Page 1333 – RTO Insider

September 7, 2018

Wood, Brownell: Unaware of Press Ban When OK’d NEPOOL

By Rich Heidorn Jr.

WASHINGTON — The FERC commissioners who approved the New England Power Pool as ISO-NE’s stakeholder body in 2004 were unaware at the time that NEPOOL barred the public and press from its meetings.

Former FERC chair Pat Wood | © *RTO Insider*

Former FERC Chairman Pat Wood III and former Commissioner Nora Mead Brownell said in interviews they would have insisted on allowing press access had they known of the ban when they approved ISO-NE as an RTO in March 2004 (RT04-2, ER04-116, et al.).

NEPOOL FERC Pat Wood press ban — Former FERC commissioner Joseph Kelliher | © *RTO Insider*

Former Commissioner Joseph T. Kelliher, the third vote on the order, declined to comment but did not dispute Wood’s and Brownell’s accounts. Former Commissioner Suedeen Kelly did not take part in the order.

FERC commissioners also were unaware of the ban in 2008 when they approved Order 719 (RM07-19, AD07-7), according to former Chairman Jon Wellinghoff. The order set requirements for the responsiveness of RTOs and ISOs “to their customers and other stakeholders, and ultimately to the consumers who benefit from and pay for electricity services.”

“I do not recall this ever coming up when I was at FERC, and I do not remember the issue in 719,” Wellinghoff said via email. “Stakeholder meetings should absolutely be open to all, including the press.”

The other former commissioners who joined Wellinghoff and then-Chairman Kelliher in voting on Order 719 — Kelly, Marc Spitzer and Philip Moeller — did not respond to requests for comment last week.

New England is the only one of seven U.S. regions served by RTOs or ISOs where the press and public are prohibited from attending stakeholder meetings.

On Aug. 31, RTO Insider filed a complaint asking FERC to overturn NEPOOL’s press ban or terminate the group’s role and direct ISO-NE to adopt an open stakeholder process like those used by other RTOs. The Section 206 complaint (EL18-196) came two weeks after NEPOOL submitted a proposal to FERC seeking to codify an unwritten policy of banning news reporters and the public from attending the group’s stakeholder meetings. (See RTO Insider Seeks Repeal of NEPOOL Press Ban.)

Media Family

Wood, attending an industry conference in D.C. on Wednesday, told RTO Insider that it was inconceivable that he and Brownell would have approved NEPOOL’s press ban. Brownell’s family owned the Erie Times-News in Pennsylvania until 2015.

“If Nora Brownell signed off on that — her being from a media family — I’m sure it did not come up,” Wood said. “Nora would be kind of the canary in the mine on anything [dealing with media]. Any time that you came up with transparency stuff, she kind of had my proxy.”

Brownell, now a board member of National Grid, confirmed Wood’s recollection in a phone interview.

“Pat is absolutely right,” Brownell said. “I did not know and would never have approved. Shame on me if it was out in the open, but it couldn’t have been obvious. I remember expressing concerns over SPP’s stakeholder process.

“I just can’t imagine why the meetings have to be closed,” she continued. “I think it is critically important for people to have confidence in the outcome of what is being recommended and what the RTO/ISO ultimately adopts. … If the consumer is paying a bill [for RTO actions], as they are, directly or indirectly, they have a right to have access to the process.”

Wood said ensuring stakeholder meetings are open to the public and press is essential. “The very first step of transparency is doing the sunshine,” he said. “You know, most things done in the dark do start to smell.”

Two Dockets

RTO Insider also filed its complaint as a protest in the docket NEPOOL opened in August (ER18-2208). Comments in the NEPOOL docket are due Sept. 14.

The commission set a Sept. 20 deadline for comments in the docket opened by RTO Insider. NEPOOL on Thursday requested that deadline be extended seven business days to Oct. 1 “to align the timing of any appropriate NEPOOL response to pleadings submitted on these same issues in Docket No. ER18-2208.” RTO Insider responded that it did not oppose the request.

