Hydro-Quebec and Public Service Company of New Hampshire (PSNH) filed a 20-year power purchase agreement with New Hampshire regulators on Tuesday that promises to deliver at least 100 MW of energy during peak hours over the Northern Pass transmission line (DE 16-693).
PSNH parent Eversource Energy hopes to build the line to deliver Canadian hydropower into the ISO-NE market to reduce power price volatility and promote fuel diversity.
The company has cited the PPA as one of the benefits of the Northern Pass, along with economic development and clean energy. The Tuesday filing begins the formal review process before the New Hampshire Public Utilities Commission, which must determine whether the PPA is in the public interest.
The 192-mile project from the Canadian border to Deerfield would have a capacity of 1,090 MW. Officials said New Hampshire consumes about 9% of the electricity used in ISO-NE, so a proportionate share of its capacity is targeted to the state’s customers.
Eversource Energy plans to lay much of the Northern Pass transmission line underground using the open cut trench method shown above. Source: Northern Pass
“This agreement is great news for New Hampshire electricity customers who have been struggling to pay some of the highest rates in the country,” Bill Quinlan, president of Eversource New Hampshire Operations, said in a statement.
Eversource says the PPA will save customers $1 billion over the first 10 years.
“The $1 billion in savings includes the $800 million in savings over a 10-year period as a result of market price suppression brought about by Northern Pass being in the regional market,” spokesman Martin Murray told RTO Insider. “In addition to that savings, the 20-year PPA will provide additional cost savings, and New Hampshire ownership of all the environmental [renewable energy credits] associated with the 100 MW of hydropower.”
Eversource said the PPA will provide its New Hampshire utility with 400,000 MWh of energy per year, Monday through Friday from 7 a.m. to 11 p.m.
Prices are redacted from the contract for competitive reasons, although the document says prices are “based on the MA Hub NYMEX forwards adjusted for delivery to the delivery point.”
Eversource said that New Hampshire retains “most favored nation” rights under the agreement. If Hydro-Quebec negotiates a PPA with another party over the first 10 years for at least 100 MW at more favorable terms, PSNH could demand similar prices.
Three New England states — Connecticut, Massachusetts and Rhode Island — have solicited clean energy proposals from regional suppliers for long-term contracts. Northern Pass is one of more than 30 respondents that are undergoing review, which is expected to be completed in about a month. (See New England States Combine on Clean Energy Procurement.)
Northern Pass has proposed to deliver energy to the three states in the second quarter of 2019, which could be ambitious given the several hurdles it has to overcome. It previously said construction would take two years once all permits were obtained.
The project has been opposed for its visual impacts on tourist-dependent northern New Hampshire, which has led to longer-than-expected reviews. Northern Pass is now before the state’s Site Evaluation Committee. It is also facing a legal challenge from conservationists. (See Northern Pass Challenge Headed to NH Supreme Court.)
CAISO’s regulation costs have quadrupled since the ISO increased requirements to help balance variable output from renewable resources.
Daily payments to regulation service providers jumped from about $100,000 to more than $400,000 after CAISO increased the requirements in late February, according to a report from the ISO’s Department of Market Monitoring.
Regulation prices more than doubled as the ISO increased its daily procurement to as much as 800 MW from 400 MW or less.
The department discounted the likelihood that market manipulation was behind the increase. “We did look at bid behavior and didn’t see it [had] changed,” Gabe Murtaugh, a department senior analyst, said during a call to discuss the report. “We don’t see any evidence of market collusion or anticompetitive behavior.”
CAISO implemented the change Feb. 20, increasing regulation requirements in both the day-ahead and real-time markets to 600 MW. Prior to that, day-ahead requirements were set in the 300-400 MW range, while real-time requirements were consistently pegged at 300 MW.
The Monitor said the ISO procured an average of 617 MW of regulation up and 619 MW of regulation down in the day-ahead market between Feb. 20 and March 31. Procurements reached as high as 800 MW on days when forecasts predicted high variability from renewables.
During that period, day-ahead prices for regulation up and down averaged $14.81/MWh and $12.92/MWh, respectively, compared with $6.50 (up) and $4.16 (down) before the change was implemented. Real-time gained in similar proportion, with regulation up averaging $17.18 and regulation down averaging $21.34.
Regulation prices more than doubled (top) after CAISO increased regulation requirements in late February. The increased prices and volumes procured quadrupled the ISO’s average daily regulation cost to $400,000 (bottom).
Regulation up and down are two of the four ancillary services products the ISO procures through “co-optimization” with the energy market, meaning that resources can bid into both markets simultaneously. Most regulation capacity is acquired in the day-ahead market, with the real-time market run used to cover additional needs or replace unavailable resources.
