FERC on Monday approved an Entergy request to transfer ownership interests in two transmission control centers from Entergy Services to the company’s operating companies (EC19-18).
The commission found that the transaction would not adversely affect horizontal or vertical competition, noting that the control centers — in Jackson, Miss., and Little Rock, Ark. — have been and will continue to be operated under MISO’s control. FERC also determined that the transaction would not have an adverse effect on rates, as transferring the control center’s ownership will increase administrative efficiency and rate transparency.
The ownership interests will be allocated to Entergy’s operating companies in Arkansas, Louisiana, Mississippi, New Orleans and Texas based on each company’s 2017 coincident peak load. FERC established the peak-load allocation factors in a separate docket (ER19-211).
The commission also granted in part a complaint under Federal Power Act Section 206 by the Louisiana Public Service Commission, one of five regulatory bodies to intervene in the proceeding. The PSC alleged that the Entergy operating companies’ current accounting and rate treatment of the control centers’ costs characterize them as transmission facilities, and that all of their costs should be included in the companies’ MISO formula rates (EL18-201).
| Entergy
FERC denied Entergy’s request to dismiss the PSC’s complaint, saying the Uniform System of Accounts for public utilities requires that “transactions with associated companies … be recorded in the appropriate accounts for transactions of the same nature.”
“Affiliate transactions that are in the nature of transmission expenses must be recorded by the public utility in transmission expense accounts,” the commission wrote. Based upon the requirement, it disagreed with Entergy’s contention that its operating companies “comply with the commission’s accounting rules.”
The commission ordered the operating companies to make a compliance filing within 30 days showing that they have made the required accounting changes and formula rate recalculations. They also must explain how the recalculations will be reflected in the annual formula rate true-up.
The control centers went into service in 2016 and 2017. They replaced five transmission operations centers and a single system operations center previously owned by the operating companies and operated by Entergy Services.
President Trump’s plan to fill the Republican seat on FERC while leaving a Democratic seat vacant isn’t playing well with Democrats and environmental groups.
Trump announced late Monday his intent to nominate FERC General Counsel James Danly to fill the Republican seat opened by the death in January of Kevin McIntyre. Danly’s confirmation would give the Republicans a 3-1 majority, leaving Democrat Richard Glick alone with Chairman Neil Chatterjee and his fellow Republican, Bernard McNamee. (See FERC General Counsel Tapped for Commission.)
“I am disappointed that the president has only announced his intention to nominate a Republican commissioner,” Sen. Joe Manchin (D-W.Va.), ranking member of the Senate Energy and Natural Resources Committee, said in a statement. “FERC has a strong history of operating in a bipartisan fashion, and failing to honor the tradition of a bipartisan pairing sets a dangerous precedent moving forward. I remain hopeful the administration will quickly nominate a Democratic commissioner so we can consider both nominations together and restore a fully functioning FERC.”
Manchin and Senate Minority Leader Chuck Schumer (D-N.Y.) are reportedly backing attorney Allison Clements for the Democratic seat formerly occupied by Cheryl LaFleur. Clements, director of the Clean Energy Markets program at the Energy Foundation, formerly helped direct the Sustainable FERC Project for the Natural Resources Defense Council.
E&E News reported last month that Schumer was threatening to block ENR Committee bills if the Republicans push a GOP nominee without a Democratic pairing.
Sen. Lisa Murkowski (R-Alaska), chair of the committee, told Politico recently that she would not let the lack of a Democratic nominee keep her from holding a confirmation hearing for a Republican.
She issued a brief statement Tuesday acknowledging Trump’s announcement but noting that the committee had not yet received the formal nomination and “associated paperwork” needed before scheduling a confirmation hearing.
“I welcome the president’s decision to nominate a Republican commissioner and to fill a critical seat that has now been vacant for nine full months,” she said.
Environmental groups reacted with indignation over Trump’s announcement.
“Donald Trump’s decision — and Sen. Murkowski’s acquiescence — to exclude a Democratic nominee from his announcement of the Republican counterpart is a breach of precedent and another swipe at FERC’s historically independent mission,” said Mary Anne Hitt, senior director of Sierra Club’s Beyond Coal campaign. “We strongly urge Sen. Murkowski to demand nominees be paired and considered concurrently, and that the administration quickly put forward Mr. Danly’s Democratic counterpart. Not doing so will risk further denigrating this important commission.”
Unqualified?