The 2004 order approved by the three commissioners, all Republicans, includes three references to “transparency” but no mention of NEPOOL’s then unwritten press ban. It noted, for example, the promise of ISO-NE and the New England transmission owners that the revised ISO-NE board procedures “would promote greater transparency by requiring board agendas to be posted, the opportunity for stakeholders to provide written input on agenda items, and for reports on board meeting actions, and proposed revisions to market rules or other tariff provisions.”

NEPOOL moved to codify its unwritten ban on press and public attendance at stakeholder meetings after RTO Insider reporter Michael Kuser, who lives in Vermont, applied for membership in NEPOOL’s Participants Committee as an end-user customer in March. NEPOOL’s proposed amendments to the NEPOOL Agreement would add a definition of “press” and bar anyone working as a journalist from becoming a NEPOOL member or alternate for a participant.

September 7, 2018

WAPA to Divide RC Services Between CAISO, SPP

By Amanda Durish Cook

Most transmission operators in the Western Interconnection are faced with choosing either CAISO or SPP to provide reliability coordinator (RC) services after Peak Reliability winds down its operations in late 2019. The Western Area Power Administration will go with both.

WAPA said Tuesday that it has selected CAISO’s new RC arm to serve its Sierra Nevada region after Peak’s closure, while its Rocky Mountain (RM), Desert Southwest (DSW) and Upper Great Plains (UGP) regions will use SPP’s RC services. (See Peak Reliability to Wind Down Operations.)

wapa caiso spp reliability coordinator — | WECC

The Sierra Nevada region already functions as a transmission operator within the Balancing Authority of Northern California, which in July was the first BA in the West to announce it would sign up for CAISO’s RC services. (See CAISO Board OKs RC Rate Plan, RMR Change.)

The RM, DSW and UGP regions contain the Western Area Colorado Missouri, Western Area Lower Colorado and Western Area Upper Great Plains-West BA areas, respectively.

WAPA has in recent years been consolidating functions among its Interior West BAAs and said keeping those regions under one RC would avoid introducing “operational and compliance complexities.” It also noted that UGP is currently a transmission-owning member of SPP and is “fully engaged” in the RTO’s stakeholder process.

WAPA said the transition is dependent on SPP and CAISO becoming certified by NERC and the Western Electricity Coordinating Council as RC providers in the Western Interconnection. (See Sept. 4 Key Date for Potential Western RC Providers.)

In a Sept. 4 memo signed by Chief Operating Officer Kevin Howard, WAPA said the move could produce more benefits than Peak’s services: “Initial analyses have determined that SPP and CAISO should be able to provide reliable RC services comparable or superior to the services provided by Peak, and the costs for such services are expected to be lower than Peak’s.”

SPP will initially cap the charge for RC services at 5.5 cents/MWh, and CAISO estimates its services will cost anywhere from 3.4 to 4.1 cents/MWh depending on total load, according to WAPA.

WAPA’s regional offices promised Howard performance check-ins during and after the transition. “Given the dynamic nature of the situation and the need for ongoing analysis, each region will keep you informed of their progress. If any significant issues arise, we will bring those matters to your attention,” WAPA said. In a separate statement, Howard promised to work with neighboring utilities “to ensure an orderly transition to the SPP and CAISO RCs.”

WAPA said its switch to SPP could contribute to the creation of an organized Western market: “Participating in the SPP RC will preserve and facilitate options for the potential development of an organized electricity market in the West.”

At press time, neither CAISO nor SPP had provided a full list of customers taking their RC services. Representatives from both grid operators have said that they would not necessarily time announcements to Sept. 4 — the unofficial deadline NERC and WECC placed on Western BAs and transmission operators to declare their RCs. CAISO said it would only announce customers only as they sign agreements. In addition to BANC, Idaho Power and PacifiCorp have also committed to CAISO.

