Less than half of PJM stakeholders considering the addition of a seasonal capacity product favor a change in the current rules.
Only 48% of members who voted in the Seasonal Capacity Resources Senior Task Force poll last week favored any change, while 52% chose the status quo.
None of the five alternatives to the status quo garnered much support, with the most popular proposal — retaining the base capacity product for an additional year, delivery year 2020/21 — topping out at 43%.
Thirty-four stakeholders representing 190 companies took part in the voting.
The results of the task force’s vote were discussed at its meeting Friday. The sponsors of each option will incorporate the feedback they received into their proposals and resubmit them for reconsideration. Redlines are due Oct. 2, and the changes will be presented at the task force’s next meeting on Oct. 14. Another vote may occur shortly thereafter based on stakeholders’ response.
At question is how to allow seasonal and intermittent generation resources to offer as capacity under the tougher, year-round requirements of PJM’s Capacity Performance rules.
Although CP rules allow multiple seasonal resources to combine in aggregated offers, no such offers have been entered in auctions thus far.
PJM sought to address the issue by relaxing the current prohibition on seasonal resources aggregating across locational deliverability areas, sub-regions such as electric distribution company zones used to evaluate locational constraints.
The RTO’s proposed solution would allow resources to aggregate their production beyond LDA borders with unmatched resources moving up to the next LDA level until a match is found.
For example, an offer containing individual resources located in the EMAAC LDA and SWMAAC LDA would be modeled in the MAAC LDA. An offer with resources in COMED and EMAAC would be modeled in the “Rest of RTO.” Performance penalties would be distributed evenly between the resources, no matter which failed to perform. This proposal received the support of only 32% of respondents.
Eligible resources would include intermittent resources, storage and summer-only demand response and energy efficiency. It would define the summer period as June through October and the following May; the winter period would run November through April.
Another proposal called winter performance equivalents would auction “WIPES” credits that allow capacity resources to not perform in the winter. Created by consultant James Wilson on behalf of the Consumer Advocates of the PJM States, the proposal was opposed by PJM and received only 21% support.
The proposal’s release of 16,500 MW from their winter capacity obligations reduces operational reliability, PJM said in comments on the proposal. The RTO said a planning analysis cited by supporters “cannot capture all the complexities of real-time operations” because of its assumptions that generator forced outages are random and independent of each other. “The winter forced outage rates have exhibited a strong correlation with lower temperatures and higher loads. PJM has also observed common mode failures across generating units. For example, the disruption of a gas pipeline will force out all single-fuel gas units being served by that pipeline,” PJM said.
The RTO also said energy market costs would increase as capacity is released.
DR provider WeatherBug Home offered a solution that would create a way to measure and value seasonal DR by using the firm service level, a predetermined load reduction.
Load is currently paying for capacity that it doesn’t use, and aggregation won’t fix that, according to the proposal. Additionally, because there is far less winter demand, it will create a situation where winter assets will essentially collect “rent” by teaming with summer resources that are much more likely to be called to perform.
WeatherBug’s plan calls for maintaining the current CP rules and limiting the amount of DR that can clear the auction. All resources can participate using their capacity ratings above their must-offer commitment, but such aggregations would only be eligible for performance bonuses if the load drops below unforced capacity obligations. This proposal received the least support at 17%.
EnerNOC’s proposal was the same as PJM’s, but with a different calculation for the balancing ratio that removes what the company called an “unreasonable barrier” for DR performance calculations. The plan received 33% approval.
ALBANY, N.Y. — California’s challenge in integrating large amounts of renewable generation is illustrated by its famous “duck curve” graph. For New York, the future looks more like a platypus.
That’s how Rana Mukerji, NYISO’s senior vice president of market structures, described the impact of large amounts of solar generation on the New York grid in the winter at the ISO’s Distributed Energy Resource workshop last week.
NYISO, which released its DER Roadmap last month, held the session to open public discussion on how it will respond to the state’s Reforming the Energy Vision initiative. (See NYISO Releases Plan for Integrating DER.)
For starters, the ISO is pursuing a modest goal of planning for the next three to five years. A conceptual market structure design will be devised next year.
The roadmap, which officials described as a guide that could change as stakeholders become engaged in the process, anticipates implementation in 2021.
New York’s recently adopted Clean Energy Standard, which calls for 50% renewables by 2030, is the impetus, along with public demand for emissions-free power generation.
“We are moving very rapidly to a resource mix [that] will have intermittent resources [that] are renewable, distributed resources, and we will also have conventional generation,” Mukerji said. “I do not see conventional generation disappearing anytime soon. There is some talk of 100% renewable, but I don’t see conventional generation disappearing over the next 20 years.”
