MISO will have to adopt neighbor SPP’s cost allocation method for interregional transmission facilities addressing reliability needs, and both RTOs must revise their proposal for public policy projects, the Federal Energy Regulatory Commission said Thursday.
However, FERC’s Feb. 19 ruling (ER13-1937) accepted the RTOs’ proposal to use adjusted production costs in allocating the costs of interregional transmission facilities addressing economic needs.
MISO and SPP agreed on a number of revisions to their joint operating agreement to comply with Order 1000’s interregional planning requirements. But the RTOs could not agree on apportioning costs for reliability projects.
FERC rejected MISO’s proposal to use only adjusted production costs to evaluate interregional reliability upgrades, saying it must adopt SPP’s plan, which also incorporates avoided costs.
FERC said it agreed with SPP that “adjusted production cost only measures the generation and congestion cost to serve load and does not account for the quantifiable benefits of meeting public policy requirements or addressing reliability issues.”
SPP argued that MISO’s proposal disregarded the nature of the constraint and forced the use of a metric that is irrelevant for measuring the benefits associated with resolving a reliability constraint.
“We agree that SPP’s proposal to use a combination of avoided costs and adjusted production cost savings allocates the costs of interregional transmission facilities addressing reliability needs to SPP and MISO in a manner that is at least roughly commensurate with the estimated benefits of the interregional transmission facility while ensuring that [the RTOs] are not involuntarily allocated costs of these interregional transmission facilities from which they do not benefit,” FERC said.
FERC, however, also faulted SPP because it said it would use a metric “yet to be determined” for public policy projects.
MISO and SPP will have 60 days to file revisions with the commission.
The Federal Energy Regulatory Commission last week approved changes to SPP’s Tariff that clarify the circumstances under which market participants are able to modify their mitigated offers during the operating day.
The commission’s order (ER15-714) approves three changes proposed by SPP to allow:
Market participants to adjust their mitigated energy, start-up, no-load and operating reserve offers during the intra-day period when the resource faces an unexpected need to change fuel types or incurs higher fuel costs due to a commitment extension by SPP;
“Quick-start” resources, which are able to generate power within 10 minutes of being notified by SPP, to address limitations in SPP’s clearing engine by reflecting their start-up and no-load costs in their mitigated energy offer curves; and
Resources with differences between their regulation and economic capacity operating limits to reflect in the real-time market their costs of ramping up or down.
“We find that the specific circumstances described in SPP’s proposal warrant allowing market participants to make intra-day adjustments to their mitigated offers without first seeking approval from the Market Monitor in order to better represent the short-run marginal costs of production for their resources,” FERC said.
SPP’s Independent Market Monitor supported the changes.
Entergy’s request for a $187 million transmission upgrade near Lake Charles, La., will receive a “full review” by MISO’s board following stakeholder dissent over its classification as an out-of-cycle project.
At the Planning Advisory Committee meeting last week, the transmission developer and independent power producer sectors voted against MISO staff’s conclusion that the request by Entergy qualified as an out-of-cycle reliability project. The vote was 2.2 in favor of the recommendation, two against and 4.8 abstaining.
Five smaller out-of-cycle proposals by Entergy received votes of 3.2 in favor and 3.8 abstaining, with the transmission developers voting against.
The MISO board must approve all out-of-cycle requests but only conducts “full” reviews for those receiving negative votes at the PAC.
George Dawe, vice president of Duke-American Transmission Co. and the representative for the transmission developers, told the PAC that MISO had failed to follow its procedures in all of the out-of-cycle requests and that the Lake Charles project failed to meet MISO’s out-of-cycle criteria.
MISO’s transmission planning rules allow out-of-cycle consideration for reliability needs identified after the deadline for inclusion in the annual Transmission Expansion Plan if the project is needed within three years and expected in service within four years. Entergy submitted the request last December, saying increased industrial demand requires the project be completed by June 2018.
Dawe argued that Lake Charles isn’t a baseline reliability project. He also said Entergy had not defined the new load it is citing as the need for the project. He said the scope of the project — including two new substations and 25 miles of 500-kV and 230-kV transmission — appears to be speculative, “beyond what is needed to reasonably serve load.”
