WASHINGTON — A panel on investing in grid innovation and clean energy infrastructure last week gave Congress low marks and said emerging economies are proving quicker to adopt some technologies. But speakers at the GridWise Alliance’s GridCONNEXT conference said they are bullish on the future.
David Yeh, a White House adviser during the Obama administration who is now managing director of Capitol Hill, an advisory firm for high net worth individuals, global asset managers and start-ups, said he is not overly concerned with the Base Erosion Anti-Abuse Tax (BEAT) provision in the tax bill passed by the Senate earlier this month. Some renewable advocates fear the language, which is intended to prevent multinational corporations from moving profits and jobs out of the U.S., will reduce the value of wind and solar tax credits.
“Right now clean energy, especially at the utility scale, is competitive, if not cheaper than, fossil fuel energy. So, you can talk about regulation; you can talk about policy. But economics will trump all of that.
“This year, clean energy funds raised about $5 billion, while fossil fuels have raised about $2 billion. That’s showing what the demands are from the … capital providers [and allocators] of this world. … These are sovereign wealth funds; these are pensions; these are large, super high net worth families. … This is how the capital markets — and these are capital markets that start with a ‘T’ — trillions — view clean energy infrastructure. When they move their allocation from 1% to 5%, that’s a game changer. And they’re moving towards that.”
Nancy Pfund, founder and managing partner of DBL Partners, predicted that there will be few gas-fired peaking plants built in California in the future.
“They’re expensive. People don’t like them. They’re [crude] compared to solar and storage or wind or demand response or any combination. That’s an example that you have to let go of what the 20th century was all about. This is really different and if you stand in the way … of consumers who want their solar or want batteries, they are going to run you over.”
An ‘F’ for Policymakers
Policymakers in D.C. haven’t heard that message, however, she said, as reflected in “the $4 billion worth of annual subsidies that the fossil industry gets.”
“If the people on Capitol Hill were in a public policy class or business school course, they would get an ‘F’ because [they are subsidizing] an industry that’s 100 years old. I think anyone in our [clean energy] industry would say we would love a level playing field. Get rid of all incentives. But it’s kind of a ‘David and Goliath’ story at this point.”
Puon Penn, executive vice president and head of technology capital for Wells Fargo, said investors would be wise to look past the U.S. to China and other growing economies that have committed to abandoning the internal combustion engine in favor of electric vehicles.
“Do you think the [original equipment manufacturers] … the Fords and the GMs are looking at the United States as their primary market today? They sell more vehicles in China. And if you’ve got to make electric vehicles for the Chinese market, you’re damn well not going to make a bunch of internal combustion vehicles for the United States. You’re just going to build one platform that you’re going to distribute across the planet. It’s inevitable. But people are still behaving like we’re still [the] Jolly Green Giant walking the earth and determining the order of things. We’re not anymore.”
Penn said new technologies are allowing greater capacity utilization in the electric industry than in the past. “There’s no other industries where you have high [capital expenditures] and such low capacity utilization,” he said. “Today we do have the wherewithal to increase capacity utilization and therefore benefit the entire economy.”
WASHINGTON — Speakers at the GridWise Alliance’s GridCONNEXT conference last week left no doubt: Electric storage is long past the “tipping point.”
Moderator Ram Sastry, vice president of infrastructure and business continuity for American Electric Power, had posed the question: “Are we going to see large-scale deployment of energy storage systems? And if not, what’s stopping that?”
“I think we’re at or past that tipping point,” responded Andy Marshall, practice director for distributed energy resource management at Landis & Gyr. “I think you see the flexibility of storage and its ability to get deployed relatively quickly. You have not only the stuff that’s going on down in Australia, but you also have the things that are happening most recently in California.”
On Dec. 1 — the first day of summer for Australia — Tesla turned on a 129-MWh lithium ion battery, the world’s largest, to help the nation’s fragile electric grid. California deployed 100 MW of storage in just six months in response to natural gas constraints following the Aliso Canyon leak.
Praveen Kathpal, vice president of AES Energy Storage, said “the technology is mature,” noting that his company entered the business a decade ago. AES claims 500 MW of storage already deployed or in development.
“There haven’t been any components that needed to be invented for any of the deployments that we’ve done, because they’re all based on lithium ion battery technology, which was commercialized 25 years ago and has benefited from its use in the consumer electronics and transportation sector,” Kathpal said.
“The tipping point we see in storage is really meshing with some of the other megatrends facing our industry right now. We have the accelerated growth in renewables, and we also have the electrification of more sectors including transportation.”
Kathpal predicted new storage technologies will break below the current pricing floor for lithium ion. “So, 10 years from now, do I think we’ll have a commercially available storage technology that’s below $100/kWh? Sure. And that’s exactly why at AES the technology platform we’ve developed is forward compatible with technology change.”
“I think you could argue that the tipping point was several years ago when big PJM systems started to come online,” said Luke Witmer, lead research engineer for Wärtsilä’s Greensmith Energy. “More and more markets continue to value the fast-ramping and bidirectional capability that energy storage provides. And I think as … systems continue to decline in cost, we will compete in more and more markets. A lot of the market prices basically clear according to the natural gas price. … So it’s really just a matter of getting renewables plus storage to below that threshold in more and more places.”
