A group of MISO transmission owners has petitioned Supreme Court Justice Elena Kagan for more time to draft a petition asking the court to reinstate incumbents’ right of first refusal (ROFR) on RTO grid projects.
The TOs, including Ameren, Indianapolis Power and Light, Northern Indiana Public Service Co. and Otter Tail Power, want until Oct. 14 to complete their petition for a writ of certiorari. The TOs are seeking to overturn a Court of Appeals decision that denied the companies’ request to void FERC Order 1000’s provisions that introduced competition into transmission development (ER13-187, et al.).
In April, the 7th U.S. Circuit Court of Appeals rejected the TOs’ challenge, which contended FERC failed to apply the Mobile-Sierra doctrine, which presumes rates negotiated by private parties are reasonable (14‐2153). The group also claims FERC didn’t uncover any evidence that the previous Tariff provisions “seriously harm[ed] the public interest.”
FERC held a technical conference on Order 1000 in July.
Seventh Circuit Judge Richard Posner said the TOs failed to show that maintaining the ROFR was in the public interest. He also said it was expected for MISO members to take issue with the removal of the provision that opens them to third-party competition.
“No one likes to be competed against,” Posner wrote. “So naturally, members of MISO in areas in need of additional facilities oppose Order 1000. They want to retain their right of first refusal — they don’t want to have to bid down the prices at which they will build new facilities in order to remain competitive.”
In the same order, Posner also denied a request by transmission developer LS Power, which said ROFRs should be dropped for even baseline reliability projects (14‐2533, 15‐1316).
LS Power received an extension for its own certiorari petition on Aug. 19. The TOs say granting their request for more time will not hold up the proceedings, as LS Power’s extension is already in effect.
In June, FERC held a technical conference to consider suggested improvements to Order 1000. The comment period in the docket, originally slated to end Sept. 2, has been extended to Oct. 3 (AD16-18). (See FERC Calls for Post-Conference Comments on Order 1000.)
SACRAMENTO, Calif. — While regionalization occupied center stage during the first day of CAISO’s annual Stakeholder Symposium, the second day’s panels took on an issue poised to be equally transformative for California’s electricity sector: the increased adoption of distributed energy resources.
“To give you a sense of the scale, in addition to over 16,000 MW of utility-grade renewables attached to the system, we now have 4,500 MW of distributed solar,” said Ashutosh Bhagwat, a member of the CAISO Board of Governors.
Rooftop solar capacity within the ISO’s balancing authority area has increased by 43% over the past five years, Bhagwat noted. “That means we’re most certainly going to hit 10,000 MW quite soon.”
Bhagwat said the ISO considers the rise of distributed generation to be an opportunity for enhancing its system, rather than a physical liability. Distributed resources have the potential to contribute to grid management, he said, but the ISO must overcome barriers to getting there.
“We have to figure out how to dispatch [DER] in a way that works,” he said.
Ron Nichols, president of Southern California Edison, said his company “is very strongly embracing the growth of distributed energy resources on our system. We’re dealing with it in an extraordinarily large way. In scale, it’s phenomenal.”
22,000 Changes
Among the questions the company is addressing: “What’s the pace of [DER] growth going to be? What are going to be the compensation models associated with that [growth]? What kinds of transactions are we going to deal with and how are we going to allocate costs with respect to that?”
The utility has made 22,000 short- and long-term changes to its distribution system to maintain reliability while incorporating DER.
“You don’t make 22,000 changes to the ISO transmission system — or even across” the Western Electricity Coordinating Council, Nichols said.
Lorenzo Kristov, principal of market infrastructure and policy at CAISO, said he started working on DER about four years ago when he led an initiative to expand the ability of distributed resources to participate in the ISO market.
Kristov said CAISO asked to him to imagine having as many as 100,000 “tiny” resources participating in the ISO’s market optimization — the platform responsible for scheduling and dispatching resources.
“Is that really the way that it’s supposed to be?” Kristov said. “My answer at that point was ‘maybe, but maybe not.’”
Among Kristov’s conclusions: Expanded DER will require distribution utilities to reconsider how they operate — while also forcing CAISO to rethink how it interacts with those utilities, he said.
Kristov said he can envision the development of a distributed service operator (DSO) “that looks pretty much like today’s distribution company. But then you could go to the very opposite extreme, where the DSO really takes on” the functions of another balancing authority.
Pilot Program
“These consumer resources can in fact be a reliable resource that can provide reliable services into the market,” said former FERC Chairman Jon Wellinghoff, now chief policy officer at SolarCity. “I think the future is at the area of the distribution utility.”
SolarCity is participating in a pilot program with Pacific Gas and Electric in which 150 homes with rooftop solar are installing the equipment and software controls necessary for the utility to provide ancillary services to the ISO, Wellinghoff noted.
“That’s one thing we need to remember … customers are an important part of this,” said Lorraine Akiba, a member of Public Utilities Commission of Hawaii, which has mandated a 100% renewable portfolio standard by 2045. “Customers have choices. We have to enable and empower them to be part of the grid.”
Federal-State Jurisdiction
Another question is which agencies will have jurisdiction over those resources in the wholesale market. While activities at the distribution level typically fall under the control of state regulators, FERC has the final say on matters related to markets and rules affecting the transmission system.
