FERC last week accepted Pacific Gas and Electric’s filing for a proposed rate increase under the utility’s transmission owner tariff, but the commission suspended implementation of the increase for five months out of concern that the proposed rates could yield “substantially excessive revenues.”
The utility’s filing raised “issues of material fact” that would be better addressed through further proceedings, the commission said in its Sept. 30 order (ER16-2320).
The new rates will become effective March 1, 2017, but they remain subject to a refund based on the outcome of settlement and hearing proceedings.
In its filing, PG&E proposed a 10.9% return on equity for 2017 — composed of a 10.4% base return plus a 50-basis-point incentive adder for its continued participation in CAISO. The utility said its transmission rate base will jump 29% to $6.71 billion, while its retail network transmission service revenue requirement is projected to increase 15.4% to $1.718 billion.
Opponents of the rate increase, which include the California Public Utilities Commission, contend that the utility should be required to calculate its ROE based on the median of its own discounted cash analysis, which would reduce the base rate to 8.65% and lower the revenue requirement by about $114 million.
Those opponents also argue that PG&E’s proposed 3.26% depreciation rate is excessive and represents an unjustified increase from its currently authorized depreciation rate of 2.52%.
The commission denied a CPUC request that it not approve PG&E’s 50-basis-point adder based on the fact that the justification for the adder is the subject of a proceeding before the 9th U.S. Circuit Court of Appeals. The CPUC contends the adder is unnecessary because PG&E is required to be a member of CAISO under California law.
“While we recognize that appeal is pending, such an appeal does not operate as a stay of the commission’s consideration of this issue here,” FERC said.
The commission will appoint a settlement judge on the matter later this month, but it encouraged PG&E and opponents to settle their disputes before the start of settlement proceedings.
SPP stakeholders have recommended the RTO’s leadership reject $114 million in remaining waiver requests for Z2 transmission upgrades.
The Z2 Task Force voted 8-4 Friday with four abstentions to “follow the Tariff” and reject all Group B and C waivers. SPP has calculated that Group B transmission customers (those that SPP said didn’t qualify for waivers from paying their Z2 bills) owe $36.9 million in directly assigned upgrade costs and Group C members (who didn’t request waivers) owe $77 million.
SPP staff made the same recommendation to the Board of Directors and Markets and Operations Policy Committee in July, but the board did not adopt the recommendation and created the task force to find a “more rounded solution” to a problem that dates back to 2008. (See Preliminary Z2 Bills Released; Task Force Develops Options for Waiver Requests.)
The task force reviewed additional data from staff and discussed six options it had developed during its previous meeting. The “follow-the-Tariff” option was a clear favorite, with accepting the waivers and regionalizing the costs drawing half as much support.
The recommendation now moves forward to the MOPC and the board later this month. The task force plans to make itself available to help improve SPP’s Z2 processes following the October meetings.
“We’re the only RTO that allows third-party impacts to these types of upgrades,” said Bill Grant, director of strategic planning for Southwestern Public Service, referring to transmission customers making service requests that affect previous upgrades. “This is a convoluted mess. It’s going to cost us money going forward. Now that we’ve seen it, and how complicated the whole [Z2] process is, why wouldn’t we change that?”
Under Attachment Z2 of the SPP Tariff, staff was to assign financial credits and obligations for sponsored upgrades. Years of incorrectly applied credits have complicated the task of trying to accurately compensate project sponsors and claw back money from members who owe debts for the upgrades.
SPP Vice President of Operations Bruce Rew said his staff has held internal discussions on how to improve the Z2 process and developed a couple of alternatives that can be presented in the future.
“One thing that has to be key is that [the process] has to be simpler than it is,” Rew said. “We’re concerned about how we manage this 10, 20, 30 years from now. It’s got to be simpler in terms of what we have, both on our side and on the visibility side, so that you can see it.”
In a related matter, FERC on Friday approved SPP’s request for Tariff waivers to allow it to offer a payment plan to transmission customers owing Z2 bills (ER16-2330).
SPP Goes Live with New Gas-Day Timelines
SPP’s Integrated Marketplace instituted its new FERC-ordered timelines for gas-day nominations Oct. 1.
Phillip Bruich, SPP’s director of markets, said the transition went “very smoothly” and thanked market participants for being prepared.