Sam Gomberg, senior energy analyst for the Union of Concerned Scientists, called Trump’s decision a “marked departure from decades of precedent” and called Danly “woefully unqualified for the job.”
Danly earned his J.D. at Vanderbilt University Law School in 2013 and worked in the energy regulation and litigation group at Skadden, Arps, Slate, Meagher & Flom before being appointed general counsel in September 2017.
“Prior to his appointment to general counsel at FERC, he had a brief stint as an associate energy attorney. I simply don’t see how the American public can have any confidence in his ability to understand the complex issues facing the energy sector right now and to make forward-looking, well-informed decisions on the issues awaiting the commission,” Gomberg said. “His inexperience absolutely increases the risk of a commission unable to defend consumers from biased and politically motivated attacks on our regulatory structure.”
Chelsea Eakin, senior manager for energy transition for climate change activists Climate Nexus, said the departure of LaFleur, who served for nine years, left the commission with a lack of institutional experience. “Combined, the three current commissioners have served for less than half the time LaFleur did and only under President Trump,” she said. “Danly’s confirmation would stack the commission, tasked with making energy decisions that have significant impacts on U.S. emissions, with like-minded Trump appointees in advance of a busy fall agenda.”
John Moore, director of the Sustainable FERC Project, said the Senate should require Danly to answer questions about his “humble regulator” philosophy.
“Before they vote on his nomination, senators must ask him what that means. Would Danly defer to the authority of states to set their own clean-energy policies? Would he continue FERC’s flawed climate review of pipelines that he defended in court?” Moore asked. “Critically, the nomination of only one commissioner when there are two vacancies reflects a further erosion of longstanding norms and undercuts the independence and bipartisan decision making at FERC.”
Nominating Rules
ClearView Energy Partners noted Tuesday that the changes to Senate nomination rules during the 115th Congress reduced the minority’s party ability to stop or slow presidential nominations.
“Although it has been customary to move bipartisan pairs of nominees for independent commissions such as FERC when two vacancies exist, we’d argue that practice had been a function of political necessity given the prior ability of either party to filibuster a nominee,” they said. “Assuming Danly’s paperwork has been or is expeditiously forwarded to the Senate Energy Committee for consideration, we think it is possible that his nomination could move through committee and to the Senate floor by the end of October. Senate consideration can only begin, however, when the White House literally forwards a nominee’s paperwork, and this part of the process has not always happened quickly.”
With only three members, recusals by McNamee or Glick have left the commission without a quorum recently, including a recent vote on FCA 13 Results Stand Without FERC Quorum.)
If Danly’s appointment allowed FERC to act on the PJM docket in November, the delayed 2019 auction could be held in mid-2020, before the 2020 auction, ClearView said.
FERC on Monday again upheld the RTO incentives it previously approved for Southern California Edison and Pacific Gas and Electric, rejecting rehearing requests by California regulators.
Commissioner Richard Glick, who had dissented on the 50-basis-point adder to SCE’s return on equity in December 2017, joined with the majority this time around. (See FERC Sets Hearing on SCE Tx Rates; Glick Dissents.)
The commission has repeatedly approved the adder for the two utilities’ participation in CAISO since creating the incentives in Order 659 in 2007.
The California Public Utilities Commission challenged the adders, arguing that the state’s three big investor-owned utilities — PG&E, SCE and San Diego Gas & Electric — were required by state law to participate in CAISO.
In 2018, the 9th U.S. Circuit Court of Appeals remanded the issue and directed FERC to conduct fact finding on whether PG&E could unilaterally leave CAISO. The commission responded with an order in July, saying that the utilities could leave CAISO without CPUC approval and thus were entitled to the incentive. (See PG&E Deserves $30M ISO Adder, FERC Says.)
In Monday’s orders (ER17-2154-001, ER18-169-001, EL18-44-001), FERC reiterated its conclusion, citing a section of the California Code that states that the IOUs “should commit control of their transmission facilities to the independent system operator.”
“The language of these statutory provisions does not mandate participation in CAISO,” FERC said. “Rather … these provisions speak in terms of encouragement and facilitation of participation.”
Glick said that although he dissented from the 2017 SCE order, “I believe that the commission has now adequately addressed the arguments against” the RTO adder.
The leaders of the Senate Energy and Natural Resources Committee last week announced bipartisan legislation to provide $250 million in funding for transmission owners’ cybersecurity investments as independent power producers said they may seek to recover their compliance costs through RTO capacity markets.