Jeff Webb, MISO’s director of planning, repeatedly pressed Dawe to specify exactly how MISO was deviating from established procedures. He also asked that opponents state what alternatives they would suggest while still meeting the June 2018 in-service date sought by Entergy.
“I have trouble seeing how we are deviating from the process,” Webb said.
Stakeholders: Not Enough Details to Justify
“Generally,” Dawe replied, “more information has to be provided regarding this OOC project.”
Dawe said he would like to see evidence that MISO verified Entergy’s load requirements and consideration of alternatives to the project as proposed. “In our view … this project is ripe for [a] market-efficiency project” that could serve ratepayers more efficiently and cost-effectively, Dawe said.
Webb said that if MISO spent another month determining whether Lake Charles qualified as an efficiency project and should be opened to competition, it’s likely that “we wouldn’t have an approved developer until a year from now.”
The question then would be whether service would be in place in time. “You’re asking us, MISO, to take a huge risk,” Webb added.
Dawe reiterated that he didn’t believe Lake Charles met the qualifications for out-of-cycle status.
Beyond Reliability Needs?
Cynthia Crane, principal policy analyst at ITC Holdings, said the need for the upgrades has not been clearly demonstrated, raising doubts about the certainty of Entergy’s need date. Crane told the committee said she was speaking for her company and not the transmission owners sector, which voted yes for the Lake Charles OOC request. (EDITOR’S NOTE: An earlier version of this article incorrectly stated that Crane was speaking on behalf of the transmission owners sector.)
Tia Elliott, director of regulatory affairs for NRG Energy and the IPP sector’s representative, told the PAC that the sheer size of the Lake Charles project warrants further scrutiny.
The project is said to be key in bringing another 617 MW to the Lake Charles area to support a rebounding industrial base.
Crane said her company’s engineers looked at the proposed project and have some concerns that it is larger than is needed for just reliability purposes.
Another issue, she said, is declining oil prices, which portend a potential economic slowdown in the Gulf region. That raises the question of whether Entergy will need the upgrades as early as it has stated, she said.
Clouded by Customer Confidentiality
Webb, as he has in previous meetings in which the Entergy request has been discussed, said Entergy’s need for the project was consistent with previous growth projections presented by the utility and with growth trends in the region.
Charles Long, director of transmission planning for Entergy Services, said the company would have had to have known about additional customer demand by September 2013 to have made the request during the normal MTEP process.
Entergy filed the Lake Charles request with MISO on Dec. 15, saying it learned of the new demand Dec. 1.
MISO said that it has not been privy to customer communications with Entergy about their expansion plans. Entergy has said that information is confidential for competitive reasons.
One stakeholder suggested that utilities that cite confidentiality claims as a reason not to be as forthcoming with MISO should be summarily denied out-of-cycle requests.
Webb said he didn’t think MISO has the authority to delve into confidentiality agreements between a utility and its industrial customers.
Some 24,447 MW of capacity resources cleared Feb. 2nd’s auction at $9.55/kW-month, an increase of more than one-third over the $7.025/kW-month clearing price for most resources in FCA 8 last year. Administrative pricing was used in the Southeastern Massachusetts-Rhode Island zone, with prices set at $17.73/kW-month for 353 MW of new resources and $11.08/kW-month for 6,888 MW of existing resources.
The Federal Energy Regulatory Commission once again dashed the hopes of the New England congressional delegation seeking to challenge the results of last year’s capacity auction.
FERC Chairman Cheryl LaFleur wrote to the delegation on Feb. 18, telling members that FERC completed its review of the eighth Forward Capacity Auction when it denied a rehearing request in October.
“As that case is no longer an open case, we are unable to reopen the question of the justness and reasonableness of the FCA 8 rates,” LaFleur wrote. “However, even if we could reopen that proceeding, I continue to believe that the rates resulting from FCA 8 are just and reasonable.”
The auction became effective as an “operation of law” in September when the commission — then short one member — deadlocked 2-2 over whether to reject the results due to unchecked market power. (See FERC Commissioners at Odds over ISO-NE Capacity Auction).
The auction, held in February 2014, saw prices more than double from the previous year’s auction to a total of about $3 billion.
