The Public Utility Commission of Texas agreed Wednesday to wait until no later than June 10 before determining whether to grant a rehearing on its decision to allow Hunt Consolidated’s acquisition of Oncor.
The commission granted the extension partly to allow time for review of the flood of filings that followed the May 1 announcement by Oncor’s debt-laden owner, Energy Future Holdings, that it had filed a new Chapter 11 reorganization plan. (See EFH Files New Chapter 11 Plan; Oncor-Hunt Deal in Doubt.)
The PUC will resume the discussion of whether to grant the Hunt group’s rehearing request at its May 19 open meeting. The intent is to make a decision then, rather than extending the timeline until its next meeting on June 9.
“I think we can make a decision on the 19th whether we can grant a rehearing,” Commissioner Ken Anderson said. “At the very least, we should discuss our position on the issues raised by the parties. I guess we’re probably decided on 80% of those issues now.”
However, the commission’s requirements that the REIT’s tax savings be set aside for customers led to EFH’s investors pulling their support for the deal. That, in turn, led to EFH killing its original bankruptcy exit plan last weekend and filing a new one.
Anderson is widely seen as the swing vote in the three-person commission’s eventual decision. Chair Donna Nelson has often sided with the Hunt group’s position, while Commissioner Brandy Marty Marquez has supported the restrictions placed on the deal.
“Is there even a transaction for us to still approve?” Anderson asked.
Two opposing groups, the Steering Committee of Cities Served by Oncor (comprising about 150 Texas cities) and the Texas Office of Public Utility Counsel, argued the commission should dismiss the rehearing request.
“The [bankruptcy exit] plan is dead, according to the bankruptcy court,” Geoffrey Gay, lead attorney for the cities coalition, told the commission. “If I was in your position, my gut reaction is this case no longer exists. You’re being asked to proceed on a hypothetical basis.”
“We believe the transaction is null and void,” said Laurie Barker, deputy public counsel for the OPUC. “While the Hunts do have an opportunity to negotiate and possibly become the next plan, there are other potential investors and plans out there as well. If we allow one entity to come before you with their preferred plan, you would have to allow all.”
Richard Nolan, an attorney for the Hunt group, said turning Oncor and its assets into a REIT is still a viable option for the bankruptcy process. He said the door has been left open for creditors and the court to approve the structure under the reorganization plan, “and we intend to pursue that.”
“We’ve receive a lot of interest from investors,” Nolan said. “To the extent we can make this work … that offers the opportunity to avoid going through another six months of proceedings. We realize the plan that was selected will have to conform to whatever the final order is.
“We think if that’s done, that would be the quickest way for the debtors to exit the bankruptcy proceeding without going through another six months and delay the process. That also gives the commission an opportunity to shape, to some degree, a plan that would be workable and approved by the [bankruptcy] court.”
Commission staff also requested an extension, saying “new developments in the EFH bankruptcy proceeding raise new issues that may affect this … proceeding.” Staff said they needed sufficient time to “identify and address any new issues.”
“I think you maintain maximum flexibility with your options if you extend time for the rehearing,” PUC attorney Sam Chang said.
EFH, saddled with $42 billion in debt following its leveraged buyout of TXU Corp. in 2007, filed its first bankruptcy exit plan in Delaware two years ago. In December, a U.S. bankruptcy judge approved the company’s plan to split into separate companies — Oncor, Luminant and TXU Energy — wiping out the buyout sponsors’ equity. The Luminant and TXU Energy businesses would go to senior lenders owed about $24 billion.
Southern Co. subsidiary Mississippi Power said its repeatedly delayed Kemper Project, now scheduled to become operational on Sept. 30, continues to mount up expenses.
In the latest tally, Mississippi Power spent another $61 million, pushing the total up to $6.7 billion. The low-carbon-emitting plant was initially estimated to cost $2.9 billion. The company is eating $2.7 billion of the cost overruns, but customers may eventually be on the hook for as much as $4.3 billion.
In an attempt to restore threatened populations of American shad and herring, Exelon Generation said it will make improvements to four of its hydroelectric plants to allow the fish to more easily pass through for breeding.
Exelon Power President Ron DeGregorio called the agreement “a significant step toward the Fish and Wildlife Service’s goals to restore American shad and river herring populations on the Susquehanna River.” While Exelon improves the fish-lift system at the dam, the “trap and transport” program will allow fish from both species to bypass the barriers on their upstream migration.
The U.S. Fish and Wildlife Service has set a goal of restoring 2 million American shad and 5 million herring above four Susquehanna River dams.
Cisco Systems is buying renewable energy from Duke Energy for its Research Triangle campus near Raleigh through Duke’s Green Source Rider program.
Cisco is the second major technology company, after Google, to join the program. Cisco will purchase power and renewable energy credits for two 5-MW solar projects near Charlotte.
Duke spokesman Randy Wheeless said a third client has signed up for the program, but the company isn’t ready to release information on that customer.
Oil Company Scraps Plans For Using 98-Year-Old Pipeline
A Houston-based pipeline company said it will scrap plans to repurpose 98-year-old pipelines running under the St. Clair River in Michigan after community protests and officials expressed concerns about the reliability of the conduits.
Plains LPG said it has withdrawn its request to use the pipelines running beneath the St. Clair River between Marysville, Mich., and Sarnia, Ontario. It had applied to use the pipelines to transport crude oil. The pipelines were built in 1918 and upgraded in the 1970s. Few comments were lodged during the public comment session, but a public outcry resulted after the Detroit Free Press reported on the plans.
U.S. Sen. Gary Peters and Reps. Candice Miller and Debbie Dingell got involved and asked U.S. Secretary of State John Kerry to intervene because the pipeline crosses an international boundary.
The Securities and Exchange Commission won’t block a Dominion Resources shareholder resolution calling for an analysis of the financial risks investors face if the company is unable to complete a new nuclear reactor.
