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November 5, 2024

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FERC Upholds VEPCO Obligation to Purchase Solar Energy from Small QFs

The Federal Energy Regulatory Commission last week denied a request by Virginia Electric and Power Co. to terminate its obligation to purchase electricity from nine North Carolina solar facilities. The facilities, owned by Community Energy Solar, each have a net capacity of 4.99 MW.

VEPCO had filed the request last October.

solarIn 2008, FERC terminated VEPCO’s obligation to purchase energy from qualifying facilities (QFs) larger than 20 MW in its service territory, with the presumption that such facilities have nondiscriminatory access to the PJM markets.

At the same time, FERC created the presumption that smaller qualifying facilities did not have the same access to the markets because of their size. The commission placed the burden of proof on utilities seeking to terminate agreements to show otherwise.

“We find that the nine Community Energy QFs established legally enforceable obligations under [the Public Utilities Regulatory Policies Act] prior to VEPCO’s filing of its application to terminate its mandatory purchase obligation for those QFs, and we therefore deny VEPCO’s application,” FERC said in its April 16 ruling (QM15-1-000).

— Suzanne Herel

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FERC Clarifies NYISO ICAP Market Power Mitigation Order

By William Opalka

The Federal Energy Regulatory Commission on Thursday clarified unresolved issues from a previous order on the installed capacity market in New York that have been pending for nearly three years (EL11-42).

new yorkIn it, FERC accepted NYISO’s filings in response to the June 22, 2012, order, which directed the ISO to clarify how the mitigation exemption test and offer floor calculations are implemented. The commission had found merit in a complaint by NRG Energy and several other generators that NYISO’s implementation of the buyer-side mitigation rules lacked transparency.

NYISO said the 2012 order was unclear with respect to the comparison made between the default offer floor and unit net cost of new entry in determining the offer floor. FERC said NYISO’s interpretation is correct, in that the value for unit net CONE to be used should be only the first-year value of the three-year average of annual unit net CONE.

FERC also:

  • Confirmed NYISO’s method of adjusting the offer floor for inflation.
  • Ordered NYISO to change how it adjusts unit net CONE for inflation.
  • Affirmed its finding that NYISO has justified its use of natural gas futures prices and historical prices in its net CONE calculations.
  • Ordered NYISO to incorporate language allowing the Market Monitoring Unit to consider all factors relevant to mitigation exemption and offer floor determinations in its reports reviewing whether the ISO’s mitigation and exemption determinations were conducted in accordance with its Market Administration and Control Area Services Tariff.

FERC also ruled Thursday in a case related to the ICAP, in which Astoria Generating and TC Ravenswood had alleged that NYISO’s buyer-side market mitigation provisions were improperly administered (EL11-50). The order generally denied rehearing, but it ordered the ISO to use the Astoria II plant’s actual cost of capital in its mitigation exemption determination.

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FERC Denies Rehearing Requests on NYISO Order 1000 Compliance Filing

By William Opalka

The Federal Energy Regulatory Commission accepted most of NYISO’s and New York Transmission Owners’ second compliance filing for Order 1000 while denying multiple requests for rehearing (ER13-102).

The parties have 30 days to submit a further compliance filing.

FERC denied LS Power’s request for rehearing, saying that cost-effectiveness is appropriately assessed in NYISO’s proposed evaluation process.

nyiso
NYISO transmission lines. (Click to zoom.)

The commission previously expressed concern that NYISO’s regional cost allocation method for public policy transmission projects could cause unnecessary delays for transmission developers seeking regional cost allocation. FERC accepted the ISO’s proposal that the process for deciding the cost allocation method run in parallel with state siting proceedings.

FERC also:

  • Accepted NYISO’s revisions clarifying how it will review transmission owners’ local transmission plans to determine whether alternative transmission solutions might meet reliability needs. FERC noted that NYISO and the Long Island Power Authority have agreed to tariff revisions that allow LIPA to determine whether “a proposed transmission need driven by public policy requirements requires a physical modification to transmission facilities located solely within the Long Island Transmission District, while also allowing the New York [Public Service] Commission to determine that a transmission need driven by public policy requirements identified by LIPA is a regional transmission need driven by public policy requirements.”
  • Accepted NYISO revisions on who may qualify as an approved transmission developer. A prospective transmission developer will be allowed to submit a detailed plan for financing, developing, constructing, operating and maintaining a transmission facility. The ISO may require information about transmission facilities that the prospective developer has already constructed.
  • Ordered NYISO to treat whether or not a nonincumbent developer has received its siting permits and other authorizations under New York state law as just one factor in the ISO’s selection process.
  • Ordered revisions to clarify that only disputes within the New York PSC’s sole jurisdiction may be subject to judicial review in state courts.
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Consumers Energy, Wolverine Power OK’d to Reclassify Facilities as Transmission Assets

By Chris O’Malley

The Federal Energy Regulatory Commission on Thursday approved requests by two Michigan electric utilities to reclassify a number of distribution facilities as transmission assets within MISO.

