WESTBOROUGH, Mass. — Stakeholders have until Feb. 25 to comment in ISO-NE’s first implementation of the public policy requirements of FERC Order 1000.
The RTO is seeking stakeholder comments on federal, state and local statutes and regulations that could require new transmission.
| Avangrid
It is the first of an eight-step process outlined to the Planning Advisory Committee on Wednesday that could result in a transmission study and a competitive procurement. Comments should be emailed to PublicPolicy@iso-ne.com.
The New England States Committee on Electricity (NESCOE) has until April 1 to identify federal and state policy requirements. The RTO also can identify such requirements, along with local (municipal and county) requirements. Stakeholders’ responses to NESCOE will be due 15 days afterward.
If transmission needs are identified as a result of the process, the RTO will provide a draft scope for a public policy transmission study.
Current rules call for ISO-NE to provide a draft scope for the study by June 1, although it is seeking a Tariff change to push the date back to Sept. 1.
If the RTO decides to seek a transmission upgrade, it will invite qualified transmission project sponsors to submit proposals. After evaluating the proposals and PAC input, the RTO will narrow the “stage one” proposals to finalists eligible to submit more detailed “stage two” proposals, one of which will be selected as the preferred solution.
ISO-NE will monitor milestones until the project is completed and in service.
EPA’s Clean Power Plan, which was expected to result in transmission to connect renewable generation with load, is in jeopardy under the Trump administration. But New England states are expected to continue their efforts to decarbonize through power purchase agreements and potentially tighter emission caps under the Regional Greenhouse Gas Initiative — initiatives that could require transmission investments. (See New England to Charge Ahead on Clean Energy Makeover in 2017.)
FERC last week found that MISO and PJM have largely complied with commission directives issued in an order resolving a complaint by Northern Indiana Public Service Co. over interregional planning (EL13-88-001, et al.).
But the RTOs still face additional compliance filings to demonstrate better alignment of studies and cost allocation.
FERC last week accepted most of the joint operating agreement changes filed by the two RTOs and denied multiple requests for rehearing, including those from MISO and PJM themselves, as well as MISO transmission customers and NIPSCO.
At last week’s MISO-PJM Interregional Planning Stakeholder Advisory Committee meeting, transmission engineer Adam Solomon said the RTOs will conduct a legal review of the order and publicly post a summary and work plan next week.
Despite protests, FERC stood firm on its directive to scrap the previous triple benefit-to-cost ratio test, where projects had to meet a joint 1.25:1 ratio as well as the same calculation within each RTO.
The RTOs must now rely on a net value of the total benefits calculated for each RTO and are responsible for determining “whether the potential interregional economic transmission project meets its individual 1.25-to-1 benefit-to-cost threshold using each RTO’s share of the project’s total cost.”
Cost allocation is now based on each RTO’s pro rata share of the project’s total benefits. The commission rejected arguments by the RTOs and MISO transmission customers that an additional interregional benefit-to-cost analysis provides a “common” benefit metric to compare projects.
“Requiring MISO and PJM to each rely on their regional analysis to calculate both the benefits and costs of a potential interregional economic transmission project creates a more direct link between the costs allocated to each RTO and the benefits received,” FERC wrote.
FERC also found that a request by the RTOs to continue allocating costs of interregional transmission projects based on a joint economic benefit calculation still contained in the JOA would “create an untenable mismatch in the process for selecting an interregional economic transmission project and the process for allocating the costs of that project.”
MISO and PJM cannot “employ an additional interregional benefit-to-cost analysis that is calculated differently than either of their individual, regional benefit-to-cost analyses,” the commission said.
FERC upheld an earlier decision to replace MISO’s requirements that a qualifying project be at least 345 kV and meet a $5 million cost threshold with a 100-kV voltage minimum and no specified cost floor.
However, as pointed out by the Organization of MISO States, the commission realized it did not address MISO’s lack of Tariff language on cost allocation for sub-345 kV projects. Market efficiency projects in MISO are currently allocated 20% to all transmission customers and 80% to transmission customers in local resource zones. FERC gave the RTO 30 days to either include sub-345-kV interregional projects into the existing cost allocation or create a different allocation method.
Solomon said the order invalidates the need to create a joint model because FERC has accepted MISO and PJM filings that removed any references to such a model.
FERC last April directed the RTOs to explore the possibility of a joint model that uses identical assumptions and criteria to align their respective regional processes. In December, MISO staff said a joint model using identical assumptions would be difficult to accomplish. (See “MISO Says Common Assumption Set with PJM a No-Go,” MISO Planning Subcommittee Briefs.)
MISO will instead use regional metrics to independently quantify benefits and split project costs.
“It’s pretty clear what we need to do going forward,” Solomon said.