The resolution will be presented at the May 11 annual meeting. It calls for Dominion to prepare an analysis by Nov. 30 reporting on the potential financial impacts if the Virginia State Corporation Commission denies a permit and the recovery of costs for the North Anna 3 project.
The North Anna 3 reactor has already cost more than $600 million. The SCC estimates the total project cost at $19.3 billion.
Mississippi Power Breaks Ground on Second of Solar Project Triad
Mississippi Power and Silicon Ranch broke ground on a 50-MW solar farm in Hattiesburg, Miss., last week. The $100 million, 450-acre solar farm will supply enough electricity for about 6,500 homes.
The 600,000-solar-panel project is the second of three planned Mississippi Power solar farms. The company and Origis Energy will begin work this month on a 52-MW utility-scale photovoltaic project in Sumrall, Miss. Construction has been underway since March on the company’s 3 to 4 MW project on the Naval Construction Battalion Center in Gulfport, Miss., in conjunction with the U.S. Navy and Hannah Solar.
The City of Austin released its short list of finalists for Austin Energy’s top job and City Manager Marc Ott said he expects to appoint a nominee by mid-May.
The four candidates for the general manager’s position are Deborah Kimberly, an executive at Austin Energy; Jacqueline Sargent, general manager of the Platte River Power Authority in Fort Collins, Colo., and a former Austin Energy executive; Terrance Naulty, who oversees the Owensboro Municipal Utilities in Owensboro, Ky.; and James West, assistant general manager of the Snohomish County Public Utility District in Everett, Wash.
Austin Energy, which has nearly 450,000 customers, has come under intense scrutiny from state officials over its management and rates, and the utility is preparing to ask for a rate hike this summer. Its last general manager, Larry Weis, departed in January to run Seattle’s electric utility.
PNM Energy Efficiency Programs Lead to Big Electric Savings
Public Service Company of New Mexico’s energy efficiency programs have saved enough electricity since 2007 to power about 274,000 homes a year, according to the company’s latest annual report. The company has also paid out $55 million in rebates to customers, helping offset the cost of installing energy-efficient appliances and systems.
The report, released last week, details a variety of programs that help customers lower consumption, such as rebates for replacing inefficient refrigerators, cooling equipment and appliances with more modern models. The company also partially reimburses efficiency upgrades for businesses and new energy-efficient construction.
PNM and New Mexico’s other public utilities began adopting measures nearly 10 years ago to comply with the state’s Efficient Use of Energy Act, which requires the companies to reduce 2005 retail sales by 5% by 2014 and 10% by 2020.
Pedernales Co-Op to Build Solar Sites in Texas Hill Country
Texas’ Pedernales Electric Cooperative will begin developing several solar generation sites across its service territory in the Hill Country west of Austin. The projects are expected to produce 15 MW.
PEC is working with Renewable Energy Systems and its subsidiary, RES Distributed, to develop and construct the sites. RES will also operate the facilities, the first of which is expected to go online later this year.
CPS Energy has begun construction on a community solar farm, but after going almost nine months without signing up paying customers, the San Antonio-owned utility’s “roofless solar” program was forced to slash its prices by almost one-third. The utility discounted its initial price for a panel from $406 to $289.
In June 2015, CPS entered into a deal with Colorado-based Clean Energy Collective to develop a roofless solar program that would supply 1.2 MW of electricity to San Antonio’s grid. CEC agreed to build the farm and sell the rights to individual solar panels to CPS residential customers for a flat fee. Those who buy the panels would receive a monthly credit on their electric bill based on their panel’s solar energy output and their consumption.
Hundreds of people signed up for information about the program. But with an initial price point of $406 to save an average of $1.90/month, CPS said the program had failed to attract many customers. Even at the discounted price, customers would need more than 12 years to recover their investment.
A Duke Energy report on the achievements of its sustainability program proposes to increase its renewable energy goal by 33%, with plans to own or buy at least 8 GW of mostly wind and solar power by 2020.
“Renewable energy will continue to be a growing part of our generation mix in the future,” said Cari Boyce, vice president for policy, sustainability and stakeholder strategy.
By the end of last year, the report said, Duke owned or purchased 4.4 GW of renewable energy in its commercial and utility businesses.
American wind generators added 520 MW of capacity in the first quarter of the year, the best quarter since 2012, according to the American Wind Energy Association.
According to AWEA’s 2016 Market Report, construction has started on another 2,000 MW of wind generation in the country, bringing the total of wind capacity under construction to 10,100 MW.
AWEA said there are now more than 48,800 wind turbines turning in 40 states, Puerto Rico and Guam. Another 5,100 MW of wind capacity are in advanced stages of development, or nearing completion, the association said.
Energy analytics company Opower said Monday that it has accepted Oracle’s $532 million purchase offer, a deal that values Opower’s shares at a 30% premium to Friday’s close.
More than 100 utilities use Opower’s data services, which track household energy-use trends, to help meet state energy efficiency standards.
Last year, Opower reported an operating loss of almost $45 million on $145.7 million in revenue. Founded in 2007, the company went public in 2014.
FERC announced Friday its staff will prepare an environmental impact statement for the Access Northeast pipeline project that would move natural gas from New Jersey to Massachusetts (PF16-1).
The commission said the EIS will determine the potential impacts of Algonquin Gas Transmission’s project to determine if it is in the public interest.
The 925-dekatherm/day project includes pipelines and storage facilities along the route of an existing pipeline. Its developers say the project will be able to serve 5,000 MW of gas-fired power generation in New England.
The commission said comments should be filed by May 30. A series of public scoping meetings will be held at various locations in New York, Connecticut and Massachusetts from May 16-19.
The project would replace 45 miles of existing 26-inch-wide pipeline with 42-inch pipe; expand six existing compressor stations; and build new pipeline loops and laterals or expand the capacity of existing ones. The project also includes an 84.6 million-gallon LNG storage facility in Massachusetts.
SANTA FE, N.M. — The SPP Board of Directors’ approval last week of the RTO’s first reduction in its planning reserve margin since 1998 almost left members wanting more.
