Page 1198 – RTO Insider

March 9, 2018December 13, 2023

Texas PUC OKs Sempra-Oncor Deal, LP&L Transfer

By Tom Kleckner

AUSTIN, Texas — Texas regulators quickly dispensed with two multiyear cases before them Thursday, clearing the way for Sempra Energy to acquire Oncor and for Lubbock Power & Light to migrate from SPP to ERCOT.

The Public Utility Commission made only minor revisions to the Sempra-Oncor order and added several tweaks to the LP&L order, spending more time during its open meeting congratulating those involved in the two proceedings.

PUC Chair DeAnn Walker recalled attending the National Association of Regulatory Utility Commissioners winter meetings, where she heard a financial analyst say, “What’s best for us is when a utility commission speaks, they stick to what they have asked.”

“This commission and the intervenors spoke at least twice, maybe three times in the preliminary order, on what their expectations were to get things done,” Walker said, referring to the Sempra-Oncor settlement agreement with all intervenors in its application (Docket No. 47675). “Sempra listened to that and came forward and did that. I think it speaks for y’all and it speaks for the commission that we have now stuck to what we said we were asking for.”

Oncor ‘Saves Best for Last’

The PUC’s approval of Sempra’s acquisition of Energy Future Holdings’ 80.03% interest in Oncor all but seals the California-based company’s pursuit of Texas’ largest electric utility. Sempra has already received approval from FERC and the U.S. Bankruptcy Court for the District of Delaware, where EFH filed for bankruptcy in 2014. (See Bankruptcy Court OKs Sempra-Oncor Deal.)

Sempra has succeeded where others failed. Its $9.45 billion all-cash bid for Oncor caught Warren Buffett’s Berkshire Hathaway Energy off-guard in August, while Hunt Consolidated and NextEra Energy saw their acquisition attempts fall apart before the PUC.

“We clearly saved the best for last with Sempra,” Oncor spokesman Geoff Bailey told RTO Insider outside the PUC’s hearing room. “We’ve got a four-year process behind us, and we’re ready to move forward into the future. I think I speak for all Oncor employees when I say it’s an exciting day for the company. We’re excited to get everything behind us.”

“We appreciate the commission’s support throughout this long, four-year process to find a new majority owner for Oncor,” Oncor CEO Bob Shapard said in a statement. “We believe this is an excellent outcome for our company, our customers and our employees. Sempra Energy is a well-run company, and we believe they will be a strong, stable majority owner for Oncor and an excellent partner for Texas.”

Headquartered in San Diego, Sempra is a Fortune 500 company with 16,000 employees and about 32 million consumers around the world. The company earned more than $11 billion in revenue last year.

Oncor operates the largest distribution and transmission system in Texas, delivering power to more than 3.5 million homes and businesses while operating more than 134,000 miles of lines.

Sempra CEO Debra Reed said she was pleased the commission found the transaction to be in the public interest.

“Sempra Energy is committed to being a good partner for the state and is supportive of Oncor’s mission to provide Texans with safe, reliable and affordable electric service,” she said.

In reaching an agreement with various consumer groups before the PUC, Sempra agreed to employ strict ring-fencing measures that include an independent board of directors, to extinguish EFH’s debt and to pass tax savings on to Oncor customers. (See Sempra, Oncor Reach Agreement with Texas Intervenors.)

Shapard and General Counsel Allen Nye will both retain positions on the post-acquisition board of directors as chairman and CEO, respectively.

“You can’t get your fancy pants on now that you are going to be CEO and think you’re too big for us,” Walker told Nye. “You have to come visit us and see us from time to time. I know you have a company to run, but this is a regulated industry, and guess what we do.”

“I‘ve had the distinct pleasure of being here almost 25 years now, and I have no intention of going away,” Nye responded. “This place means the world to me. You can get used to seeing me.”

Sempra will fund the purchase through of combination of about 65% equity and 35% long-term debt. It said in a letter to the PUC that it intends to acquire Oncor Management Investment’s 0.22% interest in Oncor when or after the transaction closes.

Should Sempra pursue the remaining 19.75% interest in Oncor held by Texas Transmission Investment, it would need to secure the commission’s approval and adhere to the same regulatory commitments to which it has already agreed.

Sempra said that the transaction “remains subject to certain customary closing conditions” and that it expects to wrap it up “shortly.”