In addition to receiving a capacity payment, resources that provide regulation service are also eligible for a performance — or mileage — award for in the event they are dispatched. Payments for mileage have historically represented just a fraction of those for capacity.
California Energy Commission analyst Christopher McLean questioned the rationale behind the volume of regulation service the ISO is acquiring.
“Is all that’s being procured being utilized?” McLean asked. “Did it offset any [spinning reserve] procurement?”
Keith Collins, ISO manager of monitoring and reporting, responded that expanded regulation reserves did not reduce the acquisition of spinning reserves — nor could he provide estimates for utilization.
“That’s not something we reported, but we can look into that,” Collins said.
McLean pressed his point, asking if the ISO was using “any sort of formula” to set the regulation requirement, something the Monitor could not confirm.
“So you’re saying there is not any formula,” McLean said. “We’ll be interested in any justification for the change in the procurement level.”
CAISO’s Board of Governors on Tuesday appointed five members to serve on the newly established governing body of the western Energy Imbalance Market.
Candidates were selected after being vetted by a nominating committee representing five industry sectors, including EIM entities, ISO participating transmission owners, power suppliers and marketers, publicly owned utilities and state regulators.
“It was a consensus-driven process,” said CAISO board member Angelina Galiteva, a nonvoting committee member. “It was a successful outcome and can serve as a basis for a larger expansion” of the ISO itself.
PacifiCorp Transmission Vice President and General Counsel Sarah Edmonds, who headed the committee, said the new governing body demonstrated the “diversity of expertise” and independence necessary to oversee the EIM. She also noted its regional diversity.
“In terms of geography, we have the Pacific Northwest, California [and] the desert Southwest” represented on the body, Edmonds said.
Left to Right: Valerie Fong, Doug Howe, Carl Linvill, John Prescott, Kristine Schmidt
The members of the EIM’s new governing body are:
Valerie Fong — Recently retired after serving as the director of utilities for Palo Alto, Calif., from 2006 to 2015. Fong previously had a 20-year career at Pacific Gas and Electric and served on the boards of the Power Association of Northern California, Transmission Agency of Northern California, and the Northern California Power Agency.
Doug Howe — A Ph.D. in mathematics who has authored or co-authored more than 30 papers and presentations covering industry subjects such as energy efficiency in the European Union and utility regulation in the U.K. Howe previously served as a New Mexico state regulator and executive with GPU Inc., which was acquired by FirstEnergy in 2001.
Carl Linvill — Principal at the Vermont-based Regulatory Assistance Project, which produces white papers on energy and environmental issues. Linvill previously served as a utilities commissioner in Nevada and still acts as technical adviser for the Western Interstate Energy Board.
John Prescott — Retired earlier this year after 10 years as CEO of the Portland-based Pacific Northwest Generating Cooperative, a member-owned policy advocate for utility cooperatives in seven Western states. Prescott previously worked at Idaho Power and Seattle City Light and served on the Pacific Northwest Utility Conference Committee and the National Rural Electric Cooperative Association’s Regulatory Standing Committee.
Kristine Schmidt – President of Dallas-based Swan Consulting, which provides advisory services to businesses entering or expanding in the electricity and natural gas sectors. Schmidt was previously a vice president at ITC Holdings and director at Xcel Energy. She also worked as a commissioner adviser at FERC.
Members are appointed for three-year terms, but because this was the first governing body, the ISO board established staggered terms by randomly selecting names. Fong and Prescott will serve until June 30, 2019, Howe and Linvill until June 30, 2018, and Schmidt until June 30, 2017. In the future, all nominations will be subject to approval by the governing body.
DETROIT — MISO’s 2016 spending is in line with its budget for the year, Vice President of Finance Jo Biggers told the Board of Directors at the RTO’s Annual Meeting last week. Year-to-date expenses are $93.3 million, $300,000 under budget. The RTO was able to save about $700,000 with the renegotiated lease of its Carmel, Ind., building, among other factors, but spent an extra $400,000 on resource adequacy efforts, including capacity auction redesign and seasonal and locational constructs.
The RTO was allotted a $225 million operating budget in 2016. It currently expects to spend between $224.7 million and $225.5 million by the end of the year.
Biggers said that although MISO is $4.1 million under budget on capital expenses to date, it expects to spend most or all of the $31 million capital budget by year-end.
Board member Phyllis Currie said the board’s Audit and Finance Committee is considering whether the RTO should file for 501(c)(3) status. MISO is currently categorized as a 501(c)(4), a social welfare organization; 501(c)(3) status would designate it a charitable organization.
Weber Source: IURC
“Over time, we’ll look at the pros and cons. It’s a good time to take a look at this,” Currie said. MISO could benefit from tax-exempt status, especially when considering the amounts it may need to borrow over the next five years, she said.