“At this time, announcements of entities committing to ISO RC services are being coordinated by the individual entities … since each entity has a different approval process and varying timelines, based on their specific business decisions and operations. We plan to share our customer list as agreements are signed,” CAISO spokesperson Anne Gonzales said in an email to RTO Insider.

WECC last week told RTO Insider that it will provide a more complete list of Western Interconnection RC selections at its annual meeting on Sept. 11.

September 7, 2018

CAISO Eases Rules for Energy Storage, DERs

CAISO moved to update its rules Wednesday to make it easier for energy storage and distributed energy resources (ESDER) to participate efficiently in its markets.

The ISO’s Board of Governors adopted the ESDER Phase 3 Tariff changes at its monthly meeting in Folsom.

Among the technical updates were new bidding and real-time dispatch options for demand response resources. Stakeholders had expressed concern that many resources couldn’t respond to ISO dispatches in real time because they didn’t have enough notice.

Currently “they only have two-and-a-half minutes of notification time to respond to that dispatch,” which isn’t feasible for many, Greg Cook, CAISO’s director of market and infrastructure policy, told the board.

The new bidding options give DR resources more time to respond by letting them provide real-time market bids as an hourly block or a 15-minute dispatch resource. (See CAISO Updates ESDER Phase 3 Proposal.)

Another provision adopted Wednesday simplifies rules for aggregated DR resources.

CAISO currently requires DR resource aggregation to be contained in a single load-serving entity with a 100-kW minimum. That minimum threshold has been a problem, especially with the proliferation of community choice aggregators, Cook told the board. The new rules will remove those requirements.

CAISO adopted rules to ease the integration of distributed energy resources to California’s grid, including electric-vehicle battery storage. | *U.S. Air Force/Sarah Corrice*

Other changes will make it easier for behind-the-meter battery storage to absorb excess electricity and return it to the grid, and will allow for electric vehicles’ charging performance to be measured separately of their host facilities.

The changes are detailed in a memo to the board. The revisions must still be approved by FERC.

— Hudson Sangree

September 6, 2018

MISO Evaluating 12 Proposals for 2nd Competitive Project

MISO announced it has received 12 complete proposals from nine developers seeking to construct and own the Hartburg-Sabine Junction 500-kV project, the RTO’s second competitively bid transmission expansion.

MISO had been screening proposals for the Hartburg-Sabine project since it closed the request for proposals window on July 20. As a practice, the RTO does not reveal which developers may have submitted incomplete proposals. (See “MISO Reviewing Hartburg-Sabine Proposals,” MISO Informational Forum Briefs: July 24, 2018.)

miso competitive transmission hartburg-sabine junction — | *MISO*

MISO said it only reviewed the proposals for completeness and has not vetted the content of the proposals.

“With the final list of complete proposals, we now begin our competitive evaluation phase, which is outlined in the MISO Tariff,” Aubrey Johnson, MISO executive director for system planning and competitive transmission, said in a statement.

MISO said it expects to announce the selected developer by Dec. 31.

The completed proposals come from Avangrid Networks; EasTex TransCo; GridLiance Heartland (with Cleco Energy); Midwest Power Transmission Arkansas; NextEra Energy Transmission Midwest; Transource Energy; Verdant Plains Electric; Xcel Energy Transmission Development Co.; and a joint bid from ITC Midcontinent Development, Hunt Transmission Services and Texas Infrastructure Holdings. MISO did not reveal which developers submitted multiple proposals.

The estimated $129-million, 500-kV line and substation project, intended to alleviate system congestion in eastern Texas, is expected to be in service by 2023. The RTO opened the submittal window in early February after MISO’s Board of Directors approved the project as part of MISO’s 2017 Transmission Expansion Plan. (See MISO Board Approves Texas Competitive Tx Project.)

