Page 1343 – RTO Insider

February 13, 2017

Texas PUC Delays Assignment of LPL Study Costs

By Tom Kleckner

The Public Utility Commission of Texas last week granted Lubbock Power & Light’s request to delay a decision on who will pay for studies related to the municipality’s planned move to the ERCOT grid.

Texas PUC Chair Donna Nelson | © *RTO Insider*

In a letter to the commission, LP&L asked that the assignment of study costs be held until ERCOT and SPP can finish separate cost-benefit studies on the potential move (Project 45633). The municipality said the two grid operators have not agreed on a common assumption for gas prices, “a key variable,” and said that the studies will indicate “the extent to which the LP&L integration into ERCOT would benefit customers in both systems.”

“Deciding who should pay the cost of the studies now, in the absence of that information, would mean assigning the cost of the studies to LP&L before it is known whether consumers in SPP and ERCOT would benefit from the transition,” LP&L said.

“I’m OK with waiting,” said Chair Donna Nelson during the PUC’s Thursday open meeting, echoing the position of the other two commissioners.

LP&L announced in September 2015 it planned to disconnect 430 MW of its load from SPP and join ERCOT in June 2019. An ERCOT analysis completed last June indicated it will cost $364 million and take 141 miles of new 345-kV rights of way to incorporate LP&L into the Texas grid. Both ERCOT and SPP are currently conducting separate studies on their systems with and without LP&L’s load. (See Texas PUC OKs ERCOT, SPP Studies on Lubbock Move.)

The utility, which plans to conduct its own study, said it “continues to expect that, on a net basis, the system transition that LP&L seeks will present quantifiable benefits to consumers in both the SPP and ERCOT systems.”

In a separate letter to the PUC laying out their respective study scopes, ERCOT and SPP estimated the combined analyses would cost between $225,000 and $255,000. The grid operators said they have assigned internal project codes to track the hours incurred for the studies and promised a final accounting to the commission.

Commissioner Ken Anderson noted SPP planned to perform its production-cost analysis with and without forced generation outages, but ERCOT would do so without taking the outages into account. Asked what the likely variance would be, ERCOT Senior Director of System Planning Warren Lasher said he didn’t think it would be a “game-changer.”

“You will be able to look at the two results and be able to see the difference, but often, it’s not going to change your decision,” Lasher said. “ERCOT doesn’t do this because it is complicated to do. You need to have very accurate data regarding outage rates, which is something we’ve had significant difficulty getting from market participants.”

Lasher said the difference in outage-rate data may also be “a function of the different market designs we have in the SPP region and the ERCOT region.”

The grid operators’ studies are expected to be completed by midyear.

Hand-Held Devices Allowed to Enroll Retail Customers

The commissioners adopted a change to the PUC’s administrative rules that will allow retail electric providers (REPs) to use laptops, tablets, smart phones and other hand-held devices to enroll customers (Project 45625).

The rulemaking came with a warning, however. “I’m going to be watching,” Nelson said.

The PUC chair added language that requires the REPs to “accurately and truthfully answer any questions” when giving customers an opportunity to review the enrollment documents.

“To the extent we get complaints about this, it’s not going to be something we look on favorably,” she said. “We want to make sure the customers get what they need.”

SPS Details Winter Storm Restoration Effort

Southwestern Public Service briefed the PUC on its recovery efforts following January’s winter storm, which left 58,000 of its customers in the Texas Panhandle without service and damaged 7,500 poles and other structures.

ercot texas puc lpl study costs — Transmission lines after the January 2017 Ice Storm | *SPS*

Evan Evans, SPS’ regional vice president of rates and regulatory affairs, said the company was prepared for the storm and its forecast of one-tenth of an inch of ice. The storm began with rain Jan. 13, transitioning into freezing rain and bitter cold through Jan. 15 that resulted in up to 3 inches of ice in some areas.

“It was a major ice storm … the worst residents said they had seen in over 50 years,” Evans said.

SPS used almost 1,100 employees, contractors and mutual aid partners to restore service to all its customers by Jan. 23. Evans said cellphone communication problems and waiting on electricians to repair damage on the customers’ lines and meters slowed the restoration effort.

