A group representing MISO power producers filed a complaint with FERC on Monday alleging that the RTO is improperly accounting for the deliverability of some capacity resources, driving down payments to those demonstrably positioned to deliver on their obligations.
The Coalition of Midwest Power Producers (COMPP) urged FERC to force MISO to properly account for deliverability of capacity resources before the annual capacity auction in April in order to safeguard reliability (EL19-28).
MISO control room | MISO
COMPP said MISO’s loss-of-load expectation (LOLE) study process is flawed because it assumes that all capacity resources are fully deliverable on an installed capacity (ICAP) basis. However, the group argued, MISO’s megawatt count from deliverable resources comes up short annually because the RTO allows certain resources to demonstrate deliverability only up to the unforced capacity (UCAP) level.
MISO’s Tariff requires capacity resources to demonstrate either network resource interconnection service (NRIS) or energy resource interconnection service (ERIS) coupled with firm transmission service up to each resource’s ICAP level. While the RTO already requires that all resources be deliverable to load to qualify as capacity resources, its deliverability requirements stipulate that ERIS resources must only secure firm transmission for their UCAP values, which tend to be about 5 to 10% below full ICAP levels.
The discrepancy amounts to a Tariff violation and risks MISO’s adherence to its own planning reserve margin, COMPP said.
“By failing to ensure deliverability on an ICAP basis for all capacity resources, MISO is acting contrary to the assumptions of its LOLE study and failing to procure enough fully deliverable resources needed to meet its [planning reserve margin] as its Tariff requires,” COMPP said.
“The seriousness of this issue is evident in the historically low reserve margins that MISO is experiencing,” COMPP said. “Requiring compliance with the Tariff for the upcoming [Planning Resource Auction] is essential both to maintaining reliability and to ensuring rates are just and reasonable and not unduly discriminatory. Yet, despite the gravity of the situation, the RTO is proceeding in a manner that will continue to improperly count approximately 1,400 MW of undeliverable generation toward satisfying its reliability requirement.”
MISO’s Independent Market Monitor last year also advised the RTO to require a planning resource’s ICAP be deliverable over the network regardless of which interconnection service it uses. (See MISO Concurs with Monitor Ideas, Pledges More Study.) The Monitor found it problematic that MISO’s LOLE study assumes all ICAP megawatts are deliverable when they’re not.
It later pointed out that during past PRAs, as much as 1,400 MW in capacity may not have been capable of delivering to load. At the time, MISO said it would work on rule changes in time for the 2020/21 PRA.
For COMPP, those changes won’t come soon enough. The group pointed out the problem is poised to recur in the upcoming 2019/20 PRA “despite the IMM having recommended that MISO fix it for the past two auctions.” It also maintains that swings even smaller than 1,400 MW “can lead to material differences in the clearing price that fails to send accurate price signals for entry and exit.”
COMPP said that despite MISO’s apparent agreement with the Monitor, it contended that the RTO has designated the issue a low priority by “only targeting to correct its failure” for the 2020/21 PRA.
“Leaving this problem unaddressed for another day fails to abide with [Federal Power Act Section] 206’s requirements and should be deemed unacceptable by the commission. … The lack of urgency on this issue is particularly galling given MISO’s focus on dealing with current reliability issues that have resulted in some 19 emergency actions since the start of the 2016/2017 planning year,” COMPP said.
The organization also requested fast-track treatment from FERC.
MISO said it was in the process of reviewing the complaint.
ERCOT enters 2019 with a major coal plant going into mothballs and two aging gas units set for decommissioning.
After burning the last load of coal at its J.T. Deely plant on New Year’s Eve, San Antonio utility CPS Energy is now in the process of mothballing the two units, which date back to 1977 and 1978.
CPS Energy’s J.T. Deely plant | CPS Energy
The municipal utility in 2011 said it would retire Deely by the end of 2018, 15 years ahead of schedule, thus avoiding millions in environmental retrofit costs. It notified ERCOT of its plans to mothball the plant in 2013, but it must submit a notification of change of generation resource designation (NCGRD) before officially retiring and decommissioning the units.
CPS spokesperson Trace Levos said the utility plans to begin razing the plant in 2025, but utility officials are also pondering converting Deely into a gas-fired plant.
ERCOT spokesperson Leslie Sopko said the grid operator will not have to conduct another reliability-must-run study whenever CPS is ready to retire the units, as the ISO already considers the units to be unavailable.
Deely’s two coal units have a combined capacity of 871 MW. Along with Luminant’s shuttering of three coals plants in late 2017, ERCOT will have seen slightly more than 5 GW of coal-fired capacity shut down over a year. (See ERCOT OKs Luminant Coal Retirements.)
The Texas grid operator survived record-breaking demand last summer without resorting to emergency measures. It is expected to enter this summer with a historically low reserve margin of 8.1%, almost three points lower than last year. (See ERCOT Faces Tight Summer Margins, Market Changes.)
Meanwhile, NRG Texas on Dec. 28 submitted an NCGRD to ERCOT, saying it intends to decommission and permanently retire two previously mothballed gas units at its SR Bertron plant near Houston, effective Jan. 23.
The Eisenhower-era units each have a capacity of 230 MW. They were shut down for economic reasons in 2011.
State utility regulators in MISO and PJM have voiced concerns that FERC’s proposed changes to transmission rate-setting could drive up costs while hampering development of more efficient non-transmission alternatives.
| MISO
In separate letters last month, the Organization of MISO States and the Organization of PJM States Inc. urged the commission to examine whether current return on equity incentives on top of a new base ROE will result in excessive customer costs.
FERC in October signaled it will allow changes to how transmission owners set ROE rates, no longer relying solely on the discounted cash flow (DCF) model it has used for about four decades. Instead, it will rely equally on results from the DCF and three other techniques: the capital asset pricing model, the expected earnings model and the risk premium model. (See FERC Changing ROE Rules; Higher Rates Likely.)