— Amanda Durish Cook

September 6, 2018

ERCOT Monitor Relieved by End of Summer; Concerned for 2019

By Rich Heidorn Jr.

WASHINGTON — ERCOT’s energy-only market survived the summer of 2018 with surprisingly modest prices and no generation shortfalls, but 2019 may be a tougher challenge, the RTO’s market monitor said Wednesday.

ERCOT Market Monitor Beth Garza AWEA — Garza | © *RTO Insider*

Beth Garza, director of ERCOT’s independent market monitoring unit, credited better-than-expected generation performance and an early summer system peak that took advantage of above-normal wind for the positive results.

Coal plant retirements reduced ERCOT’s installed reserve margin to below 11%, by far the lowest in the market’s history, leading on-peak forward prices for August to rise as high as $250/MWh. But although real-time prices briefly peaked at more than $2,000/MWh, average real-time prices in July were about $50/MWh and about $38/MWh in August, Garza said.

She acknowledged one competitive retailer was forced to surrender tens of thousands of customers to the provider of last resort when it was unable to meet collateral requirements in early summer. But disruptions were minimal, Garza told the inaugural Future Power Markets Summit, sponsored by the American Wind Energy Association and several other trade groups.

“There was certainly a high level of awareness across the market, across the state legislature, across the regulators [of the tight market], and with that high level of awareness I think came a high level of preparedness, certainly from the generators,” she said. “As it turned out … generator availability was higher than normal this summer. We also had — I think because of the timing when our system peak was — we had the … contribution from higher-than-expected wind generation this summer.”

ERCOT recorded its summer peak at 73,259 MW on July 19, while loads in August — normally the peak month — never exceeded 71,110 MW. The 2018 Long-Term Demand and Energy Forecast projected a 2018 summer peak of 72,974 MW.

Garza said generators responded to the potential for prices up to ERCOT’s $9,000/MWh cap. “Having that opportunity for our energy price to rise to very high levels creates that natural incentive for availability at the time when we need generation resources the most.”

But it won’t get any easier for ERCOT in 2019, Garza said, as its load — unlike that of other markets — continues to grow. In addition, two announced coal plant retirements will reduce capacity by more than 1 GW by the end of the year. The system has added no significant thermal capacity although there have been wind and solar additions.

“So, I think we’ll go into 2019 in a very similar state as we went through this summer,” Garza said. “And that raises all kinds of questions about outcomes … if generation availability [is] lower than expected, if wind [is] average, if load [is] a little higher.”

“The good part about this job is I get to monitor the market,” she laughed. “I don’t have to forecast the market.”

In addition to AWEA, the summit was sponsored by the American Council on Renewable Energy, the Solar Energy Industries Association, the American Public Power Association, the National Rural Electric Cooperative Association, the Large Public Power Council and the Energy Systems Integration Group, a non-profit educational association for engineers, researchers, technologists and policymakers.

[Editor’s Note: RTO Insider will have additional coverage from the conference later in Tuesday’s newsletter.]

September 5, 2018

ISO-NE Prices Top $2,400/MWh in Labor Day Heat Wave

By Michael Kuser

Hot and humid weather some 5 degrees higher than forecast and 1,600 MW of unplanned generator outages sent ISO-NE power prices soaring last Monday and led the RTO to purchase emergency energy from New York and Canada.

Temperatures hit 96 degrees Fahrenheit in Boston on Sept. 3 with a dew point of 73 as load peaked at 22,956 MW, almost 2,400 MW above the initial forecast of 20,590 MW. The bulk power system saw a five-minute peak of 23,106 MW at 5:50 p.m., according to a Sept. 7 article published on the RTO’s website.

Real-time energy prices rose to $2,454.57/MWh between 4 and 5 p.m., and reserve prices peaked at about $2,500/MWh at times between 3 and 6 p.m.

Similar weather conditions, with a heat index at or near 100, were forecast for the following Tuesday. Load peaked at about 23,000 MW, in line with forecasts, and no alerts were issued. Boston peaked at 85 degrees.

