FERC last week sided with SPP’s Market Monitoring Unit in a long-running dispute with generators over what costs can be included in mitigated offers. The commission rejected SPP’s proposal to change the definition of costs allowed under mitigated energy offer curves, start-up offers and no-load offers (ER15-2268).
The commission said SPP’s proposal to describe mitigated offers in terms of variable cost rather than short-run marginal cost was “inconsistent” with the commission’s directive in its 2012 conditional acceptance of SPP’s Integrated Marketplace.
“We find that SPP’s proposal to base mitigated offers on variable costs may lead both to inefficient dispatch outcomes, characterized by higher production cost, and to distorted locational marginal prices that do not reflect competitive conditions,” the commission said.
Generators’ Complaints
Generators subject to mitigation had complained to SPP that they weren’t being paid enough because the Monitor refused to include certain expenses, such as long-term service agreements, in its definition of allowed costs. Generators subject to mitigation include those with local market power and those manually committed by SPP or a local transmission owner.
After more than a year of stakeholder meetings failed to reach consensus on the definition of short-run marginal costs, SPP in July filed proposed Tariff changes that would replace references to the term with the variable cost components of mitigated offers. The proposal would have set default variable operations and maintenance (VOM) costs that generators could include and listed the types of costs eligible under resource-specific offers.
SPP Monitor Protests
SPP’s filing drew protests and interventions from nearly two dozen market participants and the SPP Monitor, which asked FERC to reject the change, saying it could result in VOM costs that exceed short-run marginal costs and lead to economic withholding.
The Monitor said short-run marginal cost is not a “nebulous term,” but rather a common economic phrase describing the incremental cost of production — in this case, those that vary by megawatt-hour output.
It said SPP’s proposal “attempts to fix a problem that may not exist,” noting that mitigation had decreased significantly since the Integrated Marketplace’s launch in 2014.
Independence Concerns
PJM’s Independent Market Monitor filed a protest supporting the MMU, noting that PJM recently eliminated long-term maintenance from mitigated offers.
The IMM said that the proposed changes raised questions about whether SPP was protecting its MMU’s independence. “When the SPP Market Monitor made interpretations with respect to mitigated offers that SPP market participants did not like, the response was that market participants initiated a stakeholder process to apply pressure on the SPP Market Monitor to compromise or change those interpretations,” FERC said, paraphrasing the IMM’s filing.
The New Jersey Board of Public Utilities also backed the monitors’ arguments, saying approval of SPP’s proposed changes would be “a regression from SPP’s current mitigation rules” and could create an “adverse precedent that spills over to other regions.”
Filing not Supported
In rejecting SPP’s proposal, FERC said SPP failed to define the term “variable cost” or to “describe with specificity what costs may be included in mitigated offers as variable costs that were not previously regarded as short-run marginal costs.
“As such,” the commission said, “SPP proposes to replace one phrase that SPP contends is undefined (short-run marginal cost) with another phrase that is not well defined (variable cost).”
The commission also rejected the proposed default VOM costs, saying SPP’s decision to use the 80th percentile value of costs submitted by market participants would result in figures representative of high-cost units.
The commission said the PJM Monitor’s call for an examination of whether SPP was protecting the independence of its Monitor was outside the scope of the docket. “We note, however, that the SPP Market Monitor’s participation in this case demonstrates the importance of having an independent market monitor … to ensure that markets are competitive.”
SARATOGA SPRINGS, N.Y. — Political leaders’ urge to “do something” to combat high winter power prices risks undermining ISO-NE’s power market just as it has begun adding new generation, the head of the New England Power Generators Association said last week.
Dolan
“We’ve seen new investment come into the region for really the first time in a decade,” NEPGA President Dan Dolan said in a luncheon address at the fall conference of the Independent Power Producers of New York.
He said ISO-NE’s forward capacity market had spurred a “dramatic response,” noting that 13,000 MW of generation is now in the RTO’s transmission queue, up from 5,000 MW a year ago. (See Exelon, LS Power Join CPV in Adding New England Capacity.)
“We’re seeing the market do what it is designed to do,” he said. “But the drive to do something is creating an unprecedented march to out-of-market interventions at the very moment that we’re seeing billions of dollars in investment come into the region.”
The polar vortex and massive snowstorms in Boston in recent winters has created the idea that an “energy crisis” exists that demands immediate action across the region, Dolan said.
He said generators are particularly troubled by two state initiatives.