The Protecting Resources on the Electric grid with Cybersecurity Technology (PROTECT) Act, would direct FERC to initiate a rulemaking on rate incentives, and the Department of Energy to offer grants and technical assistance, for investments in “advanced cybersecurity technology.” The DOE program would be for electric cooperatives, municipal utilities and others not regulated by FERC.
Announced on Thursday, the legislation would provide $50 million annually for fiscal years 2020-2024.
Committee Chair Lisa Murkowski (R-Alaska) introduced the bill with ranking member Sen. Joe Manchin (D-W.Va.) and Sens. James Risch (R-Idaho), Maria Cantwell (D-Wash.) and Angus King (I-Maine).
Prospects for the legislation were clouded Monday by President Trump’s announcement that he will nominate FERC General Counsel James Danly to fill an open Republican spot on the commission without also filling the open Democratic seat. E&E News reported last month that Senate Minority Leader Chuck Schumer (D-N.Y.) was threatening to block ENR Committee bills from reaching the floor if the Republicans push a GOP nominee without a Democratic pairing.
The bill, which would amend the Federal Power Act, defines “advanced cybersecurity technology” as “any technology, operational capability or service, including computer hardware, software or a related asset, that enhances the security posture of public utilities through improvements in the ability to protect against, detect, respond to or recover from a cybersecurity threat.”
FERC would be required to initiate a study within six months after the bill’s enactment “to identify incentive-based, including performance-based, rate treatments” to encourage cybersecurity investments and participation in threat information-sharing programs. FERC would be required to consult with DOE, NERC, the Electricity Subsector Coordinating Council and the National Association of Regulatory Utility Commissioners on the study.
The incentives would be available for investments that reduce cyber risks to “defense critical electric infrastructure” and other FERC-jurisdictional facilities “critical to public safety, national defense or homeland security.” Also eligible would be facilities of small- or medium-sized public utilities with limited cybersecurity resources.
Utilities would seek incentives through a “single issue” filing under FPA Section 205 that would be “without regard to changes in receipts or other costs of the public utility.”
DOE would issue grants and technical assistance on a competitive basis, giving priority to companies with limited cybersecurity resources or that own defense critical infrastructure or other assets “critical” to the reliability of the bulk power system.
“The consequences of a successful cyber-incursion would be widespread and potentially devastating,” Murkowski said in a statement. “We know the threat of cyberattacks by our foreign adversaries and other sophisticated entities is real and growing.”
EPSA Report
On Monday, meanwhile, the Electric Power Supply Association (EPSA), which represents independent power producers and marketers, issued a report saying that competitive generators may need to seek additional revenue through RTO operations and maintenance (O&M) charges if cybersecurity rules on them are tightened.
EPSA said regulators should give generation owners “flexibility … to prioritize and address critical security matters.”
“Factors including company size, extent of asset ownership, transmission configuration, physical location and design of facilities, presence in organized wholesale markets, regional resource and system constraints, and prior patterns of theft, vandalism, and other security-related activities all influence analyses and decisions regarding critical asset identification and risk threat assessments by individual companies,” EPSA said. “Should the government opt to vastly ramp up or change cyber and physical security requirements, additional cost recovery avenues or mechanisms may merit consideration for companies that operate in market-based rate regimes.”
EPSA said the costs of complying with additional security requirements should be recovered in a “regional or systemwide basis.”
“As some of the cyber and physical security costs clearly fall into the O&M bucket, the capacity markets are where these costs should be appropriately priced and ultimately recovered. By reflecting these costs into net [cost of new entry] calculations, ISOs/RTOs will ensure that resources can be compensated through the capacity markets for their costs of doing business, including necessary cyber and physical security investments.”
The report also complained that EPSA members sometimes do not learn of security incidents for 18 to 24 months afterward, “which makes preparing for and girding against these threats more difficult or not timely as the incident/threat may have already run its course or caused significant damage by the time they are briefed.
“It is important that companies have access to the critical information needed to ensure that their systems and awareness are up to date,” EPSA continued. “An important improvement would be to ensure that such information is not overly restricted as classified unless warranted, and that there are numerous persons at a company with the necessary security clearance to receive it. The security of the system is far too important to hinge on the availability of one or two people at a company with the necessary clearance to receive timely information.”