When the dew point is above 70, every 1-degree increase can cause load to rise by about 500 MW, with rising temperatures causing similar effects on load.

The RTO implemented Master/Local Control Center Procedure No. 2 (M/LCC 2) at 3:15 p.m. Monday, declaring an Abnormal Conditions Alert and directing generators and transmission owners to stop or postpone any maintenance activities that could jeopardize system reliability.

Fifteen minutes later, the RTO implemented Operating Procedure 4, Actions 1 and 2. Action 1 declares a Power Caution, saying available capacity resources are insufficient to meet anticipated demand plus operating reserve requirements. Action 1 also allows the RTO to begin depletion of 30-minute operating reserves. Action 2 declares a Level 1 energy emergency alert.

At 4 p.m., system operators issued a Power Watch and implemented two other actions of OP4, asking market participants to reduce energy consumption at their own facilities and arranging for purchase of emergency capacity and energy from neighboring systems.

All of the alerts were lifted by 9 p.m.

ISO-NE spokeswoman Marcia Blomberg told RTO Insider that the Labor Day heat resulted in “higher-than-expected demand, as well as some generator outages” and that the RTO purchased emergency power from New Brunswick and New York for a short time. “While we implemented Action 4 of OP4, declaring a Power Watch, we didn’t issue a request for voluntary conservation. We were monitoring the system and could have issued an appeal if conditions had deteriorated.

Emergency purchases from NYISO totaled 251 MW from 5 to 5:30 p.m. and 100 MW in the following half-hour, while emergency purchases from New Brunswick totaled 150 MW from 4:20 to 5:14 p.m. and 229 MW from then until 6 p.m.

“However, conditions improved rapidly as demand began to decline in the late afternoon and offline generators were able to come online quickly,” Blomberg added.

ISO-NE’s operations shift supervisor or one of its six local control center system operators can declare an abnormal condition under several scenarios, including a forecasted or actual deficiency of operating reserves. The local control centers, which are run by transmission owners, are generally responsible for transmission facilities rated 69 kV and below.

The RTO reported “underperforming resources will be penalized at a rate of $2,000/MWh for failing to meet their obligation during energy shortfalls, while resources that overperform (including resources with no obligation) will receive $2,000/MWh of additional revenue.”

The performance payment rate will increase to $5,455/MWh over the next six years.

September 5, 2018

PJM Sets Terms for Using IMM’s Cost Calculator

By Rory D. Sweeney

opportunity cost calculator IMM PJM — Stu Bresler, PJM’s senior vice president of operations and markets. | © *RTO Insider*

Responding to stakeholder demands to resolve a yearlong dispute, PJM’s Stu Bresler has sent a letter outlining his requirements for accepting the Independent Market Monitor’s opportunity cost calculator.

The public pronouncement of PJM’s terms was unexpected but welcomed. “I’m surprised that PJM has apparently decided to negotiate this publicly,” Monitor Joe Bowring said. “We will respond.” Bowring declined to address whether PJM’s terms were acceptable and detailed enough.

For more than a year, PJM and its Monitor have been unable to agree on a single calculator for opportunity costs included in generation offers. PJM argues that FERC Order 719, issued in October 2010, allows the Monitor to provide input on cost determinations but that “PJM retains the ultimate decision-making authority.” From then until “the latter part of 2016,” both calculators produced consistent results, Bresler said in his letter, but have since diverged substantially.

PJM says it can’t endorse the Monitor’s calculator until staff understand how and why it produces different results. For that reason, PJM announced in August it would only accept opportunity cost calculations using its calculator.

The Monitor argues that it has continued to enhance its calculator while PJM hasn’t changed its methodology since 2010.

PJM staff have asked to understand the calculator’s inner workings, but Bowring has been reluctant to fully throw back the curtain, arguing that PJM staff haven’t specifically detailed their requests and that the underlying computer code is proprietary intellectual property.