Wind generation, currently 3% of NYISO’s energy production, is projected to reach 13% by 2030.
“It took us 12 years to add 7% of renewables, but in the next 20 years we have to add 22%,” Mukerji said.
He cited projections that distributed generation without subsidies will rapidly reach grid parity. The Clean Energy Standard is going to accelerate renewable energy deployment, with solar growing from its current capacity of about 700 MW.
He added that the ISO has done simulations of up to 9,000 MW of solar in New York, which presents quite a different profile of the state’s demand in the morning and evening peaks.
“We will have needs for managing the ramping during the morning and the evening, so we might have to contemplate new products, like ramping products and load-following products in our market,” he said.
As more distributed resources are added, it will require the ability to manage bidirectional power flows.
“It will get more challenging, but in my mind it will get more interesting, and at the end of the day it gets better efficiency and it’s going to drive a cleaner, more resilient and more reliable grid,” he said.
Role of NYISO
NYISO will be charged with providing a bridge between distributed generation and the central station generators.
“We have to evolve from a corps of 400 central station generators to whatever is left of the corps of 400 with the distributed system platform, which coordinates or controls the distributed resources,” Mukerji said.
That’s where the nexus of REV and the ISO lay, with the distributed system platform, run by the utility. The ISO will not have visibility of the generation resources beyond the substation level.
“That is where the DSP will interact the with the ISO, like a super-aggregator to participate with this animated load and the sum total of the distribute resources into the markets. That is where the interaction of the DSP and the ISO is, where the coordination between the central station generation and the distributed resources happens,” he said.
FERC said MISO can continue doling out refunds to Wisconsin utilities, upholding the RTO’s new cost allocation methodology for three system support resource power plants in Michigan’s Upper Peninsula (EL14-34, et al.).
The commission’s Sept. 22 order determined that MISO’s plan to refund load-serving entities overcharged under the old methodology was satisfactory, rejecting rehearing requests that argued the commission did not have the power to order refunds.
Presque Isle Power Plant Source: WEPCo
The order stems from 2014, when FERC ordered MISO to scrap its SSR cost allocation on a pro rata basis to all LSEs in the American Transmission Co. service territory and instead assign costs to LSEs that required the White Pine, Escanaba and Presque Isle plants for reliability. (See FERC Upends MISO’s SSR Cost Allocation Practice.)
FERC accepted MISO’s revised SSR cost allocation methodology in early May, and the RTO submitted its refund reports in June. The RTO will make the LSEs whole in 14 monthly installments, which began in July.
However, the commission instructed MISO to suspend refunds for the Presque Isle SSR costs until it reaches a decision on an administrative law judge’s finding that Michigan ratepayers were overcharged by Wisconsin Electric Power Co. (ER14-1242-006, et al.). (See ATC Plan Could Eliminate White Pine SSR; Refunds Coming on Presque Isle?) MISO will then have to submit another refund report for the plant within 45 days of the commission’s decision.
FERC also directed MISO to provide “complete, un-redacted” copies of the refund reports to parties that have entered nondisclosure agreements.
CARMEL, Ind. — MISO posted the second draft of the 2016 Transmission Expansion Plan report last week, complete except for the executive summary and Appendix A2’s cost allocation explanation.
MISO’s Omar Hellalat told the Planning Advisory Committee last week that stakeholder feedback forms, which will be delivered to the Board of Directors, are due Oct. 3. The PAC will vote on approving the report Oct. 19. (See MTEP 16 Proposes 394 Projects at $2.8 Billion.)
“We’re not voting on the projects; we’re voting on the process. Did we follow it?” PAC Chair Bob McKee explained.
Meanwhile, MISO members have until Oct. 12 to respond to the MTEP 17 proposed futures, Senior Transmission Planning Engineer Matt Ellis said.
Ellis said the MTEP 17 forecast mirrors trends that showed up in MTEP 16, although MTEP 17 projects higher natural gas consumption. Ellis also said MISO is forecasting 25 GW of retirements by 2031 in the “existing fleet” scenario, 33 GW of retirements in a “policy regulations” future and 41 GW of retirements in the “accelerated alternative technologies” future.
The RTO is forecasting nameplate capacity additions of 30 GW, 58 GW and 94 GW by 2031, respectively.
The study will consider wind resource additions of 2.4 to 30 GW and solar additions of 1.6 to 14.4 GW. MISO also expects peak demand of 127 GW in 2016, rising to between 131 and 145 GW by 2031.
McKee asked what drove the renewables predictions. Ellis said MISO used information from projects in the interconnection queue and a study from renewable firm Vibrant Clean Energy that was commissioned by the RTO. (See “MTEP 17 Futures Process Enters Stakeholder Inspection,” MISO Planning Advisory Committee Briefs.)