Stakeholders Join Nominating Committee
Indiana Utility Regulatory Commissioner Angela Weber and Matt Brown, vice president of federal policy at Entergy Services, have joined MISO’s Nominating Committee, filling the two stakeholder vacancies, board member Michael Curran reported.
A retired elementary school teacher goes to Washington to take on a powerful utility — and wins a $4.2 million refund.
A David and Goliath story?
“It certainly felt that way,” says Martha Peine (pronounced “piney”), a former lawyer who hadn’t practiced since 2002. “I was dealing with rules and regulations and procedures I had never been familiar with. It was just me … funding my own way against what I consider a behemoth organization, with outside and inside counsel with many years of experience.”
The “behemoth” in question is American Electric Power, owner of the nation’s largest transmission system, with a market capitalization of more than $32 billion and more than 5 million customers in 11 states.
Peine received her law degree from the University of Texas and spent seven years as a sole practitioner specializing in “consumer-type” issues, before taking down her shingle in 2002. She spent the next nine years as an elementary school teacher and lecturer for the Houston Independent School District.
Ozark Mountain Tx Fight
Several years ago, Peine found herself involved in a community effort to fight AEP subsidiary Southwestern Electric Power Co.’s plans to build a transmission line through the scenic Ozark Mountains in Northwest Arkansas. A grassroots organization, Save the Ozarks, spun up enough community support around the eccentric town of Eureka Springs, a haven for artists and retired hippies, that SWEPCO withdrew its plans in December 2014.
By then, Peine was submerged in AEP’s filings at FERC, trying to make sense of transmission formula rates, protocols and operating tariffs. Poring over the company’s annual updated filings to its formula rate under SPP’s Tariff, she uncovered and contested almost $2.5 million in improperly recovered transmission costs for charitable contributions, general advertising, economic development, lobbying, and generation and distribution regulatory cases.
Peine
So what kept Peine going in what must have appeared early on to be a quixotic quest?
“Just determination. Pure determination,” she said. “I wasn’t going to give up until someone said, ‘Go home and don’t you ever come back here again.’ I just kept putting one foot in front of the other.”
Using her forensic skills and invoices provided by AEP, Peine was able to determine whether the company’s expenses were properly accounted for under FERC regulations. She contested air travel for SWEPCO President Venita McCellon-Allen to attend legislative meetings and a luncheon honoring former Arkansas Public Service Commissioner Colette Honorable before her appointment to FERC. She also contested a tree-planting program around SWEPCO’s Turk power plant in southwest Arkansas.
‘Drilling Down’
“Drilling down to the actual invoice is something that rarely happens,” Peine said, making sure she put quotes around “reviewed” when describing her understanding of how regulators and wholesale purchasers may check the annual updates. “They look at the delta from one year to the next and ask generally about it.”
A FERC staff review after her complaint found additional improper charges in SWEPCO sister company Public Service Company of Oklahoma’s AEP’s rate structure.
On June 13, Peine and AEP reached a $4.2 million settlement agreement.
The money will be distributed as a one-time credit to utilities using AEP’s SWEPCO and PSO transmission systems (ER07-1069). “I think it was a good result, a substantial refund, and I’m happy with that,” Peine said. “I followed through, I stayed committed … I think this was a right result for ratepayers.”
Pat Costner, director of Save the Ozarks, said in a press release, “Every SWEPCO electric customer owes a debt of gratitude to this remarkable woman, who has shown us that one person can make a big difference.”
It didn’t come easy, but pro se interventions — in which intervenors represent themselves — never are. Peine said she used a template provided by Keryn Newman and Alison Haverty, who successfully challenged AEP and Allegheny Energy (now FirstEnergy) in their bid to recover $121.5 million from an abandoned PJM project. (See FERC ALJ Rejects $10 Million in PATH Transmission Project Recovery.)
“That made my job much easier,” said Peine, who followed the case closely and attended several days of FERC hearings on the matter.
Peine’s interest was piqued during her work with Save the Ozarks. She asked herself, “What’s in it monetarily for these people? How do they recover costs? What’s the motivation there?”
She spent hundreds of hours on her challenges. She familiarized herself with the protocols and SPP’s Tariff. She learned how to file preliminary and formal challenges. And she researched FERC’s eLibrary database from the comfort of her home. “Everything is filed,” Peine marveled.
Proving Standing
Before filing her challenges, Peine had to first gain standing. She said AEP “quibbled” at first: Peine and her husband have a summer home in Eureka Springs, where they will eventually move to from Houston. It took a copy of Peine’s electric bill to prove she had standing.
Peine had to prove her standing again once the commission set her challenges for hearing. Administrative Law Judge Carmen Cintron recommended the commission find that ratepayers don’t have standing under the Federal Power Act. But FERC staff, the Electricity Consumers Resource Council and others strongly objected to Cintron’s interpretation, and the commission reconfirmed Peine’s standing.
