energy, and grow our economy for current and future generations.”
With the implementation of ECRs starting in 2021, states would be able to withhold up to 10% of their allowances if auction prices fall below $6/ton, with the price trigger rising 7% each year after. The withheld allowances would not be bankable, meaning they could not be resold in a future auction.
Low prices in previous auctions spurred the initial calls for reforms last year, and prices have only continued to fall since. The latest auction, on June 7, saw a $2.53/ton clearing price, a 15% drop from the previous quarter and 44% from a year ago.
RGGI will hold a meeting at the Maryland Public Service Commission in Baltimore on Sept. 25 to solicit public and stakeholder feedback on the changes.
SACRAMENTO, Calif. — Few parties in California are happy with the way the state’s community choice aggregator (CCA) program is turning out, legislators learned during a Wednesday hearing at the state capitol.
In a discussion that at times grew tense, state senators heard how the evolution of California’s CCA program has shifted hundreds of millions of dollars in costs to investor-owned utility customers because of long-term procurement contracts signed by IOUs a decade ago in a radically different energy environment. The result is consternation among ratepayers and elected officials about increased costs — rather than the promised benefits of restructuring — and alarm about resource planning.
The situation “has become a very obvious conflict to people such as myself, and I am sure other legislators have been caught in the crossfire of this debate,” State Sen. Ben Hueso, chairman of the Senate Committee on Energy, Utilities and Communication, said at the opening of the hearing.
The State Legislature authorized the creation of CCAs with the passage AB 117 in 2002, after municipalities in the Los Angeles and San Francisco areas lobbied in response to a failed deregulation effort that in part caused the Western Energy Crisis of 2000/01. The law allows local governments to form CCAs by aggregating retail customers and securing electricity supply contracts to serve them. CCAs are growing rapidly in California and also exist in Ohio, New York, Massachusetts, New Jersey, Rhode Island and Illinois.
California Public Utilities Commission President Michael Picker told the committee that the state’s retail electricity industry is being deregulated once again as it was in the mid-1990s, but this time by technology.
“We are being deregulated from the bottom up, and there is no real plan as to how it fits together,” Picker said. Amid later questioning and discussion, he told the lawmakers, “I am looking to you for direction.”
In an effort to spread the costs of legacy contracts, the IOUs in April proposed that the state adopt a new formula for allocating costs of departing CCA and other retail-choice customers, called the portfolio allocation methodology. (See Utility Proposal Would Increase Legacy Costs for California CCAs.) That approach would replace the current IOU exit fee levied on departing customers, called the power charge indifference adjustment (PCIA), which is meant to address the old contracts. The PUC is taking a look at its deregulation strategy. (See California to Reconsider Retail Choice.)
PG&E Calls for Quick Action
California’s IOUs initially resisted the creation of CCAs by introducing a ballot proposition to make their growth more difficult, but that measure failed. The utilities said they are left holding the bag for long-term procurement decisions made years ago in an industry environment that has changed significantly in terms of rate structures, prices and technology. Those costs are being borne by a dwindling rate base — including low-income customers.
PG&E Senior Vice President Steven Malnight told the committee that the legacy contracts, numbering more than 200 and signed in 2007 and 2008, enabled third-party resource developers to invest billions of dollars in California, create thousands of jobs and help the state to become an economic leader.
The IOUs “see a significant challenge that is in front of us — that needs to be addressed quickly — on cost allocation,” Malnight said. When the contracts were procured, the IOUs were planning to service their customers for up to 20 years.
“The assumption was that those customers would stay in our service territory, and that we would need to serve them,” he said. “Today, we know that reality is significantly different.”
About 30% of PG&E’s customers switched to third-party services, a number that is estimated to rise to 50% by 2020. PG&E procured energy on behalf of those customers and now must reallocate costs through the PCIA. Under that methodology, departing customers are assuming only about 65% of the costs that should be allocated to them. The remaining costs are being paid not by utility shareholders but by remaining IOU customers, many of them in areas without a CCA option, he said.
About $180 million has been shifted from CCA customers to IOU customers, he said, which will grow to $500 million by 2020. “I know in California that we do think big — but that is a lot of money,” Malnight said. Long-term contracts are often needed to provide resources to deal with renewable integration and protect grid reliability, and IOUs are generally over-procured and have limited options for solving that problem.