“Our market participants … were well prepared, ready for the changes and able to submit their bids and offers on time the first day,” Bruich said. “This is a … step toward better coordination and efficiencies between the electric and gas markets.”
The SPP market now closes the day-ahead market at 9:30 a.m. CT and posts the results at 2 p.m., moving the timelines up from 11 a.m. and 4 p.m., respectively. The day-ahead reliability unit commitment reoffer period opens at 2:45 p.m. and closes at 5:15 p.m., a shift from 5 p.m. and 8 p.m., respectively.
The changes are a result of FERC Order 809, which required RTOs to coordinate their day-ahead operations with the natural gas market. The commission says this change will “better ensure the reliable and efficient operations of our interstate natural gas pipelines and our electricity systems.”
CAISO expects to hold its 2017 revenue requirement to this year’s level despite a planned $4.3 million increase in spending driven by rising labor costs, the ISO’s chief financial officer said Thursday.
CAISO’s revenue requirement — which tracks closely with the ISO’s operations and maintenance expenses — has remained below $200 million for more than 10 years.
Although next year’s proposed budget is projected to increase 2% to $214.5 million, the ISO is seeking maintain its revenue requirement at $195.3 million for a second straight year, CFO Ryan Seghesio said during a Sept. 29 stakeholder call.
The additional expenses will be offset by revenues from other sources, including money earned from the operation of the Western Energy Imbalance Market.
Although the revenue requirement has increased 0.3% annually since 2007, it is 18% below its 2003 peak, when the ISO’s yearly debt service costs were more than three times as high as today.
“This shows our commitment to a stable revenue requirement,” Seghesio said.
CAISO recovers its annual revenue requirement through grid management charges assessed to market participants based on their use of the transmission system to serve load or deliver exports. Two out of three of those charges are slated to decline slightly next year, while a service charge associated with congestion revenue rights is expected to see an uptick.
Other fixed fees contributing to the requirement — such as those related to bidding into CRR auctions and trades by scheduling coordinators — are expected to remain unchanged.
The ISO’s operations and maintenance budget, which accounts for more than 80% of total spending, is expected to rise 2.5% next year on the back of a $4.6 million (3.8%) increase in salary and benefits expenses. The salary figure includes merit increases for existing staff and plans to hire seven new employees, bringing the total headcount to 600.
“We’ve held a very tough line on headcount for a while, but there’s some stress points [in various departments] that need to be relieved,” Seghesio said, adding that the number of full-time equivalent employees has fallen since 2012.
CAISO expects to reduce expenses related to outside contractors, consultants, training, travel and building leases, while fees to outside professionals such as attorneys are projected to rise.
Next year’s proposed revenue requirement also includes a $24 million cash-funded capital component, of which $20 million will be budgeted for approved projects, with the remainder to be held in reserve.
Debt service costs remain at $16.9 million, a figure Seghesio said will hold steady until 2023, when some of the ISO’s bonds become eligible for refinancing.
Declining transmission usage coupled with a steady revenue requirement will cause CAISO’s pro forma bundled cost per megawatt-hour — a measure of the ISO’s costs per transmission volumes used by market participants — to increase by $0.004/MWh to $0.809/MWh.
Next year’s transmission volumes are forecast to fall by 1.2 TWh to 241.5 TWh, continuing a trend in recent years.
CAISO attributes the decline to California’s extended drought — which has reduced both hydroelectric output and the amount of energy needed to move water supplies throughout the state — and the increased adoption of distributed generation, which is increasingly displacing the state’s reliance on central station power. Recent estimates indicate that rooftop solar now accounts for about 5,000 MW of capacity within the ISO’s balancing area.
Stakeholder comments on the proposed 2017 budget are due by Oct. 6. CAISO will seek board approval for a final budget in mid-December.
FERC will hold a technical conference Nov. 9 to determine what RTO rule changes may be required to accommodate electric storage. “The subject of the conference will be the utilization of electric storage resources as transmission assets compensated through transmission rates, for grid support services that are compensated in other ways, and for multiple services,” the Sept. 30 order said.
UN Heritage Monitoring Team Eyeing BC Hydro Project
A United Nations world heritage site monitoring team is taking a closer look at a plan to build a hydro project in British Columbia, concerned about the possible impact on Wood Buffalo National Park and the Peace River in neighboring Alberta.
