Page 1357 – RTO Insider

July 13, 2018

Senate Talks Gas Infrastructure amid Increasing Delays

By Michael Brooks

WASHINGTON — The Senate Energy and Natural Resources Committee returned Thursday to the issue of natural gas infrastructure permitting following reports of increasing delays at FERC.

natural gas ferc LNG — Moffat | © *RTO Insider*

Two former FERC chairmen, James Hoecker (1997-2001) and Joseph T. Kelliher (2005-2009), agreed with J. Curtis Moffatt, general counsel for Kinder Morgan, and James Murchie, CEO of investment advising firm Energy Income Partners, that failing to build adequate pipelines would lead to higher prices for consumers. They also said delays in state and federal approvals cause uncertainty and could discourage down investment.

While these sentiments aren’t new, they came on the heels of a report by Bloomberg on Wednesday that FERC has notified several developers of LNG export terminals that their applications could be delayed by 12 to 18 months as it struggles to deal with its backlog. The commission asked the developers to consider sending private contractors to help, according to Bloomberg’s sources.

In a series of tweets before the story broke, Commissioner Neil Chatterjee suggested better pay for staff and opening a regional office in Houston, “the center of the world” for natural gas.

FERC Chairman Kevin McIntyre told the committee at an oversight hearing last month that the commission has 14 pending LNG applications, up from four in 2007.

McIntyre said the commission has hired private contractors to supplement its workforce and is seeking to hire additional engineers, while also considering reallocating other staff and hiring additional contractors. It also is seeking to improve coordination with the Department of Energy and the Department of Transportation and seeking internal efficiencies.

The panelists at Thursday’s hearing made no mention of commission staffing as a problem. Rather, they mostly offered suggestions for how the commission could more efficiently process pipeline applications.

Kelliher, executive vice president for federal regulatory affairs for NextEra Energy, said FERC could be more transparent in its certificate orders about how it weighs the benefits and adverse impacts of projects. “There is a need to clarify whether and how environmental impacts should be weighed in this balancing, and whether the commission’s environmental review is under the auspices of the National Environmental Policy Act of 1969 or part of the broader public interest determination in the Natural Gas Act,” he said.

Kelliher said the pre-filing process that formerly took six to eight months now takes up to 12, while the certificate process that used to take nine to 11 months now takes two years or longer. “One factor that has contributed to the length of the certificate process is delays in approvals from other federal agencies,” he said. “If these delays are driven by resource limits at these agencies, the cost incurred by these agencies could be reimbursed by pipeline developers in a manner consistent with how the costs of other federal agencies in the hydropower licensing and relicensing process are recovered from hydropower licensees.”

The witnesses, along with several senators, noted that one of the major factors leading to delays is local opposition from environmentalists and landowners.

Murchie said the challenge for regulators was “getting people to understand that, while their land is being taken [under eminent domain], it’s being taken for a greater good, just like it is with a highway.”

FERC is already considering many of the issues discussed at the hearing as it reviews its 1999 policy statement on gas pipeline approvals. (See FERC Outlines Gas Pipeline Rule Review.)

Fears of FERC Deadlock

Committee Chair Lisa Murkowski (R-Alaska) said Thursday’s hearing was prompted by questions on gas and electric transmission infrastructure remaining following last month’s FERC oversight hearing. The Department of Energy’s efforts to provide financial support to coal and nuclear plants took up most of that discussion. (See FERC: No Emergency on Grid.)

It was not, she said, in reaction to the coming departure of Robert Powelson after only a year on the commission. (See Powelson Leaving FERC to Head Water Lobby.)

“We had all five commissioners here; it was good to see them,” Murkowski said in her opening remarks. “I don’t know, maybe we jinxed the whole thing.”

Murkowski asked Hoecker and Kelliher later in the hearing what they thought the committee should be looking for in Powelson’s replacement.

“I have long advocated that the members of the commission should include some seasoned economists [and] industry engineers, not just lawyers, as much as I love lawyers,” replied Hoecker, executive director and counsel to the trade group WIRES.