The first is a drive to “subsidize” hydropower from Hydro-Quebec through transmission and long-term power contracts. Massachusetts Gov. Charlie Baker has proposed legislation to allow 2,400 MW annually of imported power, about one-third of the state’s needs. NEPGA commissioned a study that claims such an arrangement would cost ratepayers $775 million annually in above-market prices, or $20 billion over the life of the 25-year contract.
SPP’s Regional State Committee failed to reach agreement last week on a change in its voting procedures.
During a conference call that stretched over two days, the committee considered three voting structures — simple majority, majority plus one and two-thirds — to be followed when the committee wants to intervene in federal regulatory or judicial proceedings. The seven-person committee voted 4-3 on a majority-plus one structure, falling short of the RSC’s current two-thirds threshold.
The RSC will grow to 11 members Oct. 1 when it adds representation from the Iowa, Minnesota, North Dakota and South Dakota regulatory commissions, giving the committee another chance to revisit the issue. The committee is comprised of regulatory commissioners in SPP’s footprint and provides collective agency input on matters of regional importance related to bulk electric transmission.
“My thought is to take no action and let the new states come in,” said RSC President Dana Murphy of the Oklahoma Corporation Commission. “Maybe that will be the time to look at the language with the full group.”
The previously divided RSC agreed with Murphy on that point.
Congestion Rights Tariff Filing Due
The RSC also reviewed SPP’s progress in meeting an Oct. 30 filing deadline for Tariff changes required by FERC.
The commission conditionally approved SPP’s rules on incremental long-term congestion rights (ILTCRs) last October, and then denied a rehearing request by SPP and intervenors in July (ER14-2553).
Staff told the RSC the language now clarifies that a party constructing an improvement has priority for LTCR capacity made available by the improvement. Short-term rights will be made available as soon as the improvement is in service, with long-term rights awarded during the next annual cycle.
The revised language also allocates LTCRs and ILTCRs for network upgrades funded through a combination of rolled-in transmission rates and directly assigns charges based on the ratio of each party’s funding of directly assigned facilities.
As FERC requested, the proposed Tariff language eliminates the minimum $5 million investment requirement to be eligible for ILTCRs.
The changes, which have already cleared SPP working groups, will be considered by the Markets and Operations Policy Committee at its Oct. 13-14 meeting. The RSC will also vote on the final language before it goes to the Board of Directors in late October.
CPP Task Force Fills Out its Roster
The Clean Power Plan Task Force, which will recommend SPP’s role in addressing the Environmental Protection Agency’s carbon emission rule, has announced its representation.
The task force will be chaired by Mike Wise, vice president of transmission and operations for Golden Spread Electric Cooperative.
Other members of the task force include:
Burton Crawford, KCP&L Greater Missouri Operations Co.; Dennis Florom, Lincoln Electric System; Dale Niezwaag, Basin Electric Power Cooperative; Wayne Penrod, Sunflower Electric Power Corp.; Lauren Quillian, Xcel Energy; and Richard Ross, American Electric Power. Michael Desselle, SPP’s chief compliance and chief administrative officer, will serve as the group’s staff secretary.
The task force has been charged by SPP’s Strategic Planning Committee with reviewing the CPP and EPA’s model federal implementation plan. It will recommend what role SPP should play in assisting states’ compliance, and inform staff and member dialogue with environmental regulators.
In one of its first formal actions, the group and SPP staff hosted a webinar last week for members of the RTO’s 14 states’ air-quality regulators, utility commissions and key governmental contacts at its member utilities.
SPP’s presentation noted its three assessments of the CPP indicate a regional approach to compliance is better than state-by-state approaches. State-by-state compliance would require 114% more generation retirements, a 9% increase in “generation at risk for retirement,” 185% more new natural gas generation and about the same percentage of new renewables, SPP said.
States with multiple RTOs should be aware of the potential for “overlapping impacts that could require broader coordination,” it said.
SPP RE Winter Assessment
SPP’s Regional Entity (RE) shared its draft winter reliability assessment during a webinar last week, saying reserve margins are “adequate” for what is expected to be a normal winter.
The RE said SPP has 67,058 MW of capacity available, with another 761 MW to come online during the winter months. That should be more than enough to meet expected winter peak demand of up to 42,000 MW.
The SPP RE also expects about 162 miles of 230-kV transmission to be added during the winter.