MISO has issued a draft scope for its Regional Transmission Overlay Study. The study will identify needs to develop a regional transmission plan and identify candidate projects by 2019 using the three futures created for MTEP 17. (See “MTEP 17 Futures Finalized,” MISO Planning Advisory Committee Briefs.)
“The purpose of the study is really to get our arms around what the system needs,” said Lynn Hecker, MISO manager of expansion planning.
MISO has already received a first round of comments on the study scope, with stakeholders raising many issues, including asking the RTO to incorporate non-transmission alternatives and encouraging it to work with the Organization of MISO States. Some would like to create another stakeholder group to oversee the overlay.
Hecker, who called the comments “very insightful,” said that MISO has reached out to individual states but not OMS. Hecker said further scope development will be handled by MISO’s Economic Planning Users Group.
Adam McKinnie, chief utility economist of the Missouri Public Service Commission, said OMS would have appreciated direct discussion from MISO on possible overlay needs.
Hwikwon Ham, a staffer with the Minnesota Public Utilities Commission, said it is imperative that MISO continue to reach out to state regulators with scope information.
Stakeholders also asked to what degree the Clean Power Plan would influence the overlay. Ham said use of the CPP in the overlay should not be considered “controversial” because MISO’s resource mix is changing regardless of whether the rule survives.
In February, the Supreme Court stayed the plan pending resolution of legal challenges. Oral arguments are scheduled before the D.C. Circuit Court of Appeals for Sept. 27.
Hecker said the MTEP 17 futures will be flexible enough regardless of whether the CPP “comes back to life.”
MISO will also revisit the overlay’s future scenarios when MTEP 18 futures are developed to determine if overlay assumptions need to be refreshed.
Another round of stakeholder input on the overlay scope is due Oct. 5. MISO plans to release a finalized scope at the Oct. 19 PAC meeting and schedule the first technical study meeting in November.
MISO is planning some housekeeping on Business Practices Manual 020, which governs the RTO’s long-term planning process.
Zheng Zhou, an economic studies engineer, said the changes will only be a clean-up to reflect long-term planning practices already in place. “This section hasn’t been updated for quite some time, and we understand that this BPM is important to our stakeholders,” Zhou said.
Updates include adding to the MTEP futures development MISO’s 2015 process reforms, which allowed futures to be reused across MTEPs, and a more detailed inclusion of MISO’s seven-step value-based planning process, which identifies and tests transmission fixes.
MISO hopes to file the changes by early 2017. Stakeholder input on the updates is due Oct. 19.
CARMEL, Ind. — Stakeholders support MISO’s push to revise its cost allocation process for market efficiency projects (MEPs), but their suggested approaches are a mixed bag.
By the end of this year, MISO will release a conceptual proposal that may expand its market efficiency voltage threshold to include sub-345-kV economic projects. The proposal may also revise the current MEP cost allocation: 80% of costs to benefiting local resource zones and 20% footprint-wide. The RTO said it is considering assigning 100% of MEPs to local resource zones.
Source: Entergy
MISO plans to file the revised cost allocation rules by 2018, when Entergy’s MISO integration transition period — which limits cost sharing in MISO South — expires.
Members’ proposed changes were presented at the Sept. 20 special meeting of the Regional Expansion Criteria and Benefits Working Group.
Remove Threshold?
American Electric Power Director of Transmission Planning Kamran Ali said his company believes the 345-kV threshold should be eliminated so transmission owners begin to look for the most efficient transmission projects. “I’ll be honest: My team doesn’t look for solutions that aren’t 345 kV. There’s a very limited amount of developers that will go for projects under 345 kV,” Ali said.
He pointed to three projects ranging from 115 to 138 kV in Indiana and Louisiana, identified in MISO’s 2016 Transmission Expansion Plan, whose benefits are expected to extend across multiple local resource zones.
Attorney Jim Dauphinais, on behalf of Illinois Industrial Energy Consumers and the Louisiana Energy Users Group, said MISO should lower its market efficiency voltage threshold to 100 kV, or at least down to 230 kV.
Dauphinais said MISO’s current allocation process doesn’t recognize the value sub-345-kV economic transmission projects can provide outside of their local transmission pricing zone. He pointed to a 2015 Entergy study that found the 230-kV Louisiana Economic Transmission Project has economic benefits that bleed over both transmission pricing zone and local resource zone boundaries.
Cost Allocation Below 345 kV
Currently, costs of economic projects below 345 kV are allocated only to their local transmission pricing zones unless multiple MISO members in different zones sponsor construction.