“I think they need someone who is comfortable with criticism,” Kelliher said. He also said they should be willing to work with their colleagues, “but only up to a point. It’s not supposed to be 5-0 on everything. It’s OK to dissent.”

Speaking to reporters after the hearing, Murkowski said she has not yet spoken to the Trump administration regarding a nominee, but that she hoped it would make the commission a priority. “You know, we worked very aggressively last year to get the FERC filled up,” she said, “and we’ll just do it again.”

July 13, 2018

FERC Seeks Details on Proposed MISO Retirement Rules

By Amanda Durish Cook

FERC has questions on MISO’s plan to transform its retirement notification process into a catch-all three-year suspension period.

The commission on Wednesday issued a deficiency letter ordering MISO to provide more specifics and an explanation of how it currently plans for suspension and retirements within 30 days (ER18-1636).

MISO this spring proposed that generation owners planning to retire or suspend their units submit a catch-all suspension notice that would have the RTO terminate their interconnection rights after three years of inactivity. (See “Matching Modeling with Proposed Retirement Process,” MISO Planning Subcommittee Briefs: June 12, 2018.)

miso attachment y retirements — | *MISO*

The commission wants to know how MISO’s open-ended suspension plan may affect its process for designating system support resources — those scheduled for retirement that the RTO needs to keep operating for reliability. It asked MISO whether it would model units in the catch-all as three-year suspensions or permanent retirements.

FERC also asked how MISO currently plans for uncertainty in its suspension and retirement process. In a second filing June 21, MISO told FERC that “the future status of a suspended generator is usually unknown, and the requirement to specify an end-date when the return to service is actually uncertain can lead to false assumptions and unreasonable assurance regarding future developments.”

“For planning purposes, what assumptions are made about a generator’s future status under the current suspension provisions, and how will those assumptions change given this proposal?” FERC asked. The commission also asked MISO to explain how generators’ information on their future status may be unreliable and told MISO to provide it with five years of data on the outcomes of generators that entered suspension. FERC also ordered MISO to explain the difference between how it currently treats suspensions versus retirements in transmission planning.

Earlier this year, Economic Studies Senior Engineer Tim Kopp said less than a third of generators return to service after submitting Attachment Y notices to MISO, and that treating all suspending generation as if it will never return would make for better modeling in transmission planning.

FERC also asked if MISO intends to keep its current 26-week minimum notice requirement for Attachment Y filings.

July 12, 2018

UPDATED: Montana Avista Sale OK Includes Colstrip Protections

By Tom Kleckner

The Montana Public Service Commission’s final order approving Hydro One’s acquisition of Avista includes several conditions designed to prevent the early closure of the troubled Colstrip power plant.

Most notably, the order released late Tuesday points to pledges by corporate executives that the sale would not shorten the coal-fired plant’s operational life. The commission approved the sale by a 4-1 vote on June 12.

Avista owns 15% of Colstrip Units 3 and 4, which were built in the mid-1980s and have a combined net generating capacity of 1,480 MW. Low natural gas prices and regional opposition to coal resources have bedeviled the Colstrip plant in recent years. The plant’s operator, Pennsylvania-based Talen Energy, has been exposed to low power prices on the open market as a merchant generator.

montana hydro one colstrip avista — | *Montana Public Service Commission*

Hydro One’s $5.3 billion acquisition would result in Spokane, Wash.-based Avista becoming a wholly owned indirect subsidiary of the Canadian power firm.

The sale, however, could be in jeopardy. Ontario Premier Doug Ford, who took office June 29, had campaigned on replacing Hydro One CEO Mayo Schmidt and the company’s board of directors. On Wednesday Schmidt retired and the board resigned under an agreement with the province of Ontario, which owns 47% of Hydro One.

Avista said Wednesday it was surprised by the moves, but didn’t say how they might affect the sale.

On Thursday, the Washington Utilities and Transportation Commission, which has yet to approve a settlement agreement filed in March that insulates Avista from Hydro One financial risk, said it wants Avista to address how the management changes will affect the merger.

