FERC delivered a split decision in approving a rate settlement on a West Virginia transmission project that was opposed by both FERC staff and Commissioner Colette Honorable.
Chairman Norman Bay and Commissioner Cheryl LaFleur said the settlement between Transource West Virginia, Old Dominion Electric Cooperative and Midcontinent MCN was more favorable to the public interest than the uncertainty of litigation (ER15-2114). Honorable opposed the Dec. 5 order, however, saying the only party to the docket truly representing the public interest was FERC staff, which opposed the settlement.
At question was Transource’s rate of return on equity for its Thorofare Creek–Goff Run–Powell Mountain 138-kV project awarded through PJM’s Regional Transmission Expansion Plan. Transource had initially proposed a 10.5% base ROE, which was reduced to 10% in the settlement. FERC staff argued a discounted cash flow analysis indicated an 8.89% rate was appropriate.
The settlement also negotiated a moratorium on changes to the base rate until Sept. 5, 2018, along with finalizing depreciation rates and clarifying the formula-rate template. Incentive rates had already received FERC approval and weren’t part of the settlement.
Noting support for the settlement from ODEC and Midcontinent, Bay and LaFleur said the commission “favors settlements, as they provide parties with certainty, reduce litigation cost, and permit parties to reach reasonable compromise in resolving difficult issues.” The 10% rate is consistent with rates approved in other recent uncontested settlements, they said, and denying it might upset the settlement’s other agreements. Staff’s DCF analysis would certainly be challenged in litigation, which might produce a rate well above the settled one, they said.
Honorable noted language in FERC’s approval of one of the recent uncontested settlements that describes “a case where the commission staff is the only participant to represent the interests of the ultimate consumer.”
“This settlement is the situation envisioned by the commission,” she wrote in her dissent. “Based on the record in this proceeding, I am unable to conclude that the settling parties represent all aspects of the public interest.”
While ODEC had intervened in the case, Honorable said she couldn’t determine whether the cooperative would be allocated any costs for the project, thereby giving it little stake in the case’s result and reducing the significance of its acceptance of the settlement. Staff’s determination, she said, should have received more consideration and ultimately informed the commission’s decision.
FERC dismissed a complaint seeking to overturn the results of MISO’s 2016/17 Planning Resource Auction but ordered the RTO to specify how it calculates the sub-regional transfer constraint in its Tariff.
The commission found the RTO didn’t violate its Tariff when it calculated its sub-regional export constraint for the 2016/17 auction by subtracting firm transmission reservations from the initial 2,500-MW South-to-North transfer limit (EL16-112).
A coalition of MISO transmission customers made the complaint in September, arguing that the RTO’s PRA limits are too strict and drove up clearing prices by trapping capacity in MISO South. MISO defended its method and said it plans to reuse it in future capacity auctions. (See MISO Recommends No Change to Transfer Limits.)
The commission said the RTO acted correctly and that no refunds were warranted. “MISO’s approach considered the [SPP] settlement agreement and the transmission service reservations in the prevailing direction found therein. Despite claims that other approaches could, or even should, have been used, there is no evidence to suggest that MISO’s calculation of the sub-regional export constraint was inconsistent with its Tariff provisions,” the Dec. 6 order said.
However, FERC ordered MISO to specify in its Tariff the methodology used in sub-regional export and import constraint calculations. The commission said the RTO must provide the methodology by the end of January “in order to accommodate the ongoing stakeholder process and allow MISO’s filing to be informed by it.”
Tariff revisions are also to include a formula for going-forward costs. In its complaint, the MISO transmission customers asked FERC to audit offers into the 2016/17 auction, claiming some facility-specific reference levels — which are based on going-forward costs — were too high. FERC declined, saying costs to operate and maintain MISO’s aging generation fleet would naturally rise, but it told the RTO to describe how going-forward costs are established.
CAISO has narrowed a proposal to protect smaller transmission owners from high costs for network upgrades to interconnect generation serving load outside the TOs’ service territories.