“These technologies are not only transforming the grid, but they are starting to erode the traditional barriers — the regulatory barriers — that separate the distribution system from the transmission system, and therefore [federal and state regulators] touch on each other in ways we never have before,” said Michael Picker, president of the California Public Utilities Commission.
FERC Chairman Norman Bay said jurisdictional questions can be resolved under the Federal Power Act. “If the resources are aggregated and have submitted a [CAISO Distributed Energy Resource Provider] filing — so it’s more than half a megawatt and can follow dispatch instructions — [they] can participate in wholesale markets,” Bay said.
During one panel, CAISO CEO Steve Berberich posed to Bay a scenario in which a FERC-jurisdictional DER aggregator violated an RTO’s market rules using behind-the-meter resources subject to state regulatory oversight.
“How would you bridge that gap?” Berberich asked.
FERC’s approach to enabling demand response to participate in wholesale markets could provide “a template for the way we might think about other distributed resources,” Bay responded. He noted that there have been cases in which FERC has pursued enforcement actions against DR providers for improperly verifying load reductions.
“Under our anti-manipulation authority, we have to show the conduct has a nexus with the wholesale markets,” Bay said.
In response to a question about who should be responsible for monitoring the market activities of DER aggregators, Bay pointed out that marketing monitoring presently occurs at the federal, state and RTO/ISO levels.
“There are many sources of information, and it’s very important that we use all those sources of information to make sure the market has integrity,” he said.
Bay also offered a note of support to California’s efforts to provide DER with access to the ISO’s market.
“I actually think a lot of good work is happening in California and CAISO, and I want to commend both the CPUC and CAISO for the work that you’re doing to establish market rules that allow DER and energy storage to participate in wholesale markets,” Bay said. (See FERC OKs CAISO Energy Storage Rules.)
LITTLE ROCK, Ark. — During the Great Depression, it was the newly formed electric cooperatives that electrified much of the rural U.S. Now, the co-ops want to replicate that accomplishment by bringing their customers broadband Internet access.
“There are parallels between broadband today and the lack of electricity 80 years ago,” Mel Coleman, CEO of North Arkansas Electric Cooperative and president of the National Rural Electric Cooperative Association’s board of directors, said during a speech at the Clinton School of Public Service on Sept. 6.
“Reliable, high-speed Internet access is critical for attracting new employers to small communities,” Coleman said. “What employer would want to set up in a community where you’re getting 3 or 5 or 10 megabits a second? [Rural communities] are in desperate need of an economic boost. Think what it could do for education, health care and, yes, for all the Amazon shoppers.”
Coleman said his and two other Arkansas co-ops are “hanging fiber as we speak,” as are other electric cooperatives across the country. He hopes to have his first connected members in January.
Meanwhile NRECA, the co-op’s trade association based in D.C., is seeking federal financing help to “ensure that all Americans have access to affordable broadband services,” Coleman said.
It’s another way co-ops are serving the little guy, as they have been since the 1930s, said Coleman, who also used his speech to tell the co-ops’ history and to make their case against EPA’s Clean Power Plan.
“The history of the co-op movement demonstrates good things can happen when the government partners with private enterprise to solve big problems,” he said. “The American spirit of electric co-ops is not just a relic of the Depression era. It lives and breathes across rural America today.”
NRECA represents more than 900 cooperatives in 47 states. These nonprofits serve 42 million customers and operate or maintain more than half the nation’s grid. The largest is in Texas (Pedernales Electric Cooperative, with 260,000 members), and the smallest is in Alaska (INN Electric Cooperative, with 285 members).
Earlier this summer, NRECA hired former seven-term U.S. Rep. Jim Matheson (D-Utah) as CEO to help represent its interests. In addition to lobbying for broadband funding and fighting the CPP, NRECA also is seeking relief from mandatory capacity markets. (See Little Love for PJM in Capacity Market Debate.)
‘Darkness’
As Coleman recounted the electric co-op’s beginnings, he said investor-owned utilities were reluctant to extend their lines into sparsely populated rural areas. As a result, he said, “A vast majority of rural America sat in darkness.”
“The 1920s were roaring for some people, but not for American farms. Less than 3% of farmers had electric power,” Coleman said. “You can imagine milking cows in a wooden barn, with straw floor, and a kerosene lamp waiting to be kicked over.”
At the height of the Great Depression in 1935, President Franklin Roosevelt secured $100 million for rural electrification as a part of a $5 billion public works bill. The next year, Congress passed the Rural Electrification Act (REA), which used cash incentives as a carrot to the IOUs, Coleman said.
“Their grand plan consisted of taking money and hooking up a few customers in easy-to-serve places … it was clear the power companies had no interest in serving rural areas.”
Coleman said it wasn’t until the first REA loans were extended to the handful of co-ops at the time that rural electrification became a reality. The first REA-financed poles were set in Ohio in November 1935, and the first REA-produced power line went into service the following year in Marfa, Texas. By 1936, 140 electric co-ops were in operation in 26 states and by 1940, they were serving more than a million customers.
NRECA was formed in 1942, and it quickly began taking on the big industry interests who scoffed at the little co-ops.
“One of the NRECA’s first tasks was to disprove the allegations made by the investor-owned utilities,” Coleman said. “We were able to show that electrifying farms actually played a viable role in the war effort, by those farms producing more food than farms could without electricity.”