Not Applicable to MISO-SPP Seam
MISO members hoping that the NIPSCO order would be applied to the SPP seam will have to wait for a fresh docket. FERC said its NIPSCO directives “are limited to issues pertaining to the MISO-PJM seam.” The commission rejected ITC Holdings’ request that MISO also relax SPP interregional cost and voltage thresholds — still at $5 million and 345 kV — saying ITC brought no evidence forward to support the rule extension.
FERC accepted new JOA language that describes interconnection coordination procedures already in place in the RTOs’ governing documents, language stipulating that each RTO will monitor the other’s transmission system for potential impacts and include concerns in the system impact studies of the interconnection process. The RTOs will also exchange data at least twice each year to study the impact of the other’s interconnection requests on its own transmission system.
Coordinated System Plan Needs Work
However, FERC found MISO and PJM only “partially” complied with the commission’s directive to revise the JOA to describe how the RTOs will incorporate their respective transmission expansion planning processes into future coordinated system plan studies.
The commission directed the RTOs to submit another compliance filing detailing how the plans would be integrated and create “binding deadlines” for an annual review of issues and when to decide on whether they should embark on the studies. MISO and PJM had proposed an information exchange in the fourth quarter of each year that would lead to a joint review of regional issues the following January, but they did not provide specific deadlines.
FERC denied NIPSCO’s request that market-to-market payments be added to the JOA benefit calculation. The commission said the addition would double-count a portion of the congestion — an issue still under scrutiny in a separate complaint. (See PJM, MISO Go Quiet on Pseudo-Ties; Reach Interface Pricing Accord.) FERC also said market-to-market payments do not reduce production costs but are transfer payments between RTOs “that make the RTO that redispatched its system whole for the increased production costs that it experiences to allow the other RTO to exceed its firm flow entitlements.”
FERC also denied a request by a group of MISO generators that the RTOs better identify constraints and flowgates, saying it was not an issue raised in the original NIPSCO complaint since the complaint “made only incidental references to flowgates.”
Retirement Coordination Approved
In a separate order issued last week, FERC unconditionally accepted the MISO-PJM generator retirement coordination plan (ER16-1969-002) with little comment. The plan adds generator retirement study information-sharing and mutual evaluation rules to the RTOs’ JOA. (See MISO Outlines Retirement Coordination with PJM.)
2017 MEP Identification Underway
Ling Hua, MISO’s interregional economic transmission planning adviser, said MISO and PJM have begun work to identify interregional market efficiency projects. Both RTOs have opened issues submission windows that allow members to submit solution proposals until the end of February. From March to September, the RTOs will evaluate project proposals for year-end approval by their respective boards.
| MISO
The two RTOs have separately identified congested flowgates ripe for interregional efficiency projects, with MISO submitting 13 possible projects and PJM identifying four. The only potential project common to both lists is the Olive-Bosserman 138-kV project on the western Michigan-Indiana border in American Electric Power’s territory.
Solomon said he expects a learning curve this year in identifying interregional projects as RTO staff and stakeholders move to a new interregional process.
“We’ve kind of been stuck in between two interregional processes until yesterday,” Solomon said at the IPSAC meeting.
A day before the order issuance, at its Jan. 18 Planning Advisory Committee meeting, MISO reported that it considered all nine directives in the NIPSCO order completed as of Dec. 15.
FERC last week ordered American Electric Power and FirstEnergy subsidiary Allegheny Power to refund more than $7 million to ratepayers for the canceled Potomac-Appalachian Transmission Highline (PATH) project (ER09-1256; ER12-2708).
The ruling upheld most of the $10 million in refunds recommended in an initial ruling by Administrative Law Judge Philip C. Baten, backing the judge’s decision to deny recovery of $6.2 million in advertising, lobbying and “advocacy-building” costs. But the commission reversed Baten on his rejection of some legal costs and losses on the sale of properties the companies acquired for the project. (See FERC ALJ Rejects $10 Million in PATH Transmission Project Recovery.)
The commission also found that PATH’s base return on equity should be reduced from 10.4% to 8.11% and disallowed recovery of $1.1 million in expenses booked into a wrong account.
The companies have 60 days to submit revised information, including an updated Form 1 that recalculates costs of service and estimated refunds.
Approved in PJM’s 2007 Regional Transmission Expansion Plan, the $2.1 billion project would have run from AEP’s John Amos coal generator in St. Albans, W.Va., to New Market in Frederick County, Md. PJM canceled the project in 2012 after determining it was not needed based on revised load forecasts.
The ruling was a victory for two PATH opponents from West Virginia who filed a pro se intervention challenging the companies’ recovery request for recovery of $121.5 million.