“Timely declassification of actionable information is important to grid reliability and security,” NERC spokeswoman Kimberly Mielcarek said. “The quicker the Electricity Information Sharing and Analysis Center and industry receive this information, the better we are able to safeguard the grid and mitigate risk.”
Concern Rising
Concern has risen since the revelations of Russian hackers’ attacks on Ukraine’s electric grid in 2015 and 2016.
In January, the U.S. Intelligence Community’s 2019 Worldwide Threat Assessment reported that Russia has the ability to execute cyberattacks in the U.S. that could disrupt “an electrical distribution network for at least a few hours.”
The report also said that “China has the ability to launch cyberattacks that cause localized, temporary disruptive effects on critical infrastructure — such as disruption of a natural gas pipeline for days to weeks.”
Sen. King has called for more urgency in addressing the threat, saying the federal government should develop an “offensive response” to attacks on the grid and other critical infrastructure. (See “Sen. King Calls for ‘Offensive’ on Cyberthreats,” Overheard at NECPUC 71st Annual Symposium.)
At a FERC technical conference in May, the idea of incentivizing investments to improve resilience received mixed reviews. ITC Holdings said the commission should ensure cost recovery for TOs that go beyond NERC standards “consistent with Order No. 679,” which established incentives to compensate for the challenges faced by specific transmission projects, for forming a transmission-only company and for joining an RTO.
But Alliant Energy rejected the idea of a “resilience incentive,” saying it was unnecessary and would provide a windfall to TOs. “Transmission owners currently do not have difficulty securing financing for transmission projects,” Alliant said. (See Mixed Reaction for ‘Resilience Incentives’.)
In July, NARUC released tools to help regulatory commissions gauge the effectiveness of utilities’ cybersecurity preparedness efforts and the prudence of related expenditures. (See NARUC Offers Tools for Measuring Cybersecurity.)
A notable group of claimants has added its voice to the growing chorus of parties asking a federal judge to end Pacific Gas and Electric’s exclusive right to offer a plan for emerging from bankruptcy.
On Tuesday, the Official Committee of Unsecured Creditors of PG&E filed in support of a motion urging the U.S. Bankruptcy Court in San Francisco to terminate PG&E’s so-called “exclusivity period” and open the utility’s Chapter 11 proceeding to alternative plans.
“Competing plans proposed by diverse stakeholders have created strong positive momentum, which is vital for a successful resolution of PG&E’s bankruptcy cases,” the Official Committee of Unsecured Creditors of PG&E said in a statement accompanying its filing supporting the motion. “Ending the exclusivity period would foster competition among plans and will generate improvements in both plans.”
The committee was appointed by the bankruptcy court to represent the interests of organizations with unsecured credit claims against the utility and its parent company, PG&E Corp. Its members include the International Brotherhood of Electrical Workers, Pension Benefit Guaranty Corporation, NextEra Energy, Deutsche Bank, Davey Tree and others.
PG&E last month asked Judge Dennis Montali to extend its window of exclusivity from late November to late January, arguing it has made a good-faith effort to resolve one of the biggest bankruptcies in U.S. history.
In its current — and incomplete — form, PG&E’s reorganization plan proposes using $14 billion in new equity financing to pay off wildfire claims and emerge from bankruptcy by June, in time to take advantage of a new $21 billion wildfire recovery fund established by the California State Legislature. The plan would provide a capped trust of $8.4 billion for fire victims in addition to the $11 billion for subrogation claims.
The motion to end exclusivity was submitted by an “ad hoc group” (AHG) of bondholders who hold about $10 billion in unsecured PG&E debt. They’ve proposed a competing reorganization plan that would provide them control over the utility, injecting more than $30 billion in liquidity, including about $18.4 billion for fire victims. (See Judge Weighs Competing PG&E Bankruptcy Plans.) That plan has been endorsed by the Tort Claimants Committee (TCC), the court-appointed group representing victims of wildfires sparked by PG&E equipment.
While the unsecured creditor group stopped short of outright endorsement of the bondholder proposal, it did laud the plan and call it “a significant step forward.”
“For the first time, a plan is being proposed that pays all unsecured claims, including wildfire claims, in full, is supported by the TCC, a fiduciary for all wildfire claimants, and is backed by evidence of substantial committed financing,” the creditor committee said in its filing.
It also noted the bondholder plan is not conditioned on “a lengthy and uncertain estimation process” or a trial over claims related to the 2017 Tubbs Fire in California’s wine country, which Montali in August determined should be decided in state court, likely complicating and prolonging the outcome of PG&E’s bankruptcy.