The board accepted the Capacity Margin Task Force’s recommendation to reduce the margin from 13.6% to 12% April 26 following a unanimous vote by members. SPP said the smaller margin, amounting to a 900-MW capacity reduction, would save its load-serving members about $86 million a year in capacity costs, or about $1.35 billion over 40 years.
Lanny Nickell, SPP’s vice president of engineering, said the reduction was made possible by the RTO’s expanding footprint, its ability to dispatch more than 700 resources as a single balancing authority and $6 billion in transmission expansion during the last decade. He said another $5 billion of approved projects have yet to be built.
“Looking ahead, we need a longer-term vision,” said David Hudson, president of Xcel Energy’s Southwestern Public Service subsidiary. “If all this transmission we’re building creates benefits for our consumers, we have to see if we can achieve further savings.”
Board Chair Jim Eckelberger agreed, saying, “This is one more step in getting savings out of our transmission investment.”
Nickell said stakeholders have told him the task force’s work included “the most robust study” they have seen. Staff conducted more than 300,000 simulations and three different analyses of three test years to determine loss-of-load expectations (LOLE) at various reserve-margin levels. The so-called “limbo study” indicated SPP could go as low as 8.7% before exceeding its LOLE criteria. (See SPP Capacity Margin Task Force Shares ‘How Low’ Reserve Margin Can Go.)
The task force’s recommendation included approving a package of policies defining a load-responsible entity and its obligations, planning reserve assurance and deliverability. The package had previously been approved by the Regional State Committee, the Markets and Operations Policy Committee, the Strategic Planning Committee and the Cost Allocation Working Group.
“From my perspective, this proposal is a great platform to move forward and make improvements,” Dogwood Energy’s Rob Janssen said.
“We learned a lot from this,” Nickell said. “We debated a lot, but at the end of the day, there was a high degree of consensus. Our entire region will now benefit from improved reliability and capacity savings.”
Board Approves 2016 ITPNT
Transmission buildout will continue with the board’s approval of the 2016 Integrated Transmission Planning Near-Term (ITPNT) assessment, which recommended 86 upgrades representing $362.6 million in new engineering and construction costs. The approval is pending further evaluation of seven projects, five projects totaling $74.7 million resulting from a scenario assuming summer wind generation of almost 10 GW that some stakeholders said was unrealistic.
(A sixth project in the high-wind summer scenario, a full rebuild of a 115-kV line in a West Texas load pocket that came in at $17.7 million, was excluded from the re-evaluations.)
“Pulling these off to re-evaluate is the prudent thing to do,” said Jason Atwood, the Northeast Texas Electric Cooperative’s vice president of engineering and operations. “I just think [the] scenario pushes these projects up to the near term.”
“Those projects may be fine, but I’d like to take a second look at those projects before we issue [notices-to-construct],” Eckelberger said. “I’d like to make sure we’re not being driven by the way the model is set up. Rather than spend 92 million bucks with some questions, I’d rather get some answers.”
The board also approved requests by Basin Electric Power Cooperative and American Electric Power to conduct “accelerated reviews” of their proposed projects in North Dakota and northwest Louisiana, respectively. Staff said it could complete the further evaluations of the seven projects by the July board meeting.
The annual near-term reliability assessment included the re-evaluation of 15 projects at the transmission owners’ request. Seven of the NTCs were modified and eight withdrawn, resulting in $133.4 million in costs being pulled out of the study.
The planned development includes a $20.5 million project to address needs in the Tulsa, Okla., area; a $30.5 million project to address needs near Woodward, Okla. through the construction of a new substation and a 138-kV line; and a $145.7 million project to construct new substations and 115-kV lines to address “substantial load increases” in North Dakota’s Bakken shale formation.
Nickell said that by using a winter-peak case to reflect the Integrated System’s addition, the staff models solved many constraints before considering the effects of contingencies. He said most zones experienced a load reduction, but certain pockets — North Dakota, western Kansas and the Golden Spread Electric Cooperative and SPS’ Panhandle area — saw increases. The bulk of the ITPNT’s new investment ($261.5 million) is targeted for New Mexico, North Dakota, Oklahoma and Texas.
Staff said it would continue to consolidate planning efforts with “real” operations when determining whether projects can solve operational issues. “I would hate to ignore assumptions that go into these projects,” Nickell said. “If we can find a project that solves some of these issues, I would hate to not pursue it.”
MOPC Chair Noman Williams, COO for South Central MCN, recommended the Transmission Working Group take a second look at the high-wind summer scenario and bring it back to the board. His motion passed.
At the MOPC’s recommendation, the board also endorsed the 2017 ITPNT’s score, which will evaluate as potential violations NERC TPL-001-4 planning events that do not allow for nonconsequential load loss or curtailment of firm transmission service. (See “MOPC Approves TWG, ESWG Recommendations,” ITP Work Continues as Transmission Planning Improvements Loom for SPP.)
Eckelberger asked members to opine on how TPL events should be handled in future planning studies. The MOPC removed consideration of TPL events from the 2017 ITP 10-Year assessment during its meeting two weeks earlier.
“Essentially, this takes future requirements NERC has placed on us … out of the ITP10,” he said. “The real question: Is that something we can wait on, or do we need to incorporate it now?”
NextEra Energy Transmission’s Brian Gedrich, chair of the Transmission Planning Improvement Task Force (TPITF), said his team has included the TPL standards in its work.
“It should be incorporated in the TPITF work, and let them sort it out,” said Phil Crissup, vice president of utility technical support for Oklahoma Gas & Electric.
The task force is scheduled to present its final set of recommendations to the board, MOPC and SPC for their approval in July.
Board Approves Z2 Level Payment Plan
The board approved the Z2 Payment Plan Task Force’s recommendation to use a level-payment plan resolving years of incorrect credits for transmission upgrades, despite continued stakeholder angst over the size of payments due.