FERC granted requests by Consumers Energy (ER15-910) and Wolverine Power Supply Cooperative (ER15-976). Consumers initially filed its reclassification request with the Michigan Public Service Commission, which last October approved a settlement (U-17598) between the utilities and Michigan Electric Transmission Co. (METC). The PSC approved a settlement over Wolverine’s reclassification of the assets from “excluded transmission” to “included transmission” in January (U-17742).

Consumers transferred its transmission assets in 2001 to then-subsidiary METC. A year later, it sold METC to another company, which sold it to current owner ITC Holdings.

In 2012, however, ReliabilityFirst Corp. informed Consumers that its audit had determined that a small set of the company’s distribution facilities were actually transmission facilities.

Consumers said its own analysis confirmed RFC’s findings and identified other assets that it said were similarly misclassified.

In total, Consumers said, the facilities to be reclassified have a net value of $34 million, representing 1.32% of Consumers’ distribution plant. They include equipment in 69 substations on 138-kV transmission lines, 65 138-kV line segments and six substations connecting those lines to Consumers’ bulk power substations.

Consumers noted that FERC previously stated that the 100-kV threshold has been among the factors in determining whether an asset is part of the bulk electric system.

Consumers plans to sign the MISO Transmission Owners Agreement and will join the Michigan Joint Zone, under MISO Rate Schedule 11. FERC also ordered Wolverine to include its reclassified facilities in the Michigan Joint Zone.

Ratepayer Implications Minimal

Consumers said the reclassification will benefit consumers by placing the transmission assets under “the functional control” of MISO. Becoming a transmission owner will allow it to more fully participate in the RTO, Consumers said.

Consumers said the increased costs of the reclassification are negligible, with an incremental revenue requirement of about $50,000, or .001% of Consumers’ $3.9 billion base rate revenue.

The utility noted that some of the assets are used to provide wholesale distribution service. “To avoid a potential double recovery, Consumers will remove the applicable assets from the wholesale distribution service rate and include them instead under its forthcoming transmission rates under the MISO Tariff.”

Wolverine also said a portion of its reclassified assets are also used to provide wholesale distribution service. To avoid a double recovery, Wolverine said it will coordinate with MISO to separately submit a filing to terminate its wholesale distribution service rate with the Zeeland Board of Public Works.

Wolverine said the net plant value of its updated list of included transmission facilities is $249.91 million, or an increase of nearly $16 million.

Tom King, Wolverine’s director of regulation and policy, told RTO Insider that the co-op is still calculating the impact of the change but expects the reclassification to be positive for its members.

Consumers officials could not be reached for comment.

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Company Briefs

The Tennessee Valley Authority has purchased a 700-MW gas-fired combined-cycle plant in Ackerman, Miss., from Quantum Choctaw Power. The plant is a two-one-one configuration and is the sixth combined-cycle plant TVA has purchased or built since 2007. TVA said in February, when it announced board approval of the purchase, that it would pay $340 million for the plant. The authority is retiring many of its coal units and either building or purchasing gas-fired generation in an attempt to meet emissions mandates.

Quantum Choctaw was owned by Quantum Utility Generation, an independent power producer that has coal- and gas-fired plants in Florida, Virginia and Mississippi, a solar project in Guam, and wind energy projects in Connecticut, Pennsylvania, Maine and Minnesota.

More: The Chattanoogan

TVA Has No Plans to Restart Construction of Bellefonte

The Tennessee Valley Authority’s 20-year plan for electricity generation sees the possibility of uprates at existing, operating nuclear stations and probably more natural gas and renewable generation, but its dormant Bellefonte nuclear plant doesn’t fit into any of those plans. The authority’s draft integrated resource plan is the subject of public hearings before it goes to the TVA board for a final vote in August.

