VALLEY FORGE, Pa. — PJM staff is recommending a 27% winter reserve target, the same value adopted last year, as the RTO plans for generator maintenance.
The target is based on unit summer ratings and expressed as a percentage of the forecasted weekly peak load. It is derived from simulations of the 13-week winter period.
In coordinating generator maintenance schedules, operations will seek to preserve a 27% margin after removing planned outages. This margin is a guide and not an absolute requirement.
The Operating Committee will be asked to endorse the target at its Nov. 3 meeting.
PJM has scrapped a proposed change to rules on long-duration transmission outages over concerns that it may be too restrictive for legitimate outages that cannot be planned in advance.
The current rule — which aims to identify long-term outages for the annual financial transmission rights auction — requires that outages scheduled for longer than 30 days be reported by Feb. 1 of the prior planning year.
PJM had considered amending the rule to also apply to individual outages totaling more than 30 days within an eight-week period.
Instead, PJM will monitor to ensure no one is circumventing the 30-day rule by breaking up long outages into multiple notices, said PJM’s Simon Tam.
If activity is detected that appears to go against the spirit of the rule, PJM will work with the transmission owner and enlist the Independent Market Monitor as necessary.
Proposal Aims to Increase Training, Certification Compliance
The System Operations Subcommittee has reached consensus on a PJM proposal designed to increase compliance with training and certification requirements, said Glen Boyle, manager of system operator training. (See “PJM Moves to Tighten Training, Certification Requirements” in PJM Operating Committee Briefs.)
Boyle said the subcommittee agreed with a proposal PJM presented at its Sept. 30 meeting that would quantify a company’s non-compliance and set an escalating set of responses.
If an operator is out of compliance, the company liaison and its Members Committee representative would be notified. The company’s compliance score would be based on a count of operators and months out of compliance.
For example, a company with one operator out of compliance for two months and a second operator out of compliance for three months would have a compliance score of five.
A score of five would trigger a written warning from PJM’s legal department. If the company’s score remained at five or above the following month, it would be reported to FERC as a violation of the PJM Operating Agreement and Tariff.
PJM also would require that operators who are out of compliance not be permitted to work their shifts.
NORTH LITTLE ROCK, Ark. — Arkansas environmental and utility regulators began a dialogue with stakeholders on how to comply with the Environmental Protection Agency’s Clean Power Plan in an all-day workshop Friday at the state’s Department of Environmental Quality headquarters.
ADEQ and the state Public Service Commission gathered with a diverse group that included representatives from MISO and SPP, environmentalists, and trade groups. The group discussed their reactions to the carbon emission rule and how to create an efficient stakeholder process.
“The process is undefined,” said PSC Chairman Ted Thomas, “but that’s why we’re here today.”
“Engagement is very important to us,” ADEQ Director Becky Keogh said. “We want to engage with as many stakeholders as we can.”
ADEQ and the PSC have been charged by Arkansas Gov. Asa Hutchinson with crafting a strategy that takes into account carbon dioxide reductions already underway, maintaining the “remaining useful life” of the state’s power plants and “limiting the EPA’s opportunities for overreach and encroachment upon the state’s rights.”
Thomas and Keogh have met in recent weeks with EPA Administrator Gina McCarthy and Janet McCabe, the agency’s assistant air administrator. They have also attended meetings in other states to gain additional perspectives.
The state envisions a steering committee leading the strategic effort, with a policy committee and three subcommittees focused on those areas with the most impact: the economy, the environment and the electric grid.
EPA released its final rule in August, giving states until September 2016 to decide whether to submit a final plan or an initial strategy requesting a two-year time extension. States that fail to submit a plan by September 2018 could find themselves under a federally implemented plan.
Arkansas is among the states suing to block the rule, although it saw its CO2 reduction requirements eased from 44% in the draft rule to 36% in the final. The targets, which must be reached by 2030, are based on a 2005 baseline.
“We moved from a very difficult position to the middle of the pack,” Keogh said.
SPP’s Lanny Nickell, vice president of engineering, was among those urging the state to consider a request for a two-year delay.
“We respect a state’s right to litigate, but we also believe we have to develop something on a parallel path in case the litigation is not effective,” said Nickell, who’s been leading SPP’s CPP compliance effort. “I ask that Arkansas work with us early and often in the process. We have to prepare the grid for whatever happens. The earlier we get some sense of what’s being planned, the better off we’ll be.”
Representing the other RTO in the room, MISO’s David Boyd said, “We will try and assist the state in implementing plans, but timing is still a problem. We do see a lot of transmission infrastructure and gas infrastructure [needs] and issues with design and permitting.”
Both Nickell and Boyd recommended a regional, trading-ready approach.
“We think carbon trading is a good thing,” Nickell said. “Our studies have shown that compliance on a regional basis is more effective than state-by-state. If you have to do something, it’s a good way to go, and trading ready helps.”
“Think millions of dollars being on the table,” Boyd said. “If you want to be part of a liquid market, you need a partner to trade with.”
The group also discussed the CPP’s mass-based and rate-based alternatives. Rate-based goals represent CO2 emissions per unit of generation, while mass-based represents the total metric tons of CO2 emitted by affected sources for each state.