Under the level-payment plan, each entity with a net payable will be given the option to pay the entire amount at once or in equal installments every three months, beginning in November, with the final installment due in August 2017. FERC’s interest rate for refunds will apply to the outstanding balances. (See “MOPC Accepts Z2 Task Force’s Level-Payment Plan,” SPP Markets and Operations Policy Committee Briefs.)
“Our general philosophy is we’re putting the cart before the horse on this issue,” Hudson said. “A lot of this is recovered through a rate case; that’s why we think a longer payback period is more appropriate. We don’t know the potential liability for our customers … it’s hard to agree to a payment plan when [you] don’t know what the payment is.”
Asked whether it would be wise to wait until July to make final decisions, OG&E’s David Kays, chair of the task force, said the financial information will not be available for stakeholder review until July anyway, and that postponing a vote until July would slide FERC responses into October or later.
Kays said software systems would be production-ready by June 1 and historical data will be available for MOPC review in October. SPP has promised stakeholders will be able to review their data and the software calculations at SPP headquarters in late May.
“Two pieces you won’t know” in May, SPP COO Carl Monroe said. “How many waivers get approved to go in … the amount of credits due on point-to-point reservations to pay for usage and, as the TO, how much we have to claw back from revenue paid previously to pay for credits.”
Monroe said much of that information won’t be available until September. “We have to get through that puzzle, before we can determine the rest of it.”
Board Pays Tribute to Ex-RE Chair Meyer
SPP CEO Nick Brown and Eckelberger led the board in paying tribute to John Meyer, the first chairman of the Regional Entity’s Board of Trustees. Meyer resigned his position earlier this year because of a conflict with the bylaws of Western Interconnection reliability coordinator Peak Reliability, where he is vice chair. (See SPP Briefs: New Trustee Chairman, Wind Record.)
Meyer remembered his early years with the RE, which began in 2007 after his retirement from Reliant Resources, with just four employees and facing a FERC audit.
“One of the strengths I see with SPP is its willingness to solve problems together,” Meyer said. “I’m really sad to be leaving, but I’ll be back to visit on occasion.”
The RE doesn’t expect to fill Meyer’s position until July, at the earliest.
FERC Chairman Norman Bay was a special guest at the board meeting, attending the morning session for about 90 minutes. Given his tight schedule, the board rearranged its agenda to ensure Bay could listen to the discussion surrounding SPP’s first competitively bid transmission project under the commission’s Order 1000.
“I look forward to hearing your experiences with Order 1000,” Bay said.
Bay took note of SPP’s recent achievements, including the Integrated Marketplace’s implementation and the addition of the Integrated System, and called them a “national leader” in integrating renewable energy.
“You’re helping make the case markets drive reliability and efficiency, driving benefits for consumers,” he said. “Fifty percent wind penetration … that’s pretty amazing. Just a few years ago, people were wondering whether you could get 20%, and now you’re almost at 50%.”
Bay, a former New Mexico resident, also complimented SPP on holding its board meeting in Santa Fe. “Obviously, it shows they have good taste and judgment.”
RE Report Shows 40% Drop in Violations
New RE Trustees Chairman Dave Christiano noted that SPP’s registered entities saw a nearly 40% drop in violations of NERC standards during a rolling 12-month period that ended March 31. . The RE recorded 48 violations in the current period, compared to 78 in the previous 12 months.
The systems security management, electronic security parameters and personnel and training categories showed some of the greatest improvements.
“The registered entities have this figured out,” Christiano said. “We’ll take some credit, but most of the credit goes to them.”
“This wasn’t a bunch of 15-, 16-year-old hackers in their basements,” Christiano said. “This was a very well planned-out attack over a number of months. It’s pretty scary stuff.”
The RE has scheduled a CIP workshop in Little Rock, Ark., May 24-25.
The board approved its consent agenda following a unanimous members’ vote, but only after pulling the Project Cost Working Group’s recommendation to reset the baseline value for a 110-mile, 345-kV transmission line in Nebraska and Missouri. It was valued at one time at more than $403 million, but received MOPC approval to reset its baseline value to $336.4 million.
“I thought we had a policy against resetting the baseline, unless it’s a different project,” Eckelberger said.
Staff was unable to recall any discussion of the project during the MOPC meeting, where it was part of the consent agenda. They promised to return the issue to the board with additional information.
The consent agenda included the addition of Basin Electric’s Mike Risan and the Missouri River Energy Services’ Ray Wahle to the SPC, reflecting the Integrated System’s addition. It also approved six revision requests from the Market and Operating Reliability working groups.
Annual Report Focuses on Relationships
As is the custom, SPP staff handed out the organization’s 2015 annual report before the board meeting began.
This year’s report focuses on SPP’s relationships, both internal and external. “We choose to highlight our relationships as a critical component of all we do and a binding agent, drawing together our staff, stakeholders and customers we serve to add value to our region,” the introduction says.
CAISO stakeholders last week expressed misgivings and confusion about a new issue paper exploring how the ISO can resolve certain generator and transmission contingencies currently handled by out-of-market operations.
Questions about the generator contingency and remedial action scheme modeling enhancements paper largely stemmed from uncertainty about the potential scope of the effort. Market participants also sought to understand how such an effort would differ from CAISO’s Contingency Modeling Enhancements (CME) initiative, which is nearing completion.
The diagram above shows transmission path AB being overloaded when the loss of generator G1 is replaced by low-cost contingency reserves procured from the network – what CAISO calls “transmission infeasible” procurement. The diagram assumes that there are no contingency reserve eligible resources at buses A, B or C.
“I’m curious as to why this stakeholder process is arising at this point in time,” Ellen Wolfe, a consultant representing the Western Power Trading Forum, said during an April 25 stakeholder conference call. “Especially in relation to CME and where that is.”
“This just seemed like a good time to get a jump-start on this,” responded Perry Servedio, CAISO senior market design and policy developer. “It was always the thought that these two [initiatives] would overlap.”
CAISO kicked off the CME initiative three years ago to address a Western Electricity Coordinating Council reliability provision requiring grid operators to return a critical transmission path — such as Path 15 linking Northern and Southern California — to its system operating limit within 30 minutes of a destabilizing event, such as the loss of a generator or transmission line.