The revised proposal seeks to more specifically target the situation confronted by Valley Electric Association. Any policy changes would likely also apply to other small TOs added by the ISO through regional expansion. (See CAISO Plans to Protect Small Utilities from High Network Upgrade Costs.)
CAISO is seeking to create a plan to shield small transmission-owning members like Valley Electric Association from costly transmission upgrades associated with generators not serving the utility’s customers. | Valley Electric Association
Valley Electric — CAISO’s only out-of-state member — serves 45,000 customers and about 100 MW of load in a 6,800-square-mile region straddling the California-Nevada border.
The utility’s service area sits within an area considered promising for new renewable development that would serve other parts of the ISO. Two projects with a total capacity of 100 MW await interconnection with the Valley system, with more expected to enter the queue, according to the ISO.
Under CAISO’s Tariff, a TO must reimburse generator interconnection customers for the costs of local reliability and deliverability network upgrades necessary to connect a generating unit to the transmission network.
Upon regulatory approval, the TO can include those reimbursement costs in its rate base — passing them on to ratepayers through either a high-voltage or local low-voltage transmission access charge (TAC). The ISO considers any line under 200 kV to fall into the latter category.
Postage Stamp
While CAISO’s high-voltage TAC is allocated to all ISO ratepayers at a “postage stamp” rate based on the aggregated revenue requirements of all TOs owning high-voltage transmission, the low-voltage TAC is charged only to customers within the service area of the TO owning the facilities.
That arrangement can burden ratepayers in low-population service areas who are forced to bear the low-voltage network upgrade costs for generation intended to serve other, more populous locations attempting to meet renewable mandates.
“So the question — through this initiative — that we ask is, ‘Does this current mechanism for network upgrade cost recovery appropriately allocate costs in accordance with FERC’s allocation principles?’” Bob Emmert, CAISO manager of interconnection resources, said during a Dec. 5 call to discuss the latest version of the proposal.
The revision scales back what the original proposal offered for stakeholder consideration, including eliminating a proposed cost recovery provision that would have enabled all TOs regardless of size to roll “generator-triggered” low-voltage upgrade costs into its high-voltage revenue requirement to be recovered through the high-voltage TAC.
Under the revised proposal, only small TOs would be allowed to fold generator-driven low-voltage costs into their high-voltage revenue requirements.
The exception: when a generator is being built to serve the TO in some manner. Associated costs would then be put into the TO’s low-voltage TAC rates.
“After reading [stakeholder] comments, the ISO came to agree that the current cost allocation rules have resulted in appropriate cost allocation overall — and they continue to work for generator interconnections for the large load-serving entities,” Emmert said.
Based on input from most stakeholders, the updated proposal narrows its focus, only addressing the specific circumstances of utilities such as Valley Electric.
Options
The revised proposal sets out an “Option A” that would require the ISO to determine on a case-by-case basis whether a candidate TO should be allowed to fold low-voltage generator interconnection costs into high-voltage transmission revenue requirements, thereby diffusing the costs among the ISO’s rate base. The ISO would make its determination based on whether the TO is:
Very small relative to other TOs;
Located in a renewable resource-rich area gaining “elevated” interest for generator procurements; or
Not subject to a renewable portfolio standard or has already met its requirements.
Each TO entering the ISO under that option would have to be approved by both the Board of Governors and FERC.
A more “formulaic” Tariff-based “Option B” would retain the second two points from Option A but specify that a TO’s annual gross load be no larger than 5% of the gross load for the ISO’s largest TO. Valley Electric’s load represents 0.6% of the largest TO.
“This is the criteria that was going to be the most consistent,” Emmert said. “We’d considered using a comparison against the ISO’s annual gross load, but the ISO could grow and that might change. We felt that the largest [TO] is going to remain the largest [TO] and that would remain pretty consistent over time.”
Lee Terry of California’s State Water Project expressed concern that some generation interconnected with Valley Electric’s low-voltage system could be built to serve nearby Las Vegas, rather than ISO load.
“My knee-jerk reaction would be that we would consider that to be the same as if it were serving the [participating transmission owner] in some manner,” said Bill Weaver, an ISO attorney. “Maybe we should consider broadening that [provision] to non-CAISO [TOs] rather than the [TO] itself.”