“We can’t arbitrarily walk away from that contract, [and] turn it over to a CCA or anybody else,” he said.
California Coalition of Utility Employees counsel Marc Joseph told the committee that in 2007, IOUs were facing renewable mandates when their cost was much higher and the industry and its technologies were young. It was a seller’s market, but CCAs now function in a “buyer’s market.”
IOUs could be paying back those contracts for decades, and the PCIA does not work to make IOU customers “indifferent” to the creation of CCAs. But CCAs are basing their current economic decisions on the current structure of the PCIA program, he said.
“It is easy to see the train wreck that will come,” he said, telling the legislators CCAs “will come running to you to bail them out.” He urged a slowdown in the CCA program while the PUC examines the PCIA issue, he said. Many new renewable developers are ready to build, but the result is no customers because IOUs are over-procured. As a result, in California “we have had a crash in the construction of new renewable projects” after healthy growth in 2016 at a time when large federal subsidies are available.
Contract Holders Expect to Get Paid
Independent Energy Producers Association CEO Jan Smutny-Jones told the committee that the group’s members built a lot of the renewable projects in California and also do some business with CCAs, as well as holding the IOU contracts.
“We expect those contracts to be honored,” he said, adding that “we are not really interested when someone else says something else should happen with those contracts.” They are private contracts subject to contract law and out of the jurisdiction of the PUC, he noted.
“This is a big issue. This state has a very good history of honoring contracts with my member companies. … We need to keep that up,” Smutny-Jones said. Not honoring the contracts would send a strong negative signal to companies considering investing in California.
Bradford Questions CCA Fairness
Sen. Steven Bradford, who represents parts of Los Angeles County, said that CCAs can “pick and choose” which customers they serve. That assertion drew disagreement from Sonoma Clean Power CEO Geof Syphers, but Bradford insisted that “you can — that’s why you are in Marin, that’s why you are in Sonoma.”
IOUs have an obligation to serve customers, and “you wanted to be everything a utility is, other than report to the PUC,” Bradford said. As a State Assembly member in 2014, Bradford introduced legislation that was viewed as anti-CCA. It would have put default provider status back to the IOU rather than the CCA, but the bill was defeated after opposition from CCA supporters that argued that CCAs shouldn’t be subjected to the same oversight as IOUs.
At its conclusion, Hueso said the hearing had been “enlightening” and that he was concerned about creating an ungovernable system. The committee plans to hold more discussions on the future of CCAs.
“Nobody talked about a collapse of our system, but there were a lot of comments that alluded to that,” Hueso said.
The U.S. Energy Department grid study released Wednesday added no new information to debates that have been going on for months at FERC technical conferences and RTO/ISO stakeholder meetings.
The report also acknowledged that the department has virtually no authority over generation or wholesale markets, leaving it to FERC and RTOs to act on its recommendations. (See Perry Grid Study Seeks to Aid Coal, Nuclear Generation.)
On Thursday, FERC and several RTOs responded. Their message: We’re already working on it.
Acting FERC Chairman Neil Chatterjee issued a statement saying the report “highlights many activities that the commission is carefully considering, including examining ways to enhance wholesale electric capacity markets and improve price formation in those markets, to increase electric and gas coordination, and to assure bulk power system reliability and resilience. The commission will remain focused on these and other issues that are critical to maintain the nation’s competitive wholesale electric markets and keep the lights on.”
PJM, ISO-NE, MISO, CAISO and SPP also issued statements assuring DOE that they are addressing the issues and that — despite the ominous warning Secretary Rick Perry used in his April 14 memo ordering the study — that there are no imminent risks to grid reliability.
Price Formation
Among the report’s recommendations were a call for FERC to “expedite its efforts with states, RTO/ISOs and other stakeholders to improve energy price formation in centrally organized wholesale electricity markets.”
| PJM
“After several years of fact finding and technical conferences, the record now supports energy price formation reform, such as the proposals laid out by PJM and others,” it said, citing PJM’s June report, “Energy Price Formation and Valuing Flexibility,” and MISO’s extended LMP initiative. (See PJM Making Moves to Preserve Market Integrity.)