The changes come in response to a D.C. Circuit Court of Appeals 2017 ruling vacating Opinion 531, FERC’s 2014 order on New England TOs’ ROE rates. The new policy would evaluate and incorporate industry-wide risk into ROE estimates — and likely raise rates.
In its Dec. 19 letter, OMS urged the commission to “balance the authorization of sufficient rates of return to encourage the investment on needed transmission against concerns about excessive costs to customers.”
ROE incentives on top of the base ROE should be “targeted and exceptional,” OMS wrote in the letter, signed by board President Ted Thomas, chairman of the Arkansas Public Service Commission.
“Supporters have concerns that at least some incentive adders have become overly generous and do not change or incent the intended behavior on the part of the transmission owners, resulting in excessive costs to customers. Ineffective adders may also be an unintended disincentive to development of non-transmission alternative solutions for reliability and congestion concerns,” OMS said.
Following OMS’s letter, OPSI on Dec. 28 also cautioned the commission that ROE incentives may become too generous under the new ROE. The organization said FERC should be careful to craft ROE incentives that are “truly merited.”
“OPSI has concerns that at least some incentive adders have become overly generous and do not change or incent the intended behavior on the part of the transmission owners, resulting in excessive costs to customers. Such adders may also be an unintended disincentive to development of non-transmission alternative solutions for reliability and congestion concerns,” the organization said.
RTO Adder ‘Questionable’
Both organizations singled out FERC’s 50-basis point adder incentive for RTO participation. OMS said the adder is of “particular concern and warrants scrutiny by FERC,” noting it’s worried the adder “will last in perpetuity.”
“[T]he landscape has changed drastically since 2006 when these adders were first initiated. After more than 15 years of experience with RTOs, the resulting benefits to utility members are now better understood. RTOs are no longer a new policy experiment. Moreover, transmission owners may no longer need an additional incentive adder to simply join an RTO,” OMS said.
OMS also pointed out that FERC over the years has provided other regulatory mechanisms such as formula rates, projected revenue requirements — trued up to reflect under-recovery — abandoned plant and construction work in progress, “all of which reduce transmission owners’ risk.” The group said the mechanisms “should be carefully examined in the context of this and other ROE incentives.”
OPSI called the RTO adder “questionable” since the benefits of RTO participation are now well understood.
OPSI recommended FERC open a notice of inquiry on the ROE issues “for the purpose of examining not only policy around the application of new incentive requests, but also the ability of existing incentives to achieve desired outcomes.”
OMS likewise requested a review of ROE incentive policy “to ensure that customers pay no more than is necessary to develop and to maintain a reliable and efficient transmission grid.”
OMS has previously expressed concern about whether it would be able to contribute its views to the New England ROE docket.
“You have these pretty impactful policy discussions taking place … and it’s not a docket that we are party to,” former OMS Executive Director Tanya Paslawski said during the organization’s Oct. 29 annual meeting.
FERC has approved PJM’s proposal to change how it measures seasonal demand response resources, rejecting a protest by the RTO’s Independent Market Monitor.
PJM currently permits curtailment service providers (CSPs) to combine DR resources within the same transmission zone into a single DR registration, with the capacity value based on the lower of its total summer- or winter-period reduction capability.
Under the changes approved by the commission Dec. 31, resources above 100 kW will be registered individually, with separate summer and winter capacity values (ER19-244).
PJM said the change will give it greater flexibility by allowing dispatch of individual DR resources. It will also aid CSPs, who will no longer have to determine which end-use customers should be aggregated on a DR registration to maximize the nominated value, PJM said.
The change will be effective with delivery year 2019/20, beginning June 1.
Under PJM’s old process (left), customers 3 and 4 would be combined in a single demand response registration with an annual value of 3 MW, the lesser of the combined summer and winter values. Under the new process (right), the two customers would have separate registrations with a combined 3 MW in summer and 4 MW in winter. | PJM
The IMM protested the proposed change, saying that it will overstate the capacity value of DR, displacing other resources, and that allowing more intra-zonal matching will erode locational price signals.
The commission disagreed, saying the changes should result in more accurate DR capacity values.
It also noted that CSPs are already permitted to aggregate end-use customers in a single transmission zone within a registration and satisfy a DR capacity commitment with multiple registrations. “The proposed revisions do not modify either of these permissions, and we find no evidence in the record to suggest that the instant changes will erode locational price signals,” the commission said.
The Monitor also objected to how PJM proposed to estimate load reductions for some resources, saying all should be required to have five-minute interval metering.
The commission said PJM’s use of “flat profiling” for DR that lack five-minute metering can “reasonably reflect” DRs’ performance during emergencies.
“In multiple orders, the commission has declined to require demand resources to upgrade to five-minute metering,” the commission said, adding that such technology is not necessary because of RTOs’ ability to create five-minute load and generation profiles using telemetry and hourly revenue-quality data.
The chairman’s health had become the subject of increasing speculation since a fall that left him visibly uncomfortable at the commission’s July open meeting.
Change in Appearance
McIntyre seemed healthy when he and fellow nominee Richard Glick testified at their Senate confirmation hearing in September 2017, but he had a shaved head when he was sworn in as chairman three months later.
Last March — as E&E News was about to publish a story detailing his cancer diagnosis — McIntyre explained his appearance, issuing a statement saying he had undergone “successful surgery” for a “relatively small” brain tumor discovered unexpectedly in summer 2017.
“I was advised … that, with the surgery and subsequent treatment behind me, I should expect to be able to maintain my usual active lifestyle, including working full time, and that expectation has proven to be accurate,” he said then.
He appeared healthy in May, when he was the keynote speaker at the Energy Bar Association’s annual meeting. (See “McIntyre Recalls First Day at FERC,” Overheard at EBA Annual Meeting.)
