Page 1184 – RTO Insider

April 24, 2018

UPDATE: Xcel Leaving Mountain West; SPP Integration at Risk

By Tom Kleckner

Xcel Energy, the Mountain West Transmission Group’s largest member, said late Friday that it is withdrawing from the Rocky Mountain group and its efforts to join SPP — potentially dooming the planned integration.

Executive Vice President David Eves, group president for Xcel’s utilities, said in a press release that the company recently completed a review of the Mountain West’s proposal to join SPP and determined that “continued engagement in Mountain West is not in the best of interests of our customers or the company.”

Xcel said “limited benefits” for the company’s Colorado customers, a lack of “market expansion opportunities” for the Mountain West and increasing “uncertainty over the costs of the RTO” led to its decision.

The Mountain West entities sit in the Western Interconnection, which has seen several market-related developments in recent months. Multiple Entities, Markets Now Beckon in West.)

Friday’s announcement caught SPP and Mountain West off guard. Xcel spent much of Friday alerting Mountain West members, state and federal regulators and other interested parties before issuing the release.

In an emailed statement, SPP CEO Nick Brown said the RTO was “surprised and disappointed.”

“SPP has spent significant time and effort attempting to bring organized wholesale markets and their many benefits to the West,” Brown said. “We’re hopeful there will still be opportunities to do so.”

Brown addressed the issue at the Regional State Committee meeting in Kansas City on Monday. “Obviously, we were shocked Friday by the announcement of [Xcel] pulling out of the Mountain West initiative,” he said. “In my initial discussions with other participants of Mountain West, they’re meeting to determine what their next steps are, and we will certainly do the same.”

Members of the RSC, which comprises regulators from most of the 14 states in SPP’s footprint, have also expressed reservations about the integration’s cost allocations. (See Mountain West, Cost Allocation Top SPP RSC Concerns.)

The decision left several of Mountain West’s entities pondering their next steps. With 1.4 million customers, Xcel’s Public Service Company of Colorado subsidiary represents about 40% of Mountain West’s base.

Lee Boughey, senior manager of communications and public affairs for Tri-State Generation and Transmission Association, said the cooperative would “take time to review its options and determine the best approach to move forward.”

“Ultimately, any decision to participate in a regional transmission organization will be dependent on whether it benefits our members,” Boughey said.

Tri-State is a member of both Mountain West and SPP, having joined the RTO as part of the Integrated System’s membership in 2015.

Theresa Donnelly, senior communications manager for Black Hills Corp., said her company is also “evaluating the impact” of Xcel’s departure from the SPP integration effort.

“We will continue our discussions in the coming days and weeks,” Donnelly said. “We respect Xcel Energy’s decision to end their participation in Mountain West, as the benefits and costs of RTO membership differ for each company based on their unique business situation and interests.”

Mountain West, which primarily services Colorado, Wyoming and Nebraska, began discussing RTO membership in 2013. It announced in January 2017 that it was pursuing membership in SPP, and in March, the RTO’s Board of Directors approved a set of policy recommendations intended to govern the terms of Mountain West’s membership. (See SPP Begins Work of Integrating Mountain West.)

Xcel said “a variety of interrelated items” drove the company to its decision:

The limited overall benefits to Xcel’s customers, “given the relatively small size of the MWTG footprint.”
The few opportunities for westward expansion of the RTO, “which might have added to the value proposition.”
A recent increase in the costs of forming an RTO, with “less certain” benefits that are “highly dependent on both the footprint, generation flexibility and composition of” Mountain West.
Recent developments with RTOs have “introduced an increased risk of more significant changes to state-regulated retail electric service than Xcel Energy had anticipated.”

“Xcel Energy will continue to focus on initiatives that will benefit our customers, keep bills low and facilitate the addition of renewable resources on our system,” Eves said. “Our customers and the state of Colorado benefit when states control their own energy policy.”

Colorado’s Public Utilities Commission, which has jurisdictional authority over Xcel and Black Hills, was thought to be the primary stumbling block to completing the Mountain West’s integration. The PUC declined to comment Saturday.

Denver-based attorney Abby Briggerman, who represents consumer groups before FERC, said in a statement: “We appreciate Xcel’s efforts to ensure meaningful savings for ratepayers and hope that whatever the alternatives considered, there will be a transparent stakeholder process to allow for comprehensive consideration of the best course forward.”

The Western Area Power Administration issued a statement saying it “appreciates the strong collaborative partnerships” within Mountain West and “is assessing [its] next steps” following Xcel’s withdrawal.

“WAPA maintains its commitment to working with neighboring entities across its 15-state footprint to develop strategies to adapt to the evolving electricity industry,” said Chief Public Affairs Officer Teresa K. Waugh. “We will continue to evaluate and pursue opportunities to optimize the utilization of generation and transmission resources across multiple utility systems.”

In recent weeks, a growing number of SPP stakeholders have pushed back against the Mountain West integration. A group of five members filed a letter April 6 asking the RTO’s board to reconsider its decision to move forward with the integration until “there is more consensus within the SPP membership as to how to proceed.” (See SPP Group Balks at Mountain West Concessions.)

On Wednesday, Lincoln Electric System (LES) issued its own letter, saying it agrees with the April 6 missive that the board should reconsider the approved MWTG policy recommendations.

LES said it is concerned about the recommendation proposing regionwide cost allocation for the Mountain West DC ties. “The expectation that existing SPP members would pay for DC tie legacy facilities is unprecedented and in contravention to the SPP Tariff,” wrote LES CEO Kevin Wailes.

LES also said there is no policy justification for the proposed three-year phase-in administrative fee discount for Mountain West members. “lf the purported benefits of the [Mountain West] integration have been accurately represented, there should be no need for one subset of SPP transmission owners to subsidize another subset during this period,” Wailes said. “Like others, we are in support of efforts to strategically bring in new entities that aren’t at the unnecessary expense of SPP’s existing members,” he added.

On Friday, the Missouri Joint Municipal Electric Utility Commission and the municipal utilities of Springfield and Independence, Mo., filed a joint letter outlining their concerns in language almost identical to that of LES.

SPP’s board and its Members Committee are scheduled to meet Tuesday in Kansas City, Mo. The agenda includes a Mountain West update and a president’s report, which will likely generate much discussion.

April 23, 2018

Ready to Act on DERs, FERC Tells Congress

By Rich Heidorn Jr.

WASHINGTON — FERC told Congress last week it is ready to act on distributed energy resources following a technical conference earlier this month, assuring House members they will not encroach on state jurisdiction.