She said she became aware in August 2013 of AEP’s formula rate updates to the SPP Tariff, which it files on behalf of SWEPCO and PSO each May. Peine said she asked AEP for electronic submission of the underlying documents in the filing but was told to come up to the company’s headquarters in Columbus, Ohio, to look at them.
“If you’re having a dispute like that, you can request a FERC administrative law judge to act as a discovery master,” Peine said. “Things were resolved that way. Certain documentation I never got, but we moved forward anyway.”
When Peine’s preliminary challenge was not resolved, she filed a formal challenge in January 2014. She followed the same process in challenging AEP’s May 2014 update to the formula rate.
Peine disputed the recovery of $92,511 in costs for 2013 and $2,467,024 for 2014 in her formal challenges, which were set for settlement proceedings in August 2015. The two sides exchanged and rejected offers and went through two ALJs before reaching a final agreement.
“The settlement will completely resolve all issues in the current proceeding,” said SWEPCO spokesperson Carey Sullivan, noting the agreement has yet to be approved by FERC. “The parties agree that the settlement is fair, reasonable and in the public interest.”
The settlement makes it clear that “directly assignable” AEP’s charges recovered under its formula rate after July 1 “shall mean expenses directly related to the provision of transmission services, and does not include those general, company-wide expenses that may be allocated partially to transmission.”
The parties said the settlement addresses issues “both retrospectively and prospectively,” through the ratepayer refund and by “explicitly excluding certain expenditures from recovery under the AEP formula rate.”
But while the settlement is signed, Peine says the proper recovery of rate expenses going forward is “not a resolved issue.”
“I will always wonder what mistakes there may be in the years to come,” she said. “Some [SWEPCO employees] wear so many hats and have multiple functions — public relations, lobbying and outreach to officials — it’s difficult to separate out what’s recoverable and what isn’t in a situation like that.”
Germany’s Siemens and Spain’s Gamesa will merge, creating the world’s biggest wind farm builder. Siemens will pay $1.13 billion for 59% of the company, which would pass Denmark’s Vestas to become the world’s largest wind farm manufacturer by market share.
The merger combines Siemens’ strength in offshore turbines and Gamesa’s specialty in onshore wind. The companies have a combined 69 GW of installed capacity.
“The proposed merger is a sign of the strength of wind energy technology and the demand for wind expansion,” said Jeff Clark, executive director for The Wind Coalition. “These two companies are positioning themselves to participate in a more robust global marketplace where wind is becoming mainstream, and pricing among suppliers is becoming more competitive.”
Energy Transfer Can Back Away from Williams Merger
A Delaware Chancery Court judge has ruled that Energy Transfer Equity can back out of the planned $33 billion merger with Williams Cos. because its experts could not be sure the deal would be tax-free, a condition for closure.
Glasscock
Williams’ attorneys had argued that Energy Transfer was only trying to get out of the deal because of the downturn in the oil industry. But Vice Chancellor Sam Glasscock III ruled that he didn’t think the company’s lawyers were trying to pull a fast one when they said they could not determine whether the deal would expose investors to tax liabilities.
“Just as motive alone cannot establish criminal guilt, however, motive to avoid a deal does not demonstrate lack of a contractual right to do so,” Glasscock III said. Williams is expected to appeal the ruling.
National Grid and NextEra are proposing to build New York’s largest solar farm on 350 wooded acres near the decommissioned Shoreham nuclear plant on Long Island.
The proposal was submitted in response to a Long Island Power Authority/ PSEG Long Island request for proposals for clean energy. The 72-MW project is part of the companies’ LI Solar Generation joint venture. If selected, the $100 million project would be operating by 2020.
Local officials and some conservation groups are opposed to locating the project at an undisturbed natural area.
Wolverine Power Supply Cooperative last week fully commissioned the 205-MW Unit 1 at the company’s new Alpine Power Plant, a natural-gas fired peaking facility in northern Michigan.
Along with the plant’s Unit 2, which came online in May, the 410-MW plant can supply power to nearly 120,000 homes.
The plant employs two simple-cycle GE Frame 7F.05 combustion turbine generators.
A bankruptcy court judge in St. Louis approved Peabody Energy’s plan to pay retention bonuses to “mission critical” nonexecutives to keep them from jumping ship as the energy giant navigates through Chapter 11 bankruptcy.
Judge Barry Schermer ruled in favor of the company’s request to pay as much as $3.4 million to about 40 white-collar employees at its St. Louis headquarters. The United Mine Workers of America objected, saying the company already cut $70 million in retiree health plans in an attempt to stay solvent, and the union sees this as more money leaving its members.