FERC is back to its full complement of five commissioners with the addition of former Arkansas regulator Colette Honorable. The delegation wrote to the commission, asking it to use Federal Power Act section 205 or 206 authority to look at the ISO-NE rates that have resulted from the auction. Those rates take effect in the 2017/18 capacity commitment period.
“We strongly supported the commission’s decision to conduct further review of the results of FCA 8 last summer but believe FERC’s failure to make a conclusive decision in September 2014 has unfairly left the ratepayers of New England without appropriate redress,” the delegation wrote Jan. 30. The letter was signed by six senators and 13 congressmen.
FCA 9, held Feb. 2, resulted in even higher prices — an estimated $4 billion for the 2018/19 capacity commitment period. Analysts said prices are likely to fall in the future as a result of new capacity that cleared in the 2015 auction. (See ISO-NE Capacity Prices Likely to Fall in Future.)
EPA’s proposed Clean Power Plan was the subject of several panels at last week’s winter meetings of the National Association of Regulatory Utility Commissioners (NARUC) in Washington. Energy Secretary Ernest Moniz and EPA Administrator Gina McCarthy also talked about the plan in remarks to hundreds of attendees during NARUC’s general session Tuesday.
The Nuclear Regulatory Commission said it was pleased with the way Entergy employees handled a shutdown of Pilgrim Nuclear Power Station during a blizzard in January, but it is continuing a review of the incident.
“We hope there are lessons learned that get incorporated for all future significant storms, because this has been twice in recent years where severe winter weather has resulted in a loss of offsite power and the plant having to shut down,” NRC spokesman Neil Sheehan said.
Equipment issues caused the plant to remain shut down for 12 days following January’s blizzard. The NRC plans to release a final report of its review 45 days after it completes an inspection.
The Nuclear Regulatory Commission will take over the environmental review of the proposed Yucca Mountain nuclear waste repository because the Department of Energy won’t, according to Chairman Stephen Burns.
The NRC has found that the project could be built and operated safely, but construction can’t begin until the environmental review is complete. Burns said the agency has funds available to cover the costs of preparing a supplemental environmental impact statement.
Opponents Gathering for FERC Hearings on PennEast Pipeline
The Federal Energy Regulatory Commission is holding two public hearings this week in New Jersey on the proposed $1.2 billion PennEast natural gas line. The 114-mile pipeline would run from Northeastern Pennsylvania across the Delaware River to New Jersey and would deliver gas from the Marcellus Shale region to East Coast markets.
Opposition has grown since the pipeline was announced in October. “There is a concern that one new pipeline can become a pipeline corridor,” said Paul Pogorzelski, Hopewell Township Administrator. The township has filed letters of opposition with FERC.
One hearing is scheduled for Wednesday in Ewing, N.J., and another Thursday in Hunterdon County.
FERC OKs Environmental Study for Puerto Rico LNG Terminal
The Federal Energy Regulatory Commission approved the final Environmental Impact Statement for the proposed Aguirre Offshore GasPort Project in Puerto Rico. The floating plant would convert liquefied natural gas that arrives by ships into usable gas for Puerto Rican customers.
FERC concluded that the project would result in minimal environmental impact, mostly during construction, and that the completed LNG terminal would help improve the environment through decreased barge traffic in the area.
The environmental review took three years. Excelerate Energy is developing the project in cooperation with the Puerto Rico Electric Power Authority.
IG Report: DOE Conferences Spent $21M on Golf, Dinner Cruises
A Department of Energy inspector general’s report shows that the department spent $21 million over 16 months on social events at conferences. The report shows that the expenses were racked up during 300 conferences between April 2013 and September 2014.
“We found that attendance at some conferences included associated social events,” according to the report. “For example, [Energy Department documents] showed department-sponsored conferences that included a casino night, Super Bowl party, golf tournament, banquet on a dinner cruise boat, dinner at the NASCAR Hall of Fame and a tour and dinner at an aquarium.”
BOEM to Hold Meeting in NJ Before Offshore Drilling Starts
Three New Jersey lawmakers obtained a promise from the U.S. Bureau of Ocean Energy Management to hold a public meeting before the Obama administration opens up parts of the Atlantic Ocean to oil and gas drilling.