Construction of the Bellefonte plant began near Hollywood, Ala., in 1974, but was abandoned in the 1980s after an investment of about $4.5 billion. The authority voted to restart construction of the plant in 2011, but that plan was killed in the face of slumping power demand the next year. The authority decided to go ahead with plans to complete Watts Bar Unit 2, another reactor that had been started in the previous century and then stopped. It is currently scheduled to go online by the end of this year.

More: Huntsville Times

National Grid Starts Construction on Advanced-Technology Solar Project

National Grid is starting construction of a 650-kW solar facility in Massachusetts that will test advanced technology ahead of the company’s plan to build 16 MW of solar generation in 19 sites in that state. The pilot project will test the use of new inverters, a vital component of the process of feeding solar energy into the grid. The move is part of the utility’s effort to contribute to the state’s goal of having 1,600 MW of solar by 2020. Much of the company’s efforts so far have been on connecting third-party solar generation to the grid, although it has solar generating facilities in five Massachusetts towns.

More: FierceEnergy

AWEA: Wind Industry Added 23,000 Jobs in 2014

The wind industry added 23,000 jobs in 2014, raising the total to 73,000 positions, according to the American Wind Energy Association. In its 2014 report, AWEA said 12,700 MW of wind projects were under construction as this year began. “These results show that extending the Production Tax Credit for wind power in 2013 was good for business in America,” AWEA CEO Tom Kiernan said. “We’ve got a mainstream, Made-in-the-USA product that supports jobs in every state and is gaining momentum. With a more predictable policy, we can add more jobs and keep this American success story going.”

More: PennEnergy

FirstEnergy’s Beaver Valley Loses Unit to Bad Pump Bearing

One of the reactors at FirstEnergy’s Beaver Valley nuclear station near Shippingport, Pa., went offline Wednesday when a pump supplying non-radioactive water to the steam generators shut down, probably due to a bad bearing. One of the two pumps serving Unit 1 showed signs of failing, and workers shut the reactor down at about 4 a.m. Repairs will take several days, a company spokeswoman said Thursday. Company officials said the other pump could serve the reactor at only 50% capacity.

More: PennEnergy

FE Delays Bruce Mansfield Decision Because of Possible PJM Auction Delay

FirstEnergy has decided to put off a final decision on whether to invest in a dewatering facility for coal ash control at its Bruce Mansfield coal-fired power plant until it knows when PJM’s annual capacity auction will be held. The company wants to see if the plant would clear the auction before deciding whether to invest in the dewatering facility. PJM has asked FERC for permission to delay the annual action, usually held in May, pending final commission rulings on its Capacity Performance proposal. FirstEnergy says it will now make the decision sometime this summer.

More: Pittsburgh Business Times

FirstEnergy Closes 3 Ohio Coal Plants

FirstEnergy, saying it was better to retire aging coal plants than retrofit them to make them conform to emissions mandates, has closed three coal-fired plants in Ohio.

The Ashtabula plant on the shores of Lake Erie, Lake Shore and Eastlake plants, all in northern Ohio, were shuttered last week. They were part of a list of nine the company announced in 2012 it would be retiring. Six of those nine have been decommissioned already. These are the last of that original list. The retirement of the final three was delayed until improvements could be made to transmission lines to accommodate the transmission of power in the absence of those plants. That work was completed at the cost of about $263 million, company spokeswoman Stephanie Walton said.

“There will be a period of shutdown activity, then the plant will be put into a safe and environmentally secure mode,” Walton said, describing the process for the Ashtabula plant.

More: Star Beacon

PPL Retiree Loses Bid to Have NRC Review Nuke Transfer Decision

The Nuclear Regulatory Commission has denied a request made by a former PPL employee to have the commission review its decision to transfer the operating licenses for the company’s sole nuclear plant to a projected merchant generation spinoff. Douglas B. Ritter asked the commission to hear arguments on the transfer, which the commission just formally approved.

PPL and assets associated with Riverstone Holdings are spinning off and forming Talen Energy. Ritter had raised questions about the Susquehanna nuclear plant’s operation under the new ownership, and about the plant’s decommissioning funds and waste storage. The commission based its decision on the lack of “admissible contention” in Ritter’s request.

“I’m disappointed that those issues have not been addressed publicly by the NRC,” said Ritter, who worked for 34 years at PPL and lives about four miles from the plant. “I feel like we the public are being kept in the dark by the NRC, but that’s big business, I guess.”