Source: SiteCProject.com
The team was already examining the effects of two existing dams on the Peace River at the request of the Mikisew Cree First Nation, which says the areas are under threat of development. The U.N. review will now be expanded to include the Site C hydro project, a 1,100-MW project in northeast British Columbia, near Fort St. John.
The tribe is seeking to have the Peace River region declared a world heritage site, and possibly block the dam project. “We’re looking for them to list it as endangered so Canada can really take a more proactive means in managing those impacts and activities,” said Melody Lepine, a tribe spokesperson.
News that PennEast Pipeline has 33 new changes to the proposed route of the 119-mile pipeline is spurring environmental groups to call for FERC to conduct a new environmental review of the plan.
“These 33 new modifications further demonstrate that the draft [environmental impact statement] released does not even describe, let alone analyze, the pipeline PennEast wants to build,” said Maya van Rossum of the Delaware Riverkeeper Network. “FERC needs to go back to the drawing board and issue a new DEIS and hold a new public process, one that includes real public hearings.”
A company spokeswoman said most of the changes were proposed in an attempt to minimize the environmental impact of the pipeline. “PennEast views the modifications as being responsive not only to constructive feedback provided by landowners, agencies and other stakeholders, but also to recommendations contained within FERC’s draft environmental impact statement.”
Operators at the Pilgrim Nuclear Power Station allegedly filed two false reports relating to a hydrogen leak, but the Nuclear Regulatory Commission said their regulations don’t cover hydrogen leaks, and therefore plant owner Entergy has nothing to worry about from the commission.
A local fire chief said Pilgrim incorrectly claimed that it had notified fire officials about a hydrogen leak, and then filed another false report saying the notification was made a little while later. Plymouth Fire Chief Ed Bradley said those reports are just two more in a series of incorrect or nonexistent notifications.
But the commission said it was going to take no action against Entergy. “We have not identified any regulatory requirement on our part that they do these notifications of hydrogen releases to the fire department,” an NRC spokesman said. “As far as the NRC is concerned, that is not a regulatory issue.” Bradley said plant officials have promised the communication problem will be rectified.
Despite his complaints about Washington’s “rigged system,” Republican presidential nominee Donald Trump is relying on D.C. lobbyists representing utilities and coal, oil and gas companies on his campaign and transition teams, The Washington Post reported.
The head of Trump’s energy transition team, Mike Catanzaro, is a former staffer with the Senate Environment and Public Works Committee who later handled government relations for PPL. He is now a partner at the lobbying firm CGCN, which has represented Noble Energy and Talen Energy.
Other Trump advisers include Jeffrey Wood, a partner at Balch & Bingham and a registered lobbyist for Southern Co.
Increased demand for bio-energy as an alternative to fossil fuels is leading to less forested land and less habitat for wildlife, according to a multiyear study by researchers at North Carolina State University and the U.S. Geological Survey.
Tradeoffs that come with bio-energy production include risks to species that rely on a single, mature habitat and exacerbation of habitat loss for species already losing ground to increased urbanization, said researcher Nathan Tarr.
“None of the biomass sources that we looked at were good or bad for all species, nor was a single mix of biomass sources consistently the best or worst for all species,” Tarr said.
Report: Energy Efficiency Key to Cutting Carbon Emissions
Industrial energy efficiency could cut carbon emissions by 175 million tons nationwide in 2030, according to new research by the Alliance for Industrial Efficiency.
“Process efficiency improvements, boiler upgrades, replacing chillers, insulation, even things as simple as lighting,” said Jennifer Kefer, executive director of the group. “Our report demonstrates very clearly that one can cut carbon while saving money.”
MISO and PJM have nearly completed their work on joint operating agreement and tariff language to create the new targeted market efficiency project (TMEP) type, and the RTOs have singled out seven congestion-relieving candidate projects.