The Organization of MISO States’ Transmission Cost Allocation Working Group said it could not support systemwide cost allocation of a sub-345-kV economic project without evidence from MISO that such projects can provide footprint-wide benefits.
Mississippi Public Service Commission staff counsel David Carr, representing the working group, said formulating a methodology for regionally allocating costs of sub-345-kV interregional projects is “of the essence” because of FERC’s April ruling in a challenge by Northern Indiana Public Service Co. The commission ordered MISO to remove its 345-kV threshold on interregional projects with PJM. (See MISO, PJM Working to Comply with NIPSCO Order.)
The MISO Transmission Owners sector said it does not have a position on whether MISO should lower the voltage requirement. However, the sector opposes a postage stamp cost allocation for projects below 345 kV, which would assess all regional transmission service customers a uniform rate based on the combined costs of all transmission facilities in the region.
Throw Out Postage Stamp?
ITC Holdings’ David Grover said postage stamp pricing is still appropriate for projects 345 kV and above and said if any change is considered, the footprint-wide postage stamp allocation should probably be raised beyond the current 20%. “Identifying beneficiaries with pinpoint accuracy is not realistic … [and] fraught with uncertainty,” Grover said. “I would argue that all networked 345-kV lines … have multiple benefits.”
Other stakeholders contend that MISO’s hourglass shape, with its constraint between MISO North to MISO South, precludes an equitable systemwide postage stamp rate.
NIPSCO engineer Miles Taylor said MISO should implement a more targeted benefit and cost allocation determination for lower-voltage projects.
Taylor said MISO should eliminate postage stamp rates and local resource zone cost allocation and implement cost allocation based on benefiting transmission pricing zones.
Dauphinais said MISO should replace all postage stamp rates with a 100% adjusted production cost allocation. He said MISO should allocate 100% of adjusted production costs at the transmission pricing zone instead of the current “coarser” local resource zone level. “We’re not going for perfection, but we need to have something at least in the ballpark. We want to make sure costs are assigned appropriately as we can,” Dauphinais said.
Ameren’s Dennis Kramer said wrestling with cost allocation is “endemic,” noting that MISO has been tweaking cost allocation of transmission projects for a decade. “There’s never going to be certainty because there’s assumptions and projections associated with this,” Kramer said.
Ameren recommended MISO “have a single MEP process that can be used throughout the entire MISO footprint.” However, Ameren said MISO’s current multi-value projects > MEPs > baseline reliability projects hierarchy is a “cornerstone of MISO’s Order 1000 compliance and should not be significantly altered.”
Ameren said a voltage threshold reduction should be investigated as part of an overall re-examination of the MEP process. The company said resource zones are probably too large for determining cost allocation while transmission pricing zones may be too small and could be combined.
Ameren also said MISO should determine whether stakeholders want additional benefit metrics — such as reduced capacity costs due to reduced peak hour transmission losses, reduced operating reserves and avoided reliability projects — included in market efficiency benefit calculations.
Kramer said Ameren has a problem if MISO re-examines costs that have already been allocated. “An [adjusted production cost] benefit metric will almost always result in winners and losers depending upon which side of the constraint the stakeholder is located,” Ameren said. Kramer also said low-cost MEPs are “probably not worth the time and expense” of MISO’s competitive bidding process.
Andrew Siebenaler, a planning engineer with Xcel Energy, said MISO’s modeling assumptions on MEPs must be carefully reviewed. Siebenaler also said inexpensive, lower-voltage projects carry less capacity, “making them more sensitive to changes in assumptions.”
[Editor’s Note: An earlier version of this article said that OMS had taken a position on cost allocation of sub-345-kV economic projects. The position was taken by OMS’ Transmission Cost Allocation Working Group. The OMS board has not taken a position on the issue.]
FERC has brushed aside a complaint brought forward by two companies about Ameren Illinois’ annual informational formula rate update and true-up (ER16-1169).
In April, Southwestern Electric Cooperative and Southern Illinois Power Cooperative challenged the $214.4 million revenue requirement rate filing on several fronts. Although FERC agreed with a few points the cooperatives raised, the complaint was dismissed.
FERC ordered Ameren to change how it accounts for contributions in aid of construction. The commission also said it is “improper for Ameren Illinois’ [net operating loss carryforward] to affect Ameren Illinois’ income tax allowance because the tax is deferred, not avoided.” The commission ordered Ameren to include net operating loss carryforward in its rate base to “reflect the fact that the company is unable to take full advantage of its favorable tax timing difference.”
The challenge also caused Ameren to agree with the complainants that it should exclude accrued tax debt, merger costs debt integration, regulatory asset amortization and regulatory liabilities for allowance for funds used during construction from its 2016 true-up.
