PJM CEO Terry Boston opened 2015’s first Markets and Reliability Committee meeting last week with a plea for compromise.
Boston lamented that PJM took unilateral action on several contentious proposals sent to federal regulators in 2014 after stakeholders were unable to reach consensus, including the increase in the price-based energy offer cap. He said the year ahead presented more challenges, including “the fastest fuel change in industry history” as coal-fired plants are replaced by natural gas due to environmental rules.
“We have to reach consensus on some of the issues that are before us,” Boston said. “It’s a new year. We have a new opportunity in front of us to build these relations [among stakeholders] and build consensus.”
There was no evidence of rifts Thursday, thanks to an unusually light agenda that saw the MRC and Members Committee complete their work before noon, with only manual changes brought to votes. “This may be the first time I try to stretch out an MRC meeting,” MRC Chairman Mike Kormos joked.
Update on Winter 2015/16 Plans
PJM officials provided the MRC an update on the status of efforts to postpone generation retirements or accelerate new generation to help the RTO overcome potential shortages next winter. (See PJM Seeks to Postpone Some Generation Retirements through 2015/16.) PJM’s Scott Baker said initial feedback from generation owners and developers indicates that there are less than 2,500 MW available.
Because of retirements expected as a result of the Environmental Protection Agency’s Mercury and Air Toxics Standards (MATS) and New Jersey’s High Energy Demand Day (HEDD) regulations, Kormos said PJM will have less generation available in 2015/16 than it did last winter. PJM also is concerned about its ability to meet summer loads if it loses the ability to call on demand response resources. (See FERC Files EPSA DR Appeal with Supreme Court.)
“Under normal weather conditions we are fine,” Kormos said. But under a repeat of last year’s polar vortex, “we will be close to the line and we will be relying on the outside for help,” he said.
Kormos added that generator performance this winter has improved over last January, when as much as 21% of generators were unable to produce.
On Dec. 24, PJM asked the Federal Energy Regulatory Commission to allow it to enter into capacity agreements made outside the Reliability Pricing Model auctions (ER15-739). PJM also asked for a one-time waiver on rules that would otherwise require it to release 2,000 MW of capacity in the Feb. 23 Third Incremental Auction for 2015/16 (ER15-738).
Kormos said PJM would limit operation of generators subject to HEDD regulations to emergencies to keep them under the emission threshold in the New Jersey rules. “That seems to be the path of least resistance,” he said.
Manual Changes on $1,800 Offer Cap OK’d
The MRC approved conforming changes to two manuals in response to FERC’s approval of a temporary increase in the cost-based energy offer cap to $1,800/MWh from $1,000.
The increased offer cap — one of the issues on which stakeholders were unable to reach consensus last year — became effective with the Jan. 16 order and will expire on March 21. (See FERC OKs $1,800 Offer Cap in PJM.)
The order requires changes to Manual 11: Energy and Ancillary Services Market Operations and Manual 28: Operating Agreement Accounting.
Manual 11 was changed to read that generators’ incremental energy offers “may not exceed $1,000/MWh or a market seller’s lowest available and applicable cost-based offer provided such cost-based offer is greater than $1,000/MWh (and in no instance may be greater than $1,800/MWh).” (New text in italics.)
LMPs will be limited to the $1,800/MWh offer cap, plus primary- and synchronized-reserve penalty factors and the impacts of congestion and marginal losses. Costs above $1,800/MWh can be compensated via make-whole payments with an after-the-fact review, but they would not set clearing prices.
Cost-based adders under such offers will be limited to the lessor of 10% or $100/MWh. Price-based energy offers can rise above $1,000 simultaneously with cost-based offers “to avoid inappropriate market signals,” PJM said.
Other Manual Changes Approved
The MRC also approved the following manual changes with little discussion or debate:
Manual 03A: Energy Management System (EMS) Model Updates and Quality Assurance (QA) — Includes updates and formatting changes to improve consistency and readability; new table added for important links.
Manual 14A — Updates related to MISO-PJM queue coordination. MISO will evaluate the impact of new PJM interconnections at the impact study phase. The previous procedure, in which MISO’s review occurred during the facility study phase, caused delays in studies and final agreements, PJM’s Aaron Berner said.
Manual 18: PJM Capacity Market — Updated to reflect revisions recently approved by FERC to the shape of the Variable Resource Requirement Curve, gross cost of new entry values, and the Net Energy & Ancillary Services Revenue Offset methodology. (See PJM Board Orders Filing on Capacity Parameter Changes.)
Regional Transmission and Energy Scheduling Practices document — Changes made to comply with FERC Order 676H and North American Energy Standards Board standards. PJM is primarily impacted by FERC requirements for “Service Across Multiple Transmission Systems” (SAMTS). (See FERC Proposes Revised Communication, Business Rules.)