Richard Brody, director of sales and marketing for Lockheed Martin Energy’s energy storage unit, said storage is still relatively expensive when compared with energy efficiency and demand response.
“Whether we’re talking about a C&I customer or a distribution utility, when we come look at an energy problem, we look not just at storage, but we start with efficiency, permanent load reduction, load control, demand response, demand management, grid analytics — all the tools you can bring to solve an energy problem. … We tend to look at other things first because storage — despite the declining costs — remains the most expensive way to address these problems.”
But he is nevertheless bullish on storage. “In terms of the tipping point — oh yeah, we’re passed it. This is a rapidly growing market.
“We’re seeing very strong growth in interest in doing large solar and wind coupled with storage. Most of the large developers we’re working with aren’t contemplating any large development of solar — and increasingly wind — without some way to firm it up with a fairly significant storage system.”
Brody said the demands are exceeding the four-hour maximum life for lithium ion batteries. “We’re looking at much more ambitious efforts that would require the attributes of a flow battery, which is a minimum of six to 12 hours of energy.”
A Sierra Club report released last week that said captive customers of SPP utilities are paying for uneconomical coal plants has drawn considerable pushback from the RTO and some of its members.
But the head of SPP’s Market Monitoring Unit (MMU) says the environmental group has a point in its criticism of utilities that self-commit coal generators when the RTO’s market prices don’t cover their operating costs.
When a utility self-commits a unit, it operates the plant regardless of whether SPP’s market clearing prices are sufficient to cover the plant’s marginal costs. Although self-committed units are ineligible to receive make-whole payments from SPP, the Sierra Club says, some units are apparently recovering losses from captive customers through state ratemaking proceedings.
The Sierra Club report, “Backdoor Subsidies for Coal in the Southwest Power Pool,” alleges that utilities in the footprint operate coal plants outside the wholesale markets, generating $300 million in excess costs that consumers were forced to pick up in 2015 and 2016.
SPP and its members responded by saying the Sierra Club’s analysis relied heavily on wholesale rates, which aren’t the same as retail rates that are subject to public policy and regulations. Nor do wholesale rates consider the cost of long-term supply contracts or ensuring grid reliability, they said.
Keith Collins, executive director of the MMU, says that while the report took some of the MMU’s observations out of context, self-commitment is a problem in the RTO’s markets. MMU staff raised the issue in their 2016 State of the Market report, which Collins reviewed with SPP’s Board of Directors and Members Committee in July.
The Sierra Club said it conducted a “high-resolution analysis” of 14 coal plants in SPP’s footprint. It used hourly market data to develop each plant’s cash flow analysis.
“All 14 units operated for extended periods of time when, objectively, it would have been less expensive for the electric bills of utility customers for the plants to sit idle,” the group’s report said. “The utilities that own each of the 14 coal units we examined would have saved its customers money if the coal units had operated less often.”
The report said all but one of the 14 units studied were owned by state-regulated utilities, municipal utilities or an electric cooperative with captive customers.
Utilities should be purchasing electricity for its captive customers in the SPP Integrated Marketplace (IM), the report said. But it said some utilities “appear to be going back to state commissions and using rate cases and other dockets to obtain ratepayer-funded subsidies for costs incurred in operating otherwise uneconomic coal plants.”
“In the SPP market, where nearly half of the resources are self-committing, how much of an energy market can SPP really be claiming to operate?” the report asked. “The consequence of these facts is that the SPP Integrated Market is possibly a market in name only. The impact of utility self-commit and underbidding energy offers within the SPP IM might be the most anticompetitive and anti-consumer behavior in any integrated electricity market anywhere in North America.”
The report also says self-committed coal units are denying revenues to independent merchant generators. “RTOs are supposed to create nondiscriminatory rates, but allowing coal units to self-commit discriminates against those operators that don’t have captive customers to fund a ratepayer subsidy. Moreover, it is discriminatory and unreasonable for the market to ask one subset of customers to pay above-market costs while all other customers pay market costs.”
Collins told the board and members that self-commitment of resources has declined but is “still very big.”
“When resources are self-committing, it can put downward pressure on prices also,” he said at the time, referring to the effects of incorporating uneconomic resources in wholesale prices.
“The point of the [Sierra Club’s] report is consistent with what we noted in the 2016 annual report,” Collins told RTO Insider. “Self-commitment can distort the market. It’s a message we’ve been presenting as well.”
The MMU report noted generation offers in the day-ahead market averaged 48% as “market” commitments and 35% for “self-commit” in 2016. Those numbers were 46% and 39%, respectively, in 2015. Outages accounted for the remainder.
The Sierra Club report quoted the MMU report, which said plants self-commit because of contract terms, low gas prices “that reduce the opportunity for coal units to be economically cleared in the day-ahead market,” long start-up times, and “a risk-averse business practice approach.”
Collins took exception to the Sierra Club’s claim that “reliability isn’t one” of the reasons why a unit might self-commit.
Although the MMU’s report didn’t cite reliability, Collins said, “reliability could play a factor where some of these resources self-commit. Our report identified a set of reasons for self-committing, rather than a complete list.