PPL said it expects to close on the Talen arrangement by the end of the second quarter.

More: The Morning Call

PPL Montana to Sell Retired Plant, Equipment

PPL Montana announced that it wants to sell the land, buildings and equipment of its retired J.E. Corette Steam Electric Station. The 153-MW plant, on 74 acres along the Yellowstone River near Billings, was built in 1968 and shut down last month. The company said its decision to retire the plant was based on the high cost of upgrades that would have been necessary to make it comply with emissions rules.

More: Great Falls Tribune

NextEra to Build 81-MW Solar Plant in Arkansas

NextEra Energy Resources is building an 81-MW solar plant in Arkansas County, Ark. The facility, in the Grand Prairie region of the county, will be the largest solar facility in the state. Entergy Arkansas has signed a 20-year power purchase agreement to buy the plant’s electricity, and a new substation will be constructed to transmit the power to Entergy Arkansas’ system. NextEra has applied with the state Public Service Commission to gain approval for the plant. Entergy and NextEra said the plant will be operational by mid-2019.

More: Entergy

ATC Names Mike Rowe as New CEO

Mike Rowe, an expert in asset management and construction, has been named the new CEO of American Transmission Co. Rowe will be taking the position of John Procario, who has headed up ATC since 2009. Procario announced his plans to retire last year.

Rowe has been with the Pewaukee, Wis.-based company for the past eight years, where he started as the vice president of construction, and later moved on to head the Asset Management, System Operations and Transmission Planning departments. He was promoted to executive vice president and chief operating officer in 2012. Before coming to ATC, Rowe was director of Engineering & Asset Management for Kansas City Power & Light. Before that, he spent 22 years with Commonwealth Edison in Chicago.

More: American Transmission Co.

NRG Pumps More Capital into Residential Solar

While many utilities are fighting the expansion of residential solar through challenges in state legislatures, NRG Energy is doubling down on its investment in that area. Having already fielded a company that specializes in home solar installations, NRG Home Solar, the energy giant announced it is pumping yet more money into the business. The company and its investment arm, NRG Yield, have formed a partnership that will invest up to $150 million in cash into Home Solar.

“With the completion of this partnership between the companies, we initiate a new phase in the growth strategy of the NRG Home business unit and NRG Yield,” says David Crane, CEO of NRG and chairman and CEO of NRG Yield.

More: Solar Industry

MYR Group Buys Eversource’s Transmission and Distribution Co.

MYR Group is buying E.S. Boulos, Eversource Energy’s electrical contractor that specializes in transmission, distribution and substation design and construction. ESB is headquartered in Westbrook, Maine. It was purchased by Eversource in 2001 and operated as a non-regulated company. Industry reports say the Illinois-based MYR is paying $11.4 million for the company.

More: Virtual Strategy

Millstone Nuke Worker Says He Was Fired for Reporting Co-worker’s Drug Use

A worker at Dominion Resources’ Millstone nuclear station in Connecticut told Nuclear Regulatory Commission officials that he was fired in retaliation for reporting a co-worker’s narcotic use. “I got fired for bringing up a safety issue, and you, the NRC, need to support me,” Stephen Lavoie said during the agency’s annual meeting with the Connecticut Nuclear Energy Advisory Council. NRC officials promised to look into Lavoie’s allegation. But Millstone spokesman Ken Holt said Lavoie was laid off because the demand for insulation workers had dropped. An independent investigator looked into Lavoie’s claim and found nothing to substantiate it, Holt said.

More: The Day; CBS Connecticut

Dominion Boosts Solar Fleet with Purchase of 20-MW Georgia Facility

Dominion Resources has purchased a 20-MW solar facility in Georgia, bringing the total amount of solar generation in its stable to 364 MW at sites throughout the U.S. Dominion paid an undisclosed amount for the Richland Solar Center in Twiggs County, Ga., from HelioSage Energy. It also secured a 20-year power purchase agreement with Georgia Power. David A. Christian, CEO of Dominion Generation, said the company wants to have 625 MW of contracted solar generation by the end of 2016. Dominion has set a goal of developing up to 400 MW of solar generation in Virginia alone by 2020.