FERC, however, denied other areas of the challenge:
The complainants said Ameren is allocating solely to transmission certain costs that involve both transmission and distribution. FERC said that while “the naming of certain accounts could be misleading,” the accounts were only related to transmission costs.
The two cooperatives said Ameren should not be allocating franchise fees to customers; Ameren responded that because the franchise fees allow transmission construction, they should be included in transmission rates. FERC said Ameren is allowed to recover franchise fees and said the particular challenge “amounts to a collateral attack on the filed rate.”
The complainants alleged Ameren’s formula rate was improperly related to its generation and distribution functions and asked for “a line-by-line review of specific entries to eliminate generation or distribution-related items.” FERC said that asking for cost to be “functionalized on a direct assignment basis instead of on the basis of an allocation ratio” amounted to challenging the formula rate itself and could only be addressed in a separate filing.
The cooperatives accused Ameren of including costs relating to retail distribution and customer services into the general and intangible plant cost allocation to transmission, which increased from $20.3 million in 2008 to $63.8 million in 2016. FERC said it found “no reason to conclude that Ameren Illinois is not properly classifying the challenged items.”
The complainants questioned the 117% jump in Ameren’s wages and salaries allocation over six years. FERC said the increase was reasonable because Ameren Illinois was using more transmission labor.
Below is a summary of the issues scheduled to be brought to a vote at the Markets and Reliability and Members committees Thursday. Each item is listed by agenda number, description and projected time of discussion, followed by a summary of the issue and links to prior coverage in RTO Insider.
RTO Insider will be in Wilmington, Del., covering the discussions and votes. See next Tuesday’s newsletter for a full report.
Markets and Reliability Committee
2. PJM Manuals (9:10-9:30)
Members will be asked to endorse the following manual changes:
Proposed clarifications to “Member/Vendor Open and Competitive Bidding” will allow flexibility for noncompetitive items, such as office supplies. Revisions to governing document update formatting in the definition sections.
5. Release of Capacity in Delivery Year 2017/18 3rd Incremental Auction (10:00-10:20)
Members will be asked to approve PJM’s proposal to use a straight-line offer curve for selling back excess capacity in February’s third intermediate auction for the 2017/18 delivery year, as recommended by the Market Implementation Committee on Sept. 14. (See “PJM’s Straight-Line Offer Curve Recommended for Capacity Sellback,” PJM Market Implementation Committee Briefs.)
6. Metering Task Force (MTF) (10:20-10:30)
Members will be asked to approve revisions to Manual 1 to close gaps in understanding between staff and members on metering rules. (See “Metering Standards Ready for Stakeholder Vote,” PJM Markets and Reliability Committee Briefs.)
7. Planning Committee Charter (10:30-10:35)
Members will be asked to approve proposed administrative updates to the Planning Committee Charter.
8. PJM Capacity Problem Statement / Issue Charge (10:35-11:35)
Members will be asked to approve Operating Agreement revisions to clarify the “Member/Vendor Open and Competitive Bidding” section to allow flexibility for noncompetitive items, such as office supplies.
3. Cost Development Guidelines Periodic Review (2:55-3:15)
Members will be asked to endorse revisions to Manual 15 that were developed as part of the periodic review process.
4. First Energy Transmission Reorganization (3:15-3:45)
CARMEL, Ind. — MISO will file a revised set of interconnection queue changes with FERC on Oct. 21, and this time it says it has “overwhelming” stakeholder support for the changes.
In its second attempt at a queue reform filing, MISO proposed that the revised M2 milestone become a flat charge of $4,000/MW of new capacity instead of the earlier $5,000/MW. The M3 and M4 fees would total 10% and 20% of any upgrade costs, respectively. MISO would settle any over- or underpayment after it completed a final facility study. (See “MISO Tries to Please FERC with Second Attempt at Queue Reform,” MISO Planning Advisory Committee Briefs.)
All but seven of the 27 members that provided feedback this month supported the three milestone payments. Nearly all members supported total milestone payments being applied to the generator interconnection agreement’s initial payment.
The majority agreed that a project should be able to withdraw penalty-free if a facility study shows costs 25% or $10,000/MW more than the system impact study’s projection. Stakeholders were about evenly split, however, on whether MISO should allow interconnection customers to decrease the number of megawatts they signed up for by 10% at the second decision point of the queue, where projects that withdraw before the first 220 days of the queue can be refunded their entire M3 payment. MISO is proposing 10% megawatt decrease options at both decision point two and the approximately 140-day decision point one, where withdrawing projects are credited their entire M2 milestone payment.
Of the 27 members who responded to MISO, 20 said they generally supported the revised queue reform proposal, five said they did not and two abstained from offering an opinion.