“We have been discussing this essentially since I’ve been here,” said Collins, a former FERC staffer who joined SPP in June from CAISO. “What are the factors [behind self-commitment]? What can we do to promote more market commitment? Some of it is education and creating awareness. At least there’s a dialogue there that’s begun.”
SPP Disagrees
SPP General Counsel Paul Suskie said in a statement that the RTO disagreed with the report’s fundamental assertion that “utilities’ option to either self-commit resources or purchase from the market equates to a subsidy and undermines the effectiveness and cost-efficiency of SPP’s Integrated Marketplace.”
Suskie said that “assessing the market’s fairness and effectiveness based on wholesale cost of electricity to consumers does not take into consideration a number of factors that may lead utilities to self-commit.” He listed contractual obligations, capital investments, public policy and fossil fuels’ contribution to renewable resources’ deliverability as among those factors.
“Our day-ahead market has functioned successfully for four years and, in that time, has reduced the cost of energy in our region by more than $1.25 billion while continuing to ensure the reliability of the grid,” Suskie said.
Peter Main, a spokesman for SPP member Southwestern Electric Power Co., said the company bids its generation into the RTO’s markets under its market protocols and will continue “to seek opportunities” to produce net energy revenues benefiting its customers.
“The Sierra Club report does not provide an accurate portrayal of the incremental (variable) costs and revenues associated with offering generation into the SPP Integrated Marketplace,” Main said in a statement.
Plant Operators Dispute Findings
According to the report, SWEPCO’s Dolet Hills and Pirkey plants in the East Texas-Louisiana region burdened customers with $210 million in costs in 2015 and 2016. However, SPP said the plants serve load in “locations in northeast Texas without significant wind.”
Oklahoma Gas and Electric, which owns two of the plants identified in the study, has said the units stopped self-committing into the market more than two years ago. Two other generators — Entergy-owned or co-owned plants in Arkansas — serve load in MISO.
Al Armendariz, with the Sierra Club’s Lone Star chapter, said he was confident the group has a “good handle on the cost to run these coal plants in SPP.”
Armendariz, who worked in EPA under President Barack Obama, said the Sierra Club compared the SPP LMPs paid to power plants in the immediate vicinity of the coal plants studied. The organization obtained operating data from S&P Global Market Intelligence, the U.S. Energy Information Administration and SPP in running its analysis.
“Our report is really a comparison of the revenue for electricity, compared to what it costs to actually run the power plant,” Armendariz said.
Rule Changes Sought
The Sierra Club would like to see several things happen, Armendariz said. “We think SPP should clarify its rules to require power plants to bid in their real cost of fuel and other variable [operations and maintenance] … in the day-ahead market.”
Armendariz also said the Sierra Club would like to see state commissions in SPP’s footprint “investigate this problem of self-commitment and disallow the recovery of costs borne by consumers when uncompetitive coal plants are operating.”
“Vertically integrated utilities should not be forcing their customers to pay the variable costs,” he said. “State commissions should not allow the recovery of those costs through the rate base.”
Asked whether the group planned to file a complaint with FERC, Armendariz told RTO Insider that the Sierra Club “is evaluating all avenues of legal recourse that may be available to rectify the problems.”
Both Armendariz and Collins agreed the problem of self-commitment is not unique to SPP. Collins said he saw self-dispatch at CAISO and “knows” it occurs in other markets. Armendariz said although uncompetitive coal plants are running in “virtually every market … the problem seems most acute in SPP.”
The MMU believes that will change as market participants continue to familiarize themselves with SPP’s day-ahead and real-time markets, which have been in operation for less than four years.
“It appears that resource owners are becoming more confident in the market and allowing the market to commit the resource instead of self-committing their resource,” the State of the Market report said.
The Monitor also said the market systems’ optimization algorithm is restricted to a 48-hour window. “Hence, large baseload resources with long-lead time and substantial start-up costs may not appear economic to the day-ahead market commitment algorithm,” the report said.
Collins said SPP’s Market Working Group has discussed a potential multiday optimization approach. A Tariff change has yet to materialize, he said, “but that could help address some of the concerns.”
WASHINGTON — Almost 190 investors, utility officials, technology company executives and others gathered for the GridWise Alliance’s two-day GridCONNEXT conference last week. Here’s some of what we heard.
FERC Enforcement, Tx Investment, Cybersecurity
Former FERC Commissioner Philip Moeller, a Republican, and Spencer Gray, a Democratic aide on the Senate Energy and Natural Resources Committee, talked about the newly reconstituted commission, transmission investment and the limited prospects for bipartisan action in Congress.
“We are at a low ebb in bipartisan relations,” Gray said.
But he said there was one exception. “I think there’s broad bipartisan consensus in the Senate to … focus more funds on cyber[security],” Gray said. “We’ve gotten [feedback] from a lot of groups in recent years that the federal government should have a more robust R&D program to develop new cyber tools and understanding of emerging cyber threats. That just seems like the lowest hanging fruit to me. It’s not a partisan issue at all.”
