Those words, which NYISO CEO Brad Jones uses frequently, are themes echoed throughout the 2016 NYISO Power Trends report.
New York’s Reforming the Energy Vision, the Clean Energy Standard (CES), distributed generation and customer engagement also feature prominently in the report, which was released today.
“The power market is changing as much or more than I’ve seen it in the last 20 years,” Jones told RTO Insider in an interview. “It’s a fantastic place for the NYISO to be in, in the middle of all this dramatic change.
“We wring our hands around here all the time, but I feel very good that we have the capabilities here to meet these challenges,” Jones continued.
Nuclear Power
Part of the hand-wringing concerns the possible loss of much of the nuclear fleet, which is unable to earn sufficient revenues in an energy market dominated by cheap natural gas. New York’s average wholesale electric energy price last year was $44.09/MWh, the lowest in the 15-year history of the state’s competitive markets.
Without a financial lifeline, three nuclear plants in western New York are under threat of closure in early 2017. State regulators are considering a zero-emission credit to subsidize the upstate plants.
The CES requires the state to procure 50% of its energy from renewable resources by 2030. That would require 75,000 GWh of renewable power annually, according to an estimate by the state Public Service Commission. By themselves, that goal would require either 25 GW of solar, 15 GW of wind or 4 GW of hydro, most of that in northern or western New York, far from the load centers in and around New York City.
The city, Long Island and the Lower Hudson Valley use 58% of the state’s electricity. But while more than 80% of the new generation since 2000 has been downstate, the region still produces only 40% of the state’s total, the report notes.
“What this speaks to is the need for more transmission,” Jones said. “Transmission is the key for us to be able to move green power from remote areas to the high-demand areas of the state.”
Flat Load Growth
The increasing shift to renewables will come during a period of flat load growth. “Year-over-year growth in the overall usage of electric energy from New York’s bulk electric system is expected to flatten or decline slightly over the next decade,” the report says.
Other trends highlighted in the report include:
Shifting patterns of electricity demand because of energy efficiency and distributed energy resources: “Distribution-level solar photovoltaics, in 2016, have an estimated summer capability of more than 250 MW. That total is expected to triple by 2026.”
Aging infrastructure requiring replacement and upgrades: “More than 80% of New York’s high-voltage transmission lines went into service before 1980. Of the state’s approximately 11,000 circuit-miles of transmission lines, nearly 4,700 circuit-miles will require replacement within the next 30 years, according to New York’s transmission-owning utilities and power authorities.”
Increasing choices for customers as a result of public policies aimed at reducing emissions and expanding renewable power.
The report concludes with a plea to continue the state’s commitment to competitive markets — a commitment some observers say could be undermined by generation subsidies and long-term contracting for clean power.
The report notes that five of the seven reliability assessments the ISO has conducted since 2005 identified emerging reliability needs. “In each case, markets responded with resources to address those needs, avoiding the need to call upon regulatory solutions,” the report notes.
CARMEL, Ind. — MISO and its Independent Market Monitor have developed a compromise auction design calling for a prompt, single Planning Resource Auction with separate prices for competitive retail areas.
But that isn’t stopping the RTO from also keeping its original forward auction proposal on the table, a proposal Monitor David Patton says is not viable.
“We don’t believe there is one definitive solution forward, but we do believe we have two very good options in front of us,” MISO executive director of market services Jeff Bladen said during a two-day Resource Adequacy Subcommittee meeting Wednesday and Thursday. “We’re deep into the weeds of evaluating both for price stability.”
Bladen said MISO has hired The Brattle Group to conduct an analysis on both proposals and will select a plan based on the results.
The hybrid competitive retail solution marries elements from earlier proposals by the Monitor and MISO. With it, the RTO could abandon its proposed three-year forward auction for deregulated sections of the footprint in favor of the IMM’s multi-stage prompt auction in which only merchant supply could receive competitive retail pricing set by a systemwide sloped demand curve.
Assets controlled by a load-serving entity whose demand is outside a competitive retail zone would be precluded from clearing at the competitive retail price. MISO’s forward proposal would allow non-merchant generators to offer into the separate, retail choice auction.
Two-Stage Auction
The hybrid proposal would deliver the auction in two stages: Immediately after the competitive retail stage of the auction is cleared, the PRA, with traditionally rate-regulated supply and demand, would take place. The PRA would be referred to as the “legacy” stage of the auction and would continue using the current vertical demand curve.
Fixed resource adequacy plans remain the same under the two proposals; LSEs would have to create plans on a forward basis to opt out of serving retail-choice load.
