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.
EPA announced that rules covering methane leaks from new oil and gas wells will come out soon, but the agency would give no guidance on when rules covering existing wells would be released.
The agency said it is gathering data on existing wells before developing the rules. The Obama administration has put the rules at the top of its priority list because of the effect of methane on climate change.
“We have been moving in a very methodical manner to address pollution in ways that withstood legal challenges and are making a difference on the ground, and that is what we’re doing,” said Janet McCabe, head of EPA’s Office of Air and Radiation.
NRC Approves Early Permit For Possible 4th Salem Reactor
The Nuclear Regulatory Commission’s Atomic Safety and Licensing Board approved preliminary documentation for the commission to issue an early site permit for a possible fourth nuclear reactor at PSEG Nuclear’s Artificial Island complex in New Jersey.
Although the company hasn’t yet committed to constructing a fourth reactor, it is pursuing the permit for planning purposes. If issued, the permit would be good for 20 years.
Geological Survey Says Turbines, Sandhill Crane Can Coexist
Wind energy sites in southern states are unlikely to have a significant negative effect on the migratory patterns of the sandhill crane, according to a report from the U.S. Geological Survey.
“The current placement of wind energy towers in the central and southern Great Plains may have relatively few negative effects on sandhill cranes wintering in the region,” the study concluded. Among the states included in the review were Texas, Oklahoma, Kansas and New Mexico, which serve as temporary habitats for the cranes during their migration south from Canada and northern states.
EPA to Reimburse States, Tribes For Gold King Mine Spill
EPA said it will reimburse state, local and tribal governments for the estimated $1 million they spent on environmental costs after the agency accidentally caused a massive spill of mine wastewater in Colorado last August.
The agency is also considering declaring the Gold King Mine a Superfund site, which would make it eligible for additional federal cleanup dollars.
A crew working for EPA accidentally breached a wastewater holding area, releasing 3 million gallons of water containing lead, arsenic, copper and other pollutants. The tainted water flowed downstream through Colorado to New Mexico and Utah. The affected area included land owned by the Southern Ute and Navajo Nation tribes.
Ex-NRC Commissioner: Licensing Process Hinders New Reactor Investment
Former Nuclear Regulatory Commissioner Jeffrey S. Merrifield said the commission’s current step-by-step licensing process for new nuclear reactor technology leaves advanced design developers with little information to go on and is hindering investment into research and development.
“One of the disadvantages of the current system is it’s sort of all or nothing,” said Merrifield, chairman of the Nuclear Infrastructure Council’s Advanced Reactors Task Force. “You have to put in your license application and wait a very long period of time to determine whether the NRC is going to find that to be acceptable.”
Merrifield made his comments at a House Energy and Commerce subcommittee hearing on Friday. As an example of a good model for NRC, he pointed to the Canadian Nuclear Safety Commission’s process, which has “discrete milestones” that “provide an early regulatory signal” of possible approval that costs project developers about $5 million, much less than required under current NRC procedures.
Texas Company Applies for Interim Nuclear Waste Permit
Waste Control Specialists, in partnership with France-based AREVA, has applied to the Nuclear Regulatory Commission to store used nuclear fuel and other nuclear waste in Andrews County, Texas. The company’s design envisions a facility able to store 40,000 metric tons of used fuel, with an operational date of 2021. It would remain open for 40 years.
“Establishing an economically viable solution for used fuel management in the United States is vital to sustaining and advancing nuclear energy,” said Greg Vesey, senior vice president of AREVA TN Americas.
Political and industry leaders have been unable to devise a permanent storage facility for the nation’s roughly 70,000 metric tons of accumulated spent fuel and radioactive byproducts from nuclear reactors. In April, Holtec International announced plans to open a $5 billion consolidated interim storage facility in New Mexico, with a life span of 100 years. Holtec said it will apply for its license by the end of the year.
California Senate Demands DOE Remove San Onofre Waste
The California Senate is demanding that the U.S. Department of Energy remove nuclear waste stored at the retired San Onofre nuclear generating station. The oceanfront plant has been shut down since a leak in a steam generator convinced owner Southern California Edison that it made no economic sense to restart the two units.