More: Atlanta Business Journal; Street Insider

EPRI Names Gil Quiniones New Board Chairman

The Electric Power Research Institute has elected Gil Quiniones chairman of its Board of Directors. Quiniones is president and CEO of the New York Power Authority, the nation’s largest state-owned electric utility. Current board member Patricia Vincent-Collawn, CEO of PNM Resources, was elected vice chair. Five new members were also elected: Lisa Johnson, CEO of Seminole Electric Coop.; Warner Baxter, CEO of Ameren; Mark McCullough, executive vice president of generation at American Electric Power; William Spence, CEO of PPL; and Dr. Seok Cho, CEO of Korea Hydro and Nuclear Power.

More: EPRI

Investor in McClendon Firm Settles Chesapeake Claim for $25M

Energy & Minerals Group has settled a trade secrets lawsuit by paying Chesapeake Energy $25 million. Chesapeake claimed that former CEO Aubrey McClendon stole trade secrets from Chesapeake when he left to form his own firm, American Energy Partners. EMG is a major investor in American Energy Partners.

EMG had earlier described the claims against McClendon as meritless and has invested nearly $3 billion in McClendon-directed ventures. Chesapeake claimed that the information was used to acquire Utica Shale field drilling rights. The settlement releases one of American Energy Partners’ affiliates, American Energy-Utica, harmless in exchange for the $25 million and drilling rights to 6,000 acres.

The full terms of the settlement remain confidential, but the settlement size says a lot, one expert says. “Nobody settles a lawsuit by paying $25 million and signing over 6,000 acres of valuable oil and gas leases unless they are at least a little bit troubled by what they have learned,” said Erik Gordon, a professor at the University of Michigan.

More: Reuters

Dynegy CEO Says Coal Plants Ready to Meet Emissions Regs

Dynegy CEO Robert Flexon said in an interview last week with Bloomberg News that its coal-fired generation fleet is ready to meet the looming increased emissions rules. While other companies, such as American Electric Power, are retiring aging units, Dynegy has gone on a buying spree of coal-fired generation or already retired aging plants in advance of the Environmental Protection Agency’s Mercury and Air Toxics Standards implementation.

“Coal accounts for 48% of Dynegy’s generating capacity of 25,758 MW, which is enough to power 21 million homes,” Flexon said. “All of the plants are compliant with the MATS rules and the EPA’s cross-state pollution regulations that started to get implemented this year,” he said.

He also said he expects PJM to receive approval to delay its annual capacity auction while Capacity Performance rules are finalized.

More: Bloomberg News

Compiled by Ted Caddell

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FERC Rejects Rehearing Request on SPP Order 1000 Filing

By Rich Heidorn Jr.

The Federal Energy Regulatory Commission last week rejected LS Power’s request for rehearing on SPP’s Order 1000 procedures and accepted the RTO’s December compliance filing (ER13-366).

The transmission developer had challenged the commission’s October 2014 order allowing SPP to retain tariff provisions requiring consideration of state law and rights-of-way in the early stages of its competitive bidding process. The commission had made a similar finding in a ruling on PJM last May, reversing the directive it had originally given. (See Order 1000 Reversal: Reality Check or Surrender to Incumbents?)

FERC said LS Power’s challenge “seeks to expand the reach of Order No. 1000’s reforms by prohibiting SPP from recognizing state or local laws or regulations when deciding whether SPP will hold a competitive solicitation.”

The commission noted that while Order 1000 barred any federal right of first refusal for incumbent transmission owners in commission-jurisdictional tariffs, it did not require removal of references to state or local preferences.

While recognizing that FERC lacks jurisdiction to overrule state laws, Chairman Norman Bay issued a concurring statement that seemed to invite a constitutional challenge to state laws that prohibit nonincumbent developers from winning the right to build a transmission project.

“The Constitution limits the ability of states to erect barriers to 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,” wrote Bay, a former law school professor. “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.”

The commission also rejected LS Power’s challenge to SPP’s process for evaluating competitive bids, saying the RTO “has sufficiently demonstrated that the proposed weighting of its evaluation criteria is not unduly discriminatory and will result in a regional transmission planning process that selects more efficient or cost-effective transmission solutions.”

While it rejected LS Power’s rehearing bid, the commission said SPP’s rights-of-way provision is vague. It ordered the RTO to revise tariff language “that refers to ‘rights-of-way where facilities exist’ to make it consistent with the commission’s finding that retention, modification or transfer of rights-of-way remain subject to relevant law or regulation granting the rights-of-way.”

The commission said the revision would address a protest by South Central MCN, a competitive transmission company that plans to partner with electric cooperatives and municipal utilities in SPP. It denied South Central’s request to schedule a technical conference on RTO competitive bidding processes under Order 1000 as outside the scope of the SPP proceeding.

