ISO-NE asked the Federal Energy Regulatory Commission last week to reverse its order directing a market-based solution for the next winter reliability program.
The RTO said that mandating a market-based solution now, instead of in three years as it originally contemplated, is premature. “The options for developing a market-based solution in the context of existing obligations are, at best, potentially less effective than the winter reliability programs and, at worst, less effective, inefficient, controversial and expensive to implement,” ISO-NE wrote in a Feb. 19 filing (ER14-2407-003).
ISO-NE’s Pay-for-Performance program is set to debut in late 2018. The RTO has relied on out-of-market solutions to ensure reliability over the past two winters and said it needed the interim time to develop more permanent fixes.
However, power generators in New England argued that the most recent FERC order accepting the temporary fix meant that a market-based solution should be in place for the 2015-2016 season (ER14-2407). FERC agreed in a clarification of that order issued on Jan. 20. (See FERC Orders Market-Based Reliability Program Next Winter in ISO-NE.)
New England has experienced severe natural gas pipeline constraints as the region’s power market switches to gas for power generation. Recent retirements of the Vermont Yankee nuclear station and coal-fired plants have also tightened supplies. The RTO has encouraged the development of dual-fuel generators with fuel oil as a back-up.
ISO-NE said the program to ensure adequate fuel supplies has succeeded, as demonstrated in recent weeks as New England endures a prolonged cold spell.
It also said that power generators have not advanced any potential solutions in the January or February Markets Committee meetings and that the passage of time means that developing a market-based approach for next winter is infeasible.
ISO-NE wants to have the rehearing question resolved by June 1.
Earnings from U.S. operations were a bright spot for Spanish utility conglomerate Iberdrola SA, as the company coped with the effects of slashed government subsidies for renewable energy in its home country.
Iberdrola said 2014 profits fell to 2.33 billion euros ($2.66 billion), from 2.57 billion euros in the same period last year. The Spanish government’s cuts in renewable-power subsidies and distribution reduced earnings by 617 million euros, the company said.
U.S. earnings, however, grew. “Our U.S. businesses grew EBITDA by 7.2% over last year, which enabled us to contribute more than $1.6 billion (1.2 billion euros) of EBITDA to the [Iberdrola] Group’s strong performance,” said Bob Kump, chief corporate officer of Iberdrola USA.
Subsidiary Iberdrola USA is the parent of New York State Electric & Gas, Rochester Gas & Electric, Central Maine Power and other natural gas units in Maine and New Hampshire, with a combined customer base of about 3 million.
Iberdrola officials pointed to a rate case in Maine that raised distribution rates by $24.3 million. Looking ahead, the company said it is on schedule and within budget for the Maine Power Reliability Program (MPRP), a $1.4 billion upgrade that includes 40 substations and 440 miles of transmission lines with links between Maine and New Brunswick, Canada.
The company is also due to file a rate case in the RG&E territory, which will positively affect earnings, it said. Other transmission investments are expected to pay dividends in the coming years.
“In New York now we’re already involved in two projects, transmission projects, to inject electricity into New York City,” CEO Ignacio Galan told analysts in the earnings call.
Through NYSEG and RG&E, Iberdrola is a partner in New York Transco, a joint venture designed to bring upstate power generation to the New York City area. It is also a partner in the Champlain Hudson Power Express project, which would ship hydropower from Quebec. (See NYISO Supports TO Exemptions to BSM Rules.)
DNREC Taking Public Comment on Controversial Refinery Water Permit
A plan by the Delaware City Refinery to upgrade its cooling water intake and discharge will be the subject of a public comment session on March 24.
The Department of Natural Resources and Environmental Control in December said it had reached a draft agreement with refinery owner PBF Energy that calls for the company to spend up to $10 million to reduce aquatic life deaths at its water intakes. Environmentalists, however, have called for measures to force the company to build a more expensive cooling tower system for the refinery to recycle cooling water, rather than the current method of drawing and discharging water directly from the Delaware River.
Lawmakers Introduce Bill to ‘Fix’ RPS, Set New Standards
Illinois lawmakers have introduced a bill that would increase the state’s renewable portfolio standard to 35% by 2030. The current standard calls for 25% of the state’s energy to be generated by renewable sources by 2025.
The bill, sponsored by state Sen. Don Harmon and Rep. Elaine Nekritz, directs the Illinois Power Agency to develop a long-term plan for renewables. The bill also provides guarantees that utilities will support residential and community solar installations, and encourages construction of utility-scale solar to be built on brownfields.
The legislation also directs the state Environmental Protection Agency to develop market-based strategies to reduce carbon emissions in the state.
House Committee Passes Bill Limiting Payments for Solar, Wind
A House committee last week passed a bill that would establish a fixed rate that utilities pay residential renewable energy owners, drawing protests from advocates.
The bill, HB 1320, would set a fixed rate that utilities would have to pay for electricity that small-scale solar and wind generators feed back to the grid. Opponents of the bill say they are worried that it would reduce incentives for small solar producers and that it could allow utilities to unfairly profit from reselling the power to other customers on their systems.
“For the last 10 years of my career, I’ve been working hard to develop a solar energy market in southern Indiana,” said Brad Morton, an Evansville resident and owner of Morton Solar. “HB 1320 takes away any little bit of economic incentive for rooftop solar and puts it right into the pockets of the utility companies.”