“I think the hybrid prompt proposal would work,” Monitor David Patton said after multiple stakeholders asked for his opinion. “I’m confident the forward proposal would produce more volatility than the hybrid proposal.”
Patton said the hybrid proposal’s sloped demand curve could be adjusted by MISO to correct instances of over- or under-procurement.
Dynegy’s Mark Volpe asked for Patton’s view on both proposals.
Patton said the forward proposal MISO is continuing to consider is not structured to produce an efficient price and does not represent a compromise. “It may not surprise you that I don’t think the forward proposal is not a viable proposal,” he said . …We’re going to be providing some information regarding the price that you get under both proposals at the next meeting,” he said.
Bladen countered that the hybrid approach could produce volatility. He also said MISO’s Tariff would have to undergo extensive revision to implement the hybrid proposal.
“While it has theoretical elegance, the practical application is questionable,” Bladen said. “FERC is the ultimate judge.”
Stakeholders asked if either proposal had been reviewed by FERC staff.
Bladen said although commission staff has been following MISO’s deliberations “FERC would never give advance notice on what they would approve.”
Bladen also said he didn’t have an estimate on when draft Tariff language would be in front of stakeholders, but he did say it would be “very difficult to achieve” implementation in time for the 2017/18 planning year.
“I wish I could give an exact date when we’re going to walk into the room and announce the selected proposal,” he said.
Forward Proposal Still Unfinished
MISO has yet to offer a demand curve shape for its forward proposal for deregulated areas. Bladen said the final shape is “pending further Brattle Group analysis” but the resulting shape would most likely resemble shapes used by other RTOs. MISO has asked Brattle to look at broader, New York-style demand curves that have more megawatt breadth as well as the narrower PJM-style demand curve, he said.
The RTO’s forward proposal also has yet to identify the “hurdles” rate-regulated supply could face when electing to participate in deregulated areas. Bladen said MISO is working with Brattle on restrictions.
“MISO does not want to be a party to any LSE selling itself short,” Bladen explained.
Stakeholders: Give Us the Evidence
Stakeholders sought more evidence that either proposal would work, with several asking MISO to run simulations using the 2016/17 planning year offers.
Indianapolis Power and Light’s Ted Leffler asked if simulations have been run at all.
“We’re working on it. The short answer is it’s complicated,” Bladen said. He said both MISO and the IMM would come back with simulations and concrete examples, but their results could differ.
Bladen also said there has been “a high lack of understanding [among stakeholders] on how these proposals would work.”
Susan Satter, public utilities counsel for the Illinois attorney general’s office, asked at what point regulated suppliers would supply load in Zone 4 using a hybrid model. Bladen responded that regulated suppliers would influence the competitive retail price by contributing to the systemwide demand curve. He added the systemwide demand curve is needed so deregulated areas contribute to footprint-wide resource adequacy.
“In a sense, [rate-regulated load-serving entities] are providing a moderating service on the competitive retail price,” Bladen said. “While they’re not being explicitly committed to serving load, they’re implicitly moderating the price … versus if there was only merchant generator participation.”
Stakeholders asked if MISO’s forward proposal would guarantee lower prices.
“I’m hesitant to say anything in life is a guarantee,” Bladen responded. But he added that the forward proposal’s price mechanism should produce lower prices. “We think the proposal has legs.”
Initial stakeholder feedback on the hybrid and forward proposals is due July 7.
An additional special meeting of the RASC will take place July 14, at which stakeholders are again expected to discuss the hybrid proposal. Bladen promised Brattle representatives would be on hand to explain their analysis of both proposals and answer questions.
“One of these proposals will fall by the wayside, unless they’re miraculously merged, which I don’t think will happen,” said RASC Chair Gary Mathis.
MISO Contemplates Outages in Seasonal Capacity Accreditation
Stakeholders have said some planned outages during peak hours are appropriate under certain circumstances: when a unit is undergoing a one-time upgrade, when a unit hasn’t cleared the capacity auction or when weather is mild.
Currently, MISO’s planning reserve margin does not make room for any planned or maintenance outages during peak times. Rauch said the RTO is weighing increasing the reserve margin or reducing individual units’ capacity accreditations to reflect the risk of outages during peak hours.
“We’re still trying to get the point where we identify and clear what’s needed under a two-season construct,” said Rauch.
MISO’s locational filing, which would create external resource zones, is still being examined.
“One of the things stakeholders requested is more transparency and more clarity on how local resource zones would be run in the auction,” Rauch said. “Our homework is to come back with some better examples.”
Further discussion on MISO’s seasonal and external zone constructs is expected at the August RASC meeting. Rauch said an updated design document on the constructs will be released in September.
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.
