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May 3, 2019

FERC Denies PGE Rehearing over Contracts Dispute

By Robert Mullin

FERC on Wednesday rejected Pacific Gas and Electric’s request to rehear a January ruling in which the commission asserted that it shares authority with a federal bankruptcy judge over any power purchase agreements the utility might seek to modify after filing for Chapter 11 protection.

The commission’s order also consolidated separate petitions by NextEra Energy (EL19-35) and Exelon (EL19-36) for declaratory orders preventing PG&E from reneging on high-cost contracts with renewable generators.

As part of its January Chapter 11 filing, PG&E asked the U.S. Bankruptcy Court in San Francisco to issue an injunction confirming its exclusive jurisdiction over the utility’s right to reject PPAs and other FERC-regulated agreements.

The dispute regarding PG&E’s PPAs centers on contracts signed when the cost of renewable power was much higher than today. | © *RTO Insider*

At a hearing April 10, PG&E attorney Theodore Tsekerides strenuously argued for Bankruptcy Judge Dennis Montali to impose a permanent injunction preventing FERC from interfering with the bankruptcy case. But Montali declined to make an immediate decision, instead asking lawyers to reach a compromise. (See Judge Puts off Decision in PG&E v. FERC.)

In arguing against an injunction, FERC’s lawyer told Montali that a compromise was possible but would be subject to commission approval. Wednesday’s decision suggests the commission is prepared to give little ground over the matter.

In its rehearing request, PG&E contended that FERC’s initial order failed to acknowledge Congress’ intent in enacting the bankruptcy code, specifically “to permit the successful rehabilitation of debtors” and “prevent a debtor from going into liquidation, with an attendant loss of jobs and possible misuse of economic resources.”

The utility further argued that debtor-in-possession status provides the flexibility to assume or reject any contracts until a reorganization plan is established, and that the law does not exempt wholesale power contracts from that process.

PG&E also asserted that the commission’s requirement that it approve contract changes could prevent the utility from abrogating contracts despite bankruptcy court approval, depriving the utility of the flexibility intended by Section 365 of the bankruptcy code.

In rejecting rehearing, FERC insisted that it holds joint authority over the fate of the PPAs.

The commission said the Supreme Court has “long recognized” that the Federal Power Act “is designed to protect consumers” and that the commission protects the public interest in evaluating the rates, terms and conditions of PPAs.

“By contrast, the purpose of the bankruptcy code, as PG&E acknowledges, is to provide a path to rehabilitate bankrupt debtors,” the commission wrote. “These are two distinct, yet vitally important, roles, and we conclude that it is necessary to give effect to both.”

FERC said wholesale power agreements are not “simple run-of-the-mill” contracts between private parties. Instead, they “implicate the public’s interest in the orderly production of plentiful supplies of electricity at just and reasonable rates and, as filed rates, carry the force of law binding sellers and purchasers alike.”

“Whether a wholesale rate is just and reasonable — and whether the abrogation or modification of a wholesale power contract is necessary to protect the public interest — is a question that the commission is statutorily obligated — and exclusively authorized — to consider,” the commission said.

The commission’s “unique role” in making such determinations regarding contracts “neither subsumes nor is subsumed by” bankruptcy law, FERC said. The seeking of bankruptcy protection “does not transform commission-jurisdictional contracts into non-jurisdictional ones … and it does not divest the commission of its statutory mandate to protect the public interest by examining the ramifications of unilateral changes to wholesale power contracts, a highly technical analysis that the bankruptcy process is not designed to consider.”

On Thursday, Justice Department lawyers filed the FERC decision with the bankruptcy court and requested Montali take judicial notice of the decision, establishing it as evidence in the case. It remains unclear when Montali might rule on PG&E’s petition for an injunction against FERC. The next hearing in PG&E’s bankruptcy is scheduled for May 8 at 9:30 a.m.

Hudson Sangree contributed to this report.

May 3, 2019

Eversource Earnings Rise on Tx, Distribution, Gas

By Michael Kuser

Eversource Energy’s earnings jumped nearly 15% to $308.7 million ($0.97/share) in the first quarter, driven by strong gains in its electric transmission, distribution and natural gas delivery businesses.