FERC Orders Investigation into Overcharging for Natural Gas Pipelines
The commission is investigating the rates charged by two natural gas pipelines, one of which delivers into the PJM footprint in Chicago (RP17-302 and RP17-303).
FERC believes Wyoming Interstate Co. and Natural Gas Pipeline Company of America, both Kinder Morgan subsidiaries, may have both been overcharging customers, based on reviews of their 2014 and 2015 FERC Form No. 2 annual reports.
FERC estimates Natural’s ROE for those calendar years to be 28.5% and 20.8%, respectively. Natural owns the Amarillo and Gulf Coast Lines, both of which terminate in the Chicago area.
The commission estimates WIC’s ROE for those calendar years to be 17.7% and 19%, respectively. WIC owns 850 miles of pipeline, including a mainline system between western Wyoming and northeast Colorado.
FERC says it’s concerned that both Natural’s and WIC’s level of earnings may exceed their actual cost of service, including a reasonable ROE. The commission ordered the companies to file full cost and revenue studies within 75 days.
ODEC Tariff Revisions Approved Subject to Compliance Filing
FERC last week approved a revised cost-of-service rate schedule that changes how Old Dominion Electric Cooperative collects demand costs from its 11 distribution cooperatives in Virginia, Delaware and Maryland.
The new formula replaces one that has been in place since 1992 that recovered demand costs based on each cooperative’s coincident peak (CP) usage. The new formula includes rates that ODEC said more accurately reflect market conditions and its costs under PJM’s methodology.
The commission affirmed the initial decision by ALJ H. Peter Young that found several portions of ODEC’s filing, including its four-year average “proxy rate” for PJM capacity costs and the 12 CP true-up mechanism for PJM capacity costs and third-party transmission costs, unjust and unreasonable.
It reversed the judge’s finding that ODEC’s proposed zonal averaging mechanism and the use of add-backs in 2014 were unjust and unreasonable.
The revisions were backdated to Jan. 1, 2014, and ODEC is required to make refunds and file a refund report (ER13-2483).
FERC Approves FE Companies’ Filings on Affiliate PPA Waiver
The commission last week approved tariff revisions filed by FirstEnergy Solutions and several affiliates to comply with a FERC order ruling that a power purchase agreement in which the company’s regulated utilities would buy energy from the company’s merchant generators would be subject to its affiliate abuse review (ER16-1807, et al.). FirstEnergy asked the Public Utilities Commission of Ohio to withdraw the PPA following the FERC ruling. (See FirstEnergy Foes Ask FERC to Step in Again in Ohio Dispute.)
In 1879, Thomas Edison patented the incandescent light bulb. For more than a century, the incandescent bulb and its upscale offspring, the halogen bulb, have reigned supreme.
Huntoon
The reign is ending. Light-emitting diode (LED) lighting is replacing Edison lighting.
Here’s a question: How much more impact is rooftop solar having on retail electric sales than LED lighting?
It’s a trick question. Rooftop solar has had less impact on retail electric sales. LED lighting already has reduced annual retail electric sales by 30 billion kWh. Rooftop solar has reduced annual retail electric sales by 14 billion kWh.
But it’s the future that’s really interesting. The U.S. Energy Information Administration’s latest study forecasts LED lighting over the next 20 years to reduce annual retail electric sales by 300 billion kWh under a “current path” and by 435 billion kWh under a more aggressive path.[1] Rooftop solar over the next 20 years is expected to reach 100 billion kWh annually.
Let’s think about that. For all the attention given rooftop solar as environmental boon, new age investment and regulatory flashpoint, the LED bulb is three times more significant.
And three times more significant for electric utilities. Lighting represents 15% of retail electric sales. Over the next 20 years, half of those lighting sales will disappear, perhaps three quarters under a more aggressive path. Those electric vehicles better show up soon.
And what if Haitz’s Law — the LED parallel to Moore’s Law — continues, such that the cost per lumen keeps falling by a factor of 10 every 10 years? The LED is just another form of semiconductor. The substitution could be even more rapid.
Even at today’s cost per lumen, Edison lighting is much more expensive on a life-cycle basis than LED lighting. Much, much more expensive.
A General Electric soft white 60-W Edison bulb can be had in quantity purchase for $1.30, and rated to last for 1.4 years based on an average use of three hours per day. A GE soft white 60-W equivalent LED bulb can be had in quantity purchase for $3, use 10 W and last for 13 years based on the same average. So over 13 years, Edison lighting would cost an extra $9 for the bulbs and an extra $78 for the electricity (at 11 cents/kWh).[2]
Bottom line: Rooftop solar may be all the rage, but just changing light bulbs makes a bigger dent in emissions from combusting fossil fuels. And saves money to boot. Doing good and doing well.
Watt’s in your socket?