Evans said the company upgraded its infrastructure standards in 2014 and will look for ways to improve its communications and further harden its facilities. He pointed out some neighboring utility customers are still waiting for service that may still be a week or two away.

“Your team did a tremendous amount of work in very dangerous conditions,” Commissioner Brandy Marty Marquez said.

“I’m amazed that you have people that have been out [of power] for seven days asking us if we were OK,” Evans said. “They see us working around the clock.”

Fines Approved, Cybersecurity Program OK’d

The commission’s consent agenda included approval of fines against Luminant Energy and Oncor Electric Delivery, once sister companies under bankrupt Energy Future Holdings.

Luminant agreed to an administrative penalty of $170,000 for not updating its ancillary service schedules 11 times in 2015 after ERCOT issued instructions to do so (Docket 46724). Oncor agreed to a $288,500 penalty for falling short of benchmarks on the length and frequency of outages for 2015 (Docket 46733).

The PUC also gave Executive Director Brian Lloyd the authority to negotiate and implement a contract to develop “a comprehensive cybersecurity and physical security outreach program” for Texas utilities, cooperatives and municipalities (Docket 46773).

February 13, 2017

PJM Making Cost Consciousness a Focus for RTEP Redesign

By Rory D. Sweeney

VALLEY FORGE, Pa. — PJM has made several changes to its proposed planning process for competitive transmission projects in response to stakeholder feedback, staff said Friday.

At a special Planning Committee meeting on redesigning the Regional Transmission Expansion Plan and the Transmission Expansion Advisory Committee, PJM’s Fran Barrett said the RTEP “is not just about [FERC] Order 1000.”

“The RTEP has been in service for 18 years. It’s served us well, but the market is changing,” Barrett explained. “We have heard you. [The redesign] is not just going to be about technology. It’s going to be about timing; it’s going to be about interactions.” (See PJM Proposal Would Lengthen Reliability RTEP Cycle.)

The changes would be detailed in a proposed Manual 14F. Among the changes is considering cost containment in the project selection phase, the details of which have not been finalized. “At this point, we have not made an effort to [separately] define ‘cost cap’ and ‘cost-containment mechanism,’” PJM’s Mike Herman said.

Alex Stern of Public Service Electric and Gas cautioned against creating a “race to the bottom” by selecting projects for having the lowest cost cap.

GT Power Group’s Dave Pratzon asked how the evaluation standards will be applied to what he called “squishy” situations, where the costs and benefits of a proposal might not be straightforward.

“How incidental a failure in PJM’s initial study does someone have to have before” the project is rejected? he asked.

Herman agreed that more consideration could be applied to the issue but said the manual can’t anticipate all possible situations. “I think we could get into lots of detailed discussions about ‘odd’ situations,” he said.

Proposed changes to the workflow diagram include:

Removing supplemental projects as a criteria driver, a response to stakeholders who said such projects don’t fit with market efficiency projects and should have their own diagram;
Including a footnote that explains how public-policy decisions factor into the public-policy criteria driver;
Adding “evaluation of impacts on other projects” into PJM’s factors for consideration, with a focus on whether the proposal alleviates the need for a supplemental or previously approved baseline project; and
Moving “stakeholder review” from the TEAC recommendation phase to one of the factors for consideration, to emphasize the importance of ongoing stakeholder feedback.

Stern reiterated his suggestion that the manual be limited to market efficiency projects.

“I’m not intending that we stop the discussions on reliability. In my mind, that’s going to take longer,” said Stern, who offered his own edits to the proposed manual.

“We thought there were a lot of similarities [between reliability and market efficiency projects] both on the front end and on the back end,” Herman said. “They still fall within the same decisional thinking process. … We felt it made most sense to put it all together in one manual.”

PJM RTEP redesign Market Efficiency Projects — Decisional Process Map | *PJM*

“We think it’s prudent to put the language together so you can see the differences,” Barrett added.

Other stakeholders agreed they preferred a single document. “That kind of leans me back toward ‘Let’s do this all together,’” PJM Public Power Coalition’s Carl Johnson said.