The report says that although all RTOs/ISOs have some type of shortage pricing, the designs differ, a “variance [that] could present challenges to market participants who require a threshold level of certainty to make an investment decision.” Although it acknowledged that FERC Order 831 doubled energy offer caps in the organized markets to $2,000/MWh, it cited concerns expressed by Market Monitors Joe Bowring and David Patton over the volatility of shortage pricing revenue. (See Lawyers Take an Economics Class: Capacity Markets vs. Scarcity Pricing.)
| Energy Information Administration, based on Intercontinental Exchange (ICE) prices as reported by Ventyx, February 23, 2012
It also called for mitigating negative prices “to the broadest extent possible,” quoting from the department’s January Quadrennial Energy Review report that “price suppression is occurring in RTO/ISO wholesale markets with noticeable amounts of wind and solar generation (and low-cost gas generation).”
Essential Reliability Services
The department also urged FERC to require valuation of “essential reliability services” through fuel- and technology-neutral markets or regulatory mechanisms. The report includes in that description ancillary services such as frequency and voltage support, and ramping capability.
| Department of Energy, Staff Report to the Secretary on Electricity Markets and Reliability, August 23, 2017
A table in the report shows that only MISO and CAISO have any product in the “ramp reserve” category. SPP’s David Kelley said the RTO is evaluating the benefits of a ramping product for the Integrated Marketplace and is exploring designs deployed in other markets. It has no current timeline for implementation.
Resilience
The report also called for further study on mandatory capacity markets, which it noted have “been the subject of near-constant debate” and the development of metrics and tools for evaluating “resilience.”
The department said NERC “should consider adding resilience components to its mission statement and develop a program to work with its member utilities to broaden their use of emerging ways to better incorporate resilience.”
“RTOs and ISOs should further define criteria for resilience, identify how to include resilience in business practices and examine resilience-related impacts of their resource mix,” it continued.
The report acknowledged that while wholesale markets “do not explicitly recognize or compensate system resilience,” PJM and ISO-NE have changed their capacity market rules to incentivize generator performance during scarcity conditions. It notes that only some RTOs — naming PJM, ISO-NE and NYISO — value onsite fuel storage, a characteristic of coal and nuclear plants that natural gas plants without oil-fired back-up lack.
Quoting PJM, the report notes that “criteria for resilience are not explicitly defined or quantified today.”
“Each RTO/ISO should strive to explicitly define resilience on its system and conduct resource diversity assessments to more fully understand the resilience of different resource portfolios,” the department said. “Federal, state and local work to define and support systemwide resilience is also needed.”
NERC issued a statement saying that reliability and resiliency “are key priorities for NERC and we appreciate the recognition of our work on these matters.”
ISO-NE
ISO-NE spokeswoman Marcia Blomberg said the RTO is reviewing the study. “However, in the two decades since their creation, competitive wholesale electricity markets in New England have achieved what they were designed to accomplish, including power system reliability supported by an adequate resource base, competitive wholesale power prices that accurately reflect the cost of reliable power production and a shift in resource investment risk from ratepayers to investors.
“As the energy landscape evolves, ISO New England will continue working with industry stakeholders and state policymakers to ensure that the markets can adapt to changing industry dynamics, such as state environmental policies and fuel security challenges, while continuing to produce competitive prices that support the resources needed to reliably meet consumer demand for power.”
PJM
PJM called the report “thoughtful” and “comprehensive.”
“The report acknowledges that wholesale power markets are working and providing reliability at the lowest possible cost and that power supply resources are more diverse than they have ever been. It also highlights the importance of expediently addressing needed reforms in energy price formation followed by a focus on grid resilience. These issues are a top priority.”
The RTO noted that it has posted discussion papers on price formation and capacity market reform to accommodate state policies. “Earlier this year, we published a paper, ‘PJM’s Evolving Resource Mix and System Reliability,’ which demonstrated that the PJM region has remained reliable throughout the rapid changes in the resource mix. PJM’s analysis also indicated a need to focus on fuel assurance and resilience to take into account the changing operational risks that the industry faces.” (See PJM: Increased Gas Won’t Hurt Reliability, Too Much Solar Will.)
