MISO’s latest Order 1000 compliance filing — which revises the developer selection process and outlines a pro forma selected developer agreement (SDA) — has drawn criticism from developers and transmission owners seeking additional changes (ER15-2657).
MISO’s proposed Tariff changes, filed Sept. 16, include relaxing deadlines and participation requirements for the annual transmission developer qualification process to allow for “broader participation” in the competitive developer qualification and selection model. MISO prequalified 35 developers to bid on competitive transmission projects in 2014. This year, the RTO added 13 more developers.
Transource Energy, however, said that the changes to the selection process unreasonably grant MISO too much authority in transmission projects and their cost. The company said that under the revisions, MISO is allowed to unilaterally terminate developers’ SDAs and force them to bear the costs. Transource also accused the RTO of ignoring its feedback in the stakeholder process.
Similarly, Xcel Energy said that some of the changes “inappropriately expand the role of MISO.” For example, the company said, selected developers would be required to self-report any “potential violations” of federal or state law to MISO.
In a joint filing, International Transmission Co., Michigan Electric Transmission and ITC Midwest took issue with the requirement that developers submit projected revenue requirement information. This provision “could negatively impact an existing transmission owner’s ability to submit competitive bids because two developers with the same estimated costs will calculate different revenue requirements if one developer already has [a] plant in service in MISO.”
Little Rock-based Republic Transmission accused MISO of overlooking its duty to protect ratepayers in the interest of saving money for the RTO. The company said MISO ignored suggestions from stakeholders and provisions designed to cap or minimize the costs of projects in CAISO and PJM.
“MISO does not propose to ‘improve’ its developer selection process in a manner that protects MISO ratepayers by shifting its current minimal selection focus on cost to more heavily rely on the cost components of bids,” asserted Republic Transmission in its protest filing. “Much work remains in MISO for ratepayers to benefit from Order No. 1000.”
MISO seeks to implement the changes by Nov. 16, with the aim of posting its first competitive transmission project for bidding in January. Technically, MISO’s compliance obligations to meet Order 1000 ended on March 31, but the RTO elected to keep working with transmission owners and non-incumbent developers to refine Tariff language and develop a binding selected developer agreement.
“These enhancements and clarifications reflect MISO’s experience and discussions with stakeholders during the first year of the prequalification process as well as lessons learned from observing the processes of other RTOs,” MISO said.
MISO’s competitive transmission developer selection process has been the subject of four rounds of FERC compliance filings and, according to the RTO, 16 months of consultation with stakeholders. The RTO said it will make another compliance filing next month addressing other areas needing improvement.
LITTLE ROCK, Ark. — As expected, SPP staff brought a recommendation to the Markets and Operations Policy Committee for approval of one of three interregional projects coming out of the SPP-MISO coordinated system plan study.
“MISO has its own processes,” said David Kelley, SPP’s director of interregional relations. “So far, their analysis indicates they are not willing to move forward with any of the three.”
Staff recommended approval of the South Shreveport-Wallace Lake rebuild, an 11-mile 138-kV project addressing area congestion. SPP estimates the project has a cost of $18.5 million, of which it would fund 20% ($3.7 million), and a benefit-cost ratio of 11.86 — far exceeding the 1.0 threshold.
Kelley said three of the South Shreveport-Wallace Lake futures indicate the project yields “significant benefits,” 80% of which would go to MISO. He said the RTOs’ use the same B/C calculations, “but we use more benefit metrics to determine a project’s value than MISO does.”
SPP does not recommend approving the other two interregional projects evaluated as part of a regional review: the Alto-Swartz series reactor and the Elm Creek-NSUB 345-kV transmission line. Both could be reevaluated in a future regional or interregional study.
With MOPC members wondering how to proceed, Kelley said, “MISO still has [to conduct] a lot of robust discussions with stakeholders over its cost allocations … things we’ve already done.”
MISO has accepted SPP’s invitation to participate in a Thursday debrief of the study process, but Kelley sounded skeptical of a positive result. “Unless there are fundamental changes done with MISO’s stakeholder process, I don’t think [the South Shreveport-Wallace Lake rebuild] will be approved,” he said.
SPP Board of Directors Chair Jim Eckelberger said he would talk with his MISO counterpart, Mike Curran, to “see if the project can get legs and move forward.”
The two RTOs face a December deadline to come to agreement on the interregional projects, though the current six-month window can be extended. MISO’s Board of Directors meets Dec. 10 and will take up staff’s recommendation on the interregional projects at that time.
13 Revision Requests Approved
The MOPC approved 13 revision requests from the Market Working Group totaling about $11.5 million.
A request establishing a new incremental long-term congestion rights (ILTCR) allocation process passed the MOPC with 13 abstentions after clearing the MWG with one positive vote and 17 abstentions.
But, as MWG Chair Richard Ross of American Electric Power said, “We knew we had to move it forward. We have to do this.”
The revision was necessitated by FERC’s 2014 order finding fault with SPP’s interpretation of long-term congestion rights. The commission rejected multiple rehearing requests in July. (See FERC Rejects Rehearing on SPP Congestion Rights.)
The MWG’s new process will result in awards to market participants with ILTCRs when a transmission upgrade goes into service, instead of waiting until the annual LTCR allocation. Rights awarded in the initial allocation cannot be renewed; participants with candidate ILTCRs will be eligible to nominate in the same round of the next annual LTCR allocation as load-serving entity LTCRs.
A second revision request concerned the enhanced combined-cycle project, which was suspended last year to allow for a more thorough cost-benefit study and the Integrated System’s incorporation. The change is intended to ensure the ECC team implements the market-clearing engine’s logic on time and on budget by limiting combined-cycle configurations and offline supplemental offers.
The revision request received the SPP Market Monitoring Unit’s blessing and passed unanimously.
Other approved revision requests dealt with quick-start resource improvements, ramp-scarcity pricing and violation relaxation limits.
11 Transmission Projects Withdrawn in Quarterly Review
The MOPC unanimously approved staff’s recommendation to withdraw 11 notifications to construct (NTCs) as part of SPP’s quarterly review of transmission-expansion projects.
Two of those projects were among seven with out-of-bandwidth cost variances that had their NTCs suspended during the July MOPC meeting until further studies could be conducted. (See “Out-of-Bandwidth Projects Ordered Re-Evaluated,” in SPP BoD/Members Committee Briefs.)
Antoine Lucas, SPP’s planning director, said the additional analysis revealed there was not a reliability need for the Martin-Pantex North-Pantex South-Highland Park 115-kV rebuild (Southwestern Public Service) or the Labette-Neosho SES 69-kV rebuild (Westar). Lucas said a third re-studied project — the Iatan-Stranger Creek 345-kV voltage conversion (Westar/KCP&L Greater Missouri Operations) — should have its NTC reinstated, while the other four out-of-bandwidth projects require further analysis, as a need remains.
“We don’t want to continue to defer the [Iatan-Stranger Creek] project but reinstate the NTC because it’s still beneficial to the region,” Lucas said, referring to its inclusion as an economic project in the 2015 Integrated Transmission Planning 10-year assessment (ITP10).
The other nine withdrawn NTCs came from SPP’s re-evaluation of 24 projects at the transmission owners’ request. Lucas said staff did not have time to evaluate all of the projects; the 15 remaining projects require further analysis.
MOPC Approves ITP10 Scope
Members also approved a recommendation by SPP’s transmission and economic studies working groups to approve the 2017 ITP10 scope, following a discussion on the use of reliability standards.