During a hearing before the House Energy Subcommittee on April 17, commissioners said the April 10-11 technical conference on DERs had helped them answer the questions that had led them to delay action on distributed resources when they issued Order 841 on energy storage in February. (See FERC Rules to Boost Storage Role in Markets.)

ferc der — FERC Commissioners left to right: McIntyre, LaFleur, Chatterjee and Powelson | © *RTO Insider*

Commissioner Richard Glick cited questions about DERs’ reliability and how the commission interacts with states on aggregation. “I think we got enough information [at the technical conference], in my opinion, to address the issue,” he said in response to a question from Rep. Kathy Castor (D-Fla.). (See Gatekeeper or Facilitator? FERC Panels Debate EDCs’ DER Role.)

FERC Chairman Kevin McIntyre agreed, saying “the record we are assembling in that process will enable us to take steps comparable [to the commission’s action on storage]. I’m not saying that to forecast a particular outcome. I’m just saying that we’ve got enough now to go on to make a determination about what the appropriate steps are.”

Commissioner Cheryl LaFleur said there are two “macro issues” to be determined: one financial, the other operational.

She said ensuring that DERs do not receive duplicate payments at the wholesale and retail levels “will require some very specific rules.”

LaFleur said the commission got valuable testimony on the second issue: “how the different control centers talk to each other.”

“I think one of the big issues we’re going to have to think about as a body now is how uniform we make the rules as we put them out as opposed to allowing regional variations,” she continued. “Some of the people testified about wanting different regions to go in different directions here. I’m somewhat of the belief that the technology is marching so quickly that we should try to figure out what best practices are now. That’s what we’ll be debating.”

Rep. Gregg Harper (R-Miss.) questioned whether FERC was intruding on state and local regulators. “With the issuance of Order No. 841 and its proposal for the aggregation of DERs for the purpose of participating in wholesale electric markets, FERC could expand its authority at the expense of states and localities,” he said.

“Honestly, I’m not particularly troubled by any sort of jurisdictional creep because that power would make its way onto our grid in a way that we could regulate it only after it had been aggregated and put forth to a market that we regulate — a wholesale electric market,” McIntyre responded. “And there certainly is no attempt on the part of this commission to in any way thwart the ability of the state, for example, to determine in a retail-level transaction what the owner of the generating resources — what level that owner would be compensated. Honestly, I don’t see that as being a particularly grave concern.”

The commission will likely be inviting post-technical conference comments after transcripts of the technical conference are posted.

The three-hour hearing was the first with the full commission since 2015, according to Energy and Commerce Committee Chairman Greg Walden (R-Ore.). Also discussed were the commission’s grid resilience inquiry, the financial struggles of coal and nuclear generation, the Public Utility Regulatory Policies Act and the commission’s review of its 1999 policy statement on gas pipeline licensing. (See related stories, FERC Outlines Gas Pipeline Rule Review.)

Coal and Nuke Woes

The commission’s decision to open an inquiry on grid resilience after rejecting Energy Secretary Rick Perry’s call for price supports for coal and nuclear plants came up repeatedly in questions from committee members.

Rep. Joe Barton (R-Texas) called for “regulatory relief” for struggling coal and nuclear generators, saying market changes could result in unsustainable subsidies. “The regulatory burden obviously on nuclear is very high and you can argue that it’s also very high on coal plants. If we look for solutions to keep our distressed nuclear plants and coal plants in service, we should first look at regulatory relief and only then look at market relief,” he said. He did not elaborate on what regulations should be reduced.

Rep. David McKinley (R-W.Va.) brought up the “domino effect” he said will result if the 1,300-MW Pleasants County coal-fired plant is forced to retire after FERC rejected FirstEnergy’s proposal to move it from its merchant unit to a regulated utility. FirstEnergy announced in February it would close the plant in early 2019 if no buyer is found. (See FirstEnergy Shutting down Unsold Coal Plant.)

“This is a small county. Thirty percent of the tax revenue comes from that power plant. … That’s going to affect their school system. What about their [emergency medical service]? What about their hospital? If this power plant closes down, there’s a very high likelihood that the coal producer that supplies that power plant [Murray Energy] will similarly declare bankruptcy. If [CEO Robert Murray] declares bankruptcy, his relief will be to get away from his [United Mine Workers of America] pension responsibility, which currently funds 120,000 retirees. If that’s reduced, they would be shifted over likely to the federal Pension [Benefit] Guarantee Fund. I’ve got a letter from the Pension Guarantee Fund that says, ‘Don’t put those 120,000 on us because then we’ll go under.’ So, you see the domino effect of this,” he said.

McKinley asked the commission whether it had calculated the cost to consumers of subsidizing the plant.

“I do not have that figure,” responded McIntyre.

“We have reason to believe it’s less than $50 a year per customer. The consumer currently is paying $50 a year for tree trimming,” McKinley said. “I think we have a moral responsibility to look at this thing holistically, rather than just an ideological fight [over] what we think … is a free market.”

“Would you agree? Do we have a free market system in energy?” he continued.

“We do not have a perfect market system in energy, that is certain,” McIntyre responded.

Rep. Adam Kinzinger (R-Ill.), whose district is home to four nuclear plants, said he was concerned that the loss of nuclear generation would harm resilience. McIntyre said the commission’s resilience docket (RM18-1) could result in additional revenue for nuclear plants if FERC determines they provide resilience attributes for which they are not compensated.

Commissioner Robert Powelson reminded Kinzinger of the history of Illinois’ move to retail choice. “Those nuclear plants you referenced, customers paid a competitive transition charge as part of a stranded cost investment. So here we are today in your state and my state [Pennsylvania] … where something that was quote ‘too cheap to meter’ is coming back into the market. … We’re being asked theoretically — your constituents are being asked — to do another stranded cost for those assets. So, if I’m a gas operator or I’m an emerging technology in the market, I’m not getting any type of backstop for my resource.”

Rep. Bill Johnson (R-Ohio) asked Powelson about his response to Murray’s criticism that “FERC didn’t do its job” when it rejected the Perry’s request. Responding on Twitter, Powelson initially challenged Murray to a debate, a tweet he later deleted.

“I take offense to the word ‘feckless’ being used to [describe] colleagues that I serve with here,” responded Powelson. “My colleagues and the 1,320 [FERC] employees who show up to work every day to do their job around safety and economic regulation and making sure our wholesale power markets are functioning. … I refrained from [pursuing a debate]. I thought it was inappropriate and I dialed it back rather quickly.”

Transmission Spending

Several members questioned whether FERC and RTOs were allowing unnecessary transmission spending.

Rep. Frank Pallone (D-N.J.) questioned whether Jersey Central Power & Light’s proposed $111 million Monmouth County Reliability Project is necessary to accomplish the company’s reliability goals. “Recently this view was echoed by New Jersey Administrative Law Judge Gail Cookson, who ruled that JCP&L failed to demonstrate that their transmission line is necessary and noted that JCP&L has not seriously considered alternative corridors and ignored non-transmission solutions entirely,” Pallone said, adding that the utility should have considered distributed generation, storage and new grid technologies.

