Generators asked PJM stakeholders last week to consider changes to the RTO’s new Capacity Performance program, saying the rules approved by the Board of Managers without stakeholder consensus are overly punitive.
A group calling itself the “Supplier Coalition” asked the Markets and Reliability Committee to consider two problem statements. One would expand ways for generators to minimize underperformance penalties by netting them against over-performing generators. The second would consider widening the force majeure rules under which generators can escape penalties.
Bob O’Connell, of Main Line Electricity Market Consultants, said the current rules have “ineffective and inefficient options” for generators to manage the risk of underperformance during CP compliance hours. O’Connell said current rules allow companies with multiple generators to offset poor performance with over-performing units under “narrow criteria” but does not allow after-the-fact offsets, such as bilateral trades.
That could force smaller generators to seek mergers, reducing competition, he said. It could also result in “onerous” financing terms for future generators, he said.
Storms flooded Central Maine Power’s substation in Bath last month. Source: Central Maine Power
Walter Hall of the Maryland Public Service Commission expressed support for O’Connell’s proposal to consider changes, saying it could reduce the risk premiums generators include in their offers. Hall said any changes must be “consistent with the reliability enhancement objectives” of the CP program.
But Market Monitor Joe Bowring said the change could upset the “increased risk, increased reward” bargain at the heart of the CP rules. “It was an explicit part of the design. It was done on purpose,” he said.
Exemption for Transmission Outage
Ken Foladare of Tangibl outlined the second problem statement, which would reconsider PJM’s catastrophic force majeure rules. Foladare said the current rules would penalize generators for nonperformance even if it was impossible to deliver power because of a widespread blackout or a system disturbance.
Foladare’s initiative would consider circumstances for waiving penalties when the nonperformance resulted from a lack of transmission service.
Katie Guerry of EnerNOC said stakeholders should consider any changes to CP rules together in a single committee, such as the former Capacity Senior Task Force.
“We have lots of issues we’d like to see revisited,” agreed Marji Philips of Direct Energy. “The piecemeal approach is not the way to get there.” (See Philips’ op-ed, Why Capacity Performance Isn’t Good for the Markets in the Long Term.)
“Both these [problem statements] suggest that you have created costs for providers … that are not reflected in value,” said Bruce Campbell of EnergyConnect, adding that the proposals were “rammed through the stakeholder process.”
When PJM and stakeholders designed the original capacity market rules, “we spent a lot of time working through the gory details,” Campbell said. “That did not happen in this process.” (See FERC OKs PJM Capacity Performance: What You Need to Know.)
The problem statements will be brought to a vote at the next MRC meeting Oct. 22.
Scenario Analysis
The MRC also was briefed on the scenario analysis PJM is planning to conduct on the recently completed first Base Residual Auction under CP.
The analysis will consider nine scenarios used in each of the last two years and one new one that reruns the results using the variable resource requirement curve shape and gross cost of new entry values used in the 2017/18 BRA. The rules were changed for the 2018/19 BRA following the RTO’s triennial review. (See PJM Board Orders Filing on Capacity Parameter Changes.)
The repeated scenarios include an unconstrained simulation in which locational deliverability area limits are removed and CP supply is both added and removed from the bottom of the supply curve in and outside of MAAC.
VALLEY FORGE, Pa. — Nearly everyone who spoke at last week’s PJM Members Committee meeting agreed that stakeholder discussions are enhanced by the participation of the Consumer Advocates of the PJM States. But not everyone wants to pay to have them in the room.
A proposal by CAPS Executive Director Dan Griffiths that the RTO fund the group’s $450,000 budget through an assessment on electric customers won support from state regulators and other load interests but drew sharp opposition from suppliers.
Griffiths
Griffiths and West Virginia Consumer Advocate Jacqueline Roberts proposed that CAPS’ budget be funded in part through an assessment on electric sales similar to the funding Organization of PJM States (OPSI). They said it would amount to eight-tenths of a cent for a residential customer using 12,000 KWh annually.
Opposed in Principle
But while the charge would be miniscule, some market participants said they opposed it in principle.
“Our company is a great believer in markets and competitive markets, and we have trouble funding an organization that is comprised of entities that have challenged competition at the state level and at PJM,” said Marji Philips of Direct Energy. “Frankly that was why our company decided we could not get behind this proposal.
“Some [advocates] have been vehemently anti-competition at the retail level,” she added.
“Silencing views that don’t agree with you doesn’t give you a better stakeholder process. It might give you a quieter stakeholder process,” Roberts responded.
“There’s nothing to keep you from dialing in” to the meetings, Philips countered.
She added later that while Direct Energy supports the advocates’ participation at PJM meetings, it believes their funding should come from their states.
CAPS is a nonprofit group made up of consumer advocates from the PJM states and D.C. It was formed in 2012 with start-up funding from a FERC enforcement settlement with Constellation Energy (IN12-7-00), allowing advocates to travel to PJM meetings in Valley Forge, Pa., and Wilmington, Del.
CAPS’ assessment on electricity consumers would be supplemented by remaining Constellation funds along with contributions Exelon has offered to win its acquisition of Pepco Holdings Inc. Exelon’s Jason Barker said that as part of its effort to win approval of the merger, “Exelon has agreed to support reasonable proposals to have PJM members fund CAPS.” (See related story, Reports: Exelon Considering D.C. HQ to Win Pepco Deal.)
The rationale for the assessment, said Griffiths, is that consumers deserve a voice at PJM because the majority of charges they see on their electricity bill are the result of actions taken at the RTO and FERC. “We think that being here is a benefit to everybody,” he said.
Chris Norton, director of market regulatory affairs for American Municipal Power, said the assessment would be unfair to his public power members who are not represented by CAPS. PJM CFO Suzanne Daugherty said there was no way to excuse AMP members from the assessment because many public power customers are supplied through “commingled” customer accounts.
PJM: Up to Members to Decide
PJM Market Monitor Joe Bowring and CEO-elect Andy Ott agreed that CAPS’ involvement has been beneficial.