SPP engineer Chris Haley said fuel supply and wind integration remain concerns, but it has not identified any unique or unusual operational challenges for the winter.
Haley also noted SPP will assume planning coordinator functions Oct. 1 for the Integrated System (IS) entities registered with the Midwest Reliability Organization (MRO) Regional Entity: Western Area Power Administration-Upper Great Plains, Basin Electric Power Cooperative and Heartland Consumers Power District.
While Nebraska is still registered with the MRO, both Nebraska and the IS are part of the SPP RTO operational and planning area.
The winter assessment is created using data submitted by SPP reporting entities, which is validated by a peer-review process. The draft assessment will undergo additional peer review at the North American Electric Reliability Corp. before it is finalized.
The SPP RE will host its Winter Preparedness Workshop on Dec. 10.
Entergy Gets PSC Approval for 20-Year PPA with NextEra Solar
The Public Service Commission has approved Entergy Arkansas’ request to enter into a 20-year power purchase agreement with NextEra Energy, which is building an 81-MW solar plant near Stuttgart. The facility, which will cover more than 400 acres, will be the largest solar project in the state.
Environmentalists applauded. “The Sierra Club is excited to welcome this large, home-grown, clean energy project to Arkansas,” said Glen Hooks, director of Sierra Club of Arkansas. “As Entergy is moving toward clean energy, they have also proposed shutting down one of its largest dirty coal-fired plants.”
The new solar production will reduce Entergy’s carbon footprint. “Both nuclear and solar provide emissions-free power and a natural hedge for energy price fluctuations due to uncertain environmental regulations and natural gas volatility,” Entergy Arkansas President and CEO Hugh McDonald said at the project’s announcement in the spring. The project is expected to be completed in 2019.
Delmarva Power and Light says its customers are getting a break on natural gas costs for the fifth straight year. Under new rates taking effect Nov. 1, the average residential customer will save nearly $17/month, it said.
According to the Energy Information Administration, the residential cost of natural gas in the state hasn’t been this low since 2004.
Watchdog Group Says Utilities Scaling Back Energy Efficiency Standards
The Citizens Action Coalition says that utilities are scaling back their energy saving and energy efficiency programs in response to the state’s more relaxed conservation standards.
The state’s energy efficiency standard was replaced by Senate Bill 412, which calls for utilities to establish their own energy efficiency and demand-side management programs rather than meet strict state targets. CAC says the plans for Duke Energy Indiana and Northern Indiana Public Service Co. have set substantially lower targets. It says NIPSCO’s target has dropped from 339 GWh of energy savings to 114 GWh.
“Our fears are coming true or being confirmed,” CAC Executive Director Kerwin Olson said. “The legislation allows the utility companies to establish their own goals. It puts the utilities in the driver’s seat in terms of how much energy efficiency they’re going to do.”
The Corporation Commission has approved a 4% rate hike for Westar Energy that will increase a typical monthly residential electrical bill by $5 to $7.
The Topeka utility fashioned an agreement with KCC staff, many of its largest industrial customers and the Citizens’ Utility Ratepayers Board. Last week, the commission voted unanimously to approve it.
The increase will generate an additional $78 million a year for Westar. The consumer board acknowledged that Westar was entitled to make customers pay for power plant upgrades to meet environmental mandates.
Manitoba Hydro has revealed the planned route for a proposed $350 million transmission line that will link it to the Wisconsin Public Service Corp. grid. The line would run from northwest of Winnipeg to the Manitoba-Minnesota border.
Called the Manitoba-Minnesota Transmission Project, it is part of a deal in which Manitoba Hydro is selling 308 MW of hydro power capacity to WPSC.
Baltimore Customers Might Get Hit with Higher Rates
Baltimore’s Board of Estimates has more than tripled the rate for using city-owned underground conduit. The system’s largest user, Baltimore Gas & Electric, says it will try to pass those costs on to customers in higher rates.
Beginning Nov. 1, companies will have to pay an annual usage charge of $3.33/foot, up from 98 cents. BGE has said it will try to raise residential rates by $7 or $8 per month, and from $15 to $3,350 for businesses, depending on how much electricity they use.
The Baltimore Department of Transportation said the rate increase was necessary to repair the crumbling system, which was built in the early 1900s.
A growing number of residents are joining solar cooperatives, which allow them to save money by buying rooftop solar systems in bulk.
Central Maryland is home to at least nine such groups, and 150 homeowners from the Baltimore area joined Retrofit Baltimore’s first co-op, leading it to open a second round of requests from residents in the City of Baltimore and Baltimore, Arundel and Howard counties.