The Senate resolution calls on President Obama and the U.S. House of Representatives to approve a bill that would call for consolidation of all nuclear waste being stored on plant sites.
“It’s way past time for the federal government to move the nuclear waste stored at San Onofre to a location away from densely populated and environmentally sensitive areas,” said California Sen. Patricia Bates. “I’m pleased that my state Senate colleagues have endorsed my call to Washington D.C. to approve pending legislation that would help make Orange and San Diego County residents safer.”
NRC Clears Environmental Review Of Suspended Bell Bend Project
The Nuclear Regulatory Commission last week declared that there are no environmental issues that would hold up the issuances of a combined license for the proposed Bell Bend nuclear station project near Harrisburg, Pa., even though the project is no longer active.
In 2008, PPL, which spun off its generation assets into Talen Energy, applied for the license, which launched the environmental review. But last year, the designer of the project’s proposed reactor, AREVA, asked NRC to suspend the safety review. AREVA was to design a third-generation light-water reactor for the project.
The AREVA request put the design certification review on hold, but the environmental review continued. There is no word if the project will start up again.
The Bellefonte Nuclear Generating Station, the Tennessee Valley Authority’s never-operational plant near Hollywood, Ala., is going on the market.
TVA halted construction in 1988 on two incomplete 1,256-MW pressurized water reactors on the site. TVA is considering a sale of the entire 1,600-acre complex and is conducting a webinar open to the public to discuss the possible sale.
WILMINGTON, Del. — The Markets and Reliability Committee last week deferred voting on a problem statement and issue charge to study the challenges of the pseudo-tie requirement for external Capacity Performance resources. Staff will narrow the scope of the proposal and return to the committee in May.
PJM has been working on temporary solutions to resolve operational and reliability issues, but it wants to decide on a long-term solution in time for the 2017 Base Residual Auction.
In order to participate in PJM’s capacity market, external resources are subject to pseudo-tie requirements. PJM has encountered some issues with the construct, however, including compliance risks, congestion management challenges, transmission service evaluation issues and operational impacts on neighboring systems.
Stu Bresler, vice president for market operations, said that a study such as the one proposed by the problem statement and issue charge could lead to changing the qualifications for granting transmission service into PJM.
A number of stakeholders expressed concern that if the deliverability standards are altered, they might preclude units currently allowed to deliver capacity into PJM from being able to do so in the future.
Bresler assured members that any changes would be applied “prospectively” and would not affect capacity that already has cleared.
However, that did not assuage the concerns of members including Ed Tatum, of American Municipal Power, who worried that generators may invest in upgrades only to find they are no longer eligible to deliver capacity in future delivery years.
“You need to have certainty,” he said. “We’re talking about making investments in units.”
PJM Prepares for FERC Directive on MOPR
Bresler told the MRC that PJM wants to schedule meetings so that members are prepared if FERC directs the RTO to change its minimum offer price rule (MOPR) as a result of Ohio regulators’ controversial approval of power purchase agreements for FirstEnergy and American Electric Power generating units. (See PJM: MOPR Could be Improved, but not by BRA.)
Eleven generating companies had asked FERC to expand the MOPR, which currently applies only to certain new resources, saying they feared that the Ohio PPAs could lead to below-cost offers from existing resources.
PJM agreed that the MOPR should be changed to counter subsidized offers from existing generators, but it asked FERC not to order changes before next month’s BRA.
“Putting rules of this magnitude in place in such a short timeframe could lead to significant unintended consequences. The best course of action is to kick it to the stakeholder process, allow us to thoroughly vet the issue and allow us to come back in time for the next auction,” Bresler said, paraphrasing PJM’s filing.
“Having suggested that, we came to the realization that if we waited for a response from FERC before we started the ball rolling, it would put us even further behind the eight ball,” he said. “We thought it would be prudent to get some meetings on the calendar.”