Avista, an electric and gas utility with customers in Alaska, Idaho, Oregon and Washington, has only 32 retail electric customers in Montana, most of whom are affiliated with the company.

“As a result, a traditional examination of this sale and transfer is not appropriate,” the commission said. “Instead the commission examines this transaction under the public interest standard focusing on the potential impacts on electric generation as a whole in Montana.”

Under settlements in their Washington and Idaho merger dockets, Avista and Hydro One proposed a 2027 depreciation end date for Units 3 and 4, although the units’ expected 50-year lifespans would run through 2034 and 2036, respectively.

The PSC noted that accelerated depreciation is a strategy sometimes used to “facilitate premature retirement of disfavored utility generation assets” and said the practice “potentially creates regulatory and operational risks for the other Colstrip owners, as each has diverging economic incentives to operate their respective share of the assets.”

The other owners of Units 3 and 4 are Talen, Puget Sound Energy, PacifiCorp, Portland General Electric and NorthWestern Energy.

The commission said it approved the transaction because it had been assured “that the accelerated depreciation adopted in other jurisdictions will not result in an early or different retirement date for Colstrip Units 3 and 4.” It noted that the applicants committed that the units’ depreciation “will not deviate from the existing scheduled as currently approved.”

The PSC declined to endorse any depreciation schedule for the units, saying the issue would be addressed, if necessary, in future rate cases or other contested case proceedings before the commission. It asked Hydro One and Avista to provide the commissioners with their integrated resource plans for their Montana generating resources “when those plans became available.”

The commission also reserved the right to incorporate any increased commitments made in other jurisdictions into its own approval.

Along with the states in which Avista operates, the companies must gain regulatory approval of their merger from several federal agencies.

Colstrip’s other two units, owned by Talen and Puget Sound, are scheduled to be shut down by 2022 under the terms of a 2016 agreement with environmental groups. The units were built in the 1970s and can produce 614 MW of energy. (See Puget Sound Energy, Talen Agree to Close Colstrip Units.)

July 12, 2018

Appellate Court Rejects Challenge to FERC Funding

By Rich Heidorn Jr.

The D.C. Circuit Court of Appeals on Tuesday rejected environmentalists’ claim that FERC is incented to award pipeline certificates because it collects its operating expenses from regulated parties.

Upholding a lower court ruling, the D.C. Circuit also rejected the Delaware Riverkeeper Network’s challenge to FERC’s use of tolling orders to meet its statutory deadlines for acting on rehearing applications (17-5084).

pipeline certificates due process FERC — | *PennEast Pipeline*

The case arose from PennEast Pipeline’s 2015 application with the commission to build a 114-mile natural gas pipeline through Pennsylvania and New Jersey. Riverkeeper, which works to protect the Delaware River and its tributaries, intervened in opposition.

In 2016, while FERC was still reviewing the application, the group filed a complaint in U.S. District Court alleging that the commission’s funding structure creates structural bias in violation of the Due Process Clause of the Fifth Amendment. Riverkeeper also said the commission’s use of tolling orders to satisfy its 30-day deadline for acting on rehearing applications violates its members’ due process rights.

FERC’s Funding Mechanism

Although it receives an annual Congressional appropriation, FERC is required to recover its costs from regulated industries. Riverkeeper said the structure creates improper incentives for FERC to approve more pipelines so that it could seek larger appropriations from Congress.

The district court dismissed the case for failure to state a claim, agreeing with FERC and PennEast that Riverkeeper had failed to identify any liberty or property interest protected by the Due Process Clause.

The D.C. Circuit agreed, citing the Supreme Court’s 1928 Dugan v. Ohio ruling, which concerned a mayor who served a judicial function as one of five members of a city commission. Although the mayor’s salary came from the same general fund in which fines were deposited, the court said the salary was “not dependent on whether [the mayor] convicts in any case or not.”

As in Dugan, the appellate court ruled, “the adjudicator does not control the funds collected,” because FERC’s fees and charges are “‘credited to the general fund of the Treasury,’ not placed into its own coffers. Moreover, the commission’s budget, like the mayor’s salary in Dugan, is fixed by a distinct legislative body.”