When World War II ended, half of America’s farms had electricity.
“Think about what a remarkable feat it was just to electrify rural America,” Coleman said. “Millions of miles of line, stretched across 75% of the nation’s land mass, all of it done with incentives, not mandates — incentives that were paid back in full, on time, and with interest.”
Clean Power Plan = Job Losses?
Coleman said NRECA and the co-ops are taking the same approach in their opposition to the CPP. In February, the Supreme Court stayed the plan pending resolution of legal challenges by the association and multiple states. Oral arguments are scheduled before the D.C. Circuit Court of Appeals for Sept. 27.
An NRECA study says a 10% increase in electricity prices as a result of CPP compliance would cause annual job losses of 360,000 between 2020 and 2040 in areas served by co-ops. The study estimates a $1 trillion hit to GDP by 2040.
Other studies have suggested compliance costs could be minimal if natural gas prices remain low. (See PJM: Regional Plan Cuts Costs, but Gas Prices are Wild Card for CPP Compliance.) For its part, EPA contends the CPP will have health and climate benefits of $55 billion to $93 billion per year in 2030, “far outweighing the costs of $7.3 billion to $8.8 billion.”
“As a movement that had its origins in the Depression era, and one that was formed to serve some of the nation’s most economically disenfranchised citizens, electric co-ops are sensitive to regulations,” Coleman said. “We are very sensitive to mandates. We’re very sensitive to any regulation or mandate that could impact the affordability of the service we supply to our members.”
Coleman noted electric co-ops serve 327 of the nation’s 353 poorest counties, or “93% of the nation’s most economically vulnerable places.”
“Many of those folks can’t afford to see their power bill go up. They’re honest, hard-working folks living paycheck to paycheck. A $10-20 increase in the electric bill may not be a lot for those of us in this room, but I can tell you we have members for whom that’s a lot of money.”
Coleman told a story of a 90-year-old member of his North Arkansas Electric Cooperative, who told him she had figured out that by taking her medication every other day, she would be able to pay her electric bill.
“Our concern is the person on the other side of the meter,” he said. “One of the arguments used by supporters of the [CPP] is that the cost to shut down coal-fired power plants will be absorbed by the [plant owners] and their Wall Street investors. Well, that may be true for the investor-owned, but that’s not true for co-ops. The problem is, the owners of our company are not a bunch of faceless Wall Street investors. They’re farmers and ranchers and teachers and veterans and retirees.”
Coal Dependent
He pointed out co-ops are heavily dependent on coal-fired generation because of a “previous government mandate,” the Powerplant and Industrial Fuel Use Act of 1978. Prompted by the 1973 oil crisis and the natural gas curtailments of the mid-1970s, the legislation encouraged the use of coal, nuclear power and alternative fuels in new plants. Provisions restricting the use of natural gas by industrial users and electric utilities were repealed in 1987.
“Power plants are not short-term investments,” Coleman said. “With maintenance and upgrades for the latest technology, the useful life for a power plant extends many decades. Upgrades are typically financed by long-term debt. It could be years before those debts are paid off. To retire a plant while it still has a mortgage will effectively force those co-ops members to pay for that same power twice.”
That’s not to say co-ops aren’t embracing renewable energy, Coleman said.
He listed wind, solar and biomass as being critical elements in the association’s “all-of-the-above” approach to fuels, and briefly detailed several individual co-op initiatives related to solar technology, community energy storage and carbon capture.
“The common thread to all these projects is they’re responding to local challenges,” he said. “Co-ops face change, we face challenge. The good news is, the American spirit is in the heart of every co-op.
“Electric co-ops have long been innovators in the industry. Our smaller size makes us focus on new ideas and how they affect our members. We try new things all the time, and when one co-op discovers something that works, they share it with all of us.”
MISO and SPP are moving ahead on a joint study focusing on seven projects, staff told stakeholders at a Sept. 7 Interregional Planning Stakeholder Advisory Committee meeting.
The seven needs in the coordinated study scope include four projects suggested by both RTOs and three proposals from just SPP. The original list of study prospects had 10 suggested projects from SPP and five from MISO focusing on the seam with SPP’s Integrated System.
Source: SPP
The final scope contains projects both inside and outside of the Integrated System seam. (See “MISO-SPP Coordinated Study Focusing on 5 Interregional Areas in Dakotas,” MISO Planning Advisory Committee Briefs.)
“We landed on a hybrid number that include seven issues. Part of the reason that it was limited to seven is because that’s the number we think we can complete by April,” SPP’s Adam Bell said. The coordinated study will run into the first quarter of 2017. The transmission elements to be studied are:
The Rugby tie linking the Western Area Power Administration-Upper Great Plains East balancing authority and Otter Tail Power in North Dakota;
The Hankinson-Wahpeton 230-kV line and the Jamestown-Buffalo 345-kV line on the Dakotas–Minnesota border;
The Granite Falls 115-kV circuit and the Lyon County 345-kV line in southwestern Minnesota;
The Sioux Falls-Lawrence 115-kV line and the Sioux Falls-Split Rock 230-kV line near the South Dakota–Minnesota border;
The Northeast-Charlotte 161-kV line and Northeast-Grand Ave West 161-kV line near the northern section of the Missouri–Kansas border;
The Neosho-Riverton 161-kV line and the Neosho-Blackberry 345-kV line in southeastern Kansas; and
The Brookline 345/161-kV circuit transformer in southwestern Missouri.