Though the areas that the agency has proposed for oil exploration are located hundreds of miles south of New Jersey, Sens. Robert Menendez and Cory Booker and Rep. Frank Pallone sent a letter to the White House expressing their concerns with potential spills on New Jersey’s shore. They asked for a public comment session to be held before any final permits were granted.
BOEM last week promised to hold a public meeting. Booker called it an “important first step in helping the Obama administration understand the severity of the environmental and economic risks to New Jersey if oil and gas drilling in the Atlantic Ocean’s fragile ecosystem is permitted.”
The 40-MW coal-fired White Pine power plant is one of three power plants whose SSR agreement costs MISO must reallocate. (Source: Traxys)
The Federal Energy Regulatory Commission denied MISO’s request for a rehearing of the commission’s July order that said the RTO could no longer allocate broadly within the American Transmission Co. pricing zone the costs of keeping open three power plants in Michigan’s Upper Peninsula.
MISO must now file a new study method to identify entities that benefit directly from the three plants operating under system support resource agreements (SSRs) and allocate costs of the agreements directly to them, the commission ordered on Feb. 19 (EL14-34-001).
The SSR plants at issue are Presque Isle, White Pine and Escanaba.
A few days before FERC’s order, however, Presque Isle owner We Energies asked MISO to seek the termination of SSR payments. We Energies acted after iron ore mining company Cliffs Natural Resources committed to remaining a customer of the aging 400-MW coal-fired plant near Marquette.
Wisconsin PSC Complaint
FERC’s order is a win for the Wisconsin Public Service Commission, which filed a complaint last year alleging that MISO improperly allocated SSR costs on a pro rata basis to all load-serving entities in the ATC footprint.
The PSC argued that 92% of the projected $52.2 million in annual fixed costs under the original Presque Isle SSR agreement would be allocated to load-serving entities in Wisconsin even though they would receive only 42% of the benefits from the plant’s continued operation.
FERC’s Feb. 19 order also rejected MISO’s request to revise cost allocation of the three SSR plants to reflect new, local balancing authorities established recently in the ATC pricing zone.
Michigan Complaints Moot
In a related order, FERC also dismissed as moot complaints that objected to the LBA and its cost allocation implications for the three SSR plants (ER14-103).
The Michigan Public Service Commission had alleged that Wisconsin Electric manipulated SSR cost allocation by splitting its LBA in half, with one portion encompassing Michigan’s Upper Peninsula, to increase Michigan’s allocation of SSR costs tenfold.
Michigan residential and commercial electric customers, along with numerous government agencies, flooded FERC with complaints about the effects the SSR allocation would have in the Upper Peninsula.
But FERC said the Michigan complaint was moot, as “we direct MISO to devise a new approach that will identify benefitting LSEs without relying on LBA boundaries.”
FERC said it would address refund requirements in a future order involving MISO’s new study methodology.
In a bid to win D.C.’s approval of its takeover of Pepco Holdings Inc., Exelon last week more than doubled the amount of customer credits it is offering to $33.75 million from $14 million.
The offer to increase the “Customer Investment Fund” came on the heels of its success in New Jersey, where Exelon received full approval from the Board of Public Utilities, and Delaware, where it reached a settlement with the staff of the Public Service Commission and other parties.
Those advances didn’t come cheap, though. The company originally offered $29 million in customer credits and other incentives to New Jersey customers but later upped that to $62 million. Their offer to Delaware started out at $17 million in direct customer credits, but the latest settlement offer — still to be acted on by the PSC — is $49 million in credits along with other incentives.
Not Convinced
Despite its improved offer, Exelon hasn’t won the support of D.C.’s customer advocate.
“The ‘pot sweetener’ is a factor that needs to be evaluated along with other factors in the case to determine if the proposal meets the public interest standard,” People’s Counsel Sandra Mattavous-Frye told RTO Insider. “By no means does this new proposal to increase the CIF end the matter.”
The company also enhanced its commitment to increasing reliability, vowing to meet or exceed the D.C. PSC’s existing standards “without increasing Pepco’s forecasted reliability spending.” If Pepco does not achieve the reliability performance target, it would be subject to penalties of up to $5.6 million annually, the company said.
Mattavous-Frye said that Exelon had failed to address reliability concerns earlier.