“Regardless of how many pipelines FERC may approve, it ‘shall’ charge, for each year, a total amount ‘equal to all of the costs incurred by the commission in that fiscal year,’” the court said.

Due Process Standing

The Due Process Clause forbids the federal government from depriving a person of “life, liberty or property without due process of law.”

Riverkeeper based its due process claim on the 1971 Environmental Rights Amendment to the Pennsylvania Constitution, which guarantees its citizens “a right to clean air, pure water and to the preservation of the natural, scenic, historic and esthetic values of the environment.”

But the court said the amendment “protects not private property rights, but public goods,” and therefore is “too vague and indeterminate to create a federally cognizable property interest.”

In addition, the court said, “the rights created by the amendment bind only state and local government, not the federal government. … For all of these reasons, we conclude that the Environmental Rights Amendment does not create federally protected liberty or property interests, much less ones that FERC could infringe.”

Tolling Orders

The court also rejected Riverkeeper’s challenges to the commission’s use of tolling orders, which grant rehearing for the limited purpose of giving the commission more time to consider such challenges. Riverkeeper complained that the process frustrates judicial review in violation of the Due Process Clause because FERC routinely allows construction to proceed while the rehearings are pending.

“Regardless of whether any protected liberty or property interests are implicated, the commission is not a structurally biased adjudicator, and its use of tolling orders is not facially unconstitutional,” the court said. “We have long held that FERC’s use of tolling orders is permissible under the Natural Gas Act, which requires only that the commission ‘act upon’ a rehearing request within 30 days, not that it finally dispose of it.”

July 12, 2018

New York Looks at Carbon Price Impact on LBMPs

By Michael Kuser

RENSSELAER, N.Y. — NYISO on Monday presented stakeholders details on how a carbon charge would affect locational-based marginal prices (LBMPs) and imports and exports.

The ISO’s market software will not automatically calculate a carbon component of LBMPs because the carbon charge will be included with fuel and other relevant costs when bid into the current structure. Instead, the ISO envisions calculating an after-the-fact estimate of the LBMP carbon impact, said Ethan Avallone, senior market design specialist.

NYISO will report the estimated LBMP carbon impact for each of its 11 load zones, as well as for each external interface proxy bus.

NYISO will report estimated LBMP carbon impacts for each of its 11 load zones, as well as for each external interface. | *NYISO*

“What information exactly we would use to make these calculations remains to be seen,” Avallone said at a July 9 meeting of New York’s Integrating Public Policy Task Force (IPPTF), the group charged with developing ways to incorporate the cost of CO₂ emissions into wholesale energy markets.

“I think we would tie the emission rate to reference levels for the generation resources, so it would be close to the actual,” Avallone said. “But that’s why we say estimates, because it could differ depending on the mix of the fuel, etc.”

He added, “We’re considering whether the estimated LBMP carbon impact could be calculated and posted at a time granularity consistent with today’s LBMPs or if a different frequency would be more appropriate.”

IPPTF Chair Nicole Bouchez, NYISO’s principal economist, said the stability of the emission rates will determine how well the ISO can predict them and the consequences of estimates versus using a detailed cost breakdown.

Marginal Emission Rates

Several complications prevent NYISO from capturing the exact LBMP carbon impact, including the difficulty in identifying the marginal units because of product trade-offs (energy, spin, regulation), and time interval trade-offs involved in the ISO’s look-ahead for the next megawatt of supply, Avallone said.

“To me the big concern is that when you rank the marginal units in terms of costs, break up the costs for different units, that the CO₂ component might vary or be rather erratic,” said Pallas LeeVanSchaick of Potomac Economics, the ISO’s Market Monitoring Unit. “First, that might be unnecessarily volatile, and secondly, it would gloss over the impacts of changes in commitment and other things that might not be marginal for one five-minute period, but they’re still marginal.”