Nickell said SPP is still evaluating the two alternatives, but, he said, “It appears a mass-based approach seems less complex.”
“We want to keep our options open and let the markets tell us what energy prices will be moving forward,” Thomas said.
Business and industrial interests repeated their criticism of EPA and the rule. Andrew Parker, director of governmental affairs for the state’s Chamber of Commerce, said the rule exceeds EPA’s legal authority and warned of significant cost increases to consumers, “especially the elderly, poor and others on fixed incomes.”
Jordan Tinsley, counsel for the nonprofit Arkansas Electric Energy Consumers, complained that the rule would result in stranded assets.
“They are requiring us to demolish our trusty pickups that we’ve taken good care of all these years. They won’t let us trade them in, but we have to go out and buy a shiny Lamborghini,” he said. “We think it will be very bad policy to get rid of our functional, efficient [generators], without regard for lower-cost alternatives.”
Brent Stevenson, executive director of the trade group Arkansas Forest Paper Council, took a more bombastic approach.
“Three words,” he said, pausing before thundering, “Ouch. Stop. Enough!
“There’s a cost to the EPA’s rules. Energy is one of the top three costs in our industry, along with labor and materials. Guess where we make up those costs? [The CPP] costs me money, it costs North Little Rock money, it costs the people of Arkansas money. We believe this rule should be struck down by the courts, but we’re not confident that will happen.”
Sierra Club of Arkansas Director Glen Hooks took an opposing viewpoint.
“We view the CPP as an opportunity,” he said. “If we do it properly, we can seize the opportunity in a way that benefits Arkansas and its environment and citizens.”
Or, as Keogh said, paraphrasing the late Yogi Berra, “When we reach the fork in the road, we’ll take it.”
FERC last week granted renewable energy resources an exemption from buyer-side mitigation rules in New York’s installed capacity market, a change it said will help the state comply with federal carbon emission rules. The commission also exempted self-supply resources built by load-serving entities to meet their own ICAP obligations.
But the commission denied a request to excuse demand response and most other resources from the mitigation rules (EL15-64).
In May, the New York Public Service Commission, the New York Power Authority and the New York State Energy Research and Development Authority filed a complaint seeking to limit the application of the buyer-side market power mitigation rules to only new gas- or oil-fired simple and combined-cycle units that are 20 MW or greater — seeking an exemption for resources including renewables, controllable transmission lines, nuclear generators, DR and repowered generators.
FERC ruled Friday that NYISO can no longer apply “buyer-side market power mitigation rules to certain narrowly defined renewable and self-supply resources that have limited or no incentive and ability to exercise buyer-side market power to artificially suppress ICAP market prices.”
The complainants argued that wind and solar resources are inefficient tools for exercising buyer-side market power because they require long development lead times and incur much higher development costs. They also said their intermittency and lower capacity factors made it unlikely buyers could drive down capacity market prices.
FERC agreed but said NYISO should set a megawatt cap limiting the total amount of renewables eligible for the exemption. It directed the ISO to make a compliance filing implementing the cap and other changes in the order within 90 days.
The ISO had told FERC that it supports exempting intermittent renewable resources such as wind and solar that are eligible for New York’s renewable portfolio standard.
The commission denied exemptions for controllable transmission lines, nuclear plants and repowered plants. It also said the complainants had failed to support their request for a “blanket waiver” for DR.
Self-supply resources were allowed within “net-short and net-long thresholds,” similar to those the commission previously approved in PJM.
“A well-formulated self-supply exemption will allow a load-serving entity to procure a portfolio that best allows it to manage its assessment of the risks it faces and, as [the Large Public Power Council] contends, eliminates the risk of effectively requiring load-serving entities to pay twice for capacity in the event that a self-supplied resource does not clear the capacity market,” the commission said.
Commissioner Colette Honorable issued a concurring statement saying that the ruling will help New York comply with the Environmental Protection Agency’s Clean Power Plan.
“It is clear that New York will rely upon renewable resources, in part, to meet future Clean Power Plan emissions standards,” she said. “Actions taken by the commission today will support New York’s efforts to invest in renewable resources while protecting consumers.”
SPP staff will urge the Markets and Operations Policy Committee this week to recommend approval of just one of three interregional projects coming out of the SPP-MISO coordinated system plan (CSP) study. But even that project is a long shot because MISO has already decided against it.
SPP’s Brett Hooton told the Seams Steering Committee last week that staff is recommending approval of only the $18.5 million South Shreveport-Wallace Lake rebuild, an 11-mile, 138-kV project addressing area congestion. SPP says the project has a benefit-cost ratio of 11.86, assuming it pays 20% ($3.7 million), with the remainder paid by MISO.
Hooton said staff does not recommend the other two interregional projects evaluated as part of a regional review: the Alto-Swartz series reactor and the Elm Creek-NSUB 345-kV transmission line. He said both could be reevaluated in a future regional or interregional study.