The creditors had little favorable to say about PG&E’s own plan, noting its approach stands in “stark contrast” to that of the bondholders.
“In its October rulings on exclusivity, lifting of the automatic stay with respect to the Tubbs Fire trial and setting in motion the process going forward for estimation, the [bankruptcy court] made crystal clear its view that resolution of the wildfire claims and payment of the individual victims is the Court’s paramount objective in these cases,” the creditor committee wrote. “The ad hoc group and the TCC took that guidance to heart, got in a room and reached a fair and reasonable agreement that stands to benefit all creditors. The debtors, on the other hand, chose instead to focus their efforts on a bilateral settlement with a single group of institutional creditors.
As South Carolina lawmakers field offers for state-run utility Santee Cooper, its largest customer quietly joined PJM last month.
Central Electric Power Cooperative became a voting member of PJM on Sept. 5 as part of the “other suppliers” sector. Jeff Shields, a PJM spokesperson, said Tuesday the new addition doesn’t include transmission system integration and doesn’t expand the RTO’s 13-state footprint — a somewhat common occurrence among its 1,000-plus members.
“Just like Central Electric Cooperative, they [other individual companies] find benefit from membership without integration of service territory,” he said.
The Columbia-based co-op owns 800 miles of transmission lines across all 46 counties, making it the largest customer of Santee Cooper, the state-run utility company that provides electricity and water to more than 2 million residents statewide.
| Central Electric Power Cooperative
Central Electric provides wholesale electric service to all 20 of the state’s cooperatives and has a peak demand of about 4,500 MW. The co-op owns community solar and peaking generation but obtains most of its energy through long-term power purchase agreements with Santee Cooper, Duke Energy Carolinas and the Southeastern Power Administration.
The PJM membership will become official once the company receives approval from the U.S. Department of Agriculture’s Rural Utilities Service, expected sometime in November.
“Our relationship with PJM is new, but there’s nothing new about our long-term planning,” said Robert Hochstetler, Central’s CEO. “As we plan, we consider least-cost, reliability and diversification of our portfolio, and their geographic footprint and generating capacity offer benefits other than power supply for Central.”
The cooperative said PJM membership will allow it to request feasibility studies of importing electricity generating capacity and energy from the RTO’s power pool. In its market participant category of membership, however, “Central’s interest will be purely contractual, not operational, in nature.”
“We don’t intend to commit resources into PJM, meaning we won’t be integrating our transmission system with theirs,” said Hochstetler. “We only intend to determine whether purchasing from PJM represents low-cost, risk-adjusted power supply.”
Central said it’s currently in discussions with Duke about its contract, set to expire in 2030. Its Santee Cooper agreement could last until 2058, though the company expects more conversations with other suppliers as it diversifies its portfolio.
Santee Cooper has been under increasing scrutiny after a $10 billion plan to expand the V.C. Summer nuclear plant near Jenkinsville unexpectedly fell apart in July 2017, leaving ratepayers on the hook for $4 billion racked up in construction costs before the utility and its privately run partner, SCANA, pulled the plug. Federal investigators are now trying to determine how soon the utilities knew of the impending doom and whether key information was hidden from lawmakers and regulators who could have intervened.
In March, the state legislature — long pressured by Gov. Henry McMaster — announced a plan to sell Santee Cooper in 2020 to erase the construction debt and spare customers from four decades of rate hikes. Lawmakers have also expressed support for studying RTOs and whether such a system could work well in South Carolina.
As for SCANA, Dominion Energy finalized a merger with the troubled company in January that included a $2 billion plan to freeze customer rates after mounting hikes in the wake of the abandoned nuclear project.
“Putting into effect bills below the temporary rates and keeping residential, commercial and industrial electric bills lower and competitive with neighboring states will aid South Carolina in its economic development efforts and ensure the state has a reliable energy supply to fuel growth and power the state’s homes and businesses,” Dominion CEO Tom Farrell said at the time.
President Trump on Monday announced he will nominate FERC General Counsel James Danly to fill the Republican vacancy left by the death of Kevin McIntyre.
The commission was reduced to three members — Chairman Neil Chatterjee and Commissioners Richard Glick and Bernard McNamee — after the departure of Commissioner Cheryl LaFleur in August.