Utilities Board Turns Down Request for Separate Clean Line Hearing
The Utilities Board turned down a request from Clean Line Energy Partners to hold a special hearing to examine eminent domain issues associated with the company’s planned 500-mile Rock Island Line transmission project.
The commission, which needs to grant eminent domain rights as part of its approval process, said a separate hearing on eminent domain would inconvenience property owners along the transmission line’s route while providing a benefit to the company.
The company said the $2 billion project is going forward. The line would run from northwestern Iowa to Illinois. The project has already received approval from the Illinois Commerce Commission and the Federal Energy Regulatory Commission.
Public Utilities Board Denies Manitoba Hydro’s Rate Hike
The Public Utilities Board rejected Manitoba Hydro’s application for a 3.95% rate hike that would have gone into effect April 1.
It was good news for those who think the company’s rate hike requests are too frequent. “We are pleased the PUB has taken the side of Manitobans who pay the bills,” said Hydro critic Ralph Eichler. “We see Hydro as an asset owned by all Manitobans that must be managed thoughtfully and it appears the PUB agrees with us on this.”
Manitoba Hydro may still apply for a rate hike later in the year, however.
Bill Would Stop Fees for Customers Who Don’t Want Smart Meters
Two Maryland lawmakers are filing bills that would prohibit utilities from charging customers who don’t want smart meters on their homes or businesses.
Currently, the Public Service Commission allows customers to opt out of the various smart meter programs in the state, but it allows utilities to charge those customers fees to pay for the manual reading of their meters. Pepco charges an upfront fee of $75 for not getting a smart meter and a monthly charge of $11 to $17. Baltimore Gas & Electric, Delmarva Power & Light and Southern Maryland Electric Cooperative also charge to opt out of the programs.
A bill sponsored by Sen. Nathaniel J. McFadden and Del. Glen Glass would stop the fees, and also require utilities to notify customers before smart meters are installed. Pepco indicated that it would fight the bill.
Report: Death of Cape Wind Project Shows States Need to Work Together
The death of the Cape Wind project is an illustration of everything wrong with U.S. wind energy policy, according to a report commissioned by the Clean Energy Group.
The $2.6 billion project off Cape Cod was becalmed last month when two utilities with power purchase agreements backed out after Cape Wind missed financing deadlines.
The report said that instead of securing approval by one state, future projects should get an entire region to support the projects. “While the Cape Wind project floundered amidst fierce local opposition, the project’s difficulties highlight a larger policy problem — it is difficult, if not impossible, for any single state to jumpstart the offshore wind industry,” the report states.
Supreme Court Orders Mississippi Power to Return Kemper-Related Rate Increase Money
The state Supreme Court has ordered Southern Co. subsidiary Mississippi Power to refund $271 million in rate increases that it said the Public Service Commission improperly imposed to pay for a costly power plant.
The court’s decision concerns the PSC’s decision to allow rate recovery of Mississippi Power’s over-budget Kemper County integrated gasification combined-cycle plant. The commission allowed Mississippi Power to collect $125 million for construction costs in 2013 and another $156 million in 2014. The 582-MW plant has been plagued by cost overruns and delays.
The PSC, according to the ruling, never found that the funds were “prudently incurred,” a requirement for recovery. It also found that the PSC erred in not giving proper notice to the public about the company’s request for recovery, and by keeping confidential related information. “The commission’s decision to govern in a cloak of secrecy and grant confidentiality to rate-impact information was arbitrary and capricious,” the ruling said.
The Public Service Commission wants more information from Clean Line Energy Partners about its proposed 700-mile Grain Belt Express transmission line project before it will consider approving it.
The PSC said new questions arose after a series of technical hearings in Jefferson City about the project, which would deliver electricity from Midwestern wind farms in the east.
Opponents seeking to thwart the project declared victory. The commission’s order for more information is “a very tall order and will take considerable time and funds to produce,” said a group called Block Grain Belt Express. “We interpret this as an extremely promising sign.”
Keystone Opponents Vow to Keep Fighting No Matter What Feds Do
Keystone XL pipeline opponents said they will continue to fight a change in state law that allowed former Gov. Dave Heineman to approve the pipeline’s route, bypassing the Public Service Commission.
A group called Bold Nebraska has filed suit in state court to overturn the law and to give the routing decision back to the PSC. Opponents are also pressuring lawmakers to overturn the law.
TransCanada, the company seeking to build the pipeline, said it was temporarily halting efforts to seek route approvals in Nebraska. That move came a week after a Nebraska district court judge issued a temporary injunction barring the company from invoking eminent domain along the northern Nebraska pipeline route.
Cuomo Calls to Boost Oil Spill Fund from $25 Million to $40 Million
A day after a train carrying crude oil derailed and burst into flames in West Virginia, Gov. Andrew Cuomo’s administration proposed raising New York’s soil spill fund from $25 million to $40 million and shifting its control from the state comptroller to the Department of Environmental Conservation.
The fund is used for immediate payment of cleanup costs and is financed by penalties paid by violators. Albany has become an important oil-train hub since the boom in Bakken crude.