‘Strong Support’
Southern California Edison’s Fernando Cornejo expressed his company’s “strong support” for the latest draft of the proposal.
“SCE commends the CAISO for taking a more surgical approach to a cost allocation issue that we do believe is very exceptional and unique to a Valley Electric Association type of situation,” Cornejo said. “We believe that the existing cost allocation and the bifurcation between high-voltage and low-voltage upgrades has been long-established through the cost structure and pricing paradigm that’s been in place for several decades.”
Not all utilities were as satisfied.
John Newton, a regulatory analyst with Pacific Gas and Electric, said his company opposed the ISO’s decision to scrap the cost-allocation option that would have allowed all utilities to roll low-voltage generator interconnection costs into the high-voltage TAC.
While PG&E was “sympathetic” to Valley Electric’s concerns, the allocation methodologies had been in place since the Nevada utility had joined the ISO, Newton said.
For that reason, PG&E supported the scrapped option, which he called a “non-discriminatory policy change which would fairly treat interconnection costs the same for all transmission owners” participating in the ISO.
“We’re disappointed with these Options A and B and it’s unacceptable to PG&E,” Newton said.
AUSTIN, Texas — ERCOT’s Technical Advisory Committee last week approved a revision to the ISO’s planning guide that some stakeholders called the most important policy change this year.
The planning guide revision request (PGRR042) changes the criteria used to determine the need for new transmission projects. It defines considerations for selecting the most appropriate demand forecast in planning studies and how to address certain generation resources, such as switchable and mothballed units, in planning cases.
The change also describes how to incorporate new generation units in sensitivity analyses when they have interconnection agreements, but have not met all the requirements to be included in transmission-planning studies.
[Editor’s Note: An earlier version of this story incorrectly stated that the rule change would require a 2,800-MW reserve and spell out maximum dispatch levels for wind and solar generation. Those provisions were deleted from the revision that was approved by the TAC.]
“It’s critically important to have balance in our planning process, because we’ve observed transmission costs and the transmission projects this planning criteria applies to are some of the most expensive items this stakeholder body reviews and approves,” said Reliant Energy’s Bill Barnes. “It has an impact on the cost to consumers, it has an impact on the market … there has to be some balance in the planning process. [The change] makes a lot of sense and is a huge step forward in how we think about planning the transmission system, and being responsive to the needs of the competitive market.”
“This is perhaps the most meaningful transmission reform since I’ve been involved with ERCOT,” said Shell Energy’s Greg Thurnher. “I don’t know that ERCOT has had discretion in the past to push back on some of the inputs to the planning process.”
The TAC approved the PGGR, which has been two years in the making, by a 24-4 vote with one abstention. ERCOT’s board of directors will take up the measure during its Dec. 13 meeting.
Cost Concern
The revision drew some pushback from stakeholders concerned about a revised impact analysis filed in October that indicated the need for two additional full-time positions at an estimated cost of $260,000-280,000. Committee members asked ERCOT staff to “beef up” its business case for the two positions before the board meeting.
Jeff Billo, the ISO’s senior manager for transmission planning, said the new staff is necessary to address increased responsibilities and workload being placed on his department and ERCOT’s forecasting unit, each of which would receive one new employee. The latter group’s work task is complicated by creating forecasts for ERCOT’s non-opt-in entities (Austin Energy, San Antonio’s CPS Energy and the Lower Colorado River Authority) and differences between the ISO’s use of coincident forecasts and transmission providers’ reliance on adding up individual substation forecasts.
“Part of the work in my group is not only [performing additional sensitivity] studies, but working with the load forecasting group to ensure we’re providing the proper load forecast,” Billo said. “The additional FTE is making sure we get the numbers right with our load forecasts.”
“The bottom line is this will affect the [administrative] fee,” the LCRA’s John Dumas said.
Transmission lines | ERCOT
Barnes said he was sensitive to Dumas’ concerns, but said the cost “pales in comparison to the benefits this rule change will give us.”
