A financial trading firm accused PJM of unfairly discounting the interests of up-to-congestion traders in recent rule changes that it says would shift hundreds of millions in uplift charges to them from load.
“PJM is required to act as a neutral body without giving priority to one sector over others. XO is concerned that the packages promulgated by PJM and its [Independent Market Monitor] … benefits load while producing great harm to the Other Supplier Sector, including the financial community,” XO Energy President Shawn Sheehan wrote in a Feb. 24 letter to the Board of Managers.
The letter follows a phased set of rule changes that was overwhelmingly endorsed by the Markets and Reliability Committee in January and the Members Committee in February. (See “Work on Uplift Moves Forward Despite NOPR,” PJM Markets and Reliability and Members Committees Briefs.)
Phase 1 includes in the determination of balancing operating reserve credits only the day-ahead revenues from the hours the resource operated in real-time, not all day-ahead revenues. Phase 2 includes UTC transactions in the allocation of day-ahead and balancing operating reserves in the same way as incremental offers and decremental bids. It would also remove the ability for internal bilateral transactions to offset deviation charges.
XO argues in its letter that the changes create a “triple capacity deviation,” although UTCs are intrinsically transmission products that don’t impact capacity. According to XO’s calculations, the changes will shift as much as 79% of the total real-time uplift charges and 25% of day-ahead uplift to UTCs — a total of more than $388.5 million.
The letter argues that PJM actively worked to force the changes through the stakeholder process and didn’t offer XO and its allies due process.
“XO is concerned that equitable, stakeholder-centric initiatives, which do not comport with fundamental market design principles, such as best practices and causation, are taking precedence” to sound market design, the letter reads. “In the past year or more, XO has witnessed an unwarranted negativity from PJM and its staff towards both financial products and the financial trading community. … Financial market participants feel bulldozed by PJM’s perceived priority in advancing its own proposals through the voting process and its favoritism of other [stakeholder] sectors. These actions are strongly affecting market participants’ confidence in PJM’s ‘neutral’ administration of its duties and its operation of a fair and efficient market.”
PJM did not immediately respond to a request for comment.
The complaint is the latest chapter in a long-running battle among PJM stakeholders over the value of financial products such as UTCs and whether they are paying their fair share of costs.
XO contends that PJM ignored FERC’s direction in its proposed Phase 3 package that would limit UTCs to zones, hubs and aggregates. Such changes “would effectively remove the products’ ability to mitigate local market power and converge nodal congestion,” the company said. “FERC has repeatedly held that convergence of the day-ahead and real-time markets is a key measure of market efficiency.”
The Balancing Area of Northern California (BANC) has signed an agreement with CAISO that puts the Sacramento Municipal Utilities District (SMUD) on track to join the Western Energy Imbalance Market (EIM) in spring 2019.
The footprint of the Balancing Authority of Northern California extends north to south from the Oregon border to Modesto, and east to west from Sacramento to the Sierra Nevada range. | Balancing Area of Northern California
Another municipal utility, Seattle City Light, announced its interest in joining the market shortly after SMUD’s announcement and has already signed an agreement with the ISO, putting it on schedule to join up at the same time as the California utility. (See Seattle City Light Signs EIM Membership Agreement.)
The latest agreement calls for a “phased” approach for BANC members to join the EIM, with SMUD’s participation representing the first stage, followed by discussions regarding participation for other members, possibly including federal power marketing agency Western Area Power Administration’s Sierra Nevada region.
Regardless of whether WAPA eventually links up with the EIM, BANC members Modesto Irrigation District and the cities of Redding and Roseville are considering doing so. Two other members — the city of Shasta Lake and Trinity Public Utilities District — own no generating resources and would therefore derive no benefit from joining the market, according to Jim Shetler, BANC’s general manager.
The phased implementation hinges on SMUD being accounted for separately from other BANC members, including “having separate interchange as represented by e-tags, a separate area control error calculation, and separate revenue quality metering,” the EIM agreement states.
SMUD already has an agreement that enables the utility to bid power into CAISO through a single hub in which one proxy price is selected to represent all connection points between the two areas.
Another term spelled out in the agreement: CAISO acknowledges that as public entities, BANC members want to remain outside the jurisdiction of FERC.
BANC, in turn, accepts that its transmission-owning members will be required to amend their open access transmission tariffs to reflect the fact that the EIM’s operations are subject to FERC oversight.