Members Committee
The Members Committee also approved several changes with no debate:
Tariff and Operating Agreement (OA) revisions developed by the Demand Response Subcommittee to change the way PJM measures and verifies residential demand response. The revisions allow statistical sampling and clarify rules for all residential customers. (See “Sampling to be used for Measuring Residential DR” in MRC/MC Briefs, Nov. 25.)
Tariff revisions to remove seller credit, a form of unsecured credit, from the credit policy, which RTO officials say is no longer necessary.
Tariff and OA revisions related to data availability for the bus distribution factors for zonal and residual metered load aggregates. When technical limitations restrict PJM’s ability to obtain the load distribution factors from the 0800 snapshot one week prior to the operating day, or if the data is unavailable, the load distribution factors from the most recently available day of the week that the operating day falls on will be used in the day-ahead energy market. (See “Tariff Revisions to Metered Load Aggregates” in Markets and Reliability Committee Briefs, Dec. 22.)
Southwestern Electric Power Co. asked the Public Service Commission to deny a request by Save the Ozarks to pay for legal expenses the organization incurred during its battle against a transmission line.
SWEPCO withdrew its power line application last month following a 20-month legal battle with the opposition group. SWEPCO says there is legal precedent to allow it to withdraw an application without prejudice, and that the PSC has no authority to award legal fees.
SWEPCO’s motion was joined by SPP and the Arkansas Electric Cooperative.
Exelon CEO Complains About PSC Staff Report on Merger
Crane
Exelon called on the Public Service Commission to reject staff recommendations to place additional conditions on the company’s proposed merger with Pepco Holdings Inc., parent company of Delmarva Power.
The commission staff asked for a total of $68 million in incentives to allow the merger to go ahead in the state, Exelon said. CEO Christopher M. Crane said a “particularly inappropriate” recommendation was for the regulatory agency to “micromanage” appointments to the utility’s board of directors. Crane said Exelon “must have the ability to exercise control over its subsidiaries.”
Connie McDowell, PSC senior regulatory policy administrator, said that the PSC should look at staff’s recommendation requirements as “an essential ingredient” to commission approval. Without the additional incentives, she said, the commission should reject the merger.
Peoples Gas Wins Rate Hike from Commerce Commission
The Commerce Commission approved a $74.8 million rate increase for Peoples Gas, costing a typical residential customer about $2.75 more a month. The boost was about 30% less than the company’s original request.
Meanwhile, Ameren Illinois filed Friday for a $53 million increase in the annual gas delivery rate. That request, if approved, would go into effect January 2016.
Energy Efficiency Bill to Replace Energizing Indiana Passes Senate
The state Senate approved a bill that would allow utility companies to develop their own energy efficiency rules rather than be directed by a state mandate, as was done by a previous now-repealed law called Energizing Indiana.
The bill, crafted by Gov. Mike Pence’s office, was introduced by Sen. Jim Merritt. The proposal directs utility companies to set “reasonably achievable” efficiency goals. Critics said the rule would result in less aggressive energy efficiency efforts than utilities would achieve under a state mandate.
Kentucky Power Ordered to Refund $13 Million in Overcharges
The Public Service Commission has ordered Kentucky Power to refund $13 million in overcharges to customers and barred the company from collecting $41 million in additional fuel costs that were scheduled to be collected through May.
The refund will appear as credits on customers’ bills and will total about $155 per customer over a 17-month period. The commission also criticized the company for failing to disclose additional fuel costs associated with its purchase of 50% of the Mitchell power plant in West Virginia and declined to allow the utility to raise rates to recover the cost.
PSC Approves Entergy’s Baton Rouge Gas Main Upgrade
The Public Service Commission approved a $65 million plan by Entergy to replace aging natural gas cast-iron mains in Baton Rouge. Entergy said the project should take about a decade to complete.
The commission voted 3-1 to allow Entergy to finance the gas-main replacement program through a special rider. The surcharge would increase the typical residential customer’s bill by about 43 cents for the first year, $1.28 for the second year and $2.28 the third year, with increases of about 2% for each of the following years.
Entergy replaced about 300 miles of gas lines in New Orleans after Hurricane Katrina.
Eastern Shore Firm Seeking Permits for Poultry Waste Plant
CleanBay Biofuels is seeking various permits to build and operate a poultry-waste recycling plant that would relieve farmers and processors from having to dispose of hatchery wastes. The so-called slurry conversion plant, planned for a 133-acre site near Princess Anne in Somerset County, would cost about $18 million and take two years to build.
Unlike plants that burn poultry litter to generate energy, the CleanBay process uses chemicals to convert the waste into fuel. The plant would have its own power station, according to CleanBay CEO Jason Levine.
A bill introduced by state Rep. Sam Singh would require electricity providers to cut annual energy sales 2% by 2019 by promoting energy efficiency, doubling the current goal.