“Her decision supports my long-held suspicion that often projects like this … are more about the rate of return for shareholders than reliability for consumers.”

Powelson expressed sympathy. “I have a concern when industrial customers come in to the commission as energy users telling us that they’re seeing a 400% increase in transmission costs as wholesale [energy] prices are dropping. That’s alarming. That tells me that the RTOs at the wholesale level of transmission planning are not doing a very good job of cost containment. And we are all paying for that as consumers.”

Rep. Billy Long (R-Mo.) cited complaints by the City Utilities of Springfield that it has seen a substantial increase in its transmission costs in SPP, “most … related to funding transmission projects outside of” the state.

“Some of the projects allow utilities to access renewable energy located outside of the state. However, the benefits [are] far outweighed by the rise in transmission costs,” Long said. “SPP’s own studies have shown the City Utilities’ transmission costs and energy prices are substantially higher than other customers in the Southwest Power Pool. What will FERC do to address the issue of rising transmission costs in” the RTO?

McIntyre said he was unfamiliar with the study Long referenced but agreed to investigate the matter. “Generally speaking, it would be surprising that a particular entity paying those transmission costs is paying significantly higher than other entities served by the same” RTO.

Order 1000

Glick and McIntyre, the newest members of the commission, said they want to take another look at some of FERC’s transmission policies.

McIntyre said the commission’s transmission planning rules are “something that’s ripe for evaluation as to whether it’s working as well … as was hoped for when we issued” Order 1000.

Glick said the commission should reconsider how it awards return-on-equity incentives to transmission developers.

“Are we incenting the right thing? For instance, we incent RTO participation, but a lot of … utilities are participating in RTOs regardless of whether they have an incentive or not,” Glick said. “We really should be incenting, ‘Are we using transmission capacity more efficiently? Are we using new technologies to make transmission capacity more efficient?’ Those are the kinds of things that I think congress gave us the authority to do.”

PURPA

Rep. Tim Walberg (R-Mich.) pressed the commission to revise its enforcement of PURPA, noting it has been nearly two years since the commission’s technical conference on the subject. (See FERC Conference Debates PURPA Costs, Purchase Obligations.)

McIntyre said an overhaul of the law would be up to Congress but said FERC can act to prevent abuses of its 1-mile rule and 20-MW threshold. “I think the record is already there to act on the 1-mile rule,” agreed Commissioner Neil Chatterjee. He added it “could be a challenge” to get a bill through Congress.

‘By Operation of Law’

Rep. Joseph Kennedy (D-Mass.) used his time to urge support for a bill he is sponsoring to address the commission’s 2-2 deadlock in September 2014 over whether it should reject the results of ISO-NE’s eighth Forward Capacity Auction because of unchecked market power. The 2017-18 auction results became “effective by operation of law” (ER14-1409). Under the FPA, rates take effect 60 days after they are filed with FERC, absent a commission order to the contrary.

Sen. Ed Markey (D-Mass.) is sponsoring similar legislation. (See FERC: FPA Change may not Solve Catch-22 on Vote Deadlocks.)

McIntyre said such occurrences arise “very, very rarely, once every dozen years.”

Kennedy interrupted him: “When it does it comes with a fairly big consequence.”

April 23, 2018

FERC Orders RTOs to Shine Light on Uplift Data

By Michael Brooks

WASHINGTON — RTOs and ISOs will be required to submit monthly reports detailing their uplift payments and operator-initiated commitments under a rule that FERC said would increase transparency in the wholesale markets (Order 844, RM17-2).

But the commission’s order Thursday withdrew a requirement that grid operators categorize real-time uplift costs based on their causes and allocate them only to market participants “whose transactions are reasonably expected to have caused” the uplift.

FERC made both proposals in a 2017 Notice of Proposed Rulemaking the commission issued in January 2017 as part of a larger price formation initiative it began in 2014. (See FERC Seeks More Transparency, Cost Causation on Uplift.) Thursday’s order marked the last “generic” action it took as part of that initiative, FERC said.

Under the new rule, RTOs and ISOs will be required to report:

total uplift payments for each transmission zone, separated by day and uplift category;
total uplift payments for each resource monthly; and
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.

Generators receive uplift payments when their production costs exceed their energy and ancillary services revenues. Operator-initiated commitments refer to when a generator operates at the direction of the grid operator at a loss for reliability reasons.

Penalty Factors

Grid operators will also be required to revise their tariffs to include the transmission constraint penalty factors used in their market software, the circumstances under which those factors can set LMPs and any processes by which they can be changed. Penalty factors are the maximum prices RTOs pay to redispatch resources before allowing power flow to exceed their maximum operating levels.

FERC found that although all RTOs/ISOs report some information about uplift payments and their causes, their disclosures usually lack detail and are inconsistent across markets. No RTO or ISO reports uplift on a resource-specific basis.

“A lack of transparency regarding uplift payments and operator-initiated commitments can mask system conditions, particularly in times of system stress,” Adam Cornelius, of FERC’s Office of Energy Policy and Innovation, said at Thursday’s open meeting. “The result is that market participants may not fully understand the needs of the system or recognize the resource attributes that are required to meet those needs. … Therefore, current reporting practices may not provide sufficient transparency for market participants to plan for and respond to system needs in a cost-effective manner, resulting in rates that are unjust and unreasonable.”

The increased transparency will help market participants invest in new infrastructure more efficiently and facilitate more informed stakeholder discussions, he said.

Compliance filings for the rule are due 135 days after its publication in the Federal Register, and the grid operators have another 120 days to implement it.

“Uplift isn’t the sexiest topic … even compared to FERC topics,” Commissioner Cheryl LaFleur joked. “And sometimes it’s get a bad name, as if it’s a bad thing. But commitment actions that lead to uplift are important” for reliability. The reports will “provide additional information to the marketplace so the marketplace can solve the problems that they reveal,” she said.

Commissioner Neil Chatterjee agreed. “It is no secret that transparency in RTO and ISO price formation is not the most riveting subject,” he said. “I haven’t seen a lot of headlines calling for better reports on uplift, and I wouldn’t expect these topics to be trending on Twitter any time soon. …

“But that doesn’t mean today’s action isn’t significant. The final rule is a win for all stakeholders participating in these markets, as they will benefit from the added transparency it will bring to each RTO’s commitment, dispatch and settlement processes.”

Cost Allocation Proposal Dropped

FERC had proposed that grid operators categorize deviations between the day-ahead and real-time markets, one of the main causes of uplift, as either “helping” (reducing the need for uplift) or “harming” (increasing the need) and that they allocate uplift costs to generators based on the net of their harming deviations.