At the July open meeting, however, he wore a sling and appeared uncomfortable after disclosing he had injured his arm and suffered compression fractures in two of his vertebrae in a fall. It was the last meeting he would attend and one of his last public appearances.
In September, Commissioner Neil Chatterjee began FERC’s open meeting by reading a statement in which McIntyre apologized for his absence, saying his “ongoing recovery” prevented him from attending.
At the October meeting, Chatterjee said simply: “Chairman McIntyre is not here. My prayers are with him and his family.”
A week later, McIntyre issued a statement saying he would remain on the commission but would relinquish the chair’s role “and its additional duties so that I can commit myself fully to my work as commissioner, while undergoing the treatment necessary to address my health issues.” However, he did not participate in any orders following his statement.
In their opening remarks at FERC’s last meeting Dec. 20, the commissioners wished McIntyre and his family well for the holidays. But unlike at earlier meetings, none of them offered hopes of him returning to work.
Accomplishments
Before relinquishing the chairmanship, McIntyre and the commission approved major orders on energy storage, generator interconnections and transmission rates, and opened an inquiry on gas pipeline licensing. Last January, he led a 5-0 vote rejecting the Department of Energy’s proposed bailout of coal and nuclear generation, instituting a new resilience docket. (See Ailing Chair, Resilience Inquiry Topped FERC News in 2018.)
McIntyre joined FERC after two decades at Jones Day, where he represented energy clients in administrative and appellate litigation, compliance and enforcement matters, and corporate transactions. A graduate of San Diego State University and Georgetown University Law School, he was co-leader of Jones Day’s global energy practice.
He is survived by his wife of 10 years, Jennifer Brosnahan McIntyre, chief counsel for Boeing Defense’s Autonomous Systems unit, and three children, Lizzie, Tommy and Annie. McIntyre’s mother, Alice L. McIntyre, was a retired pastoral counselor, and his father, John R. McIntyre Jr., was a retired Air Force colonel.
McIntyre’s widow released a statement through FERC thanking “the entire FERC family for their hard work every day for the American people and for their faithful support of Kevin during his time at the commission, especially in the last few months.”
“Kevin often said that being chairman of FERC was his ‘dream job’ — he truly loved and believed in the agency, its mission and its people,” she said. “He was always energized by the challenge of leading the agency ‘full steam ahead,’ even when his health faltered. His commitment to his duty, and his faith in the FERC team, never wavered. We will always be grateful for the opportunity, however brief, that Kevin had to serve our country as FERC chairman.”
FERC Chief Administrative Law Judge Carmen A. Citron swears in Kevin McIntyre as his wife, Jennifer Brosnahan McIntyre, looks on. | FERC
Condolences
“Today is a deeply sad day for the Federal Energy Regulatory Commission and for all those who had the pleasure of knowing Kevin McIntyre both personally and professionally,” Chatterjee, who replaced McIntyre as chairman, said in a statement. “During his tenure at the commission, Kevin exhibited strong leadership and an unmatched knowledge of energy policy and the rule of law. He exemplified what it means to be a true public servant each and every day, no matter the challenges that lie ahead of him.
“In the face of adversity, Kevin’s dedicated faith, devotion to family and sharp wit never faltered. His unwavering strength was — and will continue to be — an inspiration to us all. I will miss the wise guidance of my colleague, the dear camaraderie of my good friend and the frequent banter with my fellow sports fanatic, Kevin.”
Commissioner Cheryl LaFleur said the commission “was very fortunate to have Kevin McIntyre at the helm for as long as he was, and I was honored to serve with him. I particularly appreciated his keen legal judgment, unstinting commitment to the rule of law and deep concern for the organization even in the face of his personal struggles. On a personal level, I appreciated his warm collegiality and ready Irish wit, and was frequently charmed by his Catholic school vocabulary.”
Glick said he got to know McIntyre during the confirmation process. “It did not take long to recognize that Kevin was a man of great intellect and principle. He brought both qualities to the Federal Energy Regulatory Commission where, as chair, he guided the commission to bipartisan consensus during a particularly tumultuous time,” Glick said. “But there was much more to Kevin than being a FERC chairman. He was extremely kind and witty. I most enjoyed our conversations about our respective lives. Kevin often spoke glowingly about his wife, Jenny, and their three wonderful children … and never failed to inquire about my family.”
Sen. Lisa Murkowski (R-Alaska), chair of the Energy and Natural Resources Committee, also expressed condolences for McIntyre. “As a lawyer, a commissioner and as FERC’s chairman, he always had the utmost respect for the agency and its mission. He was as warm and engaging as he was knowledgeable about the issues that came before him.”
Rep. Greg Walden (R-Ore.), ranking member of the House Energy and Commerce Committee, said McIntyre’s “expansive knowledge and expertise of energy law was a tremendous asset to the commission’s important responsibilities and helped shape U.S. energy policy for years to come.”
John Moore, director of the Natural Resources Defense Council’s Sustainable FERC Project, said McIntyre “led FERC with a steady hand and with an emphasis on preserving open electricity markets and maintaining the independence of the commission. We especially salute his high civic calling.
“As we look to the future, we urge Congress, the administration and the commission itself to preserve both the spirit and letter of fairness and evenhandedness that marked Chairman McIntyre’s tenure,” he added.
“He was smart and kind, and I was glad to have met him, even briefly,” said Katherine Hamilton, former president of the GridWise Alliance.
Successor to be Named
McIntyre’s term would have expired on June 30, 2023. His death leaves FERC with two Democratic and two Republican commissioners, including Bernard McNamee, who joined the commission Dec. 11 but has not yet begun voting on orders.
Once McNamee begins to vote, analysts at ClearView Energy Partners noted Thursday, FERC could face 2-2 deadlocks on votes on “LNG terminals and natural gas pipelines, and potentially on orders that impact the fuel mix of the electric generation sector.”