“I’ve been a longtime advocate for energy efficiency because there is a direct benefit to the consumer,” Singh said. The current law, passed in 2008, sets an energy-reduction target of 1%. Natural gas providers would also have to trim 1.5% by 2019, which is also double the current target.
Raising Renewable Standard Would Boost Capital Investment to $6.2 Billion
A study by the Union of Concerned Scientists suggests that raising the renewable energy standard to 40% by 2030 would boost capital investment in the state to $6.2 billion with minimal impact on consumers.
The report was released as part of an effort to push state legislators to pass a 40% standard. The state’s current standard sets a 25% goal by 2025.
The strengthened RES would create another 3,100 MW of renewable energy in Minnesota, the report said, while reducing electricity imports so much that the state would become a net power exporter.
Vap Succeeds Landis as Public Service Commission Chair
Jerry Vap was elected chairman of the Public Service Commission last week, replacing Frank Landis. Vap said his priorities are broadband expansions, improvements to the 911 system and consumer-protection laws.
The PSC is comprised of five commissioners with six-year terms who each represent a district.
The Board of Public Utilities has unanimously approved a 16-mile transmission line project proposed by Jersey Central Power & Light.
JCP&L said the $64 million project is crucial to improving the reliability of the electric system in Monmouth County. The line was previously approved by PJM. There was no public opposition to the project, possibly in part because it does not require any new rights of way.
Another Group Pulls Out of San Juan Station Agreement
Western Resource Advocates, an environmental organization, is now the third group to withdraw its support for Public Service Company of New Mexico’s plan to shut down two of four units at the coal-fired San Juan Generation Station.
The environmental group announced it was pulling its support after learning that PNM Resources, parent company of Public Service, may buy 65 MW of generation from one of San Juan’s two remaining generation units. PNM’s plan to retire two of the units was intended to meet emissions mandates.
“If PNM Resources acquires that generation, it would mean PNM and its affiliate would actually be absorbing nearly 200 MW more of capacity in that generating unit, and that’s just too much for us,” said Steve Michel, chief counsel for Western Resources.
Supreme Court Rejects AG’s Challenge of Duke Energy’s Rate Request
The state Supreme Court on Friday rejected Attorney General Roy Cooper’s challenge of a 5.1% Duke Energy rate increase approval, ending a two-year attempt by Cooper to block the rate increase.
Cooper, who is expected to run for governor in 2016 as a Democrat, argued that the Utilities Commission didn’t take into consideration the effect of a rate increase on Duke’s customers when it approved it. The ruling represented the third time in the last year that the Supreme Court rejected challenges to rate increases for a Duke subsidiary.
3 Million Gallons of Brine Spill from Drilling Pipeline
Nearly 3 million gallons of salty wastewater from oil and gas drilling has spilled from a North Dakota pipeline, leaking into at least two streams, officials said. The brine leak was nearly three times the magnitude of any earlier spill.
A state Department of Health official said Summit Midstream Partners first noticed the spill in early January but didn’t give state officials a full account until last week. Dave Glatt, chief of the Department of Health’s environmental health section, said it was too soon to know the scope of the damage and said some earlier brine spills took years to clear up.
The nominating committee of the Public Utilities Commission forwarded four finalists to Gov. John Kasich, who will choose one for a five-year term on the commission, subject to state Senate confirmation.
The candidates are Steven Lesser, a commissioner since 2010 who is seeking reappointment; Andre Porter, former PUCO commissioner and secretary of the state Commerce Department; Thomas Waniewski, Toledo city councilman and former state Public Works Commission member; and John Honabarger, a Verizon Communications executive. Lesser is a Democrat and the other three are Republicans.
Ohio law requires that one political party can hold no more than three seats on the five-member commission. There are currently two Republicans, one Democrat and two who are not members of either party, so Kasich, a Republican, can select any nominee regardless of party affiliation.
Opponents of FirstEnergy’s proposed plan to guarantee returns for its power plants dominated a five-hour hearing last week before the Public Utilities Commission.
The majority of the 78 speakers who testified said they thought FirstEnergy doesn’t deserve any ratepayer subsidies.
“Facilities like the Sammis coal-burning power plant are exactly the type of facilities we should be seeking to phase out, not facilities we should seek to keep going at full capacity for another 15 years by giving them special financial deals,” testified 16-year-old Hilary Vogelbaum, a Moreland Hills resident and a high school junior.
Labor leaders, two mayors and representatives of non-profit organizations that are supported by the company spoke out in favor of the proposal. PUCO is scheduled to vote on the plan later this year.
PPL, PUC Urge Supreme Court to Let Privacy Ruling Stand
PPL Utilities and the Public Utility Commission have asked the Supreme Court to uphold a lower court ruling that allows them to conceal the identity of a customer who got special treatment during an outage restoration effort in 2011.