Four of the possible TMEPs are located at flowgates in Indiana, while one is in northern Illinois, one is on the southeastern Michigan-Ohio border and another is in central Ohio. The projects, produced from a joint RTO analysis that originally studied 12 candidates, range from 138 kV to 345 kV with total costs of $19 million and benefits of $117 million:
The Burnham-Munster 345-kV project on the northern Illinois-Indiana border:
Benefit-cost ratio: $32 million/$6.5 million
Cost allocation: PJM 88%/MISO 12%
The Bayshore-Monroe 345-kV project on the southeastern Michigan-Ohio border:
$17 million/$1 million
PJM 89%/MISO 11%
The Michigan City–Bosserman 138-kV project in northern Indiana:
$29.6 million/$2.3 million
PJM 90%/MISO 10%
The Reynolds-Magnetation 138-kV project in north-central Indiana:
$14.5 million/$150,000
PJM 41%/MISO 59%
The Roxana-Praxair 138-kV project in northeastern Indiana:
$6.5 million/$4.5 million
PJM 24%/MISO 76%
The Klondike-Purdue 138-kV project in north-central Indiana:
$6 million/$4.2 million
PJM 4%/MISO 96%
The Marysville-Tangy 345-kV project in central Ohio:
$12 million/“minimal” cost
PJM 98%/MISO 2%
“We’re pretty excited about this. This is exactly what we were hoping for,” PJM engineer Alex Worcester said during a Sept. 30 meeting of the MISO-PJM Interregional Planning Stakeholder Advisory Committee (IPSAC). “These aren’t projects that are just squeaking by; these are very significant cost-benefits.”
Twelve flowgate projects were initially considered in MISO and PJM’s TMEP analysis.
Worcester also said both RTOs were surprised with how evenly the cost allocation was shared among the total projects.
The RTOs used a joint survey to decide on some details of the TMEP process.
For example, the RTOs will not subtract congestion hedges in calculating project benefits. PJM said not excluding the hedge is “consistent with TMEP goal of simple, efficient metrics easily reproduced by stakeholders.” A majority of 27 survey respondents preferred not to include congestion hedges in the benefit calculation.
Worcester said there’s nothing to prevent congestion hedges being counted in the regional cost allocation, however.
A majority of 22 respondents supported using the last three years of historical congestion data in benefit calculations. Other stakeholders wanted the highest historical congestion data from two of the past three years used, while others wanted the past two years of congestion data used.
Exelon’s Sharon Midgley said the number of respondents seemed “incredibly low.” Worcester said there was “a reasonable cross-section of stakeholders” even though more MISO stakeholders responded than PJM stakeholders.
“This is what we’re going forward with now. In a couple of years from now, we’re open to revisiting this and improving it,” Worcester said.
PJM Manager of Interregional Planning Chuck Liebold said that there are internal RTO cost allocation details that need to be fleshed out in the draft JOA and respective tariff language. “But we have everything we need to know for the interregional benefit calculation and cost allocation,” Liebold said.
PJM and MISO staff said intra-RTO cost allocation rules are being worked out in PJM’s Transmission Owners Agreement-Administrative Committee and MISO’s Regional Expansion Criteria and Benefits Working Group.
MISO’s Adam Solomon said MISO and PJM will file JOA and tariff changes at the same time. In spite of unfinished cost allocation details, the RTOs plan to file the JOA changes sometime in October and recommend project candidates to their boards by December.
ERCOT is asking consumers in the Lower Rio Grande Valley region to limit or reduce their electricity use where possible through Tuesday, especially during the 3-7 p.m. peak demand hours.
ERCOT control room Source: ERCOT
“With some unplanned electric generation outages, combined with high temperatures in the region, we expect tight conditions during peak demand hours over the next few days,” Dan Woodfin, ERCOT’s director of system operations, said in a statement released Monday.
Woodfin said the 524-MW Frontera combined cycle plant’s recent withdrawal from the ERCOT system has complicated the task of meeting demand along the U.S.-Mexico border during tight conditions. Frontera’s owners, Viva Alamo, a subsidiary of The Blackstone Group, is dispatching energy into the Mexican market.
ERCOT said the conservation request is limited to the Lower Rio Grande Valley, and that it is not experiencing any systemwide issues at this time.
ERCOT has asked consumers to reduce demand during peak hours by:
Turning thermostats up 2-3 degrees during the peak hours;
Setting programmable thermostats to higher temperatures when no one is home;
Using fans inside homes;
Scheduling pool pumps to run in early morning or overnight hours, and shutting them off from 4-6 p.m;
Limiting the use of large appliances (dishwashers, washers, dryers, etc.) to morning hours or after 7 p.m.;
Use a microwave or slow cooker; and
Closing blinds and drapes during the late afternoon.