That has left the commission without a quorum in some cases as Glick, the lone Democrat, has been recusing himself from votes involving his former employer, Avangrid. (See related story, FCA 13 Results Stand Without FERC Quorum.)
Danly, formerly a member of the energy regulation and litigation group at Skadden, Arps, Slate, Meagher & Flom, was tapped to serve as general counsel in September 2017, a month after Chatterjee was named chairman.
Danly earned his J.D. at Vanderbilt University Law School in 2013 and a bachelor’s from Yale University, where he studied classics and English.
After law school, he clerked for Judge Danny Boggs of the 6th U.S. Circuit Court of Appeals.
He was a managing director of the Institute for the Study of War, a military think tank in D.C., and served an International Affairs Fellowship at the Council on Foreign Relations.
A former U.S. Army officer, he served two deployments to Iraq and received a Bronze Star and Purple Heart.
During his first tour, with an infantry company in the Dora district of Baghdad, he authored and executed Operation Close Encounters, a tactical counterinsurgency program during the troop surge of 2007, according to a biography he provided to the Council on Foreign Relations.
In his second tour, he served under General David Petraeus at Multi-National Force – Iraq.
If confirmed, Danly’s term would end June 30, 2023.
In a profile in June, E&E News reported that Danly espouses a legal philosophy he calls the “humble regulator” — that FERC should work under a very narrow reading of the Federal Power Act and Natural Gas Act rather than using the agency’s discretion to interpret the statutes.
E&E said Danly’s philosophy was influenced by the conservative Federalist Society, which has served as a clearing house for many of Trump’s judicial appointments.
Texas regulators last week formally approved one of two transmission projects necessary to integrate much of the city of Lubbock’s load into ERCOT.
The Public Utility Commission signed off on a certificate of convenience and necessity (CCN) during its open meeting Thursday, granting Sharyland Utilities and Lubbock’s joint application for a 58-mile, $90 million 345-kV link between substations in Ogallala and Abernathy. Substation improvements will increase the total cost to nearly $100 million (48625).
The commission also heard oral arguments from two landowners opposing the path of the second 345-kV project, a 33-mile line from Abernathy to Wadsworth projected to cost about $74 million (48668).
The Texas PUC holds its open meeting Sept. 26.
The PUC will vote on the second CCN during its Oct. 11 open meeting. Chair DeAnn Walker suggested neither landowner — one of whom said he was a 101-year-old World War II veteran — needed to again make the long trip from Lubbock.
“My daughters went to [Texas] Tech [in Lubbock], so I know what that drive’s like,” Walker said.
The CCNs are needed to move 470 MW of the city of Lubbock’s load from SPP to ERCOT. (See “LP&L Lines for ERCOT Integration near Final Approval,” Texas PUC Briefs: Sept. 12, 2019.)
Oncor will be responsible for the projects’ construction before turning them over to Lubbock Power & Light, the city’s municipal utility. Both lines are scheduled to be energized by June 2021, meeting LP&L’s target date to join ERCOT.
PUC Chair DeAnn Walker
Commission Approves Rate Recovery, $328K in Fees
In other business, the commission approved $110,600 in administrative penalties:
Retailer Quest Distributors was docked $20,000 for collecting deposits without informing the commission and without adequate customer protections (49576).
Utility AEP Texas settled for $69,000 (49725) and Entergy Texas settled for $21,600 (49829) in penalties regarding annual service quality.
The PUC approved El Paso Electric’s requests for a distribution cost recovery factor, based on an annual Texas retail revenue requirement of almost $7.8 million (49395), and to implement an interim fuel refund of almost $19.2 million (49482). It also agreed to requests by Southwestern Public Service (49495) and Oncor (49594) to adjust their energy efficiency cost recovery factors.
CARMEL, Ind. — Months after FERC rejected an earlier cost allocation plan, MISO is circulating a new draft proposal that would further lower voltage thresholds but raise cost minimums on economically beneficial transmission projects.
Under the new plan, MISO would lower the voltage requirements on market efficiency projects (MEPs) from 345 kV to 100 kV, compared with the 230-kV minimum in the first filing.
However, the cost threshold is set to rise from $5 million to $25 million for regional MEPs.
For interregional MEPs with either SPP or PJM, MISO will also seek a 100-kV voltage threshold but no cost threshold.
“Perfection is not achievable, but we want to be as good as we can be,” Jesse Moser, MISO director of economic and policy planning, said during a meeting of the Regional Expansion Criteria and Benefits Working Group (RECBWG) on Thursday.