‘Pretty Compelling’
Noting ERCOT’s Tier 2 transmission projects cost at least $50 million, Barnes said, “If we find through this rule change that this saves one unnecessary Tier 2 project of $50 million anytime in the next 100 years, it will have met the criteria for the cost-benefit case, and that’s pretty compelling.”
Responding to a comment that recalled ERCOT saying it wouldn’t raise its admin fee for the next several years, ERCOT COO Cheryl Mele said, “Hopefully, two FTEs is not enough to damage that expectation going forward.”
Some TAC members also raised questions about the proposed use of the “bounded higher of” load forecast methodology—in which ERCOT will compare its load forecast with the summed bus-level forecast for each weather zone. A motion to table PGRR042 for a month was easily defeated by a 21-7 margin, with one abstention.
“We’re interested in working through and talking about whether the higher-up bounding methodology makes sense,” said Luminant Generation’s Amanda Frazier. “There are a lot of open questions around … whether there should be different values between weather zones … we are concerned about codifying the process before that discussion happens.”
The TAC’s endorsement will allow staff to use the new planning methodology as it begins developing the 2017 Regional Transmission Plan in January. Following next year’s “test drive,” the methodology will become effective in 2018.
“Going to board now allow us to get started with 2017 planning under the new assumptions and studies,” Billo said.
Millennium Pipeline has taken New York to federal court to force action on a gas line needed for an under-construction power plant entangled in a corruption scandal (16-1415).
In a 32-page brief filed Monday with the D.C. Circuit Court of Appeals, the company says the state Department of Environmental Conservation is sitting on a water quality permit for a 7.8-mile lateral needed to supply the Valley Energy Center plant being built by Competitive Power Ventures in Orange County.
The department must issue a Section 401 Clean Water Act permit for the project to proceed. Millennium says the department has ignored deadlines under the CWA, Natural Gas Act and a FERC order.
“By failing to act within a year of receiving Millennium’s permit request, the department thus has waived its authority to deny that request,” the suit says. “FERC set an Aug. 7, 2016, deadline for all decisions on federal authorizations relating to the Valley Lateral Project. The department missed that generous deadline by more than three-and-a-half months (and counting).”
FERC issued a certificate of convenience and public necessity for the line Nov. 9 (CP16-17).
Artist rendition of CPV Valley Energy project | CPV
The $39 million Valley Lateral project would connect the plant to Millennium’s main pipeline through the Lower Hudson Valley. State and NYISO officials say the plant is needed to relieve generation and transmission constraints to serve the capacity zone north of New York City.
Millennium applied for the water permit in November 2015. DEC issued a Notice of Incomplete Application in December 2015 and a second NOIA in June, to which Millennium responded Aug. 31.
A DEC spokesman said the department does not comment on matters under litigation.
The department told Millennium on Nov. 18 that it had received the pipeline’s response to its second NOIA and that its review of the project was ongoing. The department said it has until Aug. 30, 2017, to issue the permit, in effect arguing that the one-year deadline for action restarted when it received the response to the second NOIA in August.
The $1 billion, 650-MW generating plant, which has been opposed by environmentalists, also has a role in an ongoing political scandal that resulted in the indictment of Joseph Percoco, a former top aide to Gov. Andrew Cuomo.
CARMEL, Ind. — MISO will spend $1.8 million on consultants to evaluate how its aging market system can be improved to respond to stress and future threats.
Jeff Bladen, executive director of market services, said it was hard to put a date on when MISO’s market system will hit its limits, but if it isn’t overhauled, it could fail in five to seven years.
Bladen told the Market Subcommittee on Nov. 29 that some of the code in the RTO’s late 1990s software platform dates back to the late 1980s. “It’s a very dated software architecture for what it’s used for today,” Bladen said. “You can install airbags into a 1950s Chevy; it doesn’t mean the car is safe. … Frankly, we’re not the only RTO having these challenges.”
Bladen said MISO and consultants will be studying the effects of changes such as increased intermittent and behind-the-meter generation and increased combined cycle units.