A majority of the 17 stakeholders that filed comments called for evaluating needs along the entire SPP-MISO seam and not individual geographic locations. However, some did support pruning the number of projects to a manageable number in light of the study deadline.
Bell said stakeholders gave “a lot of support” to studying all 11 interregional need candidates pulled from MISO’s 2016 Transmission Expansion Plan and SPP’s 2017 Integrated Transmission Planning 10-Year Assessment, which are both due to be completed in early 2017. (See SPP, MISO Try to Bridge Joint Study Scope Differences.)
Davey Lopez, MISO advisor of planning coordination and strategy, said this year’s targeted study will serve as a gateway for a large-scale overlay study process through 2019. “What we’re going to do is use this study as a foundation for a broader, longer-term effort in 2017. It’ll be a multiyear effort,” Lopez said.
MISO’s Eric Thoms said it’s yet to be seen how this year’s targeted study will feed into the overlay study, which will have its own scoping process.
Adam McKinney of the Missouri Public Service Commission repeated concerns that the RTOs were too quick to embark on an overlay study after last year’s targeted joint study failed to yield any interregional projects.
“It seems like you went on a very bad date and are proposing to get married … you’re going pie-in-the-sky here,” McKinney said.
Bell said McKinney had a point. “I personally am a strong believer that you can’t do the bigger things unless you do the smaller things. We have to be committed to this being actionable, and we don’t want to do studies for the sake of doing studies,” Bell said. Thoms added that “no-brainer” short-term studies will be given attention.
At a Sept. 9 meeting of SPP’s Seams Steering Committee, Steve Gaw, consultant for the Wind Coalition, asked if MISO was prepared to issue construction authorization if projects were identified. SPP Director of Interregional Relations David Kelley said MISO’s concern was authorizing projects that serve only as “Band-Aids” when the upcoming overlay study might reveal a larger, more permanent fix.
Paul Malone, transmission compliance and planning manager with the Nebraska Public Power District, pointed out that most of the seven projects are under MISO’s 345-kV threshold for cost allocation for market efficiency projects. He asked how MISO intends to fund them if they’re approved.
Kelley said unless the “ultimate solution” was at least a 345-kV rating, he didn’t have an answer. MISO was directed by FERC earlier in the year to remove its 345-kV threshold and $5 million cost minimum on interregional projects with PJM.
SPP asked FERC in July to apply the same directive to the MISO-SPP seam. In late July, MISO filed an answer saying that eliminating its SPP thresholds was outside the scope of the PJM order (ER16-1969). A response from FERC is pending.
Shelly-Ann Maye, representing Midwest Power Transmission Arkansas, asked if any of three additional needs identified from SPP could result in competitive bidding. Kelley said “there’s nothing to prevent” a competitive project from emerging from any of the needs. Kelley said that the RTO’s respective portions of the lines could be bid on using the RTOs’ Tariffs.
Stakeholders also asked the RTOs to explain the reasoning behind using MISO wind information from 2005 and 2006. Lopez said the 2006 wind profile that MISO is using is deemed to be appropriate for use and the RTO is not actually using 11-year-old wind data.
“It’s not the actual data we’re using. And we do plan on using a 2012 profile in the near future,” Lopez said. MISO will begin to use a 2012 wind profile beginning with MTEP 17, but the updated wind profile use won’t likely make it into the targeted study, he said.
Kelley added the targeted study will become a proving ground for interregional process enhancements between SPP and MISO. When the study is finished in April, suggested projects — if any — will be turned over for regional review and cost allocation discussions.
Offshore wind could be competitive with existing generation in the Northeast within a decade, according to the second National Offshore Wind Strategy, released last week by the U.S. departments of Energy and the Interior.
The report cites a new cost analysis by the National Renewable Energy Laboratory that predicts offshore wind costs could drop below $100/MWh between 2025 and 2030. “Assuming near-term deployment of offshore wind at a scale sufficient to support market competition and the growth of a supply chain, development of offshore wind energy in markets with relatively high electricity costs, such as the Northeast, could be cost-competitive within a decade,” it said.
The report, a joint project of the Energy Department’s Wind Energy Technologies Office and the Interior Department’s Bureau of Ocean Energy Management, updates the government’s first strategy, which was published in 2011. Officials estimate U.S. waters have a “technical potential” of 2,058 GW — nearly double the nation’s electric usage.
The report outlines 30 steps the two agencies plan to take to reach that potential, including reducing technical costs and risks, making the regulatory process more predictable and transparent, and improving market conditions for investment by quantifying the impact of integrating large amounts of offshore wind to the grid.
As of the end of 2015, BOEM has awarded 11 commercial leases for offshore wind development capable of producing 14.6 GW of capacity. Construction of the nation’s first offshore commercial wind farm, off Block Island, R.I., was completed last month and is expected to begin operations by the end of 2016.
Feds Halt Dakota Access After Judge Denies Tribe’s Request
The Obama administration ordered a halt to construction of the Dakota Access oil pipeline Friday, minutes after a federal judge rejected a request by the Standing Rock Sioux Tribe to halt construction of the $3.8 billion, 1,172-mile crude oil pipeline.