Ross noted the scope didn’t take into account the North American Electric Reliability Corp.’s coming transmission planning (TPL) standards. “To do the analysis and not be aware of what’s coming would be a mistake,” he said.
Midwest Energy’s Bill Dowling urged incorporating the new TPL-001-4 standards, which take effect Jan. 1.
The committee approved the planning study’s scope with four ‘nay’ votes after inserting language requiring compliance with the TPL standards.
The study will consider three futures: a regional Clean Power Plan (CPP) solution, a state-level CPP solution and a solution assuming the CPP is not implemented. Each future also assumes competitive wind and solar development, high availability of natural gas due to fracking, expected load growth and inclusion of all statutory and regulatory renewable mandates.
The 2020 and 2025 models will include implementation of the Environmental Protection Agency’s interim CPP goals that begin in 2022 and 2025-2027 goals, respectively.
Work Continues on Transmission Planning Improvements
Completion of work to improve SPP’s transmission planning processes may slip from January to April, but the result will be a better product, NextEra Energy’s Brian Gedrich told the MOPC.
Gedrich said the Transmission Planning Improvement Task Force, which he chairs, needs more time despite adding meetings and conference calls to its schedule. “When I saw the only day we could double up on in December was the 25th, I decided maybe we needed more time,” Gedrich told the committee.
The task force faces a January deadline to recommend changes to create more efficient planning processes. Gedrich said the group has already unanimously agreed upon an 18-month planning cycle, a common planning model and a standardized scope. It has also agreed upon a comprehensive planning process that combines the near-term, 10-year and reliability processes into a 10-year study looking at reliability, economic, policy and compliance needs. The current 20-year assessment would be separated from the annual planning cycle.
“We’ve come a long way and had a lot of great ideas,” Gedrich said. “I think it will be fine if we let it slip a little and make sure we get this right.”
Eckelberger supported the delay when Gedrich delivered the same message to the Strategic Planning Committee.
“I’m not speaking for the board, but if you need a little more time and you get it really right, let’s do that,” he said.
The task force envisions overlapping 18-month planning cycles that would produce an annual assessment, with the ensuing cycle’s modeling development beginning as soon as the previous one was completed. By using only three futures, Gedrich said, incremental, easier-to-manage changes would be made from one cycle to the next.
The task force will work with other working groups to confirm the feasibility of its recommendations and to identify any other potential issues and solutions. Gedrich said the earliest the new planning cycle could be in place would be April 2019.
Z2 Crediting Task Force Remains on Track
Stakeholders and staff working on the beleaguered Z2 credit project are still targeting January’s MOPC and board meetings as to when transmission owners will learn the amount of bills that could be as much as 10 years old. (See SPP Z2 Project Team Still Grappling with Problem’s Size.)
The project team is working to create software that would properly credit and bill transmission customers for system upgrades under Tariff attachment Z2. The problem has been avoiding over-compensating project sponsors and including a way to “claw back” revenues from members who owe SPP money for other reasons.
“It would be helpful to see a number at some point,” said ITC Holdings’ Marguerite Wagner. “We know the historic stuff. We know how much has been paid by interconnection customers, but interest is accruing on this.”
Dennis Reed, director of FERC compliance for Westar Energy and chair of the Regional Tariff Working Group, estimated $750 million for creditable upgrades, with up to $90 million in transmission customer upgrades and the remainder from sponsored upgrades. He has said previously the Z2 team can’t produce an accurate number until the software is completed.
“We’re not going to be anywhere close to the final numbers, the real size, who’s owed and who owes until the first of the year,” Reed said. “That’s the only time I’ll be comfortable with saying how big the breadbox is.”
Software is being developed in three different modules (functionality, base calculations and settlement calculations) to help accelerate the process. At the same time, SPP staff has been reviewing previous aggregate transmission service studies dating back to 2005, developing a list of project sponsors and verifying final upgrade costs if the project is still in service.
The team expects to complete historic calculations and develop payment options by April 2016.
Capacity Margin Task Force
Stakeholders working on a task force updating SPP’s capacity margin requirements and methodology said last week its preliminary work indicates the RTO can reduce its planning reserve margin from 13.6% to about 10%.
“But we want to vet that with other stakeholders,” said Mid-Kansas Electric’s Tom Hestermann, who leads the group. “The last thing we want to do is recommend a reduction in planning reserves, and then several years later, have to re-do that.”
Hestermann said the task force is focused on bringing more value to the membership from its investment in transmission infrastructure and to provide a way for entities to meet shortages on a short-term basis. He said a preliminary loss-of-load expectation reserve margin study using existing models shows generation is available, “based on the robust transmission system we have.”
The task force has three white papers in various forms of completion, including one on deliverability and a second on load-responsible entities (accounting for the fact that not all SPP load is associated with load-serving members).
The third concerns a planning-reserve assurance policy. “We thought enforcement sounded kind of draconian,” Hestermann explained.
The team has also suggested a half-day workshop before the January MOPC meeting.
“When we finish our work as a task force,” Hestermann said, “we feel strongly someone should take ownership of this process.”
Integrated System Increases SPP System’s Ramp Rate
SPP’s C.J. Brown told members the Integrated System’s Oct. 1 integration was a “non-event,” with only some tagging and scheduling issues affecting a couple of new market participants. The integration brought on 2,400 MW of load during the transition, with 3,000 MW of generation online.
The system’s nearly 2,600 MW of hydro capacity nearly quadrupled SPP’s existing hydro. More importantly, Brown said, with its quick ramp rates, the hydropower has increased SPP’s rate ramp by 1 MW/minute.
“It may be a minute, but that’s a minute across the entire system,” he said.
Brown also noted SPP’s LMPs have been lowered with the integration, making the RTO more of an energy exporter than it was previously.
Mitigated Offer ‘Strike Team’ on Hold
SPP’s Matt Dillon told the MOPC a “strike team’s” work on mitigated offers is on hold following FERC’s recent rejection of what costs the RTO can include in mitigated offers. (See FERC Sides with SPP Monitor.)
Dillon said SPP has three options: 1) ask for a rehearing, 2) ask for a clarification of “short-run marginal cost” or 3) accept the commission’s decision.
Dillon said SPP remains undecided, and the strike team has no further action.
Nuclear Regulatory Commission Chairman Stephen Burns last week toured DTE Energy’s Fermi 2 nuclear generating station and said he was impressed with the upgrades made to the plant in the wake of the 2011 Fukushima disaster in Japan.
Fermi 2, which went into service in 1985, is equipped with the same type of General Electric Mark 1 reactor as the Fukushima plant, but it is 14 years younger than the Japanese reactor.
Burns and U.S. Rep. Tim Walberg (R-Mich.) toured the plant during a refueling outage. “The plant condition looks good,” Burns said. He was briefed mostly on upgrades to the plant’s ventilation system, a weak point in the Fukushima design.
NRC says Chatham House Report ‘Based on … Hearsay’
The Nuclear Regulatory Commission last week blasted a report by a British think tank asserting that U.S. nuclear power plants are at risk from cyberattacks. London-based Chatham House issued the report recently, saying the “risk of serious cyberattack on civil nuclear infrastructure is growing” because they rely on commercial “off-the-shelf” software.
NRC said the Chatham House report “is based on generalizations and hearsay.” It argued that “the NRC has been very forward-leaning on cyber security issues, and as a result the nuclear power industry is probably better protected than any other sector of our critical infrastructure.”
The Chatham House report did acknowledge that U.S. nuclear plant operators have taken steps to make them more secure from hacking but said more needs to be done.