“If you look at the past 18 months, when the CAPS organization has stood up and been engaged in the stakeholder process, I think it’s been enriching,” Ott said. “The positive nature of having consumer advocates be engaged is obvious. It seems to me that all of us have seen that happen.”
But, he said, “When you get to the question of … should the funding be through the PJM Tariff — there, I think it’s beyond what PJM should be opining on. That’s a members’ decision.”
Cox and ODEC’s Ed Tatum
Dynegy’s Jason Cox and Jesse Dillon, assistant general counsel for Talen Energy, also opposed the proposal.
“If [the amount is] so de minimis, it seems like the states could fund it themselves,” Cox said.
“We don’t think PJM members should be forced to fund private speech and expression with which we may disagree,” said Dillon. To say retail customers would bear the charge is a “sophistry,” he added.
“They’re charging load-serving entities,” he said. “We are an LSE, and we do not have the ability to pass costs on to customers like others might.”
ODEC Position ‘Evolved’
Ed Tatum said the thinking of Old Dominion Electric Cooperative used to be in line with Talen’s.
But, he said, “Old Dominion’s thinking on this has evolved. We have experienced the stakeholder process without strong [consumer] representation. Through CAPS, now we have an engaged, knowledgeable group of folks [who seek to achieve consensus]. … We would support CAPS.”
Susan Bruce, representing the PJM Industrial Customer Coalition, said her group realizes “the importance of this forum on ratemaking at the state level: Two-thirds or three-quarters of customers’ bills are a result of actions here or at FERC.”
“We think the stakeholder process is more vibrant with them and helps us avoid surprises at the FERC level,” she continued. “My clients, they’re willing to pay that cost.”
The debate echoed that in MISO in April, when the RTO declined a request by consumer advocates for $200,000 to help cover its legal costs in a fight over MISO transmission owners’ return on equity. (See MISO to Consumer Sector: No Money for You.)
Roberts noted, however, that MISO’s advocates receive funding through the tariff for the Organization of MISO States. Griffiths pointed out that CAPS has pledged not to use its funding to litigate at FERC.
Roberts indicated confidence that the funding request will be approved, insisting those who spoke in opposition did not represent a wide group of stakeholders. “We have strong support and support in every sector,” she said.
Regulators reaffirmed the state’s first-in-the-nation ban on variable rate electric contracts, which was approved earlier this year by the General Assembly and became law Thursday.
The Public Utilities Regulatory Authority ruling said the act’s language “is clear and unambiguous about variable pricing in residential contracts starting on and after Oct. 1, 2015.” Third-party electricity providers who offer the variable rate plans had claimed the language was unclear.
Consumer Counsel Elin Swanson Katz hailed the ruling as “a victory for consumers.” Katz was active in efforts to get the variable rate ban passed.
Calpine’s Garrison Energy Center in Dover, a 309-MW combined-cycle power plant, was officially dedicated Thursday, though it has been up and running since June.
State officials hope the efficient power plant will help them achieve emission reduction targets set forth by the Environmental Protection Agency’s Clean Power Plan.
Calpine bought the rights to the gas-fired generating facility at the Garrison Oak Technology Park several years ago. The Dover City Council approved a $6 million bond issue for infrastructure improvements, and the state gave Calpine a $2.5 million grant to build a natural gas pipeline.
Construction on a 46-mile transmission line linking Peoria to Galesburg is slated to begin next year after Ameren Transmission won approval from the Commerce Commission.
Ameren’s transmission subsidiary plans to have the $150 million high-voltage line completed by 2018. MISO has also approved the line.
Ameren Transmission chairman and president Maureen Borkowski said the project will boost the state’s economy and create jobs. The project is one of three large new transmission lines being developed by Ameren Transmission as it expands infrastructure in the region.
Indianapolis Power & Light is asking the Utility Regulatory Commission for a $67.7 million rate increase, more than 10 times what the state’s consumer advocate says the utility needs.
IPL first made the request last December, but it was put on hold until Sept. 21 after the Office of Utility Consumer Counselor protested. The consumer advocate contends that the utility needs just $5.9 million to cover increasing maintenance costs and capital expenses to address the utility’s underground transmission faults that have been blamed for causing several dramatic fires and explosions.
The rate case is expected to drag on until next year.
The Paducah Power System is exploring whether to sell surplus power into PJM.
The municipal power system’s board approved a $50,000 deposit for a study to be conducted by PJM. Board chairman Hardy Roberts says he hopes the power system will be able to sell excess capacity to markets in the RTO.
The capacity would come from its gas-fired peaking plant.
Electric utilities are pressuring state Attorney General Chris Koster to join a legal challenge to the Obama administration’s carbon emission regulations.
Representatives from Ameren Missouri, Kansas City Power and Light, Empire District Electric and groups representing the state’s municipal utilities and electric cooperatives sent Koster a letter Sept. 28 asking him to join other states that have mounted legal challenges to the regulations.
Koster is a Democrat running for governor next year. Many Democrats support the rules, which are opposed by the coal industry and utilities, both politically powerful constituencies in the state. EPA wants the state, which burns coal for 80% of its electricity, to reduce carbon emissions by 37% from 2012 levels.
The Public Utilities Commission has fined Eversource NH $250,000 for failing to repair a broken cross arm on a utility pole in Keene, where an employee of Keene State College was electrocuted while investigating a report of a low-hanging wire.
The PUC’s Safety Division found that the utility’s inspectors discovered the broken cross arm in January 2014, but it went unrepaired for three months before the death of Nathan L. DeMond, whose body was discovered in contact with the wire where it passed closest to the ground. The report said the company “failed to act in accordance with good utility practice” by not repairing the broken equipment promptly.
An Eversource spokesperson said the company has not yet decided if it will appeal the ruling.
Eversource Energy is predicting a winter energy service charge of 10.39 cents/kWh, slightly lower than last year’s winter rate of 10.56 cents. The utility is not formally requesting a rate change at this time but is giving the Public Utility Commission a prediction of what it is likely to ask for in its formal filing in December. The new charge will be in effect from Jan. 1 to June 30.