“Our Eversource team has gotten off to a tremendous start in 2019,” CEO Jim Judge said in a statement.

As New England’s largest utility company, Eversource’s regulated subsidiaries offer retail electricity, natural gas service and water service to approximately 3.6 million customers in Connecticut, Massachusetts and New Hampshire.

The company said its transmission segment earned $118.2 million in the quarter, up 10% over last year, while electric distribution took in $120.1 million, up 15.2%. The improved results for the electric business were “due primarily to higher distribution revenues, partially offset by the absence of New Hampshire generation earnings in 2019 and higher depreciation expense,” Eversource said. The company last year sold off the last of its New Hampshire generating capacity as part of the state’s deregulation effort.

The natural gas distribution segment earned $76.5 million in the first quarter, up 32% from a year ago, mostly because of “the timing of distribution revenues under the recently approved decoupling mechanism for Eversource’s Connecticut natural gas business,” the company said.

The gas segment additionally benefited from capital tracking mechanisms on higher levels of investment, partially offset by higher operations and maintenance, property tax and depreciation expense, Eversource noted.

The water distribution segment earned $0.9 million in the quarter, compared with earnings of $1.5 million a year ago. “The modest decline was due primarily to higher pension costs,” the company said.

Judge noted that Eversource is “executing on a nearly $13 billion, five-year core business capital plan that will greatly help our region address its long-term infrastructure and clean energy needs.” The plan projects continued strong spending on electric distribution, solar and natural gas delivery, with steadily declining outlays for transmission heading to 2023.

May 3, 2019

Monitor: PJM Simulation Underestimates ORDC Impact

By Christen Smith

PJM’s Independent Market Monitor said the RTO’s updated simulation results for energy price formation understimate the impact of its operating reserve demand curve (ORDC).

In its own analysis released Friday, the Monitor said PJM’s decision to rely on dispatch conditions that allow the software to decommit resources otherwise required for reliability “presents a significant departure from reality” and results in understated market impacts.

At an April 10 Market Implementation Committee meeting, PJM’s Adam Keech said changing unit commitment based on real-time instead of day-ahead market runs — otherwise known as “Case C” in simulations — increased LMPs, boosted energy revenues and cut uplift by more than 80% compared with the status quo, which staff referred to as “Case A” in simulations. (See “ORDCs Shrink in Updated Energy Price Formation Simulation,” PJM MIC Briefs: April 10, 2019.)

By applying PJM’s proposed ORDC and 30-minute reserve market to conditions set in “Case B,” the simulation increased LMPs by an average of 46 cents/MWh, assigned an additional 1,350 MWh of synchronized reserves and 3,337 MWh of secondary reserves, and generated $550 million more in total energy and reserve market revenues, Keech said.

“If it is the case, and PJM implies that it is, that the ORDC would replace manual operator commitments with market commitments, the relevant comparison is Case A to Case C, because Case A contains the steam unit commitments made by operators,” the Monitor said. “Case B removes all uneconomic operator commitments.”

PJM — Summary results for the five simulation cases | *Monitoring Analytics*

The Monitor’s simulation compared Case C to Case A — defined as PJM’s optimal dispatch conditions — to get what it considers a better measure of real-life market impacts. The comparison shows less uplift, higher LMPs and revenues, with larger impacts than PJM’s Case B to Case C comparison.

The Monitor further cautioned that even Case A conditions do not represent the “actual status quo,” and using it as a benchmark still underestimates real-world costs of PJM’s proposed ORDC approach.

The Monitor’s simulation of an ORDC based on 15-minute forecast errors, compared to PJM’s 30 minutes, resulted in lower price and revenue differences.

“The Market Monitor disagrees with PJM’s conclusion that a 30-minute time horizon is appropriate for the 10-minute reserve products,” the Monitor said. “Case C 15-minute presents a case where the ORDC is shifted inward using a 15-minute forecast time horizon for the synchronized and primary reserve demand curves.”