Obama Administration Sends $15M to Bolster Coal State Economies
The Obama administration awarded $15 million in grants to fund workforce projects in coal-producing regions whose economies have suffered because of stricter federal environmental regulations.
The coal industry has shrunk and faces more pressure in the face of federal emissions regulations, low natural gas prices and the growth of renewable energy. The federal grants will fund retraining programs under Partnerships for Opportunity and Workforce and Economic Revitalization initiatives.
“These grants will help each community create new jobs, diversify its economic portfolio and better compete in the 21st century,” Commerce Secretary Penny Pritzker said.
The number of parties seeking to be heard concerning the PennEast Pipeline, which is planned to run from northeast Pennsylvania to New Jersey, is growing, according to FERC officials. The deadline for comments or to file for intervenor status is Oct. 29, a FERC spokeswoman said.
While FERC takes public comments into consideration, intervenors have legal status. There are 366 separate intervenor applications filed so far.
PennEast’s developers aren’t daunted by the number, however. A spokeswoman said there is a lot of community support for the proposed $1 billion, 114-mile natural gas pipeline. “There might be some people who are opposed to natural gas development, but there are a far greater number of people who want to receive clean, locally produced natural gas at reduced rates,” PennEast spokeswoman Patricia Kornick said. “They just aren’t on the docket.”
The Interior Department has announced it will suspend two upcoming auctions for offshore Arctic drilling rights, while rejecting the requests of two companies to explore for oil under their existing leases. The moves represent two more steps taken by the Obama administration to put the brakes on energy exploration in the region.
The department said it would cancel the previously scheduled auctions in 2016 and 2017 in the Chukchi and Beaufort seas, citing low industry interest and plunging oil prices. It also denied requests to extend leases by Shell and Statoil for parcels in the same areas, mirroring earlier actions taken against leases held by ConocoPhillips.
Secretary of the Interior Sally Jewell said the government was taking the action in response to Shell’s recent announcement that it was suspending exploration efforts in the Arctic, citing market conditions. “In light of Shell’s announcement, the amount of acreage already under lease and current market conditions, it does not make sense to prepare for lease sales in the Arctic in the next year and a half,” she said.
Application for Pennsylvania Hydro Project Submitted to FERC
A Pennsylvania developer has submitted an application to FERC for a preliminary permit for a hydropower facility to be built at the Blue Marsh Dam on a Delaware River tributary.
Developer Adam R. Rousselle II of New Hope wants to develop a hydropower project at an existing dam built in 1979 to control flooding of Tulpehocken Creek. The Delaware River Basin Commission had a preliminary permit to study such a facility at the same location, but that permit expired four years ago.
Rousselle is seeking a permit for a 2,500-kW generator. If the preliminary permit is approved, he will have three years to develop more studies on the project and submit a more detailed plan to FERC. The U.S. Army Corps of Engineer would also be involved in the approval process.
Calpine has agreed to buy the 12-year-old Granite Ridge Energy Center in Londonderry, N.H., for $500 million, or about $671/kW, the company said last week.
The 745-MW combined-cycle, gas-fired plant is located 45 miles north of Boston in ISO-NE. The acquisition will bring the company’s generation resources in the region to about 2,000 MW.
The plant, which went into operation in 2003, features two combustion turbines, two heat recovery steam generators and one steam turbine.
Xcel Completes Segment of $2B, 800-Mile Tx Project
Xcel Energy has completed its 90-mile, 345-kV segment between Minnesota and Wisconsin of the CapX2020 Hampton-Rochester-La Crosse transmission project. The project is 800 miles and begins in the Dakotas with two separate lines that converge in Minneapolis-St. Paul. The new segment terminates in Holmen, Wis., but the project will eventually extend to Madison.
The $2 billion project is expected to be completed in 2016. It is the area’s biggest upgrade of the transmission system in decades, according to project developers.
By the end of 2016, New Mexico will be producing another 165 MW of solar electricity from three large-scale generating facilities scheduled to go into service near Roswell and Deming.
Xcel Energy subsidiary Southwest Public Service has signed a long-term power purchase agreement with NextEra Energy Resources to build and operate two 70-MW solar sites, which will be the largest photovoltaic facilities in the state.
Tri-State Generation and Transmission Association, a wholesale power supplier for 44 electric cooperatives in New Mexico and three other states, also announced a deal with D.E. Shaw Renewable Investments and Denver-based TurningPoint Energy for a 25-MW solar facility in southeast New Mexico.
Ameren Adds Luminant’s Flores to Board of Directors
Rafael Flores, senior vice president and chief nuclear officer for Texas generator Luminant who is scheduled to retire at the end of the year, has been elected to Ameren’s board of directors effective Nov. 1. Flores’ election increases St. Louis-based Ameren’s board from 11 to 12.
Warner L. Baxter, Ameren’s chief executive, said Flores’ extensive nuclear operating experience will help guide Ameren, whose Callaway Energy Center is “a critical nuclear generation resource in providing safe, lean, reliable and reasonably priced energy.”
Flores has announced his retirement effective Dec. 31 after 32 years with Luminant. He oversees operations of the Comanche Peak nuclear plant southwest of Fort Worth and is active with the Nuclear Regulatory Commission, the Institute of Nuclear Power Operations and the Nuclear Energy Institute. He also serves on various committees and working groups in the nuclear industry.
Westar Announces 3 Gas Plants to Shut Down by Year’s End
Westar Energy announced plans last week to shut down three of its older gas-fired peaking units in Kansas by the end of the year. The move will mean the loss of 40 jobs, though Westar indicated it would give employees positions within the company.
Westar will close a 50-year-old, 167-MW combustion turbine at the Hutchinson Energy Center. It is also decommissioning a gas generator installed in 1962 at the Tecumseh plant near Topeka and another operating since 1954 in Lawrence.
“People are using less energy, so we no longer need these old, small generating units to meet peak electrical demand,” said John Bridson, Westar senior vice president of generation. “Plus, the current price to add more renewable energy is a reasonable alternative, so we’ll add more renewable energy, as needed.” The utility said its emission-free energy will equal more than 40% of its retail demand next year.
BNE Energy and Connecticut political leaders celebrated the launch of the state’s first commercial wind project by putting a mammoth turbine into service in Colebrook.
Two of the three turbines that were approved for the site have been erected at the 10-acre property, which is 1,500 feet above sea level. Once both wind turbines are operational, they will produce about 5 MW. BNE will not erect the third turbine until it secures a contract for the electricity that unit produces.
BNE Energy has a 20-year contract to sell the power produced by the two turbines to Eversource Energy. From 2011 to 2014, Connecticut was the only state in the country to ban wind farm development.
Citing market conditions, DTE Energy announced it is closing a 40-MW biomass plant in Cassville, Wis. DTE bought the E.J. Stoneman Electrical Station, a former coal-fired power plant, in 2008 and converted it to burn wood waste in 2010.
The power from the station was sold to Dairyland Power Cooperative. DTE said the plant was under pressure to generate affordable energy in the face of falling electricity prices from renewable energy projects in the region.
FirstEnergy Progressing on $260M Dewatering System
FirstEnergy is working to complete a dewatering facility at its giant Bruce Mansfield plant in Pennsylvania, which is expected to resolve the plant’s coal ash disposal issues. FirstEnergy has to complete the system in order to keep the 2,490-MW plant running after a Jan. 1, 2017, deadline for various emissions and ash-storage mandates.