The ISO’s present approach to managing those contingencies relies on out-of-market interventions coupled with day-ahead market measures that procure a “bucket” of responsive capacity resources based on a flat megawatt rating of the line in question, an approach that ISO staff considers to be inefficient.
The CME initiative would update CAISO market rules to instead procure those resources based on expected flows, with the process first run in the day-ahead market and then rerun in real-time. In addition, that process would be more closely integrated with the general procurement for locational ancillary services. That is expected to reduce the overall pool of reserves receiving compensation, reducing costs.
Last week’s issue paper looks to zero in on a different, if related, aspect to an emergency response: the system’s ability to gain access to contingency reserves while at the same time keeping all affected transmission paths below their emergency ratings. The ISO calls it the “transmission feasibility” of those reserves.
“We’d want to ensure that, given a generator loss, we don’t overload any lines and we can rely on the reserves,” Servedio said.
The newer initiative would also formulate a market-based response to transmission losses stemming from the triggering of remedial action schemes (RAS) — emergency plans designed to prevent one transmission outage from setting off a series of cascading outages.
Servedio noted that CAISO currently has more than 20 RAS modeled within its own system, a figure that does not include schemes elsewhere in the Western Interconnection. While the ISO currently factors RAS into its market operations through adjustments to its market software — including the use of nomograms to avoid exceeding transmission line limits — it thinks that approach comes up short.
“Even with all that modeling, you can end up with real-time exceptional dispatch [out-of-market intervention] because we don’t have a way to model the RAS in the day-ahead market,” he said.
That statement prompted one stakeholder to seek clarification about exactly what the current process entails.
“So you’re saying there is some sort of ad hoc change in modeling that takes place in both day-ahead and real-time?” asked Bonnie Blair, speaking for the “Six Cities” — municipal utilities serving Anaheim, Azusa, Banning, Colton, Pasadena and Riverside. “I’m not sure I follow, but I’ll think about it.”
Another stakeholder questioned whether the changes being contemplated by the ISO would be worth the investment.
“When you look at this [initiative] from an economic perspective, would you say this is more economic than what you do today?” asked Wei Zhou, senior project manager with Southern California Edison.
“We expect it to be the more economic solution — clearly,” said George Angelidis, principal with CAISO’s Power Systems Technology Development group.
“We currently don’t have in the market the ability to model generator contingencies,” Angelidis later added. “Without the capability to model the RAS, your market solution is a more conservative and costly solution.”
However, CAISO staff could provide no figures for how often contingency reserves have been inaccessible in past, in part because the current manual intervention process requires system operators to rely on only those resources that are accessible in real time.
“I can’t give you data on what megawatts weren’t deliverable, because our operators are working to ensure that the megawatts are deliverable [through exceptional dispatch],” Servedio said.
Other stakeholder concerns focused on the proposal’s technical details. Call participants asked questions about how many RAS would be incorporated into a possible proposal, the duration of emergency ratings and the workings of the complex flow models CAISO staff used to determine the transmission feasibility of contingency reserves.
“I’m just trying to figure out the scope of this effort,” said Seth Cochran, manager of market affairs and origination at DC Energy.
CAISO staff took pains to assure stakeholders that the issue paper did not represent an actual proposal — despite an outlined schedule proposing a Fall 2017 implementation date for any measures resulting from the process.
“We’re not really proposing anything yet, we’re just trying to flesh out the issue,” Servedio said.
FERC last week approved 11 Entergy local balancing authority (LBA) agreements stemming from the utility’s 2013 integration into MISO.
Entergy Transmission Source: Entergy
Entergy Services and Entergy Arkansas sought the agreements with entities embedded within the LBA areas to ensure accurate coordination and communication of operational and metering information. The agreements identify load and/or generation of counterparties located within each area as well as specifying operational responsibilities and meter specification and data sharing requirements.
The April 26 order (ER14-693, et al.) found that Entergy “demonstrated that the LBA agreements will assist in ensuring reliable operations” of the utility’s electric system.
The commission required Entergy to submit a compliance filing showing that cost allocations for residual loads — the amount of over- or under-claimed energy in an LBA area — will rely on cost-causation principles where possible, replacing the company’s proposed pro rata cost allocation.
Entergy’s original 2013 LBA agreements included a provision that counterparties report their metering data to help the utility correct errors responsible for producing residual loads within the LBA areas.
A revised batch of agreements the next year proposed to instead allocate residual load costs and credits based on a pro rata methodology in order to “simplify the burden associated with meter corrections.” Entergy contended that some embedded entities were too small and their contribution too insignificant to directly assign costs, leaving costs to be allocated according to overall energy injections and withdrawals within an LBA.
Entergy last year offered an additional update to that provision, proposing to work with counterparties to maintain adequate metering equipment to directly assign residual load cost responsibility to a specific company. That process would incentivize “embedded entities to maintain adequate metering and robust processes for reporting data,” the utility said.
Last week’s decision said Entergy’s pro rata cost allocation provision suffered from the same flaws as a similar MISO plan rejected in 2006, which FERC said “failed to allocate unaccounted-for energy to the load that caused it.” However, FERC said Entergy’s efforts to directly assign residual load costs when possible was a sufficient improvement to align with cost-causation principles.
FERC also sided with Entergy in ruling that the utility should not bear the entire cost of residual loads within the LBA areas “because such costs are caused by the accumulated actions of all embedded entities within the LBA areas.”
Counterparties Dow Chemical, Union Carbide, Occidental Chemical, Calpine, Tenaska and Sabine Cogen had questioned the residual load cost allocation proposal and objected to the creation of the LBAs, contending that the agreements do not accomplish anything not already covered by the MISO Tariff and required by the RTO.
FERC said the noncompulsory application of LBAs does not make them any less useful.
“We disagree that, because no commission or MISO rule or policy mandates agreements such as the LBA agreements, they are unnecessary and unjust and unreasonable,” FERC wrote.