“It is not clear yet whether Senate Minority Leader Chuck Schumer (D-N.Y.) will try to press [Majority Leader Mitch] McConnell [R-Ky.] and/or the White House to either renominate Cheryl LaFleur — whose term expires on June 30 — or nominate a different Democrat to FERC at the same time as a replacement for McIntyre,” the analysts said. “While conventional wisdom would suggest that pairing a Republican and Democrat (given LaFleur’s expiring term) could smooth the confirmation process, the reality that a simple majority suffices to confirm nominees likely makes this prior custom far less relevant.”
Environmental and public policy advocates last week challenged the Department of Energy’s proposed procedures for designating critical electric infrastructure information (CEII), saying it denies due process and could be a Trojan horse for the department’s efforts to subsidize coal and nuclear generation.
DOE announced its proposed procedures Oct. 29 under the 2015 Fixing America’s Surface Transportation (FAST) Act, which gave both FERC and the secretary of energy authority to designate information as CEII and thus exempt from disclosure.
Decision Tree for Making CEII Determinations on Dam Safety Documents | FERC
Among those weighing in in support of the rule before the comment period closed last week were the Edison Electric Institute, which said the rules would help encourage “information sharing frameworks” between government and private industry that are essential for responding to cyberthreats. PJM also filed in support.
But Earthjustice, the Union of Concerned Scientists, and Public Citizen filed joint comments opposing the rule, calling it “a breathtaking” overreach of the department’s authority that “would inappropriately broaden the department’s authority to restrict access to information critical for informed debate on issues important to the public.”
The groups said although the FAST Act gives both FERC and DOE authority to designate information as CEII, only FERC has authority to set the “criteria and procedures” for doing so. FERC, which issued its procedures in 2016, rejected a rehearing request on its order in May. (See FERC Clarifies CEII Rules, Denies Rehearing.)
DOE proposed that industry and other stakeholders could request information they submit to DOE be “pre-designated” as CEII and remain so on an “interim” basis pending DOE review, preventing disclosure under the Freedom of Information Act (FOIA).
“Information that is pre-designated or provided interim treatment would be handled like CEII indefinitely; the department commits only to ‘endeavor to make a determination as soon as practicable’ regarding its actual status as CEII,” the groups said. “… The proposed rule would functionally shift the role of designating CEII from the department to industry stakeholders, as the assertions of entities submitting the information provides the basis for treatment as CEII indefinitely.”
The rule is unnecessary, the groups said, because FOIA rules and FERC’s CEII procedures already allow for review of sensitive information before its release.
Tyson Slocum, director of Public Citizen’s Energy Program, said the rule would give DOE the “foundation” to seek coal and nuclear bailouts on national security grounds. “Right now, DOE lacks a process by which it can designate infrastructure on national security or national defense grounds,” Slocum said in an email. “This rule would provide that authority.”
In June, a leaked “pre-decisional” memo proposed that DOE require RTOs and ISOs to purchase energy or capacity from “fuel-secure” generators at risk of retirement for 24 months while the department identifies “Critical Defense Facilities” served by “Defense Critical Electric Infrastructure (DCEI).” (See Trump Orders Coal, Nuke Bailout, Citing National Security.)
In October, numerous press reports indicated that the White House had rejected DOE’s proposal following opposition from the National Security Council and National Economic Council. But there has been no official word on the plan’s demise. (See Chatterjee Dodges as DOE Spins on Coal Bailout.)
“Should the DOE be granted the authority it seeks in this proposed rulemaking, then the agency can designate as secret the methodology used to determine that certain infrastructure is critical for defense or national security,” Slocum said. “Once it has made that designation, the agency could then justify multi-billion-dollar bailouts to the owners of such facilities, and groups like Public Citizen would be unable to challenge it, since the underlying justification would now be classified. Therefore, stopping this rule is central to stopping the Trump administration’s coal and nuclear bailout.”
‘Much Care’
In contrast, EEI said it generally supports the proposal. “It is clear that much care and thought went into the preparation of the proposed rule, and the tone set demonstrates the department’s commitment to promoting public/private sector information sharing,” EEI said. “EEI supports this commitment because public and private sector entities must partner to protect the nation’s critical electric infrastructure and public/private information sharing is a crucial element to achieving that goal.”
However, EEI said DOE should specify deadlines for acting on CEII requests and ensure all DOE offices, FERC, the Department of Homeland Security and Nuclear Regulatory Commission use consistent criteria in making designations.
PJM also supported the proposal and said it should be amended to include penalties for willful disclosures of sensitive information.
“The final rule should ensure that disclosure of this information is subject to a DOE review of the requester’s actual ‘need to know’ this highly sensitive information,” PJM said. “Too often in the past, CEII disclosure rules have been written by [FERC] and other agencies to establish procedures with a going-in assumption of implementing the requester’s right to know the critical information in question.”
Having survived record temperatures despite slim reserve margins last summer, ERCOT is preparing to take on the Texas heat again in 2019 with reserve margins that have shrunk even further.
The grid operator said in December that canceled gas projects, other delayed projects and increasing demand from oil and gas production had reduced its reserve margin to a historic low of 8.1%. (See ERCOT Predicts Tight Reserve Margin for 2019.)
ERCOT said it will have more than 78 GW of operational capacity — 600 MW more than expected last May — available this summer to meet projected demand of 74.9 GW. ERCOT had an 11% reserve margin last summer, when it met a record peak of 73.5 GW and 13 other demand intervals above the previous high without resorting to emergency actions.
The reserve margin is expected to grow to 12.2% in 2021, within reach of ERCOT’s target planning margin of 13.75%. It is then expected to fall to 7.5% in 2023, when available capacity is projected to flatten, while industrial load growth continues to scale up.