Steve Huntoon is a former president of the Energy Bar Association, with more than 30 years of experience advising and representing energy companies and institutions. He received a B.A. in economics and a J.D. from the University of Virginia. He is the principal of Energy Counsel LLP.
[1] You won’t find these forecasts in EIA’s “Annual Energy Outlook 2016,” which forecasts a lighting consumption decline of only 28% from 2015 to 2040 (Figure IF3-3). Instead the forecasts are derived from EIA’s specialty study “Energy Savings Forecast of Solid-State Lighting in General Illumination Applications” (September 2016) and require interpolating from Tables 4.2 and Figure 4.2, and converting from British thermal units to kilowatt-hours and from source to sink.
[2] Edison lighting also costs more for the incremental air conditioning in the summer to combat the heat from the bulb. (Generally, this extra cost is more than the incremental heating savings in the winter.)
CARMEL, Ind. — MISO will conduct three new separate, but related, studies this year that could identify a transmission solution for the RTO’s constrained interface between its North and South regions.
The efforts include a market congestion planning study, which is part of MISO’s 2017 Transmission Expansion Plan (MTEP 17), as well as a footprint diversity study and regional transmission overlay study.
Any of the reports could produce a replacement for, or supplement to, the seven-year transmission use settlement between MISO and SPP that limits flows between MISO North and South.
While the trio of studies share modeling and assumptions, each has a different scope, Arash Ghodsian, MISO manager of economic studies, said at a Jan. 18 Planning Advisory Committee meeting. He added that he didn’t know which study might produce a feasible project.
MISO’s Eric Thoms said the congestion and footprint studies would identify project candidates in the third quarter. However, the lengthier regional transmission overlay study, which is expected to determine long-term transmission needs at the end of this year, will not identify prospective projects until the study is concluded in 2019.
The footprint study is the only effort specifically designed to “identify potential mitigation plans to increase the interface capability” between MISO North and South, Ghodsian said. That study will be completed at the end of this year in concert with the MTEP 17 market congestion planning study, which will focus on MISO South.
Project candidates emerging from the congestion planning study will be selected at the September PAC meeting, Ghodsian said. “If we have a good enough solution for transmission needs, we’ll stand by it,” regardless of what study produces it, he said.
None of the studies would result in a revised settlement with another RTO, he noted.
MTEP 19 Will Probe Demand Response, Efficiency Programs
MISO is already putting together pieces for MTEP 19 in the form of a demand response and energy efficiency study.
The RTO said the third-party study is a “refresh” of a similar 2014-15 report and will provide a 20-year forecast for DR, energy efficiency and distributed generation and “their associated costs to install in MISO and the Eastern Interconnection.” Work on the study should run through December, and the RTO said it will conduct quarterly stakeholder workshops related to the subject, with the first scheduled for Feb. 24.
Applied Energy Group, the consulting firm responsible for the 2014-15 study, has been retained to perform the analysis.
Rao Konidena, MISO adviser of energy efficiency, said the RTO recognizes that energy efficiency and DR programs are administered by states and will respect state jurisdiction by simply collecting data on savings from programs while refraining from analyzing any specific program.
MISO has admitted that there is a “gap” the DR and energy efficiency data it requires of load-serving entities and what gets reported, leading to a modeling disadvantage.
MISO will file with FERC to remove transmission service request (TSR) redispatch study options from its Tariff, citing market-based dispatch as the more efficient option.
A TSR reserves transmission capacity in the market and the redispatch option is added if a transmission customer has also purchased redispatch service. The transmission provider attempts to relieve system constraints by redispatching its resources, and the option requires MISO to identify which nearby generators — even ones external to MISO — can be redispatched to mitigate transmission constraints.
According to MISO’s Tariff, a TSR with a redispatch option is not eligible for financial transmission rights or auction revenue rights, unlike regular TSRs, making the option unappealing.
Paul Muncy, of MISO’s transmission access planning division, said market-based dispatch would take the place of TSR redispatches. Although TSR dispatches are still offered, MISO currently has no confirmed TSRs that use a redispatch option, and the study option should have been eliminated long ago, he added.
According to MISO, the current TSR redispatch option is burdensome, requiring customers to sign a contractual financial agreement with generation owners in order to use a subset of units and agree on an operating procedures guide between generation owners, impacted transmission operators and MISO.
The RTO said that when it dispatches around congestion, implementing the TSR-related operating guides “would take away from normal market-driven dispatch implementation and reduce market transparency, adding burden to [the] market system and settlement system.”
“It’s not only cumbersome, but it detracts from market efficiency,” Muncy said.
Some stakeholders have wondered if there is any harm in just retaining the language in the Tariff, but MISO compliance staff responded that keeping dead language in the Tariff is not a zero-cost option because the RTO must work to update the procedures in place behind the language.