According to the Community Power Network, which builds solar energy projects, a 9-kW system that normally would cost a homeowner about $31,000 can be purchased by a co-op for $13,000.
A suburban resident and a Baltimore Gas & Electric worker responding to a reported gas leak were injured after a house exploded and five other houses burned in Howard County on Wednesday.
The utility worker, who was responding to a suspected gas leak in an unoccupied house in Columbia, ordered the evacuation of surrounding homes moments before the vacant home exploded. The BGE employee was treated for minor burns and released. Fire officials said a resident of one of the damaged homes suffered respiratory problems and was taken to a nearby hospital.
“I’ve never seen anything like it,” said Ira Gershman, who lives in an adjacent house. “It was like a bomb.” The cause of the explosion is under investigation.
Attorney General Blasts DPU for Approving Pipelines too Quickly
Healey
State Attorney General Maura Healey is criticizing the Department of Public Utilities for approving three contracts for the Northeast Energy Direct pipeline “without knowing all the facts.”
In a letter to FERC, Healey complained that the agency approved requests by Boston Gas, Columbia Gas and Berkshire Gas for long-term capacity on the 188-mile pipeline without considering “the interrelationship of gas and electric markets” and conducting a “factual analysis of future demand.”
Meanwhile, advocacy group Northeast Energy Solutions has asked the Supreme Judicial Court to set aside a DPU order denying the organization’s ability to intervene as a full participant in hearings over the project. The group said the state agency failed to conduct a “fair and comprehensive” hearing. It joins the Pipeline Awareness Network of New England and the Conservation Law Foundation in taking legal action against the DPU.
Kinder Morgan subsidiary Tennessee Gas Pipeline wants to build the pipeline, which would run from Wright, N.Y., to Dracut, Mass. It is undergoing FERC review.
A three-year look at fracking in the state shows that the public isn’t wholly convinced the practice is a good one.
Researchers from the University of Michigan say the oil and natural gas industry, and lawmakers and regulators, have a large job on their hands to convince voters to allow the practice to continue. There is a movement to ban fracking because of environmental and health concerns.
Officials from the Department of Environmental Quality said they will review the report and use it to help make decisions going forward.
The state’s U.S. senators, expressing concern about oil pipeline spills, have proposed legislation that would ban all crude oil transport vessels on the Great Lakes and would increase scrutiny of existing underwater pipelines.
Sens. Gary Peters and Debbie Stabenow, both Democrats, introduced the Pipeline Improvement and Preventing Spills Act, citing concern over the operation of the 62-year-old Enbridge pipeline under Lake Michigan, the site of a 2010 oil spill.
“This common-sense legislation will help us prevent an oil spill in the Great Lakes, whether it’s a tanker accident or a pipeline leak in the Straits of Mackinac,” Peters said. In addition to banning tanker transport on the Great Lakes, it would also designate the Great Lakes a “high consequence” area, calling for increased federal review and safety requirements for existing pipelines.
Utilities Try to Keep up with EV Owners’ Charging Needs
The number of electric vehicles in the state has more than doubled to 3,200 in recent years, and local communities are trying to figure out how to serve and capitalize on the growing market.
Governments are following retailers’ lead and locating electric vehicle charging stations at public facilities such as libraries, regional parks and transit stations, triggering a debate about how much to charge car owners to plug in.
“A lot of private agencies and local governments are struggling with that right now,” said Taud Hoopingarner, Dakota County’s operations management director. “The jury’s still out on what the appropriate rate is.”
Regulators Say New Data Gives Ameren Time to Model SO2
State regulators say they can’t tell if Ameren Missouri’s Labadie coal plant is violating air pollution standards and gave the utility more time to measure air quality before deciding whether to take action.
The Department of Natural Resources disclosed new data gathered by Ameren that caused the department to second-guess its models, which had suggested the plant was violating sulfur dioxide limits. Because of the discrepancy between Ameren’s data and state models, the department recommended calling the area “unclassifiable,” meaning that data might need to be collected for years before determining if the area is in violation of federal rules.
The Air Conservation Commission unanimously adopted DNR’s recommendation at its Sept. 24 meeting.
Electric distribution companies have started setting their winter energy service rates, and the first company out of the gate, Liberty Utilities, has proposed a residential rate of 9.2 cents/kWh from Nov. 1 to July 31, a 40% reduction from last winter’s rate of 15.4 cents.