“Slashing the health benefits of aged and medically vulnerable retirees with extremely limited resources, while lavishly rewarding white-collar employees, is neither fair nor reasonable,” the UMWA said in filings.
Exelon announced plans to build a 200-MW wind farm in Ohio, its first in that state. According to filings, it would erect 87 turbines on 25,000 acres in four Seneca County townships, in northern Ohio.
The company has 47 wind farms in 10 states, for a total of 1,491 MW of capacity. While it is the nation’s 12th largest wind producer, wind makes up only 4% of its generation portfolio. Nuclear makes up two-thirds, but those plants have been struggling.
Ohio has only two wind farms operating; many potential wind developers have put their proposed projects on hold, citing concerns about the state’s legislature ending its renewable portfolio standard.
An investigation commissioned by Energy Northwest’s executive board has cleared company managers of accusations that they attempted to conceal falling performance measures at the Columbia Generating Station, the company’s sole nuclear plant.
While the probe by Pillsbury Winthrop Shaw Pittman confirmed that standards at the plant have declined, it found no evidence of a deliberate cover-up by managers.
The investigation was launched after company whistleblowers raised the allegations in regional media.
Westar Energy last week issued $350 million in “green bonds” to finance renewable energy projects in Kansas.
Most of the funds will go to constructing the Western Plains Wind Farm, a 280-MW facility that the company has said would go online in 2017.
The Climate Bonds Initiative says the green bond market has grown from $2.6 billion in 2012 to $41.8 billion last year. Green bonds are like conventional fixed-income bonds, except they are marketed to investors who want to target projects that promote climate or other environmentally sustainability projects.
Kip Fox, American Electric Power’s director of transmission asset strategy and grid development since 2013, was named president of Electric Transmission Texas last week. Fox will report to Wade Smith, AEP’s senior vice president of grid development.
Fox joined AEP in 2008 as senior manager in the RTO regulatory department, where he was responsible for coordinating and consensus building with SPP and ERCOT. Electric Transmission Texas, which is jointly owned by subsidiaries of AEP and Berkshire Hathaway Energy, was formed in 2007 to construct, own and operate transmission facilities as a regulated utility in ERCOT.
Fox replaces Calvin Crowder, who left for GridLiance in May.
Xcel Energy said last week it is seeking regulatory approval in Texas and New Mexico for a 240-mile, 345-kV transmission line between the states. The company said the $400 million project will meet the region’s significant increase in electricity demand.
The line would connect the TUCO substation in Abernathy, Texas, to the China Draw substation in Eddy County, N.M. Xcel hopes to complete the project by 2020.
David Hudson, president of Xcel subsidiary Southwestern Public Service, said the project “ensures power can move freely into one of the nation’s most prolific oil- and gas-producing regions, which also happens to be rich in agricultural and mining resources and renewable energy prospects as well.”
SunEdison CEO Resigns; Replaced by Restructuring Expert
Chatila
Ahmad Chatila, CEO of bankrupt solar energy developer SunEdison, has resigned and will be replaced by John Dubel, who has served as the company’s chief restructuring officer since April 29.
Chatila, 49, notified the company June 16 of his decision to resign after seven years as CEO. He won’t receive any severance, in accordance with his current employment agreement.
Dubel, 57, most recently was CEO of Financial Guaranty Insurance Co., and prior to that he was a partner in hedge fund Gradient Partners. He also heads Dubel & Associates, a restructuring and turnaround services provider he founded in 1999.
Exelon says it is hundreds of millions of dollars short of the funds it needs to restore the Clinton and Quad Cities nuclear plant sites after the generators are taken offline in the coming years.
Exelon said in a June 2 Securities and Exchange Commission filing that it might have to put up an additional $790 million for cleanup. Federal rules require nuclear operators to maintain a fund for eventual reclamation. The company announced last month it would shutter Clinton next June and Quad Cities in 2018 after failing to win subsidies from the Illinois General Assembly. (See Exelon to Close Quad Cities, Clinton Nuclear Plants.)
Federal rules also allow operators up to 60 years to clean up nuclear generator sites. Exelon has not said how long it will take to complete the work.
Three California utilities top the rankings for renewable power as a share of total sales, according to a report released Tuesday by Ceres, a nonprofit organization that seeks to encourage companies and investors to act on climate change.
The report said Sempra Energy (parent of San Diego Electric & Gas), Pacific Gas and Electric and Edison International (Southern California Edison) topped its ranking of the 30 largest electric utility holding companies, each with renewables representing more than 23% of sales — more than double the median of 10.2%. Consolidated Edison, American Electric Power and Florida Power & Light were at the bottom of the list with less than 1%.
A Wyoming federal judge’s ruling last week striking down the Obama administration’s regulations on fracking on federal lands will save operators about $113,000 per well, according to an industry-sponsored analysis.