Improvements Sought for Competitive Transmission Process
MISO will convene a Competitive Transmission Task Team to improve its competitive transmission selection process, aiming to complete a FERC filing on the matter sometime after October.
Brian Pedersen, MISO senior manager of competitive transmission administration, asked for stakeholder feedback on every aspect of the competitive process — from qualification to MISO’s communication — to begin the effort.
“We want to pop our heads up and ask how well we’ve done,” he said.
Stakeholders should also think about how to streamline the process in cases where MISO is dealing with multiple competitive transmission projects at the same time, Pedersen said.
“This is definitely a substantial undertaking,” he said. “We need to think about how to stagger that, scale it.”
MISO also reflected on the breadth of proposed projects stemming from its first request for proposals. The RTO said the process resulted in a “variety of innovative and novel cost caps, concessions and commitments … taking advantage of the freedom to develop new ways to compete on cost” and the annual transmission revenue requirement within the developer selection process.
Pedersen said an “extraordinary amount” of resources and innovation went into project proposals.
“It definitely was an instruction in innovative thinking and competitive spirit,” Pedersen said.
The RTO is moving ahead on voluntary meetings with developers that were not chosen.
MISO has also opened its 2017 prequalification window for organizations seeking to become a qualified transmission developer. Interested parties must be a MISO member and submit a transmission developer application — along with a $20,000 application fee — before Feb. 6.
In December, LS Power subsidiary Republic Transmission was awarded the Duff-Coleman 345-kV transmission project, the RTO’s first competitive project under FERC Order 1000. The company will construct two substations and a 28.5-mile line in Southern Indiana and Western Kentucky. Republic will deliver quarterly updates to MISO throughout 2017 on the progress of the $49.8 million project. (See LS Power Unit Wins MISO’s First Competitive Project.)
Minimum Design Requirements Task Team Retired
MISO has retired the Minimum Design Requirements Task Team upon conclusion of the group’s work, PAC Chair Cynthia Crane said.
A first version of Business Practices Manual 029, which governs minimum design requirements for competitive projects, was implemented last January. A second version of the manual, detailing a set of ratings that transmission projects will be required to meet, is slated to be released this spring.
Crane said future improvements to BPM 029 will be funneled through the upcoming Competitive Transmission Task Team.
DALLAS — SPP stakeholders last week spent the remains of a meeting cut short by weather-related travel problems discussing staff and member solutions to the RTO’s Z2 crediting process.
In the end, the Z2 Task Force came no closer to a solution to the albatross and decided to schedule monthly meetings in an effort to reach an April deadline for recommending improvements.
The task force was established last August and had hoped to present its findings to the Board of Directors and Markets and Operations Policy Committee in January or April of this year.
“We knew six months was aggressive,” said Bruce Rew, SPP’s vice president of operations and the group’s staff secretary.
Stakeholders drilled down into two of the six options first presented by SPP staff in November: “reverse engineering” of the Z2 process and using incremental long-term congestion rights (ILTCRs). (See Z2 Task Force Looks at Incremental Congestion Rights.)
The task force also reviewed a proposal from Westar Energy that suggested modifying SPP’s generator interconnection process and transmission service requests and incorporating financial hedging instruments. Westar also proposed revising the Tariff so that any proposed sponsored projects would be studied for inclusion in the planning process and possible selection for Tariff funding.
That suggestion did not seem to gain much traction with stakeholders.
Grant pointed out that Westar’s plan would result in a separate process to secure annual revenue rights or transmission congestion rights. “I want to get back to being simple and not doing anything more than we need to do, because that’s what got us into trouble,” he said.
Under the SPP Tariff’s Attachment Z2, staff is responsible for assigning members financial credits and obligations for sponsored upgrades. However, staff had not applied the credits for years dating back to 2008, complicating the task of trying to accurately compensate project sponsors and claw back money from members who owed debts for the upgrades.
Kansas City Power & Light’s Denise Buffington, who chairs the task force, noted that each discussion on Z2 unearths new information previously unknown to the group.
“We’re still trying to figure out what the universe looks like, and how to rate it,” she said last week.
Staff’s reverse-engineering proposal would remove short-term TCRs (less than one year) from the crediting process, although short-term revenues have declined substantially since the start of SPP’s Integrated Marketplace. A second proposal over the long term would implement a standard credit payment rate for all creditable impacts, including both network and point-to-point reservations, should the Z2 process be terminated.
SPP also suggested using its current ILTCR process as a cost-recovery mechanism for upgrades with directly assigned upgrade costs (DAUC). To be eligible for the ILTCRs and megawatt capacities, upgrades would have to be sponsored with DAUC, create additional available transfer capability on a specific path and be the outcome of a study request.