Liberty serves about 6% of the retail customers in the state, mostly in the Salem-Derry area and Upper Valley. The lower rate means a Liberty residential customer using an average of 500 kWh in November will pay $46, compared to $77 in November of last year.
Eversource Energy, which serves 75% of the state’s residential customers, had the lowest rate of the state’s three regulated utilities last winter, at 10.56 cents/kWh.
The staff of the Public Utilities Commission says that the divestiture of Eversource Energy’s power plants would cost ratepayers money and should be put off for at least five years. An agreement earlier this year resolved several issues that have been pending between the PUC’s Electric Division and the state’s largest utility, such as who pays for $425 million worth of upgrades to the Eversource coal-fired plant in Bow. But changing conditions in the electricity market led the technical staff to suggest the projected savings have been overstated.
“We find that the customer savings as anticipated by Eversource and the settling parties are by no means clear and that the sale of Eversource generation assets at this time may actually burden ratepayers to a greater degree than maintaining the status quo,” according to an analysis by the PUC staff.
Regulators Give Energy Industry 10 More Months to Cut Flaring
Recognizing that economic pressures have made it difficult to meet a strict deadline on capturing natural gas that is flaring from wells, regulators and the governor have given the energy industry another 10 months to cut their gas emissions from wellheads and other parts of the drilling and collecting apparatus by 85%.
Industry officials had argued that widespread adoption of the infrastructure needed to capture the escaping gas was almost impossible to complete by the original deadline. The new deadline is Nov. 1, 2016.
AEP Energy is building a 3.6-MW solar plant and has secured a 20-year agreement to sell the output to the municipal power system of Clyde.
The American Electric Power subsidiary said the Clyde Solar Energy Center will generate enough power to supply 550 residences. The plant, which will be built on 20 acres of city-owned land, is scheduled to be completed by the first half of 2016.
“The City of Clyde has been pursuing this zero emission project since 2011,” city officials said. “This is another major step toward that goal.”
State Rep. David Zimmerman has proposed a bill that would prevent the Public Utility Commission from limiting how much power derived from methane systems could be sold to offset the cost of such systems.
The move stemmed from a debate over whether a state net-metering law requiring utilities to purchase excess power generated by small-scale wind and solar units is fair to the agricultural companies and their customers.
Utilities have complained that paying retail price for wholesale power will drive up the price of electricity. Energy companies also say that getting the power distributed onto the grid shifts costs from one consumer class to another. About 97% of the state’s net metering facilities are solar.
Austin City Council in Fight over Purchasing 600 MW of Solar
The Austin City Council is debating how Austin Energy will pay for 600 MW of solar power by 2017, nearly triple the amount of solar energy currently in the utility’s solar portfolio.
Austin Energy recommends that it should buy 200 to 300 MW of solar power this year through a power purchase agreement with a West Texas solar farm developer. That agreement could cost between $22.5 million and $33.2 million per year for a period between 15 to 25 years, and is paid for through a fuel charge on its customer’s bills.
After it adds 600 MW, Austin Energy would generate more of its power from the sun than any other utility in the state. The utility is set to generate 55% of its power from renewable sources by 2025.
MISO told FERC last week that a group of wind generators alleging special treatment for external generators misunderstands the purpose of the M2 milestone payment in the RTO’s interconnection process (EL15-99).
The generators — EDF Renewable Energy, E.ON Climate & Renewables N.A. and Invenergy — complained to FERC earlier this month that revisions to MISO’s rules would exempt generation outside the RTO’s footprint from providing a cash-at-risk deposit in order to enter the definitive planning phase of the study queue. They argued this was unfair to internal generators, which are required to make the deposit, known as the M2 milestone. (See MISO Beats Challenge on Wind Exports.)
MISO said the complainants are asking that existing external generators seeking network resource interconnection service (NRIS) pay the M2 milestone, which is only required for new generation, regardless of its location. The RTO said the milestone isn’t charged to existing internal generation that only seeks NRIS.
The payment, approved by the commission in 2012, is to discourage speculative projects from entering the queue; withdrawals from the queue result in time-consuming and costly restudies.
“The M2 milestone is a ‘readiness’ milestone, designed to demonstrate that projects are ready to proceed to commercial operation,” MISO said. “External NRIS projects need not demonstrate ‘readiness’ because they must be ‘existing’ generators by definition under the MISO Tariff.”