Moeller, who oversees the Edison Electric Institute’s business operations group and regulatory affairs, said the industry is “actually doing a very good job” on cybersecurity through the Electricity Subsector Coordinating Council. “But I’m not sure as an industry we necessarily tell our story well, partly because of the sensitivity” of the subject matter.
Moeller lamented the court rulings that rejected FERC’s “backstop” transmission siting authority in the 2005 Energy Policy Act. But he acknowledged the commission’s efforts to encourage transmission investment haven’t always been helpful.
“Our feeling is that the capital is out there but perhaps some of the [investment] signals need to be clarified. Whether it’s the [return on equity] mess at FERC, which I helped create unintentionally. But in trying to solve a problem, we’ve probably made it a little bit worse. I think there’s some uncertainty on the future of Order 1000. And it took a while I think for people to, like it or not, have the Clean Power Plan more in the rear-view mirror before they could focus on the expansion of the transmission grid.”
On Wednesday, EEI released a report suggesting changes to FERC’s ROE calculations that ClearView Energy Partners said could increase the model’s results by approximately 50 basis points.
Gray said Sen. Maria Cantwell (D-Wash.), ranking member of the ENR Committee, will be watching “what happens under the new leadership of FERC to the Enforcement office.” In response to the abuses that contributed to the 2000-2001 Western Energy Crisis, Cantwell helped draft language in the 2005 Energy Policy Act that gave the commission increased authority over market manipulation.
Scott Prochazka, CEO of CenterPoint Energy and chairman of the GridWise Alliance, said Hurricane Harvey — “our third 500-year storm in two and a half years” — proved the “incredible” value of mobile substations. The company also is likely to add airboats and trucks able to drive through high water, he said. (See Weeks Later, Utility Officials Still Awed by Scale of Hurricane Harvey.)
Robert Schimmenti, senior vice president of electric operations for Consolidated Edison, recalled how the utility was “humbled” by the 14-foot storm surge that drenched parts of Brooklyn and Lower Manhattan during Superstorm Sandy in 2012.
“All the weather predictions were around 12 feet. We did all the math and all the projections, and we thought we were good for about a 12-and-a-half-foot storm surge. It was only until a bunch of bright engineers linked the buoy data in the East River to a map of storm projections that they created — and this is well before high tide — and as they created these projections, we were like ‘Hey, wait a second. This doesn’t look good.’”
More than 1 million Con Ed customers in New York City and Westchester County lost power during the storm. The company has spent $847 million to make its system more resilient, including the addition of “smart switches” to isolate and clear trouble on lines, flood gates, pumps and 3 miles of flood walls around critical equipment.
Hurricane Maria took down “only” 220 230-kV towers in Puerto Rico, said Bruce Walker, assistant secretary for the Department of Energy’s Office of Electricity Delivery and Energy Reliability. But replacing each tower is a five- to seven-day project requiring ferrying of workers and equipment by helicopter, Walker said.
“One of the things that was striking to me regarding their system is their transmission lines; while very well built, [they’re] built right through the mountains. There are no rights of way; there are no roads. There is no tree clearing in those areas.”
Praveen Kathpal, vice president of AES Energy Storage, said his company recently outlined for the Puerto Rico Energy Commission “a vision of how 10 GW of solar plus 2.5 GW of storage, arranged in essentially sectionalized grids across the island, could provide both resilience and lower costs, because those [investments] break even with how much Puerto Rico would spend on burning oil for power generation over the next 10 years.”
Kathpal said AES’ 10-MW battery installations in the Dominican Republic “rode through all the grid disturbances of Hurricanes Irma and Maria” despite damage to transmission lines and generation outages. “A battery installation is physically resilient. It’s not as subject to the factors that during an intense storm would cause other resources to disconnect. So even as 40 to 60% of the generation in the Dominican Republic tripped off, the batteries continued to operate. And as you can imagine with those kinds of generation trips, the frequency was flopping all over the place. So they actually did more work to restabilize the system.”
CARMEL, Ind. — The MISO Board of Directors last week learned about the recent discovery that PJM had been committing two market-to-market errors that have likely cost MISO millions of dollars over a period of years.
They also heard that MISO may have little recourse to recover those losses.
At issue was PJM’s longtime practice of overstating its own transmission loading relief (TLR) because of a calculation error and its failure to order mandated tests required to define M2M constraints between the two RTOs. (See MISO Monitor Blames PJM for Market-to-Market Errors.)
During a Dec. 5 meeting of the board’s Markets Committee, Independent Market Monitor David Patton said MISO has anted up millions in unnecessary congestion costs stemming from PJM’s mistakes.
The untested M2M constraints led to $84 million worth of congestion in 2016 and $187 million in 2017, Patton said, adding a disclaimer that his firm probably couldn’t perfectly duplicate the constraint test that the RTOs perform, and that they may show different congestion values. Delays in defining constraints resulted in $44 million worth of congestion last year and $25 million this year.
“If they don’t define the constraint, they basically get to a free pass to use the transmission system,” Patton told the board.
Patton said one flowgate that wasn’t tested or defined as M2M led to $43 million in congestion in September alone.
“A unit was running, overloading the constraint, and we did not tell PJM to back it down,” Patton said. “We need to be vigilant. … We don’t always ask our neighbors to test the constraints.”