On Monday, PJM spokesperson Jeff Shields said the RTO stands by its filing and disagrees with the Monitor’s opinion.

“PJM’s simulation analysis was intended to reflect and isolate the impacts of implementing the enhanced ORDCs,” he said. “While PJM acknowledges that there will also be benefits in the form of more optimal commitment and dispatch solutions, PJM does not agree that the entire difference between Cases A and C in the IMM report reflect the anticipated impact of the changes PJM filed on March 29.”

(Updated to reflect that the Monitor’s analysis compared Case A to Case C and found PJM’s simulation underestimates ORDC impact. A previous version of this story said the simulation results were overestimated.)

(Updated to include PJM’s statement.)

May 3, 2019

FERC Upholds PJM Monitor’s Right to Protest Fuel-cost Policies

By Christen Smith

FERC said Monday that the Independent Market Monitor’s filing of complaints regarding PJM’s fuel-cost policies doesn’t violate Tariff conditions or commission rulings, ending — for now, at least — a long-simmering debate over the extent of the IMM’s authority (ER16-372).

Joe Bowring, PJM’s Independent Market Monitor | © *RTO Insider*

The commission denied the RTO’s request for clarification regarding the Monitor’s ability to file complaints regarding issues besides market seller offers in capacity auctions.

The Monitor had protested PJM’s August 2016 proposed Tariff revision regarding the fuel-cost policies that generators submit showing how they calculated their cost-based offers. It said the RTO was trying to usurp its authority to regulate the policies. (See PJM Attempting to Usurp Market Mitigation Role, Monitor Says.)

FERC ultimately sided with PJM in February 2017, saying the changes didn’t alter the fundamental roles of the RTO and the Monitor, “but rather [they] codify the role of the IMM in advising and providing input to PJM in its determination of whether to approve a fuel-cost policy submitted by a market seller.”

But FERC also rejected PJM’s proposal that any disputes between PJM and the Monitor be referred to the commission’s Office of Enforcement, saying that was the province of its administrative law judges.

When the RTO filed further changes on compliance in March, it also filed the clarification request, questioning whether the commission intended “to enable the IMM to initiate a complaint against PJM” when they disagreed over the policies.

“Although PJM is correct that its Tariff explicitly delineates one instance in which the IMM has the right to file a complaint with the commission, the inclusion of an express right to bring a complaint does not necessarily foreclose an entity’s general right to file complaints under Section 206 of the [Federal Power Act],” the commission said. “In any case, we need not reach that issue here because we are unpersuaded by PJM’s narrow reading of Attachment M” of its Tariff.

FERC accepted PJM’s March 2017 compliance filing in the same order. (See FERC Seeks More Details on PJM’s Fuel-Cost Policy Proposal.) The commission accepted the RTO’s clarifications on several issues, including:

Clearly specifying when a penalty for noncompliance with a fuel-cost policy would be terminated by PJM.

Allowing a new resource a 90-day time period before it submits its fuel-cost policy.

Specifying that a market seller may only update its minimum run time for the uncommitted hours in real time and that a market seller’s make-whole payment be based on the minimum run time specified at the time of commitment.

The Tariff and Operating Agreement revisions for the penalty structure became effective May 15, 2017, and the rest of the provisions Nov. 1, 2017.

May 3, 2019

NPCC Sees Lower Summer Peak for 2019

By Rich Heidorn Jr.

The Northeast Power Coordinating Council (NPCC) is projecting a summer peak demand of 103,548 MW in the week of July 28, a 0.6% reduction (589 MW) from last year, despite growth in Ontario.

“This continues an almost decade-long trend of overall flat or declining peak demand forecast due to energy efficiency and conservation initiatives, as well as the significantly increasing role of behind-the-meter PV resources in New England and New York,” NPCC CEO Edward Schwerdt said in a May 2 press release announcing the summer Reliability A ssessment.

With the addition of 2,855 MW of net new capacity since summer 2018, NPCC forecasts a minimum operable capacity margin (spare operable capacity less transfer capability limitations) of 12,545 MW (12.2%) for the summer.