However, many commenters, while agreeing with the rule’s general principle, questioned its feasibility.

Exelon pointed to PJM and the 2014 polar vortex as an example. During the period of extremely cold weather, high natural gas prices led to high energy prices in PJM, and the RTO dispatched high-cost generators to maintain reliability. At the same time, generators in neighboring regions self-scheduled imports into PJM, “chasing” the high prices, which led prices to drop. Thus, the PJM generators’ operating costs exceeded their revenues, leading to high uplift payments.

“While the large volume of self-scheduled imports may have ‘helped’ PJM meet system needs, and would ostensibly qualify as ‘helping’ deviations as contemplated in the NOPR, these self-scheduled imports nevertheless directly caused the system uplift payments,” Exelon said.

“Given the complexity of this issue and the varying practices among RTOs, the NOPR’s preliminary finding that someexisting RTO practices may be unjust and unreasonable does not justify standardizing this aspect of the various RTOs’ market design,” the Transmission Access Policy Study Group (TAPS) said in its comments.

“If the commission proceeds to a final rule, TAPS generally supports netting of helpful and harmful deviations as consistent with cost-causation principles,” the group said. “However, the commission should allow each RTO to propose specific criteria for determining whether a deviation is helpful or harmful and should recognize that in certain circumstances, a deviation’s ‘helpfulness’ or ‘harmfulness’ may be difficult to establish.”

Most commenters, however, expressed “broad” support for the transparency proposal. The lone dissenter was CAISO, who argued that its existing reporting provides enough transparency and that the new requirements — specifically the deadlines for filing the new reports — would be overly burdensome.

FERC disagreed that CAISO was sufficiently transparent. The ISO aggregates uplift data to its 10 local capacity requirement areas and reports daily total uplift costs for each month by market and type of cost. (See graph.) It also reports the daily aggregated megawatt-hours of “exceptional dispatches.” But it does not specify which of those resulted from operator-initiated commitments.

ferc uplift — CAISO’s exceptional dispatch uplift costs for January and February 2018. The ISO includes these graphs in its monthly Market Performance Reports, but some stakeholders noted that it does not include the underlying data. FERC said this level of transparency was insufficient. | *CAISO*

To address CAISO’s concerns, the commission said it would consider extending the filing deadline for the monthly zonal report (20 days after the end of the month) if the ISO can show in its compliance filing that 20 days is not enough time. FERC also extended the deadline for the monthly resource-specific report from 20 days after month-end to 90.

Several commenters argued that resource-specific uplift data should only be obtainable through a password-protected page on the grid operators’ websites, an idea FERC rejected. “Providing data only to certain market participants does not achieve the goals of this final rule,” the commission said. “Transparency into resource-specific uplift payments can highlight potential instances of gaming and collusion for other market participants, and allow them to advocate for solutions and call attention to such issues more quickly and efficiently.”

April 23, 2018

NYPSC OKs Con Ed EV Charging Program, REV Initiatives

By Michael Kuser

The New York Public Service Commission on Thursday approved a seven-year tariff for Consolidated Edison’s electric vehicle quick-charging station program (17-E-0814).

new york REV EV Con Ed — The New York Department of Public Service held a commission session on April 19

Under the tariff, the utility will expand the scope of its economic development Business Incentive Rate (BIR) to be available to owners of EV quick-charging stations with a minimum aggregate charging capacity of 100 kW and a maximum aggregate demand of 2,000 kW in New York City and Westchester County. The program could support more than 85,000 EVs by the end of the seven-year program, the company said.

“The city already indicated the program will complement its efforts in increasing access to quick-charging infrastructure,” said Department of Public Service staffer Mary Ann Sorrentino.

The New York State Energy Research and Development Authority indicated that Con Ed’s program, coupled with NYSERDA’s incentives, will likely achieve the near-term economics necessary for greater uptake and installation of quick-charging stations, she said.

The New York City area was one of 17 metro areas selected for the first cycle of $250 million in spending on zero-emission vehicle infrastructure under the $2 billion Volkswagen settlement for violating the Clean Air Act.

The state expects to receive $127.7 million for air pollution mitigation projects, according to a Department of Environmental Conservation report.

Delaying implementation of the Con Ed EV program would result in decreased uptake and a missed opportunity to leverage the BIR to maximize new investment in the utility’s territory, Sorrentino said.

PSC Commissioner Diane Burman voted against the tariff filing, without prejudice.

“I think we’re oversimplifying the issues here,” Burman said. “I don’t understand how this is not in conflict with moving forward at this time. Are we saying that failure to act now is going to cause us to not be able to get the VW settlement monies in the New York City area? Because there’s nothing in the record to say that we need this for the VW settlement monies.”

Warren Myers, DPS director of regulatory economics, said, “This is a very specific program that, to me, is very consistent with all of our economic development flex-rate programs that have been around for years and years. This is a way, as Commissioner [Gregg] Sayre said, to try to attract load that otherwise would not come to the electric utility.”

The PSC on April 19 also instituted a proceeding (18-E-0138) to encourage greater penetration of EVs and related supply equipment, possibly through the solicitation of scalable pilot programs.

The new proceeding supports other state initiatives such as ChargeNY— Gov. Andrew Cuomo’s goal of installing 10,000 EV charging stations by 2021, up from 2,000 today.

As in the Con Ed charging station program, utilities will help design rates to incentivize off-peak charging and invest in EV infrastructure and related supply equipment. The commission will soon announce the stakeholder feedback schedule for the new initiative.

“This proceeding is important because we need a framework that will get this right in respect [to] the costs, the benefits and the issues for the distribution grid that arise out of the penetration of electric vehicles,” said PSC Chair John B. Rhodes.

More REV

The PSC also acted on other initiatives under the Reforming the Energy Vision strategy to lead on climate change: expanding the integration of energy storage systems onto the grid; approving an upstate community smart energy project; creating an online platform for data sharing among energy companies; and streamlining permitting for farmers using anaerobic digesters to produce electricity.

In the matter of the Value of Distributed Energy Resources initiative (15-E-0751), the commission ordered that distributed generation suppliers be allowed to connect energy storage projects up to 5 MW to distribution systems. In addition, the commission issued two orders (18-E-0018; 15-E-0557) to improve the standardized interconnection requirements application and contract process to allow developers to connect projects to the grid without undue delay.

“Our standardized interconnection requirement simply can’t stand still,” Sayre said. “Some of the changes in this item are necessary because of our orders on the Value of Distributed Energy Resources, some of them come out of the stakeholder process to improve the interconnection process, and still others are necessary to accommodate technological and market changes in areas like energy storage.”