Bouchez said, “Just to remind everyone, when we talk about marginal, we mean what unit would you be moving to serve the next megawatt of load, so the unit that is on a fixed schedule would not be the one that would be moved. … Pallas is also thinking a bit larger, which is do you actually change commitment to serve that next megawatt of load?”

Mark Reeder, representing the Alliance for Clean Energy New York (ACE NY), asked, “If a generator is in a zone, do you know how often the carbon on the margin on their bus would likely be quite different from what you get in terms of a zonal calculation?”

“The point to consider is that the generator at the bus that receives the carbon charge (impact in its bus LBMP) must pay the carbon charge for its emissions,” Avallone said.

Carbon Charge on External Transactions

NYISO staffer Nathaniel Gilbraith summarized the ISO’s proposal to rely on a “status quo” carbon pricing approach (referred to as Option 1) that would not consider the specific carbon content in energy trades from out of state. A second option under consideration would evaluate marginal emissions rates from out-of-state imports. (See NYISO Floats Carbon Pricing Straw Proposal.)

The ISO’s first consideration “was to avoid distorting import and export incentives, so that the goal here was to avoid creating a seam at the border where certain resources were compensated differently than others, which would result in a reshuffling of resources or fundamentally change import-export engineering,” Gilbraith said.

Representing New York City, Couch White attorney Kevin Lang said, “If what we’re trying to do is lower carbon emissions, then I’m not sure what the concern is about incentivizing more carbon-free imports into New York. In other words, we should be trying to create a level playing field for imports, just like what we’re doing in-state, where we’re trying to incentivize renewable resources.

“By trying to avoid the carbon character of imports and exports, you’re really creating an unlevel playing field, when what we are really trying to do is create a fundamentally competitive market with anyone to be able to compete on an equal basis.”

“I’d rephrase it as we’re trying to draw a specific border, and I think you would like to expand that border to include a broader set of resources that are potentially subject to the carbon pricing,” Gilbraith said.

Howard Fromer, director of market policy for PSEG Power New York, asked whether the complexity of calculating the marginal emission rate in neighboring areas is still the “driving reason” for the preference for this Option 1.

“There are several reasons why Option 1 is preferable and that’s one of the major ones,” Gilbraith responded.

Erin Hogan, representing the Department of State’s Utility Intervention Unit, said, “A generator that wants to export will have their carbon charge in the LBMP, but yet they’ll get a credit back at the border; so theoretically, if it’s equal, we could be exporting a significant amount of energy outside the state and … that would be the status quo.”

“That’s exactly right,” Gilbraith said. “If a generator is currently competitive with generation in an external control area and would like to export its power, let’s say in New England, it can do that today and they can profit on its relative efficiency compared to New England’s current system.”

“So then the drawback is not necessarily that it doesn’t incentivize cost-effective carbon abatement outside of New York, but that it also could limit the carbon abatement within New York,” Hogan said.

Warren Myers, DPS director of market and regulatory economics, said, “This has become focused on the technical aspect of the quantity of the emissions external to New York, and everybody’s just glossing over the fact that … it’s not just the quantity, it’s the value of carbon.

“In this proposal, New York state, not Pennsylvania, not Tennessee, not Massachusetts, would be saying how much each ton of carbon is worth,” he said. “To my mind, Option 1, for good or ill, minimizes the exporting of a New York state policy when it comes to interstate trade.”

Revised Charter

NYISO Senior Manager for Market Design Michael DeSocio presented a revised charter for the task force, which requires that all proposed analyses and their methodologies go through the ISO’s stakeholder process, starting at the Market Issues Working Group before going to the Business Issues Committee.

The task force next meets July 16 at NYISO headquarters to review draft recommendations for issue Tracks 2, 3 and 4 covering, respectively, wholesale energy market mechanics, policy mechanics and interaction with other state policies.

July 11, 2018

UPDATED: Exelon Bids $140M for FirstEnergy’s Retail Business

By Rich Heidorn Jr.

Exelon announced Tuesday it has signed an agreement to purchase the retail business of bankrupt FirstEnergy Solutions for $140 million in cash, an acquisition that would increase the number of customers for its Constellation unit by almost 50%.