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ITP10 to Include 3 Scenarios for Clean Power Plan

By Rich Heidorn Jr.

TULSA, Okla. — SPP’s next 10-year transmission plan will consider three future scenarios to assess the potential impact of the Environmental Protection Agency’s Clean Power Plan, members agreed after a lengthy debate last week.

The Markets & Operations Policy Committee decided the 2017 Integrated Transmission Planning 10-Year Assessment will include one scenario assuming regional compliance with the EPA rule and one assuming state-by-state compliance. The third scenario will be a business-as-usual case that assumes the EPA rule is abandoned — due, for example, to a legal challenge or a change in leadership at EPA after the 2016 presidential election.

clean power plan
SPP’s 2015 10-year plan compared a business-as-usual case, which projected the need for 15.3 GW of new conventional generation at 60 sites, with a decreased baseload scenario, which projected a need for 21 GW of new conventional generation at 82 sites. The latter scenario assumed the retirement of all coal units less than 200 MW and a 20% reduction in hydropower capacity due to drought.

EPA plans to issue the final rule this summer. It is intended to reduce power generation CO2 emissions by 30% from 2005 levels.

SPP this month released a study estimating the RTO could comply with the rule through a regional approach that includes a $45/ton carbon adder and 7.8 GW of additional generation, most of it wind. The study estimated an annual cost of $2.9 billion in increased energy costs and capital spending for new gas and wind generation. It did not evaluate additional transmission that may be needed, an element ITP10 will seek to quantify. (See SPP: $45/ton Adder, Wind, Gas Meets EPA Carbon Rule.)

The Economic Studies Working Group had recommended use of three futures, including one that assumed increased load growth as a result of the elimination of the Clean Power Plan. MOPC members amended that to assume normal load growth — creating a business-as-usual scenario as a comparison with the regional and state-by-state compliance schemes.

Members first rejected a proposal to include a fourth future that included an “extreme” EPA final proposal. It won only 41% support. A second vote limiting the study to the regional and state compliance scenarios but allowing the working group to seek approval of a third future, also fell short at 57%.

Fundamental Questions

The debate over the study revealed fundamental questions over the RTO’s planning strategy.

“Once again we are doing the absolute minimum and not looking at the long-term future,” said Kristine Schmidt, vice president of regulated grid development for ITC Holdings.

Board of Directors Vice Chairman Harry Skilton said the 18-month timeline for completion of the study is too long. “This is unbelievably ridiculous that it takes this long,” he said.

Lanny Nickell, vice president for engineering, said the length of the study process reflects the incorporation of stakeholder input. “We have a very open and transparent stakeholder process,” he said. “That is very valuable, but it takes time.”

The debate continued during Wednesday’s meeting of the Strategic Planning Committee, as Skilton, Board Chairman Jim Eckelberger and member Phyllis Bernard called for changes.

Eckelberger said MOPC’s debate over whether it should spend $270,000 in planning staff salaries for a fourth future was shortsighted considering the at least $8 billion the RTO expects to spend on new transmission.

“We’ve got this all backwards,” he said. We’re “trying to put the right lines in the right place. We don’t want to misspend money. We don’t want to get it wrong. We want to have as much foresight as possible. We have not built the robust capability within SPP to get this right — and it’s one of our primary responsibilities.”

Steve Gaw, representing The Wind Alliance, said SPP needs information on a variety of generation sources it may call on under the EPA plan. “You can’t get there with two futures — or with three if one of them is a business-as-usual case.”

Skilton and Bernard also called for a broader range of scenarios.

“I’m not in favor of planning too far out, but I’m in favor of planning much more broadly — casting a really wide net,” she said. “But don’t necessarily try to project it too far forward because we don’t know what’s coming.”

Skilton said the RTO also should seek a shorter planning cycle — ideally six months instead of a two years.

“People have told me six months is impossible,” he acknowledged. “We may not get to six months but we won’t be at 24.”

Nickell said he would relay the board’s thoughts to the newly formed Transmission Planning Improvement Task Force, which has been charged with producing “more progressive, forward-thinking, regional planning processes that are more responsive” to the continued growth of SPP’s transmission system and markets in response to federal and state environmental regulations and reliability rules.

“If I could boil it down,” said Nickell, “you all said you want it bigger, better, quicker… more agile.”