Bailey promised that Oncor’s customers “will see no changes and not be impacted by this transaction.”

LP&L Welcomed into ERCOT

“Welcome to ERCOT, hopefully,” Walker said to Lubbock Mayor Dan Pope after the commission approved a draft order allowing the city’s utility to join the ISO (Docket No. 47576). “It is by far the best ISO/RTO in the United States.”

Speaking to the media minutes later, Pope agreed with Walker as he called it a “big day.”

“In some ways, this is pretty historic,” he said, noting Lubbock is the largest municipality to join ERCOT in almost 25 years. Pope said the key reason the city decided to join the ISO’s open-access market is because “it is the most efficient, competitive energy grid in the country, and it provides the most choice.”

LP&L announced in 2015 that it intended to move about 70% of its load from SPP to ERCOT. The city’s power needs are currently met through two long-term contracts with Southwestern Public Service, one of which expires in June 2021, LP&L’s target date to join ERCOT.

LP&L has agreed to pay $22 million annually over five years to compensate ERCOT’s transmission customers for additional infrastructure costs and to make a one-time $24 million payment to SPS for previous infrastructure costs. (See PUCT Nears Approval on LP&L Move to ERCOT.)

The PUC directed LP&L to work with Sharyland Utilities — which has proposed a $247.5 million, 345-kV project that overlaps with the facilities necessary to integrate Lubbock’s load into ERCOT — to coordinate their responsibility for respective parts of the system. Lubbock must also determine how to extend customer choice to all its customers.

Pope said the city and LP&L are already working on interconnecting with ERCOT and giving all its customers a competitive option. “Ideally, all of our citizens have to have that ability to opt in,” he said.

Speaking for SPP, General Counsel Paul Suskie said the RTO recognizes that membership and participation is voluntary.

“Entities have the ability to make decisions they believe are best for their organization and their customers, which Lubbock has done in this situation,” Suskie said.

March 8, 2018

PGE, BPA Sign 5-Year Hydro PPAs

By Robert Mullin

Portland General Electric (PGE) and the Bonneville Power Administration said Wednesday they have signed two agreements that will help PGE avert a generation shortage after it shuts down its coal-fired Boardman Generating Station in 2020.

PGE in 2010 agreed to close the 550-MW Boardman plant to avoid investing the $470 million in pollution controls needed to keep Oregon’s last coal-fired generator running until its original 2040 retirement date. The utility last year halted efforts to build two new gas-fired plants at the Boardman site, saying it was instead pursuing talks to obtain existing resources.

PGE BPA Hydropower PPAs — The Dalles Dam | © *RTO Insider*

Wednesday’s announcement revealed those resources will be supplied by BPA, which will sell the Oregon utility up to 200 MW of surplus hydropower from the Federal Columbia River Power System under two concurrent five-year power purchase agreements for two different energy products, starting in January 2021. BPA told RTO Insider it could divulge only limited details about the contracts because they are subject to a non-disclosure agreement.

“That said, we can say that the two products are an advance notice right to power, each with different notification timeframes,” BPA spokesman David Wilson said. “Each product also carries asset-controlling supplier status,” which allows the associated energy to be exported to California with a low emissions factor for the purpose of greenhouse gas reporting under that state’s cap-and-trade program.

BPA said there were benefits to both parties in the deal, with PGE gaining access to fast-ramping resources while the federal power marketing agency pursues one plank of its recently announced strategic plan, which includes the marketing of “competitive products and services.”

“In addition to allowing BPA to take advantage of a new opportunity to market its clean, flexible hydropower and generate direct revenue as part of a broadening portfolio of power products, the contracts allow PGE more time for new dispatchable resource technologies to mature to help the company integrate increasing amounts of renewable power onto its system,” BPA said.

“These agreements are a great opportunity for us to collaborate with BPA to achieve shared goals in the region,” said PGE CEO Maria Pope.

The deal also has found support among key ratepayer and environmental advocates in the region.

“This is a great deal for the region. It’s a value-added product for the federal power system and a good alternative for PGE. It puts off big new investments in gas that would have locked PGE and its customers into fossil fuels for decades,” said Bob Jenks, executive director of the Oregon Citizens’ Utility Board.

“Instead of building new carbon-emitting resources, PGE is able to take advantage of existing clean hydropower, and BPA is able to lock in a future sale to help strengthen its financial health,” said Wendy Gerlitz, policy director with the NW Energy Coalition.