“We believe these voluntary actions by consumers can help limit the need for further action, such as rotating outages, to maintain overall reliability in the valley,” Woodfin said.
The Members Committee approved by acclamation a rate-increase proposal that struck a balance between allowing for cost increases and providing long-term certainty.
Members endorsed the Finance Committee’s unanimous recommendation for a composite rate of $0.36/MWh for two years and then a 2.5% annual increase that will result in a rate of $0.41/MWh in 2024. The approved rate schedule creates the lowest projected refunds, explained PJM’s Suzanne Daugherty, and allows for future revisions. The ability to install fee escalators later was built in, along with a five-year review.
PJM touted Moody’s Investors Service’s recent upgrade in the RTO’s credit rating, which praised its structure for recovering administrative costs.
“Under stated rates, PJM uses fixed, long-term capped rates for the administrative costs of managing the grid and wholesale electricity markets. Costs are managed within the rates,” PJM explained. “Other grid operators automatically pass through their administrative costs to members through formula rates that vary from month-to-month or year-to-year.”
PJM noted it has taken on additional responsibilities since the rates were first implemented in 2006, including enhanced physical and cybersecurity, increased planning and analysis related to changing governmental policies and implementation of new technologies.
Transmission Task Force Halts Most Action in Response to FERC Order
Calling it a “unique situation,” PJM’s Fran Barrett won approval from the Markets and Reliability Committee to suspend most of the activities of the Transmission Replacement Processes Senior Task Force in response to a recent FERC order.
The Aug. 26 Order to Show Cause calls into question whether PJM transmission owners, per FERC’s Order 890, are complying with their local transmission planning obligations, specifically with respect to supplemental projects (EL16-71). (See FERC Orders PJM TOs to Change Rules on Supplemental Projects.)
All but the task force’s forward-looking work on transmission project costs — which isn’t affected by the order — has been suspended.
PJM and the TOs have until Oct. 25 to respond to the FERC order, which opened a Section 206 proceeding. An addendum was also approved that allowed the task force to reconvene in March if FERC, which has no deadline for responding, hasn’t acted.
Susan Bruce, who represents the PJM Industrial Customer Coalition, commended the parties involved for maintaining communication during resolution of the issue.
Proposal Chosen for Capacity Release
After months of consideration, the MRC approved the straight-line offer curve PJM proposed for selling back excess capacity in February’s third incremental auction for the 2017/18 delivery year. The curve had to compete against several member proposals, but it was ultimately recommended by the Market Implementation Committee on Sept. 14. (See “PJM’s Straight-Line Offer Curve Recommended for Capacity Sellback,” PJM Market Implementation Committee Briefs.)
Members voted over the objections of Market Monitor Joe Bowring, who reiterated his concerns that the RTO is undervaluing the capacity and shouldn’t publicly broadcast its asking price. “PJM bought this capacity for a fairly high price. We believe, with reliability and the benefits associated with it, the minimum price should be much higher than you’re proposing,” he said.
No Objections to Metering Revisions
The MRC approved revisions to Manual 1 to close gaps in understanding between staff and members on metering rules. The proposal had minor edits from previous presentations, but it maintained its basis on solutions recommended by the Metering Task Force. (See “Metering Standards Ready for Stakeholder Vote,” PJM Markets and Reliability Committee Briefs.)
Flexibility for Vendors Approved for Competitive Bidding Rules
A PJM request to revise the Operating Agreement’s requirement to use open and competitive bidding when procuring goods or services from a member breezed through both the MRC and MC without objection.
There was some minor concern that the revisions — which exclude certain vendors from PJM’s competitive bidding requirements — might eventually allow for awkward conflicts of interest, but PJM assured that the screenings it devised would eliminate the potential.
PJM’s solution cribs off an existing provision in the OA that addresses a similar issue in allowing PJM personnel to invest in member companies with a de minimis PJM relationship based on a three-part test. To avoid the competitive bidding rules, a company must not:
be considered an electric sector company under the North American Industry Classification System;
receive more than 0.5% of its gross revenue from PJM; and
be involved in more than 3% of PJM’s total market transactions.
“What we found is that over the years, increasing numbers of nontraditional companies … engaged in activities at PJM as a member, but their focus was on other areas” than participating in the energy markets, explained PJM’s Steve Pincus. As examples, he cited office suppliers, such as Target and Walmart, and software companies, such as Microsoft and Siemens.