The deal, which must be approved by the U.S. Bankruptcy Court for the Northern District of Ohio, would transfer FES’ retail electricity and wholesale load-serving contracts and other commodity contracts to Constellation.

Constellation unit FES firstenergy solutions Exelon — Constellation currently serves about 2 million customers, including residential customers in 17 states and Washington D.C. | *Constellation*

In an 8-K filing, Exelon said it will close the deal in the fourth quarter if it is successful in a bankruptcy court-supervised auction. Either party can cancel the transaction if it is not complete by the end of the year.

FES filed for a Chapter 11 bankruptcy restructuring on March 31. (See FES Se e ks Bankruptcy, DOE Emergency Order.) On Monday, FES filed a m o tion seeking approval for bidding procedures and scheduling an auction for Sept. 6, with bids due Aug. 23.

FES’ retail power business serves 900,000 commercial, industrial and residential customers in Michigan, Ohio, Pennsylvania, Illinois, Maryland and New Jersey.

“The purchase would leverage Constellation’s significant retail platform and is in line with our generation-to-load strategy, strengthening our position as the nation’s largest competitive energy supplier and bringing Constellation’s total customer base to more than 3 million residential and business customers across the continental United States,” Exelon said in a statement. “We would honor all existing retail customer contracts and look forward to offering newly acquired customers the same quality products and services that existing Constellation customers currently enjoy.”

FES said in a press release that it expects to receive a net of $280 million in cash from the transaction “subject to certain purchase price adjustments, including the return of cash collateral and collection of retained net working capital.”

“We believe this transaction is another important step in our restructuring plan,” said FES Chief Financial Officer Kevin Warvell. “If approved, we will work with Constellation to ensure the transition of customer accounts is seamless. During the sale process, our daily operations will continue as usual.”

FES hired Barclays Capital early last year in a bid to sell the assets but decided not to proceed after receiving initial proposals from eight suitors. The company said it abandoned the sale because the purchasers’ proposed terms “made it challenging” for the company to complete a deal outside of a bankruptcy proceeding.

Before entering bankruptcy in March, FES retained Lazard to handle an in-court divestiture. Lazard contacted 35 potential buyers, including “broadly focused financial investors, power- and energy-focused financial investors, strategic retail and power generation companies,” FES said.

The second effort yielded offers from six bidders in March, one of which was rejected because it did not include FES’ entire retail business. FES said it ultimately selected Exelon’s offer as the best, or “stalking horse,” bid.

Under the proposed auction procedures, a bidder challenging Exelon would need to offer an “initial topping bid” of $146.6 million, with subsequent bids in increments of at least $1 million. The auction will be canceled if no bids other than Exelon’s are received.

In a separate m o tion Monday, FES sought to file the unredacted sale agreement under seal to prevent it from disclosing the details of a mechanism that could adjust the purchase price and that allocated value by individual customer accounts. FES said disclosure of those details could reduce the ultimate purchase price.

Constellation serves residential customers in 17 states and D.C. after acquiring retail operations from Consolidated Edison in 2016 and Integrys Energy Group in 2014. (See Exelon’s Constellation to Buy Con Ed’s Retail Opera t ion.)

FirstEnergy shares closed Tuesday at $35.39, up 0.2%. Exelon rose 0.76% to $42.17.

July 11, 2018

FERC Denies Cloverland PURPA Exemption

By Amanda Durish Cook

FERC on Monday denied Cloverland Electric Cooperative’s request for relief from its mandatory purchase obligation under the Public Utility Regulatory Policies Act (PURPA), citing the co-op’s lack of RTO membership as a primary reason (QM18 –11).