NPCC is the NERC regional entity for New England, New York, Ontario, Québec, New Brunswick and Nova Scotia. The U.S. represents 46% of NPCC’s net energy for load with Canada accounting for 54%. NPCC represents about 70% of Canada’s electric demand.

While New England and New York often hit their summer peaks together because of the proximity of their load centers, “there is some potential” for Ontario’s summer peak to occur at the same time, the report said. “Ambient weather conditions remain the most important variable in forecasting peak demand during the summer months,” it said.

The report included regional snapshots of the changes in generation since summer 2018 and the projected peaks for this year:

New York added a net 127 MW, including 158 MW of wind, with 167 MW of coal generation retirements and 446 MW restored with the withdrawal of Selkirk 1 and 2’s mothball notice. NYISO projects a peak of 32,382 MW, a 522-MW drop from the summer 2018 forecast, because of state energy efficiency programs and the growth of BTM, including retail PV, combined heat and power, anaerobic digester gas, fuel cells and energy storage.
New England added a net of 568 MW, including the dual-fuel Bridgeport Harbor expansion (510 MW), Canal 3 (333 MW) and Medway Peaker (208 MW). Wind and solar generation increased by 135 MW. Entergy’s Pilgrim nuclear plant (680 MW), Massachusetts’ only nuclear unit, is expected to retire by June 1. ISO-NE’s forecast peak is 25,323 MW, 406 MW below last year’s projection. The RTO cited demand reductions from energy efficiency, load management, passive demand response, distributed generation and BTM PV.
Ontario’s generation increased by a net of 1,418 MW, including the Napanee gas-fired generator (985 MW), wind (375 MW), solar (98 MW) and hydro (16.4 MW). About 56 MW of gas-fired generation is retiring. Ontario’s Independent Electricity System Operator forecast a 103-MW increase in peak demand, to 22,105 MW. Conservation savings and distribution-connected generation are expected to partially offset increased demand from economic and population growth.
Québec and the Maritimes, both winter-peaking areas, will see a slight increase, with Québec adding 38 MW of biomass and losing 8 MW of other generation for a net change of 30 MW. Québec is forecasting a 471-MW increase in the peak, to 21,005 MW. The Maritimes expect a peak of 3,255 MW, up 20 MW from last summer.
Entergy’s 680-MW Pilgrim nuclear plant will shut down by June 1. | Entergy

Transmission, Pipelines

Although NPCC expects spare operable capacity (capacity above reserve requirements) of 19,884 MW during its coincident peak the week of July 28, limited transfer capability from Québec and the Maritimes will reduce the amount available to the rest of its territory to 14,954 MW.

Since last summer, NYISO has added the Cricket Valley 345-kV substation — on the Pleasant Valley-Long Mountain 345-kV tie line with New England — to serve the new Cricket Valley combined cycle generating station expected to begin operation after the summer.

Unlike in winter, ISO-NE does not expect natural gas deliverability issues to affect generation. The RTO also can call on 340 MW of active demand resources on the peak.

The RE said it foresees “no significant likelihood” of implementing operating procedures for resource shortages (voltage reductions, and reductions of 10- and 30-minute reserves) during the summer for the expected peak load, a forecast based on the probability-weighted average of seven load levels simulated.

NPCC said operating procedures are available if needed to maintain reliability during severe system conditions and extreme heat simultaneously. The assessment also considered scenarios with extended unit maintenance; reductions in DR; reductions in the ability to import power from neighboring regions; transmission constraints; and widespread and prolonged heat waves with high humidity.

Geomagnetic Disturbances

The RE, which has had operating procedures since 1989 to respond to geomagnetically induced currents (GICs) from solar storms, said it expects “quiet levels” of solar activity for the summer.

“The solar coronal regions are stabilizing as the next solar minimum approaches, with fewer coronal holes and fewer extensions to lower solar latitudes that can sweep higher velocity solar winds toward the Earth,” NPCC said, while acknowledging that sunspot formations are difficult to predict.