Generators say the dispute has left them in a bind, fearing a referral to FERC enforcement for using an unapproved number.

At the Aug. 23 Markets and Reliability Committee meeting, generators attempted to force a resolution by threatening Tariff revisions that would require PJM to accept the Monitor’s calculator. (See Stakeholder Proposal Aimed at Ending PJM-IMM Dispute.)

Bresler’s letter details three requests to the Monitor:

the design requirement specification documents for the Monitor’s calculator, including descriptions of steps taken to calculate adders and accompanying mathematical formulas.
alternatively, the calculator’s output from pre-defined sample inputs and parameters so PJM can compare the results with its calculator’s output using the same inputs.
a commitment to notify PJM of any changes to the calculator and to rerun the comparative analyses afterward.

Bresler, PJM’s senior vice president of operations and markets, shot down an earlier suggestion from Bowring that they allow a third-party auditor to compare the calculators, saying it was less efficient and more expensive than his solutions. He gave Bowring a Sept. 10 deadline to respond to the proposal.

The Members Committee is set to vote on the proposed Tariff revisions on Sept. 27, barring an agreement before then.

September 3, 2018January 3, 2024

FERC Lowers ROE for Segmented Pioneer Transmission Project

By Amanda Durish Cook

FERC last week approved a reduced return on equity for Pioneer Transmission’s portion of a recently completed 765-kV line in Indiana.

The commission’s Aug. 30 order reduces Pioneer’s ROE to 10.82% from the 12.54% approved in 2009, which included a 150-basis-point (bp) adder as a new interregional project (ER18-1159).

Pioneer, a joint venture of American Electric Power and Duke Energy, will use the ROE in its formula rates to recover costs for it and Northern Indiana Public Service Co.’s 65-mile, 765-kV Greentown-to-Reynolds line.

Pioneer in March proposed to adopt MISO’s 10.32% base ROE for transmission owners, with a 50-bp adder for RTO participation and the 150-bp adder for new transmission.

FERC allowed the base ROE and adder for RTO participation but denied the 150-bp adder because the current project does not include PJM.

Regional Processes

The Pioneer Project was intended as a single, $1 billion, 240-mile project across MISO and PJM to address “a critical shortage of high voltage transmission” in Indiana and help transport new wind generation from the state’s southwest to its central and northern regions.

At the time the project was proposed a decade ago, the MISO-PJM interregional planning process did not have “a tariff mechanism in place for evaluating and approving an interregional project such as the Pioneer Project that provided benefits to both RTOs,” according to Pioneer.

The company said it broke the project into smaller segments to be reviewed under PJM’s and MISO’s separate regional processes after encountering difficulties getting the RTOs to approve the line as an interregional project.

Pioneer and NIPSCO took up a $347 million Greentown-Reynolds line, which was approved in MISO’s 2011 multi-value project portfolio. This June, the MISO Board of Directors voted to add Pioneer as a MISO TO, and Pioneer has handed over operational control of the completed line.

FERC said the 150-bp adder would not go into effect “unless and until the project is approved by the regional transmission planning processes of [PJM and MISO] and there is a commission-approved cost allocation methodology in place.”

FERC said because the line had been broken into regional segments, it could not meet the condition that the Pioneer Project be included in both the PJM and MISO transmission plans. Pioneer had argued that the condition was no longer applicable or should be waived because the project “continues to be a large-scale transmission project and the first 765-kV transmission facilities in MISO’s service area.”

In its Aug. 30 order, FERC said Pioneer was free to apply for the new transmission incentive again once it could satisfy the requirement.

“Our denial of the 150-basis-point ROE adder is without prejudice. If Pioneer satisfies the commission’s previously stated conditions, then Pioneer may make a Section 205 filing to seek to prospectively implement the full 150-basis-point ROE incentive that the commission previously granted,” FERC said, adding that it “continues to value transmission rate incentives as a tool to encourage investment in new transmission.”