“Constraints on natural gas supply into New England often drive up the cost of energy during winter months, and the region continues to experience higher energy prices compared to other areas of the country,” said Penni Conner, senior vice president and chief customer officer at Eversource.
Report: Room for Improvement in Storm Restoration Efforts
After six major storms in eight years, utilities have gotten better at restoring power, but there’s still room for improvement, according to a 100-page report by state regulators.
According to Public Utility Commission staff, Eversource, which has 70% of the state’s customers, was slow to deploy out-of-state restoration crews during a Thanksgiving storm in 2014, was hampered by weak weather forecasts and did not communicate effectively with its customers about likely restoration times.
Response to the Thanksgiving storm was complicated by holiday staffing issues, but the utilities had plenty of time to prepare, according to the PUC. The commission also expressed concern about inconsistencies in the weather forecasts among utilities.
Protesters opposing the PennEast natural gas pipeline took aim at the state’s biggest electric utility, Public Service Electric and Gas.
About three dozen protesters walked from the statehouse to PSE&G, a partner in the PennEast pipeline, demanding the project be killed. Among them was Democratic Assemblywoman Elizabeth Muoio.
PennEast said in a statement that construction of the 36-inch pipeline would have an estimated $1.6 billion positive economic impact and support about 12,000 jobs. The 118-mile pipeline would stretch from in Luzerne County, Pa., to near Mercer County. Affiliates of five gas distribution companies, mostly in the state, are the major customers.
A Rutgers University study on bioenergy potential shows that the state produces 7 million dry tons of biomass annually, more than 4 million of which could be recovered and used to generate power, heat or vehicle fuel.
The report aimed to update 2007 feedstock and technology assessments and considered statewide waste and biomass resource by location, greenhouse gas reduction potential and policy recommendations.
According to the assessment, the recoverable biomass could generate up to 654 MW of power — 6.4% of the state’s electricity consumption. It also represents the equivalent of 230 million gallons of gasoline, or 4.3% of transportation fuel consumed in the state.
The Nassau County Legislature unanimously approved a measure allowing PSEG Long Island to pay nearly $1.4 million less in property taxes than it was initially billed.
The legislature voted to allow the county treasurer to accept a one-time reduced tax payment from PSEG of $28.6 million instead of the $30 million it had been billed. The county is exploring options to collect the remaining amount, including litigation, officials said.
The Long Island Power Authority, which still owns power facilities operated by PSEG, had directed the utility to limit tax-bill increases to 2% because its lawyers said the state-approved LIPA Reform Act of 2013 caps tax hikes to 2% a year on company properties.
Duke Settles Coal Ash, Wastewater Issues with $7M Payment
Duke Energy agreed to a $7 million settlement with the state Department of Environmental Quality, concluding its troubles with state regulators over coal ash and groundwater violations.
The agreement, announced last week, represents a substantial reduction from the initial fine of $25.1 million. The company argued that the state failed to follow its own regulations when it imposed the fine without giving Duke a chance to respond.
The settlement calls for Duke to quicken the pace of cleanup at four of its 14 coal plants and ash-containment impoundments. The state estimates it will cost between $10 million and $15 million for those cleanup projects. Duke in February settled federal charges relating to coal ash with a $101.2 million payment.
The state became the first in the Southeast, and the fourth in the U.S. overall, to surpass 1 GW of solar capacity, according to a report from the NC Sustainable Energy Association. According to the report, the state follows California, Arizona and New Jersey to reach the 1-GW mark.
While the pace of solar installations has been high in the state, it will probably slow down. The General Assembly in September voted to end the state’s Renewable Energy Investment Tax Credit. The report said that the tax credit helped fund about $182.6 million in solar projects between 2007 and 2014.
The report also said that the clean energy industry in the state now counts about 1,200 companies employing 23,000 people and generates about $4.8 billion in annual gross revenues.
Supreme Court Sets Hearing in Delayed Wind Farm Project
A dispute over the stalled Buckeye Wind Power Project in Champaign County will move forward after the state Supreme Court set Dec. 16 for oral arguments in the case.
The Power Siting Board approved the second phase of the project in May 2013, but nearby property owners and several local government entities appealed.
The project is split into two phases, the first of which was approved in 2010 but is still unbuilt. Combined, the two phases call for construction of about 100 turbines in several townships across rural Champaign County, generating 200 MW.
Gov. John Kasich’s office said last week a recommendation from a state panel that it indefinitely continue its freeze on renewable and energy efficiency mandates is “unacceptable.”
The Republican-controlled Energy Mandates Study Committee released its report recommending that the state not resume its march any time soon toward achieving at least a quarter of its power from renewable and advanced technology sources.
Green energy advocates say the committee was stacked against renewable energy. Utilities like FirstEnergy, the Akron-based parent of Toledo Edison, have opposed the standards.
Andrew Place, former corporate director for energy and environmental policy at natural gas producer EQT Corp., was welcomed to his seat on the Public Utility Commission following his unanimous confirmation by the state Senate.
Place helped establish the Center for Sustainable Shale Development and worked at the state’s Department of Environmental Protection. He pledged to be “an unassailably independent voice” on the commission.
“Andrew’s unique background — blending work in academia, business and state government — will serve the commission well as we strive to ensure a continued balance between consumer and utilities,” PUC Chairman Gladys M. Brown said.
A State Corporation Commission hearing examiner recommended that Dominion Virginia Power’s plan to build a solar farm near Remington is in the public interest and should receive a certificate of public convenience and necessity. The three-member commission must still approve it.
Dominion has said the solar facility, which will be the largest in the state, could be in operation by late 2016. The 20-MW facility in Fauquier County would tie into existing transmission lines.
A power plant owner affiliated with The Blackstone Group is asking state and federal regulators for expedited approval to buy two coal-fired power plants in western New York (15-E-0580).
Riesling Power is seeking to buy the 668-MW Somerset facility in Niagara County and the 312-MW Cayuga facility, which is operating under a controversial reliability support services agreement.