Responding to stakeholder requests, PJM said it would consider providing a list of the vendors it uses for operations and services as long as it doesn’t run afoul of any confidentiality or disclosure rules.
FE’s MAIT Receives Needed OA Revisions
FirstEnergy received approval for several Operating Agreement changes that will allow Mid-Atlantic Interstate Transmission, its newly formed transmission subsidiary, to assume the rights and obligations of Metropolitan Edison and Pennsylvania Electric in PJM’s Consolidated Transmission Owners Agreement. (See NJ Opposition Derails FirstEnergy’s Tx Reorganization — but not Projects.)
FE plans to make necessary FERC filings in October with a targeted effective date of Jan. 1. Several “legacy” contracts won’t have their interconnection service agreements finalized until later that month.
MRC Endorses Manual Changes
Members unanimously approved the following manual changes:
AUSTIN, Texas — ERCOT’s Technical Advisory Committee passed three nodal protocol revision requests (NPRRs) Thursday to improve the ISO’s reliability-must-run procedures following its decision earlier this summer to extend an RMR contract for an aging natural-gas unit in the Houston area.
The three revisions, previously endorsed by the Protocol Revision Subcommittee, would modify the Texas grid operator’s RMR planning studies, create a clawback mechanism for ERCOT-funded capital expenditures and clarify the reliability unit commitment process. The Board of Directors is scheduled to consider all three revision requests at its Oct. 11 meeting. The NPRRs were classified as urgent requests following this summer’s extension of an RMR contract through 2018 for NRG Texas’ Greens Bayou Unit 5. (See ERCOT Finds No Alternatives to Greens Bayou; RMR Rule Changes Advance.)
The TAC approved NPRR788, which modifies the system’s RMR planning studies, after accepting revisions from the Independent Market Monitor. The revision request will require that future studies include forecasted peak loads, and it says a potential RMR unit must have “a meaningful impact on the expected transmission overload” to be considered for an agreement.
“ERCOT filed comments [after the subcommittee vote] that I feel effectively rebutted the comments made by [stakeholders] that they were concerned ERCOT was not being compliant with NERC standards,” said Beth Garza, the IMM’s director.
The Monitor’s revisions would allow ERCOT, “in its sole discretion,” to deviate from the planning criteria “in order to maintain … reliability. However, ERCOT shall present its reasons for deviating from the above criteria at the next regularly scheduled [TAC] and [board] meetings.”
Transmission Providers Opposed
The measure was opposed by transmission providers American Electric Power, CenterPoint Energy, Sharyland Utilities and Luminant, Texas’ largest generating company.
Valentine Emesih, CenterPoint’s vice president of grid and market operations, said the ISO’s approach could create problems in a year or two. “If you force me to operate the line at 110% of [rated capacity], you’re essentially using a policy that forces you to use load shed to upgrade the system,” he said. “The real solution to mitigate the issue is to build appropriate infrastructure to inoculate yourself from that situation, and that’s where the planning comes in.”
ERCOT staff assured stakeholders there were no plans to shed load and there were no reliability issues.
“It’s more about what is the risk this market is comfortable with when deciding whether or not to get an RMR unit,” said Jeff Billo, senior transmission planning manager. “We are going to plan transmission projects to address those issues.”
The transmission providers also lost a bid to revise the planning criteria’s threshold for overloaded transmission facilities to 100% of the emergency rating under normal system conditions following a contingency loss of a generating unit, transmission unit or other facilities. The threshold will instead remain at 110%.
Stakeholders unanimously approved NPRR795, which creates a mechanism to refund capital expenditures funded by ERCOT under an RMR agreement, but not before adding amended language from Texas Industrial Energy Consumers and the ISO.
Attorney Katie Coleman, representing industrial customers, said she wanted to “tighten the parameters around the depreciation assumptions” and compensate customers for the value of accelerated tax depreciation, “which can provide a significant tax write-off for a resource owner.”
Coleman proposed requiring 10% of this value to be repaid along with the capital expenditure before a resource re-enters the market.
“This approach compensates loads for funding a tax write-off for the resource entity in excess of what straight-line depreciation would provide during the RMR contract period,” Coleman said, “but then transfers the value of any accelerated depreciation back to the asset owner after the asset is returned to service.”