The power that PGE acquires under the BPA contracts will not count toward Oregon’s 50%-by-2040 renewable portfolio standard, which bars facilities that began operating before 1995. But it will contribute to the utility’s efforts to meet an Oregon requirement to reduce emissions to 80% below 1990 levels by 2050.

PGE earlier this month circulated a draft request for proposals seeking 100 MW of renewable power to help meet both those mandates. The utility expects to bring those resources into its portfolio by 2021.

The utility last October joined Western Energy Imbalance Market (EIM), drawing $2.8 million in net benefits during its first three months of participation, according to CAISO.

March 8, 2018

Xcel, NPPD Lose Z2 FERC Complaints

By Tom Kleckner

FERC on Tuesday rejected separate complaints by the Nebraska Public Power District and Xcel Energy over billed charges under Attachment Z2 of SPP’s Tariff.

Filing on behalf of its Southwestern Public Service affiliate, Xcel alleged SPP’s assignment of $12.8 million in credit payment obligations under Z2 and $485,000 in zonal charges violated service agreements with SPS, and that the filed rate doctrine and the RTO’s implementation of Z2 violated the Tariff’s “but for” test (EL18-9).

NPPD complained SPP misinterpreted its Tariff and improperly billed the utility for 86 Z2 revenue credit obligations and said the misinterpretation will subject it to future monthly charges under regionwide and zonal rates eligible for recovery (EL17-86).

Attachment Z2 assigns financial credits and obligations for sponsored transmission upgrades. The RTO last year completed a resettlement of the Z2 revenue, crediting amounts for March 2008 to August 2016, a move made necessary because of corrections and true-ups to the data that were identified before the first settlement of the charges. (See “More Z2 Woes; SPP to Resettle 9 Years of Data,” SPP Markets and Operations Policy Committee Briefs: July 11-12, 2017.)

SPP FERC Xcel Energy SPP Tariff attachment Z2 — SPP’s headquarters in Little Rock, AR | *WER Architects*

FERC has consistently sided with SPP in member complaints to the commission. It denied requests by several members to rehear FERC’s 2016 order waiving the one-year limit for adjusting Z2 payment obligations and revenue distributions for transmission projects. It also partially granted Kansas Electric Power Cooperative’s complaint in a separate transmission dispute with SPP, denying some claims and setting settlement judge procedures on others. (See FERC Rejects SPP Change on Network Resource Upgrades.)

FERC: Xcel Should Have Been Aware of Z2 Costs

The commission dismissed Xcel’s argument that SPS’ service agreements with SPP resulted from the RTO’s aggregate transmission service study process, were accepted by the commission and should have reflected SPS’ final cost responsibility as part of the filed rate. Xcel asserted that when SPS executed the resulting service agreements with SPP, the agreements should have contained all of the final responsible upgrade costs.

But FERC found the aggregate study reports alerted Xcel to the potential for SPS to be directly assigned costs for upgrades later determined to be necessary to support the transmission service request (TSR) in SPS’ agreements. It noted SPP was developing the Z2 revenue crediting mechanism when it provided Xcel with study reports and, “therefore, could not provide accurate estimates.”

The commission also rejected Xcel’s allegation that SPP’s assignment of costs violated Attachment Z2 and the filed rate doctrine, finding that Xcel misinterpreted the RTO’s application of the “but for” test. FERC found SPP’s methodology to be “reasonable” in determining whether a TSR makes subsequent use of creditable upgrades and that the “but for” test to determine credits under Attachment Z2 was a “reasonable and practical application.”

SPP’s Tariff Interpretation Correct

FERC also found SPP correctly interpreted its Tariff by classifying more than $860,000 in upgrades identified in NPPD’s complaint as service upgrades eligible for base plan funding cost allocation. The commission said the upgrades were initially determined to be necessary for generator interconnection requests, and the costs were directly assigned to customers “consistent” with interconnection procedures and the Tariff’s pro forma interconnection agreement, making them creditable upgrades.

The directly assigned upgrade costs became eligible to be recovered through revenue credit payments that made “subsequent use of the upgrades,” the commission said. In implementing the Z2 crediting process, SPP identified additional creditable upgrades subsequently used by previously studied TSRs and associated credit payment obligations, FERC said.