Both plants are owned by Upstate New York Power Producers, formed by a group of bondholders that purchased the plants from the bankrupt AES Energy East for $240 million in 2012. The filing asks for approval by the New York Public Service Commission’s Dec. 17 meeting. The buyer said all personnel would remain in place and the plants would continue operating. The purchase price was not disclosed.
“Expedited approval is appropriate here because the proposed transfer does not raise any issues regarding retail energy sales to captive ratepayers or market power concerns in the competitive wholesale markets in New York and is consistent with commission precedent,” the state filing states.
Upstate New York Power, whose largest stockholders are the California Public Employees’ Retirement System (CalPERS), Carlyle Strategic Partners, J.P. Morgan Investment Management and Marathon Asset Management, asked for FERC approval of the deal by Nov. 24 (EC15-214).
Riesling is a wholly owned subsidiary of Bicent Power, which in turn is 95.6%-owned by GSO Capital Partners. GSO represents the credit-oriented business of The Blackstone Group, one of the largest players in the leveraged buyout business. Upstate New York Power had hired Blackstone in 2014 to sell the plants, according to Power Finance and Risk.
Neither Riesling nor Bicent own generation in New York, the filing states.
The Plants
Cayuga, a 60-year-old pulverized coal-fired power plant on the eastern shore of Cayuga Lake in Lansing, N.Y., is operating under a RSSA with New York State Electric and Gas (NYSEG). The plant is also the subject of a PSC proceeding considering whether to repower it from coal to natural gas.
Plant owners had proposed to mothball the facility in early 2013, but NYISO and NYSEG determined the plant was needed for system reliability. A one-year RSSA was ordered by the PSC. With no suitable alternatives identified, the commission approved a second RSSA that expires June 30, 2017.
NYSEG, Niagara Mohawk and several stakeholders are promoting the proposed Auburn Transmission Project Phase 2 as an alternative to the Cayuga repowering (13-T-0235). The project has been endorsed by PSC staff.
Somerset, a pulverized coal-fired power plant in Barker, N.Y., on the southern shore of Lake Ontario that began commercial operations in 1984, has been described as too distant from existing natural gas pipelines for a conversion.
The largest taxpayer in its home county, Somerset is a merchant plant selling its output into NYISO.
Energy Highway
When New York Gov. Andrew Cuomo proposed the Energy Highway in 2012 to bring power from generation plants upstate to load centers in and around New York City, Upstate New York Power responded that the plants could play an “important role” for the proposal.
“New York’s energy needs require a diverse blend of fuel-type resources to provide the state’s residents and businesses with a dependable and affordable energy pool,” the company said. “Upstate New York Power Producers looks forward to being a part of the solution.”
It said the two plants are in compliance with the current environmental regulations and “well positioned” to meet future regulations, having invested in technologies including flue gas desulfurization and selective catalytic reduction to reduce sulfur dioxide (SO2) and nitrogen oxides (NOx) emissions.
Last month, the PSC staff took a step toward making the highway a reality, recommending transmission routes that would help move 1,000 MW of upstate generation. (See NYPSC Staff Recommends $1.2B in Transmission Projects.)
Somerset, located in Zone A, is connected to the main 345-kV east/west transmission corridor with NYSEG at the Kintigh Switchyard. Cayuga, in Zone C, connects with NYSEG at the Milliken Switchyard at 115 kV.
WASHINGTON — A key House committee last week approved what would be the first comprehensive energy legislation in eight years, but hopes for passage dimmed after Republican amendments eroded bipartisan support.
H.R. 8, the North American Energy Security and Infrastructure Act of 2015, cleared the House Energy and Commerce Committee 32-20 on Wednesday with support from only three Democrats. The bill includes measures to improve energy infrastructure, resilience and reliability while increasing scrutiny of RTOs and FERC.
Pallone (left) and Upton.
A preliminary draft of the bill had passed a subcommittee unanimously. But Wednesday’s markup devolved into partisan sniping after Chairman Fred Upton (R-Mich.) replaced the original bill with a 208-page amendment that stripped gas and electric infrastructure funding sought by Democrats. The amendment also includes provisions that would speed the approval of liquefied natural gas export terminals and repeal current law requiring that federal buildings phase out the use of fossil fuel-generated energy.
The changes left Rep. Frank Pallone (D-N.J.), the ranking Democrat on the committee, fuming. “This bill only aims to help polluters in my opinion,” he said. “It continues to ignore the impact of climate change, which remains the biggest threat to our energy security and way of life.”
Upton said the bill is intended to create jobs, improve infrastructure and ensure affordable energy. “While it has been difficult to find bipartisan consensus on as many fronts as I would have liked, I believe we have written a substantive, thoughtful bill,” he said in opening the committee markup.
Congress has not approved a comprehensive energy bill since the Energy Independence and Security Act of 2007. While the House bill is unlikely to pass as is, many of its provisions could find their way into final legislation if bipartisanship prevails.
The Senate Energy and Natural Resources Committee passed its own legislation, the Energy Policy Modernization Act, on July 30 by a bipartisan 18-4 vote.
The package, crafted by Chairwoman Lisa Murkowski (R-Alaska) and ranking member Maria Cantwell (D-Wash.), also would expedite LNG projects and streamline the federal permitting process. It includes measures to improve energy efficiency and cybersecurity and encourage hydropower and geothermal development.
Below is a summary of the House bill’s major provisions affecting the electric industry:
RELIABILITY
Fuel Security
The bill would require traditional vertically integrated utilities to incorporate “reliable generation” into their integrated resource plans, defining it as generation facilities with firm-fuel contracts, dual-fuel capability or sufficient on-site fuel to operate “for the duration of an emergency or severe weather conditions.” (Section 1107)
The requirements would not apply to companies engaged in competitive, unbundled retail electric sales.