ERCOT added language that would only require a signed attestation from a company’s officer or executive, rather than having the ISO audit tax forms.
The TAC also quickly passed the final revision request, NPRR793, by a unanimous vote. It adds several responsibilities for RMR unit owners, revises RMR formulas and makes other clarifications to ensure RMR units are not accidentally committed as a reliability unit before other resources.
Two Transmission Projects Sent to Board
ERCOT stakeholders endorsed staff recommendations for a pair of West Texas reliability projects that address the region’s Permian Basin oilfield load growth without opposition. Reliant Energy Retail Services abstained from both votes.
The first project, estimated at $50.6 million and belonging to Texas-New Mexico Power, will rebuild 39 miles of 69-kV line and three substations to 138-kV standards, and add a new 138-kV ring substation and 6 miles of 138-kV line.
According to ERCOT’s analysis, that portion of the TNMP system will see coincident peak loads of 254 MW by 2022, resulting in reliability violations. The project, expected to go into service in the fall of 2019, would reduce loading on other transmission lines in the utility’s system.
AEP and Oncor proposed the second project, a 138-kV line between Barrilla Junction and the Permian Basin. The 54-mile line’s load is expected to grow from 95 MW to 150 MW by 2020.
Staff recommended a rebuild of the existing line and installing a new 100/-50-MVAR static VAR compensator at an estimated cost of $77 million. The project will not require new rights of way, which will help keep the costs down. It is expected to go into service in June 2019.
Committee Deactivates 4 Groups
The TAC’s annual structural review resulted in the deactivation of four stakeholder groups, agreements to improve the revision-request process and the incorporation of additional binding documents into ERCOT’s protocols and guides.
The committee’s leadership agreed to move the Competitive Renewable Energy Zone Task Force, the Future Ancillary Services Team, the Scenario Development Working Group and the Long-Term Study Task Force to ERCOT’s inactive groups list.
Stakeholders agreed NPRRs and any accompanying guide revisions will now both require board approval, eliminating the discrepancy in the timing of the approval process. NPRRs have normally been approved at the board level, but guide changes are only endorsed by the TAC.
The committee also agreed to incorporate some of ERCOT’s 49 other binding documents — 24 of which have not required frequent changes — into the appropriate guides or protocols, either as new language within existing sections or as appendices.
Additional TAC Endorsements
TAC unanimously approved five NPRRs and one revision to the nodal operating guide (NOGRR) after first agreeing on several refinements to ERCOT’s approval process following the committee’s annual structural review.
NPRR755: Allows an entity to register as a data-agent-only qualified scheduling entity (QSE) to connect to ERCOT’s wide area network (WAN) as an agent for another QSE without meeting applicable collateral and capitalization requirements.
NPRR769: Clarifies the alternative-dispute resolution process to note the proceeding is the next level of appeal following ERCOT’s denial of verifiable costs. Also clarifies the confidentiality of data submitted in connection with a verifiable-cost appeal.
NPRR775: Strengthens the limits on fast responding regulation service (FRRS) to address future operational issues. A previous revision (NPRR581) added limits of 65 MW to FRRS up and 35 MW to FRRS down, but it lacked implementation details regarding self-arrangements in the day-ahead market and restrictions on providing the service in real time without a day-ahead award.
NPRR781: Addresses the market’s growing use of advanced metering systems (AMS) by updating protocol language to clarify purpose and definitions, update processes and methodologies and remove outdated ones.
NPRR789: Requires ERCOT to publish all of its mid-term load forecasts for market participants and note which one is currently being used by operations. The ISO currently publishes several forecasts per weather zone, but it only makes one at a time available to the market.
NOGRR154: Clarifies the WAN’s installation requirements, allows a QSE to designate an agent in order to connect to the WAN and requires ERCOT and its market participants to use the network to exchange resource-specific XML data.
CARMEL, Ind. — MISO began working with stakeholders to refine its behind-the-meter generation procedures last week with a special meeting at which it dropped hints on changes it might seek.
“We have a few ideas, but we want to hear from you,” System Support Resource Planning Manager Neil Shah said in opening the meeting.
“We do realize that [behind-the-meter generation] does span across several MISO processes,” MISO Director of Market Engineering Kim Sperry told stakeholders. “Our goal is to work with you on what the next steps should be.”