FERC rejected MISO’s first proposal in March, saying the RTO failed to consider other factors when it blamed the queue bottleneck on “speculative” projects. The commission also said MISO’s proposed milestone payments created a “barrier to entry” (ER16-675).
At last week’s Planning Advisory Committee meeting, MISO Director of Interconnection and Planning Tim Aliff said the RTO is responding to FERC’s order by adding more requirements for itself and its transmission owners to lessen the burden on the interconnection customer.
At this month’s MISO Board of Directors meeting in St. Paul, Minn., MISO Vice President of System Planning and Seams Coordination Jennifer Curran said the RTO is hoping to build more certainty into the process and reduce restudies and the amount of time it takes for projects to clear the queue. “It’s currently a two- to three-year process and is challenged by restudies,” she said. “We think we’ve struck a nice balance between all of the interested parties here.”
If approved by FERC, queue changes will take effect in January. Although the new queue rules have not been approved, MISO has nevertheless moved ahead with the transition, which will be fully completed after February 2017’s batch of interconnection entrants.
CHICAGO — The growth of distributed energy resources and behind-the-meter innovation will require upgrades to the distribution network, speakers told PJM’s Grid 20/20 symposium last week.
While the innovative technology driving DER was the subject of much of the daylong conference, many speakers made sure to mention the more mundane network issues as well.
Often, the distribution and transmission networks are treated “as if they’re almost identical,” said the symposium’s keynote speaker, Michael Caramanis, a mechanical and systems engineering professor at Boston University. But a major advantage of the distribution network over the transmission network is that DER capabilities can allow it to sustain a much more competitive market, he said.
While distribution networks tend to experience more unusual situations on a regular basis — a condition described as “normal abnormalities” by CAISO’s Lorenzo Kristov — they also introduce greater marginal-cost granularity across the system, Caramanis said. Using distribution locational marginal pricing (DLMP), that granularity can be harnessed.
“That granularity, if it’s projected into management of distributed energy resource behavior … may affect the aggregate demand [seen] at the transmission and distribution interface,” he said.
“Right now, we’re in a period of evolution,” explained David Owens, the Edison Electric Institute’s executive vice president for business operations group and regulatory affairs. “The goal is to try to move more toward a market. … We have peer-to-peer transaction, but somebody’s got to see all of [the transactions]. Somebody’s got to provide that platform. Somebody’s got to manage it. There’s got to be visibility. There’s got to be interoperability standards. There’s got to be an integrated information and communication system. There’s got to be a data-exchange platform. We don’t have any of that today. … We’ve got a long way to go.”
DER Issues
“The obvious environmental benefits of distributed energy resources can be thought of as being blunted … by the inability to control renewable generation and by its volatility,” Caramanis said. “The way we reward and incentivize distributed energy resources — and, in particular, renewable generation — is introducing certain non-economical choices.”
Information privacy and what he termed as “computational complexity” are also concerns. “How do we handle billions of bits of information that characterize the preferences of millions of” customers? he asked.
That complexity extends to the network as well. “The distribution wires are in abnormal configuration all the time because there are so many circuits that keep changing,” Kristov said. Yet, communication and dispatching is between the grid operator and the resource owner, leaving the distribution-network owner uninformed about the situation.
With voltage changes of 5% able to damage appliances and cause brownouts, distribution networks require careful control, Caramanis said.
Utilities aren’t accustomed to the rapid changes DER may require, speakers said.
“Utility [information technology] systems are very cumbersome, closed and expensive to adapt,” said Kristin Munsch of the Citizens Utility Board.
“We don’t want to sit there and deploy something that we’re going to go back and regret and change a little bit later,” said Ben Kroposki of the National Renewable Energy Laboratory.
And there is no guarantee that consumers will respond to market signals in the way economists would expect. “The one thing we know is people make uneconomic decisions all the time,” Munsch said. “We talk about these sort of transaction incentives and things we’re going to create with this underlying assumption that, ‘Well, all we have to do is explain it to them, and they’re going to be fine with it,’” she said. “Well, they’re not because on some level, utilities — whether it’s energy, natural gas, water — they are different. There’s an expectation they will be there when I want them, how I want them, at a price I can pay.”
Large-scale strategic companies are seeing ways to help with economies of scale, Marathon Capital’s Sarah Nash said. “A lot of these larger players who aren’t necessarily within the traditional energy space, they’re seeing ways to be able to supplement their offerings and move into the energy storage space,” she said.
On a more traditional level, local governments “are on the front lines of these things,” Owens said, and companies should “help them be ambassadors” of the system upgrades.
“Some get it; some fight it,” he said. The models are “smart cities” that have taken an active role in the process, he said.