Complicating matters, however, was MISO’s announcement before its Planning Advisory Committee last month that it would not recommend any of the three projects for approval to its board. Staff told the PAC it found all three projects’ costs outweighed the calculated benefits. MISO said the project showed a benefit-cost ratio of 0.86. (See “No Go for MISO-SPP Interregional Projects,” in MISO Planning Advisory Committee Briefs.)
The two RTOs face a December deadline to come to agreement on the interregional projects, though the current six-month window can be extended. MISO’s Board of Directors meets Dec. 10 and will take up staff’s recommendation on the interregional projects at that time.
“MISO can act or decide not to act,” said David Kelley, SPP’s director of interregional relations. “That will be a decision if MISO decides not to make a recommendation at all.”
Hooton told the SSC that MISO staff has been invited to present its study results at the Oct. 22 meeting of SPP’s Economic Studies Working Group, which has also endorsed the South Shreveport-Wallace Lake project. A MISO spokesperson said the RTO would participate in the conference call.
SPP’s review of the three projects took into account modeling updates since the CSP’s initial approval. These included transmission projects approved in January, updated generator information based on the 2017 Integrated Transmission Planning 10-year assessment and a new 500-kV MISO project to serve added industrial load in southern Louisiana.
MISO is evaluating alternatives to the Alto series reactor project for resolving local area congestion and reliability and transmission service needs in the market congestion planning study.
SPP Adds TO Members, Tie Lines with Integrated System
The Oct. 1 addition of the Integrated System has more than doubled SPP’s tie lines, from 233 to 498.
With the IS, SPP is now responsible for both DC ties from the Eastern Interconnection to ERCOT and seven DC ties to the Western Electricity Coordinating Council.
In addition to the system’s three main entities — Western Area Power Administration-Upper Great Plains, Basin Electric Power Cooperative and Heartland Consumers Power District — SPP added Basin Electric members Corn Belt Power Cooperative, East River Electric Power Cooperative and Northwest Iowa Power Cooperative.
Also coming aboard as TO members were NorthWestern Energy, Missouri River Energy Services and Harlan Municipal Utilities.
SPP now has 30 TO members. On Jan. 1, it will add two more when it picks up Basin Electric members Tri-State Generation and Transmission Association Cooperative and Central Power Electric Cooperative.
Tx Project Proposals Increase with Order 1000
SPP has seen a large increase in the number of transmission project proposals as a result of FERC Order 1000.
The RTO received more than 1,700 detailed project proposals in its last planning cycle as a part of its transmission-owner selection process, which allows for competitive bidding on certain transmission projects. SPP normally sees 300 to 400 proposals a cycle, according to Ben Bright, SPP’s manager of regulatory processes.
Bright told the Transmission Planning Improvement Task Force last week the sudden increase “creates a lot of churn and staff time,” but that SPP is working to improve the submittal forms and discussing other options to streamline the process. He said working with states on individual right-of-way issues has also added to staff’s workload.
“We’re expecting even more [proposals] this cycle,” Bright said.
Entergy has agreed to sell a Rhode Island natural gas-fired power plant to The Carlyle Group for $490 million, a 40% mark-up in less than four years.
Entergy acquired the 13-year-old Rhode Island State Energy Center in Johnston, R.I., from NextEra Energy Resources for $346 million in December 2011. Entergy increased the plant’s capacity from 550 MW to the current 583 MW.
“Our strategy for Entergy Wholesale Commodities is focused on being disciplined about reducing risk and freeing up financial resources for other opportunities,” Entergy CEO Leo Denault said in a statement. “RISEC has been a very good investment for us, and its sale is consistent with that strategy.”
Entergy expects to record a net gain of approximately 50 cents/share assuming closing of the sale occurs in the fourth quarter, it said.
Carlyle insists it is a good deal for it as well.
“RISEC is among the most efficient combined-cycle facilities in New England and is well-positioned to capitalize on strong regional market dynamics. New England represents an attractive market for investment due to its transparency and incentives for reliable generation,” Matt O’Connor, Carlyle managing director and co-head of Carlyle Power Partners, said in a statement. “Additionally, the retirement of aging generation in the region is putting a greater emphasis on efficient gas-fired generators, like RISEC, to meet everyday electricity demand.”
The purchase is being made through Carlyle’s portfolio company Cogentrix Energy Power Management. It increases its power generation portfolio to 18 power plants totaling more than 4,900 MW.
The plant is located in ISO-NE’s constrained Southeastern Massachusetts-Rhode Island capacity zone. The zone failed to meet its capacity requirement in February’s ninth Forward Capacity Auction, which led to the imposition of administrative pricing well above those of resources that cleared at auction. (See Prices up One-Third in ISO-NE Capacity Auction.)
The announcement comes just a few weeks after UBS Global Research downgraded Entergy to sell, based on the prospects for its wholesale commodities unit.
“After the latest disclosures of potential early retirements of Fitzpatrick [838 MW, in New York] and Pilgrim [688 MW, in Massachusetts], we are increasingly concerned about the unregulated plant value,” UBS wrote.
Entergy last month said it may close Pilgrim rather than begin expensive repairs required by the Nuclear Regulatory Commission. (See “NRC Downgrades Arkansas One, Pilgrim Nuclear Plants” in Federal Briefs.)