The departments of Justice and Interior and the Army jointly ordered work to stop on one segment of the project in North Dakota, where it crosses under the Missouri River near the Standing Rock reservation, and asked developer Energy Transfer Partners to “voluntarily pause” action on a wider span on private land that the tribe says holds sacred artifacts. The tribe has challenged the Army Corps of Engineers’ decision to grant permits for the pipeline at more than 200 water crossings.
In his ruling, U.S. District Judge James Boasberg said that the court “does not lightly countenance any depredation of lands that hold significance” to the tribe, but nonetheless said the tribe “has not demonstrated that an injunction is warranted here.”
Bay Names Andrea McBarnette FERC Administrative Law Judge
FERC Chairman Norman Bay appointed Andrea McBarnette, former federal prosecutor and administrative law judge with the Social Security Administration, to be an ALJ for the commission.
A 1997 graduate of Georgetown University Law Center who earned her undergraduate degree from Stanford University, McBarnette built a private law practice in intellectual property, employment law and securities fraud. She then became an assistant U.S. Attorney for the U.S. District Court for D.C. She became an ALJ for the Social Security Administration last year.
“I am pleased to welcome Judge McBarnette to the commission,” Bay said. “I am confident that her experience will serve the public and our stellar ALJ office.”
NRC to Review Generator Failure at Wolf Creek Nuclear Station
Operators of the Wolf Creek nuclear generating station in Kansas are scheduled to meet with Nuclear Regulatory Commission staff to review the failure of an emergency backup diesel generator during a test two years ago. The commission released its preliminary findings of the 2014 incident, when a faulty electrical component kept the emergency diesel generator from starting up when called on.
The findings come just days after the Coffey County plant shut down following a reactor cooling system leak, quickly followed by a magnitude 5.6 earthquake that was centered near Pawnee, Okla. Plant officials said the station was scheduled to go offline for a refueling outage in mid-September, so they decided to keep it idle until the refueling is completed.
An EPA update to its Cross-State Air Pollution Rule falls short of what some environmentalists wanted to see. An attorney for the Sierra Club, Zachary Fabish, said the updated rule calls for only “modest” emissions reductions for 22 states in the South, Midwest and East Coast.
The new rules would cut ground-level ozone, or smog, by 80,000 tons by 2017. The states covered by the smog rule are: Alabama, Arkansas, Illinois, Indiana, Iowa, Kansas, Kentucky, Louisiana, Maryland, Michigan, Missouri, Mississippi, New Jersey, New York, Ohio, Oklahoma, Pennsylvania, Tennessee, Texas, Virginia, West Virginia and Wisconsin.
Renewable, Green Energy Groups Push for Tax Credit Extensions
Trade groups representing the biomass, hydro and other energy industries are putting pressure on Congress to extend tax credits seen as vital to helping their businesses compete with solar and wind.
If the tax credits now afforded to them expire at the end of the year, they say, “the end result is less reliable renewable baseload power will be deployed, which we believe is not the intent or desire of Congress and not in line with an all-of-the-above energy strategy.” While many hydro and biomass tax credits expire in December, credits for wind remain until the end of 2019.
The letter was written to congressional leaders by the National Hydropower Association, American Biogas Council, Biomass Power Association and Energy Recovery Council.
PHILADELPHIA — More than 100 generators, consultants, RTO officials and utility executives attended Infocast’s PJM Market Summit 2016. Here’s some of what we heard:
Don’t understand what the big deal with the capacity market is? Jeff Plewes of Charles River Associates offered a metaphor most people are likely to understand: buffet restaurants.
Plewes likened the energy market to the main buffet and the capacity market as the salad bar. High natural gas prices allowed for “steak night every night” early on, Plewes said. But when tour buses of new diners in the form of new renewable generators showed up to “feast” on the main buffet, it sent existing customers to the salad bar for most of their meal.
That’s led to new house rules in the form of Capacity Performance — and many additional questions. Among them, Plewes said:
How locational deliverability area prices will be influenced by the relative shares of base and CP capacity;
How seasonal and intermittent resources will be accommodated and the role of aggregation; and
Whether the capacity market will be split into separate classes for subsidized and competitive units.
Storage requires significant coordination to get interconnected into PJM’s grid and what to do with it when it gets there isn’t quite clear. “Arbitrage is actually a really bad economic model for storage,” said RES Americas’ John Fernandes.
PJM’s Frank Koza said his group is developing some new documents for clarity on Order 1000 processes, but bristled at the idea of being so transparent that developers are “standing next to us” while rules are being crafted. “Quite frankly, we’ve got to be able to strike a balance,” he said.
He also acknowledged that PJM hasn’t always been fully committed to the sponsorship model — in which the RTO defines the problem and invites developers to engineer and “sponsor” solutions. “We have done some soul searching about the model itself,” he said. “We’ve thought about it and decided to stay with the sponsorship model.”
While there was some support for PJM’s work, most saw room for improvement. Tom Dagenais of American Transmission Co. likened the process to “making love in a bathtub” — it seems like a great idea, but implementing it is a real challenge.
The Future of Demand Response
Even though the U.S. Supreme Court upheld FERC’s Order 745 earlier this year, demand response as a capacity resource in PJM is “mostly dead barring changes in CP,” said Jed Trott of Customized Energy Solutions. Annual changes to DR rules have made customers more “cynical” that power markets are designed to take advantage of them, he said. Customers thought they were performing a public service by installing DR, but they will start making decisions based on what’s best for them, rather than what appears best for the grid.