“You’d be hard-pressed to find someone who says there isn’t overlap” between the state oversight of retail energy sales and the federal oversight of wholesale markets, FERC’s Jignasa Gadani said. “Is the new world going to be cooperative federalism? I don’t know how otherwise you move forward.”
The largest changes, however, might be in perception.
Kristov said the wholesale markets that developed in the late 1990s have created a “commodity concept” of electricity.
“I think we need to question whether that’s an adequate concept going forward because customers don’t care [about] kilowatt-hours; they care about services,” Kristov said. “The value of the grid used to be: get this commodity over here and move it over here, and that’s not the business of the distribution company anymore. It’s creating a new kind of network where the value may not be moving a commodity. It may be providing network services.”
Caramanis disputed that, saying the grid “essentially commoditizes the quality of service.”
“At the end of the day, in order for this to happen, the utility has to have the right incentives as well,” SolarCity’s Seyed Madaeni said. “We’ve got to have a paradigm shift and make sure all the incentives are aligned.”
Consolidated Edison’s Shelly Lyser added that properly valuing DERs’ environmental benefits also is important.
SANTA MONICA, Calif. — Attendees at last week’s Infocast California Distributed Energy Summit received a crash course in the complexity of developing policies on distributed energy resources in a state that already boasts nearly 5,000 MW of rooftop solar.
The takeaway: Conflicting regulatory drivers and misaligned utility business models must be addressed to ensure the value of DERs is maximized and that consumers aren’t saddled with the costs of stranded assets.
Moderating a panel on regulatory issues, Brandon Smithwood, California state affairs manager at the Solar Energy Industries Association (SEIA), let panelists weigh in on the “alphabet soup” of agency proceedings intended to foster the integration of DER.
“To us, DER is anything that’s connected to the distribution level,” said Tom Flynn, storage and DER policy manager at CAISO. “Any resource of any type, any technology. It doesn’t matter to us whether it’s in front of the meter, behind the meter — but it’s connected to the distribution grid, connected to the grid below the ISO’s grid.”
A few years ago, DER advocates expressed interest in aggregating those resources to participate in CAISO’s wholesale market, which requires participating resources to be at least a half-megawatt in capacity, Flynn said.
In response, the ISO allowed DERs to aggregate as a “virtual resource” distributed across multiple pricing nodes within the ISO’s system. That program, known by the acronym DERP — or Distributed Energy Resources Provider — was approved by FERC in June (ER16-1085). (See CAISO Tariff Change Would Extend Market to DER.)
Since then, the ISO has started another initiative called Energy Storage and DER — or ESDER. Among other things, that effort would allow developers to use storage to offset load behind the meter. Unlike other DERs such as rooftop solar, that storage could then bid demand response into the wholesale market.
Storage, “in effect, creates one of the first multiple-use applications,” Flynn said, noting that it can simultaneously participate as a supply- and demand-side resource.
Flynn noted that the California Public Utilities Commission has initiated a proceeding that explores similar issues, such as multiple-use applications; the ability to provide services to multiple entities; station power for storage; and interconnection processes and metering rules for DERs participating in wholesale markets.
Will Speer, director of electric system planning at San Diego Gas and Electric, tossed a few more letters into the regulatory alphabet soup, bringing up the CPUC’s Integrated Resources Plan and Distributed Resources Plan.
The goal of the DRP is to determine the ability of a utility’s distribution system to accommodate DER, Speer said.
“The first requirement was to complete an integration capacity analysis,” he said. “The next big piece of this is a locational net benefits analysis. It’s really looking at — for the locations of feeders — what is the locational net benefit of DERs in those spaces?”
Another component of the plan: demonstration projects to examine the locational benefits of DER and the use of microgrids.
Jim Baak, director of grid integration at nonprofit policy advocacy group Vote Solar, said the number of acronyms indicates the complexity of the regulatory landscape.
“In typical public utility code fashion … we’re very good at parsing issues into siloed proceedings and programs,” Baak said.
To provide a sense of the complexity, Baak listed the topics being treated under separate and overlapping proceedings: electric vehicles, DR, energy efficiency, interconnection rules, the renewable portfolio standard, time-of-use rates, net energy metering, general rate cases, integrated resources planning and energy storage.
That creates a lot of “conflicting drivers” for DER, Baak said.
One of those drivers is the traditional utility planning process, which focuses on loads, resources and forecasting.
Another driver is state policy objectives, which seek to reduce GHG emissions, support jobs and enhance customer choice in energy supply.
And then there’s yet another layer: customer demand and the market forces responding to it.
Although the industry recognizes consumer demand in terms of forecasting and deployment of DER, the planning process is not fully factoring in long-term changes in consumer behavior, Baak contended.