While “these rogue events can and do occur,” the report said, “the odds of such an event during any particular week of the coming summer are very low.”

May 3, 2019

Rainwater Exit Leaves Open Seat on MISO Board

By Amanda Durish Cook

MISO’s Board of Directors will hold a special vote to fill the seat of former Director Thomas Rainwater, who left last month to serve on the board of a for-profit energy company outside the RTO’s footprint.

Rainwater was re-elected to the MISO board late last year after having served since early 2015. His new term was set to expire at the end of 2020.

Reached by telephone, Rainwater said he preferred not to reveal the name of the New England waste-to-energy company where he will assume his new role. MISO viewed the two board positions as possibly conflicting.

“Because this opportunity is in a similar or related industry, he is precluded from also continuing as a MISO board member,” the RTO said in a release. It has removed Rainwater’s entry from its leadership webpage.

MISO bylaws stipulate that the board must hold a special vote to fill a vacancy stemming from a director departing before their term expires. Directors will evaluate a pool of candidates provided by an outside executive search firm. Candidates must have the same type of qualifications as the departing board member, and the selected candidate will serve out the remainder of their predecessor’s term.

The special board vote has not yet been scheduled.

Rainwater has 30 years of experience in both the electricity and natural gas sectors and has chaired the board’s Corporate Governance and Strategic Planning Committee and the Audit and Finance Committee.

“Tom has been very generous in sharing his broad experience with the board, MISO staff and our stakeholders over the last four years,” Chair Phyllis Currie said.

Rainwater said he enjoyed his time on the on the board and was leaving with “nothing but praise” for MISO and its work.

Rainwater’s exit comes as a special Advisory Committee task team is re-examining the RTO’s board qualifications, including the possibility of requiring departing directors to observe a “cooling-off” period before joining a MISO-related organization. (See related story, Task Team Begins Look at MISO Board Rules.) Directors drawn from MISO-related companies are already subject to a yearlong industry moratorium before taking a seat on the board.

May 3, 2019March 19, 2025

NRG Energy Earnings Drop on ERCOT Hedges

By Michael Kuser

Citing hedging losses in ERCOT, NRG Energy on Thursday repor t ed $94 million in income from continuing operations for the first quarter ($1.72/share), down 60% from $238 million in the same period a year ago.

Adjusted EBITDA for the quarter was $333 million, a slight decline from 2018.

The drop in income from continuing operations was “driven by retail gains and partially offsetting generation losses on mark-to-market hedge positions in 2018 as a result of ERCOT heat rate expansion and increases in electricity prices,” the company said.

“Our integrated platform delivered strong first-quarter results,” CEO Mauricio Gutierrez said. “We are preparing for summer operations and executing on our capital allocation priorities, including returning capital to shareholders.”

NRG east generation fleet | NRG

The company highlighted having completed $500 million of its $1 billion share buyback program, as well as the planned June 2019 return to service of its 385-MW Gregory combined cycle plant in Corpus Christi.

In an ERCOT market update, the company said it sees reserve margins continuing to tighten as new builds lag demand growth, and that its retail business is prepared for summer volatility. The company is relying on enhanced demand management programs, hedges on “priced load,” expanded maintenance and excess generation to see it through the summer.

NRG said it also plans to complement its fleet with power purchase agreements.

PJM, ISO-NE

In its Eastern markets, the company highlighted that FERC Orders Fast-start Rules for PJM, NYISO.)

The company said it views current ISO-NE fuel security proposals as insufficient.

The RTO in March filed an interim proposal with FERC to address winter energy security for the commitment periods covered by Forward Capacity Auction 14 (2023/24) and FCA 15 (2024/25), a voluntary two-year program to “provide incremental compensation to resources that maintain inventoried energy during cold periods when winter energy security is most stressed.” (See ISO-NE Filing, Whitepaper Address Energy Security.)

NRG said it completed the sale of its Renewables Platform and its interests in NRG Yield on Aug. 31, 2018, and the South Central Portfolio on Feb. 4, 2019.