“I do want to stress that we see no risk to reliability in the near term,” he said.
The $1.8 million in funding will be used to cover a series of independent and third-party studies from November to April, with the first 30-day study examining if MISO’s planned efforts are enough. MISO plans to spend $1.1 billion on information technology between 2015 and 2019.
Bladen said the aim of the studies is to provide the Technology Committee of the Board of Directors with “a complete and comprehensive view of the limitations and viability of current market systems.” He said MISO will make reports on its findings to the committee during the first three board meetings in 2017. Bladen said he did not expect an immediate “huge” investment to be revealed at the meetings.
Market Improvements Continue in 2017
MISO’s Mia Adams reported that three Market Roadmap projects were completed in 2016 and six projects are planned for 2017.
In 2016, MISO expanded its day-ahead market coordination with PJM with a firm flow entitlement exchange process and introduced pricing floors to its emergency pricing structure.
It also rolled out a product allowing generators to voluntarily set aside ramping capability for fleet flexibility during peak hours compensated by MISO at no more than $5/MWh. Chuck Hansen, of MISO’s market evaluation design group, said the ramp product has been delivering “tangible benefits” since its May launch, with projected annual savings of $4.2 million in resource production costs and reserve shortage price spikes.
For 2017, MISO plans to:
Make improvements to its day-ahead reliability assessment commitment software.
Control power swings caused by market-to-market dispatch.
Improve MISO-PJM interchange modeling and pricing.
Tighten thresholds for uninstructed deviation. Jason Howard, MISO market quality manager, said strengthened thresholds for uninstructed deviation are still under review for their impacts. Proposed changes, draft Tariff language and analysis results will be readied in early 2017. (See Monitor Again Criticizes MISO’s Uninstructed Deviation Rules.)
Introduce the second phase of its extended locational marginal pricing, which will expand price-setting eligibility to online resources with a one-hour start-up time. MISO’s Congcong Wang said the expansion had stakeholder support because it was a change the RTO could adopt without new software and captured about 60% of peaking resources. A FERC filing is planned in the first quarter with testing to begin in the second quarter. (See “MISO to Expand ELMP Price Setting, but not to IMM’s Specs,”MISO Market Subcommittee Briefs.)
Launch MISO-PJM coordinated transaction scheduling. MISO’s Beibei Li said the product should come online in October 2017, after vendor General Electric delivers the software sometime in December and the RTOs spend time testing it. (See “MISO-PJM Coordinated Transaction Scheduling Delayed,”MISO Market Subcommittee Briefs.)
Additionally, MISO research and development adviser Yaming Ma said the RTO will publish a study by July on automatic generation control to better use fast-ramping resources. The project was identified as high priority in 2015’s Market Roadmap classification, and a two-stage study began in September. Ma said design details would likely emerge in late 2017, but first MISO will use a prototype to develop strategies for storage resources that may have limited amounts of power on hand.
DTE Energy market developer Nick Griffin asked how fast resources must be to be included in automatic generation control. Bladen said while MISO would use battery storage as “proxy speed, MISO will test a small gamut of different response speeds.”
BOSTON — New England appears poised to withstand another winter of tight natural gas supplies, an ISO-NE official told the RTO’s Consumer Liaison Group meeting on Thursday. Other speakers debated whether states’ renewable portfolio standards are demanding enough to meet climate goals.
Anne George, ISO-NE vice president of external affairs and communications, said the 342,000-dekatherm Algonquin Incremental Market project just went online, and while it’s primarily meant to serve local distribution companies’ natural gas customers, it should ease system constraints for power generators.
“But as we see [the 1,517-MW] Brayton Point station retire [next June], we see the additional gas capacity going away as a large non-gas resource will likely be replaced by more gas generation,” she said.
Overall consumer costs for electricity have remained relatively flat for New Englanders over the past six years, even as more charges have been added to the distribution side of the bill. Electric distribution companies and their customers are responsible for funding public policy as renewable standards, including the cost of solar carve-outs, energy efficiency and other programs grow, said Jim Bride, president of Boston-based Energy Tariff Experts.