The commission said those obligations became eligible for base plan funding under the Tariff’s cost allocation rules and were included in the rolled-in allocation of costs to transmission customers through the regionwide and zonal rates.

“Therefore … these costs were properly allocated under base plan funding,” FERC said, in rejecting NPPD’s assertions that SPP should allocate the costs differently.

March 7, 2018

No Refunds in 20-Year-Old Entergy Rate Complaint

By Amanda Durish Cook

Entergy will not have to issue refunds in a decades-long rate dispute with the Louisiana Public Service Commission, the D.C. Circuit Court of Appeals ruled Tuesday.

In denying the PSC’s petition for review, the court upheld FERC’s decision not to order the refunds, acknowledging that the federal commission does not have a “generally applicable policy of granting refunds,” something the court did not understand when it originally remanded the rate case (16-1 3 82).

FERC LPSC rate dispute entergy — Galvez Building housing the Louisiana Public Service Commission | *LA.gov*

The issue dates back to 1995, when the PSC and the New Orleans City Council filed a successful complaint with FERC, arguing that Entergy’s formula for determining peak load responsibility in its multistate system agreement was unfair because it included interruptible load in addition to firm load.

In a 2004 order, FERC found that certain aspects of Entergy’s rates were unreasonable. And while the commission required Entergy to remove all interruptible load from its cost allocation, it declined to order refunds, concluding that the utility did not over-collect despite relying on an inequitable cost allocation.

FERC does not historically order refunds when “the company collected the proper level of revenues, but it is later determined that those revenues should have been allocated differently,” the court noted.

The court said that in 2016 it was initially convinced by the PSC’s argument that FERC had failed to “‘reasonably explain the departure’ from its ‘general policy’ of ordering refunds when consumers have paid unjust and unreasonable rates” and remanded the case to FERC. Last year, the PSC was still arguing at FERC that refunds to Entergy Louisiana could be possible. (See FERC Accepts Entergy Revision on ‘Moot’ Settlement.)

But, on remand, FERC told the court that it “actually has no general policy of ordering refunds in cases of rate design.”

FERC acknowledged that throughout the case it had referred to “a ‘general policy’ in favor of refunds” but said that the phrase was a mischaracterization and that it has no such policy.

The court accepted the explanation, saying FERC had clarified its “previously muddled position.”

“Now that the commission has corrected its characterization of its own precedent, we find that the commission’s denial of refunds accords with its usual practice in cost allocation cases such as this one. We also find that the commission adequately explained its conclusion that it would be inequitable to award refunds in this case. The commission did not abuse its discretion. … We find that the commission has made its historic practice clear and justified its application of that practice here,” the court said.

March 7, 2018

Picker Seeks Guidance on IOUs, Aliso Canyon

By Jason Fordney

California Public Utilities Commission President Michael Picker on Tuesday asked state lawmakers for guidance on the increasingly precarious financial health of the state’s investor-owned utilities, which face growing risks stemming from wildfires.

CPUC CAISO Aliso canyon — Picker | © *RTO Insider*

That topic — and reliability concerns surrounding the Aliso Canyon gas storage facility — dominated discussion at a hearing of the State Senate Energy, Utilities and Communications Committee in Sacramento.

Committee Chairman Ben Hueso (D) said that “there has been one issue over another” affecting utility planning and operations, including earthquakes, floods and wildfires.

CPUC CAISO Aliso canyon Michael Picker — Hueso hears from Picker at a hearing last year | © *RTO Insider*

“There has always been something that complicates the ability of the state of California to provide energy to the people of the state,” Hueso said.

Picker noted that analysts had recently downgraded the credit rating of a solar project owned by an independent power producer because it holds a contract with a utility, showing the ripple effect of utility credit downgrades that have occurred recently over wildfire risk. The trend could make it more difficult for California to meet its greenhouse gas reduction goals, he said.

“If this continues, we will probably have a hard time saying to the rest of the world that we could accelerate the process of greening the grid,” Picker said.

Several IOUs have recently been downgraded or placed on credit watch by ratings agencies, leading to worries in Sacramento about a repeat of the California energy crisis of 2000-2001 and IOU bankruptcies. The State Assembly recently held its own hearing on the issue, at which Picker also spoke. (See Wildfire Costs Ig n ite Worry at CPUC, Legislature.)