Willful Neglect?
Patton said PJM’s failure to order these tests was deliberate: “In our mind, this is a pretty gross violation of the Tariff, particularly since they knew they weren’t doing the test.”
Director Baljit Dail asked how Patton could be sure PJM knowingly neglected the test.
Patton said at the beginning of the RTOs’ M2M process nearly a decade ago, PJM was aware it needed to devise a new constraint model that included an actual representation of MISO system outages with shift factors, but it failed to create such a model. “They never did it, and they knew they didn’t do it.” Patton said.
“I’ll hold the rest of my questions for closed session,” Dail replied, referring to a closed session on the matter following the board’s open meeting.
“What is it that we can do as a board?” Director Thomas Rainwater asked.
Patton said there weren’t many options available to the board. It could urge enforcement by FERC, “which to be honest, hasn’t been very active in enforcement on violations of RTOs.”
“I don’t think there’s a lot you can do other than telling PJM how serious you think this is,” Patton said. He also said MISO stakeholders could pursue resettlement of prices related to the TLR miscalculations, although no precedent exists for such resettlements. PJM has been overstating its TLR response since 2009, “inappropriately” raising the relief obligation of MISO and other balancing authorities, Patton said.
Patton said it’s up to stakeholders to decide whether to pursue TLR resettlement at FERC.
“We’ve certainly resettled for less,” Patton said.
“These are serious issues with big dollar amounts,” Director Barbara Krumsiek said.
MISO Executive Vice President of Operations Richard Doying said strategies for resettlement would “certainly be a closed discussion item.”
PJM Responds
PJM Chief Communications Officer Susan Buehler told RTO Insider that PJM acknowledges it had “an internal process issue regarding the flowgate tests as well as a calculation error with respect to relief obligations,” but it disagreed that the issues amounted to a Tariff violation. She also said the MISO Monitor is possibly overstating the monetary impacts.
“PJM has corrected both issues and is evaluating the potential impacts, but at this time we do not believe the impacts are what the MISO IMM has indicated,” Buehler said.
She also said the congestion impacts and monetary values the Monitor has disclosed are projections and not solely a consequence of PJM’s “internal process issues” and “potential M2M inefficiencies” with constraints. PJM cannot confirm Patton’s numbers, she said.
JOA with TVA
Patton also urged the board to consider entering a joint operating agreement with the Tennessee Valley Authority over the TLR issue. MISO discovered PJM’s incorrect TLR values while investigating a northeastern Tennessee constraint, and Patton said TVA often calls TLRs on its 500-kV Volunteer-Phipps Bend line, which leads to price increases in the Midwest and corresponding reductions in the South. The TLR constraint contributed to higher prices during a late September emergency event, Patton said.
He said MISO has incurred 100 dispatch violations of its own constraints in responding to the competing dispatch effects of the Volunteer-Phipps Bend constraint.
“We’ll violate our own constraints in order to provide TLR to TVA,” Patton said. He also said TVA’s generation is almost always more effective and economic for managing a TVA constraint than MISO’s.
Patton originally complained about the excessive amount of relief MISO is asked to provide the Volunteer-Phipps Bend more than two years ago. (See External Constraint Vexing MISO, Market Monitor Says.) Now he thinks the RTO could lower its transmission constraint demand curve for TLR requests to avoid incurring costs to provide “very small amounts of relief.” He said MISO should instead pay TVA for economic relief on constraints pursuant to a JOA.
Doying said MISO is not in 100% agreement with the Monitor’s suggestions. “We value the reliability of our neighbor’s systems as much as we value the reliability of our own,” Doying said.
However, Doying said MISO is currently drafting a narrow JOA with TVA that would govern certain flowgates. He said MISO has had similar agreement with TVA in the past.
Patton also noted that TVA at times orders TLRs on Volunteer-Phipps Bend as a proxy to obtain relief on a nearby 161-kV constraint, and he questioned the efficiency of TVA’s process.
Director Paul Bonavia asked MISO executives if it was appropriate under NERC rules to use the 500-kV line as a proxy for a 161-kV line. Doying said the practice doesn’t violate NERC policies.
MISO General Counsel Andre Porter then reminded the board that further discussion was best left for a closed session.
“We’re not going to solve all of this today, but we’ll grapple with it, get it on the table,” Bonavia said. “How do we approach the resettlement issue. … How do we help our neighbors without being overzealous?”
“I do think we have a lot of issues to untangle with PJM and TVA,” Doying said.
CARMEL, Ind. —The MISO Board of Directors last week stepped in to order a plan of succession for the RTO’s executive leadership, while also approving its requested 2018 budget.
As part of the plan, the board immediately promoted Executive Vice President of Operations Clair Moeller to president, a permanent appointment. In the event of unforeseen circumstances related to CEO John Bear, Moeller would act as CEO, the board decided.
The RTO’s board usually takes a “nose in, fingers out” approach except when it comes to matters of personnel succession and strategic planning, Chair Michael Curran explained during a Dec. 7 meeting. He said the appointment will ensure that MISO is spared uncertainty in the event that Bear leaves his post.