Cloverland, which serves customers in Michigan’s Upper Peninsula, filed in April to terminate its PURPA obligation to buy power from qualifying facilities (QFs) over 20 MW, arguing that, as a transmission-dependent utility that purchases transmission service from American Transmission Co. (ATC), QFs over 20 MW could not “safely interconnect” to the co-op’s distribution system “even with significant upgrades.”

ferc purpa cloverland electric cooperative mandatory purchase obligation — Cloverland’s hydroelectric plant | *Cloverland*

Cloverland argued “the only practical way” for a QF over 20 MW to sell its input to the co-op would be to interconnect to ATC’s transmission system. It also contended that, although it doesn’t participate in MISO, ATC is a member of the RTO, where QFs have nondiscriminatory market access. The co-op said QFs within its service territory could utilize ATC’s transmission system to gain nondiscriminatory access, a prerequisite for utilities seeking relief from PURPA purchase obligations.

A utility can be exempted from its PURPA energy and capacity purchase obligations if it can demonstrate a need for relief and is a member of an RTO/ISO market.

But FERC said Cloverland could not use ATC’s MISO membership as a proxy for securing its own RTO/ISO membership.

“In essence, Cloverland, while not itself a MISO member, is seeking to claim the benefit of ATC’s MISO membership in requesting relief from the mandatory purchase obligation under PURPA … We are not persuaded to grant Cloverland’s application,” FERC said.

FERC determined that, because Cloverland is not a member of MISO, it is not entitled to relief from the purchase obligation despites its claim that nearby QFs nevertheless have access to MISO’s markets.

“We are not persuaded to change our position on the reach of PURPA … Membership in an RTO/ISO remains a requirement for claiming an exemption under PURPA … ” FERC said. “ … Accordingly, since Cloverland is not itself a member of MISO, it is not entitled to relief.”

July 10, 2018

FERC Closes Book on Va. Tx Undergrounding Dispute

FERC last week ended a seven-year-old dispute over cost allocation for three Virginia Electric Power Co. transmission undergrounding projects when it accepted a compliance filing and denied related rehearing requests (ER18-318, EL10-49, et al.).

At issue was whether Old Dominion Electric Cooperative and North Carolina Electric Membership Corp. (NCEMC) should be required to pay the additional costs of undergrounding VEPCO’s Pleasant View, DuPont Fabros and Garrisonville projects.

ferc cost allocation virginia electric — FERC Headquarters | © *RTO Insider*

VEPCO’s filing revised its tariff to remove, extending back to March 17, 2010, the incremental costs of undergrounding the projects, and instead charged those costs to wholesale transmission customers in Virginia, which had mandated the undergrounding. In response to a conditional protest by NCEMC, the tariff was amended to exclude NCEMC and all other North Carolina wholesale customers from the undergrounding costs in light of another FERC decision on the issue last October affirming that North Carolina customers would bear no additional costs. (See FERC Upholds Cost Allocation on Va. Tx Undergrounding.)

The commission last week denied rehearing requests from VEPCO, which had argued against excluding several costs from the allocation. FERC said it was reasonable to exclude any costs that had not been shown to be directly related to constructing the projects underground.

The commission also denied rehearing requests from ODEC, Northern Virginia Electric Cooperative and Virginia Municipal Electric Association No. 1. FERC said it had already determined it appropriate to allocate incremental undergrounding costs to all Virginia customers in the Dominion zone, and that the only issue set for hearing was the appropriate amount of the costs to be allocated among those customers on a load-ratio share basis.

— Rory D. Sweeney

July 10, 2018

Factors in New PJM VRR Curve Still in Question

By Rory D. Sweeney

VALLEY FORGE, Pa. — PJM has altered one of its recommended revisions to its capacity auction demand curve in response to stakeholder pressure, and a coalition of generators is pushing for other changes.

Staff have agreed with stakeholder requests to recommend moving the curve 1% left, negating a 1% shift to the right when the curve was last analyzed in 2014 and reducing excess capacity. The recommendations are part of PJM’s quadrennial review of the variable resource requirement (VRR) curve in its Reliability Pricing Model capacity market construct.

The announcement came at a Friday meeting of stakeholders interested in revisions to the curve. Tanya Bodell of Energyzt also provided an analysis funded by the PJM Power Providers Group (P3) that argued for retaining the current model of combustion turbine as the curve’s reference resource. A reference resource is representative of a peaking unit in the energy market that derives a significant portion of its revenues from the capacity market.