The commission approved New York State Electric and Gas’ request to implement a pilot program of time-differentiated electric rate options, the Energy Smart Community project, which includes deploying advanced metering infrastructure to approximately 12,000 customers in Ithaca and the surrounding area.

The Utility Energy Registry approved by the PSC will make load data for the major utilities available for local planning, market research and community choice aggregation development, without providing individuals’ consumption profiles.

The commission also ordered that community distributed generation (CDG) projects serving only farm customers no longer be required to comply with several CDG program requirements, including the 10-member minimum.

Rhodes closed the session by reading a resolution of appreciation for DPS Chief of Electric Rates and Tariffs Michael Twergo, who is retiring after 32 years of service.

April 23, 2018

MISO Renewable Study Predicts Later Peak, Narrower LOLE Risk

By Amanda Durish Cook

Increased renewable integration, especially solar generation, will shift MISO’s peak load to evening hours, with a spikier but shorter daily loss-of-load risk, according to the initial results of the RTO’s new long-term renewable study.

Senior Policy Studies Engineer Jordan Bakke said the study, which has thus far focused only on resource adequacy, found distinct trends as renewable penetration was dialed up by increments of 10% of the resource mix:

The average daily loss-of-load expectation (LOLE) becomes heightened, though it compresses to a smaller window later in the day;
Wind and solar resources are less likely to be able to meet the late-day risk owing to their operational characteristics; but
Geographically dispersed and diverse technologies like demand response and storage can assist renewables in their ability to meet load.

“We found strong evidence that the sun-down part of the day becomes high-risk hours,” Bakke told stakeholders at an April 18 Planning Advisory Committee meeting.

MISO’s multiyear Renewable Integration Impact Assessment, announced last year, seeks to identify “inflection points” where the growth of renewables and the retirement of baseload units will require changes in the structure or operation of the system.

The study aims to predict how and when reliability will be impacted under heavy renewable output; if there are limits to the amount of wind and solar generation MISO can support; how long before energy storage becomes a requirement; what parts of the grid will be stressed first; and how much renewable energy can be deployed before significant system changes are needed. (See MISO to Conduct Long-Term Renewable Integration Study.)

MISO renewable power LOLE — Loss of Load Risk with Renewable Penetration | *MISO*

MISO studied an ever-increasing renewable penetration in the footprint, topping off at 100% using a mix of 75% wind, 17.5% utility-scale solar and 7.5% distributed solar.

Bakke said even with a small solar penetration increase, net peak load will shift from 3 p.m. to 6 p.m. MISO currently has 270 MW of installed solar.

“We’re seeing some dramatic shifts with relatively low levels of penetration,” Bakke explained. “What we’re seeing here is even when solar is at 5% penetration, this time shift already occurs … as solar drops off early in the evening.”

Bakke also said while MISO’s average year-round risk of losing load peaks from “noon to late in the day,” the risk period narrows to 5 to about 8 p.m. as more renewables are employed.

Some stakeholders set into an M.C. Escher-esque discussion on the change in loss-of-load risk, saying that while rising solar generation could cause a shift in the traditional peak load pattern, the traditional 3 to 6 p.m. peak demand hours do still exist — albeit muted by increasing solar supply. Some pointed out that a late-day loss-of-load risk falls to hours that historically have had less electricity demand and could be manageable.

Wind on the Wires’ Natalie McIntire asked if MISO’s study included a scenario in which increasing use of energy storage offsets the sharper loss-of-load risk.

Although MISO’s study indicates that storage can help offset the risk, Bakke said MISO used existing levels of non-renewable resources for the study and did not run scenarios with escalating use of energy storage. Customized Energy Solutions’ David Sapper said storage scenarios would have been “fundamental” to the early stage of the study.

MISO’s early results also show that a 100% renewables scenario can force negative loads during the day, meaning some generation must be curtailed or exported, Bakke said.

But some stakeholders said the need to plan for daytime negative loads is decades away, if it ever happens.

“We have a long way to go to get to 100% renewables, if we ever do. We need to focus on 10, 20, 30 years out,” McIntire said.

Bakke agreed, but said, “It’s important to look at these things early and often” because just a small increase in solar shows MISO may have to reallocate generation and load.

MISO found that wind and solar combinations do work symbiotically over an average day, especially in summer, with mid-day solar able to offset small dips in mid-day wind generation.

“They are not the perfect complement to each other, but they do complement one another,” Bakke said.

MISO plans to continue the renewable study on an open-ended basis; the RTO said it will continue to study resource adequacy under increasing renewables through the end of the year.

MTEP Resource Siting

In a related matter, Bakke said MISO’s 2019 Transmission Expansion Plan resource siting forecasts have been retooled this year to account for renewable adoption. Resource siting will rely on predictions of future energy storage sited at MISO’s busiest load buses; MISO predictions on electric vehicle adoption; National Renewable Energy Laboratory predictions on distributed resources; and the usual study from Vibrant Clean Energy that identifies areas ripe for utility-scale wind and solar development. MISO will reveal a first draft of MTEP 19 resource siting in September. (See Renewables, Storage Get More Play in MISO 2019 Planning.)

Meanwhile, the Planning Advisory Committee in June will begin to flesh out how to analyze and recommend energy storage as baseline reliability solutions in the MTEP process, a responsibility passed to it by the Energy Storage Task Force last month. PAC Chair Jeff Webb said MISO may have to submit Tariff changes with FERC to allow storage projects to be considered for reliability purposes.

Webb said staff and stakeholders have until Sept. 15 to propose reliability projects for MTEP 19. Some stakeholders have requested MISO allow storage projects to be submitted as baseline reliability projects in MTEP 19.

April 23, 2018

Calif. Energy Bills Move Forward, but Big Ones Stall

By Jason Fordney

California lawmakers moved forward with several pieces of energy legislation last week, but hotly watched items such as a 100% renewable energy standard and CAISO regionalization seem to be set on simmer.

california energy legislation — Several bills moved through a California Assembly Committee last week | © *RTO Insider*

There has been no movement this year on SB100, former State Senate President Pro Tempore Kevin de Leon’s 100% renewable energy bill that was front and center as the 2017 legislative session drew to a close. (See CAISO Regionalization, 100% Clean Energy Bills Fizzle.) SB100 has seen no votes since the Assembly Appropriations Committee last September.

And AB813, legislation that would regionalize CAISO, sits in committee during this session as other, higher-profile issues heat up. (See Calif. Lawmakers Relaunch CAISO Regionalization.) The regionalization language is currently in the Senate Rules Committee and the next step is a referral to the Energy Committee.