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‘Quick Hit’ List at PJM-MISO Seam Narrowed to 4 Projects from 39

By Chris O’Malley

MISO and PJM said last week they will pursue four “quick hit” flowgate projects that show promise in relieving market-to-market congestion.

misoThe four low-voltage projects could generate market-to-market congestion savings of more than $90 million, based on modeling of day-ahead and balancing congestion during 2013-2014, the RTOs said during the PJM-MISO Interregional Planning Stakeholder Advisory Committee (IPSAC) meeting on April 14.

The four projects were selected from a list of 39 flowgates with $408 million in historical congestion that IPSAC studied. MISO said it is still awaiting responses from transmission operators regarding five other projects that are still possible quick-hit projects. (See MISO, PJM Ponder List of ‘Quick Hit’ Upgrades.)

Flowgates that showed significant day-ahead and balancing congestion in 2013 and 2014, and flowgates that caused auction revenue rights infeasibilities, were included. Solutions had to be completed and provide a payback on investment quickly. Greenfield projects were not considered.

Eric Laverty, MISO director of sub-regional planning, said most of the potential flowgate projects that were studied should be disqualified because they experienced no recent congestion, they had already been identified for in-service upgrades or they did not represent a solid business case.

The four projects chosen were:

  • Benton Harbor-Palisades, an American Electric Power-Michigan Electric Transmission Co. tie line that would receive terminal upgrade equipment. Congestion relief: $61.5 million.
  • Beaver Channel-Sub 49 161-kV, consisting of a SCADA equipment upgrade. Congestion relief: $6.9 million.
  • Michigan City-Laporte 138-kV line upgrades. Congestion relief: $2.7 million. Day-ahead relief: $23 million.
  • Cook-Palisades 345-kV, consisting of upgrading terminal equipment. Congestion relief: $31.5 million.

“We believe there’s a business case for these four projects,” Laverty said.

Laverty said the cost of the four projects ranged from “tens of thousands of dollars” to “low millions.” The only project with a specific price was the $2.5 million Michigan City-Laporte flowgate upgrade.

Committee members said they were confident the upgrades would not simply move congestion to other parts of the RTOs’ footprints.

Chuck Liebold, PJM’s manager of interregional planning, said the RTOs modeled not only historical congestion patterns but also what effects the upgrades would have in relieving congestion on the seam. “In the cases we recommended, the upgrades were very successful at that,” Liebold added.

Both RTOs are talking with transmission owners about the possibility of making upgrades and about who will foot the bill. The committee said it would welcome ideas about cost-sharing.

Stewart Bayer, transmission policy engineer at Northern Indiana Public Service Co., suggested that the RTOs address the issue of cost allocation first, before transmission operators make upgrades. “I don’t know how willing we are to proceed without knowing who’s paying for it,” he said.

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FERC Approves Final Rule on Gas-Electric Coordination

By Ted Caddell

The Federal Energy Regulatory Commission on Thursday approved a rule to improve coordination of the wholesale natural gas and electric market schedules, adopting two gas scheduling changes but declining to move the start of the gas day to 4 a.m. CT from 9 a.m. CT (RM14-2).

Order 809 revises the interstate gas nomination timeline, moving the timely nomination cycle deadline for scheduling gas transportation to 1 p.m. CT from 11:30 a.m. CT. It also adds a third intraday nomination cycle, which should allow shippers to better adjust to changes in demand.

Thursday’s order was a win for the Natural Gas Council, which last year rejected an earlier start time, saying it would cause safety and contractual problems. The group represents nearly all the companies that produce and deliver gas, including members of the American Gas Association, America’s Natural Gas Alliance, the Independent Petroleum Association of America, the Interstate Natural Gas Association of America and the Natural Gas Supply Association.

The failure to reach consensus between the electric and natural gas industries was noted in a FERC staff presentation at the commission’s open meeting Thursday. “The … final rule finds that there has not been a showing that the benefits of changing the nationwide gas day from 9 a.m. CT to 4 a.m. CT sufficiently outweigh the potential adverse operational and safety impacts and costs of making such a change,” staff said.

Growing Pains

gas-electric
Facing opposition from pipeline operators, FERC retreated from its earlier proposal to move up the start of the gas day.

The growth in natural gas-fired generation has strained pipeline capacities and provided operational challenges to grid operators. Two issues were spotlighted: communications between generators and natural gas transmission operators, and gas-electric scheduling.