FERC Reliability Review
FERC, in consultation with the North American Electric Reliability Corp., would be required to conduct reliability analyses of any federal rule affecting electric generators that is expected to result in an annual effect on the economy of at least $1 billion. The FERC review would evaluate the impact of the rule on electric reliability; resource adequacy; the nation’s electricity generation portfolio; the operation of wholesale markets; electric transmission lines; and natural gas pipelines. (Section 1108)
RESILIENCE
Hardening
The bill would require all utilities to develop plans for improving the resilience of their systems against physical sabotage, cyberattacks, electromagnetic pulses, geomagnetic disturbances, severe weather and earthquakes. Among the measures that utilities may consider are the hardening of distribution facilities; technologies that can isolate or repair problems remotely, such as advanced metering and monitoring and control systems; cybersecurity measures; distributed generation; microgrids and non-grid-scale energy storage. (Section 1107)
State regulators “shall consider” authorizing spending on such improvements, the bill says.
The legislation also establishes a competitive grant program for states and local governments for spending on resilience and reliability. (Section 1201)
Strategic Transformer Reserve
The bill would authorize the creation of a stockpile of large power transformers and trailer-mounted mobile substations to recover from the threats listed above. (See “Hardening.”)
The issue caught Congress’ attention as a result of the April 2013 rifle attack on Pacific Gas and Electric’s Metcalf substation and a campaign by former FERC Chairman Jon Wellinghoff to raise awareness of the grid’s vulnerabilities. Wellinghoff cited a 2013 FERC analysis that he said concluded that an attack that disabled nine critical substations could cause an extended blackout in the continental U.S. (See Report: Sabotage Threat Uncertainty Could Lead to Wasteful Spending.)
The Energy Department would be required to develop a plan for the reserve and identify preferred funding options, including fees on owners and operators of bulk-power systems and critical electric infrastructure, federal appropriations, and public-private cost sharing. (Section 1105)
Grid Security Emergencies
If the president declares a grid security emergency, the Secretary of Energy would have authority to order measures to protect or restore the reliability of critical electric infrastructure. (Section 215A)
FERC
Merger Authorization
It would limit FERC review of merger and consolidation acquisitions to those of $10 million or more. (Section 4222)
FERC Enforcement
FERC would be required to create an Office of Compliance Assistance and Public Participation to “promote improved compliance with commission rules and orders.” (Section 4211)
The proposal is an apparent response to complaints by some in the Washington energy bar that FERC’s Office of Enforcement, formerly headed by Chairman Norman Bay, is unfair and heavy handed. (See Gates, Powhatan Say FERC Enforcers Didn’t Share Crucial Info.)
The office would “promote improved compliance” with commission rules through outreach and publications and, “where appropriate, direct communication with entities regulated by the commission.’’
The provision is intended to provide entities subject to FERC regulation “the opportunity to obtain timely guidance for compliance with commission rules and orders” — an opportunity FERC says it already offers through “no-action” letters.
RTOs/ISOs
GAO Study
The Government Accountability Office would be required to conduct reports on each RTO’s and ISO’s “market rules, practices and structures.” (Section 4221)
The grid operators would be judged on a number of issues, including whether they produce just and reasonable rates; facilitate fuel diversity, reliability and advanced grid technologies; and promote “equitable treatment of business models, including different utility types.”
GAO also would evaluate the transparency of grid operators’ governance structures and stakeholder processes as well as the transparency of dispatch decisions, including the need for out-of-market actions and the accuracy of day-ahead unit commitments.
The report also would review how well grid operators facilitate “the ability of load-serving entities to self-supply their service territory load.”
The American Public Power Association, which opposes mandatory capacity markets, said the bill doesn’t go far enough. The group said the bill doesn’t address problems faced by public power utilities “forced to participate in the FERC-blessed mandatory capacity markets and is silent on the issue of self-supply for such LSEs.”
APPA, which represents more than 2,000 community-owned, not-for-profit utilities, said it wants the legislation changed to allow wholesale markets to “become more affordable and workable for public power utilities that are willing and able to build a variety of power generation facilities if not blocked from doing so by rules skewed toward certain market participants.”
Financial traders could benefit from a requirement that RTOs ensure “the proper alignment of the energy and transmission markets by including both energy and financial transmission rights in the day-ahead markets.”
Industry sources said the provision would encourage more widespread use of products similar to PJM’s up-to-congestion trades and ERCOT’s point-to-point congestion hedges.
Capacity Markets
RTOs and ISOs operating capacity markets would be required to provide to FERC an analysis of how the markets use competitive forces and include “resource-neutral” performance criteria. FERC would be required to report to Congress on whether each market meets the criteria and make recommendations for those that don’t. (Section 215B)
INFRASTRUCTURE
Deadlines
A final decision on a federal authorization for gas pipelines would be due no later than 90 days after FERC issues its final environmental document, unless a schedule is otherwise established by federal law. (Section 1101)
It would require the Energy Department to act on applications for LNG export facilities within 30 days of the conclusion of reviews under the National Environmental Policy Act. (Section 3006)
Frank Macchiarola, executive vice president for government affairs at America’s Natural Gas Alliance, praised the bill, saying that it “recognizes and seeks to maximize the opportunities presented by our nation’s domestic energy abundance.” ANGA represents independent natural gas exploration and production companies in North America.
Carbon Capture
The Energy Department would be required to evaluate all carbon capture and sequestration projects funded by the agency every two years. (Section 1109)
Hydropower
The bill would reauthorize hydroelectric production incentives through fiscal year 2025 and require FERC to minimize infringement on private property rights in issuing hydropower licenses. (Sections 1301-1304)
FERC would be authorized to issue exemptions from licensing requirements for development of new hydropower projects at existing non-powered dams.
It would build on changes in two bills enacted in 2013 that streamline regulations on small hydropower sites. A 2012 Energy Department report said the powering of non-powered dams could unlock 12 GW of generating capacity. (See Tiny Hydro Projects Joining Generation Mix in PJM.)
APPA said it was disappointed that the bill does not include “substantive” licensing reform.
“The current hydropower licensing process must be reformed so that public power and other utilities can increase reliable emissions-free hydropower generation without unnecessarily prolonged resource agency review,” it said.
The bill would provide special relief for one hydro project, however.
The developers of the proposed hydro project on the U.S. Army Corps of Engineers’ W. Kerr Scott Dam on the Yadkin River in North Carolina would have an additional six years to start construction under the bill. Wilkesboro Hydropower has proposed adding a turbine that would generate 2 MW at the unpowered dam.