“It’s kind of like slapping them in the face,” said Judy McElroy of Fractal Business Analytics. “It’s like, ‘whatever you did didn’t count.’”
As customers add in-house DR technologies that markets aren’t aware of, it will become increasingly harder to accurately predict demand, “which probably means the RTO will be over-procuring because they won’t have that much insight into the curtailment by those customers,” said Allen Freifeld of Viridity Energy.
But the markets will have to adjust to that new reality, said Frank Lacey of Electric Advisors Consulting. “One of the major benefits — the major benefit — to a company is it can avoid its capacity charges by participating in demand response. … Demand response companies [are] going to have to change their business models, but demand response is alive and well,” he said. “Maybe not in PJM, maybe not in any of the other markets, but from a customer perspective, from a supplier perspective, the market’s not going away. You’ve given customers a taste for something, and they like it. They’re not going to give it up. ”
Others on the financial side at the summit weren’t as concerned about DR’s future. “DR, frankly, is a crappy tool,” said Barry Trayers of Citigroup Energy. “You can see why PJM isn’t very happy to price it in the supply curve.”
The issue with aggregating seasonal DR resources is that there are far fewer winter options, explained Robert Weishaar Jr. of McNees Wallace & Nurick, which represents the PJM Industrial Customer Coalition. So while summer options provide the majority of the value and potential risk for nonperformance, winter products are necessary to create a year-round capacity offer, he said.
“There is a lot of money at stake,” he said.
So far, there have been no commercially aggregated offers in any CP Base Residual Auction, he said. Asked how seasonal resources will likely be married, he said he expects “forced weddings.”
The Future of Solar
Solar installations are “booming,” according to Jay Carlis of Community Energy, because the module price per watt has fallen to less than $1 and “trackers” allow panels to pivot along with the sun to produce more energy during late peak hours when it is more valuable. In addition, companies are finding value in financing development projects through long-term, offsite power purchase agreements.
That said, Carlis sees no opportunity for further wind development in PJM without PPAs. The last round of major wind development in the market happened around 2008, he said, and “those owners are not happy” with the returns they’re receiving.
Getting More from Hydro
Dana Hall of the Low Impact Hydropower Institute highlighted the potential growth of both run-of-river hydro and pumped storage — and the Department of Energy’s keen focus on utilizing it.
Hall quoted from the department’s Hydropower Vision Report 2016, which said more than 48 GW of new hydropower capacity could be online by 2050 through advances in technology, financing and environmental considerations. Pumped storage has the biggest upside, with growth potential of 62%.
“We have plenty of dams in this country,” she said. She showed a map of the country’s unpowered dams with a potential capacity of more than 1 MW; spots dotted the U.S. Most were in the midcontinent near the Mississippi River, but every PJM state except Delaware showed opportunity.
Hall’s institute provides certifications that allow projects to qualify as, for example, Tier 1 resources in Pennsylvania. By 2021, Pennsylvania utilities must obtain 8% of their power from Tier 1 renewables.
“I think every project has the potential to pass,” Hall said, “but they might have to invest heavily.”
Simple-Cycle Offers Opportunities in Volatility
Matti Rautkivi, of generator manufacturer Wärtsilä, sees volatility as an opportunity to make money. For example, volatility in the Australian market means that prices hit the market’s $13,000 price cap several times a month, he explained.
While price caps are lower in PJM’s markets, there’s certainly plenty of volatility to exploit. Rautkivi showed a map of volatility in the U.S., and the vast majority — including the highest prices — was in PJM’s footprint.
His solution to capturing that value utilized natural gas as the fuel — no surprise there — but relied on simple cycle plants rather than larger combined cycle ones. Why? Speed, of course. The “reality today” of Wärtsilä’s 225-MW “standard plant” design is highly sensitive response, needing 30 seconds to synch, two minutes to ramp up to full capacity, one minute to ramp down and five minutes of downtime before it can do it all again.
That responsiveness was the basis of a plan that allowed Denton, Texas, to achieve its goal of receiving 70% of its supply from renewable sources. Modeling showed that using the plant to make a profit off of price spikes in the market while also avoiding paying high costs for electricity would save the town $975 million compared to securing its desired supply mix exclusively from the market.
FERC on Thursday dismissed a complaint by transmission developers who were excluded from New York public policy projects under Order 1000 (EL16-84).
The developers had asked the commission in June to order New York regulators to begin a new process to evaluate transmission upgrades to alleviate congestion and bring renewable energy downstate. The New York Public Service Commission had approved a list of transmission developers eligible to participate in building the state’s Energy Highway initiative. (See New York Transmission Developers Ask FERC to Order a Do-over.)
The developers — Boundless Energy NE, CityGreen Transmission and Miller Bros. — jointly filed their complaint as Competitive Transmission Developers (CTD). They said NYISO violated its Tariff and FERC directives under Order 1000 when it solicited projects without conducting its own review and instead deferred to state regulators.
The developers said the ISO should follow its normal study process — including its base assumptions and generator dispatch modeling — to consider competing solutions without excluding specific technologies or relying on the PSC’s assumptions and modeling.