ERCOT faces historically low reserve margins next year in the face of expected increases in demand. | ERCOT
But no worries, says ERCOT. “What we’re encountering now is nothing new,” Pete Warnken, the grid operator’s manager of resource adequacy, said in December.
Texas Public Utility Commission Chair DeAnn Walker has called the 8.1% reserve margin “very scary.” Yet, given a chance to discuss market changes to ensure continued reliability, the PUC in December twice declined to take up the issue during its open meetings. Staff say the commissioners want more time to study stakeholder input, consultant studies and other recommendations, and that they want to “get it right.”
ERCOT’s energy-only market was supposed to incent new generation. Rather than finance new plants on the backs of the ratepayers, the Texas model shifts the risk to investors who might benefit from high power prices.
However, ERCOT’s wholesale prices are among the lowest in the nation, hovering around $25/MWh the last few years. Uneconomic coal-fired plants — like Luminant’s three last year — have closed down or will close down. CPS Energy’s announced shutdown of J.T. Deely at the end of 2018 means almost 5 GW of coal generation have been taken out of the market in the last two years.
Power producers want to increase the payouts from ERCOT’s operating reserve demand curve (ORDC), which provides a price adder during periods of generation scarcity. During an October workshop on electricity prices, Exelon said the change would result in an annual $4 billion increase in electricity prices.
“Prices have to go up. They do!” Bill Berg, Exelon’s vice president of wholesale market development, said at the time. Without the increase, he said, prices won’t support the needed investment.
That $4 billion number has been thrown around by opponents to ORDC changes, which include consumer advocates and the conservative Texas Public Policy Foundation.
“Let the market work,” urged Bill Peacock, the foundation’s vice president of research, in a Dallas Morning Newsop-ed.
Former FERC Commissioner Pat Wood, who also chaired the PUC when ERCOT’s deregulated market was established in 1999, doubts the $4 billion figure, saying that is “nowhere near” the necessary cost. Wood says “the cheapest and most market-oriented way” to plan for the future is to continue to rely on the ORDC.
The PUC is also pondering whether to incorporate marginal line losses into how it allocates transmission costs among power generators, an idea being pushed by NRG Energy and Calpine.
Unlike other states, Texas shares the cost of lost electricity among all generators evenly. The allocation process and nearly $7 billion worth of transmission infrastructure has resulted in Texas, with nearly 23 GW of capacity, becoming the top producer of wind energy in the U.S.
Critics say the marginal line-loss proposal would suppress the continued development of wind and solar projects, which far outnumber gas generators in ERCOT’s interconnection queue.
While the PUC weighs which, if any, changes to make, Texas policymakers could also have a say. The 86th Texas Legislature will open for business on Jan. 8 and will end its biennial session May 27.
Legislators have already filed more than 100 bills that could affect the Texas energy market and its consumers. Many of those will inevitably die, but one to watch is Senate Bill 76. The legislation would create a Grid Security Council comprising appointees by Texas Gov. Greg Abbott, including ERCOT representatives, to monitor issues that touch on grid security.
WASHINGTON — 2018 brought chilling warnings about the growing dangers of climate change — and seeming evidence of it in November’s Camp Fire that killed more than 80 people and destroyed almost 19,000 structures and the town of Paradise, Calif. It was the state’s most destructive wildfire on record.
The November 2018 Camp Fire was the most destructive in California history. | CalFire
A month before the fire, the U.N.’s Intergovernmental Panel on Climate Change issued a report saying climate change could have catastrophic effects sooner than previously thought and calling for an unprecedented global response.
In November, a congressionally mandated report by the federal government predicted that if carbon emissions continue to grow at historic rates, some economic sectors will see hundreds of billions of dollars of annual losses by the end of the century — “more than the current gross domestic product of many U.S. states.”
President Trump told reporters he had read “some of” the report but didn’t believe its findings. Just two days before the report was released, he tweeted, “Brutal and extended cold blast could shatter ALL RECORDS. Whatever happened to global warming?”
Pruitt, Zinke Depart; Dems to Take House
Despite the resignations of two of the president’s most controversial cabinet members, EPA Administrator Scott Pruitt and Interior Secretary Ryan Zinke, the administration’s efforts to reverse Obama administration policies on climate and the environment continued unabated in 2018.
In August, acting EPA Administrator Andrew Wheeler, a former coal industry lobbyist, announced the replacement for the Obama Clean Power Plan. The Affordable Clean Energy (ACE) rule defines the “best system of emission reductions” as heat-rate efficiency improvements that can be achieved at individual coal plants, in contrast with the CPP, which set state emissions limits and encouraged switching to natural gas and renewables. Compared to the CPP, EPA said, ACE will cut electric prices by up to 0.5% in 2025 while increasing coal production for power sector use by up to 5.8%.
In December, Wheeler proposed eliminating the requirement that new coal-fired generation incorporate carbon capture technology. Given competition from lower-cost natural gas and renewables that has cut coal’s market share, it was a largely symbolic measure. EPA acknowledged no new coal-fired generating units are likely to be built in the U.S.
President Trump signing his executive order seeking to undo the Clean Power Plan as coal miners, Interior Secretary Ryan Zinke, EPA Administrator Scott Pruitt and Vice President Mike Pence watch.
The Energy Information Administration said U.S. coal consumption will fall to 691 million short tons (MMst) in 2018, a 4% decline from 2017 and the lowest level since 1979. About 11 GW of coal-fired generating capacity retired in the first nine months of 2018 with another 3 GW of retirements expected in the last quarter, making the year second only to 2015 in retirements. An additional 4 GW is expected to retire by the end of 2019. (See related story Critics: CEII Rule a Trojan Horse for Coal, Nuke Bailouts.)