“It’s a challenge, but we like challenges,” said James Fitzgerald, FirstEnergy manager of special projects. The facility will be able to handle between 2.5 million and 3 million tons of coal ash slurry per year. Once the ash is dried, it will be trucked to a number of company-owned disposal sites. The final destinations have not yet been decided, but one could be at the company’s Hatfield’s Ferry station in Fayette County, Pa. That power plant was retired in 2013.
The dewatering project is estimated to cost $260 million, up from initial estimates of $200 million.
The Nuclear Regulatory Commission initiated an inspection of Dominion Resources’ Millstone Unit 2 nuclear station in Connecticut after a leaking relief valve was found. The discovery triggered the declaration of an “unusual event” Oct. 4 at the plant, the lowest of four emergency classifications.
Millstone was preparing to power down for a refueling outage when the event occurred. NRC officials said the event raises questions about operator performance, and so it ordered an inspection.
Naperville’s municipal power provider has a $13.2 million shortfall, officials said. Since 2011, according to records, Naperville’s energy costs have exceeded projections every year, and by as much as 16% during fiscal 2014.
Much of the overrun can be traced to the utility’s membership in the Illinois Municipal Electric Agency and the assumed costs from the problem-plagued Prairie State Energy Campus. IMEA owns 15% of the project, which is expected to cost $4 billion and has experienced 25% in construction-cost overruns. Naperville and other IMEA members are paying a share of the overruns each month.
Former Naperville Councilman Bob Fieseler said the project’s costs add about $5 to every monthly residential electric bill.
Consumer Advocate Comes out Against Vectren’s Energy Efficiency Plan
The Utility Consumer Counselor is opposing Vectren’s proposal to boost rates to pay for its energy efficiency program, saying it would result in higher customer charges than are necessary.
UCC spokesman Anthony Swinger said Vectren already makes enough to fund the program without charging customers. Vectren proposed charging $1.10/month for residential customers to fund the program. Vectren said the program encourages energy conservation and affects the company’s bottom line.
Low energy prices will stunt the state’s economy over the next two years, although massive industrial projects will help drive job gains in the Baton Rouge and Lake Charles areas, according to an economic forecast released last week.
“Louisiana Economic Outlook: 2016 and 2017” projects that the state will add 15,400 jobs in 2016 and 19,600 in 2017. “Normally these numbers would be a lot better except for what’s going on in the oil patch,” said economist Loren Scott, co-author of the report.
The economic forecast also says new federal ozone rules could raise electricity rates so much that Baton Rouge may not be able to compete for new industry. Scott said the narrowing gap between the price of natural gas in the U.S. versus Europe and Asia may also slow industrial growth.
Environmentalists fear Gov. Larry Hogan’s administration is retreating from the previous Democratic administration’s support of renewable energy and energy efficiency after he shook up the state’s Energy Administration last week by firing two senior managers and moving the agency’s headquarters from Annapolis to Baltimore. The Republican also stated his opposition to raising rates to pay for energy efficiency efforts.
“The administration’s apparent hostility toward nationally recognized energy efficiency programs in this state is deeply troubling,” said Mike Tidwell, executive director of the Chesapeake Climate Action Network. “The No. 1 way to lower ratepayers’ bills is to invest in efficiency.”
A Hogan spokesman brushed off the concerns. “The governor and the director are 100% committed to continuing the great work the agency does,” spokesman Doug Mayer said. “This administration is against raising fees.”
The Public Service Commission has promoted Dan Hurley to director of the energy analysis and planning division and hired Tori Leonard as director of communications.
Hurley will oversee the agency’s energy efficiency and conservation programs, smart grid implementation and the state’s new renewable energy portfolio standard. Leonard will manage communications, media relations and social media.
Hurley, who joined the PSC in 2006 as a regulatory economist, has been an assistant director in the department since 2009. Leonard was the public relations manager at Rosborough Communications, working with the firm’s transportation clients.
Energy Secretary: Pilgrim’s Loss Means Time to Look at Hydro
Beaton
Entergy’s decision to shut down its Pilgrim nuclear generating station will leave the state looking for other ways to meet federal and state clean energy goals, and Energy and Environmental Affairs Secretary Matthew Beaton said Canadian hydropower could help.
The loss of Pilgrim is significant, he said. “It’s a big step back in meeting our Global Warming Solutions [Act] targets because it was over 80% of the clean energy we had to help us towards our clean energy goals,” Beaten said, “making it all the more important to see the other policy solutions we are pursuing actually happen.”
He said it may be possible to import hydropower from Quebec, an option explored by Gov. Charlie Baker.
Power producers are set to retire 25 coal-fired plants in the state by 2020, citing aging equipment and increasing environmental restrictions.
Coal currently provides more than 50% of the state’s electricity supply. Industry experts expect the state to replace the lost coal power by importing power through the regional grid and from new construction of gas-fired and renewable sources.
Under the Clean Power Plan, Michigan must reduce carbon emissions by 39% from 2012 levels by 2030. According to the U.S. Environmental Protection Agency, the state is on course to reach a 17% reduction by 2020. In September 2016, officials will be asked to hand over a plan detailing how the state will comply with the new regulations.
The state is on target to meet mandates set in 2008 to generate about 10% of its energy from renewable sources.
Gov. Rick Snyder outlined a renewable energy plan in March, encouraging the state to meet up to 40% of its power demand through “energy waste reduction, increased use of natural gas and renewable energy sources.”
According to the Public Service Commission, almost half of the state’s renewable energy comes from wind, 17% from landfill gas and solid waste and about 10% from hydroelectric. Solar power represents less than 1%.
Attorney General Chris Koster, who is running for governor, says he will join more than a dozen other states in suing the U.S. Environmental Protection Agency to challenge rules imposing targets on states to reduce carbon emissions.
The state’s utilities, including Ameren Missouri, had urged Koster to join the mostly Republican-led states fighting the rules. Koster, the only Democrat in the state’s governor’s race, has sued EPA over other recent regulations, including the controversial “Waters of the United States” rule strongly opposed by large agricultural interests.
Koster made the announcement during a speech at a meeting of rural electric cooperative members in Branson. He argued that the state’s businesses rely on lower-cost energy and that costs would rise under EPA’s rules, which would force the state to shift its heavy reliance on coal power to renewables and natural gas.
PSC Cuts NorthWestern’s Ability to Raise Rates to Make Up for EE
The Public Service Commission voted 5-0 to rescind a mechanism that had allowed NorthWestern Energy to raise rates to make up for demand lost because of energy efficiency programs. Commissioner Roger Koopman called the Lost Revenue Adjustment Mechanism “one of the worst ideas policymakers have ever come up with.”
Commissioner Kirk Bushman said, “It just doesn’t make sense for public policy to allow an electric company to encourage their customers to save money on their monthly bill by conserving energy, and then turn around and increase electricity rates on everybody to recover that lost revenue.”
The PSC ruling will reduce NorthWestern’s collections from state customers by about $12.7 million next year. The policy was put into effect in 2005 to compensate NorthWestern for reduced sales attributed to state mandated energy conservation programs.
A legislative committee instructed the Site Evaluation Committee, the state body responsible for issuing certificates to energy facilities, to revise key sections of its proposed rules for new projects such as the Northern Pass transmission line and the Kinder Morgan natural gas pipeline.
The legislators worked for three years with stakeholders to develop the new rules, which are opposed by energy industry and business representatives and generally supported by the environmental community.
But it’s still unclear if the Site Evaluation Committee will impose the new rules on the Northern Pass transmission project or the Kinder Morgan Northeast Energy Direct pipeline along the state’s southern boundary, according to Pamela Monroe, the committee’s administrator. Both projects have attracted opposition.