“Can I just say ‘what Carl said,’ or do I have to repeat it?” Calpine’s David “Scarp” Scarpignato said.

FirstEnergy’s John Syner also leaned toward a single manual, but he said incumbents should be given “brownie points” such as basis points for their longevity and reliability.

“I don’t know how you can put a manual together and be able to give all of those ‘brownie points,’” he said, adding that it likely will need to occur during transmission owner prequalification and would require a Tariff change.

February 10, 2017

EEI Pledges to Fight Elimination of Tax Deductions

By Rich Heidorn Jr.

NEW YORK — Investor-owned utilities will fight any tax overhaul that doesn’t preserve deductions for interest and property taxes, the head of the Edison Electric Institute told Wall Street analysts Wednesday.

As the nation’s “most capital-intensive industry,” electric utilities hope to convince Congress and President Trump that they should be treated differently from others when it comes to eliminating deductions, EEI CEO Tom Kuhn said.

“We can make a case that we’re different,” Kuhn said. His argument: Current tax policies allow utilities to reduce their weighted average cost of capital, saving ratepayers money.

EEI said that while it supports simplifying the tax code, broadening the tax base and reducing rates, it will seek to preserve the federal income tax deduction for interest expenses and state and local taxes (primarily property taxes), as well as maintain parity between dividend and capital gains tax rates.

It also will fight to continue tax “normalization” rules, which require state regulators to treat tax benefits to customers in the same way that the recovery of the cost of the associated property is treated.

Normalization spreads the tax benefits associated with assets over the same time period that the costs of those assets are recovered from customers. “It is critically important to maintain tax normalization to the extent that accelerated depreciation or other investment incentives are retained in the tax code,” EEI said in a position paper.

About 100 analysts attended the annual briefing at the tony University Club off Fifth Avenue, about a block from Trump Tower.

Kuhn said a group of utility CEOs traveled to D.C. a few days after Trump’s inauguration to make their case to White House officials and congressional leaders. “We’re going to be in the front of the curve” in lobbying, he promised.

Although tax reform wasn’t a major issue in the fall elections, Kuhn said he sees the call by the president and Congress for change as reminiscent of the conditions in 1986, before President Ronald Reagan’s tax package was approved.

“Tax reform doesn’t happen very often — every couple of decades,” he cautioned, adding that a tax initiative will likely be a back burner issue until Trump and Congress act on replacing the Affordable Care Act. “I don’t think it’s going to be an easy lift.”

One wild card is the proposal by prominent conservatives, including former secretaries of state George Schultz and James Baker III, for a carbon tax. “It’s really early in the debate right now,” Kuhn said of the proposal, noting questions about how the proceeds for the tax would be spent.

Convincing Regulators on Capital Spending

EEI projects that its 44 investor-owned utilities made a record $120.8 billion in capital spending in 2016, up from $103.3 billion in 2015. Of that, 35% was spent on generation (up from 32% in 2015), while transmission dropped to 17% (from 18%), and distribution was unchanged with a 26% share. Much of that spending has been on smart grid improvements.

What are ratepayers getting for their money? Job growth, resiliency and economic benefits from shorter outages, said David Owens, EEI’s executive vice president for business operations and regulatory affairs.

EEI officials said the increase in smart grid technology — along with stronger wires and poles, use of robocalls and improved situational awareness — helped utilities in the Southeast restore power to all customers within two days after Hurricane Matthew in fall 2016.

About 70 million smart meters have been deployed to date — representing 60% of U.S. households — up from 32 million in 2012, when Superstorm Sandy knocked out power to millions along the East Coast for as long as two weeks.

“We’ve got to demonstrate [to regulators] that there’s a whole string of benefits that accrue” from smart grid investments, said Owens, a long-time EEI official who has announced he will retire June 30. “We’ve got to demonstrate to the regulator that there’s a fair way to allocate those costs. If you’re rolling in those costs, you’ve got to be able to demonstrate that all the customers benefit. If you’re not rolling them all in, you have to charge that individual customer.”

FERC’s Future

Former FERC Commissioner Philip Moeller, EEI’s senior vice president for energy delivery and chief “customer solutions” officer, commented on prospects for restoring the quorum lost Feb. 3 following the resignation of former Chairman Norman Bay.