“We believe the implementation agreement and our partnership with [the] ISO recognizes the unique situation of our public power members,” Shetler said in a statement. “We are pleased to begin the work that will enable our members to participate in the EIM if they choose to do so.”
Solano Wind Project in the Sacramento Municipal Utility District | Balancing Authority of Northern California
Incorporation of other BANC members in the future will require that the agreement be amended, or that a completely new one be executed.
CAISO CEO Steve Berberich said he was pleased with the decision by BANC and SMUD.
“SMUD is one of the premiere community-owned utilities in the country that will benefit from access to low-cost resources from the entire EIM footprint,” Berberich said.
SMUD has cited the benefits of increased renewable integration, potentially reduced reliance on gas-fired generation and lower operational costs as its primary reasons for joining the market — although the first two benefits outweighed the latter in the utility’s decision-making, according to Shetler. A joint study conducted by BANC and the WAPA estimated that SMUD would gain $2.8 million in yearly net benefits from transacting in the market, possibly increasing to $5 million in about five years — a “small number” compared with the utility’s overall portfolio, he said.
Established in 2011, BANC is the third largest balancing area in California and the 16th largest of the 38 balancing areas in the Western Electricity Coordinating Council. The agency contracts with SMUD to perform day-to-day balancing functions.
The Indiana Senate has approved a controversial bill that would phase out the state’s retail net metering program.
State senators voted 39-9 to approve Senate Bill 309, which gradually lowers the payments residents receive for selling excess energy from their distributed resources back into the grid. The bill now proceeds to the state’s House of Representatives.
Indiana residents currently earn the retail energy rate for their excess electricity, but the bill would reduce that compensation to 25% above the wholesale rate.
The bill originally contained a “buy-all, sell-all” provision that, if passed, meant homeowners would not have been able to use the power generated by their own solar or wind resources. Instead, they would have been required to sell all output to their local utility at wholesale, to be repurchased at retail. That provision was removed from the bill before the full Senate vote.
The bill underwent other amendments, including the addition of a grandfather clause — expiring in 2047 — for existing net metering customers and any residents who have equipment installed before July 1. Residents who sign up for net metering over the next five years would be covered under existing retail rate rules until 2032.
A provision that would altogether eliminate net metering by 2027 was also tossed from the bill.
The proposed law would also allow utilities to discontinue offering net metering in their service areas when net metering generation equals 1% of their peak summer demand load.
In a Feb. 22 opinion in Fort Wayne’s The Journal Gazette, bill author Sen. Brandt Hershman (R) praised the legislation, calling it a “net gain for Hoosiers.” The bill encourages “renewable energy generation while bringing more fairness and market sensibility to the way privately owned solar panels and wind turbines are subsidized by other customers,” he wrote.
Hoosier Energy Power Network Solar Power Plant in Bloomington, In. Inovateus Solar
Hershman said that having electric utilities pay full retail rates for consumer-generated energy is unfair and that the prices are “two to three times the actual value of the energy on the market.” Net metering was established to encourage investments in consumer-owned solar and wind generation when installation costs were higher, he contended, but the generation is now more affordable. He pointed out that the federal government has reduced its incentives for residential renewables.
The bill has found support from Indiana’s major utilities, according to Mark Maassel, president of the Indiana Energy Association, which represents major Indiana electric utilities Duke Energy, American Electric Power’s Indiana Michigan Power, Indianapolis Power and Light, Vectren and Northern Indiana Public Service Co.
“All Indiana’s investor-owned utilities are working together on this,” Maassel said. “The companies are very thankful for Senator Hershman.”
Maassel said the utilities did not have a hand in authoring or revising the bill.
“The bill, where we ended up at, is a positive step and something we would like moved forward,” Maassel said.
But solar and renewable advocates are not happy with the final product, arguing that the bill gives utilities too much control over residential solar and wind.
“Senator Hershman, Indiana’s monopoly utilities and their friends in the legislature who are backing the bill say it was ‘fixed’ with amendments, but that’s not true,” said Wendy Bredhold, an Indiana-based representative of the Sierra Club’s Beyond Coal campaign. “The utilities want to control solar power and take away Hoosiers’ freedom to generate their own.”