Supreme Court Sides with Duke on 2 Challenges to Rate Hike
The state Supreme Court on Wednesday upheld the Utilities Commission’s approval of a 2013 Duke Energy Carolinas rate hike, turning away challenges by the state Attorney General and NC WARN, a solar advocacy group.
The rate increase was based partly upon a 10.2% return on equity that the commission allowed Duke. NC WARN had argued that the company’s allocation of costs discriminated against residential customers. In December, the court upheld the company’s 2012 rate case. Attorney General Roy Cooper, who is eyeing a 2016 gubernatorial bid, has challenged several Duke rate increases.
TransCanada Proposes Another Pipeline – This One to Send Oil into Canada
The company that wants to build the Keystone XL pipeline is now proposing a second pipeline — this one to deliver oil from the state into Canada.
TransCanada is proposing to build a $600 million pipeline to go from northwestern North Dakota to Saskatchewan. The Upland Pipeline will need approval from the U.S. State Department, the Public Service Commission and Canada’s National Energy Board.
Supreme Court Rules States have Exclusive Authority over Fracking
The state Supreme Court has ruled that states have “exclusive authority” over hydraulic fracturing, and that cities and counties cannot regulate or ban the practice.
The 4-3 vote held that the Department of Natural Resources in 2004 was given the power to license and regulate where the state’s wells can be drilled. The ruling was seen as a victory for oil and gas producers, who often faced local opposition.
“We have consistently held that a municipal-licensing ordinance conflicts with a state-licensing scheme if the local ordinance restricts an activity which a state license permits,” wrote Justice Judith L. French in the majority opinion.
State Audit IDs Millions in Possible FirstEnergy Savings
A performance audit of FirstEnergy’s four utilities in the state identified ways to save nearly $20 million in one-time savings and a further $3.7 million annually.
The state audit made 28 recommendations. FirstEnergy has accepted 25 of them and is working to put new procedures in place by the end of 2019. The audit looked at 14 areas such as customer service, emergency preparedness and inventory management. The auditors said West Penn Power could save $8.4 million in inventory control improvements alone.
Public Service Department Asks for NRC Hearings on Yankee Plan
The Department of Public Service asked federal regulators to hold hearings on Entergy’s plan to cut back on emergency responsibilities now that its Vermont Yankee nuclear generating station has been permanently shut down.
The Nuclear Regulatory Commission said last week that it is setting up an Atomic Safety and Licensing Board panel to review the proposed changes. Entergy has said it wants to reduce its emergency responsibilities to reflect the plant’s lower risk profile.
The Public Service Commission issued a siting certificate to Moundsville Power for a 549-MW combined-cycle natural gas plant in Marshall County that will also be the first U.S. plant able to burn ethane.
The certificate allows Moundsville to seek financing for the $815 million project. When completed in early 2018, the plant will become a wholesale generator in the PJM market. In addition to helping offset carbon emissions from coal-fired plants, the Moundsville project will secure its natural gas and ethane from state sources.
Gov. Scott Walker named a former Madison Gas & Electric executive to head the state Department of Administration.
Scott Neitzel was named as the department’s new secretary a week after he abruptly resigned from a senior vice president position at MG&E. He is replacing Mike Huebsch, who is moving to the Public Service Commission.
Neitzel gave no reason for leaving MG&E, where he’d worked since 1997. He left behind a $315,180 salary. Before working at MG&E, he served a five-year term with the PSC.
WASHINGTON — Senior Environmental Protection Agency officials promised energy regulators and utility executives last week that the final carbon emission rule the agency issues this summer will protect reliability and not crush consumers.
But the message, delivered at the winter meetings of the National Association of Utility Regulatory Commissioners and a Federal Energy Regulatory Commission technical conference, left many in attendance skeptical. While officials said they will make changes to address concerns raised over the proposed rule issued last June, they offered few details.
EPA Administrator Gina McCarthy at NARUC’s 2015 Winter Meeting
EPA Administrator Gina McCarthy told a NARUC general session Tuesday that the agency has been taking critiques of the Clean Power Plan to heart. Referencing prior EPA rulemakings, McCarthy said “each and every time, we learned from the comment period.”
McCarthy acknowledged the frustration state and industry officials have expressed over the lack of certainty in the proposed rule, which seeks to reduce power plant emissions 30% by 2030. “We’ll try to be a lot more specific in the final rule so states can design their [compliance] plans with the certainty they’re looking for,” she said.
Later that day, Janet McCabe, acting assistant administrator for EPA’s Office of Air and Radiation, appeared on a NARUC panel discussion with FERC Commissioner Philip Moeller. McCabe and Moeller spoke after listening to utility regulators from states both supportive of the plan (California and Maryland) and those highly critical of it (Wisconsin, Wyoming, Arkansas and Texas).
McCabe also was the leadoff witness at FERC’s day-long technical conference on the reliability impacts of the plan Thursday.
The topics at the two forums included the “early cliff” of 2020 targets; states’ willingness to embrace regional and market compliance methods; how to craft a “reliability safety valve;” and the limitations of Order 1000.
In addition to McCabe, FERC heard from more than two dozen state regulators and industry and RTO officials — and about 10 protestors. The demonstrators, wearing red T-shirts and carrying signs, broke several times into chants of “Gas is dirty, wind and solar now,” before being escorted out by security.