Fishermen’s Energy, a firm that wants to put five windmills about 3 miles off the coast of Atlantic City, will cut ties with its Chinese turbine partner and revamp its plan after learning that the state Supreme Court won’t hear its appeal of regulators’ numerous rejections.
Instead of using turbines from the Xiangtan Electric Manufacturing Group, whose financial condition did not meet regulators’ standards, the company will build a demonstration facility using turbines from German manufacturer Siemens.
The U.S. Department of Energy pledged up to $47 million for the project in May 2014, but the Board of Public Utilities declined to approve it, saying the project would need at least $100 million in federal subsidies to proceed. The wind farm, which developers are promoting as a pilot project, would generate an estimated 25 MW of power.
The Public Regulation Commission last week began a protracted hearing on the future of the coal-fired San Juan Generating Station. The hearing, which could last up to two weeks, will examine an agreement that plant co-owner and operator Public Service Company of New Mexico (PNM) signed in August with environmental groups, the Attorney General’s office and the commission’s staff. The agreement would shut down two of the plant’s four generating units.
The agreement provides for a new PRC review of San Juan in 2018 to determine whether the remaining two units should be shut down after 2022, when the current partnership among plant co-owners expires and PNM’s coal supply contract ends. PNM also agreed to lower ratepayer costs for nuclear energy to replace lost coal generation and to support more renewable energy development.
New Energy Economy, an environmental pressure group, is opposed to the agreement and advocates the immediate closure of more San Juan units and the procurement of more solar and wind generation.
Installations of new residential and commercial solar systems on Long Island in 2015 are set to eclipse sales of the previous eight years combined.
The market has been driven by falling system prices, an influx of aggressive national leasing companies, generous state and federal subsidies, and frustration with Long Island’s high electricity rates that are set to rise again next year, experts say.
The growth of solar is “staggering,” said Carlo Lanza, chairman of the Long Island Solar Energy Industry Association, a business group. Local solar employment has almost doubled in two years, to at least 2,500 workers, the group estimates. “What we always dreamed of seeing happen here is coming to fruition,” Lanza said.
An environmental group says Duke Energy’s gains in solar energy come at the expense of competing producers who want to participate in the solar revolution.
Duke says it has helped elevate the state to become the nation’s No. 4 producer of solar power and is installing photovoltaic facilities in a number of other states. But an advocacy group says Duke has worked with lawmakers to try to reduce subsidies for competing private solar projects.
Environment North Carolina, in a report titled “Blocking the Sun,” charges that Duke’s support of solar “only extends … to solar panels the utility owns and that deliver profits to its balance sheet.” A Duke spokesman dismissed the report as a “rehash of a lot of previous anti-utility reports and news accounts.”
Public Service Commission Chairman Julie Fedorchak reported last week that more than 16% of the retail electricity sold in the state in 2014 came from renewable sources (2.6 million MWh out of 16 million MWh).
The state exported more than half of the 36 million MWh of electricity it produced in 2014, which included about 27 million MWh of coal-fired energy and 8.8 million MWh of renewable energy, mostly wind power. Fedorchak said the state’s carbon dioxide emissions have dropped by more than 15% since 2002.
The PSC filed comments opposing the U.S. Environmental Protection Agency’s proposed Clean Power Plan, saying the rule is uneconomic, uses unrealistic assumptions and violates the Federal Power Act that gives states decision-making authority over their power supply.
The $5 billion Atlantic Coast Pipeline could be held up by 5 inches — the length of the Cow Knob salamander, which inhabits a protected area of the George Washington National Forest, in the path of the proposed project.
The salamander and its rocky, forested habitat are protected under a federal pact struck in 1994 aimed at maintaining the amphibian’s numbers so that it wouldn’t wind up on the endangered species list.
Currently, 5.5 miles of the 564-mile pipeline would run through the creatures’ home. Lead project partner Dominion Resources said it is evaluating its options and plans to meet with forest officials to discuss how the sensitive habitat could be avoided.
The state has joined Pennsylvania and Ohio in an agreement to work together to attract shale-related industry to the region, home to the most productive natural gas basins in the country, the Marcellus and Utica shales.
The effort was announced at a summit last week aimed at promoting cross-state efforts to woo manufacturers and petrochemical plants. The forum featured speakers who outlined focus areas such as interstate pipeline siting, public projects to store natural gas liquids and workforce training.
The states plan to bring together government, industry and economic development voices for more discussion.
The D.C. Public Service Commission should not reopen the record to consider a newly reached settlement in Exelon’s proposed $6.8 billion takeover of Pepco Holdings Inc., parties opposed to the deal said in a filing Friday.
PSC rules prohibit settlements to be submitted after a final decision, the group said, referring to the commission’s Aug. 25 rejection of the merger as not in the public interest. The group argued that the commission should require the companies to file a new application.
The group represents DC Solar United Neighborhoods, Grid 2.0 Working Group, Mid-Atlantic Renewable Energy Coalition and Maryland DC Virginia Solar Energy Industries Association.
The settlement, brokered by Mayor Muriel Bowser’s administration, was filed Oct. 6 in an attempt to persuade the commissioners to approve the deal, which has been approved by FERC, Delaware, Maryland, New Jersey and Virginia. (See Mayor’s Settlement Puts DC PSC on the Spot in Exelon-Pepco Deal.)
Regardless of the agreement, the filing said, “the public continues to share the commission’s concern that the ‘potential conflicts of interest inherent in Pepco’s role and its parent company’s policy positions and interests might inhibit our local distribution company from moving forward to embrace a cleaner and greener environment.’”
The prevailing concern involves Exelon’s commitment to its generation assets, in particular to its partly struggling nuclear fleet.
To shore up that point, the filing includes more than 800 emails from district residents opposing the merger, most using a template letter saying in part, “I am dismayed by the D.C. government’s behind-the-scenes Exelon settlement. Their secretive process took place over the objection of the majority of D.C. ratepayers. … Your unanimous ruling against the merger, and the thorough process that preceded it, restored faith in the district’s democratic institutions. Anything less than a full process now would deprive D.C. residents of our due process rights.”
The petitioners acknowledge that the commission has the right to waive its own rules, but they advised it not do so because of the unprecedented interest the case has drawn — more than 3,000 commenters, the most in the agency’s more than century-old existence.
“Many of the interested customers or groups have justifiably relied on the formal parties to present and champion their positions, including particularly the District of Columbia government and the Office of the People’s Counsel,” the filing said. “Now, both the district government and OPC have acceded to the terms that the joint applicants offered, so they no longer reliably represent the views of residential customers or groups that are unwilling to concede to Exelon.
“The realignment of some parties with Exelon and Pepco effectively muffles the public’s voice in any proceeding that merely reopens the existing case and that does not give other interested individuals or organizations a full opportunity to participate as parties.”
They allege that reopening the case would set a dangerous precedent for future applicants seeking to negotiate a settlement only after the commission has highlighted the deficiencies in their filing.
Friday was the deadline to submit comments regarding the joint applicants’ request to reopen the case.
In addition, the Ward 3 Democratic Committee submitted a filing saying that the settlement amounts to a new proposal and should be treated as such under a new application.
WASHINGTON — A newly formed advocacy group on Friday filed its intent to acquire the district assets of Pepco Holdings Inc. and transform it into a not-for-profit utility that it said will generate about $1 billion in savings over the next 20 years.