The U.S. Senate Democratic primary between de Leon and longtime Sen. Dianne Feinstein is taking up a great deal of political oxygen and an unrelated series of sexual assault controversies are another major distraction in the Capitol. (See Wildfire Costs Ignite Worry at CPUC, Legislature.)

On Thursday, the Assembly Utilities and Energy Committee, chaired by Assemblyman Chris Holden (D) passed several pieces of legislation, including:

AB2068(Chu), to Appropriations: It would require IOUs to evaluate the feasibility of discounting rates for public schools by at least 15% and for the California Public Utilities Commission to determine whether to adopt the discount. It requires the CPUC to direct IOUs to evaluate and report on the feasibility and economic impact of establishing the discounts. The evaluation must include commercial rate increases for the past five years that affected schools and the economic impact to other ratepayers if all public schools receive the discount. The bill requires the CPUC to submit the report to the legislature by Jan. 1, 2020.
AB2208(Aguiar-Curry) to Natural Resources: The bill requires investor-owned utilities, community choice aggregators, retail energy sellers and publicly owned utilities to procure an unspecified percentage of their resources from geothermal, biogas or biomass facilities. An unspecified amount would have to be procured from the Salton Seageothermal resource area, 10 generating plants producing 327 MW in Southern California’s Imperial Valley. According to an author’s statement, “AB 2208 will make it easier to reliably integrate higher amounts of renewable energy generation into the grid by requiring the procurement of ‘grid-balancing’ renewables, such as geothermal and bioenergy.” It would allow bioenergy facilities open to continue accepting wood waste as a forest fire management measure.
AB2515(Reyes) to Appropriations: The bill requires the CPUC to report to the legislature pending and previously approved changes to IOU revenue requirements over at least the past five years that resulted from requests by IOUs and CPUC decisions and resolutions. It also requires IOUs seeking a rate change to disclose estimated rate and bill impacts on each customer class.
AB2831(Limon) to Appropriations: Requires the CPUC, in consultation with the Office of Small Business Advocate within the governor’s Office of Business and Economic Development, to ensure that adequate marketing, education and outreach are undertaken to enable small business customers to fully participate in demand-side energy management programs.

April 23, 2018

Western Regulators Get Schooled in RTO Legal 101

By Robert Mullin

VANCOUVER, Canada — With three RTOs advancing competing efforts to extend their services into the West, the region’s utility regulators last week took a timely crash course on the legal implications of allowing their utilities to join organized markets.

It was a bracing — and invaluable — session, according to some industry stakeholders attending the spring joint meeting of the Western Interconnection Regional Advisory Body and the Committee on Regional Electric Power Cooperation.

organized electric markets — Hempling | © *RTO Insider*

Scott Hempling, an attorney specializing in public utility law, provided a compressed but comprehensive 90-minute primer of the statutes, regulations and case law governing the functioning of RTOs, beginning with their origins in FERC Order 2000, which encouraged — but did not require — utilities to form or join an RTO.

“The primary purpose was to end discrimination by transmission owners,” Hempling said. “One of the methods of discrimination before Order 2000 was to keep secret the availability of transmission.”

Hempling explained the four “minimum characteristics” of RTOs required by FERC: independence; appropriate scope and regional configuration; operational authority; and exclusive authority over short-term reliability.

In addition, RTOs must fulfill eight “required functions,” including tariff design and congestion management. “Understanding those 12 things is crucial to understanding what’s getting turned over to the RTO,” he said.

Hempling clarified that a transmission-owning utility legally becomes a customer of an RTO once it joins the RTO and turns over its transmission assets. It also becomes FERC jurisdictional. “When your utility joins an RTO, it no longer provides transmission service,” he said.

“Let me put it bluntly: you lose jurisdiction over transmission costs” when a utility joins an RTO, Hempling told the audience of commissioners. As a result, any state commission that has approved RTO membership cannot “logically disallow” a utility from including in retail rates the costs of becoming a customer of the RTO.

“Once FERC determines that the rate charged by the RTO to the transmission owner is prudent, the state must pass that cost on” to customers, Hempling said.

And while a transmission-owning utility does receive a pro rata share of the revenues the RTO generates from all transmission customers, the resulting credits don’t always make retail ratepayers whole. “You’d think the retail charges and credits would be a wash, but that’s not necessarily the case,” Hempling said.

One commissioner asked if FERC made distinctions within RTOs between how it treats investor-owned utilities on the one hand and rural cooperatives and municipal power systems on the other.

Hempling noted that the Federal Power Act exempts publicly owned systems from FERC oversight — unless they are TOs and join an RTO. “Co-ops and munis join RTOs by contract. Now if they’re transmission owners, are they subject to FERC jurisdiction? The answer is ‘yes.’” Based on FERC’s reciprocity rule, “if you want to take transmission service and you own transmission, then you’re going to need to provide transmission service,” Hempling said.

FERC ‘Controversies’

Hempling turned to key areas “where FERC finds itself resolving controversies” related to the nation’s RTOs.

Chief among the agency’s concerns: return on equity for transmission investments.

“There is a great deal of controversy over what is the ‘fair return on equity,’ and it’s not just about profiteering,” he said. “We’re talking about hundreds of billions of dollars in necessary transmission investment, and that money is going to have to come from somewhere and get paid off over a certain period of time. So return on equity matters, both from the customer standpoint and the investor standpoint.”

Hempling pointed to the differences between administering general rate cases (FERC’s past approach) and formula rate cases (its current approach).

“A formula rate’s a spreadsheet, and I guess the word is that you ‘populate’ the spreadsheet with the numbers — as opposed to a general rate case, where everybody and their brother and father and mother and sister gets into the case and everybody fights over what the ultimate [regulated rate of return] should be,” Hempling said. “For years, FERC set transmission rates with a general rate case, but now it prefers to set them by formula. But just because it’s a spreadsheet that you populate across doesn’t mean that FERC goes to sleep and just asks that you include whatever you want to put in there.”

Hempling expressed his respect for FERC, calling the agency “very, very professional — even in the current political environment.” But he cautioned state commissioners about the agency’s limitations in judging the reasonableness of transmission project expenditures, another area of focus for the agency.

FERC “does not disallow costs very often. … There is a question whether an agency whose authority is transmission [has] competency in looking at alternatives,” he said, adding that FERC “does not do integrated resource planning.”

Hempling also pointed to FERC’s role in overseeing RTO transmission cost allocation.

“You’re a multistate region — which state’s customers are paying for what? And there are now a variety of court of appeals decisions and FERC decisions that allocate costs among the family members, who at conferences like this are all happy to see each other over pastries, but then they’re happy to hire very expensive lawyers to fight over who’s getting which dollars.”

Power to the States?

Hempling posed a series of hypothetical questions regarding a state’s influence over utilities before and after a decision to join an RTO. His answers, he made clear, were based on his own professional opinion, not settled law.