“Transmission charges have gone up a lot. So, there’s this increasing cost wedge, whether it’s renewables or other mandated charges over transmission that’s taken up a greater portion of the bill. What has allowed that to happen without consumers really noticing is the decrease in natural gas prices. Wholesale market power costs are down significantly,” he said.
Massachusetts lawmakers abandoned an effort to increase the state’s RPS this year to further reduce greenhouse gas emissions.
Ron Gerwatowski, an advisor on energy policy and utility regulation and former assistant Massachusetts energy secretary, said the renewable energy credit market that has driven clean energy projects needs further study and more recent data, noting that complete regionwide figures are about three years old. Another area worth more study is the impact of high alternative compliance payments in Massachusetts. The $67 cap draws RECs away from neighboring New Hampshire, Connecticut and New York, potentially leaving them short of meeting their own goals.
“Will an increase in annual obligations really achieve emissions reductions? Or, will it just cause a reshuffling of where the RECs are sold over time? I’m not suggesting we eliminate the RPS … but we really do need a comprehensive study before states consider raising them,” he said.
Greg Cunningham, vice president and director of clean energy climate change for the Conservation Law Foundation, said the two largest New England states, Massachusetts and Connecticut, are mandated to reduce greenhouse gas emissions by 80% below 1990 levels by 2050. From that, the Integrating Markets and Public Policy initiative was born to help markets assist all of the states to reach their climate goals.
“We, CLF, have watched as slowly clean energy has been built out, but at a trajectory that doesn’t come close to meeting this essential obligation — that is not only law, but [what] the science dictates we must do — to avoid the worst implications of climate change,” he said.
CAISO’s internal Market Monitor is proposing new enforcement measures to address market power concerns in the Energy Imbalance Market — an effort that could help participants win market-based rate authority in the West’s only real-time energy market.
The Monitor’s efforts come in response to FERC rulings limiting nearly all of the EIM’s current participants to transacting at cost-based rates — the result of the commission’s ongoing concerns about manipulation in the nascent market.
“We’ve been working with the [EIM] participants and the ISO to address the various concerns that FERC articulated so [participants] could refile and get market-based rates,” Eric Hildebrandt, director of CAISO’s Department of Market Monitoring, told a Nov. 30 meeting of the EIM’s governing body.
Hildebrandt pointed out that FERC now requires all prospective EIM members to file for market-based rate authority before joining the EIM — even if those entities already exercise that authority in the rest of the West.
“At the Market Monitor, we actually think it’s a very good thing — as long as the conditions are competitive — to have the full flexibility of bidding that is afforded entities which have market-based rates,” Hildebrandt said.
That flexibility has so far been elusive for three out of the four current EIM members.
Denials
FERC denied NV Energy and PacifiCorp — both subsidiaries of Warren Buffet’s Berkshire Hathaway Energy — EIM market-based rate authority in a November 2015 ruling that cited the companies’ failure to employ sufficient tests demonstrating their inability to wield economic power in their portions of the imbalance market (ER15-2281). The commission rejected Arizona Public Service in an August 2016 ruling (ER10-2437).
In both instances, the commission said it could not rely on CAISO’s market monitoring and mitigation to sufficiently address market power concerns in the EIM. All three utilities were invited to reapply for market-based rate authority once they could provide an additional 12 months of operational data demonstrating whether or not they possess market power.
FERC is concerned about the potential for EIM participants to engage in physical or economic withholding of generating resources in areas of the EIM subject to transmission constraints — wide areas dominated by generation owned by EIM members themselves.
Physical withholding can involve a supplier not bidding lower-cost resources into the market in order to allow higher-cost units to set clearing prices. This risk arises from the fact that the EIM has no must-offer requirement.
Economic withholding occurs when a unit bids into the market above its marginal costs in order to elevate the market price.
Monitor’s Proposals
CAISO has attempted to address this risk through automated bid mitigation procedures that kick in when transmission congestion limits supply into an EIM area. But FERC expressed concern that the ISO might not enforce the market constraints required to trigger mitigation.