But FERC said the ISO was in compliance with its Tariff and Order 1000. “NYISO’s [Tariff] permitted NYISO, in consultation with stakeholders, to rely on the New York commission, with input from NYISO and interested parties, to identify the public policy transmission needs, and the New York commission identified the public policy transmission needs here,” FERC added.
“Additionally, we disagree with CTD that the New York commission’s identified public policy need transformed NYISO’s sponsorship model into a competitive bidding model. The New York commission did not select a specific project and did not require NYISO to conduct only a bid-based solicitation for a specific project.”
Boundless participated in an evaluation of potential projects last year by NYPSC staff, but staff recommended that the developer be disqualified because its proposals were deemed not cost-effective. CityGreen, which is interested in developing HVDC and AC transmission facilities, and Miller Bros., a utility contracting company, are not qualified transmission developers in NYISO.
Developers’ proposals, which were submitted in late April, are currently being evaluated by NYISO staff.
A task force developing cost allocation rules for seams projects identified outside the FERC Order 1000 interregional process agreed last week to take another crack at crafting language more agreeable to stakeholders and staff.
SPP attorney Matt Harward will help guide the staff effort to produce the revised business practice, in coordination with the Seams Steering Committee’s small task force.
During the committee’s Sept. 9 meeting, Harward questioned whether a business practice is the correct method to solve the problem, while members raised concerns that the task force’s current draft of Revision Request 170 hews too closely to Tariff language rejected by FERC Rejects SPP Proposal for Seams Transmission Projects.)
Some members also said it doesn’t include a suitable interaction between seams projects and Order 1000 projects. ITC Holdings said RR 170 creates a “carve-out” from the Order 1000 process for seams projects and would exclude “a class of projects that have heretofore met various thresholds for Order 1000” by requiring they have a funding mechanism with a seams partner.
Staff drafted the initial business practice based on member input and the seams committee’s 2014 seams project policy paper, which was approved by the Board of Directors. The original language allows transmission providers to recommend the board direct staff to file requests with FERC that regionally allocate 100- to 300-kV seams projects if the zone in which the projects are located receives less than 60% of their benefits and if their benefit-to-cost ratios are less than 1.0.
Oklahoma Gas & Electric’s Jake Langthorn, who leads the task force, said he still hopes to meet next month’s deadline for finalizing the revised language. “It’s in staff’s hands,” he said.
The new language will have to be approved by the Seams Steering Committee and the Business Practice and Cost Allocation working groups before it can be brought before the Markets and Operations Policy Committee and the board.
SPP-AECI Models due in October
SPP interregional coordinator Adam Bell told the committee a joint study with Associated Electric Cooperative Inc. is continuing to focus on five target areas in Missouri. He promised models and transmission needs will be published before October “so we can start looking at different transmission options.”
The SPP-AECI Interregional Planning Stakeholder Advisory Committee will meet again next month. It is sticking to a January delivery of its final report.
M2M Payments Shifting?
The market-to-market update showed a rare payment of more than $606,000 from SPP to MISO for flowgate congestion along the RTOs’ seams in July, a sign of changing flows.
Since March 2015, MISO has paid SPP $11.2 million from congestion on the 10 most active permanent and temporary flowgates. However, MISO sent less than $632,000 to SPP for March 1 through July 31, 2016, for the 10 most active flowgates.
SPP to Share Z2 Bills This Week
SPP said it will release draft reports this week detailing the approximate payments owed by transmission customers under Attachment Z2 of the RTO’s Tariff.
The reports are the latest step in settling a contentious issue that dates back to 2008, when SPP was to have begun crediting and billing customers for system upgrades. In July, staff said it had identified $848.8 million in assigned costs from 158 creditable upgrade projects.
Members will also receive detailed data files to allow them to validate the results and perform shadow calculations. The draft reports and data files will cover March 2008 through June 2016.
SPP will then make available later this month payment-election forms for entities that owe money. Those companies are required to notify the RTO whether they will pay the full balance or enroll in a payment plan and pay the balance in 20 installments over a five-year period ending in August 2021.
A Macquarie Infrastructure subsidiary has filed with the city of Chesapeake, Va., to build a 1,400-MW combined cycle plant on the Elizabeth River near the site of Dominion Virginia Power’s retired Chesapeake Energy Center.
The plant would use three turbines and one steam generator. It is to be built on land owned by International-Matex Tank Terminals and fueled by natural gas delivered by Dominion Resources’ planned Atlantic Coast Pipeline.
Macquarie CEO James Hooke said the project was a good fit because the company already owns the industrial land near transmission lines and the planned pipeline. It is one of several similar projects planned by Macquarie, including a power plant to be built in Bayonne, N.J.
A severe storm last week severely damaged Minnesota Power’s nearly completed solar array at the Minnesota National Guard’s Camp Ripley base near Little Falls.
The utility said the 10-MW solar array was supposed to be completed last week; instead, 25% of the 97 rows of solar panels sustained damage from the storm’s high winds that sent debris flying, including a storage container that completely obliterated several rows of panels. The facility was built to withstand golf ball-sized hail.
Minnesota Power plans to file an insurance claim and begin replacing broken equipment. When completed, the $25 million facility would largest of its kind on any National Guard base in the U.S.
NIPSCO’s O’Leary to Retire After more than 38 Years
O’Leary
Northern Indiana Public Service Co. President Kathleen O’Leary will retire Oct. 3 after almost 38 years working for the company and its affiliates.