Not having to pay federal taxes or dividends to shareholders would “unlock” $150 million a year in savings — or about $60 million after subtracting debt — that could be spent on reliability, improvements and rate reductions, said Michael Siegel one of D.C. Public Power’s four board members, in announcing the proposal Friday morning at the National Press Club.
“Additional benefits will accrue by maintaining local ownership and presence as well as additional economic activity,” added board member John Chelen.
In its filing, DCPP also objected to the Public Service Commission reopening the record for Exelon’s proposed $6.8 billion acquisition of PHI and requested late intervenor status because the group was formed April 30, after the filing deadline for joining in the case. Other parties also objected to reopening the record. (See Opposing Parties to DC PSC: Require a New Exelon-Pepco Merger Application.)
‘Strong Interest’ from Lenders
Chelen said the group had received “strong interest” from “recognized investment banks” in financing the deal, which would occur after Exelon consummates the purchase.
The group said the utility’s debt would be “an extremely secure and attractive investment” because of the district’s strong economy and low interest rates for alternative investments.
It said PHI D.C.’s book value was $1.4 billion as of March 2013 — though shareholders would certainly seek a higher price in any sale.
Chelen said the group already had approached Exelon with its interest but was turned down.
Exelon, Pepco: No Deal
In a letter included in the filing, Exelon and PHI attorney Mark Director wrote that the concept “raises many complex legal, financial, regulatory, operational and commercial considerations. It would require substantial time to evaluate those complexities, and that would complicate and delay, rather than simplify and streamline, matters to be considered by the D.C. PSC and would require approvals from other regulatory authorities.
“As Exelon and PHI remain committed to completing their merger as promptly as possible, the companies do not believe it would be productive to have further conversations about your proposal.”
Said Chelen, “DCPP had, in fact, structured its proposal to be as uncomplicated as possible with the intent of facilitating Exelon’s and PHI’s ability to complete their merger. Perhaps the real reason is they were able to attract a better deal for them from the mayor and D.C. officials.”
That settlement was presented Oct. 6 to the PSC, which denied the merger as filed on Aug. 25 as not being in the public interest. (See Mayor’s Settlement Puts DC PSC on the Spot in Exelon-Pepco Deal.) The proposal envisions a non-profit board hiring an experienced utility operator to run day-to-day operations, similar to Long Island Power Authority’s contract with Public Service Enterprise Group.
Exelon referred a request for comment to Pepco. A PHI spokeswoman said Thursday that a district-only system would be “expensive and inefficient.”
Myra Oppel, regional communications vice president at PHI, said the group’s proposal “raises many complex legal, financial, regulatory, operational, commercial and customer considerations that the group has not begun to address.”
The group said it had discussed its proposal with numerous city leaders but not directly with Mayor Muriel Bowser. “Some people are wildly enthusiastic,” said Chelen. “Other people are guarded.”
Public Power in Cities
Of the about 2,200 power providers in the U.S., about 2,000 are public power, including Seattle, Los Angeles, Sacramento, Austin, Jacksonville and Cleveland. Only 200 are investor-owned utilities, though they tend to be in bigger cities.
The group said public power agencies similar to that of Chattanooga, Tenn. — a city about 60% the size of the district — have “extremely high capital productivity,” unlike IOUs, whose profits can increase with higher spending.
“From our point of view, the [Exelon-Pepco] deal relies on an extremely complex, vague and opaque non-unanimous settlement agreement [NSA] that will be a nightmare to monitor and enforce,” Chelen said.
“What is most disturbing is it calls upon divestiture that is the severance of Pepco D.C.-based assets as an ultimate means to ensure compliance,” he said. “The inclusion of this provision affirms that divestiture is the best method to secure the public interest. The NSA severance clause amounts to exclusive acknowledgment that the NSA is a risky deal for the district.”
[EDITOR’S NOTE: See updated story on D.C. Public Power’s filing Friday.]
By Suzanne Herel
A D.C. advocacy group on Friday will release details of a proposed alternative to the Exelon-Pepco Holdings Inc. merger that it says would provide up to $1 billion in benefits to the district over the next 20 years.
In a Sept. 28 filing with the D.C. Public Service Commission, D.C. Public Power, which advocates energy independence for district ratepayers, said that it planned to seek “an agreement with Exelon to acquire between 51 to 100% of PHI’s D.C.-based assets at an agreed-upon price and terms.”
The nonprofit group called its plan “workable and feasible” and said it would “meet all of the D.C. PSC’s concerns with the proposed merger.”
DCPP said a transaction would occur as soon as possible and would provide “appropriate assurances sufficient to satisfy the D.C. PSC, intervenors and elected officials that the acquisition is in the public interest.”
The group said it had shared its proposal with Exelon and the D.C. government, but had “not yet engaged the cooperation of the merging parties.”
Exelon referred a request for comment to Pepco. A PHI spokeswoman said Thursday that a District-only system would be “expensive and inefficient.”
Myra Oppel, regional communications vice president at PHI, said the group’s proposal “raises many complex legal, financial, regulatory, operational, commercial and customer considerations that the group has not begun to address.”
“PHI and Exelon, along with the District government, the Office of the People’s Counsel, and other parties have filed a proposal with the Public Service Commission of the District of Columbia that is reasonable and achievable and delivers significant benefits to D.C. residents and the community. We believe that it is in the best interests of our customers.”
DCPP plans to outline the details at 10 a.m. at the National Press Club in D.C. A statement announcing the press conference claimed the plan would produce a net present value of $1 billion in benefits over 20 years.
Friday marks the deadline for public comment to be filed with the PSC in response to a request by Exelon and Mayor Muriel Bowser’s administration to reopen the record for the proposed $6.8 billion acquisition of Pepco. As of Thursday afternoon, no comments had been posted. Anya Schoolman, head of solar advocacy group DC SUN, which did not sign on to a new proposed settlement brokered by Bowser, told The Washington Post that her group would be filing comments in opposition on Friday.
Bowser, who hailed the rejection, entered into negotiations with the companies and several interveners who also had opposed the merger, most notably Attorney General Karl Racine and People’s Counsel Sandra Mattavous-Frye. They released a settlement Oct. 6 designed to assuage the PSC’s concern and convince it to reconsider. (See Mayor’s Settlement Puts DC PSC on the Spot in Exelon-Pepco Deal.)
Among the concessions, Exelon would provide a Customer Investment Fund worth $72.8 million, including $25.6 million to offset the effect of any rate increases over the next four years; one-time funding of various renewable and sustainable energy efforts; and a commitment to buy 100 MW of wind power within PJM. (See Details of Exelon-DC Settlement.)
Exelon, based in Chicago, also would co-headquarter its offices in the district.
An initially approved D.C. Council plan to study the feasibility of turning Potomac Electric Power Co. into a city-owned utility was killed in June after Pepco lobbyists communicated with seven councilmembers or their aides. That majority amended the agreement to reallocate the $250,000 to study “emerging alternatives” for energy and energy efficiency. (See Pepco’s Influence Runs Deep.)
WASHINGTON — The Supreme Court’s liberal wing indicated support Wednesday for FERC’s jurisdiction over demand response, but the commission faced harsh questions from conservatives Antonin Scalia and Chief Justice John Roberts and swing vote Anthony Kennedy.
Kennedy and Scalia challenged Solicitor General Donald Verrilli’s arguments on behalf of FERC, with Kennedy referring to them as “circular” logic and Scalia expressing opposition to the commission’s “fiddling around” with retail rates.