To address the commission’s concerns about physical withholding, the Monitor suggests that the ISO improve the EIM’s outage reporting rules by logging when plant outages are submitted by market members for non-physical reasons. In short, the ISO must have more visibility into EIM outages, Hildebrandt said.
To counter economic withholding concerns, the Monitor recommends that the ISO step up enforcement of local market constraints in specific EIM areas and provide FERC an explanation when it decides not to enforce them.
Hildebrandt said the Monitor will heed a commission request that it comment on market-based rate authority proceedings, something the department hasn’t done in nearly a decade, he noted.
Puget’s Success
Lessons can be learned from Puget Sound Energy’s successful effort to obtain market-based rate authority in the EIM, Hildebrandt said (ER10-2374).
The commission determined that Puget provided sufficient evidence that its limited link to other EIM areas would not become constrained frequently enough to create a submarket requiring specific measures to mitigate market power.
A significant factor in gaining approval: Puget’s commitment to providing 300 MW of firm transmission to the market at all times. Other EIM members committed a “less certain” volume of transmission to the market, Hildebrandt said.
“I think the key there is the amount of potential transmission,” Hildebrandt said. “If they can satisfy to FERC that it’s going to be offered or available all hours, that would seem to play a big role.”
Hildebrandt said Puget’s approach could provide a template for how the ISO can work with other members to help them win FERC approval.
The EIM’s continued expansion should go a long way in assuaging FERC’s concerns about the interplay between transmission constraints and local market power, according to Hildebrandt. The Monitor’s own analysis indicates that the addition of NV Energy a year ago created enough additional transfer capacity to ensure competitiveness in all EIM balancing authority areas during nearly all hours.
That additional capacity is translating into increased flows between EIM areas, making the market more competitive, Hildebrandt said.
Map illustrates average transfer capacity throughout the Energy Imbalance Market since Arizona Public Service and Puget Sound Energy joined the effort in October. | CAISO
“Now with multiple connections between the ISO and the EIM, you really have to have congestion on multiple constraints at the same time to isolate any one area,” he said. If congestion occurs at one constraint, energy can be scheduled around it to supply the affected area.
“You’re really operating as one single market on a system basis throughout most — if not all — of the EIM,” Hildebrandt said.
MISO and PJM’s targeted market efficiency project portfolio has dipped from seven projects to five.
The latest project to drop off is the Marysville-Tangy 345-kV upgrade in central Ohio, which was supposed to deliver $122 million in benefits at a “minimal” cost. PJM and MISO staff have since learned that the line’s emergency rating will be increased by the end of this year, eliminating the need for a congestion-relieving fix.
The Klondike-Purdue 138-kV project in north-central Indiana was also scrapped this fall after RTO staff discovered the congestion the project was aimed at relieving was merely outage-driven. (See MISO, PJM Move Forward on TMEPs; 6 Projects Planned.)
The five remaining projects are expected to cost $14.45 million and deliver $100 million in benefits, a 6.9:1 benefit-cost ratio. The original seven-project TMEP package was expected to cost $19 million and deliver $117 million in benefits, a 6.2:1 ratio.
Twelve flowgate projects were initially considered in MISO and PJM’s TMEP analysis.
During the Dec. 2 MISO-PJM Interregional Planning Stakeholder Advisory Committee conference call, PJM engineer Alex Worcester said the RTOs will continue to monitor the Marysville-Tangy project site to see if it could use future improvements.
“We’re still looking at a $100 million benefit for [less than] $15 million in this portfolio of projects,” Worcester added.
There are no recommended changes to the other five projects, MISO and PJM staff said.
WPPI Energy’s Steve Leovy said he wanted more information on how the TMEP costs and benefits were calculated. “Based on [the dropped projects], the benefit metric could have changed significantly,” Leovy said.
Leovy also said he would like the TMEP cost-benefit calculation to resemble the benefit analysis used in MISO’s Market Congestion Planning Study. Leovy said when the TMEP project creation is filed with FERC, he will recommend WPPI make a filing asking the commission to consider making MISO use the Market Congestion Planning Study’s benefit analysis for TMEPs.