For example, Curran joked, “if John gets hit by a truck, wins the lottery [or] beamed up by a spaceship.”
The board also approved a $321.7 million total operating budget and $29.6 million in capital spending for 2018.
As part of the budget, MISO will spend $21.7 million to begin replacing its aging market platform with a more adaptable modular market platform, a project it expects to complete by 2024. (See Winter Launch for MISO Website, Market System Project.) The RTO’s existing market platform relies on technology from the late 1990s, while its day-ahead and real-time market systems were added around 2005. The age of the system is limiting the new market products MISO can pursue.
“It’s approaching its teen years — God help us all,” Dynegy’s Mark Volpe joked during a Dec. 6 Advisory Committee meeting.
Alliant Energy’s Mitch Myhre, chair of the MISO Finance Subcommittee, said his group will track spending on the project.
“This is a big deal. $130 million is half of MISO’s annual budget,” Volpe said.
To date, MISO is under its 2017 base operating budget by about $1.8 million and predicts it will end the year having spent $240.8 million instead of the budgeted $241.7 million.
Chief Financial Officer Melissa Brown said the savings will result from not implementing a previously planned forward capacity market for the RTO’s deregulated areas, as well as lower-then-expected spending on building maintenance and employee travel.
MISO is $500,000 overbudget on this year’s capital spending but is poised to shrink the overage to $200,000 by year-end. The increase was mainly driven by the RTO’s effort to replace its market settlements software.
Last week also marked Director Paul Bonavia’s final meeting on the board, with his term expiring Dec. 31. In parting remarks, Bonavia called MISO a “civics lesson” and said the RTO was proof that decorum and cooperation could exist in an industry with several competing interests. “It’s positively breathtaking, with how you come together representing different interests but still have goodwill and move billions of dollars in investment,” he said.
Newly revealed photographs show Energy Secretary Rick Perry and Murray Energy CEO Robert Murray meeting in late March to discuss the coal mining company’s “action plan” — the apparent basis for Perry’s controversial call for price supports for coal generating plants.
The photos, obtained by magazine In These Times and The Washington Post, appear to contradict Murray’s statement to Greenwire in November that “I had nothing to do with” the DOE Notice of Proposed Rulemaking.
One photo shows the action plan’s cover letter, printed on Murray Energy letterhead. Another shows Perry embracing Murray.
Cover letter of Murray Energy’s “action plan” | Photograph obtained by In These Times
In These Times reporter Kate Aronoff said a confidential source provided the magazine with the photos, as well as additional, unpublished photos showing pages in the document, which propose, among other things, cutting EPA’s staff by half and replacing members of FERC, the Tennessee Valley Authority’s Board of Directors and the National Labor Relations Board.
Murray and Perry embrace. | Photograph obtained by In These Times
Aronoff said her magazine had only obtained photographs of the meeting and of the document, not the document itself.
The action plan contains language regarding the need for “immediate action” to support struggling coal plants like that in the DOE NOPR issued to FERC on Sept. 28 (RM18-1).
One section of the plan calls for “immediate action … to require organized power markets to value fuel security, fuel diversity and ancillary services that only baseload generating assets, especially coal plants, can provide,” according to In These Times.
The DOE NOPR says “immediate action is necessary to ensure fair compensation in order to stop the imminent loss of generators with on-site fuel supplies, and thereby preserve the benefits of generation diversity.”
Murray had referenced the document in an Oct. 11 episode of PBS’s “Frontline,” “War on the EPA.”
“I gave Mr. Trump what I called an ‘action plan’ very early,” said Murray, whose company’s political action committee donated $100,000 to President Trump’s campaign last year, according to the Federal Election Commission. “It’s about three-and-a-half pages … of what he needed to do in his administration. He’s wiped out page 1,” which apparently included repealing the Clean Power Plan.
Several other officials are portrayed in the photos: Perry’s chief of staff, former Edison Electric Institute Vice President for External Affairs Brian McCormack, is pictured shaking hands with Murray. Also seen is Andrew Wheeler, at the time a registered lobbyist for Murray Energy, now Trump’s nominee for EPA deputy administrator.
Murray Energy CEO Robert Murray (right) shakes hands with DOE Chief of Staff Brian McCormack (left) as Energy Secretary Rick Perry (center) looks on. | Photograph obtained by In These Times
At his confirmation hearing in early November, Wheeler testified to the Senate Environment and Public Works Committee that he had only briefly seen the document. Sen. Sheldon Whitehouse (D-R.I.) has called for its release. Wheeler has cleared the committee, and his nomination is pending a vote by the full Senate.
DOE did not dispute the authenticity of the photos. “Industry stakeholders visit the Department of Energy on a daily basis,” a department spokeswoman told Politico.
The March 29 meeting at DOE headquarters occurred just weeks after Perry was sworn in as secretary, and weeks before he would order a study on the effect of federal policies on the reliability of the grid.
Later in July, according to a letter from Murray to Trump obtained by the Associated Press, Murray met with the president and Perry in Youngstown, Ohio, where he asked that the secretary declare an emergency on the grid under Section 202(c) of the Federal Power Act in order to protect coal-fired plants owned by FirstEnergy, Murray’s biggest customer.