PPL paid $60,000 to settle a PUC investigation into charges that a customer moved up the priority list during the outage restoration. The PUC denied the request of several news media outlets to release materials from the investigation. The state Office of Open Records ordered the file open. The Commonwealth Court reversed that decision. The media have appealed that ruling to the Supreme Court.
About 100 people turned out for a public meeting in Iroquois, population 250, to voice concerns and support for the proposed $3.8 billion, 1,134-mile Dakota Access crude oil pipeline.
Citizens asked the builders of the project, which would deliver North Dakota crude oil to a pipeline interconnection in Illinois, to pay more to compensate landowners for easements along its 272 miles through South Dakota.
Craig Walker, a farmer, suggested the company had set aside too little money to acquire rights of way. “That’s one of the reasons I came today, was to see how sharp your pencil was,” he said.
Appalachian Power Customers Getting SCC-Ordered Refund
Appalachian Power’s customers in Virginia will see a $5.8 million refund, thanks to a State Corporation Commission ruling.
The refunds will average about $1.11 a month for a typical residential customer, and will be paid in six monthly bill credits. The refund is derived from excess company earnings from 2012 to 2013.
The House of Delegates and Senate voted to repeal the Alternative and Renewable Energy Portfolio Standard, a law that called for large utilities to generate 25% of their power from alternative sources by 2025.
The law that was repealed broadly defined “alternative sources” to include some coal- and natural gas-fired technologies, as well as those burning tires. City-owned utilities and cooperatives were exempt. But in the coal mining state, repealing the standard was seen as a move to benefit the coal industry, which is coming under increasing federal regulation and economic pressure.
“The purpose of the bill is, if we save just one coal miner’s job, it’s well worth it,” said Del. John Shott, a Republican.
It’s official: Wisconsin Public Service plans to construct a 400-MW, natural gas-fired combustion turbine combined-cycle power plant.
In filings with the Public Service Commission last week, the company said it is going forward with plans to build the $517 million Fox Energy Center plant near Kaukauna. The company announced its intentions last year, but its plan came under review during the proposed acquisition of its parent company Integrys by Wisconsin Energy.
“We have to make decisions for our customers and the best decision is to move forward,” spokesman Kerry Spees said. “The studies say this is the best thing to do to meet our needs in 2019. It’s the right site, it’s the right time, it makes great sense.”
Solar energy advocates in Indiana are decrying a proposal that would allow utilities to seek fixed charges for customers generating their own electricity.
House Bill 1320 would allow utilities to petition the Indiana Utility Regulatory Commission for fixed charges “to avoid, reduce or eliminate” a subsidy to customers that use distributed generation. The commission would authorize the charge if it concludes that the proposed “nonvolumetric rate design is based on principles of cost causation.”
As currently drafted, the law would not affect those who installed solar systems before Jan. 1, 2015.
Currently, Indiana’s small-time generators can sell their excess power back to a utility for roughly what they would otherwise pay for an equivalent kilowatt.
Reducing that return for those generating less than 1 MW by introducing a charge would be a disincentive for customers to install solar or wind generation and would effectively gut the state’s decade-old net metering law, opponents say.
“This is probably one of the most aggressive pieces of legislation we’ve seen to eliminate net metering,” said Amy Heart, a policy analyst for The Alliance for Solar Choice.
“Investor-owned utilities are fine with solar — if they can own it, if they can control it and then charge ratepayers what they want to charge,” Heart added.
Making Solar Affordable?
The bill’s chief backer, the utility trade group Indiana Energy Association, counters that HB 1320 would actually promote distributed generation, in part by allowing leased generating equipment to be eligible under the state’s net metering law.
A rooftop solar system can cost more than $25,000 to buy, which is beyond the means of many electric customers, said Mark Maassel, president of the trade group, whose members include Duke Energy Indiana, Northern Indiana Public Service Co., Indianapolis Power & Light and Indiana Michigan Power.
The utility group also said HB 1320 would ensure that those who generate their own power are also paying for the upkeep of the grid — not just ordinary ratepayers.
Those ratepayers effectively subsidize neighbors who can afford to purchase solar or wind generation of their own, Maassel said. “What we’re doing [under current law] is creating an advantaged group of people.”
The bill also would prevent counties and municipalities from prohibiting distributed generation in their jurisdictions.
Common Theme
The Indiana legislation is similar to what is being pursued by utilities in other fast-growing solar generating states, such as Wisconsin.
Last year, We Energies proposed raising its fixed charge by 75% while reducing what customers are paid for their own solar generation fed back to the grid. Consumer groups countered that WE’s proposed capacity charge would offset nearly 30% of a customer’s savings from solar.
They also argued that utilities, while paying consumers less for power they generate and feed back to the grid, could then turn around and re-sell the same power for much more during peak summer hours.
Maassel paints a different picture. A utility may be more often in a situation where it has to pay a generating customer for his excess electricity at the retail rate, say around 10 cents/KWh, whereas the utility otherwise could have purchased the same power for just 3 cents/KWh on the wholesale market.