The study, which was performed by John Dunham & Associates at the request of the Western Energy Alliance, found that the regulations by the U.S. Bureau of Land Management would have added at least $403 million annually to well development costs.
The regulations would have affected several thousand wells each year on federal and Indian lands, either as new drilling or maintenance of existing wells. The majority of the lands are in western states and the Gulf of Mexico.
Wyoming, Colorado, Utah, North Dakota and the Ute Indian Tribe challenged the regulations in a case that was combined with a separate suit by WEA and the Independent Petroleum Association of America.
The regulations, which were to take effect in June 2015, were stayed pending the outcome of the case.
While the breakdown between oil and gas wells was unclear because federal statistics don’t separate them, U.S. Energy Information Administration data show that the average cost to develop a natural gas well has been steadily rising to more than $600/foot as of 2007, which is the most recent information the agency provides. EIA reported the average total well cost at nearly $4 million.
Fossil fuel production on federal and Indian lands, FY 2014 Source: U.S. Energy Information Administration based on U.S. Department of the Interior, Office of Natural Resources Revenue.
In his ruling, U.S. District Judge Scott Skavdahl explicitly avoided the question of whether or not the regulations are necessary and instead focused entirely on BLM’s authority to enact them (Case Nos. 2:15-CV-043-SWS, 2:15-CV-041-SWS).
Dismissing the agency’s arguments that it has jurisdiction through several tangential regulations, Skavdahl searched for specific delineation of authority from Congress. He found that the Safe Drinking Water Act requires EPA to adopt requirements for state programs to prevent underground injection from threatening drinking water sources.
He also cited the Energy Policy Act of 2005, which expressly excluded federal oversight of fracking that doesn’t involve diesel fuel.
Skavdahl rejected BLM’s argument that the generalized authority the agency cited would supersede the more specific SWDA and EPACT.
“Given Congress’ enactment of the [Energy Policy] Act of 2005, to nonetheless conclude that Congress implicitly delegated BLM authority to regulate hydraulic fracturing lacks common sense,” he wrote. “Congress’ inability or unwillingness to pass a law desired by the executive branch does not default authority to the executive branch to act independently, regardless of whether hydraulic fracturing is good or bad for the environment.”
The administration filed an appeal on Friday. “We believe that we have a strong argument to make about the important role that the federal government can play in ensuring that hydraulic fracturing that’s done on public land doesn’t threaten the drinking water of the people who live in the area,” White House spokesman Josh Earnest said during a press briefing on Wednesday.
NEW YORK — Whether the view is from PJM, which sits atop the Utica and Marcellus shale gas formations, or ISO-NE, at the “end of the pipeline,” the so-called “dash to gas” shows no sign of abating, speakers said Friday at the Energy Bar Association Northeast Chapter’s 2016 Annual Meeting.
“There’s a fairly high degree of confidence in the market that gas prices will be consistently low for a fairly long time,” said Vince Duane, senior vice president and general counsel at PJM. Of 36,000 MW of PJM generation that has retired in the last two decades, about 30,000 MW of the units replacing them are natural gas, he said.
Duane said that while the energy industry has “done a very poor job of forecasting prices and deploying capital” in the past, “the markets are [now] giving such an overwhelming signal” to choose gas.
In response to calls by FirstEnergy, American Electric Power and Exelon for subsidies to keep coal and nuclear plants operating, Duane co-authored a recent PJM study that counseled against such interventions. (See PJM Study Defends Markets, Warns State Policies can Harm Competition.)
“I do take issue with the idea that the entire nuclear fleet is at risk across the board. There’s always been well-run nukes … and the well-located ones are doing well,” he said, calling the predicted demise “hyperbole.”
Duane said markets have responded to environmental regulations in unexpected ways. EPA’s Mercury and Air Toxics Standards rule “is kind of a national experiment in that it’s imposing costs on every coal plant, whether it’s in an organized market or a regulated market,” Duane said.
“I thought I was going to write [that] the unregulated markets were ruthlessly efficient and regulated markets [were] holding onto that invested capital longer. We cut it every which way: the age of the resource; the size of the resource; the heat rate efficiency. And every time, we came up with no statistical difference … as both are doing a comparable job of pushing out the inefficient coal resources.”
Even where gas supplies are distant, market signals still point toward that fuel source.
“We are having more gas units come in through our capacity auctions, but we haven’t really had any gas infrastructure built,” said Kevin Flynn, senior regulatory counsel at ISO-NE.
Natural gas provides about half the energy in New England now, up from about 15% in 2000.
And as policymakers mandate more renewable energy resources, their integration requires more quick-start resources, usually natural gas, to maintain system balance, he added.