Andrew Wheeler, President Trump’s nominee for EPA deputy administrator, is seen on the far right, as Murray speaks with Perry. | Photograph obtained by In These Times
Trump was receptive to the proposal and, according to Murray, told Perry three times that “I want this done.” On Aug. 3, Murray again met with the president, along with FirstEnergy CEO Charles Jones, in Huntington, W.Va., where Trump told personal aide John D. McEntee III to tell Gary Cohn, director of the White House’s National Economic Council, “to do whatever these two want him to do.”
Perry, however, rejected the emergency order, the AP reported on Aug. 22. The next day, the department released its grid study. And a month later, Perry issued his NOPR, ordering FERC to consider fully compensating plants with a 90-day supply of on-site fuel their operating costs. (See Perry Orders FERC Rescue of Nukes, Coal.)
The PJM Board of Managers last week authorized $348 million in transmission projects. Coming two months after it greenlit $1 billion in projects, the approvals irked American Municipal Power, the RTO’s biggest critic when it comes to its Regional Transmission Expansion Plan.
“There was another $186 million of supplemental projects that will move forward in the PJM process. In other words, over a third of the transmission projects reviewed in this time frame were not approved by the PJM board,” American Municipal Power’s Ed Tatum said in an email. “These projects were not subjected to the same level of rigorous review afforded baseline projects, yet the cost of these facilities will ultimately be borne by the consumers in the constructing transmission owners’ zone.”
Tatum was referring to the separation within PJM’s RTEP between different types of projects: baseline projects requested to address reliability issues that receive significant RTO scrutiny; and “supplemental” projects proposed by TOs to address their own internal criteria that aren’t subject to the same level of analysis.
PJM must make recommendations and receive board authorization before assigning baseline projects, but TOs do not need RTO approval for supplementals.
“Another half-billion dollars of more supplemental projects are waiting in the wings. The sheer volume of projects moving forward absent adequate review for need and alternatives should be a grave concern to the PJM board,” Tatum said.
Last week’s decision by the board authorized 26 projects, most of which were reliability upgrades or replacements. There were three market efficiency proposals PJM staff recommended for authorization, though they accounted for less than $10 million. Twelve of them are in the Mid-Atlantic region of PJM’s footprint; 10 are in the Western area and four are in the Southern area.
The board also approved PJM’s installed reserve margin (IRM) of 15.8% for 2021/22. The IRM dropped from 16.6% thanks to an anticipated fleet-wide equivalent forced outage rate (EFORd) reduction from 6.59% to 5.89%. (See “IRM Results Approved,” PJM Planning/TEAC Briefs Oct. 12, 2017.) An IRM study earlier this year also created updated margins for other delivery years, which the board also approved: 16.1% for 2018/19 and 15.9% for 2019/20 and 2020/21.
The board also approved five targeted market efficiency projects (TMEPs) in conjunction with MISO that traverse the grid operators’ borders. The smaller, congestion-relieving interregional projects were also approved last week by MISO’s board. (See related story, MISO Board Approves $2.6B Transmission Spending Package.)
The portfolio of system upgrades has a combined cost of $20 million. On average, project costs will be allocated 69% to PJM and 31% to MISO, based on projected benefits, which are expected to reach $100 million.
FERC last week approved several changes to MISO’s competitive transmission developer selection process under Order 1000, which the RTO says will greatly improve its efficiency.
The most substantial of these changes eliminates MISO’s facility-by-facility evaluation when considering a developer’s bid, allowing the RTO to evaluate the project as a whole (ER18-44). Previously, the RTO had to individually assess a project’s facilities, such as lines and substations, even if they were all part of the same project. MISO called this approach both “inefficient” and “analytically flawed.”
MISO will now evaluate mixed-facility projects (those consisting of both competitive lines and substations) using the following weights:
35% for cost and facility design quality;
30% for project implementation capabilities;
30% for operations, maintenance, repair and replacement capabilities; and
5% for MISO transmission planning process participation.
Previously, the RTO used separate weighting for lines and substations.
Developers Midcontinent MCN and LS Power protested the new weighting. Both said the cost and description criterion, though increased by 5% for both types of facilities, should have significantly greater weight.
FERC rejected this, saying it agreed with MISO “that providing greater weight (35%) for cost and reasonably descriptive facility design quality appropriately accounts for the evaluation criterion that MISO anticipates will result in the greatest challenges for these types of projects, which include different types of facilities.”
“Indeed, MISO’s proposal to provide greater weight for the cost and reasonably descriptive facility design quality evaluation criterion for mixed-facility projects is consistent with LS Power’s and Midcontinent MCN’s general view that this evaluation criteria should play a greater role in the competitive developer selection process,” the commission said.
Additionally, FERC accepted other noncontroversial changes to the selection process. One of these allows MISO to stagger its requests for proposals for competitive projects. The RTO had explained that, as its Board of Directors approves projects for bidding in packages, drafting RFPs for the projects at the same time created significant staffing crunches (ER18-41).
The commission also approved several revisions to MISO’s governing documents to update terms and definitions related to the competitive process, as well as to improve their clarity, grammar and formatting (ER18-39).