FERC canceled its Feb. 16 meeting and said no monthly agenda meetings would be scheduled until a third commissioner is confirmed to join acting Chairman Cheryl LaFleur and Commissioner Colette Honorable. FERC’s annual joint meeting with the Nuclear Regulatory Commission will be held as scheduled on Feb. 23.

“Realistically, the most optimistic scenario I would say would be [to have] multiple slots filled in 60 days. But that’s very optimistic,” Moeller said, adding that a candidate who has already cleared the FBI background check could be installed more quickly. Among those rumored as a candidate for the commission is former Texas regulator Barry Smitherman.

He predicted the new commission will seek to ensure that wholesale markets recognize the reliability value nuclear generators provide as baseload resources, citing financial supports approved in Illinois and New York. (See related story, Connecticut Lawmakers to Draw Up Millstone Rescue Plan.)

Moeller also said the new commission may revisit Order 745, which required RTOs to pay demand response the same LMPs as generation, and Order 1000, which he said “has not provided the certainty for transmission planning that FERC intended.” (See FERC Won’t Revisit Demand Response Pricing.)

He also called for the commission to “update” its interpretation of the Public Utility Regulatory Policies Act. (See FERC Conference Debates PURPA Costs, Purchase Obligations.)

EEI will be urging the commission to change its discounted cash flow model for calculating returns on equity “to attract additional capital to the transmission system,” Moeller said.

In June 2014, Moeller voted with LaFleur and former Commissioner Tony Clark to apply to electric utilities a two-step DCF process that incorporates long-term growth rates. The new formula has resulted in numerous ROE reductions.

February 9, 2017

ISO-NE Capacity Prices Fall 25%, Lowest Since 2013

By William Opalka

Prices dropped by one-quarter to $5.30/kW-month in ISO-NE’s capacity auction Monday, the lowest clearing prices since the RTO eliminated its price floor after the 2013 auction.

Forward Capacity Auction 11 easily surpassed the 34,075 MW of resources needed for the 2020/21 capacity commitment period, with a total of 35, 835 MW. Unlike in recent auctions, the RTO said, no new large power plants qualified, nor did any large power plants announce their retirements beforehand. However, 640 MW of new energy efficiency and demand response resources cleared, the equivalent of a new generating plant.

Three new power plants cleared in FCA 10 last year, which had a clearing price of $7.03/kW-month. That followed two consecutive record-breaking years, topped by the record $9.55/kW-month in 2015. (See Prices Down 26% in ISO-NE Capacity Auction.)

Falling prices are “the result of competition to provide plenty of the capacity that we need in New England,” Robert Ethier, vice president of market operations at ISO-NE, said at a news briefing Thursday.

Although the auction did not have large, significant new resources, “we did have a lot of smaller, other resources clear in the auction,” Ethier added.

The clearing price will be paid to all resources in all three capacity zones in New England and 1,035 MW of imports from New York and Quebec. Imports from New Brunswick, totaling 200 MW, will receive $3.38/kW-month. That price is lower because of excess capacity available over a 200-MW tie line.

The total cost this year is about $2.4 billion, down from last year’s $3 billion and 2015’s $4 billion.

Ethier said the lower prices allowed ISO-NE to acquire more than the minimum target to give it flexibility and to enhance reliability. Almost 40,500 MW — 34,505 MW of existing capacity and 150 new resources totaling 5,958 MW — qualified. (See ISO-NE Capacity Requirement Shows Flat Demand, More Solar.)

Several oil-fired units dropped out of the auction, “well under 200 MW” in the aggregate, officials said, but they remain available in the energy market. “We have not yet received any retirement notices from them,” said Stephen Rourke, vice president of system planning.

The new efficiency and DR resources bring the total available to more than 3,200 MW, or about 9% of the total capacity market.

In addition, demand reductions from the RTO’s forecast of behind-the-meter solar PV growth reduced the capacity target by 720 MW.

Six megawatts of new wind and 5 MW of new solar resources cleared the auction, bringing their totals to 137 MW and 66 MW, respectively.