Because inadequate gas supplies exist during winter cold snaps, ISO-NE added its Pay-for-Performance program to incentivize generators when they’re needed most. It starts in 2018.
More than 3,000 MW of gas-fired generation has cleared in the last two Forward Capacity Auctions. “What we found in FCA 10 is that all gas resources that cleared are dual-fuel, as that’s the way the market is responding to Pay-for-Performance,” Flynn said. (See FERC Accepts ISO-NE Auction Results.)
The region has lost most of its coal fleet, and much of its nuclear generation is at risk. Vermont Yankee closed at the end of 2014, and Pilgrim in Massachusetts will leave the market in 2019.
Two nuclear units in New York are at risk, as the James A. FitzPatrick plant is set to close in the spring, and the R.E. Ginna plant could follow at the end of its reliability support services agreement, also early next year.
From 2010 to 2016, 11,665 MW of generation was built to replace aging or retiring units, representing about a quarter of the state’s total capacity of 39,000 MW, NYISO Assistant General Counsel Carl Patka said.
“We’re seeing a greater amount of deactivation notices, especially in western New York. Not a great surprise to see some of the older coal units” retiring, he said.
The retirements will make it a challenge for NYISO, which has a reserve margin of 20%, to maintain its reliability.
DETROIT — MISO’s Independent Market Monitor added eight new recommendations in its 2015 State of the Market Report.
The 124-page report concluded that MISO’s energy and ancillary markets “generally performed competitively” last year.
Monitor David Patton outlined the recommendations, four of which involve resource adequacy and planning, before the Markets Committee of the Board of Directors on Wednesday:
Energy Pricing and Transmission Congestion
Disable price setting by offline resources in extended locational marginal pricing (ELMP) and expand the share of online generators eligible to set prices to include those with start times of one hour or less and minimum run times of two hours or less, regardless of whether they are scheduled in the day-ahead market.
MISO has proposed increasing the share of online peaking resources able to set prices to 14% from the current 2% in ELMP Phase II, which would eliminate $4.4 million in revenue sufficiency guarantee (RSG) payments. Patton said the RTO should permit pricing by 90% of online peaking resources, which he said would eliminate $20 million in RSG payments.
The Monitor said offline resources should only set prices when they are economic and can be started quickly to address a shortage — a threshold it said was met by less than 10% of the offline resources that currently set prices. “Accordingly, we conclude that ELMP’s offline pricing is inefficiently changing prices during shortage conditions and recommend that MISO disable the offline pricing logic as quickly as possible,” the report says.
Board member Paul Feldman said the negligible benefits of ELMP were “disappointing.” (See “‘Modest’ Price Impacts as Extended LMP Enters Phase 2,” MISO Market Subcommittee Briefs.)
Jeff Bladen, executive director of MISO market services, said ELMP Phase I was “designed to be conservative” and that MISO is analyzing the Monitor’s recommendation.
Increase use of temperature-adjusted and short-term emergency ratings for transmission facilities.
Guarantee Payment Eligibility Rules and Cost Allocation
Begin modeling the voltage and local reliability requirement in the day-ahead market.
Improve Dispatch Efficiency and Real-Time Market Operations
Address “poor” dispatch performance and state estimator model errors in real-time operations by improving tools and procedures.
Resource Adequacy and Planning
Implement firm capacity delivery procedures with PJM instead of using pseudo-tied resources.
The Monitor said a firm capacity approach with PJM “would guarantee the delivery of the energy from MISO capacity resources to PJM, while maintaining the efficiency and reliability of MISO’s dispatch.”
In its quarterly report for spring 2016, Patton said 100 new market-to-market flowgates were created between March and June when MISO pseudo-tied 22 resources to PJM territory. Congestion on the new constraints totaled $22 million for the quarter, a six-fold increase over the first quarter.
Patton said the M2M process doesn’t have an efficient enough response for pseudo-ties positioned farther from the seam.
The next batch of pseudo-tied resources to be committed outside of MISO will occur in June 2017.
“We expect higher congestion as this process unfolds. We hope PJM gets tired of these high prices … and bearing the cost of MISO congestion. It’s certainly bad for the Eastern Interconnect,” Patton said.
However, PJM has said it will not consider firm capacity delivery as an alternative to continue pseudo-ties, he said.
MISO CEO John Bear said the RTO is discussing the issue with PJM but doesn’t expect a resolution until the middle of 2017.
“I’d encourage both parties to go back to the beginning,” board member Michael Curran said. “Untying this knot could be more difficult than going back to the beginning and saying, ‘how did we get here?’”
Improve the modeling of transmission constraints in the Planning Resource Auction.
Improve the physical withholding mitigation measures for the PRA by addressing uneconomic retirements and recognizing affiliates.