New industry entrants such as Google, Microsoft, General Electric and ADP are seeking to provide services to consumers about how they “consume, produce and think about energy,” Baak noted, asking how that development fits with the traditional utility planning structure and business model.
“If you think about it for a while … there’s not a real good fit,” he said. “We’re sort of trying to overlay this existing infrastructure that we have in the regulatory process with market forces that are happening.”
DER is comparable with the “disruptive” technologies and processes that gave rise to businesses like Uber and Airbnb, and something that can’t be forced into traditional utility structures, Baak said.
“And the one piece that I feel is missing in California is the vision for this,” he said.
Baak acknowledged that the technical proceedings seeking to identify ideal locations for implementing distributed resources are necessary for maintaining reliability. But he also wondered how well equipped they are for meeting state policy objectives and consumer needs.
“What happens when a customer wants to put in an electrical vehicle or solar system in an area of the grid where there are not necessarily grid benefits for doing so?” Baak asked.
And Baak pointed to the elephant in the room: the need to reform the utility business model, an effort that requires regulatory input and oversight.
“We do need to recognize that there’s a misalignment between the utility’s financial objectives and the policy objectives that we have here for DER,” Baak said. Utilities are being asked to defer investment in infrastructure on which they could earn a rate of return for shareholders and instead procure third-party DERs.
In May, New York regulators approved an order revamping their utility business model, creating new revenue streams tied to utilities’ willingness to become “distribution system platform providers” that plan, operate and administer markets for distribution-level services. The order creates incentives based on how well utilities meet goals for GHG reductions, system efficiency and energy efficiency. Customer satisfaction surveys of DER providers also will be a factor. (See NY REV Order Revamps Utility Business Model.)
California has put no such mandate in place, just a set of incentives and “a vague idea of where we think this should go,” Baak said.
“We have to make sure the utilities are structured in a way, and financially awarded in a way, that they support the policy goals of the state as well as the market forces that are driving this,” Baak said.
Speer concurred with Baak up to a point, contending that the state’s support of DER is focused on a goal.
“It’s not just to promote DER to promote DER, it’s to achieve reductions in GHGs,” Speer said. “I do think that vision’s out there, but there is a lot of work to be done.”
“I get a sense in everywhere that we go that we want it to happen today,” Speer continued, adding that customers will suffer without proper planning.
Baak said Vote Solar feels “a sense of urgency,” both because of the state’s climate goals and an anticipated increase in consumer demand for DER as prices decline.
CAISO’s Flynn acknowledged that “evolving customer preferences” — and not just public policies — are driving the adoption of DER.
DER owners’ desire to maximize their investments led the ISO to begin developing ways for DERs to access its wholesale markets.
The ISO is starting to see DER as a more significant supply resource, something that can both offset and serve more load.
Keeping Distribution in the Loop
But with that trend comes increased effects on the utility distribution system, which “are going to more and more affect the transmission system — and vice versa,” Flynn said.
Distribution utilities are developing the capabilities to manage those effects, but increased participation by DER in wholesale markets will require improved data transfers between CAISO and utilities, he said.
Flynn pointed out that an ISO dispatch order to a DER market participant — which puts power on the distribution grid hosting the resource — leaves the distribution utility “completely out of the loop in terms of information.”
“They don’t know what that DER is offering to provide us in the wholesale market,” Flynn said. “They don’t know that we’ve issued a dispatch instruction to them.”
That has alerted CAISO to a “major gap” in its processes: the need to improve data exchange with utilities — something just as important to the ISO, which needs to ensure a predictable response by a DER.
“I think everyone’s goal here is to optimize the use of DER,” Flynn said. “We don’t want to leave value on the table.”
Baak brought the consideration of that value into the context of the regulatory process, noting that Southern California Edison has submitted a rate case proposing more than $2 billion in distribution grid investment to facilitate increased deployment of DER.
While Baak acknowledged the need to modernize the grid, he contended that some of that investment could be displaced by using DERs more cost-effectively.
His organization is concerned that without a utility business model reformed to accommodate DER, regulators will sanction unnecessary investment in utility infrastructure that will remain as a fixed cost in the rate base for 20 years. As the growth of DER allows more customers to supply their own energy, the utility rate base will decline.
“Well, what happens to that fixed-cost recovery?” Baak asked. “Now you’re exacerbating the problem of fixed-cost recovery over a diminishing rate base. What happens to rates?”
Those issues will have to be resolved in a way that supports the state’s energy and environmental goals, Baak contended.
“We’re concerned that, because these proceedings are moving forward independently without that vision, we’re going to end up with a solution in the end that’s less cost-effective for consumers.”