McCabe Vague on Alternatives to Building Blocks
Many critics have challenged the assumptions in EPA’s four “building blocks” for achieving compliance: heat rate improvements, more natural gas generation, nuclear and renewables, and energy efficiency.
McCabe attempted to reassure FERC that there will be other ways to achieve EPA’s targets beyond the four spelled out in the agency’s proposed rule.
“A lot of attention has been zeroing on the four building blocks, and why they pose challenges and why EPA didn’t get that quite right,” McCabe said. “I think it’s important not to forget that there’s a range of other activities that states and utilities can engage in that will lead to reduced carbon.”
But, pressed by Moeller for details, the command she had displayed in reading a prepared statement was replaced with halting, vague sentences.
“A lot of the stakeholders and people in the industry are having good discussions about this. There are other ways to improve the efficiency of the system. One that’s been mentioned a number of times is transmission efficiencies and working on those areas …” she responded. “One of the significant uses of power in municipalities is water and wastewater. So efforts to be more efficient there can reduce the amount of power that’s needed. So we think there are a variety of things that can be done.”
Thursday’s “national overview” session was the first of four scheduled technical conferences on the EPA proposal’s impact on reliability and wholesale electricity markets.
FERC announced the conferences in response to a request from three Republican lawmakers, including Alaska Sen. Lisa Murkowski, chairman of the Energy and Natural Resources Committee. The Republicans said in a letter to FERC that EPA “lacks the mission and the expertise to determine what is necessary to maintain the reliability of the nation’s electric grid.”
Additional sessions are scheduled for Feb. 25 in Denver, March 11 in D.C. and March 31 in St. Louis (AD15-4).
The day-long technical conference included discussions on numerous aspects of EPA’s carbon emission rule. Below is a summary of several of them, along with links to the witnesses’ written testimony.
Downbeat Moeller Says Only 2 of 4 Building Blocks Work
Moeller on Thursday offered his harshest critique yet of EPA’s proposed carbon emission rule, saying that only two of the plan’s four “building blocks” are viable.
Moeller told the FERC technical conference that building block 1’s call for average heat rate improvements of 6% for coal steam electric generators is unrealistic and that states will be reluctant to adopt building block 4, which calls for improving demand-side energy efficiency to 1.5% annually, because of questions about how states will enforce such goals.
Building blocks 2 and 3 — dispatching natural gas combined-cycle units to up to a 70% capacity factor, and use of more zero- and low-emitting power sources — are also fraught with challenges, Moeller said.
“In the Midwest there’s already a lot of wind and a lot of transmission access. Can there be a lot more? Well, yeah, but basically the Midwest has got to get through to building block 2,” he told reporters during a break in the hearing.
“To go from what is a 24 to 28% capacity factor … now to something approaching 70[%] — I don’t see how the math lines up for peak demand for pipeline capacity in an area of the country that gets very, very cold. Is it doable? I hope so. But you go back to the fundamental problem I’ve been raising.”
That problem: finding new ways to fund pipeline expansions. While previous expansions have been backed by long-term contracts with local distribution companies, “the new customer base is power plants and the day-two market and they’re not likely to sign long-term firm contracts,” Moeller said. “So how do we get the financing for these new pipes?”
At the NARUC meetings, regulators from Wisconsin, Wyoming and Texas expressed similar concerns, with Wyoming Public Service Commission Chairman Alan Minier saying that none of the four methods would work for his state.
Regulators: ‘Bake in’ Reliability Safety Valve to Rule
Backers of a “reliability safety valve” said it should be explicitly included in the EPA rule to ensure it survives legal challenges.
FERC Chairman Cheryl LaFleur said she was aware of about four proposals, the most detailed of which she said was that of the ISO/RTO Council (IRC).
The IRC proposed that a safety valve be allowed to address reliability issues that were not previously identified or anticipated, or that arise or become fully identified during development or implementation of state plans. It would require independent verification by reliability authorities and be limited to issues that cannot be addressed by modifying a state plan in a way that would allow it to comply under its approved compliance schedule.
“We’ve got to write these processes into the final rule itself” to make it harder for courts to throw it out, said Craig Glazer, PJM vice president of federal government policy, representing the IRC. “If you write the reliability safety valve into the rule itself, it’s harder for a district court judge to find that you’ve violated the rule.”
John Moore, senior attorney for the Natural Resources Defense Council’s Sustainable FERC Project, said the rules for implementing the safety valve must be “fairly tight” to encourage states to first take advantage of the flexibility in the EPA rule.
With accurate reliability modeling, and proposer planning, “we think the reliability safety valve … will be needed a lot less than many say,” he said.
Carbon Price Adder: Rational and Cost Effective for Some, Political Poison for Others
Several witnesses, including those representing PJM and Exelon, called for implementing the rule through a carbon-price adder that would incorporate compliance into an RTO’s economic dispatch.
Kathleen Barrón, Exelon’s senior vice president of federal regulatory affairs and wholesale market policy, outlined a proposal that would have EPA set a nationwide price for carbon at a level high enough to reduce emissions to meet the Clean Power Plan’s goals. The plan is adopted from one suggested by Great River Energy, which serves 28 distribution cooperatives in Minnesota and Wisconsin.