“I see the exact same pattern with respect to the investor-owned utilities that we have seen before,” said Sen. Robert Hertzberg (D), adding that credit downgrades can cause “cross-defaults” and other complications.

“The rate at which this thing falls apart is extraordinary,” Hertzberg said. “The house of cards is impacted in a way that is not quite positive.”

Picker has repeatedly asked lawmakers for direction on the issue.

“I am not here to tell the legislature what to do,” Picker said Tuesday. “I agree that it is urgent, but I do tend to work at the direction of the legislature.”

Elected officials have publicly discussed new legislation on the issue of “inverse condemnation,” a legal provision that allows utilities to seek recovery of wildfire-related costs in regulatory proceedings. The state’s three IOUs have banded together to challenge a recent CPUC decision denying cost recovery for San Diego Gas & Electric for damages from a 2007 fire, despite the utility’s reliance on the provision. (See Sempra J o ins ‘Three-Pronged’ Wildfire Front.)

Stern Objects to Aliso Canyon Decision

During the hearing, Sen. Henry Stern (D) vocalized his displeasure with a March 3 decision by CPUC Energy Division Director Edward Randolph that the legislator said “secretly granted” a Southern California Gas request for “immediate, seemingly open-ended utilization of the Aliso Canyon underground storage facility.”

In a March 5 l e tter to the commission, Stern asked questions about the status of gas pipelines taken out of service this winter and how those decisions were made. Stern, whose district includes Porter Ranch, the site of numerous local health complaints attributed to the facility, has called for Aliso Canyon’s closure.

But Aliso Canyon is also central to California’s electric reliability, leading CAISO to implement special measures to mitigate concerns about gas supplies to generators. (See Gas Adders a Necessary Tool, CAISO Says and CAISO Board Appro v es Aliso Canyon Rules Packag e.)

Stern said when there is a “Saturday night letter from Ed Randolph” that becomes public, “it starts to corrode that public trust.”

“We want to see this public trust restored, and it’s just not there right now,” Stern said. “People are going to assume the worst.”

Picker responded that he had recently proposed a moratorium on new commercial gas hookups in the Los Angeles County area that met heavy resistance from the business community. At its most recent meeting, the commission withdrew the proposed agenda item.

Picker said that “there is a core denial” of gas supply concerns and that “I need your help to get through that.” The real need for gas units is peaking power, he said.

“I completely agree there is plenty of blame to spread around here,” Stern said.

Picker also briefly sparred with Sen. Mike McGuire (D), who objected to Picker’s recent public suggestion that ratepayers in high-risk fire zones pay more for electricity. Picker used the example of homeowner’s insurance premiums in those areas that are higher based on fire risk.

McGuire, a Democrat from the North Coast district, which includes Marin County, replied that many of the fires occurred in areas without heavy tree growth.

“I will fight it with every bone in my body,” McGuire said of Picker’s proposal.

Picker and CPUC staff recently sent the commission’s 2017 annual repo r t to the legislature, along with the Office of Ratepayer Advocates rep o rt.

March 7, 2018

Court Backs FERC in Hydro License Dispute

By Rich Heidorn Jr.

FERC adequately explained why it limited Duke Energy Carolinas to a 40-year extension on the Catawba-Wateree hydro project, the D.C. Circuit Court of Appeals ruled Tuesday.

Duke had sought a new 50-year license for the project, which includes 11 developments on hundreds of miles of the Catawba and Wateree Rivers in North Carolina and South Carolina; its original 50-year license expired in 2008. The commission issued the 40-year license in 2015, concluding that construction and environmental measures under the new license were “moderate” (Project 2232-522).

FERC Duke Energy DC Circuit hydropower — Lake 16A | *Catawba Wateree Water Management Group*

The company asked the court to overturn the ruling, arguing it was similarly situated to applicants that had received 50-year extensions, making the commission’s order “arbitrary and capricious.”

The court declined to second guess the commission, noting the “narrowly circumscribed” role for the courts in ruling on hydro matters. “According due deference to the commission’s expertise in determining whether measures under a license are moderate or extensive and to its interpretation of its precedent and policy choices, we deny the petition for review,” it wrote (16-1296).

The commission generally issues a 30-year license for projects with “little or no” new development, capacity, or environmental mitigation; a 40-year license for projects requiring “moderate” investments; and a 50-year license for projects involving “extensive” measures.