ISO-NE said it will file the results with FERC at the end of the month, hoping for acceptance that traditionally occurs in June. The commission is operating without a quorum and would not be able to approve FCA 11 results on time if they are contested.

“We’ve thought about it, but it’s not a big concern, yet,” Ethier said.

February 9, 2017

MISO Auction Redesign in Limbo After FERC Rejection

By Amanda Durish Cook

CARMEL, Ind. – MISO will likely fall back on its existing Planning Resource Auction design next year after its Competitive Retail Solution failed to win FERC approval, but the RTO says the door is still open on instituting a locational auction construct.

ferc miso capacity auction — Bladen | © *RTO Insider*

At the Resource Adequacy Subcommittee meeting Wednesday, MISO officials were tight-lipped on whether they would seek rehearing on FERC’s Feb. 2 order or what approach they might pivot to in stakeholder discussions this year. (See FERC Rejects MISO’s 3-Year Forward Auction Proposal.)

While MISO Executive Director of Market Design Jeff Bladen discussed the possibility of rehearing, he stopped short of saying that the RTO would file a request. He also said the reliability issue in MISO’s competitive retail areas remains.

“It’s important to remember that there is a 30-day period where any party to the filing can request rehearing. Effectively, the docket remains open until then,” Bladen said. “I certainly would not prognosticate on if anyone would request a rehearing and what FERC would do with that … but I don’t want to be too opaque. MISO still recognizes that some things need to be fundamentally changed.”

While he didn’t rule out changes for the 2018/19 planning year capacity auction, Bladen said a retooled auction design by next year is unlikely. Bladen also said a “one size fits all” auction approach isn’t likely given the differing state regulatory structures in MISO.

“It’s pretty clear the proposal we made with the forward auction is not implementable on the timeline we proposed. It’s impossible for me to answer the hypothetical on what’s possible between now and the 2018/19 auction, but it’s hard to see [auction changes] implemented before then,” he said.

Some stakeholders asked if the auction would remain status quo until FERC regains its quorum. (See FERC OKs Pipelines, Delegation Order Before Losing Quorum.)

In the interim, MISO attorney Jacob Krause said, commission staff can delegate letter orders only for “non-controversial” filings.

February 9, 2017

Exelon’s Crane Reports ‘Monumental Year’

By Ted Caddell

This time last year, Exelon had its hands full.

The company was deep in a problematic $6.8 billion acquisition of Pepco Holdings Inc. while bogged down in a two-front battle trying to get nuclear subsidies for plants in Illinois and New York.

Things look much brighter for the Chicago-based energy giant in early 2017.

First, the acquisition of PHI has closed, adding PEPCO, Delmarva Power and Atlantic City Electric to Exelon’s stable of electric distribution companies.

Second — and against most odds — the company was able to convince Illinois and New York legislators to pass laws providing subsidies for its troubled nuclear plants.

And somewhere along the line, Exelon picked up yet another nuclear generating station, the James A. FitzPatrick station, from Entergy. The FitzPatrick deal is expected to close this spring, the company said.

As Exelon CEO Chris Crane put it during an analyst earnings call on Wednesday, “2016 was a monumental year for Exelon.”

The company earned $410 million ($0.44/share) during the fourth quarter, compared to $347 million ($0.38/share) for the same period in 2015, missing analysts’ expectations by a penny. Annual earnings came in at $2.5 billion, up from $2.2 billion in 2015.

“We made great progress in the ongoing transformation of our company, with a focus on meeting our commitments to stakeholders via the PHI merger and the creation of the [zero-emission credit] programs in both New York and Illinois that compensate our nuclear plants for their carbon-free attributes,” Crane said.

The successful push for ZEC legislation reversed the company’s decision to retire the Clinton and Quad Cities nuclear plants, saving $120 million in projected early retirement costs, Crane said. He also noted that Exelon’s nuclear fleet had a 94.2% capacity factor for the year, up nearly 1 percentage point from the previous year.

exelon zec nuclear generation — Exelon says ZEC credits helped save Clinton Nuclear Plant | *NRC*

All of the company’s electricity distribution companies enjoyed fewer storms and therefore lower outage-related costs throughout the year, he said.