“Reliability has been a focus for [the Office of the People’s Counsel] for the past 10 to 12 years,” she said Friday. Exelon’s “new reliability commitment is vastly different than their position from the beginning of the case that they could not meet the reliability standard,” she said. “Therefore, OPC is carefully evaluating the details that support this new commitment to ensure it is viable.”
Exelon CEO Chris Crane said the latest offer shows that the company is paying attention to the needs of the District. “We’ve listened to the feedback of stakeholders in the District of Columbia and have substantially enhanced our proposed package,” he said in a statement.
Delay Likely
The negotiations with state regulators are taking a toll on Exelon’s timetable for approval.
Initially, Exelon said that it anticipated closing the acquisition in the second quarter. Exelon spokesman Paul Adams said last week that it now appears the deal may not be consummated until the third quarter.
The D.C. PSC is scheduled to hold evidentiary hearings from March 30 through April 8, which would mean a decision in late July or early August, Mattavous-Frye said. She said talks between parties continue but, “at this point, it is not clear if a settlement will be reached in this case.”
Maryland Remains
In addition to D.C., Exelon still must win support from regulators in Maryland.
Adams said the company is prepared to up its offer to there too.
“During the hearings before the commission in Maryland, Exelon CEO Chris Crane made clear that Exelon would accept, as a final resolution of the matter in Maryland, a settlement on terms equivalent to the settlement in New Jersey” prorated for the number of customers, Adams said.
“The settlement in Delaware is equivalent to the New Jersey settlement, and both are equivalent to what we have offered in D.C.,” Adams said. He did not say when a new offer to Maryland would be presented.
Exelon’s initial offer of customer credits for Maryland was $40 million. The state’s PSC staff has recommended $167 million in credits.
The state’s Office of People’s Counsel has urged the PSC to turn down the deal as it stands, calling the benefits Exelon is offering “either non-existent or woefully deficient.”
Generators would be permitted to sell frequency response services at market-based rates under a rule proposed by the Federal Energy Regulatory Commission last week.
“While most balancing authorities should be able to meet the new reliability standard using their own resources, some may nevertheless be interested in purchasing primary frequency response service from others if doing so would be economically beneficial,” the commission wrote, concluding “there could be interest in the near future in voluntary purchases of a primary frequency response product.”
FERC would allow entities with market-based rate authority for energy and capacity to also sell frequency response at market-based rates.
The NOPR applies to generators providing primary frequency response — the ability to automatically change their output within seconds when the grid’s frequency strays above or below 60 Hz.
It is distinguished from regulation — also known as secondary frequency response — which involves manual or automated dispatch from a centralized control system.
The requirements of the reliability standard will be phased in over a year beginning April 1. The commission expects to finalize the rule after a 60-day comment period.
Public Service Enterprise Group reported fourth-quarter net income of $476 million ($0.94/share), more than double the $200 million ($0.39/share) for the same quarter in 2013. The company posted net income of $1.518 billion ($2.99/share) for 2014, compared to $1.243 billion ($2.45/share) a year earlier.
CEO Ralph Izzo attributed the increased earnings to its investments in its regulated business, Public Service Electric & Gas. “As a result of an extended capital program, earnings from our regulated company grew to represent 52% of our consolidated operating earnings, as PSE&G’s investment in transmission has grown to represent 39% of its $11.4 billon rate base.”
Izzo highlighted several aspects of the investment in the regulated business, much of it in response to the pounding New Jersey, and PSE&G in particular, took during Hurricane Sandy. “We received approval to invest $1.2 billion in Energy Strong, a program that will improve the resiliency of our electric and gas distribution systems,” he said during a conference call.
The company is updating and replacing about 250 miles of its natural gas lines, as well as making upgrades to its electric transmission network. “We completed construction of two, 230-kV transmission lines during the year, as well as the New Jersey portion of the 500-kV Susquehanna-Roseland line,” he said.
Izzo acknowledged that PSEG Power’s bid to build a new 475-MW combined-cycle plant in Connecticut didn’t clear ISO-NE’s recent capacity auction, but he said “we haven’t abandoned this work and we’ll invest when the markets support its development.” (See Exelon, LS Power Join CPV in Adding New England Capacity.)