On Friday, EPA proposed changing its cost-benefit calculations to eliminate the “co-benefits” of reducing pollutants other than those being targeted. Had the rule been in place, EPA said, it would have prevented the 2011 Mercury and Air Toxics Standards, which pushed many coal generators into retirement. The Obama Administration’s EPA said although the MATS rule would cost utilities $9.6 billion a year and produce only $6 million in direct public health benefits, it was justified by co-benefits of reducing soot and nitrogen oxide, saving at least $37 billion in annual health costs and lost workdays.
A Change in the House
Democrats picked up about 40 House seats in the midterm elections, giving them control of the lower house when Congress convenes its new session Jan. 3. Rep. Frank Pallone (D-N.J.), who will become chairman of the Energy and Commerce Committee, has pledged “robust oversight of the Trump administration’s ongoing actions to sabotage our health care system, exacerbate climate change and weaken consumer protections.” Rep. Raúl Grijalva (D-Ariz.), who will chair the Natural Resources Committee, says he will seek to elevate discussions on climate change while increasing oversight of the administration.
In the Senate, where Democrats lost two seats, West Virginia Democrat Joe Manchin will replace Sen. Maria Cantwell (D-Wash.) as ranking member of the Energy and Natural Resources Committee, although his outspoken support for coal will place him at odds with most of his party.
Progressive Democrats are pushing the idea of a Green New Deal to transition the U.S. to 100% renewable energy. Although it has no chance of passing with Trump in the White House and Republicans still controlling the Senate, advocates said it could help frame the issue for the 2020 presidential and congressional races.
“Climate change is clearly back on the table as a priority issue for the Democratic Party,” Dylan Reed, head of congressional affairs for Advanced Energy Economy (AEE) said in a year-end webinar Dec. 18.
Renewables Continue to Gain Share
Despite the Trump administration’s cheerleading of fossil fuels at home and abroad, states and businesses accelerated efforts to increase renewable generation and reduce emissions in 2018.
As of August, nonutility buyers had contracted for more than 3.5 GW of renewable energy in 2018, breaking the annual record of 3.12 GW set in 2015.
In October, the U.S. marked 1 million electric vehicles sold, with 2018 sales up more than 50% over the year before. While EVs represented only 2% of vehicles sold in 2018, electrification is being embraced more quickly in other transportation areas, with electric buses now more than 10% of new sales. State regulators approved $880 million in EV charging infrastructure in 2018 with another $1.5 billion in proposals pending, according to AEE.
The Electric Power Research Institute predicts that EVs and other electrification efforts could result in load growth of 24% to 52% by 2050.
Renewable prices continued to fall during the year.
| Lazard Levelized Cost of Energy Analysis
In November, Lazard’s annual Levelized Cost of Energy Analysis found that onshore wind costs have dropped to $29-$56/MWh, with utility-scale solar at $36-$44/MWh — matching or bettering natural gas combined cycle plants at $41-$74/MWh. Coal is higher than all of them at $60-$143/MWh.
Offshore wind costs also are dropping. Vineyard Wind, an 800-MW project off the Massachusetts coast, will provide power and renewable energy credits at a levelized price of 6.5 cents/kWh in 2017 dollars. “That’s pretty much comparable to [Massachusetts’] big hydro power contract procurement at … a levelized cost of energy of 5.9 cents,” said AEE spokesman Bob Keough.
Since Trump announced plans in June 2017 to withdraw from the Paris climate agreement, 17 states have joined the U.S. Climate Alliance and pledged to honor U.S. commitments, according to AEE.
In September, California lawmakers approved legislation to get 100% of its power from renewable and other zero-carbon resources by 2045. Six other states — Nevada, New Mexico, Colorado, Maine, Michigan and Illinois — also are pledging to move toward a 100% clean grid, AEE said.
Missouri adopted a green tariff allowing Ameren customers to get up to 100% of their load from renewables, said J.R. Tolbert, AEE’s vice president of state policy. “This is sort of the proverbial camel’s nose under the tent,” he said. “We expect to see more green tariffs in the Midwest as a result of what happened in Missouri.”
Environmentalists fared less well at the polls in November, with voters in Arizona, Nevada and Washington rejecting initiatives following expensive campaigns.
AEE’s Reed said the Trump administration’s efforts to bail out coal power forced clean energy advocates to produce legal and financial analyses opposing the proposals. “This required a lot of time, effort and resources that could have otherwise been used to accelerate the transition” to cleaner energy, he said.
PJM ended an era in 2018 with the retirement of Chairman Howard Schneider, who had served on the Board of Managers since the RTO’s inception in 1997. But in many ways, the year was much like those before, with capacity and energy market rules under constant redesign. Some stakeholders have grown weary of the churn.
The year also saw battles between transmission owners and load interests and the biggest default in PJM history, which raised questions about the RTO’s credit practices.
Here’s a review of some of the biggest PJM stories of 2018, and a look at what’s ahead in 2019.
2017 ended with PJM and its stakeholders at odds over the best way to insulate the capacity market from state-subsidized generation. RTO officials had rejected the Independent Market Monitor’s proposal, endorsed by stakeholders, to extend the minimum offer price rule (MOPR) to all units indefinitely, with carve outs for states’ renewable portfolios and public power self-supply.
PJM’s board responded by asking FERC to choose between the IMM plan and staff’s capacity repricing proposal, under which the RTO would have accepted bids from subsidized resources in its capacity auctions but then isolate them during a second stage and reset the price without them (ER18-1314).
FERC rejected both proposals and ordered PJM to expand the MOPR — which now covers only new gas-fired units — to all capacity receiving out-of-market payments, including renewable energy credits. The commission recommended creating an “alternative” fixed resource requirement allowing states to pull subsidized resources and associated loads from the capacity auction. The 3-2 ruling, which partially granted a 2016 complaint led by Calpine (EL16-49), initiated a Section 206 proceeding in a new docket (EL18-178).