Looking ahead, company executives are eyeing legislative action in several other states — including Ohio, Connecticut, New Jersey and Pennsylvania — that could result in ZEC-style subsidies for nuclear plants there.

Joe Dominguez, Exelon executive vice president of governmental and regulatory affairs and public policy, described the company’s approach to winning those concessions.

The first stage is “establishing a recognition that nuclear is the lowest-cost and most reliable zero-carbon option” for electricity customers.

“That’s where we are in Pennsylvania,” Dominguez said.

The next step: identify different “solution sets,” such as the ZEC programs already adopted or including nuclear as a qualifying resource for renewable portfolio standards.

“And it’s way too early for me to handicap where that discussion is going to go,” Dominguez said.

February 9, 2017

Connecticut Lawmakers to Draw Up Millstone Rescue Plan

By William Opalka

HARTFORD, Conn. — Supporters of the Millstone nuclear power plant on Tuesday issued impassioned pleas for Connecticut legislators to save the plant but were short on details on how to provide enough revenue to keep it operating beyond 2021.

dominion millstone nuclear plant — Formica | © *RTO Insider*

Those supporters were speaking at a Joint Committee on Energy and Technology hearing to discuss a preliminary bill, which, for now, merely says its purpose is “to provide a mechanism for zero-carbon electric generating facilities to sell power to electric utilities.” Sen. Paul Formica (R), committee co-chair and lead sponsor of the bill, said the hearing was intended to gather input from different constituencies.

While plant owner Dominion Resources has not said that it will close the Waterford facility, the company has acknowledged that the plant is under financial stress because of record low power prices set by cheap natural gas.

“We need to gather all the facts because we need a baseload power source here in Connecticut,” Formica said. “But if this baseload goes away, what happens to rates?”

Millstone can produce 2,111 MW, or about half of the state’s energy needs.

Bill co-sponsor Melissa Ziobron, a Republican representative from the nearby 34th District, said her husband has worked at the plant for 20 years.

“The premise of Millstone closing is real,” Ziobron said. “It is present for our family and 1,200 others.” She and others said the plant’s closure would devastate the economy of southeastern Connecticut.

An aborted plan introduced at the end of last year’s legislative session is presumed to be the starting point in any current deliberations to help Millstone. In the waning hours of that session, the Senate unanimously passed a measure that would have allowed the plant to bid into the state procurement process now reserved for renewable energy, large-scale hydropower and trash-to-energy facilities.

The bill passed the Senate without any hearings, but time ran out for the House of Representatives to act.

Elin Swanson Katz, the state’s consumer counsel, took no position on the bill, but she said her office is pleased with the mechanisms the state has put in place for long-term energy procurement to protect ratepayers.

“These processes have been highly competitive and well managed,” Katz said.

John Erlingheuser, associate state director of advocacy at AARP, called the bill “a special deal that has the same impact as a subsidy” that effectively reclassifies 50% of the state’s generation as renewable energy.

Dominion contends that the policy is justified.

“If Connecticut wants the lowest-cost, longest-term resource that also meets its environmental and economic goals, the solicitation process has to be expanded,” Kevin Hennessey, the company’s director of state policy for New England, said in written testimony.

Connecticut State Joint Committee on Energy and Technology | © *RTO Insider*

Power producers say that reverses 20 years of progress in building competitive markets in the region.

“Proposals to selectively grant some resources preferential treatment without regard for the impact of doing so on the rest of the power supply system risk highly adverse and likely irreversible consequences,” the Electric Power Supply Association wrote.

Eric Brown, general counsel for the Connecticut Business and Industry Association, disputed those who said Dominion needs to open its books to justify the policy change.

“We don’t need to see their books,” Brown said. “The marketplace has sent a very clear message: Nuclear power is struggling throughout the country. We’re losing plants in New England. That’s the best kind of evidence.”

Dominion commissioned a recent study indicating that state carbon emissions would increase by 2.5 million tons if the plant retired and was replaced by natural gas-fired generation.

Roddy Diotalevi, senior director of sales and external relations for UIL Holdings, said that Millstone is important in helping the state reach its environmental goals but that the costs to keep the plant running are still unknown.