CAISO
CAISO said it has “experienced success in integrating large amounts of renewable resources without threatening grid reliability. There’s no doubt that energy markets are evolving as the fundamental resource mix changes. The ISO will continue to operate a reliable grid that can capture the benefits of this transformation.”
MISO
MISO said it “has been preparing for the challenges of the evolving resource mix, and we will continue to ensure that planning constructs, market designs and operational practices are in place to support the reliability of the electric grid across our footprint. We look forward to continuing our work with DOE, regulators, policymakers and stakeholders as that effort continues.”
SPP
SPP spokesman Derek Wingfield said the RTO “is pleased the report acknowledges the value of transmission investments in enabling ‘an array of benefits’ including reliability, congestion relief, market competition, diversity of fuel sources and more, and that our own Value of Transmission study had some influence on the Department of Energy’s analysis. The report’s recommendation to further study market structures and the impacts of renewable integration is also welcome, and we pledge to assist the DOE and FERC with such analyses should the opportunity arise.” (See SPP Begins Promotional Campaign to Tout Transmission Value.)
Last month, SPP stakeholders approved recommendations from a study on how much wind energy the RTO’s system can safely and reliably absorb. The RTO has routinely broken the 50% penetration level for wind energy, and has said it can go even higher. The recommendations include the installation of online transient-stability and voltage-stability analysis tools. (See “Wind Integration Study’s Recommendations Move On,” SPP Markets and Operations Policy Committee Briefs: July 11-12, 2017.)
ERCOT
ERCOT, which is not subject to FERC jurisdiction, held a discussion with the Texas Public Utility Commission on Aug. 11 on price-formation issues including scarcity pricing and marginal losses. (See ERCOT, Regulators Discuss Need for Pricing Rule Changes.)
ERCOT has also successfully integrated renewables at 50% penetration levels.
NYISO officials had no immediate comment, saying they were digesting the report.
CARMEL, Ind. — While MISO officials were unsurprised that the Aug. 21 solar eclipse did not impact Midwestern grid operations, they do say an increase in solar capacity will complicate matters by the next total eclipse in 2024.
MISO Communications Director Jay Hermacinski on Tuesday said the RTO will study eclipse impacts over the next few weeks and request data from CAISO, a grid operator that was “truly” impacted by the eclipse. (See Grid Operators Manage Solar Eclipse.)
MISO’s US footprint outlined in green | GreatAmericanEclipse.com
All of MISO’s footprint fell within the 80 to 100% eclipse band, and Hermacinski said the footprint’s solar generation reacted “as predicted.” Grid-scale solar output dropped 100 MW during the eclipse, plunging to a nearly zero output during the peak and picking back up to about 40 MW around 3 p.m.
| MISO
Hermacinski said that MISO operators had no problem meeting demand with stifled solar output.
“Our portfolio looked like it always does. We did not have to do anything special or bring on additional generation,” he said during an Aug. 22 Informational Forum. “Quite frankly, our operators prepared for the solar eclipse as if it were any other day. … We did not expect the eclipse to have an impact on our grid operations, and it did not.”
However, storms in the Upper Midwest and cooler-than-expected systemwide temperatures that day cut load, and MISO load dropped by 2 GW during the eclipse window.
“What we didn’t expect was the number of pop-up storms in the MISO region that brought about a 5- to 8-degree drop in temperature,” Hermacinski said.
MISO will use CAISO’s data to complement its own to help prepare for the next solar eclipse in April 2024, which will cut a path of totality from southwest Mexico to the northeastern U.S., putting the RTO’s Carmel, Ind., headquarters in the direct path. By that time, MISO is expected to have an additional 13.5 GW of grid-connected solar generation participating in its market, an amount exceeding that participating in the CAISO market today. MISO currently has about 180 MW of utility-scale solar and 350 MW of distributed solar in its footprint.
“MISO will be in a much different position in 2024 in terms of solar capacity than it is today,” Hermacinski said. A partial solar eclipse occurring in October 2023 will serve as a practice run before the 2024 event, he added.
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.