“In that vein, we encourage Pioneer to continue its efforts to complete the Pioneer Project,” the commission said.

September 3, 2018

NYISO Stakeholders OK Change on Reliability Margins

NYISO’s Management Committee agreed Wednesday to relax its minimum 20-MW constraint reliability margin value in its initiative to price transmission constraints on 115-kV facilities.

The ISO’s Tariff currently requires at least 20 MW be set for any non-zero constraint reliability margin value used in the day-ahead and real-time markets

David Edelson, NYISO manager of operations performance and analysis, noted as an example that a 20-MW CRM equals 13% of the rating for 115-kV lines with post-contingency limits of 150 MW, limiting them to 130 MW in dispatch.

nyiso constraint reliability margin — 115-kV transmission line | *Exponential Engineering*

By contrast, for a 345-kV circuit with a 1,550-MW post-contingency rating, a 20-MW CRM represents only about 1% of the line rating.

Edelson said the ISO wants to limit CRMs to no more than 10% of a facility’s rating to allow for the continued pricing of transmission constraints on lower-voltage lines.

NYISO wants to change the Tariff to permit CRMs of less than 20 MW until it can implement enhancements under its constraint-specific transmission shortage pricing project. The ISO said the timing of that project is subject to stakeholders’ prioritization and scheduling.

The ISO would publish on its website a list of transmission facilities and interfaces assigned a CRM other than 20 MW.

The rule change will be presented to the Board of Directors for approval in September. The committee approved the proposal unanimously by a show of hands.

— Rich Heidorn Jr.

September 3, 2018

PUCT Reduces Rates for AEP, Others on Income Tax Cut

The Public Utility Commission of Texas last week approved a settlement agreement reducing AEP Texas’ annual revenue requirement (ARR) by $27 million, largely to reflect last year’s federal income tax legislation (Docket No. 48222).

AEP Texas agreed to reduce the revenue requirement in its distribution-cost recovery factors (DCRFs) to $55.6 million, with AEP Central’s ARR cut by $21.2 million and AEP North’s by $5.8 million.

Commission staff, the Alliance for Retail Markets (ARM) and several cities served by AEP signed on to the agreement. Texas Industrial Energy Consumers and the Office of Public Utility Counsel did not sign the agreement, but they are not opposed to it.

The changes, effective Sept. 1, reflect the reduction in the federal income tax rate from 35% to 21%.

The commissioners approved similar settlement agreements filed by CenterPoint Energy (Docket 48226) and Oncor (Docket 48231).

CenterPoint, which requested an ARR of $82.6 million effective Sept. 1, agreed to $42.4 million, rising to $63.7 million in September 2019, reflecting other tax changes.

Oncor agreed to a DCRF based on an ARR of $15.2 million, also effective Sept. 1. The utility had requested an ARR of $19 million.

ercot puct aep income tax cut — Left to right: Commissioners Shelly Botkin, DeAnn Walker and Arthur D’Andrea share their thoughts | *Admin Monitor*

PUC Chair DeAnn Walker expressed reservations with the AEP settlement during the commission’s Aug. 30 open meeting, noting that state statutes require DCRF adjustments “be applied by the electric utility on a systemwide basis.” She pointed out that the commission’s 2016 approval of the merger of AEP Texas Central and AEP Texas North into AEP Texas required the company to maintain separate divisions with separate rates, riders and tariffs (Docket 46050).

“Systemwide rates would require a rate that is in effect for the entire AEP Texas system,” Walker said, pointing to the settlement agreement’s separate DCRF rates for AEP’s Central and Northern divisions.

AEP legal counsel Melissa Gage said the company’s interpretation of the law “wasn’t intended to mean systemwide in terms of AEP Texas as a whole, but on a division basis.”

Steve Davis, representing ARM, agreed with AEP’s interpretation and said the case posed “an odd situation.”