Justices Stephen Breyer, Sonia Sotomayor and Elena Kagan were equally critical of attorney Paul Clement, representing the Electric Power Supply Association. Sotomayor interrupted Clement early in his argument, demanding “where is that written down?” after the attorney categorized FERC’s intent as trying to reduce retail demand.
EPSA filed the lawsuit challenging FERC Order 745, which set rules for compensating DR in RTO energy markets. In May 2014, the D.C. Circuit Court of Appeals vacated the order, saying DR is a retail product and thus subject to state, not federal, jurisdiction.
Conservative Justice Clarence Thomas and liberal Ruth Bader Ginsburg were silent during the one-hour argument, which drew numerous RTO stakeholders as observers.
If the justices side with their normal allies, the court could end up deadlocked 4-4, meaning the D.C. Circuit ruling would stand. Justice Samuel Alito has recused himself in the case.
“If the court does cast a four-to-four vote at its private conference on Friday, and decides that [is] the most that it can do, that result would be announced promptly, perhaps as early as next Monday,” SCOTUS Blog predicted.
Breyer’s Wife Sells Stock
Bloomberg reported that Alito recused himself because he owns stock in Johnson Controls, which owns EnergyConnect, a DR provider that has filed a brief with the court. Bloomberg also reported that Breyer’s wife owned stock in the same company, which it said Breyer was unaware of when he heard the case. She sold her 750 shares for about $33,000 the following day after an inquiry by a Bloomberg reporter.
FERC sought Supreme Court review because of the growing importance of DR. While the D.C. Circuit ruling explicitly addressed only DR participation in wholesale energy markets, FERC said the ruling also threatened its participation in wholesale capacity markets.
That could create upheaval in markets such as PJM, where capacity auctions represent about 95% of total DR revenue. After some uncertainty, PJM decided to include DR in the 2018/19 Base Residual Auction in August.
The Supreme Court agreed in May to reconsider the D.C. Circuit ruling on two questions:
Whether FERC reasonably concluded that it has authority under the Federal Power Act, 16 U. S. C. 791a et seq., to regulate the rules used by operators of wholesale electricity markets to pay for reductions in electricity consumption and to recoup those payments through adjustments to wholesale rates.
Whether the Court of Appeals erred in holding that Order 745 — which required RTOs and ISOs to pay DR the same LMPs as generation in energy markets — is “arbitrary and capricious.”
Most of the arguments focused on jurisdiction, however.
Direct Effect
Verrilli led off the arguments and was interrupted almost immediately by Kennedy, who — after noting the interplay between retail and wholesale markets — asked what “marks the end of federal power and the beginning of local power?”
Verrilli did not answer directly, but contrasted the current dispute with the Mississippi Power case, in which FERC ruled that the utility could recover at wholesale its investment in a nuclear plant. The commission was overruled, with the court ruling that FERC had infringed on the authority of the state regulator to deny cost recovery in retail rates as imprudent. “That was a very direct effect on the exercise of state regulatory jurisdiction, which you do not have here,” Verrilli said.
“I find that a pretty fuzzy line, ‘very direct effect,'” Scalia jumped in. He continued, “Yes, FERC has the power to regulate wholesale rates. But … the argument is, not through the fiddling around with retail rates, which is what is asserted is happening here.”
$8 Hamburgers
After several exchanges between the two, Roberts took his turn with Verrilli, comparing FERC to someone “standing outside McDonald’s” offering diners $5 not to go in and spend $3 on a hamburger.
Because of FERC’s action, Roberts said, “the price of a hamburger is actually … $8, because if they give up the $5, they’ve still got to pay the $3. And your answer is, there’s no impact on what the states can do, because they can still say, no, the price of the hamburger should be $2, or it should be $4. The point is that … FERC is directly affecting the retail price.”
Kennedy returned with another question: “Is it fair to say that FERC is luring retail customers into the wholesale market? And if that … were true, would that not be a serious problem for the government?”
“It’s wrong as a matter of history. It’s wrong as a matter of law,” Verrilli responded. “Wholesale demand response was not FERC’s idea… This is a practice that grew up organically out of the private actions of market participants once the wholesale markets were deregulated. It’s exactly the kind of innovative private market conduct that you would hope that deregulation would bring about. And the private actors, the wholesale market operators, brought that idea to FERC as early as 1999.”
Verrilli went on, saying that the Federal Power Act gives FERC authority “over practices that affect … wholesale rates. And there’s just no doubt … that all of the practices FERC is regulating occur in the wholesale auction.”
Limiting Principle
Roberts acknowledged that was true, but he pressed Verrilli to identify the “limiting principle” on FERC’s authority, saying that without one, “FERC can do whatever it wants.”
Verrilli responded that “the effects have to be direct.”
Repeating hypothetical examples cited by the D.C. Circuit, he said, “regulating steel, regulating inputs into electric generation — we don’t think FERC’s authority goes anywhere near that far.”
Verrilli concluded by citing the Chevron doctrine, which says FERC is entitled to deference in its interpretation of the Federal Power Act. “There is no statutory text that unambiguously denies FERC this authority that it’s exercising here over this wholesale conduct.”
Reliability Benefit
Representing DR provider EnerNOC, attorney Carter G. Phillips backed Verrilli, saying that FERC did not create DR but rather responded to a market created by his clients and others who were trying to create a demand-side component to the wholesale market and a way to avoid brownouts. “And so tariffs were filed in order to provide a basis for putting in the demand side. And the reason why this is a direct effect on the … wholesale rates is because it’s an absolute one-to-one relationship. If I put in a unit of — or reduce a unit of — demand, I don’t need as much supply, and that affects the price directly. And that’s the direct relationship that derives from the economic principles.”
Phillips also sparred with Kennedy and Scalia. “FERC’s argument is essentially circular,” Kennedy said. “It says, well, the market forces will work this out — but we define the market.”
Scalia asked Phillips why “all the companies” aren’t in agreement with FERC and EnerNOC. DR provider EnergyConnect, the Coalition of MISO Transmission Customers and the PJM Industrial Customer Coalition joined EnerNOC’s brief.
“Most of the private companies on the other side generate electricity” and see DR as competition, Phillips responded.
Clement, the final attorney to speak, made a point to note that he represented not only the generators that make up EPSA but also load-serving entities that could provide DR under state-sanctioned retail programs.
Signing on to EPSA’s brief were the National Rural Electric Cooperative Association, the American Public Power Association, PPL and Old Dominion Electric Cooperative.
FERC Reducing Retail Demand?
“What FERC was trying to do here was to reduce retail demand by providing payments to retail customers on an otherwise wholesale market in an effort to change the effective price for retail sales,” Clement said. “Now, that sure sounds like something that belongs to the states.”
“Where is that … written anywhere that that was their goal?” interrupted Sotomayor. “What I’ve heard them say is, we’re trying to lower the price of wholesale [power] to a more just amount. That’s what’s in anything I’ve seen written. You’ve recharacterized it.”
Clement persisted: “These retail customers don’t belong on the wholesale market. Whether you think they were lured in or you think they walked in the door, it doesn’t matter. They are in a market where they don’t belong.”
“What’s the horror here of concurrent jurisdiction … if, in fact, it’s lowering prices?” Sotomayor asked.
“You actually have the … federal regulators and the state regulators bidding against each other for the same customers to reduce their same retail demand,” Clement responded.
LMP Too High?
That led Clement to move from the jurisdictional dispute to the second question, saying that while no states raised a jurisdictional objection before FERC itself, Ohio, Illinois and all of the MISO states said FERC should not require compensation at LMP “because that’s too high.”