“With Z2 credits, there’s no question whether or not they’re given,” said NextEra Energy Resources’ Aundrea Williams. “With ILTCRs, there’s no certainty they’ll be awarded. Z2 is the byproduct of a formula. There’s still a possibility of not getting them as part of the auction. You would have to look at the overall pool of who gets what and what’s eligible for a” generator interconnection.
Oklahoma Gas and Electric’s Greg McAuley suggested another option: not completely disregarding the “do-nothing option.”
“I don’t like Z2 either, but if there’s enough confusion with these [proposals], I still think there’s a problem,” he said. “It’s like the devil you know. We know this devil, and until we’re sure that we have a viable option that isn’t just as complex, or more so, we shouldn’t dismiss the do-nothing option out of hand.”
FERC last week rejected Vote Solar’s request that the commission reconsider its decision not to enforce the Public Utility Regulatory Policies Act against Montana regulators (EL16-117-001).
Vote Solar petitioned FERC in early December after the dismissal of its first complaint, which alleged that the Montana Public Service Commission violated the federal law when it allowed NorthWestern Energy to suspend its tariff for solar qualifying facilities pending an updated rate review. (See FERC Rejects Complaint on Montana Solar; 2nd Case Pending.)
FLS Solar’s Fairmont Solar Farm in Fairmont, NC | FLS Solar
The Montana PSC issued the suspension last June after the utility argued that QF rates for solar producers were 35% above avoided costs and that the 130 MW of planned solar projects in the utility’s service area would place an undue burden on ratepayers.
The solar advocacy nonprofit said that NorthWestern was seeking to “undermine” PURPA and renewable generation.
The commission reiterated that it cannot direct the Montana PSC to take any action because state regulators are not FERC-jurisdictional public utilities subject to the Federal Power Act. The commission also said Vote Solar did not have standing to petition for enforcement because it was neither an electric utility nor a QF.
The commission rejected Vote Solar’s contentions that FERC has the authority to issue a declaratory order against the Montana PSC through the Administrative Procedure Act and that the commission can bring an enforcement action pursuant to Section 210 of PURPA based on the nonprofit’s complaint.
By granting Vote Solar’s request, the commission said it would be acting ultra vires — beyond its authority.
Furthermore, the commission maintained that its choice not to act against the PSC is backed by the Supreme Court, which “has established the general rule that an agency’s decision not to exercise its enforcement authority, or to exercise it in a particular way, is committed to its absolute discretion” under circumstances when their enforcement is not legally mandated.
“Because there is no legal requirement here to commence an enforcement action, there is thus no decision subject to legal error,” the commission said. “Although Rule 206 of our Rules of Practice and Procedure permits ‘any person’ to file a complaint with the commission, our regulations cannot grant us more authority than the statute grants us.”
Vote Solar said that FERC’s original dismissal created a “framework wherein the commission can only take action against a state regulatory authority when asked to do so by a regulated party … [and] leaves the public without a path to seek relief from the commission when state regulatory authorities fail to implement PURPA properly and places the burden on electric utilities, qualifying cogenerators and qualifying small power producers as the only entities that can seek enforcement action.”
The commission countered that Vote Solar is already an intervenor in a similar, separate complaint against the Montana PSC by North Carolina-based solar developer FLS Energy (EL17-5).
“Our dismissal of Vote Solar’s complaint here did not foreclose Vote Solar’s public participation in our proceedings,” FERC said.
DALLAS — SPP’s Mike Ross told the Strategic Planning Committee last week the industry can expect a future with less federal intervention under President Trump’s administration.
Ross, SPP’s senior vice president of government affairs and public relations, and a former six-term Democratic congressman from Arkansas, said he expects Trump to quickly issue an executive order withdrawing from the Paris Agreement on climate change.
“I believe the Clean Power Plan will be rolled back through whatever kind of legal thing they need, from executive order to rescinding the rule to simply not funding the [EPA]. Overall, I think you’ll see less regulation,” Ross said. “Everything in our industry will be regulated a lot less and pushed back to the states.”
Ross said he expects Trump’s opposition to the CPP to result in the delay of some coal plant retirements but not in new generator construction. “Quite frankly, I don’t think many companies are going to be spending millions of dollars to build a new power plant based on who the new president is,” he said.
He said he expects Congress to pursue legislation on cybersecurity and to review the Federal Power Act and RTO capacity markets. He also said there is some talk of FERC revisiting Order 1000.
Bloomberg reported last week that Trump will tap Commissioner Cheryl LaFleur as chairman of the commission, replacing Norman Bay.
FERC currently has three Democrats and two vacancies, but it will shift to a 3-2 Republican majority under Trump, so LaFleur’s appointment could be temporary.