“It’s kind of hard to make it all fit correctly,” he said. “You have the statutory language, then you have the commission’s order in the merger case, which talks about separate rates” until some point in the future, he said. “Maybe there’s a path in future DCRF cases to follow to get to where you want to go.”

The commissioners saved further discussion on the proceeding for their closed session, which apparently eased Walker’s concerns. “I’m fine with moving forward,” she said afterward.

Commissioner Arthur D’Andrea pointed out the DCRF order is temporary, as AEP Texas is scheduled to file a full rate case in May. AEP Texas’ 8.96% rate of return last year was below that authorized by the commission during its last rate proceeding, according to the company’s 2017 earnings monitoring report.

Hearings Set for AEP Texas Legal Cases

AEP Texas also figured in two orders on the commission’s consent agenda.

The PUC first approved a procedural schedule for AEP’s bid to recover about $415 million in system restoration costs for 2017’s Hurricane Harvey. The schedule includes a Nov. 13-14 hearing before an administrative law judge (Docket 48577). AEP has proposed using a portion of its excess deferred taxes created by last year’s federal tax legislation to reduce the system restoration costs it will recover from consumers.

The commission also approved a procedural schedule in the company’s dispute with Rio Grande Electric Cooperative over which utility will serve certain customers in a Uvalde subdivision (Docket 47186).

An ALJ ruled on Rio Grande’s request for a cease-and-desist order in June, finding that AEP lacked the authority to serve some, but not all, of the customers in the disputed area. The case is of interest to retailers because Rio Grande’s service territory is not open to retail competition while competition was introduced in AEP’s footprint in 2002.

The procedural schedule for the second phase of the case includes a hearing to be held Oct. 31.

Commissioners Grant CCN to Tx Project — and Pole

The commission granted AEP Texas and Brazos Electric Power Cooperative a certificate of convenience and necessity for a jointly owned transmission line after the parties agreed to name a pole marking the midway point between them (Docket 47691).

Under the CCN, the two companies will each construct and operate half of the 138-kV transmission line southeast of the Texas Panhandle. The 20-mile line will connect Brazos’ Gyp switching station to AEP’s expanded Benjamin substation.

The utilities have yet to determine which one will own the pole, which represents a new interconnection point between the two. After jokingly offering to paint the pole two different colors, the utilities’ legal counsel took advantage of free time during the commissioners’ executive session to agree on a name for the pole: Gyp-to-Benjamin Terminus.

“We thought long and hard about the name but came up with what’s written there,” AEP’s Jerry Huerta said, as the commissioners stared quizzically at their documents.

The project will cost an estimated $20 million. No word on how much the terminus pole will cost.

Entergy Texas Gets OK for 230-kV Line

The commissioners also granted a CCN to Entergy Texas for a proposed 230-kV line north of Houston (Docket 47462). The line is one element of a MISO western region project identified in its 2015 Transmission Expansion Plan that will provide economic benefits to MISO South. It will be between 33 and 45 miles long and cost up to $140 million, depending on the final route. Entergy plans to energize the line in June 2020.

October Workshop to Review ERCOT’s Summer Performance

The commission will hold a workshop in late October to review ERCOT’s market performance this summer (Project 48551). The workshop is intended to be an open meeting, with all three commissioners attending.

The commission in March directed ERCOT to exclude reliability unit commitments from online reserve capacity used in the calculation of the operating reserve demand curve price adder. It said at the time that further market design changes would be examined after an analysis of the market’s summer performance.

Luminant Accepts $1.1M Penalty for 2015 Violations

The PUC on Aug. 17 approved a settlement agreement with Luminant, in which the generation company agreed to pay a $1.1 million administrative penalty for violations in 2015. Luminant was fined for telemetering a down ramp rate of zero for 15 quick-start units when they were operating near full capacity for four days that summer, preventing ERCOT from dispatching the units down.

— Tom Kleckner