NRC twice in recent weeks announced deficiencies in the plant’s safety operations. (See “NRC Finds Pilgrim Station’s Weather Tower Inoperable” in Federal Briefs.)
The settlement reached between D.C. Mayor Muriel Bowser and Exelon contains provisions designed to persuade the Public Service Commission to approve the company’s acquisition of Pepco Holdings Inc. If the deal is approved:
Exelon will provide a Customer Investment Fund worth $72.8 million. The fund is broken down as follows:
$25.6 million in rate credits against any future rate increases.
$14 million toward one-time, direct credits to all customers (estimated at $57 per customer).
$3.5 million for a Renewable Energy Development Fund.
$3.5 million paid to D.C.’s Sustainable Energy Trust Fund, which helps residents and businesses use renewable energy, increase energy efficiency and reduce overall energy consumption.
$10.05 million paid to D.C.’s Consumer and Regulatory Affairs Green Building Fund.
$16.15 million toward low-income residential customer assistance: forgiveness of debt that is more than two years old ($400,000); funding to customers eligible for the federal Low Income Home Energy Assistance Program ($9 million); and funding for the district’s energy efficiency programs, such as its home-weatherization program, earmarked for low-income residents ($6.75 million).
Exelon will also contribute $5.2 million to the district’s workforce development programs.
Exelon will move part of its corporate headquarters from Chicago to the district. This includes moving the offices of the CFO and the chief strategy officer. The executives must spend the majority of their office hours in the district.
Exelon will move Pepco Energy Services from Arlington, Va., to D.C.
Pepco will hire at least 102 union workers in the district within two years of the merger’s close.
Pepco must exceed the PSC’s current reliability requirements. Failure to do so will result in self-imposed fines, up to $6 million, paid to the Sustainable Energy Trust Fund.
Pepco will develop an “action plan” to improve its customer satisfaction ratings.
Ring-fencing provisions: “Pepco will maintain its separate existence as a separate corporate subsidiary and its separate franchises, obligations and privileges.” Pepco will not be liable for any debt related to the merger or any future Exelon acquisition. Exelon and Pepco will use “separate legal and government-affairs personnel, support personnel, and separate law firms and consultants to advocate before the commission.”
Pepco, Atlantic City Electric, Baltimore Gas and Electric, Delmarva Power & Light and PECO Energy will remain PJM members until at least the end of 2024. Exelon will also make a one-time contribution of $350,000 to the Consumer Advocates of PJM States.
By the end of 2018, Exelon will develop or assist in developing at least 10 MW of solar generation in D.C. Exelon will also provide $5 million in “capital to creditworthy governmental entities at market rates for the development of renewable energy projects” in D.C.
Pepco will develop and interconnect at least four microgrid projects.
Exelon will enter into power purchase agreements with at least 100 MW of wind energy projects in PJM.
The Market Implementation Committee last week approved rule changes implementing a new Tier 1 resource compensation plan that the group endorsed in July. The changes passed with 28 opposed and 16 abstentions.
The policy requires changes to Manual 11: Energy & Ancillary Services Market Operations; Manual 28: Operating Agreement Accounting; Schedule 1 of the Operating Agreement; and Attachment K of the Tariff.
The revisions will go before the Markets and Reliability Committee for endorsement later this month and to the Members Committee in November. The earliest they would take effect is the beginning of next year.
Under the new compensation scheme, Tier 1 synchronized reserve resources will be obligated to respond in emergencies and subject to penalties if they can’t.
It retains Tier 1’s ability to receive compensation outside of synch reserve events whenever the non-synch reserve market price is more than $0. Units could opt out of the performance obligation, but by doing so they would forfeit any credit they would have received outside of responding to an event.
Estimated Tier 1 megawatts would still be considered when clearing the synch reserve market so that opting out could not be used to withhold supply from the market and drive up prices. (See “Non-Event Tier 1 Credit to Continue, Obligation Added” in PJM MIC Briefs.)
Proposal Would Define Non-Summer DR Capacity Compliance
The committee adopted a problem statement and issue charge to develop a method for calculating customer baselines (CBL) to be used in measuring the compliance of demand response capacity resources in non-summer months.
PJM said new methodology is required under Capacity Performance rules to avoid use of an alternate method requiring two months of load data. “This effort is only focused on how to determine the CBL that will be used to determine non-summer capacity compliance,” the problem statement said.
The problem statement passed with four abstentions; the issue charge with three abstentions.
Fuel Cost Rules Under Development
The Independent Market Monitor said he is developing more complete and better defined rules for generation owners that offer their gas-fired units based on replacement cost.
Monitor Joe Bowring said the new guidelines are needed in light of the experience of the polar vortex and the upcoming rule changes that will permit offers above $1,000/MWh and hourly changes in offers.
“We are not telling generators how to value the gas they purchase. But whatever method you use, we need to be able to verify, a day later or a month later,” he said. “It is critical that verifiable, algorithmic, systematic fuel cost policies be in place to ensure that all gas-fired generators are following the rules when these changes are implemented and that there is no ability to exercise market power.”
PJM Reviews Feedback on Disclosure, Confidentiality
PJM officials reviewed feedback on proposed changes to the RTO’s rules on confidentiality and transparency.