Although Ross didn’t name names, he said potential appointees include those “who knew SPP very well and have been involved with SPP.”
“She’s pro-coal,” he said of Honorable, who previously chaired Arkansas’ Public Service Commission. “The last coal plant in America [AEP subsidiary Southwestern Electric Power Co.’s John W. Turk Jr.] was built in Arkansas, and she voted for it.”
Audrey Zibelman, chair of the New York Public Service Commission since 2013, is headed to Australia to lead the operator of that country’s largest gas and electricity markets.
In a press release late Sunday — Monday morning in Australia — the Australian Energy Market Operator said Zibelman will become its CEO on March 20. Zibelman’s last meeting heading the NYPSC is scheduled to be on March 16 in New York City.
Then living in the Philadelphia area, Zibelman was appointed by Gov. Andrew Cuomo as PSC chair in 2013. She was tasked with shepherding the state’s Reforming the Energy Vision initiative, which was unveiled in 2014.
Prior to joining the NYPSC and founding Viridity Energy, a demand response and demand management provider, she was the chief operating officer of PJM from 2004 to 2007 and held various utility and regulatory positions before that. She is the wife of former PJM CEO Phil Harris.
“Audrey’s vast experience in creating and managing new wholesale electricity markets, and transforming existing energy markets and large power systems will further strengthen the work that AEMO has undertaken to support Australia’s energy industry transformation,” Anthony Marxsen, AEMO board chair, said in a statement.
“Audrey has the vision to lead, guide and support our organization and the broader Australian energy industry as we transition our energy markets and reform power systems planning and management.”
Melbourne-based AEMO is responsible for operating Australia’s largest gas and electricity markets and power systems, including the National Electricity Market and interconnected power system in Australia’s eastern and south-eastern seaboard, and the Wholesale Electricity Market and power system in Western Australia.
Zibelman succeeds acting CEO Karen Olesnicky, who has held that title since the death of AEMO’s founding CEO, Matt Zema, in July 2016.
“I am forever grateful to have played a part in bringing the governor’s highly lauded vision of a clean-energy economy to fruition,” Zibelman said in a statement. “Thanks to the governor’s leadership, New York state is on a pathway to achieve 50% renewable electricity by 2030 and create an affordable, clean and resilient power system for all New Yorkers. It has been an immense privilege to work with my colleagues in the governor’s office, on the commission and the dedicated, capable Department of Public Service staff.”
Anne Reynolds, executive director of the Alliance for Clean Energy New York, was dismayed by the news.
“PSC Chair Audrey Zibelman and New York’s energy team have made our state a national and global model for the 21st century energy grid. Her leadership in reforming utility regulation, the promotion of distributed generation and public participation testify to her lasting contribution. Her departure will be a real loss for New York state,” Reynolds said. “But Gov. Cuomo has a very strong energy team and vision, and we assume the administration’s sharp focus on modernizing and decarbonizing the grid will continue with Audrey’s replacement.”
Her departure leaves the PSC even more short-handed than it already is.
Former Chair Garry Brown left the commission in February 2015 and was not replaced. Last month, longtime commissioner and former chair Patricia Acampora said she would retire after the Feb. 16 commission meeting.
That would leave only two current members, Gregg Sayre and Diane Burman on the five-member panel. Their terms expire Feb. 1, 2018.
Sayre, a former telecommunications assistant general counsel from the Rochester area, was appointed in 2012.
Burman, chief counsel to the New York State Senate Republican Conference before her appointment to the PSC in 2013, is often the lone dissenting vote in commission meetings.
Rocco LaDuca, spokesman for Senate Energy and Telecommunications Committee Chair Joseph Griffo, said the senator is aware of the pending vacancies. “The [Republican caucus] will be having discussions in the days and weeks ahead to determine how to move forward. They are mindful of the commission’s responsibility to conduct its business, but there’s still time until March to address this issue,” he said.
Commissioners are appointed to six-year terms and are paid $109,800 annually. The chair has a $127,000 salary.
WASHINGTON — FERC last week proposed regulations intended to reduce uplift, allocate it more accurately and increase transparency (RM17-2).
The Notice of Proposed Rulemaking — the fourth issued by the commission in its ongoing price formation initiative — is premised on a preliminary finding that current RTO and ISO practices regarding reporting of uplift payments and operator-initiated commitments are unjust and unreasonable.
“The allocation of uplift costs should, to the extent possible, encourage behavior that will reduce the need for uplift-creating actions and avoid discouraging market participant behavior that lowers total production costs (i.e., enhances efficiency),” the commission said.