States that opt-in would be considered in compliance under what Exelon calls a “Reliability Dispatch Safe Harbor.” Generators in those states would include the carbon fee as a variable operating cost.
The plan would boost the competitiveness of all low-carbon generators, including renewables and Exelon’s nuclear fleet, while allowing dispatch of high-emitting plants during times of high demand to ensure reliability.
States could require grid operators to return the collected carbon adders to electricity suppliers for refunds to consumers, mitigating compliance costs, Barrón said.
Exelon estimates the proposal could reduce states’ compliance costs by 75%, limiting retail rate increases to 2 to 5%.
PJM Executive Vice President for Operations Mike Kormos said a carbon price would be the simplest way for the RTO to help states achieve compliance. Although it would be more complicated, PJM could administer the system even with different states adopting different prices, he said.
“Absent an explicit price, it is unclear how an RTO would be able to allocate available run hours of units to when they are needed most,” Kormos said in his written testimony. “… Unit-specific environmental constraints could decrease price formation transparency as well as lead to congestion being transferred into uplift for which hedging is not possible.”
How would states react to such a proposal? Moeller wondered.
Maine Public Service Commissioner David Littell termed Exelon’s proposal a “very good one.” Maine is one of nine Northeast and Mid-Atlantic states in the Regional Greenhouse Gas Initiative, which administers a market-based cap-and-trade system. RGGI says it has reduced carbon emissions by 40% from 2005 levels.
But the idea is a non-starter in some other regions, such as the coal state of Kentucky. Public Service Commissioner James Gardner said complying with the Clean Power Plan will be much more difficult than meeting EPA’s Mercury and Air Toxics Standards (MATS) because the earlier rule didn’t require legislative approval.
“The key building block is the state and the state is a political entity,” said Gardner, who noted that the General Assembly has approved legislation that says the state can only include building block 1 (heat rate improvements) into its plan. “There’s no way Kentucky is going to approve a carbon price.”
Great River Energy Vice President Jon Brekke said stakeholders should push a market-based solution despite such opposition. “I think you can make a construct of the willing,” he said.
Relying on the market means you don’t have to choose winners among generation technologies in advance, he added. In contrast, EPA’s building-blocks approach treats renewables better than carbon capture and sequestration and nuclear fusion, two elusive technologies that Brekke said might become viable in the future.
Carla Peterman of the California Public Utilities Commission said the cheaper cost of compliance under a market-based system will attract reluctant states. “Once you start demonstrating that there are benefits, others will join.”
Littell agreed. Responding to a question from FERC Commissioner Norman Bay, Littell said more will join such a system “once we get through the litigation period” — court challenges to EPA’s authority. “I’m not so pessimistic” on a carbon price, he said. “Utilities are the ultimate rational actors.”
2020/2030 Deadlines
One of the most controversial aspects of EPA’s proposal is its interim 2020 carbon-reduction goals.
Gerard Anderson, CEO of DTE Energy and representing the Edison Electric Institute, said it was no problem getting consensus among EEI members on the need for a longer timeline for compliance. The EPA plan, he said, is the “most fundamental transformation of our bulk power stem that we have ever undertaken.”
Anderson said the plan requires most states to implement 50% of their compliance by 2020 and 11 states, including Michigan, to achieve 75% of their goal by the interim deadline.
Anderson said compliance could mean shuttering of 85 coal-fired generators in MISO, including 12 DTE generators representing 40% of energy production and 30% of peak production. “The front end of this is compressed in a way that affects reliability,” he said.
Jay Morrison, vice president of regulatory affairs for the National Rural Electricity Cooperative Association, said his members are concerned about the “early cliff” of the 2020 interim goals, with some fearing they won’t be able to comply with the final targets by 2030.
Morrison asked FERC to “recognize that reliability and affordability are two sides of the same coin.” Policymakers will have failed, he said, if “we keep the lights on but consumers can’t afford to flip the switch.”
Susan Kelley, president of the American Public Power Association, agreed. “Removing the 2020 cliff would be a huge help, but it doesn’t solve all the problems.”
Alexandra Dunn, executive director of the Environmental Council of the States, said the compressed timelines could result in less efficient, state-by-state compliance. “I’ve had states say ‘I don’t have time to work across state lines. I will have to write a plan that’s just about my state.’”
The NRDC’s Moore insisted “the rule doesn’t have a 2020 cliff.”
“We strongly disagree with the idea that resources are all facing that deadline,” he said, noting EPA’s requirement that states meet average emission targets between 2020 and 2029.
He said the reliability modeling NERC and some regions have done failed to fully account for new replacement generation above the minimum levels specified in the building blocks.
Interregional Transmission
Several speakers touched on the subject of interregional transmission, which could help deliver wind power to load centers that require low-carbon generation.
“Don’t hold your breath on interregional transmission,” said Moeller, “because Order 1000 kind of punted on that.” The order requires transmission providers only to “consider” whether the needs identified in their local and regional transmission plans could be addressed most cost-effectively through joint projects with a neighboring region.
Rob Gramlich, the American Wind Energy Association’s senior vice president for government and public affairs, said the commission should reconsider Order 1000’s public policy provision, which he said didn’t anticipate the Clean Power Plan. The order requires transmission providers only to identify transmission needs driven by public policies, and potential solutions, in their plans.