MISO also disputed the complaint’s claim that not having to paying the M2 milestone gave external generators an unfair competitive advantage. Because it treats existing generation the same regardless of location, MISO said, “under complainants’ theory, internal NRIS-only projects within MISO also would have an unfair advantage, and by extension, also should pay the M2 milestone. Such a position is a collateral attack on the commission-approved Tariff that provides for different payments for NRIS-only projects as just and reasonable.”
‘Unripe Complaint’
MISO also criticized the generators’ decision to file an ‘unripe complaint,’ saying that the language of the revisions was not final. The RTO said such filings circumvent the stakeholder process and that FERC should continue to discourage them.
The generators said that their decision to file was based in part on an e-mail from MISO to Wind on the Wires that said the Business Practice Manual revisions concerning M2 milestone payments was final.
The Planning Advisory Committee in August tabled WoW’s proposal that all external generators seeking NRIS pay a portion of the M2 milestone.
The issue was to be taken up again at the PAC’s Sept. 16 meeting but was struck from the agenda at the request of WoW’s Sean Brady.
Brady said he asked to remove the item from the agenda because of MISO’s email. “Making the BPM language effective immediately indicated that this matter was resolved and a vote on the M2 milestone payment was moot,” he said.
Talen Energy asked FERC on Friday to allow it to sell four generators totaling 1,351 MW in eastern PJM to satisfy divesture conditions the commission set in a December order approving the company’s formation (EC14-112).
In their application to spin off their generation into the new company, PPL and Riverstone Holdings proposed two mitigation packages.
One involved divestiture of six Riverstone plants, and one PPL plant, in New Jersey and Pennsylvania totaling 1,315 MW. The second involved the same six Riverstone plants, plus the 399-MW Crane coal-fired plant in Maryland and two PPL hydro plants in Pennsylvania, for a total of 1,346 MW. (See PPL, Riverstone Accept FERC Mitigation Plan on Talen Spinoff.)
Talen now says it wants to replace the two divestiture packages with a third involving the Crane plant and three former PPL generators in Pennsylvania: the 660-MW Ironwood combined-cycle plant, the 248-MW Holtwood hydro plant and the 44-MW Wallenpaupack hydro generator.
Talen said its request was the result of its inability to negotiate a lease extension for its 158-MW combined-cycle plant in Bayonne, N.J., which was part of both previous divestiture options.
The Bayonne plant provides steam to a tank terminal storage facility, which owns the land beneath the generator. The storage facility is owned by a subsidiary of Macquarie Infrastructure Co., the Australian conglomerate.
Macquarie informed Riverstone last October of its intention not to extend the lease on the generator. (In February, Macquarie agreed to purchase the nearby Bayonne Energy Center, a 512-MW gas-fired generator, from ArcLight Capital Partners.)
Talen said efforts to negotiate an extension of the lease beyond its current expiration in October 2018 “proved futile,” forcing it to retire the plant effective Nov. 1, 2018.
“Accordingly, divesting the Bayonne facility could prove challenging,” Talen said. The proposed “Option 3” divestiture package will provide “the market more flexibility to identify the assets more highly valued by potential purchasers,” it said.
Talen said the revised divestiture plan would have essentially the same reduction in the company’s market power.
The company — which is required to complete its divestiture by June 1, 2016 — asked FERC to rule on its request by Nov. 30.
FERC has agreed to a pre-filing review of Columbia Gas Transmission’s proposed 165-mile natural gas pipeline in West Virginia. Columbia said the formal application of the $2 billion Mountaineer Express Project will be filed in April. If approved, construction will begin in the second half of 2017.
The proposed pipeline is designed to give producers in the Marcellus and Utica shale regions a new gateway to markets in the east. The pre-filing process, which involves a series of public scoping sessions, allows the pipeline operator to modify its design before submitting a formal application.
Senate Democrats Ask Obama to Block Arctic Drilling
A dozen Democratic U.S. Senators last week sent a letter to President Obama asking him to block any more drilling in the Arctic Ocean. The senators had previously opposed Royal Dutch Shell’s drilling program in the Chukchi Sea, which Obama allowed.
“You have stated many times that America must reduce our greenhouse gas emissions and build our capacity for clean, renewable energy,” the letter reads. “Allowing Shell to expand fossil fuel drilling in the Arctic is incompatible with this imperative and with your commitment that the United States will lead the global effort to address climate change.”