MISO engineer Adam Solomon disagreed, replying, “We think having separate benefits metrics is OK.”
Ohio regulators recently provided $600 million to FirstEnergy, the state’s largest utility. Although the decision was labeled as a “distribution modernization rider,” the money seemingly came with no strings attached, meaning the utility giant need not do anything to update or improve its system of wires and transformers.
Even the chairman of the Public Utilities Commission of Ohio, Asim Haque, described the decision as “undoubtedly unconventional.” His rationale for the subsidy was that FirstEnergy could not modernize its grid until it reduced its debt, which would allow it to obtain a better credit rating, which, in turn, would lead to lower financing costs for future grid investments — if they occur.
That line of thinking led to the $600 million decision, raising six questions.
First, rather than advance grid modernization in the state, has the decision actually set it back? FirstEnergy will not spend any of the money on near-term upgrades. Plus, other electricity companies will avoid investing in Ohio, as regulators are showing a preference for the incumbent utility monopolies. Innovative entrepreneurs will not risk their capital when regulators have stacked the market against them.
Second, should we reward a utility’s poor management? FirstEnergy needed to reduce its debt because its executives made bad business decisions, particularly buying up old coal-fired power plants at the very time the price of natural gas was falling, making those plants uneconomic. Rather than reduce executive bonuses or trim generous dividends to shareholders, regulators sent the tab to customers, every one of whom must pay $36 more per year to cover FirstEnergy’s mistakes. Regulators are signaling more interest in a utility’s pleas than its performance.
Third, how much will Ohioans really have to pay? Since every other utility in the state is now lining up to get the same deal regulators gave to FirstEnergy, the cost will certainly be much more than $600 million.
Fourth, doesn’t the subsidy distort regional power markets? FirstEnergy originally asked for money to cover power purchase agreements that would support the continued operation of its uneconomic (and dirty) power plants. Federal regulators objected, saying such a subsidy would distort competitive markets. To skirt those objections, the utility then asked for the subsidy to go to a different subsidiary instead. The effect, however, is the same — state regulators have provided a competitive advantage to FirstEnergy’s generators. As a result, FERC will need to decide if such a “virtual PPA” also illegally disrupts regional markets.
Fifth, is there true corporate separation between FirstEnergy’s generation and distribution subsidiaries, as required by Ohio’s deregulation law? As mentioned, FirstEnergy diverted the subsidy, directing the money away from its generation units to its distribution companies. Those subsidiaries, ironically, are doing very well financially, largely because they are monopolies that enjoy guaranteed profits. Although state law requires arms-length dealings among the utility’s subsidiaries, the subsidy came in through a different door but ended up in the same house. In effect, it is still propping up FirstEnergy’s economically challenged generation units that are not able to compete in regional power markets.
Sixth, should utilities get something for nothing? Ohio regulators did “not place restrictions on the use” of the subsidy and said FirstEnergy could use the funds to cover “outstanding pension obligations, reducing debt or taking other steps to reduce the long-term costs of accessing capital.” Almost as an afterthought, PUCO also said FirstEnergy could use the subsidy “to indirectly support grid modernization investments.” The operative word, of course, is “indirectly,” noting the utility need not show any connection to grid modernization efforts. Put another way, Ohioans are paying millions of dollars for something they have no guarantee of receiving.
Such questions suggest a simple subsidy prompts ripple effects that set back grid upgrades, hurt customers and distort competitive markets. The PUCO chairman has said he wants to move beyond the subsidy debate so regulators can focus on modernizing the grid. Perhaps the question he should be considering is, what are the investments and innovation needed to build a cleaner, more affordable energy system?
Dick Munson is director of Midwest Clean Energy for the Environmental Defense Fund.
Fifth, is there true corporate separation between FirstEnergy’s generation and distribution subsidiaries, as required by Ohio’s deregulation law? As mentioned, FirstEnergy diverted the subsidy, directing the money away from its generation units to its distribution companies. Those subsidiaries, ironically, are