Public Service Enterprise Group CEO Ralph Izzo last week asked New Jersey legislators to approve subsidies for the company’s three in-state nuclear facilities, warning they may otherwise be shuttered.
Testifying at a joint session of the General Assembly’s Telecommunications and Utilities Committee and the Senate Environment and Energy Committee on Dec. 4, Izzo said PSEG’s three nuclear units at the Salem and Hope Creek facilities remain profitable but are threatened by low natural gas prices and could become uneconomic within two years. He said the plants’ finances have been propped up by hedging over the past three years, but most of those contracts are set to expire by the end of next year.
“Unless market prices change, we will no longer be covering our costs within the next two years. Without intervention — without a thoughtful economic safety net — PSEG will be forced to close its New Jersey nuclear plants,” he said. “It would be an extraordinarily painful decision because of how much we value the importance to New Jersey, but it is a cut-and-dry decision.”
A Brattle Group study produced for PSEG and Exelon found that allowing the facilities to close would increase New Jersey power bills by $400 million annually over the next decade while reducing state tax receipts by $37 million, eliminating 1,400 jobs and increasing carbon dioxide emissions by 13.8 million metric tons annually.
Izzo requested state subsidies like the zero-emission credits approved in Illinois and New York for units owned by Exelon, which also owns 43% of the two Salem units.
Opposition Coalescing
Opponents questioned Izzo’s prediction that the plants will become unprofitable.
“It is not enough to simply accept PSEG’s assertions regarding the plants’ profitability, and that even if the plants are shown to be at risk of losing money in the future, the solutions must be found within the federally administered markets and not through out-of-market payments for plants that are already profitable,” said Stefanie Brand, the director of New Jersey’s Division of Rate Counsel. “Just because nuclear plants in other parts of the country are not profitable, doesn’t mean that plants in New Jersey — the state with the highest prices in PJM — are also unprofitable.”
PSEG’s units benefit from constraints in New Jersey’s EMAAC locational deliverability area (LDA) that traditionally put its clearing prices near the top in PJM. Capacity prices for delivery year 2020/21 during May’s Base Residual Auction fell to $76.53/MW-day in most of the RTO, while EMAAC jumped to $187.87 from less than $120 for 2019/20. (See Analysts See End to New Builds in PJM Capacity Results.)
PJM sent identical letters to Sen. Bob Smith, chair of the Senate committee, and Wayne DeAngelo, chairman of the Assembly committee, urging lawmakers to consider a regional approach rather than having the state act on its own. “As a state within PJM, New Jersey need not address these challenges alone or in a vacuum. Being located within PJM — a regional organization with a multistate market — allows for solutions and alternatives that can augment, enhance and amplify the means by which you meet your state policy priorities.”
“There is no evidence that PSEG’s nuclear plants are uneconomic and facing a retirement signal from the PJM markets,” said Joe Bowring, PJM’s Independent Market Monitor. “Neither plant is defined as at risk according to the criteria that the IMM applies to all units in the IMM’s annual PJM State of the Market Report.”
He argued that subsidizing the units would also deter investment in newer technology.
“Subsidies suppress energy and capacity market prices and therefore suppress … investment incentives for innovation in the next generation of energy supply technologies and energy efficiency technologies. These impacts are large and long lasting,” he said. “If subsidies are provided to one generating plant, this will suppress prices for all generating plants and create a need for additional subsidies for the remaining units. Competition in the markets will be replaced by competition to receive subsidies.”
Other Opponents
Also opposing PSEG’s proposal are AARP, which launched an anti-subsidy ad campaign, and the New Jersey Coalition for Fair Energy — whose members include Calpine, Dynegy, NRG Energy and the Electric Power Supply Association — which released a TV spot.
The New Jersey Coalition Against Nuclear Taxes includes AARP, environmental groups, the New Jersey Petroleum Council and other groups. Over the summer, one of its members — Dennis Hart, executive director of the Chemistry Council of New Jersey — criticized PSEG for “trying to build support in the New Jersey Legislature for another government handout that may cost all New Jersey ratepayers about $350 million annually over a 10-year period, or $3.5 billion.”
In a press release announcing its formation about a week before last Monday’s hearing, the Coalition for Fair Energy upped that estimate to “the range of $475 million a year or more, or in excess of $4 billion total” based on analysis of the New York and Illinois initiatives.
“There is no need for the Legislature to rush to pass a bill of such magnitude in a lame duck session without a full and thoughtful examination of a subsidy and its implications on the cost of electricity and its impact on a fair, level and competitive electric marketplace,” coalition spokesman Matt Fossen said in the release. “The public deserves complete transparency and a review of PSEG’s finances to see if there is any basis for a ratepayer-financed subsidy.” In his testimony, Izzo promised to open his company’s financial books for an independent examination.
After the Dec. 4 hearing, Smith said that legislation supporting the plants could be enacted during the lame-duck session, which ends early in January. “I learned enough today to begin the discussion,” he told NJ Spotlight.
Outgoing Gov. Chris Christie said he would sign a bill to save the nuclear plants, but only if it does not include incentives sought by environmentalists.