FERC granted the developers a license in July 2012 giving them two years to begin construction and five years to complete it. In May 2014, FERC granted Wilkesboro Hydropower a two-year extension (P-12642-007).
Under the Federal Power Act, FERC told the developers, the deadline for starting construction may only be extended once.
VALLEY FORGE, Pa. — The Markets and Reliability Committee voted overwhelmingly Thursday to raise the energy market offer cap to $2,000/MWh in a move that outgoing CEO Terry Boston called “the stakeholder process at its best.”
The MRC approved the new cap by an unweighted 84-17 margin, after which the Members Committee gave final approval by voice vote.
Boston said the Board of Managers would approve the new framework and PJM would be filing a Tariff change with FERC within a couple of weeks.
He apologized for not having the Tariff language ready before the vote, saying, “We were not as optimistic as we should have been about this getting approved this morning and afternoon.” He said the language would be made available to members a few days before the FERC filing.
Boston appeared touched by the vote, which comes as his seven-year tenure nears its end. “In the first meeting of the year, after this was voted down last year, I begged for consensus,” he recalled.
There was a smattering of applause when the vote was revealed at the MRC, and many who had sparred this year over the issue offered praise to PJM staff, each other and the four entities who agreed to withdraw their own proposals in favor of the simplified plan: Direct Energy, Old Dominion Electric Cooperative, PJM Power Providers Group (P3) and the Independent Market Monitor.
“It’s really cool that we were able to pull this off given the short time frame,” said Marji Phillips of Direct Energy, which had initiated the first of the four proposals. “I want to compliment everyone who supported this — especially when I was yelling at you at the last meeting.”
Pepco Holdings Inc.’s Gloria Godson called the vote “a beautiful thing to behold.”
The Details
The proposal caps cost-based offers at $2,000/MWh and allows them to set LMPs, with market-based offers allowed to equal cost-based ones. Generators with approved fuel-cost policies claiming costs above $2,000/MWh would be compensated through after-the-fact review and subsequent make-whole payments.
Supporters of an increase in the cap say it is necessary to ensure that gas-fired generators can recover their costs when fuel prices spike during extreme conditions such as the 2014 polar vortex.
Jeff Whitehead of Direct Energy, whose proposal would have raised the cap to $2,700/MWh for cost-based day-ahead offers and price-based real-time offers, said the company was willing to back the compromise because it ensures “that as much generator compensation cost is recovered as possible in energy prices, which are hedgeable, and something load servers can compete on.”
“Uplift is not [hedgeable] and is a cost that gets rolled into risk adders that get passed on to consumers,” he added.
Likewise, David “Scarp” Scarpignato of Calpine said P3 didn’t believe the consensus proposal offered the “proper price formation,” but the group was willing to support it because it does allow generators to recover costs and raises the level that can set LMPs.
Temporary Change; FERC Action Expected
Some of those who opposed raising the cap previously — or thought the compromise was insufficient — were willing to support what is now assumed to be a temporary solution. FERC on Sept. 17 announced its intention to take action on offer caps and other price formation issues. (See NOPR Requires RTOs Switch to 5-Minute Settlements.)
Exelon’s Jason Barker, who at the last meeting on the issue had criticized the framework, supported it Thursday as “an improvement over the status quo” and said he hoped FERC would improve on the filing. “We will look forward to FERC … recognizing flaws inherent in this proposal,” he said. (See Consensus Near on PJM Energy Market Offer Cap?)
Similarly, Dynegy’s Jason Cox said, “Dynegy reluctantly supports this compromise as a way to ensure that our costs are covered until FERC acts. We believe that we should not allow market distortions and continue to support potential massive uplift during critical periods.”
Susan Bruce of the PJM Industrial Customer Coalition said her group continued to have concerns over the proposal but offered support in return for a promise from the Market Monitor and PJM that there would be “robust reporting” on offers between $1,000, the current cap, and $2,000.
Delaware, Maryland Unconvinced
Representatives of state commissions generally opposed the proposal.
John Farber, public utility analyst for the Delaware Public Service Commission, asked that PJM consider releasing information about the heat rates of the generators setting the clearing price.
Walter Hall of the Maryland Public Service Commission said his agency remained unconvinced of a need to raise the cost cap.
Jim Jablonski of the Public Power Association of New Jersey pointed out that PJM fared better this past winter, which saw colder temperatures, than it had during the previous season’s polar vortex.
And, he said, “Capacity Performance is designed to provide a financial incentive to perform whenever needed and designed to eliminate future emergencies. Reliability, therefore, in our view is protected. We do not think a change is warranted. Two thousand dollars is not supportable except as a compromise, has no factual basis and definitely is going to be open to challenge.”
IPPNY President Gavin Donohue said generators are willing to work with New York regulators regarding the state’s capacity market but said it’s unclear what changes are being sought. “What problem are we trying to solve?” he asked. “We’ve had stresses on the system during the winter [and] during the summer the last few years and quite frankly the system has worked very well.”
IPPNY Chairman John Reese, senior vice president of US Power Generation, called on state regulators to demonstrate “courage” by pushing for an increase in the cost of new entry. “Nobody believes you can actually build or enter the New York market for the current cost of new entry price,” he said. “Upstate New York capacity prices are lower than PJM, are lower than New England. Those are not survivable.”
Kenneth Daly, CEO of National Grid New York, speaks as James Gallagher, executive director of the New York State Smart Grid Consortium (left), and UBS Securities analyst Michael Weinstein (right) listen. Daly said the next five years of the state’s Reforming the Energy Vision initiative will be transitional, as state regulators evaluate demonstration projects and determine which worked and which did not. “Ten years from now is when we’ll start to see game changers. Battery storage is clearly the one biggest change that our industry will face. And if we go through another investment cycle these next five years of modernizing our grids we’ll then have far greater capability in that second five-year period to integrate renewables, to give customers choice, to use more local demand response.”