The letter was signed by Sens. Sheldon Whitehouse (R.I.), Jeff Merkley (Ore.), Patrick Leahy (Vt.), Ben Cardin (Md.), Bernie Sanders (Vt.), Al Franken (Minn.), Richard Blumenthal (Conn.), Brian Schatz (Hawaii), Martin Heinrich (N.M.), Ed Markey (Mass.), Cory Booker (N.J.) and Gary Peters (Mich.).
NRC Inspecting Failure of Control Valves at Callaway
The Nuclear Regulatory Commission is conducting a special investigation into the failure of three of four steam generator water-flow control valves at Ameren’s Callaway nuclear plant in Fulton, Mo.
The failures were noted in three separate instances: one in August 2014, one in December 2014 and a third at an unspecified date. The 2014 incidents were related to a system modification. The third instance was also related to the same system and has since been corrected.
“The purpose of this special inspection is to better understand the circumstances surrounding the valve failures, determine if the licensee’s extent of condition review was sufficiently comprehensive and review the licensee’s corrective actions to ensure that the causes of the failures have been effectively addressed,” NRC Region IV Administrator Marc Dapas said. Callaway is a 1,190-MW single-unit station that went commercial in 1984.
EPA Hears Criticism of Proposed Methane Emission Rule
Representatives of the oil and gas industry told the Environmental Protection Agency that its proposed rules controlling methane emissions could kill the incentive to produce natural gas.
Industry representatives shared their views at a meeting in Colorado hosted by EPA to hear feedback on the proposed rule, which would cut emissions by 40 to 45% by 2025 compared with 2012 levels. The agency said the rule could add $420 million annually to the cost of energy extraction but would reduce health care costs by up to $550 million a year.
But Kathleen Sgamma of the Western Energy Alliance said the rule would push up the price of natural gas and maybe convince industrial consumers to switch back to dirtier fuels, such as diesel. She and other industry officials noted that while the rules only target the oil and natural gas industries, other industries, such as agriculture, produce significant amounts of methane emissions but would remain unregulated.
PennEast Files FERC Application for Marcellus Shale Gas Pipeline
A group of New Jersey and Pennsylvania utilities filed a formal application with FERC to move forward with the controversial $1 billion PennEast Pipeline project to tap into Marcellus Shale natural gas production, saying the new pipeline would deliver low gas prices, stable electricity rates and a manufacturing renaissance to the region.
The 118-mile pipeline, which is fiercely opposed by environmentalists and adjoining landowners, will deliver 1 billion cubic feet of gas a day from the Marcellus gas region to markets in Pennsylvania and New Jersey. About 72% of the capacity is committed to local distribution companies, including UGI Utilities in Pennsylvania and Public Service Electric & Gas, South Jersey Gas, Elizabethtown Gas and New Jersey Gas in New Jersey. Power plant operators and gas producers have locked up the rest of the capacity.
The Energy Department has agreed to reopen the environmental study of the Northern Pass transmission line, which would import hydroelectric power from Canada.
Developer Eversource Energy made enough changes to the transmission line’s route to warrant preparation of a supplement to the draft Environmental Impact Statement, the department said. Political leaders and environmental groups asked the department to reopen the environmental review of the project in light of the new tower heights, configuration and locations.
The department is also extending the public comment period on the draft EIS to Dec. 31, 2015, and postponing the public hearings to a date to be determined before the end of the new public comment period. Eversource said it does not expect the changes to the schedule will delay the project.
Feds Plan Auction of Offshore Leases for Windmills
Federal officials will seek bids to lease nearly 344,000 acres of ocean floor off of New Jersey on Nov. 9. If fully developed, the area could provide enough power for 1.2 million homes, according to the Interior Department and the Bureau of Ocean Energy Management.
Thirteen companies have qualified to bid on the leases in an area which runs roughly from Long Beach Island to Cape May. Gov. Chris Christie’s administration would have to approve the projects.
By Christopher Hargett, Diana McNally-Barsotti and Joel Yu
The benefits of wholesale electric markets can only be achieved when competition is effective. FERC must not only provide for markets that benefit customers but must also not lose sight of the importance of protecting markets (and customers) against market power abuses. To this end, the focus on customer impacts must remain as FERC considers changes to existing electric market offer caps. Some organized markets have sought to increase offer caps to levels above $1,000/MWh because of the impact seen from high natural gas prices during the extreme weather events in the winter of 2013/14. Such efforts are overly reactionary to one winter season experience and do not indicate that a change in policy and consumer protection is warranted at this time. Moreover, they are predicated on the misguided belief that increasing the offer cap is the only means to properly compensate generators for their performance. Since the advent of organized electric market operation, there has been no evidence that a change to this important offer cap is needed.