Small-but-Growing Presence
Like Wisconsin, Indiana’s solar generation remains a tiny sliver of the overall power produced, although that share has been growing quickly.
From virtually nothing in 2005, there are now about 500 net metering customers — mostly generating solar power — with a nameplate capacity of 7,000 kW in Indiana.
Heart, of the Alliance for Solar Choice, said electric utilities are trying to nip that growth before it can blossom. She questioned claims by utilities that solar generators are contributing to grid costs, saying utilities have not provided convincing evidence.
In September, a study conducted for the Public Service Commission of Mississippi found “very little substantiated evidence that there are significant costs incurred by grid operators or distribution companies as a result of low levels of solar distribution resources.”
The study, by Synapse Energy Economics, concluded that solar net metering would have estimated benefits of $170/MWh and estimated costs of $143/MWh, resulting in $27/MWh of net benefits to Mississippi.
The Alliance for Solar Choice has been especially critical of Duke Energy, painting it as schizophrenic on net metering. While a key backer of HB 1320 in Indiana, Duke recently won praise for its support to help South Carolina become the 44th state to institute net metering.
Duke Indiana spokeswoman Angeline Protogere acknowledged that the utility was among those supporting HB 1320. Protogere said the bill was developed with the goal of “beginning the Indiana discussion [on the proper policy for customer-owned generation], one that balances the interests of customers who have their own generation and those who don’t.”
The Federal Energy Regulatory Commission last week approved a revised reliability standard, PRC-005-3 (Protection System and Automatic Reclosing Maintenance). The standard proposed by the North American Electric Reliability Corp. requires testing and maintenance of auto-reclosing relays and includes one new definition and six revised definitions (RM14-8). FERC required NERC to modify the standard to include maintenance and testing of supervisory relays.
ISO-NE must find a market-based solution for ensuring adequate generation by next winter, the Federal Energy Regulatory Commission said last week in a clarification of a previous order.
FERC’s Jan. 20 order (ER14-2407) sided with the region’s generators, who contended ISO-NE was not acting with the urgency the commission intended in a Sept. 9 ruling, in which it approved the second year of the RTO’s Winter Reliability Program.
The program provides dual-fuel capable generators with out-of-market incentives to ensure they can switch to oil when cold weather stresses natural gas supplies. The RTO had previously won FERC approval of a long-term, market-based reliability plan, the Pay-for-Performance program, which will result in a two-settlement process for capacity resources starting in 2018 (ER14-1050).
“We’ll continue with the stakeholder process, which we began a couple of months ago. We’re still assessing the impact of this order, in light of the work that’s been done so far,” ISO-NE spokeswoman Marcia Blomberg. “A jump-ball filing [reflecting a lack of consensus among stakeholders] is theoretically a possible outcome of a stakeholder process on any proposal but, as I said, it’s premature to speculate on the possible outcomes of this stakeholder process.”
The Sept. 9 order directed ISO-NE to start a stakeholder process by Jan. 1, 2015, to develop a market-based solution before Pay-for-Performance takes effect.
Generators: No More ‘Band-Aids’
The RTO began the process last fall, filing a schedule of New England Power Pool stakeholder meetings on Oct. 8, but it made no promises that it would result in an interim market-based solution.
The New England Power Generators Association responded Oct. 9 with a filing complaining that the RTO was misinterpreting FERC’s directive.
“ISO-NE is interpreting the commission’s order to allow ISO-NE to continue proposing out-of-market fixes for the three consecutive winters after winter 2014/2015,” the group wrote. “… The commission’s order should not be read to condone three additional years … of seasonal, out-of-market Band-Aids in lieu of market rule changes based on the competitive market principles necessary to efficiently price system reliability.”
It asked the commission to clarify that the September order required ISO-NE to implement a market-based solution for 2015/16, saying it wanted “to avoid potentially wasting valuable NEPOOL stakeholder meeting time on out-of-market solutions, if any, proposed by ISO-NE.”
ISO-NE: No Consensus
In a Dec. 8 progress report to FERC, ISO-NE said that in response to “concerns that the winter reliability programs to date have not been resource-neutral and market-based, ISO-NE has committed to have a dialogue with stakeholders on current and alternative objectives for winter reliability programs, and the feasibility of designing and implementing a market-based solution for future winters.”
But the RTO said that at a November meeting of the NEPOOL Market Committee, stakeholders were split over what alternatives they should pursue for future winters, with some calling for the development of “price formation projects,” others supporting continuation of the existing winter program, and others for a market-based solution.
“In short, no consensus emerged,” the RTO said, adding that it would discuss the issue again at future Markets Committee meetings.
In its Jan. 20 order, FERC agreed with the generators.