Moser said the cost requirement increase maintains a “demarcation of larger, regionally beneficial projects.” MISO’s $5 million threshold was approved by FERC in 2007.
The $25 million figure is not final and still open to suggestion, Moser said. He said a regional MEP cost threshold could also be designed to move with inflation. Going forward, MISO intends to review its MEP cost allocation method with stakeholders once every three years, he said.
“It was more about having a way to have some separation between local and regionally economic projects,” Moser said. “There’s not going to be an answer that doesn’t have some controversy and challenges.”
As in the first filing, the new plan would exempt from MISO’s competitive bidding process any MEPs needed within three years to mitigate reliability issues. The filing also preserves the elimination of a 20% postage stamp cost allocation. It additionally still seeks to add new benefit metrics for savings from the avoided costs for reliability projects and cost reductions related to the MISO-SPP transmission contract path.
But the new filing has abandoned a provision that would create a local economic project type.
FERC rejected the first cost allocation filing in June, finding it would have violated the principle of cost causation because projects proposed under the local economic transmission category would be required to demonstrate regional benefits while only being cost-shared on a local level.
The project type was meant for smaller, economically driven transmission projects between 100 and 230 kV, with 100% of costs to be allocated to the local transmission pricing zone containing the line. The projects would not only have to meet a local benefit-to-cost ratio of 1.25-to-1 or greater within their pricing zones but also be required to show the same minimum regional 1.25-to-1 ratio required of MEPs. (See MISO Mulling Next Steps on Cost Allocation Overhaul.)
“While FERC expressed appreciation for many aspects of the proposal, the commission had some concerns about the newly created local economic project category,” MISO CEO John Bear said at the RTO’s July Informational Forum.
Discord
MISO considered several possibilities before settling on the draft proposal, including lowering the voltage threshold to 100 kV for interregional MEPs only or placing projects lower than 230 kV back into the RTO’s existing “other” project category. Stakeholders have offered various opinions on the refiling, with some urging MISO to lower the interregional voltage threshold to 100 kV on both sides of the seam, and others advising that any 100-kV project be eligible for regional cost-sharing.
“This seems simpler than some of the earlier discussions,” Clean Grid Alliance’s Natalie McIntire said of the new version at the RECBWG meeting.
However, other stakeholders contended the MISO community was suffering from “cost allocation fatigue.” Some said it wasn’t clear why the RTO so dramatically altered its original proposal to include 100-kV projects instead of simply removing the lower-voltage project issues FERC raised.
Xcel Energy’s Susan Rossi characterized the proposal as a “drastic change at the last minute.”
But others said that if MISO failed to address the lower-voltage cost-sharing, it would be ignoring LS Power’s pending complaint that asks FERC to compel MISO to lower the threshold for competitively bid transmission projects from 345 kV to 100 kV. (See Complaint Seeks Bigger Role for Smaller MISO Projects.)
McIntire also said some stakeholders were forgetting that the original proposed 230-kV threshold was just the product of a compromise that several stakeholders still disagreed with because they felt it still represented too high a bar.
“I think MISO’s decision to move to 100 kV throws that compromise out the window, and that will be evident to FERC,” Entergy’s Matt Brown contended.
2020 Extension
The new MEP filing will still contain a cost allocation proposal for interregional projects with PJM, even though FERC’s rejection of MISO’s first allocation plan stood to complicate separate deadlines associated with compliance around the longstanding complaint by Northern Indiana Public Service Co. (See “Interregional Filings Also Rejected,” MISO Allocation Plan Fails on Local Project Treatment.)
FERC in mid-September granted an extension that will allow MISO to file its interregional allocation compliance by Jan. 2, 2020, instead of the original late September deadline (EL13-88). MISO was originally due to file its PJM interregional cost-sharing plan by Sept. 23, the date established in FERC orders stemming from NIPSCO’s 2013 complaint over the PJM-MISO seam that ultimately eliminated a cost minimum and lowered the voltage threshold for MISO-PJM interregional projects to 100 kV.
MISO said it needed the extra time for the MEP filing “to ensure proper coordination” with the compliance filing ordered in the NIPSCO complaint. The RTO also said that this is its first extension request since FERC rejected its proposed cost allocation changes to interregional and regional MEPs.