Can a state order its utility to join an RTO?

Yes, Hempling said. A state commission could find that a utility’s rates “will not be just and reasonable, reliability will be insufficient to satisfy state law unless the utility joins an RTO,” he said. “I also think therefore — and everything I’m saying now is subject to debate — that a state can reject a utility’s request to join, I think for the same reason.”

Can FERC order a utility to join?

“This question, along with all the others, is untested, because if FERC does have the authority to order a utility to join, then that would pre-empt a state that rejects a utility to join. That would be an inconsistency, right? You can’t put a utility between a rock and a hard place,” Hempling said.

“Do I think FERC has the authority to order a utility to join? I think they do. … And in any event, FERC has never said so,” he said. “And that’s why the joining of RTOs by utilities is opportunistic. That’s why they at least get to decide … based on their own self-interest, because FERC has not said it can order a utility to join.” But FERC has conditioned a utility’s request for merger approval on joining an RTO, he noted.

Hempling also posed the possibility of a state requiring a utility to get state permission before proposing to the RTO any new construction of transmission above a particular level. “In my legal opinion, a state can do that, but it has not been tested,” he said.

After the Fact

How can a state pursue its values after a utility joins an RTO?

Hempling noted that legal precedent precludes states from forcing a utility — including an RTO — to submit a tariff change with FERC. Still, a state can circumvent that restriction by persuading the utility or RTO to make a state-sought filing.

“The way the Federal Power Act works is this: If a utility makes a filing at FERC, and that filing satisfies the Federal Power Act standard of ‘just and reasonable’ … FERC is obligated to approve it, even if FERC has a better idea. … It’s a utility-deferential statute,” he said. “Which means if you are a state wanting to say, ‘I’ve got a better idea,’ and so you introduce at FERC a filing, FERC is going to say, ‘I like your idea a lot better, state, but the utility’s idea is just and reasonable.’”

SPP has worked around this situation through the authority granted to its Regional State Committee, which can order SPP to make a filing even if the RTO disagrees with it, Hempling said. “Now SPP can also make its own filing, and they can say, ‘We think the state’s idea is crap,’ but we file it because we agreed to file it. And what happens now is that FERC can actually choose either one. So it puts the states on equal legal footing in terms of the chances of being selected.”

Former California Public Utilities Commissioner Mike Florio, now principal of Florio Consulting, said that California legislators have asked him whether the state can direct an investor-owned utility to leave an RTO.

“My … answer is no, because … it’s a contract that FERC has approved,” Hempling replied. “And that contract is where you go to find out the authority of someone to leave. And because it’s a FERC-jurisdictional contract, a state cannot issue an order that causes a utility to act in violation of the contract. That would be pre-emptive.

“FERC wants the stability about decisions to be in FERC’s hands,” he added.

Utah Public Service Commissioner David Clark said one of his concerns about his state’s utilities joining an RTO is the cost-of-service differential between it and other states in the region — namely, California.

“I know FERC has been concerned that the RTO process maintain status quo benefits and focus on new benefits,” Hempling said. “I think FERC has not had the notion of creating enemies of the RTO process.”

Another commissioner asked: “How do we know we’re protecting our state’s interests?”

Hempling replied with a question: “What is the commonality that we’re trying to pursue through the RTO mechanism when there are so many differences? … Focus on what the commonalities are.

“I was once at a [National Association of Regulatory Utility Commissioners] meeting and there was a Midwestern commissioner who said, ‘Whoa, if we’re not preserving state regulation, what are we here for?’” Hempling said. “And I’m thinking, ‘What you’re here for is something bigger than that. You’re here for efficiencies; you’re here for the customer; you’re here for investors; you’re here for marginal values. You’re here for something. You’re not here for jurisdiction.’

“The mission is not jurisdictional preservation. It’s jurisdictional effectiveness.”

April 23, 2018

Stakeholders Concerned over Tx Conflicts in MISO Retirement Plan

By Amanda Durish Cook

MISO stakeholders are concerned over the RTO’s unit retirement proposal, saying it could result in conflicts over interconnection service rights between suspended units and those in the queue.

“Folks were not comfortable with granting … conflicting interconnection rights,” MISO engineer Patrick Jehring said during an April 17 Planning Subcommittee meeting.

MISO is proposing to model suspended units as offline during the three years of their suspension, then considering them available to participate in local balancing authority dispatch in planning scenarios thereafter. Units that retire during the three-year process by waiving their interconnection rights with MISO will be modeled offline indefinitely in planning models.

Jehring said the modeling plan is like the three-year offline modeling used today but aligns with MISO’s new proposal to have generation owners considering a shutdown enter a catch-all suspension period for three planning years.

Owners would no longer have to decide between a permanent retirement and a temporary shutdown, which requires an estimated return-to-service date. Instead, they would have three full planning years to prepare a return to service or decide on retirement. Suspended generators would lose interconnection service after three planning years if they don’t resume operations. (See MISO Readies Retirement Change.)

Pat Hayes, LS Power transmission policy manager, asked what happens when the owner of a suspended unit returns after the three-year rescission period to find that new generation is poised to assume its interconnection service.

“It’s never happened before,” Jehring said. In such a case, he said, the projects’ local transmission pricing zone would bear the cost risks of the network upgrades necessary to accommodate both the new and existing unit.

“Basically, the stars need to align for this situation to occur. … The likelihood of this occurring is low based on what we’ve seen in the past and what we expect in the future,” Jehring stressed.

Some stakeholders said MISO’s modeling still leaves open the risk that local transmission pricing zones will bear the cost of interconnecting two conflicting units.

“I guess what I would say to that is the possibility for this rift already occurs today. It’s an if-upon-if-upon-if situation to get to that situation,” Jehring said.

Of the approximate 27 GW of Attachment Y suspension/retirement notices that MISO has received, Jehring said only 6 GW has returned to service. MISO unit owners typically submit Attachment Y when catastrophic equipment failure occurs or the units become uneconomic to operate. “When we think about the magnitude of it, we’re only talking 6,000 MW.”

Jehring said including suspended units in the dispatch in modeling after their three-year suspension period doesn’t mean the units would ever be dispatched again. The decision to dispatch is based on the “most economic firm resources being utilized to meet a local balancing area’s firm load and interchange obligations,” according to MISO.

“If a unit goes on suspension for economic reasons, it is unlikely it would be dispatched in the planning models anyway,” Jehring said. “The only real reason that a unit will stay on suspension is they’re on the economic bubble … and they’re truly seeing if they’ll become economic again.”

MISO will accept written stakeholder comments on the modeling proposal through May 4.

April 20, 2018

Gas Dominates, Again, in FERC State of the Markets Report

By Michael Brooks

WASHINGTON — By now, it sounds like a broken record.