In November 2013, the commission approved a rule allowing gas pipeline operators to exchange non-public operational information with RTOs. (See FERC OKs Gas-Electric Talk.)

A 2013 report by the North American Electric Reliability Corp. said that the disparity in schedules meant that “electric generator nominations, with their relatively large gas loads, are based upon estimates by the individual fuel planners of each Generator Owner (GO) between 24 and 36 hours in advance. The issue could be magnified when scheduling on a Friday, since gas markets are closed for the weekend.”

The new rule “illustrates how the commission can engage with industry and stakeholders in a collaborative process to offer real improvements in our natural gas and electricity markets,” Commissioner Cheryl LaFleur said in a statement.

The American Gas Association, which represents more than 200 local distribution companies, praised the ruling.

“I am pleased to see that FERC will maintain the 9 a.m. CT start time, a positive step that recognizes what is in the best interest of both gas and electric customers,” CEO Dave McCurdy said. “We appreciate FERC’s attention to the coordination between gas and electric systems, and believe this is a critical issue that needs attention, but changing the gas day was not a step that would have ultimately improved this coordination.”

Retreat

But Thursday’s order was a retreat from the commission’s March 2014 Notice of Proposed Rulemaking, which proposed the 4 a.m. start time. (See FERC: Six Months to Move Gas, Electric Schedules.)

The commission approved the NOPR on a 3-1 vote with LaFleur, Commissioner Philip Moeller and former Commissioner John Norris in support. Commissioner Tony Clark dissented, saying he wanted to give the industries more time to reach consensus. Since then, the commission has added Commissioners Norman Bay and Colette Honorable.

The rule becomes effective 75 days after publication in the Federal Register. Each ISO and RTO must come up with tariff revisions to either coordinate its day-ahead market with gas pipeline scheduling changes or show why changes shouldn’t be implemented.

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FERC Rejects Ginna Rates, Orders Settlement Proceeding

By William Opalka

The Federal Energy Regulatory Commission on Tuesday rejected the rate schedule proposed for a struggling nuclear power plant needed for reliability in western New York and ordered hearing and settlement proceedings (ER15-1047).

The commission approved only part of the reliability support services agreement for the R.E. Ginna nuclear plant between Rochester Gas & Electric and Exelon’s Constellation Energy Nuclear Group, the plant’s owner, which is also under review by the New York Public Service Commission.

The commission rejected the proposal that Ginna receive 15% of its NYISO market revenues, saying it “does not comport with the general principle that rates under [a reliability-must-run] agreement must be cost-based.”

“A compensation structure that provides for both a cost-based monthly fixed rate (whether going-forward costs at the low end, or a full cost of service at the upper end) and a share of market revenues does not meet this principle, as the revenue-sharing provision is not cost-based and may allow for Ginna to earn more than its full cost of service,” FERC wrote.

The commission approved a provision that would require Ginna to repay capital investment costs it recovers under the RSSA if it were to return to the market after the agreement’s expiration.

The capital recovery balance would range between $20.1 million and $65.3 million depending on when it was invoked, “a sufficient disincentive” to dissuade Ginna from “toggling” between compensation under the RSSA and the NYISO markets, the commission said.

FERC thus excluded the issue of toggling from the hearing but said it may address whether the amounts in the capital recovery balance are just and reasonable.

FERC said it would allow about 45 days for settlement discussions before scheduling a hearing.

The RSSA was ordered by state officials and is scheduled to be retroactive to April 1, once approved by regulators. The agreement would cost about $175 million a year and be effective through late 2018. Ginna says it lost more than $150 million between 2011 and 2013.

The immediate effect of FERC’s order is that a procedural case before administrative law judges of the PSC has been slightly delayed. The PSC ordered initial “issue statements” by April 15 in a review of the rate impact on consumers, but that has been pushed back until April 22. (See NYPSC Rejects Opponents’ Request for More Time in Ginna Rate Review.)

FERC has ordered NYISO to standardize its procedures for RMR agreements, of which the proposed Ginna deal is the most recent. (See FERC Orders NYISO to Standardize RMR Terms in Tariff.)

As a result, Tuesday’s order also struck a provision allowing an extension of the agreement beyond 2018. “If there is a future reliability need for the RSSA beyond its initial term, Ginna will be subject to the procedures that NYISO establishes, and the commission approves, in response to the NYISO RMR order,” FERC wrote.