Richard Dewey, executive vice president of NYISO (left), and John Shelk, president of the Electric Power Supply Association (right), said EPA’s final Clean Power Plan addressed problems with the draft rule. Dewey said the preliminary rule “would have left us with about one to three days of oil burn in New York state – which is about 100 less than we typically need [for] reliability.” Shelk said the final rule fixed an “artificial” advantage for new gas plants. But he said it remains unclear how regions outside the Regional Greenhouse Gas Initiative will incorporate carbon costs in economic dispatch. “Clearly we’re not going to have — certainly not on day one — a price on carbon in the rest of the states,” he said.
SPP will welcome the Integrated System and its three primary entities as full members Thursday, extending its footprint into Big Sky Country.
The IS — comprised of Western Area Power Administration-Upper Great Plains, Basin Electric Power Cooperative and Heartland Consumers Power District — expands SPP’s footprint to 14 states, adding the Dakotas and parts of Iowa, Minnesota, Montana and Wyoming.
It will add more than 5,000 MW of peak demand and 9,500 miles of transmission infrastructure to SPP’s responsibilities, while increasing its territory by 55% to 575,000 square miles.
“It’s a significant change for SPP, considering the amount of area we’re responsible for and the parties we’re responsible for as members,” Executive Vice President Carl Monroe, SPP’s chief operating officer, told RTO Insider. “We’re extending our footprint and ensuring SPP’s members will get the benefits of our services.”
While SPP expands with the IS, indications are it will not gain another potential member with Lubbock Power & Light’s announcement last week that it will join ERCOT in 2019.
Reliability Coordination Began June 1
SPP has been providing reliability coordination for the IS since June 1, monitoring power flow and managing congestion while WAPA, Basin Electric and Heartland dispatched their generating resources. The three entities will transfer functional control of their facilities to SPP at midnight Wednesday night and become active participants in the Integrated Marketplace, forming the new Upper Missouri transmission zone.
Other entities will become full SPP members Thursday, including the East River Electric Power Cooperative, Northwest Iowa Power Cooperative and Corn Belt Power Cooperative. It will be SPP’s first major membership additions since 2009, when Nebraska’s major utilities joined the RTO, and boosts its membership to 92.
“We’re really looking forward to Oct. 1,” Monroe said. “We have very good relationships with those parties, and some are already participating in SPP’s working groups.”
SPP prides itself on being a stakeholder-driven organization and its governance model was a major reason the IS joined. Heartland CEO Russell Olson cited the RTO’s “collaborative process” in a statement announcing the move last year.
“They felt they would have a voice,” Monroe said, “and that made a difference in their decisions.”
Joining SPP gives IS members access to the RTO’s markets. Several current members have already credited market savings with allowing them to reduce the size of rate increases or providing additional pricing efficiencies through a broader pool of resources.
“I would guess that would be able to happen again from expanded footprint,” Monroe said. “Savings in the energy market will reduce the cost of wholesale energy. Depending on how each entity handles its customers, it could be a reduction in costs.”
Monroe said SPP’s increased membership also will reduce RTO service fees for existing members. “Everyone will be paying less as a ratio than they would have paid before,” he said.
WAPA, Basin Electric and Heartland began discussing joining an RTO four years ago to increase their options for buying and selling power. All three conducted public hearings and assessments before determining last year that SPP was the best fit. FERC approved the move in November.
“We felt that SPP was a solid philosophical match for our cooperative,” said Paul Sukut, Basin Electric’s CEO and general manager.
WAPA will become the first federal power marketing administration to join an RTO. WAPA spokesperson Lisa Meiman said joining SPP “alleviates the marketing restraints” the agency was facing in delivering firm power to its customers.
Because the Energy Policy Act of 2005 placed conditions on power marketing administrations joining RTOs, SPP did have to “accommodate” WAPA’s “unique needs,” Meiman said. SPP modified its Tariff to exempt WAPA from regional cost-sharing charges. WAPA also is exempt from congestion and marginal loss charges when it is marketing and delivering federal hydropower to its federal load, she said. FERC issued an order Monday approving SPP Tariff changes accommodating WAPA (ER15-2350).
WAPA will merge its Eastern Interconnection balancing authority into SPP’s balancing authority, and its Eastern and Western Interconnection transmission facilities will be incorporated into the new Upper Missouri Zone. Meiman said WAPA will remain a transmission operator and develop transmission rates, revenue requirements and other necessary rates for use in SPP’s Tariff.
WAPA’s Western Interconnection BA will not become a part of SPP’s BA, nor will UGP’s Western Interconnection generation and load become part of the Integrated Marketplace.
Lubbock Sees Savings in ERCOT
Excitement over the addition of the IS was tempered last week when Lubbock Power & Light, which receives its energy through SPP member Xcel Energy, said it will join ERCOT to reduce its energy and capacity costs. (EDITOR’S NOTE: An earlier version of this story incorrectly stated that Lubbock Power & Light was an SPP member.)
The LP&L Electric Utility Board met with the Lubbock City Council on Sept. 24 to outline its transition to ERCOT, which manages 85% of the Texas grid. LP&L is the third-largest municipally owned electric company in the state, after San Antonio and Austin.
“That’s their decision,” Monroe said. “We’re a voluntary organization. If that’s what they intend to do, they make those choices that are best for their organization.”
LP&L says significant transmission infrastructure will be needed to interconnect with ERCOT, and that approval, certification and construction will likely take four years. The process began with a feasibility study, which was approved by the Public Utility Commission of Texas last week.
The utility says taking advantage of smaller, cheaper contracts in the ERCOT market will save it $20 million annually over what it currently spends in a long-term wholesale contract with Xcel Energy. LP&L’s three old, small power plants are seldom committed.
Lubbock also will be freed of about $40 million in annual capacity fees in ERCOT’s energy-only market.
LP&L also said it will benefit from Texas’ diversified energy portfolio and a simplified regulatory environment.
Monroe said SPP hasn’t had any conversations with LP&L or Xcel or looked at the implementation plans. “I’m not sure what [the announcement] means,” he said.