The proposed changes to Manual 33: Administrative Services for the PJM Interconnection Operating Agreement would relax rules barring the release of data such as uplift payments, DR deployments, generator outages and cleared capacity resources. (See PJM Stakeholders to Study Relaxing Confidentiality Rules.)
Under the proposed language, certain information on individual generation outages would be released under a two-month lag.
Some stakeholders cautioned against releasing information they said should remain confidential. Others called for release of information on causes of uplift and for posting cleared capacity by zone.
PJM officials plan to revise the manual language further based on last week’s discussion. No timeline is set for a vote.
The Planning Committee last week approved an increase in PJM’s Installed Reserve Margin despite misgivings by some who said the rise seemed counterintuitive under the RTO’s Capacity Performance program and other efforts to reduce generator outages.
The Reserve Requirement Study results were endorsed by a 100-2 vote with 35 abstentions. It increased the IRM for delivery year 2016/17 to 16.4% from 15.5% in the 2014 study. IRMs also rose for 2017/18 and 2018/19 (see table).
PJM’s Patricio Rocha-Garrido said the increase resulted from changes in capacity and load models as well as a decline in the capacity benefit of ties (CBOT) — the help PJM can expect from imports during peak loads.
The forecast pool requirement (FPR), which determines the amount of capacity procured in the annual Base Residual Auction, also is slated to rise, to 109.52% of peak for 2016/17, up from 108.96%. Rises also are forecast for 2017/18 and 2018/19.
Steve Lieberman of Old Dominion Electric Cooperative said ODEC had too many questions about the methodology to endorse the results. “We don’t understand how, with CP and everything that is required of generators, [PJM’s analysis] will result in an IRM that’s higher,” he said.
Carl Johnson, representing the PJM Public Power Coalition, also abstained, saying stakeholders have repeatedly raised similar criticisms of PJM’s modeling. With the “fundamental change” in capacity assumptions under CP, “It’s probably time for us to undertake a formal process for reevaluating how this is done,” he said.
James Wilson, a consultant to state consumer advocates, presented a harsh critique of PJM’s methodology, saying there was no reason for planners to increase the IRM or FPR.
Wilson said the results were dictated in part by PJM’s “rather arbitrary” choice of the 2003-2012 period for its load model, one of 40 he said it could have selected.
He also disputed planners’ claim that PJM’s and its neighbors’ annual peaks are becoming more coincident. Wilson said PJM’s PRISM modeling software treats all of the RTO’s neighbors as a single “world,” ignoring their diversity.
“PJM is blessed with multiple diverse and substantial neighbors,” he said. “We greatly underrepresent the potential assistance from these neighbors.”
David “Scarp” Scarpignato of Calpine defended PJM’s modeling, saying there were “20 to 30” input assumptions that could increase or decrease the IRM and FPR. “I don’t think the supply side has laid out all the counter” arguments, he said.
Scarp said the IRM is based on meeting summer peaks, while CP was designed in response to problems with generators’ winter performance, including mechanical failures and access to natural gas.
“Calpine is a large gas generation fleet,” Scarp said. “We don’t have problems getting gas during the summer. That’s not changing because of CP.”
Winter Study Criteria, Uplift Added to Planning Manual
Members endorsed PJM’s first criteria for reliability studies focused on meeting winter peaks.
The criteria, outlined in Manual 14B: PJM Region Transmission Planning Process, define the winter peak period as 06:00-09:00 and 17:00-20:00 from Dec. 1 through Feb. 28.
The studies will include thermal and voltage evaluations; solutions to identified problems will be developed through the Transmission Expansion Advisory Committee.
The criteria will be effective for baseline studies on Jan. 1 and for interconnection queue requests received after the effective date of the revised manual language. The criteria are scheduled to be considered by the Markets and Reliability Committee on Oct. 22.
Members also endorsed a separate change to Manual 14B, adding energy market uplift payments as an issue to be considered in the planning process when developing transmission upgrades for operational performance.
Task Force to Seek Fix for Late Filings in Interconnection Queue
Members endorsed the charter for the Earlier Queue Submittal Task Force, which will seek new ways to discourage late entries into the interconnection queue.
PJM had instituted an escalating filing fee in an effort to encourage generators to file their interconnection requests earlier, but the change was “complicated and ineffective at dissuading late entry,” the RTO said. The influx of 11th-hour entries results in a higher proportion of deficient filings and interferes with planners’ ability to start feasibility analyses. (See PJM to Try Again to Speed Interconnection Filings.)
The group, which will be facilitated by PJM’s Andrew Gledhill, will seek a solution that could be implemented by May 1, 2016.
FirstEnergy Removing Black Oak SPS
FirstEnergy is removing the special protection scheme for the Black Oak 500/138-kV #3 transformer.
The scheme was put in place in 2010 after PJM identified potential overloads with the loss of the Black Oak-Hatfield 500-kV line.
FirstEnergy said the scheme is no longer necessary because of generation retirements, the rerating of the transformer in 2012 and completion of the Trans-Allegheny Interstate Line (TrAIL).