“UIL remains concerned about the impact that these above-market payments will have on ratepayers and the negative effects that a long-term obligation and financial liability would have on the utility,” Diotalevi said.

Millstone and NextEra Energy’s Seabrook plant in New Hampshire are soon to be the only remaining nuclear plants in New England. Vermont Yankee closed two year ago, while the Pilgrim station in Massachusetts will shut down in 2019. New York’s nuclear fleet has been saved by a state subsidy, but that program is currently being litigated.

February 8, 2017

PJM Tracks the Power of the Super Bowl

By Rory D. Sweeney

VALLEY FORGE, Pa. — If you thought the ending of Sunday’s Super Bowl matchup was electrifying, you’re not alone. The event had a noticeable impact on electricity demand.

Just after the game started at about 6:30 p.m. on the East Coast, PJM’s demand dipped below the RTO’s forecast by about 1,000 MW, or about 1%, when everyone dropped everything to watch.

It recovered and then jumped above the forecast around 8 p.m., roughly corresponding with halftime, when everyone took a break to do other things, like cooking wings or microwaving some more queso dip. The load then followed the forecast until the game ended around 10:30 p.m., when it again exceeded the forecast as everyone went back to their normal routine.

The “Super Bowl dip” is a phenomenon that many RTOs experience. In fact, ISO-NE examined it in a post it published on its website last week. Part of the reason PJM could predict the load with fairly good accuracy is because the RTO factored the phenomenon into its forecast.

But that isn’t always the case. A similar event happened on Jan. 15, when the real-time load dropped about 2,000 MW, or roughly 2%, below the forecast around 6:30 p.m. ET, then jumped back up to the forecast around 8:30 p.m.

“It seems to have coincided with the end of the Green Bay [Packers]-Dallas [Cowboys] football game,” PJM’s Phil D’Antonio told the Operating Committee on Tuesday. “Apparently, that [playoff] game had enough attention that people were sitting in front of the TV. Then after the game, they went back to their normal lives.”

D’Antonio, a manager of reliability engineering at PJM, explained that the “load deviation” caused alerts within PJM’s control system. Ken Seiler, PJM’s senior director of system operations, noted later that it caused an eight-minute spin response of almost 703 MW.

February 8, 2017

CAISO Issues Final Plan for Small TO Interconnection Costs

By Robert Mullin

CAISO has issued a draft final proposal to prevent smaller transmission owners from bearing the high costs for network upgrades needed to interconnect generation serving load outside of their service territories.

While the latest revision keeps its focus on the specific circumstances faced by Valley Electric Association, it would also provide CAISO the flexibility to apply the proposal’s principles to similar TOs seeking entry into the ISO in the future.

caiso valley electric interconnection costs — CAISO has developed the small transmission owner generator interconnection proposal to accommodate Valley Electric Association, which faces high network upgrade costs for resources intended to serve other load centers. | *Valley Electric Association*

The most recent, and likely final, proposal settles on one of two plans spelled out in the last iteration, with some refinements. (See CAISO Refines Small Generator TO Interconnection Plan.)

That plan (referred to as “Option A”) would require CAISO to determine on a case-by-case basis whether a candidate TO should be allowed to fold low-voltage generator interconnection costs into high-voltage transmission revenue requirements. Doing so would diffuse the costs among the ISO’s full rate base to avoid saddling small TO ratepayers with outsized fees.

Under the proposal, CAISO will make its determination based on whether the TO is:

Very small relative to other TOs, with a gross load of 2 million MWh or less (currently about 2.2% of the load of the ISO’s largest TO);
Located in a renewable resource-rich area gaining “elevated” interest for generator procurements; or
Not subject to a renewable portfolio standard or does not need the new interconnecting generation to meet that requirement.

CAISO rejected a more “formulaic” Tariff-based “Option B” that included the last two provisions but would have had the Tariff specify that a small TO’s gross load be no larger than 5% of that of the largest TO.

“Rather than trying to develop Tariff provisions that could address every potential unique circumstance, this [Option A] proposal specifies guiding principles the ISO would apply on a case-by-case basis to alleviate unintended adverse impacts for each unique” participating TO, CAISO said.