NRDC’s Moore agreed, saying “we’ve seen almost no interregional projects getting built.”
NYISO must amend its Tariff to establish uniform rules for identifying and compensating reliability-must-run (RMR) generators, the Federal Energy Regulatory Commission ruled Thursday.
“Without such provisions, there is no assurance that generation resources will be treated on a not unduly discriminatory basis and have the opportunity to collect compensatory rates without a protracted proceeding,” FERC ruled.
FERC ordered the ISO to make a compliance filing within 120 days specifying the rates, terms and conditions for RMR service (EL15-37).
Noting that the ISO has been unable for nearly four years to win stakeholder consensus regarding compensation for RMR units, FERC said “the commission thus has no expectation of NYISO and its stakeholders addressing the matter on their own. Yet, the need for RMR service remains.”
FERC said the lack of uniform rules created uncertainty that could compromise system reliability. It ordered NYISO to include in its filing a process for determining which generation resources seeking to deactivate are needed for reliability; compensation for RMR service, including accelerated cost recovery for generators that require upgrades, retrofitting or other investments; and how RMR costs should be allocated.
The commission pointed to MISO’s process for considering alternatives to RMRs, such as generator construction or transmission upgrades, and to PJM’s cost allocation method.
RMR agreements should be of limited duration and not prolong out-of-market solutions, FERC added. In addition, the Tariff provisions must include rules to minimize incentives for generators to “toggle” between RMR compensation and market-based rates, FERC said.
“The commission appreciates that uneconomic units could become economic for a number of reasons, including changing market conditions and the need for and timing of capital investments,” FERC said. “However, the commission is concerned that any proposed provisions not provide an incentive for a generation resource to propose to deactivate earlier than it otherwise would have in expectation of being needed for reliability and, therefore, be able to receive more revenues under an RMR service agreement than by remaining in the market.”
The order was spurred by two coal-fired generating stations in western New York, Dunkirk Power and Cayuga Operating Co., which had been targeted by their owners for mothballing.
The New York Public Service Commission had determined the two plants were needed to maintain reliability.
Dunkirk is a 635-MW, four-unit coal-fired plant outside Buffalo that owner NRG Energy sought to close in 2012. More recently, it won PSC approval to repower the plant as a 475-MW gas-fired station.
Cayuga is a 306-MW coal-fired plant in Lansing, near Ithaca, that is owned by Upstate New York Power Producers. It, too, sought to close its plant in 2012 due to economic factors and expensive upgrades needed to bring it into environmental compliance.
While the circumstances of the plants were similar, FERC noted that different filings were made before it or the PSC with various financial incentives to keep the plants operating. The companies requested cost-based RMR proceedings before FERC be held in abeyance while they negotiated reliability support services agreements (RSSAs) with the host utilities under the guidance of the PSC.
FERC last week rejected Dunkirk’s 2012 filing of an unexecuted cost-of-service RMR agreement. FERC said no service was ever provided under the agreement and the time period covered by it has expired (ER12-2237).
FERC granted Cayuga’s request to withdraw an unexecuted 2012 cost-of-service RMR agreement (ER13-405). Cayuga said the agreement was moot now that it has reached an agreement on an RSSA with New York State Electric & Gas.
Another RSSA proceeding in New York is underway to avoid the closing of the R.E. Ginna nuclear station outside Rochester. Plant owner Exelon and local utility Rochester Gas & Electric were ordered by the PSC to reach financial terms. Negotiations concluded and the agreement was filed with FERC and state regulators earlier this month. (See Ginna Nuclear Plant Wins Contract to Keep Operating).
Former FirstEnergy CEO Anthony Alexander announced last week that he will retire and leave the company’s board of directors at the end of April, after only four months as the company’s executive chairman. The announcement came just before the company released its year-end earnings report, showing that it sustained a net loss in the fourth quarter of 2014.
Alexander, 63, stepped down as the company’s CEO on Jan. 1 and took the executive chairman title to serve as an advisor to new CEO Charles Jones, 59.
Jones began the company’s fourth-quarter earnings call last week by thanking Alexander.
“Tony guided our company through a dramatic expansion and navigated through one of the most challenging periods in the history of the utility industry,” Jones said. “We certainly wish him well as he begins this new chapter in his life and enjoys more time with his family.”
Alexander spent 43 years with FirstEnergy, beginning his career in the tax department of the company’s predecessor, Ohio Edison.
Another Lackluster Year
FirstEnergy reported a net loss of $306 million ($0.73/share) in the fourth quarter of 2014, compared to net income of $142 million ($0.34/share) for the same period in 2013. Profits for the year dropped 23.7% to $299 million ($0.71/share) from $392 million ($0.94/share), the company reported.
CFO Jim Pearson cited reduced margins on competitive operations and milder weather that drove down residential sales as two of the primary drivers for the drop.
The company’s operating earnings for 2014 were $2.56/share, on the low end of the range it projected a year ago. (See Reboot for FirstEnergy.)
Rate Cases, Rebound for Competitive Operations?
Jones (Source: FirstEnergy)
Despite the drop in earnings, Jones was optimistic about the company’s future.
The company is still in the midst of shifting focus from its unregulated FirstEnergy Solutions subsidiary to upgrading in regulated transmission and distribution, according to Jones.