FERC last week scheduled a technical conference for Nov. 12 to examine how PJM determines whether solutions to local transmission needs should be part of the regional transmission plan and opened to competitive proposals under Order 1000.
It also will examine how the RTO and its transmission owners identify local transmission needs (ER15-1344, ER15-1387).
The commission ordered the conference Sept. 15 in response to PJM’s filing seeking approval of the cost allocations for 61 baseline upgrades added to its Regional Transmission Expansion Plan (ER15-1344).
The conference also will address issues raised by rehearing requests filed over the TOs’ proposal to change the cost allocation for reliability projects selected in the RTEP solely to address local transmission owner planning criteria (ER15-1387-001).
In March, Dayton Power & Light protested the cost allocation of a $106 million transmission project by Dominion Resources that was included in the 2015 RTEP. The 500-kV Cunningham-Elmont end-of-life project (Project b2582) initially was designated a supplemental proposal, for which Dominion, as the incumbent utility, would bear the full cost.
But after changing its local planning criteria last year, Dominion asked PJM to study the need for the project and received permission to change its designation to baseline, categorizing it as a new line and allowing the company to reduce its costs by more than half. (See DP&L Protests Dominion Project over New Cost Allocation.)
A supplemental project is one that is not required for compliance with state public policy or PJM system reliability, operational performance or economic criteria.
PJM: No Policies for Reclassifying Supplemental Projects
FERC issued PJM a deficiency letter in June seeking more information on the RTEP filing.
In its response, PJM acknowledged that there are no provisions in its Tariff, Operating Agreement or manuals that explain how the RTO re-categorizes a supplemental project to a baseline upgrade that is eligible for regional cost allocation. Nor is there any documentation that describes the process by which a transmission owner updates its local planning criteria, PJM said.
In its September order, FERC said that PJM’s RTEP filing and deficiency letter response raised issues that could not be resolved based on the record before it.
“Although we are establishing a technical conference, we do not find merit in Dayton’s argument for rejecting the cost assignment for project b2582,” the commission said. “The record indicates that Dominion followed the appropriate procedures to update its local planning criteria. Specifically, after Dominion presented its proposal to add end-of-life criteria to its individual transmission planning criteria at a PJM Planning Committee meeting, Dominion adopted the proposed criteria in its FERC Form No. 715.
“Thus, Dominion’s revisions to its individual transmission planning criteria will not be discussed at the technical conference. Instead, the technical conference will focus on PJM’s application of its Order No. 1000-compliant planning procedures, including PJM’s process for opening proposal windows.”
The commission said the conference also will examine concerns regarding how PJM plans for local transmission projects, including PJM’s “process for soliciting, identifying and selecting the more efficient or cost-effective regional transmission solutions for all needs for purposes of cost allocation.”
Inuit Association Seeks Nunavut Interconnection to Manitoba System
The Kivalliq Inuit Association says connecting its remote electric grid in the far northern, and sparsely populated, territory of Nunavut to Manitoba’s hydroelectric power would be a win for the region, despite the estimated $904 million cost.
An engineering study commissioned by the association said that construction of a transmission line from Churchill, Manitoba, up the western Hudson Bay coast would allow Nunavut to replace costly diesel generation with Manitoba hydroelectric power. The project would save $40 million a year and pay for itself over the course of its 40-year lifespan.
“Ever since I’ve been elected I’ve been pushing for this,” said Joe Savikataaq, Arviat-South member of the Legislative Assembly of Nunavut. “Our power plants are aging and the amount of diesel our communities can hold has to be expended.”
ComEd Project Aims to Boost Use of Demand Response
A pilot project in Chicago aims to demonstrate that demand response can be a year-round resource able to compete in PJM’s capacity market.
The Combined Capacity Asset Performance Project will combine renewable energy like wind and solar with the DR capability of several Chicago buildings. It is being led by PJM, the Environmental Defense Fund, the Accelerate Group and the Citizens Utility Board.
Under previous market rules, suppliers of DR could choose to participate only in the summer months. New PJM rules require that resources be able to respond whenever there is a critical need.
Suburu Blames High Power Prices for Advantage Loss
Automaker Subaru says that the state’s increasing power prices are causing its Lafayette assembly plant to lose its competitive advantage.
Industrial electricity prices in the state have risen 75% between 2003 and 2015, about twice the national rate, according to U.S. Energy Information Administration data. The state had the fifth lowest industrial electricity prices in the nation in 2003, but today 25 states offer lower pricing.
The Indiana Energy Association blames the rise in the state’s industrial electric rates on federal environmental regulations, which have hit the state’s coal-fired power generators. Industrial leaders are pressuring policymakers to allow for the increased use of on-site cogeneration.
Renewable Tax Credits Sitting Idle in Developers’ Hands
Renewable energy developers are failing to build many projects for which production tax credits have been set aside, according to Midwest Energy News.
A study of Utility Board records shows that 113 proposed wind projects were assigned the production tax credits but were never constructed. The study showed that 37 of those were approved in 2009 but received repeated 12-month extensions. Nineteen other proposed wind projects were on standby because the tax credits had already been assigned.