PJM responded with an Oct. 2 brief outlining its proposal for an “extended resource carve out” that would allow subsidized resources to obtain capacity commitments without clearing the capacity market, while creating a mechanism to restore prices to “the theoretically correct competitive level.”
“Making room, outside the auction, to accept subsidized generation as a PJM ‘capacity resource’ ineluctably will degrade auction prices,” PJM said. “Unless the commission is prepared to accept a mechanism to adjust prices to their ‘correct’ level, this trade-off must be understood as an unavoidable consequence that comes once uneconomic resources are relieved from having to participate in the market.” (See Little Common Ground in PJM Capacity Revamp Filings.)
Stakeholders offered at least seven other alternatives for the MOPR and numerous modifications on FERC’s FRR concept and PJM’s carve out. In initial filings and reply comments filed in November, the stakeholders generally fell into two camps. One argued for a rejection of any carve out, calling instead for a “clean,” MOPR-only construct that extended to all resources. The other generally supported the concept of the FRR Alternative but argued that because of the repricing mechanism, PJM’s extended resource carve out would inflate capacity prices. (See PJM Stakeholders Hold Their Lines in Capacity Battle.)
The stakes are large, as illustrated by two of the most recent filings in the docket. On Dec. 6, eight generation developers, including Calpine and Tenaska, warned that the FRR Alternative “would in fact end the competitive PJM capacity market as we know it,” without a mechanism to avoid price suppression of competitive resources.
Public power and renewable advocates, including the American Public Power Association, the National Rural Electric Cooperative Association and the Natural Resources Defense Council, responded with a Dec. 21 letter to the commission. “We agree that states and locally governed utilities have the authority to make resource choices, and that it is not the role of the Regional Transmission Organization (RTO) to shield market participants from the effect of those policies,” they said.
BRA Results ‘Not Competitive’
In 2018, the second Base Residual Auction, in which all resources had to meet the Capacity Performance requirements, saw prices jump 83% in most of the RTO. But the IMM reported in August that the results of the auction were “not competitive” because prices were not capped at the net avoidable cost rate. The analysis said offers exceeding net ACR, while permitted by current rules, amounted to “economic withholding” and boosted total auction revenue by 41.5%. PJM insisted the rules had been followed, saying “the proper forum for such concerns about competitiveness of offers is the Federal Energy Regulatory Commission.”
The Market Monitor’s analysis found that clearing prices in the 2018 Base Residual Auction would have been lower everywhere but the PSE&G zone had prices been capped at net avoidable cost rate. Not identified is the DEOK zone, which cleared with the rest of the RTO at $140/MW-day, but would have priced at $128/MW-day. | PJM, Monitoring Analytics
In April, the commission held a technical conference to consider whether the RTO should move from a year-round to a seasonal capacity construct. Although it has yet to issue an order on the merits of the issue, FERC signaled its concerns in denying rehearing requests in the docket in August (EL17-32, EL17-36). “Given that PJM is a summer peaking system, … the move to a single, annual capacity product may have pushed valuable summer-only resources out of the capacity market and thereby increased capacity costs with little or no reliability benefit,” it said.
While it’s not known when or how FERC will rule on these issues, one thing is clear: State officials will be upset with any rules that make their initiatives more difficult or more costly.
States’ efforts to preserve their nuclear fleets continued in 2018, with New Jersey approving zero-emission certificates (ZECs) in May. In September, a federal appellate court upheld a similar program in Illinois, ruling the initiative did not violate the Federal Power Act.
After a year in which some state regulators threatened to leave the RTO or end the capacity market, RTO officials are in a very difficult spot.
In the energy market, PJM officials are trying to win stakeholder approval for a plan to allow large, inflexible generators such as coal and nuclear plants to set market prices. PJM’s board told stakeholders in December that it will make a unilateral FERC filing supporting its price formation proposal if they do not act by Jan. 31. Stakeholders have heard first reads on three alternative proposals.
“We feel we are correctly criticized as a region for not addressing known price anomalies,” CEO Andy Ott told the Markets and Reliability Committee’s Dec. 20 meeting. “There is a very strong opinion by the board that we are long overdue for these changes.”
PJM also is pushing to compensate generators for their “fuel security,” another initiative that could benefit struggling coal and nuclear generators. PJM released a report on the issue in December, saying that while there is no imminent threat, “fuel security is an important component of reliability and resilience — especially if multiple risks come to fruition.”
PJM said the compensation could be achieved through the capacity market or through a winter reserve product in the energy market.
Regardless of what the RTO decides, the proposal is likely to be viewed skeptically by stakeholders representing load, who have long complained of the costs of PJM’s large reserve margins and increasingly restrictive Capacity Performance rules.
Transmission Owners vs. Load
Load interests spent much of 2018 battling with transmission owners over their supplemental projects, which address individual planning criteria and are not subject to competition or PJM’s analysis for inclusion in its Regional Transmission Expansion Plan. In September, FERC approved TOs’ compliance filing in response to the commission’s February show cause order requiring them to increase stakeholder engagement in the development of supplemental projects (EL16-71, ER17-179). (See FERC Upholds PJM TOs’ Supplemental Project Rules.)
FERC also weighed in on a highly charged cost allocation issue, saying the solution-based distribution factor (DFAX) method is unjust and unreasonable for projects that address stability-related reliability issues. (See FERC Rethinking DFAX for Stability Transmission Projects.)
In May, PJM stakeholders endorsed a proposal requiring PJM to evaluate cost commitments — including construction costs, return on equity and capital structure — in its analysis of competitive bids for transmission construction.
In February, PJM and Peak Reliability, the reliability coordinator (RC) for the Western Electricity Coordinating Council (WECC), proposed creating an energy market as an alternative to the Western Energy Imbalance Market (EIM) managed by CAISO. But the effort quickly unraveled after CAISO said it would begin offering its own RC services at costs much lower than Peak’s. Seeing its customers defect to CAISO and a competing RC offering from SPP, Peak abruptly announced in July it would cease operations.