“As a result, 2018 financial information for the South Central Portfolio, NRG Yield, the Renewables Platform and Carlsbad Energy Center was recast to reflect the presentation of these entities as discontinued operations,” NRG said. The South Central Portfolio ($1 billion) and Carlsbad Energy Center — sold to Global Infrastructure Partners on Feb. 27 for $385 million — were also treated as discontinued operations through their dates of sale this year.

May 2, 2019December 12, 2023

FERC OKs SERC’s Expansion into Florida

By Rich Heidorn Jr.

FERC on April 30 approved the dissolution of the Florida Reliability Coordinating Council as a regional entity and SERC Reliability’s expansion into the Sunshine State (RR19-4).

FRCC agreed in October 2018 to relinquish its role following NERC’s determination that its REs — which are deputized to police reliability — should be separate from registered entities subject to NERC reliability standards.

In addition to serving as an RE, Tampa-based FRCC also has a Member Services division, which served as a reliability coordinator and planning authority. FRCC will continue to serve in those functions. “FRCC staff and members will continue to steadfastly pursue our vision to maintain a highly reliable and secure bulk power system for peninsular Florida,” CEO Stacy Dochoda said in a press release.

SERC, based in Charlotte, N.C., is expected to take over FRCC’s RE responsibilities July 1, with FRCC completing its “wind down” of those services by Aug. 31.

Some 37 registered entities in peninsular Florida east of the Apalachicola River will move to SERC, including large utilities Tampa Electric, Florida Power & Light and Duke Energy Florida and small municipal utilities serving Key West and the city of Bartow. (SERC already serves the panhandle west of the Apalachicola.)

SERC is revising its bylaws to expand its Board Executive Committee from 12 to 15 members and divide committee members into two groups with staggered, two-year terms.

SERC expects to add 17 to 21 full-time equivalent staff members to handle the increased workload. NERC and the two REs will use FRCC’s available cash as of July 1, its third and fourth quarter 2019 assessments, and a possible special assessment of up to $630,000 to fund the transition.

FERC also approved a request to allow use of any FRCC penalty funds submitted to NERC between July 1, 2018, and July 1, 2019, toward the transition costs. Penalties submitted between July 1 and Dec. 31 or not otherwise applied to the transition will be reimbursed to FRCC entities on a pro rata basis.

Answering Questions

SERC, which will hold its regular second-quarter “Open Forum” webinar at 2 p.m. May 6, has published a list of frequently asked questions on the transition.

Last year, SERC reorganized from five to six subregions: SERC PJM; SERC MISO-Central; SERC MISO-South; SERC Central (the Tennessee Valley Authority RC area); SERC South (the Southern Co. RC area); and SERC East (the VACAR South RC area).

SERC has one regional standard, PRC-006-SERC-02, governing automatic underfrequency load shedding requirements. SERC said it agreed with FRCC’s recommendation that Florida entities seek a compliance exception from the standard, saying “such action would be the simplest to allow time for the FRCC entity system to be included.”

May 2, 2019

UPDATE: Texas ROFR Legislation Pits Incumbents, Transcos

By Tom Kleckner

Fast-moving Texas legislation that would give incumbent utilities the right of first refusal (ROFR) to build transmission projects in the state remains on the brink of passage, though its days may be numbered.

H ouse B ill 3995, which was voted 11-0 out of the State Affairs Committee in April, was scheduled to be taken up by the House this week. However, the House adjourned May 3 without taking further action on the bill. It faces a May 9 deadline for passage.

Its companion bill, Senate Bill 1938, cleared the Senate on April 17, with all 31 members voting in favor. Because the bills are identical, should HB 3995 pass the House, it would only require the governor’s signature to become law — and become effective immediately, thanks to an “emergency rider.”

Texas officials often boast of the state’s 17-year-old deregulated electricity market as being the world’s best competitive market. It’s also the same state, opponents of the legislation note, where the $6.8 billion Competitive Renewable Energy Zone project resulted in 3,600 miles of high-voltage transmission lines being built in just five years.

“An ironic twist,” said Vera Carley, a spokesperson for GridLiance, a competitive transmission company that caters to public power agencies.