Assuming FERC respects PJM’s wishes and does not order changes for the upcoming auction, the first educational meeting would be scheduled for late May or early June.
Manual 19: Load Forecasting and Analysis. Revisions remove outdated rules for legacy air conditioner and water heater cycling programs and correct formulas for end-use weather variables.
Manual 12: Balancing Operations and Tariff changes incorporate business rules of dynamic transfers.
Settlement Method for Demand Response Adopted
The committee endorsed a new method for measuring emergency demand response. It changes the emergency energy default customer baseline (CBL) from the hour before to the current default economic CBL. (See “Members Endorse New Way to Measure Emergency DR,” PJM Market Implementation Briefs.)
GDECS Definitions and Clarifications Endorsed
The MRC and the Members Committee approved the nonsubstantive reorganization and relocation of definitions recommended by the Governing Documents Enhancement and Clarification Subcommittee (GDECS).
As part of its consent agenda, the MC also approved an additional 11 items recommended by the GDECS.
Over 16 objections, the MC also endorsed the definition of capacity import limit. Members had expected to vote on a friendly amendment to the definition, but that was withdrawn before the meeting.
MRC First Readings
The MRC heard the proposed charter for the End of Life Senior Task Force, created in March to develop ways to provide more transparency and consistency in the communication and review of end-of-life projects in the Regional Transmission Expansion Plan.
Members were informed of a proposed revision to the charter of the Energy Market Uplift Senior Task Force to include the review of virtual transaction rules.
PJM’s Dave Egan presented the recommendations of the Earlier Queue Submittal Task Force. The changes would require interconnection customers to provide more documentation earlier to ensure consideration of their projects. (See “Stricter Rules Proposed for Queue Submittal Process,” PJM Planning Committee and TEAC Briefs.)
Barry Trayers of CitiGroup Energy proposed adding the phrase “Any transactions that PJM staff determine would not benefit from delaying until the [equivalent forced outage rates] are published” to the “Replacement Resources” section of Manual 18.
A proposed charter was presented for the Seasonal Capacity Resources Senior Task Force, which will study how such resources may participate in the Capacity Performance model in the 2020/21 delivery year and beyond.
Dave Anders presented some minor word changes to a previously approved problem statement and issue charge to study distributed energy resources’ path to PJM markets. (See “Faster Path to Market for Distributed Resources to be Studied,” PJM MRC & Members Committee Briefs.)
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 
EPA announced that rules covering methane leaks from new oil and gas wells will come out soon, but the agency would give no guidance on when rules covering existing wells would be released.
The Nuclear Regulatory Commission’s Atomic Safety and Licensing Board approved preliminary documentation for the commission to issue an early site permit for a possible fourth nuclear reactor at PSEG Nuclear’s Artificial Island complex in New Jersey.
Wind energy sites in southern states are unlikely to have a significant negative effect on the migratory patterns of the sandhill crane, according to a report from the U.S. Geological Survey.
EPA said it will reimburse state, local and tribal governments for the estimated $1 million they spent on environmental costs after the agency accidentally caused a massive spill of mine wastewater in Colorado last August.
Former Nuclear Regulatory Commissioner Jeffrey S. Merrifield said the commission’s current step-by-step licensing process for new nuclear reactor technology leaves advanced design developers with little information to go on and is hindering investment into research and development.
Waste Control Specialists, in partnership with France-based AREVA, has applied to the Nuclear Regulatory Commission to store used nuclear fuel and other nuclear waste in Andrews County, Texas. The company’s design envisions a facility able to store 40,000 metric tons of used fuel, with an operational date of 2021. It would remain open for 40 years.
The California Senate is demanding that the U.S. Department of Energy remove nuclear waste stored at the retired San Onofre nuclear generating station. The oceanfront plant has been shut down since a leak in a steam generator convinced owner Southern California Edison that it made no economic sense to restart the two units.
The Bellefonte Nuclear Generating Station, the Tennessee Valley Authority’s never-operational plant near Hollywood, Ala., is going on the market.