The commission also rejected arguments that the agreements too closely resembled generation interconnection agreements and said it was “unpersuaded by arguments that Entergy does not need the LBA agreements in order to carry out its responsibilities as an LBA area administrator.”
A merchant transmission developer asked FERC last week for authority to negotiate transmission contracts for a mostly underwater cable to transport 1,000 MW of electricity underneath 260 miles of the Erie Canal and Hudson River to New York City (ER16-1495).
Erie Canal Source: New York State Canal Commission
Empire State Connector filed an application for transmission service on a HVDC line that would deliver renewable energy from upstate New York.
ESC is a joint venture of Toronto-based transmission developer oneGrid and investment firm Forum Equity Partners. The company says it is assuming the entire financial risk of the $1.5 billion project. It asked for FERC approval by June 26 to keep to its preferred permitting and open season schedule.
“Our strategic location and innovative, low-impact route will ‘unlock’ upstate renewable and zero-emission generators, helping New York state achieve its ambitious goal of 50% renewable generation by 2030,” CEO John Douglas said in a statement.
The project would originate at a converter station located near Utica and terminate at a converter station located in either the Bronx or Brooklyn. Underground cables would be connected to a new converter station near the existing Marcy substation near Utica until it enters the canal. Cables would be buried under the locks and dams along the canal route.
The company said a NYISO feasibility study concluded the project is viable and it has secured a spot in the ISO’s interconnection queue.
ESC said it will file its Article VII application for major infrastructure review certification with the New York Public Service Commission by the end of the year. It will also conduct a solicitation later this year seeking subscribers for capacity on the line.
The project will create more than 500 construction jobs and 1,200 indirect jobs during the three-to-four-year construction period, the company said. Each converter station is estimated to cost more than $200 million. The target in-service date is for some time in 2021.
The NYPSC in December declared a public policy need for above-ground transmission to move upstate power from central New York to the New York City area through AC lines that are using existing corridors. (See NYPSC Directs NYISO to Seek Tx Bids.) Douglas told RTO Insider on Monday that he sees ESC and above-ground AC as “complementary.”
“New York state certainly has ambitious goals to develop renewable energy,” Douglas said. “It’s going to need a lot of new transmission, especially if it succeeds in closing Indian Point. So we see … room for both [projects] for both energy and capacity.”
ERCOT’s Technical Advisory Committee voted last week to dissolve its Distributed Resource Energy Ancillaries Market (DREAM) task force, agreeing the group had brought issues to the forefront that could now be taken up in the ISO’s stakeholder process.
The DREAM team was created last May to investigate the regulatory and market framework for distributed energy resource (DER) participation in ERCOT’s wholesale markets.
Shell Energy’s Greg Thurnher, the DREAM team’s chair, said the goal was to establish a marketplace where price-taking and price-responsive distributed generation (DG) resources can efficiently coexist.
Expanding the scope of price-responsive loads and resources in security-constrained economic dispatch, he said, more accurately reflects the price elasticity of demand.
“In the eyes of TAC, I think we’ve achieved our charter,” said Thurnher, who represents the Independent Power Marketer segment.
TAC Chair Randa Stephenson, with the Lower Colorado River Authority, agreed and thanked the team for its work. “We’re now at a point where we can vet specific and technical issues through the stakeholder process,” she said, before casting the only abstention in an otherwise unanimous vote.
Thurnher said Shell will sponsor a nodal protocol revision request (NPRR) following up on the DREAM team’s recommendations. He has proposed five market rule changes for price-responsive DG, among them a proposal to exclude the resources from participating in ERCOT’s congestion revenue rights markets.
He would also exclude DG from participating in regulation until distributed storage becomes larger and more cost competitive. DG “is a low-cost hedge, it’s out there and it’s growing. These assets are right-sized and can solve many of the smaller constraints we have on our system,” Thurnher said. “When you have resources with no load responding to the system, they should be given the opportunity to bid into the market and contribute to price formation.”
Kenan Ögelman, ERCOT’s vice president of commercial operations, responded with a spreadsheet listing 15 short- and long-term issues identified by the ISO as needing revision requests or new market rules. “The idea was to put down ERCOT’s perspective on what our needs are,” he said.
Ögelman said staff looked initially at accounting for larger resources and then tried to capture smaller resources. He said the focus was on “what’s in the market, instead of getting these resources participating in the market.”
“Some of these things are what Greg was talking about,” Ögelman said. “We understand your priorities might be slightly different, and we’re happy to work with you and move them up. This is not written in stone.”
Ögelman said he would like to combine Thurnher’s proposals with ERCOT’s spreadsheet and hand the effort over to a working group. He said he would be “looking for input and timing from the market as to when these should come into play.”
Several stakeholders expressed concern smaller market participants might lack the resources to ensure their voices are heard in stakeholder proceedings. Others cautioned about moving too quickly to allow stakeholders to provide input.
Stephenson said she will work with ERCOT “to ensure the right people,” including distribution utilities, are involved in the discussions.
TAC Approves Addition of Responsive Reserves
The TAC approved staff’s recommendation to add 200 MW of responsive reserve service (RRS) during the afternoon hours in July and August. The vote came after the TAC asked ERCOT to include in its 2017 ancillary service methodology review an analysis of how the elimination of the reserve discount factor (RDF) would affect operations.
The ISO’s current minimum RRS requirement is 2,300 MW under normal conditions. The additional 200 MW will come into play during those four-hour blocks when average temperatures are most likely to exceed 95 degrees Fahrenheit. Effective this year, RDFs are reviewed and adjusted based on the generator’s performance during an unannounced test.
“If the temperatures are over 95, we need to move this market away from the old zonal market rules and control area rules,” Calpine’s Randy Jones said. “You should not be doing testing around peaks.”
Austin Energy’s Barksdale English agreed with Jones, saying the RDF should be based on actual performance, not unannounced testing.
The recommendation has already been endorsed by the Wholesale Market and Reliability and Operations subcommittees. It will go to ERCOT’s Board of Directors in June for final approval.