“The commission intended that ISO-NE would determine whether a winter reliability solution is necessary for the 2015-2016 winter and future winters and, if so, develop an appropriate market-based solution through the stakeholder process that can be implemented beginning with the 2015-2016 winter,” FERC wrote. “While the two-settlement capacity market design could help address winter reliability concerns in the future, that design will not be fully implemented until the 2018-2019 Capacity Commitment Period.”
The Federal Energy Regulatory Commission last week approved new rules governing how transmission customers can challenge formula rate filings by MISO transmission owners.
The commission conditionally accepted the proposals by MISO and transmission owners Northern Indiana Public Service Co. (ER13-2376-002) and Southern Indiana Gas & Electric Co. (ER13-2375-002) revising the rules regarding how transmission customers can review and appeal the TOs’ cost claims. These formula rate “protocols” are specified in Attachment O of the MISO Tariff.
In a third order, the commission required MISO’s transmission owners to add language stating that a party that has submitted an informal challenge to the TO on any issue has standing to later file a formal challenge with the commission (ER13-2379-002, ER14-2379-003). “We find that the proposed modification will lend clarity to interested parties that the subject of formal challenges does not need to be the same as an interested party’s previous informal challenge,” the commission said, responding to concerns raised by the Organization of MISO States (OMS).
In the same order, the commission conditionally accepted revised protocols by the Central Minnesota Municipal Power Agency, which FERC said had adopted the MISO TOs’ protocols “virtually verbatim.”
Previous Rules Not Just and Reasonable
MISO’s TOs were forced to change their rules in response to the commission’s May 2013 order finding the prior protocols were “insufficient to ensure just and reasonable rates.”
The commission opened a Federal Power Act section 206 investigation in 2012, expressing concern about “the (1) scope of participation (i.e., who can participate in the information exchange); (2) the transparency of the information exchange (i.e., what information is exchanged); and (3) the ability of customers to challenge transmission owners’ implementation of the formula rate as a result of the information exchange (i.e., how the parties may resolve their potential disputes).”
OMS Rehearing Request Denied
In a fourth order last week (ER13-2379-001, et al), the commission denied OMS’ rehearing request of its March 2014 orders on the issue.
OMS contended the commission erred when it allowed the revised formula rate protocols to become effective on Jan. 1, 2014, rather than the refund effective date of May 23, 2012, set by the commission when it began the section 206 inquiry.
OMS said FERC could not conclude that the charges assessed between May 2012 and the end of 2013 were just and reasonable. Establishing the effective date in May 2012 “would provide the first opportunity for meaningful review of those charges by state commissions and other interested parties,” OMS said.
The commission said it was not able to determine the justness and reasonableness of the charges assessed under formula rates between May 2012 and December 2013.
“We find it neither necessary nor practical to require application of the revised protocols as of May 23, 2012, because, as OMS recognizes, it is impossible to re-run the full protocols process for past periods. Instead, the protocols establish a new open and transparent process for conducting the MISO transmission owners’ formula rate updates prospectively, beginning Jan. 1, 2014,” the commission said.
FERC added, however, that OMS and other parties had the right to challenge the prior years’ annual updates under section 206 “if there becomes reason to believe that those prior years’ annual updates were in violation of the filed rate, or that unjust and unreasonable (i.e., imprudently incurred) costs were passed through the formula in the charges assessed pursuant to those updates. The commission has authority to order refunds of charges assessed pursuant to those prior years’ annual updates to the extent those are found to have occurred.”
OMS also sought clarification that the revised protocols accepted by the commission in the March 2014 order apply to the revenue requirement established when a transmission owner joins MISO or an existing MISO member switches from a historical to forward-looking formula rate.
The commission responded that while “neither the formula rate protocols nor our prior orders in these proceedings specifically address how the protocols will be applied to initial rates … we expect that all formula rate updates, including initial rates calculated by a transmission owner under Attachment O of the Tariff after Jan. 1, 2014, will be subject to review and challenge procedures consistent with our determinations in these proceedings.”
OMS Executive Director Bill Smith said Friday that it was too soon to say how the organization might respond to the rulings.
NIPSCO, Southern Indiana Compliance Filings
The commission ordered NIPSCO and Southern Indiana to make compliance filings within 30 days revising their Tariffs to specify that they will file their annual informational filing in a separate docket each year.
The commission told NIPSCO to change the deadline for customers to submit formal challenges to the commission to April 1 — one month following NIPSCO’s informational filings. The commission required Southern Indiana to extend the deadline for submitting a formal challenge to April 15.
The Federal Energy Regulatory Commission last week approved the latest set of Order 1000 compliance filings from PJM and MISO.
The commission conditionally accepted MISO’s third-round regional compliance filings (ER13-187-006). It denied requests for rehearing of the commission’s second compliance order issued in May 2014.
FERC also found that PJM and its transmission owners have partially complied with their second compliance order and denied in part and granted in part requests for rehearing and clarification of the order (ER13-198-003).