Lack of Transparency
“The lack of transparency regarding uplift and operator-initiated commitments, which can cause uplift, hinders market participants’ ability to plan and efficiently respond to system needs,” the commission said. “Market participants may lack the information necessary to evaluate the need for and value of additional investment, such as transmission upgrades or new generation. Also, without sufficient transparency, market participants may not be able to assess each RTO’s/ISO’s operator-initiated commitment practices and raise any issues of concern through the stakeholder process.”
Generators receive uplift payments when their production costs exceed their energy and ancillary services revenues. Last week’s order focuses on one of the main causes of uplift: deviations between the day-ahead and real-time market that can force operators to commit additional units. This can result from generators delivering less energy in real time than their day-ahead offers or real-time loads exceeding expectations.
Balancing charges (canceled resources, generators, imports, load response, local constraints control and lost opportunity cost) were responsible for 59% of all uplift in the first nine months of 2016 in PJM. The top 10 generators received 35.4% of all uplift and the top 10 organizations received 77% during the period. PJM’s Independent Market Monitor has long advocated disclosing the recipients of uplift payments, something that FERC’s recent NOPR would require monthly.
Although all RTOs and ISOs use some form of beneficiary pays or cost-causation principles to allocate uplift, their methods “vary significantly, both in terms of granularity and the exemption of certain types of transactions,” the commission said. “The definition of what precisely constitutes a deviation also varies across RTOs/ISOs.”
Some RTOs also fail to consider how deviations affect uplift costs. “Deviations from day-ahead market schedules that create the need for additional resource commitments in real-time tend to increase real-time uplift costs. On the other hand, deviations can also contribute to the convergence of the day-ahead and real-time markets,” the commission said.
“Allocating costs to deviations that did not cause the costs to be incurred may inappropriately penalize certain types of transactions that are beneficial to price formation,” the Office of Energy Policy and Innovation’s Stanley Wolf said in a presentation at Thursday’s commission meeting, which was closed to the public because of concerns about disruptions by anti-pipeline activists.
‘Helping’ and ‘Harming’ Deviations
The NOPR requires RTOs and ISOs to separate uplift costs assigned to deviations into at least two categories based on their causes: congestion management or systemwide capacity, a catch-all for any other deviations made to meet the system’s energy needs. The commission said categorization would ensure the costs are allocated more precisely to the participants that caused the uplift. The NOPR gives RTOs flexibility to create additional categories.
Grid operators would also be required to distinguish between deviations that help or harm their systems. Generators would be assigned uplift costs based on the net of their “harming” deviations — the total amount of deviations minus their “helping” deviations.
FERC said that any actions generators take in response to dispatch instructions should not be considered deviations. Also excluded would be transactions economically evaluated by RTOs in real time, such as the coordinated transaction scheduling between PJM and its neighbors NYISO and MISO.
The commissioners said they were inclined to exclude instructed deviations from the “help” category but asked for stakeholders’ comments on the issue.
RTO Requirements
The commission also proposed several requirements to increase transparency into uplift cost allocation and the decision-making of grid operators, noting that while all RTOs and ISOs release some information, “there is significant variation in the timing, granularity and types of data released.”
RTOs and ISOs would be required to:
Report total uplift payments for each transmission zone, separated by day and uplift category;
Report total uplift payments for each resource monthly;
Report megawatts of operator-initiated commitments in or near real time and after the close of the day-ahead market, broken out by transmission zone and the reason for the commitment; and
Define in their tariffs the transmission constraint penalty factors, how those factors can set LMPs and the process by which they can be changed. Transmission constraint penalty factors are the values at which an RTO will relax the flow-based limit on a transmission element to relieve a constraint rather than re-dispatch resources.
“The proposed transparency reforms will help market participants understand the operational constraints on the system, plan and efficiently respond to system needs, and evaluate the need for and value of additional investment,” FERC said.
“While uplift is not constituting a large proportion of total costs and is unavoidable to some extent, I think RTO/ISO stakeholders and the commission should strive to minimize uplift when and where possible because uplift is unhedgeable, lacks transparency and, if not allocated properly, can encourage inefficient behavior,” Chairman Norman Bay said.
The NOPR only addresses uplift costs incurred because of deviations. RTOs may also pay uplift for reliability reasons, such as stand-by costs, or inaccurate load forecasting.
“We note that the commission is not proposing to require RTOs/ISOs to allocate any amount of uplift costs to deviations; rather we are simply proposing reforms to uplift cost allocation to deviations to the extent an RTO/ISO chooses to allocate some uplift costs to deviations,” FERC said.
Comments on the NOPR are due no later than 60 days after its publication in the Federal Register.
Previous orders in the commission’s price formation initiative concerned fast-start resources, shortage pricing and the alignment of settlement and dispatch intervals and a doubling of the “hard” energy offer cap. (See FERC: Let Fast-Start Resources Set Prices.)