As they have in the past four years, the trends in natural gas dominated the discussion of FERC’s annual State of the Markets report at the commission’s open meeting on Thursday.

The report found that average U.S. natural gas spot prices rose 21% in 2017 from 2016, while average day-ahead on-peak LMPs increased 3 to 13% at pricing nodes in RTO/ISO markets.

State of the Markets Report FERC Natural Gas — FERC had a packed agenda for its open meeting April 19, including a presentation on the 2017 State of the Markets report. | © *RTO Insider*

While the previous two years were marked by cheap prices driven by warm winters, last year saw cold weather at both its beginning and end, with an especially severe cold snap at the end of December and into January 2018 leading to a sharp spike in prices, especially in ISO-NE. (See FERC, RTOs: Grid Performed Better in Jan. Cold Snap vs. 2014.)

Last year also marked the first since 1958 that the U.S. was a net exporter in gas, propelled by increased LNG export capacity. “The largest increase in demand for natural gas came from LNG exports, which rose from 0.63 Bcfd to 2.19 Bcfd, a 248% increase,” according to the report. Total exports to Mexico, the U.S.’ biggest LNG customer, increased by 0.5 Bcfd to an average 4.2 Bcfd for the year, aided by several new cross-border pipelines.

Gas producers also found new markets within the U.S. About 12 billion Bcfd and 773 miles of new pipeline capacity went into service last year, most of it in the Marcellus and Utica shales. “New pipeline capacity out of the Marcellus and Utica shale plays allowed producers to meet demand in previously inaccessible markets,” the report says. “These shale plays demonstrated the largest U.S. natural gas production growth in 2017, with a 10.3% year-over-year increase for a total production of 22.1 Bcfd by the end of 2017.” Total U.S. gas production rose 1.0%, averaging 73.6 Bcfd.

One of the only metrics to fall significantly was storage inventory. 2017 saw the third lowest weekly storage injection rate since 2010, while the end-of-year cold snap led to the largest withdrawal in history, 359 Bcf. The large winter withdrawals also led to the lowest end-of-winter storage level since 2014: 1.35 Tcf on April 5, 2018.

Commissioners Neil Chatterjee and Robert Powelson both noted the prevalence of gas in the report, focusing their comments on the importance of fuel security and gas-electric coordination to grid reliability.

“Staff’s report indicates that at the beginning of last year, fuel security was already a particular concern within New England and Southern California because of limited natural gas transportation and storage infrastructure, and that by last winter, those concerns had grown into real anxiety,” Chatterjee said. Noting the cold snap in the East and pipeline outages in California, “I look back at 2017 as the year of close calls that underscore the importance of examining fuel-security issues,” he said.

“The analytics … in today’s report are really a testimony to the benefits of organized markets and what they do in terms of providing reliability,” Powelson said.

He said he was concerned about the phaseout of the Aliso Canyon storage facility in California, noting the state’s aggressive renewable portfolio standard, the closure of several nuclear plants there and, in what he called “the “who-would-have-thunk-it moment,” commission-approved reliability-must-run contracts for gas units in CAISO. He called these, along with the high prices in New England, “alarming situations.”

The report was released right after FERC issued a Notice of Inquiry to review its 1999 policy statement on natural gas pipelines. (See related story, FERC Outlines Gas Pipeline Rule Review.)

April 20, 2018

FERC Order Seeks to Reduce Time, Uncertainty on Interconnections

By Rich Heidorn Jr.

FERC on Thursday ordered new rules to increase the transparency and timeliness of the generator interconnection process (RM17-8, Order 845).

The order adopts all but four of 14 potential rule changes in the commission’s December 2016 Notice of Proposed Rulemaking revising the pro forma large generator interconnection procedures and large generator interconnection agreement (LGIA). (See FERC Proposes Changes to Interconnection Rules.)

The rulemaking, which was prompted by a complaint by the American Wind Energy Association, applies to generators larger than 20 MW.

ferc generator interconnection — Blue Canyon wind farm | *EDP Renewables*

Commission staff said the revisions acknowledge the inefficiencies that have resulted from changes to the generation industry since the commission issued the pro forma interconnection procedures and agreement in 2003 (Order 2003).

“These inefficiencies include backlogs in interconnection queues, long timelines to process interconnection requests and late-stage withdrawals of interconnection requests that can lead to cascading interconnection restudies, which can lead to even more withdrawals,” staff said in a presentation at the commission’s open meeting.

It also seeks to address transmission providers’ concerns that the interconnection study process has become difficult to manage because they have been flooded with requests for new facilities that have little chance of reaching commercial operation.

The final rule removes a limitation on an interconnection customer’s ability to construct interconnection facilities and standalone network upgrades and requires transmission providers to improve their dispute resolution procedures.

To improve transparency and efficiency, the rule:

requires transmission providers to make public their methods for determining contingent facilities and to list the processes and assumptions used for network models employed in interconnection studies;
revises the definition of “generating facility” to explicitly include electric storage;
sets requirements for reporting on aggregate interconnection study performance;
allows an interconnection customer to request a level of service lower than its generating facility capacity;
requires transmission providers to allow provisional interconnection agreements that offer limited operation of a generator before completing the interconnection process;
requires transmission providers to offer the use of surplus interconnection service; and
requires transmission providers to consider changes in an interconnection customer’s proposed technology that occur during the interconnection process to determine if they constitute a material modification.

“The transparency reforms make information more timely and accessible to transmission customers, thereby potentially reducing the number of interconnection requests for projects that are unlikely to reach commercial operation,” staff said. “The efficiency and enhancement reforms facilitate the use of existing interconnection, mitigate the likelihood of unnecessary upgrades and related costs, provide paths to bring generation online more quickly, and allow for the incorporation of technological advancements into an interconnection request.”

Stakeholder comments persuaded FERC not to adopt four other rule changes requiring periodic restudies, self-funding of network upgrades, the posting of congestion and curtailment information and the modeling of electric storage.

The commission also took no action on two other issues on which the NOPR sought comment but for which no proposals were made: cost caps for network upgrades and affected-system coordination, the latter of which was the subject of a two-day technical conference in early April. (See Renewable Gens Face Off with RTOs at Seams Tech Conference.)

The American Council on Renewable Energy (ACORE) issued a statement praising the order. “While the reforms cover interconnection for all types of energy generators, we believe the final rule is an important recognition of a fundamental shift in the U.S. electric sector as we continue to diversify our electricity supply. Going forward, we are optimistic the rule will improve and expedite critical interconnection procedures for solar, wind and other renewable technologies, while also expanding access to energy storage resources.”

The rule will be effective 75 days after publication in the Federal Register.