Page 1174 – RTO Insider

March 11, 2018

‘Hesitancy’ Around Western RTO, EIM Chair Says

By Jason Fordney

LOS ANGELES — Despite recent developments favoring more organized energy markets, Westerners still hold some “anxiety” and “hesitancy” about a new RTO in the region, says Doug Howe, chairman of the Western Energy Imbalance Market’s (EIM) Governing Body.

EIM PJM Western RTO Doug Howe — Howe | © *RTO Insider*

Howe, a doctor of mathematics, independent consultant, former utility executive and former New Mexico regulator, joined the body when it was established in 2016.

At an EIM meeting in Los Angeles last week, RTO Insider asked Howe how he sees the Western landscape taking shape, and what his concerns are about a possible new Western RTO.

“My sense is still that there is a lot of hesitancy towards a full RTO,” Howe said. “The idea of transmission allocation and a uniform transmission price across a region as big as the Western Interconnection gets a lot of people a little nervous, because we have widely varying transmission costs in the West.”

Several possible changes are stirring the West, including a joint proposal by Peak Reliability and PJM to create a new market and CAISO’s plan to extend its day-ahead market across the EIM. (See Peak Touts ‘Independent’ Western Market Plan and CAISO Plan Extends Day-Ahead Market to EIM.) There is also California legislation underway that could regionalize CAISO. (See Calif. Lawmakers Relaunch CAISO Regionalization.)

CAISO and EIM Governing Body Personnel left to right: Keith Casey (CAISO) Carl Linvill, Valerie Fong, Howe, John Prescott, Kristine Schmidt, Roger Collanton (CAISO) | © *RTO Insider*

While the Peak/PJM market proposal only sets out to establish an energy market, and not a full RTO, Peak executives have described it as a “pathway” to an RTO.

“All of these initiatives are in some sense a pathway to an RTO,” Howe said. The question is how to deliver the benefits of an RTO, such as day-ahead, real-time and ancillary services markets, “without triggering all this anxiety,” he said.

The best approach, according to Howe?

“Let’s get the energy markets established first and then we will see where stakeholders are comfortable going.”

Howe said industry participants have several choices to examine now and will be analyzing the costs and benefits of each one, “and whether it has sufficient bells and whistles — is it the right market to be in?”

One concern is “the absence of a real exit strategy” if a market participant joins an RTO, he said.

“If you find it’s not working out for you, getting out is extraordinarily expensive,” Howe said. While CAISO is seeking to extend the day-ahead market across the EIM, an RTO “is not what we are proposing at this point.” The trade-off is that participants don’t get the full benefits of an RTO either, he said.

When asked about whether there is unease about a balkanized and noncontiguous market taking shape, Howe said, “I don’t think there is a lot of concern about that.” The Eastern U.S. is balkanized to some degree and “it’s a spider web of transmission,” he said. In the West, transmission lines run north and south and east and west from the coast inland.

“They have worked that out in the East, but there is some concern that the West is not the same as the East, and that is going to be part of the working-out process,” Howe said. “There might be a little more concern about the reliability coordinator becoming balkanized, because they are the ones that have a high-level view of the entire grid.”

March 11, 2018

EIM Governing Body Approves CAISO Bidding Flexibility

By Jason Fordney

LOS ANGELES — Western Energy Imbalance Market (EIM) leaders last week endorsed CAISO’s controversial proposal to give generators more bidding flexibility, but not without giving ground to the plan’s skeptics.

The EIM’s Governing Body on Thursday approved the ISO’s Commitment Costs and Default Energy Bid Enhancements (CCDEBE), designed to give generators more latitude in how they reflect their commitment — or start-up and minimum load — costs and overhaul the way the ISO calculates the default energy bid, which replaces bids of units found to have market power.

The EIM Governing Body met last week in Los Angeles, California | © *RTO Insider*

The current method can artificially limit a generator’s commitment cost and limits what the generator can bid in, the ISO has said.

But to the end, market participants and the ISO’s Department of Market Monitoring raised questions after a lengthy stakeholder process to develop the rules. (See CAISO Developing New Bidding Rules.)

The rule changes still require approval by the CAISO Board of Governors, which will consider the proposal at its March 21-22 meeting.

‘A Good Place’

CAISO’s proposal replaces a static commitment cost bid cap with a local market power mitigation test, which identifies whether a resource needs to be committed to relieve a transmission overload or other constraints, the same way energy bids are handled. The ISO will only mitigate bids when a generator fails the test.