MISO staff said BTM generation could be incorporated into transmission planning, modeling and retirement notifications and questioned whether interconnection requirements need updating.
The RTO currently defines BTM generation as load-serving resources located behind a commercial pricing node.
Shah said some — but not all — BTM generation load data is captured when load-serving entities or transmission owners submit load information for planning models.
MISO’s Transmission Expansion Plan (MTEP) studies model generators with interconnection agreements, designated legacy network resources of MISO member utilities and all generators with long-term firm point-to-point service.
Eric Swanson, MISO modeling adviser, said all BTM generators greater than 5 MW and directly connected to MISO transmission are modeled. He said the effort to model all BTM generation could “exceed the benefit.” Swanson said if BTM generation is modeled, it would need to be registered as either a Type II demand response resource (DRR) or under a pricing node of a load zone or a DRR Type I.
Director of Planning Jeff Webb asked if BTM generation should be subjected to retirement studies. Webb said the RTO has about 6,000 MW of BTM generation and said it would be a problem only if it all retired simultaneously. “Perhaps we ought to treat it like a load addition,” he said of the retirement study process. “If generation can go off-grid and we don’t look at the impacts, is that okay?”
MISO also wants to know if changes are needed in how it registers BTM generation.
Currently, if BTM generation wishes to register as a load-modifying resource, it must submit to an annual generator test and registration and get assigned to a commercial pricing node. It must be able to respond in emergencies with a minimum 12-hour notice, be available five times during the summer and run for at least four hours. It also must submit its status daily to MISO.
Shah said if BTM generation wants to become a capacity resource, it needs an energy resource interconnection service (ERIS) or network resource interconnection service (NRIS) with firm transmission service. If the resource isn’t already connected to the MISO transmission system, it must enter the interconnection queue to obtain NRIS.
Indianapolis Power and Light’s Lin Franks said requiring BTM generation to enter the interconnection queue does not make sense when the generation will only serve nearby load. “If it’s going to serve load in your own territory, then there is absolutely no need for it to qualify for transmission service because it’s not going anywhere,” Franks said.
“Things might be unclear in the Tariff right now,” Shah told stakeholders. “In this meeting and meetings going forward, we’d like to clarify what’s required to make changes to the Business Practice Manuals if necessary. We want to work with you all to be if there needs to be any change.”
Justin Stewart of MISO’s stakeholder relations unit asked for stakeholder feedback on how definitions and requirements should evolve. He said responses would influence a yet-unannounced follow-up meeting.
Maxim Power will pay $8 million to settle a FERC complaint that it manipulated the New England power market in a fuel-switching scheme (IN15-4).
FERC alleged that in July and August 2010, the Canadian company submitted offers for its 181-MW dual-fuel generating station in Pittsfield, Mass., based on fuel oil prices when it actually burned less expensive natural gas. The plant provides voltage support to the ISO-NE market.
Pittsfield Plant Source: Maxim Power
Under the consent agreement approved last week with FERC’s Office of Enforcement, Maxim agreed to pay a $4 million fine and disgorge another $4 million in earnings to ISO-NE but did not admit guilt.
FERC issued Maxim a $5 million fine in May 2015 and sued the company in U.S. District Court two months later to collect the money. On July 21, 2016, the court rejected Maxim’s motion to dismiss the case.
The settlement also closes FERC investigations into allegations that the company gamed ISO-NE market mitigation rules in 2012 and 2013 and that it improperly boosted its generators’ outputs during testing in order to collect inflated capacity payments from 2010 to 2013. (See Maxim to FERC: Prosecute or Drop Probe.)
FERC Chairman Norman Bay, the former head of the Office of Enforcement, did not participate in the decision approving the settlement.
News that PennEast Pipeline has 33 new changes to the proposed route of the 119-mile pipeline is spurring environmental groups to call for FERC to conduct a new environmental review of the plan.
Operators at the Pilgrim Nuclear Power Station allegedly filed two false reports relating to a hydrogen leak, but the Nuclear Regulatory Commission said their regulations don’t cover hydrogen leaks, and therefore plant owner Entergy has nothing to worry about from the commission.
Industrial energy efficiency could cut carbon emissions by 175 million tons nationwide in 2030, according to new research by the Alliance for Industrial Efficiency.