NOGGR Tabled, Other Revision Requests Approved
The TAC unanimously approved a previously tabled revision request and several other change requests brought forward by its subcommittees. It also tabled a nodal operating guide revision request (NOGRR) that recommended a 25-MW annual-peak threshold to exempt distribution service providers from procuring designated transmission operator services from a third-party provider.
NOGRR 149 was developed last year to settle the noncompliant status of seven municipally owned utilities (MOUs), ranging in size from 9 to 21 MW. It was rejected by ROS and tabled by TAC, but the revision request’s proponents appealed.
GDF Suez’s Bob Helton, representing the Independent Generators segment, recommended tabling the NOGRR to allow ERCOT staff to answer several other questions. TAC Vice Chair Adrianne Brandt, of CPS Energy, asked that transmission service providers meet with the MOUs to further discuss the issue.
The committee approved:
NOGRR 151, aligning operating guides with changes made in NPRR 748 and providing consistency, transparency and clarification related to communication protocols;
NOGRR 153, creating a new process to maintain alignment of the energy emergency alert language between the protocols and nodal operating guides;
Nodal protocol revision request (NPRR) 752, clarifying the revision-request process protocol language to reflect current ERCOT practices; and
System change request (SCR) 788, updating the resource-limit calculator formula used to determine the generation-to-be-dispatched value.
Ögelman updated the TAC on NPRR 667, which he called an “odyssey” more than two years in the making. The revision request is designed to improve regulation-up and regulation-down service and replace RRS and non-spinning reserves with a combination of four new ancillary services.
ERCOT is hoping the Protocol Revisions Subcommittee (PRS) will endorse the NPRR in May, before bringing it back to the TAC.
“We believe 667 meets a lot of board objectives and market-design objectives,” Ögelman said, “but ERCOT is willing to wait on TAC’s final input on the issue.”
In March the PRS withdrew a similar revision request (NPRR 756) that would redesign the ancillary services market. Staff said at the time NPRR 667 was the better option.
Data Workshop Scheduled
The committee discussed ERCOT’s upcoming workshop on data reports, tentatively scheduled for May 20. The workshop is a result of a discussion at the March TAC meeting about how the ISO and its market participants exchange data and handle changes to reports. (See “TAC to Schedule Data-Exchange Workshop,” ERCOT Technical Advisory Committee Briefs.)
Ögelman said the workshop would focus first on changes to reports and how they impact market participants, and then the internal need for “some type of controls around [the reports] that give people comfort.”
“We want to explore more stable, different ways to interact without scraping data,” he said.
“I think this is an important step for us to take,” Citigroup Energy’s Eric Goff said. “It’s so critical to ensure everyone has reliable and robust access to all ERCOT data. Over the long run, I think it will be a significant improvement to the transparency of data.”
ERCOT staff said it is also working on an NPRR to improve the accuracy of its wind forecasts by synching them with the current operating plan for intermittent resources.
Stephenson noted market participants have seen “big swings” of about 175 MW during March and April, creating volatility in the market. She assigned the NPRR’s work to the Wholesale Market Subcommittee.
SANTA FE, N.M. — SPP’s Integrated Marketplace continues to show growth and member benefits in its second year of business, SPP Vice President of Operations Bruce Rew told the Regional State Committee (RSC) last week.
Rew said 172 market participants — 110 classified as financial-only, 62 as asset-owning — are now registered for the Integrated Marketplace, comprising the day-ahead and real-time markets, a price-based operating-reserve market and a central balancing authority. He also said the markets delivered $380 million in net savings in the 12 months after they went live in March 2014 and $422 million in savings in 2015.
“We’re still providing a lot of benefits with optimized dispatch, even with natural gas prices under $2,” Rew said.
Part of the marketplace’s success stems from SPP’s growing wind capacity, currently 12,400 MW, with another 574 MW in the pipeline. The RTO, which previously had 50 MW of solar capacity, had an additional 140 MW register April 1, its first addition of solar in years, Rew said. The facilities will go online later this year.
Rew strayed from his presentation to note SPP had set two more wind energy records over the weekend, extending its wind peak to 10,989 MW on April 23 and its wind penetration level to 49.17% on April 24.
SPP has seen its generation profile change and become more diverse with the October addition of the Integrated System and its hydro and wind resources. The RTO set a new winter peak load of 37,412 MW on Jan. 18, 417 MW more than last winter’s peak.
Rew also noted that the day-ahead market was only delayed from posting once in the first quarter of 2016. The real-time balancing market has successfully solved 99.9% of all intervals, he added.
More market improvements are coming. Rew said the gas-electric harmonization project is still on schedule for a fall implementation, and the enhanced combined cycle project is expected to meet its March 2017 target. (See “Enhanced Combined Cycle Project Moves Forward,” SPP Board of Directors/Members Committee Briefs.)
CAWG Updates
The Cost Allocation Working Group (CAWG) updated the RSC on its work, including several issues which will come up for RSC and/or board votes in July.
Nebraska Power Review Board consultant John Krajewski said he hopes a new member cost-allocation review process will be ready for approval in July. He said the process should add consistency to the process used when new members are being considered or ask for changes to the Tariff.
“When we integrated Nebraska and the IS, there wasn’t a firm process to follow,” Krajewski said. “My impression was we flailed around as an RSC.”
Adam McKinnie, chief regulatory economist with the Missouri Public Service Commission, said the working group’s review of aggregate study waiver criteria will help the committee determine which transmission project costs are paid by companies purchasing transmission service and which are allocated to the SPP footprint. SPP’s aggregate study assesses which projects are necessary to sell transmission-service requests (TSR) to move energy around the SPP system, as well as who pays for those projects.
McKinnie pointed out that costs are initially assigned to the different purchasers once the study is complete, but if those purchasers meet certain criteria, a portion of those costs will be paid for by the region. The amount approved for base plan funding is the “safe harbor,” he said, but TSR purchasers who don’t meet the safe harbor’s three criteria can ask for a waiver.