Under the current rules, the ISO calculates reference levels for each gas-fired generator based on published natural gas price indices. The commitment cost reference level is determined by multiplying costs by 125% and bids are capped at the generator’s reference level.

CAISO plans to phase in commitment cost bidding flexibility, first raising the commitment cost multiplier to 150% for the first 18 months after implementation, and then increasing it to 300% if no issues arise.

During the rulemaking process and at Thursday’s meeting, there was heavy debate over CAISO’s plan to automatically increase the reference levels after 18 months. Some commenters, such as Governing Body member Kristine Schmidt, suggested that a new stakeholder process might be needed at the 18-month point.

caiso eim commitment cost — Casey | © *RTO Insider*

But CAISO Vice President of Market and Infrastructure Development Keith Casey resisted the idea, saying “it sends a message to the market that we are not serious about this.”

Body members compromised by adding a provision to the decision that the ISO provide a status report to the EIM and CAISO board at the 18-month point.

“This was tough one, but I think we ended up in a good place on this,” Governing Body Chairman Douglas Howe said.

The ISO recently lowered the proposed multiplier for the first 18 months to 150% from 200%, in an “abundance of caution,” Market Design Manager Brad Cooper said, calling the bid cap a “circuit breaker.” The proposal also allows suppliers to seek adjustments to their reference levels based on changes in documented costs.

“We believe that we have a robust design, but we agree we need to proceed cautiously with changes,” Cooper said during a presentation to the Governing Body.

Respectful Disagreement

DMM Director Eric Hildebrandt supported the proposal, saying “the basic framework is there.” But he recommended a few changes, saying there are some gaps, a potential for economic withholding and for a “kind of gaming.” (See Monitor Critical of CAISO Commitment Cost Mitigation Plan.)

“We have looked at it, and we respectfully disagree,” Casey responded, adding that some power suppliers are “sort of biting their tongue” on the arrangement for the first 18 months. An automatic change at the 18-month point provides certainty that the ISO is committed to moving to the higher cap, he said, adding that CAISO can always file with FERC to keep the level at 150% if it discovers issues.

Howe said the EIM’s decision “is trying to carve a middle road,” but he didn’t think CAISO should “back into” a second stakeholder process that would “allow everybody to have a second bite” at things they didn’t like.

Body member John Prescott said, “I support this, and I would advise the Board of Governors to support this as well.” He said he expects the DMM to make sure issues don’t materialize.

Representing the Western Power Trading Forum, Carrie Bentley of Resoro Consulting told RTO Insider that the parties most affected by the change will be EIM entities or others who have experienced challenges with CAISO calculating their proxy costs, and generators and scheduling coordinators impacted by high gas prices.

She said that while WPTF supports the proposal, she called CAISO’s changing the reference level late in the proceeding “an unfortunate circumstance of panic policymaking in response to a few influential stakeholders. The CAISO had an excellent proposal, and it would have been better if they just remained confident in it.”

March 11, 2018

Monitor Backs MISO Uninstructed Deviation Proposal

By Amanda Durish Cook

CARMEL, Ind. — MISO’s Independent Market Monitor is backing the RTO’s proposal to revise its uninstructed deviation rules to allow generators to recoup a portion of make-whole payments even when their ramp rates fall short of expectations.

Monitor David Patton said last week that he now favors the “less draconian” performance-based proposal over his original recommendation from last year’s State of the Market report.

MISO’s plan would calculate a generator’s uninstructed deviation by comparing the time-weighted average of its real-time ramp rate with its day-ahead offered ramp rate, while allowing for a 12% tolerance from set point instructions. The proposal eliminates the RTO’s current “all or nothing” eligibility for make-whole payments, instead allowing generators to collect full payments when they respond to dispatch instructions at a rate of 80% or higher over an hour, while excluding payouts when performance rates fall below 20%. Units operating between those two thresholds would earn make-whole payments in proportion to performance.

The RTO currently flags generators that deviate from ramp rate dispatch instructions by more than 8% over four consecutive five-minute intervals, putting them at risk of losing day-ahead margin assurance payments (DAMAPs). The new approach would eliminate all current ramp rate requirements except for the one requiring rates of greater than 0.5 MW/minute.

Patton said MISO’s time-weighted approach provides generators greater incentive to follow their offered ramp rates than his earlier proposal requiring units to move at least half their offered ramp rate within a 20-minute grace period before being flagged and losing make-whole payments. (See MISO Tempers Dispatch Plan After Stakeholder Pushback.)