Ott said in October that PJM remains interested in the idea but that the pace of talks has slowed since Peak’s announced departure. (See Q&A: PJM’s Ott Still Looking West.)
GreenHat Default
In the cross fire between load and supply, PJM officials often take shrapnel over their policy choices. But the RTO rarely faces the kind of questions about its competence that followed the default of FTR trader GreenHat Energy.
GreenHat listed its address as Suite 565, 826 Orange Ave., Coronado, Calif. — a UPS store between a nail salon and a RiteAid. | Google
The company — run by two traders who were involved in a scheme to manipulate the CAISO and MISO markets between 2010 and 2012 — amassed 890 million MWh of FTRs (the largest FTR portfolio in PJM) with only about $600,000 of collateral.
The company’s collapse in June was the biggest default in PJM history. The incident led to calls for changes to PJM’s credit policy and questions about the RTO’s failure to respond promptly to warnings from other FTR traders, which allowed GreenHat’s $10 million loss in 2017 to grow to more than $100 million.
An investigative committee of the Board of Managers is expected to issue a report on what went wrong as soon as February.
Market Monitor: New Contract, More Oversight
The year also brought a new contract for Monitoring Analytics, PJM’s Independent Market Monitor, led by Joe Bowring.
The contract, which was extended through 2025, requires the Monitor to submit to an annual independent audit. In addition, the Board of Managers announced in December that it had hired former FERC General Counsel Michael Bardee as an external liaison to receive direct member feedback on the Monitor and report it to the board’s Competitive Markets Committee.
Connecticut officials on Friday announced the selection of two nuclear plants, nine solar projects and one offshore wind project in the state’s solicitation for nearly 12 million MWh of zero-carbon electric power, equivalent to 45% of the state’s electric load.
“Despite President Trump’s refusal to listen to scientists on this matter, the reality is that urgent and significant action is needed to dramatically reduce our dependence on carbon-based energy sources,” Gov. Dannel P. Malloy said in a statement.
The selections help secure the future of Dominion Energy’s at-risk Millstone Power Station, the state’s only nuclear plant, and include energy from NextEra Energy’s Seabrook nuclear plant in New Hampshire. (See Connecticut Likely to OK Millstone for Zero-carbon RFP.)
One contract adds 100 MW to the prior selection of 200 MW from the Revolution Wind project being developed by Ørsted US Offshore Wind, formerly Deepwater Wind. Another award will create 165 MW of new solar generation in Connecticut and throughout New England, including two projects paired with energy storage.
Punting Price Negotiations
The selection of Millstone’s bid follows a Nov. 16 draft decision by the state’s Public Utilities Regulatory Authority (PURA) categorizing the 2,111 MW plant as “an existing resource at risk for retirement” without ratepayer support (Case 18-05-04).
“We agreed with PURA that the Millstone nuclear facility is at risk of early retirement and created an evaluation framework that lets us compare the costs of retaining the resource with the cost of replacing it over time with a variety of renewable resources,” said Department of Energy and Environmental Protection (DEEP) Commissioner Robert Klee.
Out of 24 different bids from Millstone, DEEP selected a 10-year bid for about 50% percent of the plant’s output.
“DEEP selected and treated this option as though it were two separate bids: one for the next several years when they are not considered at risk due to their existing market commitments, and one for the latter years,” said the press release.
The award selection directs Connecticut’s electric distribution companies, Eversource and United Illuminating (UI), to negotiate the price downward to better reflect a reasonable rate of return for Dominion.
“The selected price for the first three years reflects Dominion’s submitted energy-only price. For the at-risk period of the bid, 2022 to 2029, Eversource and UI are directed to negotiate for a price that reflects the costs and risks Dominion faces. The negotiations are requested to conclude by March 31, 2019,” the release said.
While a normal utility rate of return on equity is 9%, DEEP said it would consider 12% to 15% reasonable for a merchant power plant with a long-term contract.
However, “Dominion has sought a rate of return that is not in the best interests of ratepayers,” said the regulator.
Seabrook Station did not seek at-risk consideration and therefore did not disclose its operating costs to PURA.
“It was selected on the basis of its price of 3.3 cents/kWh levelized (3.9 cents/kWh nominal), which beats the market forecast and is projected to save Connecticut ratepayers $18 million per year over its eight-year term. The Seabrook contract begins in 2022 and is for 1.9 million MWh,” said the release.
Offshore Wind and Solar
Connecticut officials in June announced they would purchase 200 MW of output from the Revolution Wind project, adding to Rhode Island’s 400-MW procurement. (See Conn. Awards 200-MW OSW, 50-MW Fuel Cell Deals.)
The additional 100-MW “procurement is another step forward for Connecticut in growing its commitment to offshore wind,” said Emily Lewis, senior policy analyst at Acadia Center. “Adding more offshore wind to the state’s clean energy portfolio will continue the momentum of this growing industry … To ensure continued growth of this industry in Connecticut, the state should set an offshore wind mandate similar to other east coast states.”
As a result of drafting behind larger procurement processes in Massachusetts and Rhode Island, Connecticut obtained a 600-MW price for 200 MW of offshore wind and was also able to leverage the developer’s investment criteria, Matt Morrissey, vice president of Ørsted US Offshore Wind, said at an event in October. (See “Offshore Wind Savvy,” Connecticut Explores its Energy Future at CPES Event.)
While bid details remain confidential until the contracts are signed, state officials disclosed that Ørsted US Offshore Wind committed an additional $13.7 million to Connecticut and the port of New London for infrastructure enhancements, economic development and education.
The nine solar projects chosen include “the first selections of grid-scale energy storage as part of Connecticut’s energy procurements,” with an average levelized cost of about 4.9 cents/kWh, the release said.