“There are a few projects that I think are ready to go, and are on the waiting list, and projects ahead of them may never be built,” said Nathaniel Baer, energy program director for the Iowa Environmental Council. Baer called for “a fresh look” at the projects if they haven’t been built years after getting awarded the credits.
Kansas Municipal Utilities to Open Training Center
Kansas Municipal Utilities broke ground last week on a $3.2 million workforce training center in McPherson. The center is due to open in June 2016 and is the only one of its kind in a multistate area.
The project is answering the call from Kansas Municipal Utilities’ 176 members, which have aging workforces. The training center would not serve rural electric cooperatives or investor-owned utilities.
The Public Service Commission is exploring whether to allow net metering. The state is one of five that do not require utilities to buy surplus power produced by customer generators.
At a two-hour hearing last week, supporters of the proposed net-metering rules say they would benefit all utility customers, while utilities expressed concern that the rules would shift costs to non-producing customers. State regulators are also considering whether it has the authority to order member-owned cooperatives to abide by net-metering rules.
Commissioners extended the comment period, and it’s not clear when they will vote on the issue, which they’ve been considering since 2011.
State Energy Plan Calls for Wind Incentives, More Renewables
The state’s new Comprehensive State Energy Plan, released last week during the Midwest Energy Policy Conference in St. Louis, recommends adopting a building code, requiring power companies to offer efficiency programs and boosting the amount of renewable energy utilities have to offer their customers.
Gov. Jay Nixon launched the effort last year. The Division of Energy has spent more than a year meeting stakeholders. What emerged is a plan calling for incremental changes that will give the state time to adapt.
The Division of Energy says the plan is unrelated to efforts to comply with the federal Clean Power Plan. The plan does offer dozens of policy recommendations on everything from better energy education to complex changes in utility regulations.
TransCanada, the company seeking to build the Keystone XL Pipeline, is withdrawing its eminent domain claims on the land it planned to use for the pipeline and will instead go to the state’s Public Service Commission for route approval.
The company’s decision came on the eve of the state trial on the eminent domain issue, which was scheduled to start Oct. 19. Even if it had prevailed in state court, TransCanada would have still had to get approval from the PSC to go forward.
“The writing’s kind of on the wall,” said University of Nebraska law professor Anthony Schutz. “The prospect of losing was significant enough that they probably looked at the tea leaves and said, ‘Why don’t we just go forward with that process now?’ ”
Facing a shortfall to pay for retirement benefits, Nebraska Public Power District is asking its biggest wholesale customers for more money. However, 10 local power districts and cities are speaking out against a proposal they say is discriminatory, unfair and even outlandish.
NPPD says it needs $25 million more a year to address a shortfall in its retirement fund. It is asking for a 3.85% increase in the wholesale rate. However, those that sign a new contract will get a discount, so their increase would be just 0.6%.
A handful of cities and power districts are abandoning the public power supplier and shopping for electricity from other producers, which NPPD CEO Pat Pope says he did not anticipate.
Gov. Maggie Hassan will not reappoint Susan Chamberlin, the incumbent consumer advocate on utility issues. Opponents of a Kinder Morgan natural gas pipeline project, who see her as an ally in proceedings before the Public Utilities Commission, are upset by the move as well as delays in finding her replacement.
State officials have known since July that Chamberlin, whose term expires Nov. 5, was not likely to be reappointed. “The dismissal of one of the most powerful advocates for New Hampshire residents, and the significant delay in nominations for a replacement, is a telling lack of concern for all of New Hampshire ratepayers,” said Maryann Harper, a spokesperson for the Pipeline Awareness Network of New Hampshire.
The decision regarding Chamberlin was the result of a review in which the committee received confidential, anonymous feedback from managers, peers and direct reports that were not favorable enough to lead to a reappointment.
Kinder Morgan announced Thursday that it is exploring a modification to the proposed Northeast Energy Direct pipeline route in Merrimack. Barry Duff, project manager, said the company met with officials from two businesses about some newly proposed amendments.
“I am happy that the businesses are being listened to,” said Jody Vaillancourt, Town Council member. However, she maintained the community is at a huge disadvantage because new modifications are being introduced in the final hours.
Kinder Morgan said the original route was amended and moved farther to the east to minimize impact to a nearby school and to avoid conservation land.
Public Service Company of New Mexico and the state’s Attorney General’s Office are challenging an advocacy group’s allegations that PNM manipulated numbers to justify the company’s plans for the coal-fired San Juan Generating Station. PNM proposes to close two of the plant’s four coal-fired units and replace the lost capacity from other sources, including coal-generated power from another unit at the plant.
David Van Winkle, an expert for Santa Fe-based New Energy Economy, last month filed written testimony claiming PNM significantly understated the size of rate increases the utility would seek during the next 20 years if the state’s Public Regulation Commission approves its plan.
PNM’s Patrick O’Connell last week filed a response that said the consultant’s “derogatory and inflammatory accusations about PNM’s alleged manipulation of data to achieve a ‘predetermined’ result are totally false.” Andrea Crane, a consultant from The Columbia Group, a Connecticut-based firm specializing in utility regulation that is contracted with the Attorney General’s Office for cases involving utilities, also filed a rebuttal last week.