In a press release, Xcel expressed disappointment and said the city’s proposal will increase costs for customers in both ERCOT and the areas it serves in SPP. Noting the “significant investments” it has made in the area’s high-voltage network, Xcel said “Lubbock’s portion of the annual cost of these investments will be added to the costs Xcel Energy customers in Texas and New Mexico already pay.”
Xcel also said its long-term power supply agreement for a portion of Lubbock’s power needs through 2044 could be “impacted” by the utility’s move to ERCOT. According to LP&L, it will honor the contract by purchasing 170 MW from Xcel after June 1, 2019, which means it will remain interconnected with SPP.
By joining ERCOT, the city says it would also escape FERC regulation. As a Texas-only grid operator, ERCOT is regulated by the PUCT and the state legislature; FERC governs SPP and other interstate providers.
The PUCT and ERCOT would both have to approve LP&L’s move.
Below is a summary of the issues scheduled to be brought to a vote at the Markets and Reliability and Members committees Thursday. Each item is listed by agenda number, description and projected time of discussion, followed by a summary of the issue and links to prior coverage in RTO Insider.
RTO Insider will be at the PJM Conference and Training Center in Valley Forge, Pa., covering the discussions and votes. See next Tuesday’s newsletter for a full report. (Note: The meetings were delayed by a week because of the pope’s visit to Philadelphia and relocated to the CTC because facilities were not available in Wilmington on the new date.)
Markets and Reliability Committee
2. PJM Manuals (9:10-9:30)
Members will be asked to endorse the following manual changes:
Manual 40: Certification and Training Requirements. Makes miscellaneous edits; clarifies concepts, roles and responsibilities related to PJM’s systematic approach to training; updates the process for member training and PJM certification and reflects changes in terminology of operator titles.
Manual M10: Pre-Scheduling Operations. Adds procedures for maintenance outages under Capacity Performance rules: the requirement for PJM members to provide estimated “early return time” for planned outages; ensures that PJM will coordinate rescheduling if it withdraws or withholds approval of a planned outage; references PJM’s authority to withhold or withdraw approval of maintenance outages with at least 72 hours’ notice; adds requirement that maintenance outages be submitted at least three days prior to the operating day of their commencement.
Members will be asked to vote on a proposal to change the $1,000/MWh energy market offer cap. The proposal, hammered out by Direct Energy, Old Dominion Electric Cooperative, the Independent Market Monitor and the PJM Power Providers Group (P3), would cap cost-based offers at $2,000/MWh and allow them to set LMPs, with market-based offers allowed to equal cost-based. Generators with approved fuel cost policies claiming costs above $2,000/MWh would be compensated through make-whole payments. (See related story, Consensus Near on Energy Market Offer Cap?)
Members Committee
CONSENT AGENDA (1:20-1:25)
B. The committee will be asked to endorse Reliability Assurance Agreement revisions regarding external capacity rights. The rule change allows load-serving entities to meet their internal capacity requirements using historic resources under certain conditions: The percentage internal resource requirement is enforced only if the locational deliverability area has been separately modeled due to certain triggers; a fixed resource requirement entity is permitted to terminate its FRR alternative election prior to meeting the minimum five-year commitment period requirement under certain conditions; and first-time elections of the FRR alternative are due four months prior to a Base Residual Auction instead of the current two-month deadline. (See IMEA Reaps Limited Relief from Capacity Rule Change.)
C. New Tariff language reflects the switch from eMkt to Markets Gateway.
ENDORSEMENT (1:25-2:25)
Members will be asked to vote on a proposal to change the $1,000/MWh energy market offer cap. (See MRC agenda item 3, above.)
SARATOGA SPRINGS, N.Y. — New York Power Authority CEO Gil Quiniones says the state-run company will be the “most innovative and advanced utility in the U.S. in a very short period” due to massive investments and its commitment to facilitate the remaking of the industry in the state.
Quiniones
Addressing the fall conference of the Independent Power Producers of New York, Quiniones said NYPA expects to spend $3 billion to $4 billion on infrastructure over the next decade, with nearly half of that total — $1.5 billion — in smart grid generation and transmission assets.
New York has embarked on the Reforming the Energy Vision initiative to transition to cleaner and more distributed generation. NYPA’s five-year strategic plan was written in the context of REV, he said.
That means a revamping of operating procedures and technologies that can accommodate distributed resources. “As we move into this REV world, we have to be sure that all this generation and transmission infrastructure works in synchronicity with the advent of distributed resources,” Quiniones said. “… Our grid has to be connected and smart and optimized and the only way to do that is to digitize it and use big-data analytics.”
NYPA has 16 power plants and 1,400 circuit miles of transmission, including one-third of the state’s high voltage system. It serves 51 small municipal and rural cooperatives.
One project now underway is the retrofit of the Massena substation, which Quiniones said will result in “the most advanced substation of its size in this country. It will be microprocessor-based, fiber optic-based; it will provide unparalleled situational awareness and operational flexibility.”
Last year, NYPA built a 15-MW microgrid on Rikers Island in New York City, which captures waste heat from the facility and runs parallel and synchronous to the utility system. It can island in the event of another city-wide power interruption, such as during Superstorm Sandy. This is intended to be the first of several microgrids NYPA will build.
NYPA is acting as a facilitator with vendors SolarCity and SunEdison to install solar panels at the 698 school districts in the state. “I predict there will be a very fast ramp up of solar in our public schools,” Quiniones said.
In October, six drones from different vendors will be tested to monitor the condition of power lines. The authority also is beginning to monitor power line conditions and operations with a robotic device from Hydro-Quebec.
Much of the innovation is taking place in the North Country, home to most of the state’s wind farms, whose variability stresses the system.
Other initiatives include:
Installing dynamic line rating technology sensors and intelligence so the system can know exactly how much power is being carried through its lines. This aids efficiency by acting as a “fast switch” as it can transfer as much as 300 MW from one line to another in milliseconds to prevent system overload;
Condition-based monitoring that would base equipment replacement on the condition of the asset rather than on manufacturers’ recommendations;
Transformer-testing software to prevent catastrophic events.