“That 15 minutes is a knife edge,” Patton said of the originally proposed 20-minute grace period before becoming ineligible for DAMAPs. “Generators motionless after 15 minutes will have to move at 100% of their ramp rate immediately to avoid exceeding 20 minutes.”

He also pointed to the benefits of performance-based partial payments.

“Over the course of an hour, generators will have a stronger incentive to perform better. If you perform reasonably well, you’ll make more money than if you don’t perform reasonably well,” he said.

The Market Subcommittee (MSC) met on March 8, 2018 | © *RTO Insider*

Patton said MISO generators have so far been discouraged from providing a “multi-point” ramp rate that factors the time it takes to move a unit in the first few moments after firing it up. He said using an average of hourly performance will allow for nuances.

Some stakeholders agreed that it was a good idea to allow a lagging lead-time for slow-moving units but said the proposal doesn’t help wind and solar generators, which have a tendency to be flagged for excessive energy production.

Patton acknowledged that wind power may need a “special rule,” saying MISO could make “simple” changes to excessive energy flags for wind only when the excessive ramping doesn’t cause congestion.

MISO plans to continue refining the uninstructed deviation proposal through April.

March 9, 2018

IMM Report Says PJM Prices Sufficient

By Rory D. Sweeney

While structural issues persist, PJM’s markets were competitive in 2017, the RTO’s Independent Market Monitor said Thursday, contradicting concerns from PJM and some stakeholders that prices are unsustainably low.

In his annual State of the Market R eport, Monitor Joe Bowring noted that PJM’s energy, capacity, regulation, synchronized reserve, day-ahead reserve and financial transmission rights markets all produced competitive results with competitive participant behavior, although all showed either market structure or design issues. Bowring recommended improvements for each market.

State of the Market Report PJM Market Monitor Bowring — | *Monitoring Analytics*

But the results show that the generation fleet remains relatively diverse and that most plants are receiving enough revenue to be profitable. All diesel and pumped-storage resources, and nearly all gas-fired combustion turbines and hydro stations, received full recovery of their avoidable costs, as did 88% of oil- or gas-fired steam units and 86% of gas-fired combined cycle plants.

Among nuclear plants, 68% earned enough revenue to cover an industry-standard calculation of costs developed by the Nuclear Energy Institute.

Using capacity auction results going forward, the report found only four nuclear facilities are threatened with negative revenues: Oyster Creek (which is already slated for decommissioning), Davis-Besse, Three Mile Island (TMI) and Perry. Quad Cities and Byron, the beneficiaries of Illinois’ controversial zero-emissions credits legislation, had been unprofitable four of the past five years but are projected to turn a profit through 2020.

The Salem nuclear plant also is expected to remain profitable through 2020. Asked why Exelon and Public Service Enterprise Group, which jointly own the two-unit facility in southern New Jersey, decided to halt capital expenditures at the plant, Bowring said he was “not quite sure” the reasoning.

“Based on publicly available data, it is more than covering its costs,” he said. “Nuclear units are not making a lot of money, but generally … they are not receiving a retirement signal from the market.”

“It’s not surprising” that single-unit facilities are the ones that are getting that signal, Bowring said. Additionally, he argued that NEI’s number was “inappropriate” because it included additional costs that were incurred in the aftermath of the Fukushima disaster in 2011. Using two-thirds of those costs, all but TMI and Davis-Besse will be profitable.

Just 52% of coal-fired plants recovered their avoidable costs, the report showed. PJM’s plan to revise price formation would support large, inflexible units like coal plants, but Bowring said the reforms were not based on market flaws. Nearly 79% of the $24.7 million uplift costs from day-ahead operating reserve differences were paid to coal units in 2017, but not because of market design issues, he said.

“That actually has to do with some very specific circumstances about coal units that have nothing to do with convexity and non-convexity and would not be affected by PJM’s price-formation proposal,” Bowring said.

Coal units also received nearly 85% of $20.4 million in uplift paid for reactive services, but gas turbines gobbled up the vast majority of the remaining $83 million uplift payments for lost opportunity cost, black-start services, local constraints control and balancing operating reserves.

While new combined cycle facilities could turn a profit in some zones, the revenue available in 2017 didn’t cover the cost of entry for new combustion turbine generators, nuclear or other units.

“The PJM system is significantly long” on generation, Bowring said, in part because the RTO has been regularly over-forecasting demand. The average real-time demand was down 2.2% from 2016 to 86,618 MWh. Peak and average load were also down.

That factored into a $30.99 average LMP, which was up 6% from 2016 but lower than every other year since 2000. Much of that came from coal and gas prices, which combined to account for nearly 70% of the LMP.

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.