Long Island Officials Challenging PSEG Rate Increase
Elected officials are asking for a halt to PSEG Long Island’s rate increase hearings, saying the rate case is flawed because of “constitutional and contractual” concerns.
The request comes a week after the Long Island Power Authority tentatively approved a $325.4 million rate increase. The increase still needs a final vote. In a letter to the state Department of Public Service, 12 Long Island Republican state assemblymen contend that there is “no true oversight” over PSEG and that the LIPA board lacks “objectivity and expertise.”
PSEG, which originally sought a $387 million increase, said it followed the rate increase request process dictated by the 2013 LIPA Reform Act.
NCWARN, a solar advocacy group, installed a solar facility atop a Greensboro church and is selling the power directly back to the church, bypassing area utility Duke Energy. The move is intended to create a test case for state regulators.
The organization says it entered into a three-year contract to sell the power directly to the church as a way to spur a ruling on what it sees as Duke’s monopoly on direct sales to customers. Current law requires the owners of a solar facility to either use the power themselves or sell directly back to the area utility.
NCWARN earlier this year built a 5.2-kW solar project on the roof of Faith Community Church and signed a three-year agreement to sell the power back for 5 cents/kWh, about half the rate charged by Duke. NCWARN is asking the state Utilities Commission to rule that the three-year arrangement is legal.
Staff: PUCO Should Reject AEP Profit-Guarantee Plan
Public Utilities Commission staff have recommended that the commission reject American Electric Power’s proposal that would guarantee profits at some of its power plants.
“Staff recommends that the commission deny the [proposal] as it is currently proposed,” said Hisham Choueiki, a senior energy specialist for PUCO. “However, it is possible that the [proposal], if properly conceived, may be in the public interest.”
Last month, staff recommended that the commission reject a similar proposal from FirstEnergy. AEP has said its plan will help to reduce volatility in electricity pricing and preserve jobs at power plants that may otherwise close.
State is Likely to Meet Stricter Ozone Regulations
The state is expected to comply with the Environmental Protection Agency’s recently unveiled tighter limits for ground-level ozone. Officials were still studying the new standards, but the Department of Environmental Quality said the state likely would fall under a three-year period that includes monitoring data from 2014-2016.
Based on monitoring data from 2013 and into 2015, all counties would meet the new standard of 70 parts/billion, said ODEQ spokeswoman Skylar McElhaney.
Bud Ground, environmental and regulatory affairs consultant with the Oklahoma Oil and Gas Association, said the new limits could put Oklahoma City and Tulsa counties closer to non-attainment status and wouldn’t leave much room for variation in years with hot summers, nor would it account for smog coming over the border from Texas.
Goliad County has set aside tax revenue collected in 2014 from Coleto Creek Power because the power company is embroiled in a lawsuit with the county’s tax appraisal district. The company is challenging the plant’s tax valuation. It was assessed at $353.7 million in 2014 and $403.9 million this year.
Coleto Creek Power claims that the 35-year-old coal-fired plant “has faced dramatic adverse developments” due in part to a newfound abundance of natural gas at low prices. The 632-MW plant also has to contend with stricter emissions requirements and is spending more to transport coal from Wyoming to Texas because a railroad agreement has expired.
Legislation that became effective Sept. 1 requires counties to repay tax revenue back with 9.5% interest, according to the county judge. The next court date is in May.
Hearing Requests Withdrawn for North Texas Gas Plant
Van Alstyne residents have withdrawn their requests with the Commission of Environmental Quality for a formal hearing of a proposed Navasota Energy power plant.
In September, some residents named themselves as affected parties of Navasota Energy’s plans to build just outside the town’s city limits. That would have required Navasota officials to secure an air-quality permit from TCEQ.
A TCEQ spokesperson said that because the affected parties had withdrawn their requests, the commission now anticipates the matter will come back to the commission as uncontested.
More Wind Farms Likely as Part of ‘Energy Revolution’
The wind industry held a two-day conference to promote renewable energy, which attracted several dozen protesters who warned that large-scale mountaintop wind turbines are a poor match for the state.
Gabrielle Stebbins, executive director of Renewable Energy Vermont, the trade group that hosted the two-day conference, said the state’s “energy revolution” is picking up speed, investment and credibility. That momentum will very likely include the ridge-top development of more large-scale wind projects, she said.
The group outside waved signs reading “ridgelines are not renewable,” “stop destroying Vermont,” “no wind turbines” and “save the ridge.”
Republican lawmakers in the state are trying to end a 1983 ban on new nuclear construction. Bills sponsored by Sen. Frank Lasee of De Pere and Rep. Kevin Petersen of Waupaca would waive the Public Service Commission’s requirement that a waste repository be in place in order to approve new nuclear generation.
Similar bills were introduced in 2005 and 2009 but did not advance. With the 2013 closure of Dominion’s Kewaunee nuclear station, the only operating nuclear generating station in the state is NextEra’s Point Beach facility. Dairyland Electric Cooperative’s La Crosse Boiling Water Reactor in Genoa was shut down in 1987 and is in the midst of decommissioning.