The CAWG is considering criteria that would limit a utility’s designated resource to no more than 125% of its forecasted load if it’s granted a TSR, ensuring base-plan funding is not used for “resources which are unnecessary or uneconomic.”
“The goal is to make sure only designated resources that are needed or close to forecasted load receive the waivers,” McKinnie said.
Stephen Stoll, a commissioner with the Missouri PSC and chair of the Regional Allocation Review Task Force, told the RSC his group had finalized the language for a new business practice implementing each of the remedies recommended in the 2012 RARTF report. The task force intends to bring the revision request for MOPC and board approval in July.
The business practice is designed to “lay the foundation for documenting the potential [regional-cost allocation review] remedies and clarify the process … implementing [an RCAR] remedy.” The task force is responsible for defining the analytical methods used to review the “reasonableness” of the regional-allocation and zonal-allocation methodologies.
The committee also received a status report from the Transmission Planning Improvement Task Force and an update on the 2016 Integrated Transmission Plan’s 10-Year Assessment and report (See related story, SPP Board of Directors Briefs.)
MISO Settlement Funds Held Up
COO Carl Monroe told the committee that SPP has received funds from the recent $9.6 million settlement with MISO, but that protests have delayed distribution of the money.
MISO agreed to the payment to reimburse SPP and impacted members for its use of their transmission systems since 2014. (See FERC OKs MISO-SPP Transmission Settlement.)
On Jan. 27, SPP proposed a new Tariff Attachment AU to govern the distribution of the settlement revenues. The City of Lincoln, Neb., and four wind farms protested in February.
Lincoln said that SPP’s proposal to create a new revenue allocation methodology is unnecessary, and that the RTO should allocate the revenues under the rules in Tariff Attachment L.
In its answer, SPP said that Attachment L is not applicable to the settlement revenues. Contrary to Lincoln’s protest, SPP said it is not providing point-to-point (PTP) transmission service but available system capacity (ASC) usage.
PTP service is charged based on the amount reserved, regardless of actual scheduled usage, and includes a point of receipt and a point of delivery on the SPP system. ASC usage is charged based on actual usage of the SPP and joint parties’ transmission systems as determined by the flow impact of MISO market dispatches between its North and South regions. (The joint parties are Associated Electric Cooperative Inc., PowerSouth Energy Cooperative, Southern Company Services, Tennessee Valley Authority, Louisiana Gas and Electric and Kentucky Utilities.)
SPP also rejected the wind farms’ complaint that its proposal would circumvent the Z2 revenue crediting process, which gives upgrade sponsors a share of revenues received by SPP when the transmission upgrades they funded are used by others. “Attachment Z2 of the SPP Tariff is simply not applicable to the [joint operating agreement] settlement revenues,” SPP said.
On March 25, the commission accepted SPP’s proposal in part and set the docket for hearing and settlement procedures, saying there were factual issues in dispute that could not be resolved based on the record before it (ER16-791).
The commission rejected SPP’s proposal to reimburse $456,000 spent by some transmission owners on legal expenses in the SPP-MISO dispute. “SPP has not provided any commission precedent permitting a regional transmission organization to reimburse certain stakeholders for legal expenses, nor has SPP shown that the transmission owners that incurred the legal expenses represented the interests of SPP and its transmission customers rather than their own interests,” FERC said.
The first settlement conference was held April 21, with a second scheduled June 16.
In the meantime, Monroe said, SPP has asked FERC for permission to distribute the funds to members who signed on to the settlement agreement. “We will be distributing those funds based on our proposed distribution,” he said, but he noted the distribution would be to entities that can make refunds to SPP “if the settlement is different than … proposed.”
‘Where Policy Issues Go to Die’
Denise Buffington, director of energy policy and corporate counsel with Kansas City Power and Light, asked Monroe whether the MOPC’s recent decision to develop a business practice to address non-Order 1000 seams projects was the right mechanism to resolve FERC’s rejected Tariff revision. (See “SPP Pondering ‘One-Offs’ as Potential Seams Projects,” SPP Markets and Operations Policy Committee Briefs.)
“It feels like a business practice is a place where policy issues go to die,” Buffington said.
“We’ll debate that as we go through the business practice,” Monroe assured her. “No one wanted to go through a FERC refiling. The question we’re still trying to address is whether there’s a gap … the business practice is going to have to deal with where the gap is.”
RENSSELAER, N.Y. — NYISO is proposing to change the way stakeholders prioritize internal projects, effective with the 2017 priority list.
The ISO reviewed its proposal at Wednesday’s Management Committee meeting, nearing the end of a process that began in the Budget and Priorities Working Group last September. “This is based on stakeholder feedback,” NYISO senior manager Ryan Smith said.
The projects include software and product development and NYISO capital expenditures.
NYISO scoring uses objective criteria that reflect strategic alignment, expected outcomes, risks and ability to execute. The stakeholders score projects based on their organizational priorities.
Among the proposed changes is the exclusion of mandatory and continuing projects from priority scoring. Stakeholders, who rank projects by assigning them shares of 100 voting points, would no longer have to “waste” their votes on projects that are already considered mandatory or are already under development, the ISO said.
NYISO also is proposing the use of sector-weighted scores in addition to raw scores. Affiliates and nonvoting entities would be excluded from weighted scoring but would be included in the raw scores.
Another change would provide cost and benefit information in advance of the stakeholder scoring deadline.
The timeline for drawing up the 2017 list includes identification of candidates through mid-June, followed by prioritization and evaluation by the end of July. That would be followed by recommendations in August, with final decisions made in the fall during NYISO’s annual budget process.
Project expenditures have averaged about $25 million annually in recent years, Smith said.
The changes are expected to be brought to a vote at the June board meeting.
The commission said the EIS will determine the potential impacts of Algonquin Gas Transmission’s project to determine if it is in the public interest.
The DREAM team was created last May to investigate the regulatory and market framework for 
The ISO reviewed its