Duke applied for a new license after reaching an agreement with 70 entities that specified measures it would take under a renewal.

FERC Duke Energy DC Circuit — Catawba Wateree Project Map | *FERC*

In its request for rehearing, Duke argued that FERC had failed to consider the costs of its investments, saying it had spent about $54 million on construction required by the agreement and $111 million in other relicensing costs.

FERC responded it does not rely on a “a strictly quantitative analysis” because “cost estimates can fluctuate widely over time.” It also said Duke’s cost data were “not reliable.”

“In response to commission staff’s request to simply update the cost estimates … Duke Energy instead filed new estimates — unsupported by any explanation,” the commission said, noting the company included a $40 million gate instead of the $10 million bladder dam called for in the license order.

The court cited FERC’s observation that Duke had not claimed it could not recoup its costs within 40 years.

“Further, the commission noted that some of Duke Energy’s cost estimates were not fully supported, or were inconsistent with the new license, because it was unclear that all the enhancement and mitigation measures are new measures. Duke Energy’s effort to avoid the plain meaning of the staff request to update the cost estimates is unpersuasive; as license applicant it had every incentive to explain the basis for its cost estimates and it cannot prevail by shifting the burden of clarification to the commission,” the court said.

March 7, 2018

Low ISO-NE Prices Persisted in 2017

By Amanda Durish Cook

ISO-NE power prices last year climbed from record lows, but they didn’t recover by much.

The RTO said Tuesday that cheap natural gas and declining regional demand left 2017 average wholesale prices at the second-lowest level on record.

In 2016, prices dropped to their lowest levels since New England’s current competitive electricity markets were established in 2003, according to ISO-NE.

Prices averaged $33.94/MWh in 2017, up 17.3% from the previous year but nearly 35% under 2004 levels. Last year’s wholesale market value of $4.5 billion was also the second-lowest on record, compared with 2016’s record low of $4.1 billion.

ISO-NE attributed the soft market to the second-lowest natural gas prices since 2003 ($3.72/MMBtu) and mild weather throughout much of the year. Gas prices averaged $3.09/MMBtu in 2016.

Gas-fired generation last year accounted for 48% of the power produced within New England and 41% of the region’s total energy mix, including imports.

The RTO said the extreme cold that arrived the last week of December constrained gas supplies and drove up prices, yielding $396 million of the month’s total electricity sales of $856 million.

But aside from December, consumer electricity demand remained light, averaging 121 GWh in 2017, down 2.7% for the year, according to preliminary numbers, ISO-NE said.

“Wholesale power prices were low in 2017 because of low fuel costs and relatively low consumer demand for power during most of the year,” ISO-NE CEO Gordon van Welie said in a rele a se. “However, the last week of December illustrates the impact of constrained natural gas supplies on electricity prices. The challenging operating conditions also highlighted a growing need for competitive markets to more transparently signal the potential costs of inadequate fuel security, which creates the potential for significant reliability risks to the region.”

August and June of last year saw the seventh and eighth lowest monthly price averages on record, at $23.77/MWh and $23.93/MWh, respectively. ISO-NE’s nine lowest-priced months all occurred in 2015, 2016 and 2017. The RTO’s highest prices occurred in January 2014 during that winter’s “polar vortex,” when prices averaged $162.88/MWh.

The RTO also said consistently improving transmission congestion played in role in keeping 2017 prices low. ISO-NE said that about $10 billion in transmission upgrades since 2002 has dropped congestion and reliability-related costs from more than $700 million in 2006 to about $57 million in 2017.

March 6, 2018

Coalition Targets Capacity Markets in Resiliency Docket

By Rich Heidorn Jr.

A coalition of consumer advocates, environmentalists, wind and solar developers and public power laid down a marker in FERC’s resilience docket Tuesday, calling on the commission to “review the design of organized wholesale electricity markets, particularly capacity constructs.”

The group — the American Public Power Association, Large Public Power Council, National Rural Electric Cooperative Association and the Transmission Access Policy Study Group from public power; the Electricity Consumers Resource Council (ELCON) and National Association of State Utility Consumer Advocates, representing load; and green energy proponents Natural Resources Defense Council, American Council on Renewable Energy, American Wind Energy Association and Solar Energy Industries Association — sent a letter to the commission listing five “principles” it said FERC should embrace in future rulings.