The bills would grant certificates of convenience and necessity (CCNs) to build, own or operate new transmission facilities that interconnect with existing facilities “only to the owner of that existing facility.”

GridLiance and other opponents of the legislation argue it would:

Make it illegal for anyone other than incumbent utilities to build new transmission in Texas.
Eliminate the Texas Public Utility Commission’s authority to license new entrants to build transmission assets and provide transmission services.
Prevent public power utilities and cooperatives from choosing with whom they want to partner by limiting their choice to the local incumbent utilities.
Overturn the Hartburg-Sabine Junction 500-kV project, which MISO last year awarded to NextEra Energy Transmission (NEET). The PUC has yet to grant a CCN for the project, though FERC in March authorized NEET to recover all “prudently incurred” costs related to its investment in the project. (See NextEra Gains Incentive for Hartburg -Sabine Project.)

The bill’s opponents include the U.S. Department of Justice, which r e sponded to an inquiry by Texas Rep. Travis Clardy by expressing concerns that the bills would “limit competition, thereby potentially raising prices and lowering the quality of service for electricity consumers.”

“By restricting the development of transmission facilities to local incumbents, H.B. 3995 can harm consumers by reducing or eliminating competition,” wrote Daniel Haar, acting chief of competition policy and advocacy in DOJ’s Antitrust Division. “Even if an incumbent is best-situated to develop a particular project, H.B. 3995 would likely reduce the competitive pressure on such incumbents to develop higher-quality, lower-cost transmission facilities.

“Furthermore, consumers may face higher electricity rates and less reliable service, as H.B. 3995 may limit construction of transmission that would increase the supply of generation available to serve a local territory or area,” he said.

‘Multitude of Benefits’

GridLiance is among those leading the charge against the legislation. In written comments filed with the State Affairs Committee, CEO Calvin Crowder said the bill would “deprive Texans … of the benefits of planned competitive transmission processes and would protect incumbent investor-owned utilities from competitive forces that drive project costs down.”

Crowder backed up his argument by pointing to a Brattle Group study of U.S. projects that found noncompetitive projects average 34% above initial estimates, while winning bids in competitive projects average 40% below estimates.

NEET Southwest won the Hartburg-Sabine bid with a $115 million bid, below MISO’s $122.4 million project estimate.

NextEra’s Aundrea Williams | © *RTO Insider*

Aundrea Williams, president of NextEra affiliates NEET Southwest and Lone Star Transmission, said in testimony before the State Affairs Committee that the Florida-based company “supports preserving the PUC’s jurisdiction over [in-state] transmission projects.”

“The PUC … should not be forced to pick from an unnecessarily limited set of qualified transmission providers,” she said. “Options would be taken away from the PUC, and thus Texans would be robbed of the multitude of benefits that transmission-only utilities provide.”

Commission spokesman Andrew Barlow said simply, “The PUC will implement whatever legislation becomes law.”

Xcel Energy subsidiary Southwestern Public Service supports the legislation “because our ability to build and own transmission lines that connect to our regional system protects our customers’ best interests,” spokesman Wes Reeves said.

“We have a long history of building transmission lines at a lower cost to our customers, and we have the resources available to repair them quickly to ensure the reliability of the system,” Reeves told RTO Insider.

Xcel and SPS have an appeal pending before the Texas 3rd Court of Appeals that protests a prior PUC declaratory order saying there is not a ROFR in the SPS service area. (See Texas Commission Rejects SPS ROFR Request.)

Williams said utilities supporting the legislation have lost their arguments on competitive transmission awards wherever they have made them.

“They took a swing and lost at the PUC; they took a swing and lost in the courts; and they took a swing and lost in the markets,” she said. “Now, as a last resort, they are changing the rules of the game. They’ve already had their three strikes and are out. Their market design is not what is best for Texas.”

Point, Counterpoint

The legislation has resulted in a flurry of competing op-eds in Texas newspapers.

Former FERC commissioner Tony Clark weighed in on the debate with an op –ed in the Houston Chronicle calling for the bill’s passage, writing that there’s “scant proof” that FERC Order 1000’s competitive process would “benefit Texas consumers, employers or industry.”