“We continue to believe the initiatives that were put in place during 2014 laid the path for our future growth and success,” he said, citing pending rate filings. “The recent major storm events that have impacted FirstEnergy’s service territory have highlighted a need for hardening of our distribution systems.”
He also defended the company’s approach to its competitive business.
“I’ve been asked numerous times about the possibility of divesting this business,” Jones said of FES. “Frankly, at this point in time it doesn’t make sense, while we are at or hopefully near the bottom of the market, to sell these assets at the lowest value they will likely ever have. In addition, capacity market reforms and pending changes to the treatment of demand response are likely to provide near-term value for this business.”
UBS Reiterates Sell Rating
Some analysts are not so hopeful. Following the company’s earnings call, UBS Securities reiterated its sell rating on the company and lowered its projections for 2015 operating earnings to $2.53/share from $2.68.
UBS also said it was skeptical of Jones’ assertions that it would not unload its competitive business, saying Alexander’s departure means less board support for merchant operations.
“While there’s nothing to confirm our thoughts here yet, we suspect management could yet look to spin/sell the business later this year,” UBS said. “… We expect the writing will largely be on the wall well before November following the outcome of the Ohio [Electric Security Plan] and PJM capacity auction.”
MISO will have to adopt neighbor SPP’s cost allocation method for interregional transmission facilities addressing reliability needs, and both RTOs must revise their proposal for public policy projects, the Federal Energy Regulatory Commission said Thursday.
However, FERC’s Feb. 19 ruling (ER13-1937) accepted the RTOs’ proposal to use adjusted production costs in allocating the costs of interregional transmission facilities addressing economic needs.
MISO and SPP agreed on a number of revisions to their joint operating agreement to comply with Order 1000’s interregional planning requirements. But the RTOs could not agree on apportioning costs for reliability projects.
FERC rejected MISO’s proposal to use only adjusted production costs to evaluate interregional reliability upgrades, saying it must adopt SPP’s plan, which also incorporates avoided costs.
FERC said it agreed with SPP that “adjusted production cost only measures the generation and congestion cost to serve load and does not account for the quantifiable benefits of meeting public policy requirements or addressing reliability issues.”
SPP argued that MISO’s proposal disregarded the nature of the constraint and forced the use of a metric that is irrelevant for measuring the benefits associated with resolving a reliability constraint.
“We agree that SPP’s proposal to use a combination of avoided costs and adjusted production cost savings allocates the costs of interregional transmission facilities addressing reliability needs to SPP and MISO in a manner that is at least roughly commensurate with the estimated benefits of the interregional transmission facility while ensuring that [the RTOs] are not involuntarily allocated costs of these interregional transmission facilities from which they do not benefit,” FERC said.
FERC, however, also faulted SPP because it said it would use a metric “yet to be determined” for public policy projects.
MISO and SPP will have 60 days to file revisions with the commission.
The Federal Energy Regulatory Commission last week approved changes to SPP’s Tariff that clarify the circumstances under which market participants are able to modify their mitigated offers during the operating day.
The commission’s order (ER15-714) approves three changes proposed by SPP to allow:
Market participants to adjust their mitigated energy, start-up, no-load and operating reserve offers during the intra-day period when the resource faces an unexpected need to change fuel types or incurs higher fuel costs due to a commitment extension by SPP;
“Quick-start” resources, which are able to generate power within 10 minutes of being notified by SPP, to address limitations in SPP’s clearing engine by reflecting their start-up and no-load costs in their mitigated energy offer curves; and
Resources with differences between their regulation and economic capacity operating limits to reflect in the real-time market their costs of ramping up or down.
“We find that the specific circumstances described in SPP’s proposal warrant allowing market participants to make intra-day adjustments to their mitigated offers without first seeking approval from the Market Monitor in order to better represent the short-run marginal costs of production for their resources,” FERC said.
SPP’s Independent Market Monitor supported the changes.
Entergy’s request for a $187 million transmission upgrade near Lake Charles, La., will receive a “full review” by MISO’s board following stakeholder dissent over its classification as an out-of-cycle project.
At the Planning Advisory Committee meeting last week, the transmission developer and independent power producer sectors voted against MISO staff’s conclusion that the request by Entergy qualified as an out-of-cycle reliability project. The vote was 2.2 in favor of the recommendation, two against and 4.8 abstaining.
Five smaller out-of-cycle proposals by Entergy received votes of 3.2 in favor and 3.8 abstaining, with the transmission developers voting against.
The MISO board must approve all out-of-cycle requests but only conducts “full” reviews for those receiving negative votes at the PAC.
George Dawe, vice president of Duke-American Transmission Co. and the representative for the transmission developers, told the PAC that MISO had failed to follow its procedures in all of the out-of-cycle requests and that the Lake Charles project failed to meet MISO’s out-of-cycle criteria.
MISO’s transmission planning rules allow out-of-cycle consideration for reliability needs identified after the deadline for inclusion in the annual Transmission Expansion Plan if the project is needed within three years and expected in service within four years. Entergy submitted the request last December, saying increased industrial demand requires the project be completed by June 2018.