PJM is recommending switching from the Frame F to the Frame H of a General Electric turbine based on an analysis it commissioned from the Brattle Group, but Bodell said Frame F allows for flexibility and modularity, which is currently favored over unit size by market participants. Characteristics of the Frame H units are “so 2000s,” she said, because they’re designed and being used for “large, baseload combined cycle applications.” She noted that no Frame H units are being installed as CTs in PJM’s territory, and there is no evidence they will be, while Frame F units are. The mismatch would result in an inappropriate demand curve, she said.

“Going solely for the least-costly estimated technology can really squeeze out a lot of innovation and a lot of long-term gains that you can get from new technologies that are coming in,” Bodell said.

PJM VRR curve frame h units — PJM had a special meeting of the Market Implementation Committee on July 6th | © *RTO Insider*

Erik Heinle of the D.C. Office of the People’s Counsel thanked Bodell for the presentation and said it’s “worth considering” proposals for the F and the H frames as either CTs or CCs.

PJM is targeting Oct. 12 to make its filing for FERC approval, and seeking endorsement votes by the Markets and Reliability Committee on Aug. 23 and the Members Committee during a Aug. 31 teleconference.

July 10, 2018

PJM Market Efficiency Project Rules Could Slip Deadline

By Rory D. Sweeney

VALLEY FORGE, Pa. — With the opening of PJM’s next long-term transmission proposal window looming less than four months away, it remains unclear whether the RTO will have new rules in place for evaluating and selecting market efficiency projects.

That would mean that any rule changes discussed by the Market Efficiency Process Enhancement Task Force since February that aren’t in place by the window’s Nov. 1 start will have to wait another two years for the Regional Transmission Expansion Plan’s next window.

Market Efficiency Project, Regional Transmission Expansion Plan (RTEP), PJM Interconnection LLC (PJM) — The PJM Market Efficiency Process Enhancement Task Force meeting on July 5th | © *RTO Insider*

After a three-hour meeting on Thursday, stakeholders remain at odds about how to move forward. A nonbinding poll showed stakeholders were unable to find at least 50% consensus on any of six solution proposals to address how PJM evaluates and chooses the discretionary transmission projects, which aren’t necessary for reliability but are meant to reduce congestion costs.

The Package A proposal received 49% approval, but stakeholders remained at odds over whether to exclude facility study agreements from the base case unless needed for reliability; whether to use a $10 million versus $20 million threshold on project re-evaluation criteria; and how to calculate energy benefits.

Given the intractability, PJM’s Brian Chmielewski, who oversees the task force, said the group should not forward all six proposals for consideration at the July 12 Planning Committee meeting, but instead attempt to sort through the polling results to assemble three new proposal packages. Stakeholders allowed Chmielewski to create the composite proposals but then balked at sending just those three to the committee.

LS Power’s Sharon Segner said the changes were significant enough for the task force to take another poll, which was supported by representatives from transmission owners Public Service Electric and Gas and American Electric Power. Chmielewski expressed concern about the further delay.

“If we do another poll, we lose the Nov. 1 effective date,” he explained, because there won’t be enough time to get it through the stakeholder endorsement process and receive FERC approval. “Slowing down a month means you miss another two years of new rules. … I think we should go to that [PC] meeting with the intent of having a first read” and take the committee’s input, he said.

Segner suggested adding the new rules to the upcoming window after it opens if FERC would approve such a move, but GT Power Group’s Dave Pratzon expressed concern that such late changes could disadvantage bidders.

Pauline Foley, PJM’s counsel, said she wasn’t “comfortable” with making a determination on whether PJM would be willing to ask FERC for a waiver to grant the approval in less than 60 days. PJM’s Asanga Perera added that other stakeholders might complain about the bidding rules potentially being changed halfway through the process. The window runs through February.

“I don’t think it’s just PJM’s call,” Perera said.

On Friday afternoon, RTO staff opened a poll on the three new proposals and gave stakeholders until noon on Wednesday to respond, giving staff enough time to compile and report the results at the PC.