The group said the FERC Rejects DOE Rule, Opens RTO ‘Resilience’ Inquiry.)

Capacity Markets Resiliency Dockets FERC — | *GAO*

The principles: technology-neutral market rules; wholesale market rules that respect state and local resource choices and don’t make customers pay twice; allowing self-supply without RTO “second guessing”; no guaranteed recovery of investment costs for particular resources or technologies; and allowing markets “to function and stabilize before new solutions are deemed necessary to be implemented.”

“The capacity constructs include design features that may limit choice, create conflicts with state and local policy objectives, over-procure or unnecessarily retain capacity, and raise costs for customers,” the letter says, calling for avoiding “costly over-procurement.”

“We as a group are committed to contributing to solutions,” the letter continued. “We emphasize that solving this challenge directly and holistically, rather than layering costly Band-Aids on top of organized wholesale markets, will benefit customers most in the long run.”

FERC may ultimately rule that the coalition’s effort to inject a review of the capacity markets in PJM, ISO-NE and NYISO is out of the scope it set in the resiliency docket. The commission directed all RTOs and ISOs to identify their resilience risks; whether they should assess their resource portfolios against contingencies from the loss of key infrastructure; and the bulk power system attributes that contribute to resilience.

The issue is more central in docket AD17-11, the subject of a two-day FERC technical conference in May. (See Power Markets at Risk from State Actions, Speakers Tell FERC.)

But the breadth of the coalition indicates that disenchantment with mandatory capacity markets — which public power has questioned since their inception — has grown as state officials attempt to execute climate policies in the face of markets that ignore carbon emissions.

The group’s letter, however, noted the limits of the alliance, saying, “These design principles work together; individual signatories do not necessarily support every principle if other principles are not also honored.”

March 6, 2018

Powelson: States Pushing RTOs’ Backs to the Wall

By Jason Fordney

SAN DIEGO — Some states are creating energy policies without enough regard for grid reliability, possibly forcing federal regulators to intervene in the future, FERC Commissioner Robert Powelson said last week.

FERC CAISO Robert Powelson WPTF — Powelson | © *RTO Insider*

“We are seeing states that are pushing the envelope in some of these market constructs, with no understanding of what this means to overall electric reliability,” Powelson told the Western Power Trading Forum (WPTF) on March 2. “It is pushing the RTOs and the ISOs to a very ‘back-to-the-wall’ scenario, and that’s not good.

“FERC is going to have to rightly interject itself into some of these states,” he said.

Powelson addressed the WPTF in an informal speech interjected with humor and endorsements of his beloved Philadelphia Eagles, the reigning Super Bowl champions.

He noted that California and states in New England are pushing more renewables onto the system, creating issues such as CAISO’s “duck curve” and forcing oil units to run during this winter’s “bomb cyclone” in ISO-NE. He also said that four years ago he would have laughed if someone told him that gas-fired units in some California zones would be coming to FERC for approval for reliability-must-run contracts. (See FERC Orders Hearing, Settlement Talks for Calpine RMRs.)

Other California issues that concern Powelson: the possible phase-out of the Aliso Canyon gas storage field, as well as the retirement of the San Onofre and Diablo Canyon nuclear power plants.

While Powelson said he respects states’ rights, he added that “in some of those cases, the states get to choose the winners and losers in those markets, but the FERC has to deal with the moral hazards created by those decisions.”

Organized markets are benefiting consumers, who are increasingly becoming “prosumers” through using technology such as smartphones to manage energy usage, Powelson said. States like Nevada are considering retail competition, penetration of renewables is growing and FERC is contributing through actions such as its recent order on energy storage, he noted. (See FERC Rules to Boost Storage Role in Markets.)

But states cannot consider the policy aspect without heavily considering system balancing and reliability, he said. He also suggested the industry more strongly promote organized market competition to state governors and leaders, and he discussed a “cooperative federalism model” for FERC.

FERC CAISO Robert Powelson National Grid — California’s State Capitol Building | © *RTO Insider*

“There is a tectonic shift taking place across the ISO and RTOS, and a lot of that is driven by states,” Powelson said, pointing to the growth of markets across the West. “The fever of electric competition and competitive markets is going viral these days, and I think that’s a good thing.”

But he acknowledged there are differences in regional markets, “and you have to respect that, and I am learning that rather quickly.” He said, “I was warned not to talk about capacity markets” at the WPTF meeting, drawing laughter.