“And by setting it so high, what you are going to do is you’re going to crowd out our own efforts at dealing with demand response,” Clement said for the states. “Because we love demand response. We want demand response. But we don’t want to pay twice as much as the market really should pay for demand response. And if you’re out there offering our same retail customers the ability to get demand response paid at huge LMP levels, then [states are] going to be crowded out.”
Breyer said Clement’s logic would prevent FERC from allowing large consumers to buy electricity at wholesale, “because that would take the retail customers away from the jurisdiction of the state.”
He continued: “I have found no case … that would say that they cannot do this for the reason you suggest.”
Kagan said Clement’s argument seemed to be that FERC “can’t do anything with respect to demand response.”
Clement disagreed, saying FERC was allowed to have a role in “true wholesale demand response,” which he said meant working through load-serving entities.
He said FERC’s premise “that the sky will fall if you don’t have this precise type of retail customer on wholesale market demand response” was belied by the experience of Southern Co., which does not participate in an RTO or an ISO, yet it has “a greater level of demand response than other parts of the country” subject to Order 745.
Congressional Intent
Kagan said Clement’s argument was at odds with the 2005 Energy Policy Act, “which made it so clear that Congress liked demand response — that it wanted FERC to lower barriers to demand response — to then say, well, FERC has no jurisdiction to do exactly what the policy that Congress articulated is.”
Clement cited Commissioner Philip Moeller’s dissent on Order 745 and comments by the Federal Trade Commission, which he said told FERC “you are picking the wrong compensation level.”
Having saved five of his 20 minutes for closing remarks, Verrilli got the last word, saying Clements’ view of “hermetically sealed-off retail and wholesale spheres” was unrealistic.
“In the real world today, large customers can buy directly. They can do it through contract, and they can also go into the wholesale market auctions and buy, if their states permit it… And this is really no different because demand response entities that want to come in and participate can only do so if their state law allows them to do so. So it’s no different than what’s been going on in the real world for quite a long time.”
Verrilli also responded to Clements’ arguments about the role of load-serving entities in providing DR. FERC “found that load-serving entities don’t have sufficient incentives to engage in demand response. And it’s obvious why they don’t, because they cannibalize their own profits. The higher cost they have, the higher their rate-of-return profits are going to be generated. They will do it under commands from state regulatory agencies to do it, but they’ll do it grudgingly. And what FERC said is you want people to come in who have a real profit motive to do it and that’ll incent the LSEs to get in there and try to get a piece of the action rather than letting it go to somebody else.”
Fears Unwarranted
Verrilli said fears that state and federal DR can’t coexist were unwarranted, saying “we have 24 states in which this is going on. And if this were a problem, you’d expect to see in this administrative proceeding some evidence that it was a problem, and there is zero evidence. You look at all these briefs; there isn’t a citation to anything in the administrative record that suggests that the federal and state programs can’t work in harmony.”
“You’ve got a practice … that has saved billions of dollars in wholesale costs and will save billions of dollars, and it’s an effective tool against blackouts and brownouts, and that nobody has shown in the real world does any harm.”
INDIANAPOLIS — MISO and SPP have filed a settlement agreement with FERC allowing MISO to use the SPP transmission system to transfer power freely between its North and South regions.
The settlement (ER14-1174, et al.) eliminates the $9.57/MWh hurdle rate established in 2014 after SPP complained that MISO’s use of the SPP grid exceeded a 1,000-MW transfer limit in their joint operating agreement.
The agreement also supplants MISO and SPP’s Operations Reliability Coordination Agreement (ORCA), set in place in early 2014 to address capacity sharing across the region.
Six transmission owners outside of MISO and SPP — Southern Co., the Tennessee Valley Authority, Associated Electric Cooperative, Louisville Gas and Electric, Kentucky Utilities and PowerSouth Energy Cooperative — signed off with the two RTOs on the deal.
Moving forward, MISO’s compensation of SPP and the independent transmission owners will be determined through application of a capacity factor for flows exceeding the existing 1,000-MW contract path. New directional transfer limits were included in the deal: Power flowing from north to south is limited to 3,000 MW, while power flowing south to north is capped at 2,500 MW. Otherwise, the capacity usage provision between MISO and SPP under their joint operating agreement stands intact.
Under the settlement, MISO will pay SPP and the independent transmission owners $16 million — $8 million per year — to settle all claims of compensation from Jan. 29, 2014, to Jan. 31, 2016. Sixty percent of the funds will be paid to SPP, while the remaining 40% will be disbursed to the independent transmission owners. SPP said it will distribute the funds it collects to its members. The RTO will have to file the proposed distribution method with FERC because the funds are not being collected under its Tariff.
The settlement creates an operating committee to manage any disputes that may arise. The committee will be composed of two members each from MISO, SPP and the independent TOs.
The agreement will last seven years from the date of the initial complaint in January 2014. In early 2021, the parties will have the opportunity to give notice to terminate or revisit settlement provisions.
Jennifer Curran, MISO’s vice president of system planning and seams coordination, said that the RTO will “continue to evaluate if there are … appropriate alternatives to the agreement,” including expansion of its own grid to reduce the use of its neighbors’ systems.
“That work will be ongoing to see if there could or would be appropriate transmission solutions,” she said during a press conference.
In recognition of the limits of the 1,000-MW contract path, FERC on Thursday granted MISO a year-long extension on a waiver of Tariff provisions and North American Energy Standards Board rules on the processing of long-term firm transmission service requests (TSRs) between MISO South and MISO Midwest or PJM (ER14-2022-001). “A number of long-term TSRs remain in the queue that seek capacity from the MISO South region to non-contiguous geographic regions outside of MISO. MISO expects the number of these already-sold long-term TSRs to exceed the 1,000-MW threshold until 2019. MISO intends to honor fully these transmission commitments, but they make it very difficult for MISO to process adequately any additional long-term TSRs,” MISO wrote in the waiver request.
The waiver relaxes processing, assessment and timing regulations on long-term TSRs. MISO said that without the waiver, it would be forced to deny the requests.
The waiver, which expired April 1, 2015, now lasts until April 1, 2016 or until the resolution of the dispute between MISO and SPP.
Curran said MISO will file with FERC to remove the hurdle rate.
“We’re excited to have made this filing today. We think it’s a good compromise. Most importantly, it provides us clarity,” Curran said. “It took a lot of work across all parties.”
David Kelley, SPP’s director of interregional relations, said SPP’s main objective was to protect the interests of its members. He called the settlement a “mutually beneficial agreement.”
“Both sides weighed the risks of not settling and realized both parties were better off not litigating and reaching consensus instead. We had some uncertainty, too, for our members, with continued litigation,” Kelley said.
FERC set the dispute for hearings and settlement negotiations in March 2014. The parties met for seven settlement conferences at the commission’s offices in Washington.
MISO said the settlement will allow cost-effective energy delivery through continued shared use of the transmission system.
“We are pleased to have reached a resolution that provides electricity savings to consumers across the MISO region and brings clarity to our members and all stakeholders,” MISO CEO John Bear said in a statement. “With the issue of capacity sharing behind us, we can now collectively return our full attention to the significant challenges facing the industry.”
SPP CEO Nick Brown also praised the arrangement.
“As the SPP region grows and we continue to modernize the electric grid, cooperation with our neighboring regions has never been more important,” Brown said in a statement. “I am pleased we were able to reach this agreement with MISO to ensure that our member companies and their customers are compensated for the use of the SPP transmission system.”