Both RTOs were directed to make additional compliance filings within 30 days.
FERC also conditionally accepted interregional compliance filings by PJM (ER13-1927-000), MISO (ER13-1923-000) and transmission providers in the Southeastern Regional Transmission Planning region, the Florida Reliability Coordinating Council and the South Carolina Regional Transmission Planning region (ER13-1922).
The orders accepted the proposal to allocate costs of interregional transmission facilities to each region based on its share of the total avoided cost of regional transmission facilities displaced by the interregional project.
Bay Statement on ROFR
Commissioner Norman Bay filed concurring statements in the MISO and PJM regional compliance orders, warning states not to attempt to protect their incumbent utilities from competition in transmission development.
Bay noted that while Order 1000’s prohibition on federal rights of first refusal (ROFR) for incumbent transmission developers does not preempt state law regarding construction of transmission facilities, states are also barred by the Constitution from interfering with interstate commerce.
“State laws that discriminate against interstate commerce — that protect or favor in-state enterprise at the expense of out-of-state competition — may run afoul of the dormant commerce clause,” Bay, a former Constitutional law professor, wrote. “The commission’s order today does not determine the constitutionality of any particular state right-of-first-refusal law. That determination, if it is made, lies with a different forum, whether state or federal court.”
Commonwealth Edison and American Electric Power, which had been members of MISO, later joined PJM, leaving islands of PJM within MISO territory near Chicago and in Southwest Michigan.
The Federal Energy Regulatory Commission last week ordered a paper hearing to revisit its decision to prohibit MISO from assessing export charges to PJM for multi-value projects that benefit PJM customers.
FERC’s Jan. 22 order (ER10-1791) is in response to a 2013 remand by the U.S. Seventh Circuit Court of Appeals ordering the commission to determine whether its limitations on export pricing to PJM are still justified.
The commission will accept comments for 45 days, with reply comments due 30 days afterward. The commission urged parties to provide studies or other evidence in support of their positions.
The issue stems from the commission’s July 2002 order allowing American Electric Power, Commonwealth Edison and Dayton Power and Light to join PJM. That left small islands of PJM within MISO territory near Chicago and in southwestern Michigan, dividing highly interconnected transmission systems.
In subsequent rulings, FERC ordered MISO to eliminate rate “pancaking” that it said would otherwise result from the irregular seam, including a prohibition on charging PJM load for multi-value projects.
Less Disjointed Seam
In June 2013, the Seventh Circuit ordered FERC to reconsider whether its prohibitions on charging PJM for multi-value projects was still reasonable in light of membership changes that straightened out the border.
The court also cited the nature of multi-value projects, noting that they are not local in scope and will benefit other regions.
“Since they will benefit electricity users in PJM, those users should contribute to the costs,” the court said.
It added that FERC was being “arbitrary” in continuing to forbid MISO from charging anything for exports of energy to PJM enabled by multi-value projects “while permitting it to charge for exports of energy to all the other RTOs.”
“The commission must determine in light of current conditions what, if any, limitation on export pricing to PJM by MISO is justified.”
PJM TOs Seek Clarity
Impatient at FERC’s inaction since the court’s remand, PJM transmission owners petitioned the commission last May to set the issue for a paper hearing.
Whatever FERC ultimately decides regarding allocation costs of MISO multi-value projects, the TOs said, “there is no disputing the importance of a timely resolution in this matter. At issue are the costs of billions of dollars of projects, some of which are already underway, with others expected to follow.”
“Until this matter is resolved, interested parties will be left with great uncertainty regarding their burdens with respect to the MVP costs.”
The Federal Energy Regulatory Commission has requested more information on the market impact of the proposed $2.8 billion sale of Duke Energy’s Midwest power plants to Dynegy. FERC’s request caused a postponement of the deal’s closing date.
FERC wants more information to ensure that competition in wholesale power markets will not be impaired. Dynegy is engaged in two large acquisitions — the Duke transaction and a separate $3.45 billion deal with New Jersey-based Energy Capital Partners — to acquire a total of 21 power plants. Both deals were supposed to close during the first quarter.
In their application for approval of the purchase, the companies contend Dynegy’s 6.5% share of the PJM market after completing the two deals would have a minimal impact on competition. FERC said the companies failed to demonstrate that Dynegy’s post-acquisition market share qualified as minimal.
NRC Issues Two Yellow Findings Against Entergy’s Arkansas One
The Nuclear Regulatory Commission issued two “yellow” findings of “substantial safety significance” against Entergy’s Arkansas Nuclear One station, citing shortcomings in the plant’s flood protection barriers.
The problems “created the potential for water to enter the auxiliary building in the unlikely event of extreme flooding, potentially compromising safety-related equipment,” according to NRC Region IV Administrator Marc Dapas.