Powelson also mentioned the Department of Energy’s proposed grid resilience pricing rule that would have bolstered nuclear and coal units to maintain reliability, which he called “DOA.” (See Powelson, Regulators Talk Resiliency, Slam DOE NOPR.) He said that FERC’s rejection of the proposal shows that the rule of law and independence still matter at the commission.

March 6, 2018

PJM Proposes One-Time Frequency Response Recovery

By Rory D. Sweeney

VALLEY FORGE, Pa. — PJM won’t be offering market compensation to comply with FERC’s requirement that almost all resources provide primary frequency response (PFR), but the RTO is willing to give everyone a shot at recovering any upgrade costs to provide it.

PJM FERC frequency response primary frequency response — The Primary Frequency Response Senior Task Force met last week. | © *RTO Insider*

RTO staff unveiled their newest proposal on the issue at a meeting of the Primary Frequency Response Senior Task Force (PFRSTF) on Wednesday. The idea generated some stakeholder interest but also created plenty of concern in light of FERC’s recent ruling. (See FERC Finalizes Frequency Response Requirement.)

“In general, we’re going to disagree with all of this,” said Carl Johnson, representing the PJM Public Power Coalition. “We are not in favor of where PJM is going with this.”

Johnson said it would create a substantial cost to customers for something that should be baked into the cost of doing business. He said PJM would likely hear from the consumer advocates on the issue.

Staff said they couldn’t quantify the overall cost but would get back to stakeholders with estimates.

Applicable units could seek the cost recovery or include it in their capacity offers, but they couldn’t do both. Howard Haas of Monitoring Analytics, the Independent Market Monitor, outlined a situation in which units that sought the recovery could also clear the auction at a clearing price set by another unit’s bid that includes the upgrade costs.

“From our position, that would be double recovery,” he said.

The Monitor’s proposal argues that units already have opportunities to recover the cost through capacity or energy offers.

“I’ve got good news for you,” he said. “You’re already being compensated.”

CPower’s Bruce Campbell said he would have to review how distributed energy resources are handled in his company’s proposal.

PJM’s proposal also increased its proposed threshold for exempting units, from 10 MW to 20 MW, because the potential benefit from such small units might not outweigh the upgrade costs.

Brock Ondayko with American Electric Power disagreed with Haas on whether units could seek recovery. AEP’s proposal would allow units to petition FERC for recovery if they feel they need it and can justify the request. Ondayko said he would consider PJM’s one-time recovery proposal, but he also mentioned concerns about the cost to customers because provision of PFR isn’t a NERC requirement.

PJM’s Glen Boyle said PFR is a requirement for balancing authorities and therefore an “implicit” requirement for resources.

FirstEnergy’s Jim Benchek agreed with other members that PJM’s proposal seemed to be giving some BAs “a free pass.”

“Is this a solution looking for a problem?” he asked.

AEP’s proposal diverged from PJM’s on how performance would be evaluated. Both agreed that the calculation should be a quarterly pass/fail test on whether units provided at least half of the PFR they were expected to provide. AEP suggested a higher deviation and longer duration of frequency outside the deadband settings before performance could be evaluated.

“There should be something there that makes it possible to identify the unit response from the noise,” AEP’s Jim Fletcher said.

PJM’s Danielle Croop said staff would consider rolling that into their proposal.

“If we’re going to put that minimum of five or six events in there … we want to make sure that we’re still able to perform these evaluations on a quarterly basis and that it’s not that we’re sitting around waiting for events to happen,” she said.

Staff noted that in the 2017 operating year, there would have been 14 events that fit AEP’s standards, which wouldn’t allow for the six events per quarter that PJM planned to use for evaluation. AEP proposed evaluating five events each quarter because they would be “more meaningful,” Ondayko said.

AEP also suggested researching the importance of synchronous inertial response and preserving “what we have today because once it’s gone, it’s gone for good,” Fletcher said.

“If you look at interconnections that are losing their synchronous inertial response, like Texas, you’ll find that they have to resort to paying load resources to compensate for the fact that there isn’t enough primary frequency response anymore to cover that deficit, so the operation of the grid becomes more erratic … and the need for primary frequency response goes up, but there’s limited capability,” Ondayko said. “We recommend that this type of concept be considered in the future, at least recognizing the issue of how it impacts restoration.”