The option would require ISO management and staff to apply the principles to determine the “appropriate treatment” of each small TO and then seek approval for its recommendations from the Board of Governors and FERC.

CAISO dismissed the contention of some stakeholders who preferred Option B out of concerns that a case-by-case review could bog down the interconnection process.

“The ISO does not agree with the argument that Option A would cause delays since any ISO decision and subsequent FERC approval could be combined with the [TO] application process when a new [TO] joins the ISO,” CAISO said.

Valley Electric, CAISO’s only out-of-state member, serves 45,000 customers and about 100 MW of load in a 6,800-square-mile region along the California-Nevada border. The cooperative last year agreed to sell its 230-kV transmission network to GridLiance for $200 million. (See Valley Electric Approves Sale of 230-kV Network to GridLiance.)

The utility’s service area has high potential for the development of new renewable resources that would serve more populous areas of the ISO. Two projects with a total capacity of 100 MW await interconnection with the Valley Electric system, with more slated to enter the queue, according to the ISO.

Under CAISO’s Tariff, a TO must reimburse its generator interconnection customers for the costs of local reliability and deliverability network upgrades necessary to connect a resource to the transmission network. The TO can then seek regulatory approval to roll those reimbursement expenses into its rate base, passing them on to ratepayers through either a high-voltage or local low-voltage transmission access charge (TAC). The ISO considers any line under 200 kV to fall into the latter category.

While the high-voltage TAC is allocated to all ISO ratepayers at a postage-stamp rate based on the total revenue requirements of all TOs owning high-voltage transmission, the low-voltage TAC is charged only to customers within the service area of the TO owning the facilities.

That arrangement could burden ratepayers in low-population service areas who are forced to bear the low-voltage network upgrade costs for generation intended to serve other locales attempting to meet renewable goals.

CAISO has scheduled a Feb. 13 conference call to discuss the proposal and is asking stakeholders to submit comments by Feb. 22. ISO management seeks to present a plan for board approval in March.

February 8, 2017

Dominion Resources Changing Name to Dominion Energy

By Ted Caddell

Dominion Resources is changing its name to Dominion Energy to unify the look and brand of the holding company that now does business in 18 states.

The company said it wanted to bring all of its businesses under a single flag, especially since its $4.4 billion acquisition of Questar in September, which added 56 Bcf of gas storage and 3,400 miles of gas transmission.

Dominion operates natural gas and electric distribution companies in seven states, with 2.5 million electric customers in Virginia and North Carolina, 2.3 million gas customers in Idaho, Ohio, Utah, West Virginia and Wyoming. It also has 1.3 million retail energy and energy services accounts in 13 states.

The company owns 26,400 MW of electric generation, 6,600 miles of electric transmission and 14,600 miles of natural gas pipelines.

Its newly branded Power Delivery Group, Power Generation Group and Gas Infrastructure Group will replace Dominion Virginia Power, Dominion Generation and Dominion Energy.

The new name — subject to stakeholders’ approval at the company’s annual meeting this spring — will be accompanied by a new logo: a blue “D” with energy-suggestive strips through it.

“Our company and our employees are proud of the work we have done in delivering energy for 119 years,” CEO Thomas Farrell said in a statement. “Dominion Energy builds upon this equity, updates our company’s look and unifies the company’s brand across all of our lines of business.”

“This is a good time to unify the brand, clarify the name and simplify the logo,” said Kelly O’Keefe of Virginia Commonwealth University’s Brandcenter, who worked on the branding project.

The branding announcement comes about a week after Dominion announced earnings of $457 million ($0.73/share) for the fourth quarter of 2016 and $2.1 billion ($3.44/share) for the year. The company earned $357 million for the fourth quarter of 2015 ($0.73/share) and $1.9 billion ($3.20/share) for that year.

Farrell used the earnings call to spotlight some of the company’s accomplishments for the year, including adding 727 MW of solar to its portfolio, bringing it up to 1,400 MW; continued progress on its 1,588-MW combined cycle station in Greensville County, Va.; the connection of 11 new data centers; and the completion of $784 million in transmission projects, with another $800 million on the horizon.