Violet Sistovaris, NiSource executive vice president for NIPSCO, will take on the title of president and shoulder many of O’Leary’s responsibilities while still maintaining her existing position. Sistovaris became an executive vice president for NIPSCO last year.
O’Leary was named NIPSCO president in 2012 and currently supervises NIPSCO’s economic development rates, communications and regulatory and legislative affairs.
AEP Names Sundararajan to Lead FERC, Regulatory Outreach
Sundararajan
American Electric Power has named Raja Sundararajan as its vice president of regulatory services, responsible for interactions with FERC and 11 state regulatory commissions. He replaces Rich Munczinski, who is retiring in December.
Sundararajan joined AEP in 2002 and has been vice president of transmission asset strategy and policy since March 2012. “Raja has proven success in advancing transmission regulatory policy at FERC, with state regulators and in the regional transmission organizations where we operate,” said Bruce Evans, AEP’s chief customer officer.
Sundararajan has a bachelor’s degree in mechanical engineering from the Indian Institute of Technology Madras. He also has a master’s degree in mechanical engineering from the University of Maryland College Park and an MBA from the University of Michigan. He also completed the Executive MBA program at the University of Virginia.
SolarCity Jumps into Austin Market with New Solar Financing Program
SolarCity launched residential service in the Texas capital last week, introducing a new financing program in Austin that offers to install rooftop solar systems with monthly payments starting at $50 a month.
The California-based company recently completed a major solar panel project with grocery giant H-E-B, installing the company’s panel systems at 20 Austin-area stores. It said it would begin hiring workers in the Austin area, starting with 20 to 30 employees with the potential to ramp up to 100 to 120 in the future.
Southern Adds 3rd Facility to Oklahoma Wind Portfolio
Southern Co. subsidiary Southern Power has acquired a third wind farm in Oklahoma, buying the 147-MW Grant Plains Wind facility from Apex Clean Energy. The project is expected to be ready for commercial operation in December.
Southern has already purchased two other wind farms in Oklahoma that were formerly owned by Apex: the adjacent 151-MW Grant Wind farm and Kay Wind, a 299-MW facility in Ponca City.
With the Grant Plains addition, Southern will own more than 2,400 MW of renewable generation from 31 solar, wind and biomass facilities. The company has added or announced more than 4,000 MW of renewable generation since 2012.
American Electric Power has nearly completed the bidding process to sell more than 5,000 MW of merchant generation in Ohio and Indiana.
AEP spokesperson Tammy Ridout said the company would make a decision before the end of the year about the future of the plants: the 2,640-MW coal-fired General James M. Gavin Power Plant in Cheshire, Ohio; the 850-MW natural gas-fired Waterford Energy Center in southeastern Ohio; the 480-MW gas-fired Darby Electric Generating Station, 20 miles south of Columbus; and the 1,096-MW gas-fired Lawrenceburg Generating Station in Dearborn County, Ind., on the Ohio border.
Gavin Power Plant Source: AEP
“We are primarily a regulated utility that provides stable returns for our investors, and we determined that we needed to evaluate whether the risks associated with owning and operating competitive generation fit into our overall strategy,” said Ridout, who said AEP would not discuss potential bidders.
CEO Nick Akins told Bloomberg TV the company has drawn “robust interest” in the plants and expects to make a decision “very soon.”
A sale would cut into AEP’s current generation portfolio of 31,000 MW.
AEP’s acquisitions of the Lawrenceburg, Darby and Waterford plants occurred between 2005 and 2007. Gavin, built in the mid-1970s, is one of the largest coal plants in the nation; AEP has spent millions installing scrubbing technology at the plant.
Ridout said the rest of AEP’s competitive generation in Ohio — representing about 2,700 MW — is also under strategic review, but as part of a separate company evaluation.
AEP began evaluating “strategic options” for its competitive fleet in early 2015, Ridout said. The rest of AEP’s 11-state fleet is under traditionally regulated utility structures with guaranteed rates of return.
Operators of the Wolf Creek nuclear generating station in Kansas are scheduled to meet with Nuclear Regulatory Commission staff to review the failure of an emergency backup diesel generator during a test two years ago. The commission released its preliminary findings of the 2014 incident, when a faulty electrical component kept the emergency diesel generator from starting up when called on.
An EPA update to its Cross-State Air Pollution Rule falls short of what some environmentalists wanted to see. An attorney for the Sierra Club, Zachary Fabish, said the updated rule calls for only “modest” emissions reductions for 22 states in the South, Midwest and East Coast.
A Macquarie Infrastructure subsidiary has filed with the city of Chesapeake, Va., to build a 1,400-MW combined cycle plant on the Elizabeth River near the site of Dominion Virginia Power’s retired Chesapeake Energy Center.
A severe storm last week severely damaged Minnesota Power’s nearly completed solar array at the Minnesota National Guard’s Camp Ripley base near Little Falls.
SolarCity launched residential service in the Texas capital last week, introducing a new financing program in Austin that offers to install rooftop solar systems with monthly payments starting at $50 a month.
Southern Co. subsidiary Southern Power has acquired a third wind farm in Oklahoma, buying the 147-MW Grant Plains Wind facility from Apex Clean Energy. The project is expected to be ready for commercial operation in December.