At a Sept. 17 meeting of the MISO board’s System Planning Committee, Director Nancy Lange urged stakeholders to keep working on a cost allocation refiling and remain undeterred by FERC’s rejection of the first proposal.
“I was happy that there was a consensus that could be filed with FERC,” Lange said of MISO’s first filing in late February.
Moser said MISO doesn’t envision using all the extension period granted in the NIPSCO complaint and hopes to make a revised cost allocation filing before Thanksgiving. MISO’s latest proposal is open to stakeholder comment through Oct. 10.
The Public Utilities Commission of Ohio last week delayed ruling on the need for two solar projects proposed by American Electric Power after the company asked for a “brief hold” to update its filings to reflect the impact of the recently approved Clean Air Act.
In its request filed Sept. 20, AEP said certain provisions of the new law — also known as House Bill 6 — convey potential benefits to the 300-MW Highland Solar and 100-MW Willowbrook facilities proposed in its long-term forecast report filed last year. The company offered very few details of how the legislation changes its proposal, citing confidentiality agreements, but did ask for a 60-day delay in proceedings.
“The new filing, if successful, would present the commission with additional options and flexibility as compared to the company’s existing proposal filed in these proceedings,” Steven Nourse, AEP’s attorney, wrote in the request. “Moreover, it is the company’s view that the new filing will ameliorate many of the concerns and objections raised by opponents in these proceedings. Such developments should be viewed as helpful regardless of whether the potential opinion and order scheduled for consideration on Wednesday would have initially rendered a positive finding or a negative finding on the need issues.”
The $170 million Clean Air Act, signed into law in July, curtails the state’s current renewable portfolio standards and tacks on monthly fees — ranging from 80 cents for residential customers to $2,400 for large industrial plants — to electricity bills, mostly for FirstEnergy Solutions’ Davis-Besse and Perry nuclear facilities. Some $20 million of the fees collected will support six solar power projects, including Highland Solar and Willowbrook, in rural areas of the state. (See Ohio Approves Nuke Subsidy.)
PUCO’s ruling on the need for two proposed AEP solar projects didn’t come Thursday, as anticipated. | Solar Energy Industries Association
AEP submitted documents last year seeking cost recovery under the state’s renewable generation rider (RGR) for 500 MW of wind and the Highland and Willowbrook solar projects.
PUCO said last year that it would first determine the need for the projects before approving cost recovery mechanisms. On Sept. 19, the commission indicated it would announce a decision in the first half of the proceedings at its Thursday meeting; however, the agenda item was subsequently withdrawn. PUCO spokesperson Matt Schilling said the commission gave no reason for the change, telling RTO Insider that “it’s not uncommon to pull cases from the agenda to allow for more time to consider.”
Protesters — including the Ohio Consumers’ Counsel, Direct Energy, IGS and IGS Solar — urged the commission to rule in the case anyway, calling the bill irrelevant to “the statutory issue of whether Ohio utility consumers need electricity from the proposed solar plants.” Kroger and the Ohio Coal Association also opposed AEP’s request.
“HB 6 did not alter Ohio law that strictly limits a utility’s ability to seek PUCO approval of customer-funded subsidies for new generation plants that it proposes to own or operate,” the protesters wrote in a joint filing. “This separate funding for a monopoly utility generation project (including solar) can only be approved by the PUCO if the utility can show, among other things, that utility consumers need the electricity from the proposed power plants. As has been shown in this case, Ohio consumers don’t need electricity from AEP’s proposed plants, as the competitive market provides more than an adequate supply of power.”
The companies further allege that AEP doesn’t need a second revenue stream on top of the money afforded to the projects via HB 6.
“An outcome that could actually ‘ameliorate many of the concerns and objections raised by opponents in these proceedings,’ as AEP asserts, would be for AEP to withdraw its proposal and to develop the contested renewable projects through a separate affiliate,” the companies wrote. “Of course, AEP is free to undertake that endeavor outside this proceeding, without a delay in the PUCO’s decision.”
Scott Blake, an AEP spokesperson, told RTO Insider on Monday that concerns about the company collecting twice on the same projects presuppose the commission would accept the proposals as filed — an unlikely scenario given the impacts of HB 6 and the points raised by protesters within the proceeding.
“The HB 6 credit would also be factored in to any customer charge,” he said. “Under the proposal, we would purchase power at a fixed cost per megawatt-hour from the developer of the project. The credit from HB 6 would be included in the cost and used to calculate the customer portion.”