Protecting Electric Customers
Bids into wholesale electric markets and associated federal regulations are based on the premise that, absent market power, competitive market pressure should discipline offers to levels at or near suppliers’ marginal costs required to cover short-run operations (including opportunity costs). However, because marginal suppliers may be limited during peak periods, and because the market demand-side load is generally not price responsive, a truly functional competitive market may not be present. As a result, offer caps are necessary to protect customers from excessive prices as generation resources become scarce during high demand periods. Moreover, they take into account the fact that “prices are generally more sensitive to withholding and other anticompetitive conduct under high load conditions,” when more costly supply is required.[1]
Due to the experience of the 2013/2014 winter, organized electric markets are seeking to promote resource availability and performance in ways that add competitive forces to the market’s supply side during peak demand hours. While the organized electric markets have well developed mitigation measures in place, there is no substitute for the $1,000/MWh offer cap as a fail-safe protection to customers. Furthermore, energy market offer caps serve as a valuable incentive for generators to minimize fuel costs, which in turn translates into customer benefits through fair electricity prices. Moreover, the existing cap encourages generators to limit their reliance on spot fuel purchases. This incentive is not only good for economics but also for the reliable operation of the electric system. And, under existing rules, individual generators are able to be compensated for documented increased fuel costs when incurred. Such provisions protect generators as well as consumers, and any change to the offer cap should consider the experience with such requests, as discussed below.
It is also inaccurate to claim that higher short-term price signals will result in better resource performance and help maintain reliability. This hypothesis was proven false in PJM’s experience over the past two winters. In response to high natural gas prices in winter 2013/14, PJM temporarily increased its offer cap to $1,800/MWh for the 2014/15 winter but ultimately had no resource clear above $1,000/MWh. In fact, while prices cleared below $1,000/MWh, generators boosted performance year-over-year. When PJM experienced its all-time winter peak in February 2015, the generator forced outage was 13%, compared to 22% in January 2014. In New York, historical data supports this conclusion as well, as no generator in NYISO has ever demonstrated that it incurred costs above the $1,000/MWh offer cap, including the 2013/14 winter when natural gas prices spiked to unprecedented levels.
Regional Coordination
FERC should not act on a generic basis to modify energy market offer caps across organized markets, nor should it allow differences in offer caps between regions. Contrary to FERC’s goal, any difference in offer caps in neighboring regions would create unnecessary seams issues and could result in inefficient bidding behavior between regions. That’s because suppliers could concentrate their offers into the market with the higher offer cap, forcing operators in the lower offer cap region to call on resources out-of-market to meet their system reliability needs. This would unnecessarily increase costs to consumers in both regions. Such bidding incentives are an unjust application of market power and should be avoided. True price flexibility and differentiation between markets are, and should continue to be, a reflection of infrastructure constraints.
The Right Approach
Price signals are not the only tool available to compensate suppliers according to their cost of operation.[2] Out-of-market payments are the appropriately tailored solution when considering the precarious alternative. Taking this approach ensures that generators are compensated for their performance and for meeting customer needs in extreme conditions, without creating potential market vulnerabilities at all other times to the detriment of electric customers. Out-of-market payments address these rare costs in a fair manner for generators and customers and should be transparent for all market participants. Trends should be monitored, and any changes, if considered in the future, should be based on information about such payments.
[2] PJM recently received FERC approval for its Capacity Performance program, whereby units that perform under high demand conditions are rewarded. In New York, NYISO is undertaking several initiatives to bolster performance while ensuring compensation including clarifying market mitigation measures and fuel availability reporting.
Christopher Hargett, Diana McNally-Barsotti and Joel Yu are senior policy advisors at Con Edison. Subsidiaries Con Edison Company of New York and Orange and Rockland Utilities are transmission owners within NYISO. A subsidiary of Orange and Rockland Utilities, Rockland Electric, is a transmission owner within PJM.
(Editor’s Note: This column marks the beginning of an occasional RTO Insider feature, Stakeholder Soapbox. If you’d like to contribute your own op-ed article, contact Rich.Heidorn@RTOInsider.com.)
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.