The report says falling capacity margins will leave MISO more vulnerable to physical withholding and cites Tariff provisions that it says prevent the RTO from addressing it. “First, the physical withholding thresholds are applied on a market participant basis, rather than a company basis. This would allow a large supplier to create multiple market participants to effectively circumvent the mitigation. Second, it is not clear [that] retiring a unit that is clearly economic to continue operating would be considered physical withholding and subject to MISO’s mitigation measures.”
Improve modeling of the limit on transfers between MISO South and Midwest regions in the PRA.
MISO’s recent settlement with SPP and other parties allows the RTO to transfer as much as 2,500 MW from MISO South to Midwest. But in the most recent PRA, MISO set a limit of only 874 MW.
The Monitor said the transfer limit in the PRA should equal the total transfer limit minus a derating factor that represents the probability that MISO neighbors will request a derating because of an emergency. “This recommendation would have had a substantial effect on the clearing prices in most of the Midwest zones in the most recent PRA for planning year 2016/17,” it said.
Incentives for New Investment Lacking
Curran said the board would schedule a conference call with MISO and the Monitor for a more in-depth conversation on the remaining recommendations.
Patton said long-run price signals continue to discourage new investment, with net revenues declining in 2015. The Monitor noted the $27/MWh average electricity price was 32% lower than in 2014. Natural gas prices fell 50% for the year to their lowest levels since MISO launched its energy markets in 2005.
Milder weather in 2015 caused average load levels to fall 2% from 2014. The peak load of 120 GW, set in July, was well below the forecast peak of 127.3 GW.
Gas-fired generation increased its share of total output from 17% to 23% over the year. Gas-fired resources were central to price-setting, “setting the system marginal price in 76% of intervals and locational prices somewhere in MISO in 95% of intervals,” the report said.
Patton said the spring 2016 quarter was competitive, attributable in part to continued low natural gas prices. The average cost of energy was $21.50/MWh, about 20% lower than in spring 2015.
Board member Thomas Rainwater asked how much MISO’s market would have to value carbon to incentivize continued operation of nuclear units. Patton said if carbon was valued at $20/short ton, nuclear resources would be closer to recovering costs. Patton also said expansion of wind generation is not the most cost-effective means to reduce carbon but is currently economic because of subsidies.
Board members expressed concern that the Monitor’s report included capacity margin values for the summer that differed from the RTO’s projected 18.2% summer reserve margin.
The Monitor’s base case scenario predicted a 20.5% margin because Patton said the 1,000-MW North-South transfer limit is too “pessimistic.” For its margin, MISO assumes 1,203 MW of capacity in MISO South cannot be accessed because of the North-South transfer limit. However, in the Monitor’s one-year-in-10 scenario, in a high-temperature, high-load forecast, the reserve margin falls to 11.6%.
Board members questioned the disparate reserve margins and asked why the board wasn’t presented with them during MISO’s summer readiness presentation. (See “MISO Prepped for Summer Demand,” MISO Markets Committee of the Board of Directors Briefs.)
“If MISO doesn’t see the world in the same way, our numbers may not match,” Patton said, reminding the board that the Monitor is independent of MISO.
Board members asked that Patton display his results alongside MISO’s in future summer readiness presentations. MISO and the Monitor agreed.
MISO’s Shawn McFarlane also delivered the RTO’s quarterly report during the meeting:
Average load for the spring was 86.3 GW, 2.7% lower than last spring.
Natural gas prices averaged $1.87/MMBtu, a 34.2% decline relative to spring 2015.
Total forced and planned generation outages accounted for 23.8% of market capacity: Planned outages averaged 23.6 GW, an 18% drop from spring 2015; forced outages averaged 19.3 GW, up 5.5%.
Average wind generation increased to 5.6 GW, 4.5% higher than last spring. Wind production was 4,934 GWh in April, setting a new monthly record.
FERC is taking another look at its April orders approving the cost allocations for a stability fix for New Jersey’s Artificial Island nuclear complex and an upgrade of the Bergen-Linden Corridor.
The commission issued orders June 21 granting rehearing — a technical step to allow it more than 30 days to reconsider complaints that PJM’s use of the solution-based distribution factor (DFAX) cost allocation method is inappropriate for the two projects (EL15-95, ER15-2563 and ER15-2562, et al.).
In the case of the Artificial Island project, the public service commissions in Maryland and Delaware, along with some transmission owners, complained that the customers they represent will bear the brunt of the cost of the fix while receiving a small percentage of load savings.
Similarly, Consolidated Edison and Linden VFT disputed the fairness of the Bergen-Lindon Corridor upgrade cost allocation.
“We know this is only one step in the process of continuing to fight the current proposal, but we are encouraged by the opportunity to again make the case to FERC that the current cost allocation scheme is both unjust and unreasonable,” Delaware Gov. Jack Markell said in a statement.