The problems were discovered at the Russellville, Ark., power station during inspections in 2013 and 2014. The NRC said Entergy has fixed the problems, and the agency is reassessing “the appropriate level of oversight for the plant.”
‘No Chilled Work Environment’ at Palisades Plant, NRC Determines
Nuclear Regulatory Commission inspectors, following up on last year’s report chiding Entergy for a “chilled work environment” at its Palisades Nuclear Plant, says that workers at the Michigan reactor no longer feel uncomfortable raising safety issues.
The NRC reviewed plant operations, conducted focus groups and interviewed 30% of security department workers before issuing its findings that the work climate at the plant had improved. “The NRC will continue to monitor for safety-conscious work environment issues to assess the sustainability of improvements seen to date,” an NRC official wrote.
Palisades spokeswoman Lindsay Rose said the company promised to maintain the improved climate. “This is not an issue that we’re going to drop and wash our hands of,” she said.
FERC Extends Comment Deadline for PennEast Pipeline Project
The Federal Energy Regulatory Commission has extended the public comment deadline from Feb. 12 to Feb. 27 on the proposed PennEast natural gas pipeline running from Pennsylvania into New Jersey after the pipeline operator altered some contentious parts of the 108-mile route.
FERC has already scheduled five public “scoping” meetings, starting this week, which will give the public information on the proposed line. Pipeline opponents argued that the public comment period did not allow enough time for property owners affected by proposed route changes to respond.
The $1 billion pipeline would transport natural gas from the Marcellus Shale region in northeastern Pennsylvania to a connection near Trenton, N.J. It is financed by UGI and four New Jersey gas utilities.
Interior Department Moves Forward on North Carolina Offshore Wind Lease Plan
The Department of the Interior released an environmental assessment last week supporting a plan to lease up to 300,000 acres off the North Carolina coast to developers of wind farms. “In close coordination with our partners in North Carolina, we are moving forward to determine what places make sense to harness the enormous wind energy potential off the Atlantic seaboard,” Secretary of the Interior Sally Jewell said.
The study delineates three areas off the coast that could be leased to developers: about 122,000 acres 24 miles off Kitty Hawk; a 51,000-acre tract 10 miles off Wilmington; and a third area of about 133,000 acres 15 miles offshore of Bald Head Island.
A North Carolina Sierra Club organizer, Zak Keith, called the announcement “a huge opportunity to create jobs and investment in the clean energy sector without the risk of oil spills.” The study is open for public comment through Feb. 23.
The mild winter that has moderated energy prices in New England shouldn’t lull policy makers into complacence about the region’s infrastructure needs, ISO-NE CEO Gordon van Welie said last week.
In a Jan. 21 presentation to the media on the state of the energy market, van Welie acknowledged that this winter has been warmer than the previous two, resulting in less demand for power and natural gas and a reduction in pipeline constraints.
“But this is New England,” van Welie said. “Winter’s not over yet, and a mild winter or two doesn’t guarantee we won’t have extremely cold winters again.”
The increasing reliance on natural gas-fired generation and retirements of oil- and coal-fired power plants have created “an urgent need for more energy infrastructure,” he said.
ISO-NE began a winter reliability program for 2013-2014 that was essentially repeated for the current season. That supplemental program provided financial incentives for oil-fired generators to store more oil than they otherwise would have. It has encouraged dual-fuel capable generation that can switch from gas to oil.
Although the RTO has added $7 billion in transmission since 2003 and has generation projects totaling about 9,500 MW in its transmission queue, plant retirements are causing localized stresses.
“We’re already seeing worrisome conditions in greater Boston, with the recent retirement of the Salem Harbor station and delays in development of the proposed Footprint natural gas power plant. That area will be short of needed resources as soon as 2016,” van Welie said.
Southeastern Massachusetts and Rhode Island also are areas of concern, with Brayton Point’s planned retirement in 2017.
In addition, the RTO hasn’t been able to add natural gas pipeline capacity fast enough to react to increased power and heating demand.
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For each of the last three winters, natural gas prices have risen steeply, showing the effects of increasing pipeline constraints. On Jan. 1, 2014, the spot price for natural gas in New England was nearly $20 higher than the price paid in most of the country.
“They were not only the highest forward prices in the U.S.; at the time, they were the highest on the planet,” van Welie said.
He said ensuring the reliability of the power system will likely require more gas pipelines, more liquefied natural gas storage and more transmission lines.
“The region faces a conundrum: who will be the customer to ensure new gas infrastructure is built? Will it be end-use electricity consumers or electricity producers — that is, generators?” he asked. “Thus far, electric generators have not signed up for additional gas infrastructure and as a result, the New England states have been considering making an investment in additional gas infrastructure on behalf of consumers.
“Until more infrastructure is added, consumers can expect volatile pricing for both natural gas and wholesale power, with price spikes when either the pipeline or power system is operating under stressed conditions,” he said.