“At worst, [Order 1000] does more harm than good, delaying investment in needed transmission projects,” Clark said. “The only verifiable results of the federal process? Bureaucracy, litigation and delay. It is a rule with high compliance costs, but few tangible results to date. That’s not competition; it’s just a regulation that does not work.”

Clark’s op-ed was rebutted by Allen Johnson, director of government affairs for Citizens Against Government Waste in D.C. Johnson’s counte r point said the legislation is “clearly designed” to protect the incumbents at the expense of customers.

The legislation “would not only apply to any future transmission projects, it would overturn a competitively awarded transmission project,” he said. “Rather than receiving the lower prices that would be provided by the winning bidder, consumers would be stuck with the current transmission company. … This is plain and obvious corporate welfare.”

Bernard Weinstein, associate director of Southern Methodist University’s Maguire Energy Institute, took Clark’s argument a step further in the Dallas Morning News by saying the legislation is necessary because “a few companies and hedge funds are attempting to upend the system” by imposing Order 1000 on Texas.

That would open the state to federal regulation, Weinstein warned, overlooking the fact SPP and MISO already have footprints in Texas. The PUC and ERCOT, which would be responsible for implementing the bills, are not FERC-jurisdictional.

“Let’s not be seduced by the claim that so-called competition in transmission line development will mean a better deal for households and businesses. It won’t,” Weinstein said.

Williams responded with a letter to the Morning News. Identified only as “Aundrea Williams, Austin,” she charged that the legislation was prompted when NextEra “beat out the incumbent by tens of millions of dollars.”

“Supporters of the bill refuse to address the savings to Texans,” Williams wrote. “Make no mistake: Texans will have safe power either way, but their way costs a whole lot more. Texans deserve the best, and taking time to study the issue lets our representatives do that. Don’t let sore losers become winners — force them to do better.”

May 2, 2019

Task Team Begins Look at MISO Board Rules

By Amanda Durish Cook

A new MISO task team this month is seeking stakeholder suggestions to improve the process for choosing the RTO’s board members.

The newly established Board Qualification Task Team is exploring whether to extend to state regulators a one-year “cooling-off” period required of other industry participants before they can apply to serve on MISO’s Board of Directors. The group will also examine other aspects of the board’s makeup and required qualifications.

MISO’s Advisory Committee created the task team in March following last year’s board elections, in which Nancy Lange, then chair of the Minnesota Public Utilities Commission, was nominated to fill a seat on the board without observing the yearlong moratorium. (See New Task Team to Review MISO Board Rules.)

The MISO Board of Directors in March | © *RTO Insider*

The task team could recommend that the board amend its Transmission Owners Agreement bylaws to adopt improvements, which must be approved by FERC. Neither MISO nor its board is under any obligation to act on Advisory Committee recommendations.

During its first conference call Tuesday, the small task team decided it will issue a public document should it identify any worthwhile recommendations for changing the board selection process. Those recommendations would be reviewed and possibly taken up by the board’s Corporate Governance and Strategic Planning Committee, led by Director Theresa Wise.

However, the task team decided against drafting a white paper on board selection improvements, with Chair Mark Volpe saying such documents should be reserved for technical matters.

In addition to taking stakeholder recommendations, the new team will also review the composition of board nominating committees at other RTOs as possible examples for changing MISO’s Nominating Committee, which vets and selects board candidates for stakeholder voting.

The Nominating Committee currently holds slots for two stakeholders and three directors, prompting some Advisory Committee members to criticize its lack of stakeholder diversity and suggest that MISO should ensure broader representation of stakeholder sectors in selecting board candidates.

Volpe said stakeholders might prefer “broadened and more inclusive” representation and suggested that MISO could add stakeholder seats or rotate sector representation year to year. Task team members may also recommend that directors be required to observe an additional cooling-off period before joining a MISO-related organization after having served on the board.

Volpe asked task team members to come up with draft recommendations in time for the group’s May 28 conference call.