Dawe argued that Lake Charles isn’t a baseline reliability project. He also said Entergy had not defined the new load it is citing as the need for the project. He said the scope of the project — including two new substations and 25 miles of 500-kV and 230-kV transmission — appears to be speculative, “beyond what is needed to reasonably serve load.”
Jeff Webb, MISO’s director of planning, repeatedly pressed Dawe to specify exactly how MISO was deviating from established procedures. He also asked that opponents state what alternatives they would suggest while still meeting the June 2018 in-service date sought by Entergy.
“I have trouble seeing how we are deviating from the process,” Webb said.
Stakeholders: Not Enough Details to Justify
“Generally,” Dawe replied, “more information has to be provided regarding this OOC project.”
Dawe said he would like to see evidence that MISO verified Entergy’s load requirements and consideration of alternatives to the project as proposed. “In our view … this project is ripe for [a] market-efficiency project” that could serve ratepayers more efficiently and cost-effectively, Dawe said.
Webb said that if MISO spent another month determining whether Lake Charles qualified as an efficiency project and should be opened to competition, it’s likely that “we wouldn’t have an approved developer until a year from now.”
The question then would be whether service would be in place in time. “You’re asking us, MISO, to take a huge risk,” Webb added.
Dawe reiterated that he didn’t believe Lake Charles met the qualifications for out-of-cycle status.
Beyond Reliability Needs?
Cynthia Crane, principal policy analyst at ITC Holdings, said the need for the upgrades has not been clearly demonstrated, raising doubts about the certainty of Entergy’s need date. Crane told the committee said she was speaking for her company and not the transmission owners sector, which voted yes for the Lake Charles OOC request. (EDITOR’S NOTE: An earlier version of this article incorrectly stated that Crane was speaking on behalf of the transmission owners sector.)
Tia Elliott, director of regulatory affairs for NRG Energy and the IPP sector’s representative, told the PAC that the sheer size of the Lake Charles project warrants further scrutiny.
The project is said to be key in bringing another 617 MW to the Lake Charles area to support a rebounding industrial base.
Crane said her company’s engineers looked at the proposed project and have some concerns that it is larger than is needed for just reliability purposes.
Another issue, she said, is declining oil prices, which portend a potential economic slowdown in the Gulf region. That raises the question of whether Entergy will need the upgrades as early as it has stated, she said.
Clouded by Customer Confidentiality
Webb, as he has in previous meetings in which the Entergy request has been discussed, said Entergy’s need for the project was consistent with previous growth projections presented by the utility and with growth trends in the region.
Charles Long, director of transmission planning for Entergy Services, said the company would have had to have known about additional customer demand by September 2013 to have made the request during the normal MTEP process.
Entergy filed the Lake Charles request with MISO on Dec. 15, saying it learned of the new demand Dec. 1.
MISO said that it has not been privy to customer communications with Entergy about their expansion plans. Entergy has said that information is confidential for competitive reasons.
One stakeholder suggested that utilities that cite confidentiality claims as a reason not to be as forthcoming with MISO should be summarily denied out-of-cycle requests.
Webb said he didn’t think MISO has the authority to delve into confidentiality agreements between a utility and its industrial customers.
Some 24,447 MW of capacity resources cleared Feb. 2nd’s auction at $9.55/kW-month, an increase of more than one-third over the $7.025/kW-month clearing price for most resources in FCA 8 last year. Administrative pricing was used in the Southeastern Massachusetts-Rhode Island zone, with prices set at $17.73/kW-month for 353 MW of new resources and $11.08/kW-month for 6,888 MW of existing resources.
The Federal Energy Regulatory Commission once again dashed the hopes of the New England congressional delegation seeking to challenge the results of last year’s capacity auction.
FERC Chairman Cheryl LaFleur wrote to the delegation on Feb. 18, telling members that FERC completed its review of the eighth Forward Capacity Auction when it denied a rehearing request in October.
“As that case is no longer an open case, we are unable to reopen the question of the justness and reasonableness of the FCA 8 rates,” LaFleur wrote. “However, even if we could reopen that proceeding, I continue to believe that the rates resulting from FCA 8 are just and reasonable.”
The auction became effective as an “operation of law” in September when the commission — then short one member — deadlocked 2-2 over whether to reject the results due to unchecked market power. (See FERC Commissioners at Odds over ISO-NE Capacity Auction).
The auction, held in February 2014, saw prices more than double from the previous year’s auction to a total of about $3 billion.
FERC is back to its full complement of five commissioners with the addition of former Arkansas regulator Colette Honorable. The delegation wrote to the commission, asking it to use Federal Power Act section 205 or 206 authority to look at the ISO-NE rates that have resulted from the auction. Those rates take effect in the 2017/18 capacity commitment period.
“We strongly supported the commission’s decision to conduct further review of the results of FCA 8 last summer but believe FERC’s failure to make a conclusive decision in September 2014 has unfairly left the ratepayers of New England without appropriate redress,” the delegation wrote Jan. 30. The letter was signed by six senators and 13 congressmen.
FCA 9, held Feb. 2, resulted in even higher prices — an estimated $4 billion for the 2018/19 capacity commitment period. Analysts said prices are likely to fall in the future as a result of new capacity that cleared in the 2015 auction. (See ISO-NE Capacity Prices Likely to Fall in Future.)