Bredhold called the bill a “step backwards” for Indiana and “energy freedom” and said that it “effectively kills homegrown, rooftop solar” in a state “controlled by powerful utility interests.”
The Indiana Distributed Energy Alliance said the bill “will eviscerate net metering and customer-owned solar and small wind in Indiana.”
Sean Gallagher, vice president of state affairs for Solar Energy Industries Association, said the bill’s language fails to account for the full range benefits that residential generation can provide.
“Compensating … local power at average wholesale prices, as SB 309 proposes, significantly undervalues the benefits of producing that power — such as avoiding the need to build new power lines — and ignores the fact that solar power is produced during daytime peak periods when wholesale energy prices are higher,” Gallagher said.
Gallagher has called on Indiana’s legislature to let the Utility Regulatory Commission investigate the costs and benefits of rooftop solar before setting “arbitrary limits or determining compensation that customers would receive in statute.”
Great Plains Energy has complied with the Missouri Public Service Commission’s order that it seek commission approval on its proposed acquisition of Westar Energy.
Great Plains, the parent of Kansas City Power and Light, relented on filing the $12.2 billion sale with the regulators in response to the commission’s Feb. 22 ruling on a complaint by the Midwest Energy Consumers Group.
Westar Transmission | Westar
The group cited KCP&L’s 2001 application to reorganize into a holding company (EM-2001-464). The restructuring — which created Great Plains as parent and KCP&L its subsidiary — contained an agreement that Great Plains would not attempt to merge with or acquire a public utility without first seeking commission approval.
The PSC had ordered Great Plains to file by March 4. Great Plains is asking that the commission render a decision before April 24 to keep the expected spring transaction closing date on schedule.
The commission said last year that it should have jurisdiction over the sale, but Great Plains said that the deal didn’t require its approval because Westar is a Kansas company. (See Great Plains Energy, Westar Shareholders OK $12.2B Deal.)
Great Plains had argued that allowing the PSC in on the decision would “improperly expand the commission’s jurisdiction to include the acquisition of non-Missouri regulated utilities by Missouri-based holding companies.”
PJM has received FERC approval to divide $40.8 million from an enforcement settlement with GDF SUEZ Energy Marketing among market participants who were impacted by the company’s scheme to improperly capture make-whole payments.
FERC’s Office of Enforcement, which reached the settlement with GDF, approved of PJM’s plan to distribute the funds as negative operating reserve charges to any market participants that incurred deviations between the day-ahead and real-time energy markets between May 2011 and September 2013, according to an email from David Budney, the RTO’s manager of market settlements. It noted that the adjustments have been processed and are available in the market settlements reporting system.
The Troy Energy gas-fired plant in Luckey, Ohio, is one of the units GDF Suez used to own in PJM.
The funds are part of a nearly $82 million payment by GDF to settle market manipulation charges for offering generation below cost to capture make-whole payments in PJM. Enforcement charged GDF with violating the commission’s Anti-Manipulation Rule for an improper bidding strategy designed to increase its receipt of lost opportunity cost credits (LOCs).
According to the settlement, the Houston-based power marketer offered below-cost bids on some of its 12 natural gas-fired units to clear PJM’s day-ahead market and profit off the LOCs when the units weren’t dispatched in real time. GDF used a probabilistic, risk/reward approach to compare when units were unlikely to be dispatched against the risk of running the units at a loss, the settlement said. (See GDF SUEZ to Pay $82M in PJM Market Manipulation Settlement.)
GDF’s parent company rebranded as ENGIE in 2015 and sold off its U.S. fossil-fuel generation assets in 2016. PJM has since updated its rules to eliminate the loophole of which GDF took advantage.
ERCOT announced it is terminating its reliability-must-run agreement for NRG Texas Power’s Greens Bayou Unit 5 in Houston, effective May 29.
Greens Bayou
The grid operator said studies using new criteria indicated the unit would not be needed for transmission system reliability after Exelon’s 1,148-MW Colorado Bend II Generating Station in Wharton County, Texas, becomes operational in June.
The new criteria took effect with the passage of Nodal Protocol Revision Request 788 last fall. NPRR 788 requires a potential RMR unit to have “a meaningful impact on the expected transmission overload” to be considered for an agreement.
ERCOT said the previous rules, which used a forecast based on a 90% probability of exceedance, were overly conservative and that the new criteria should reduce the use of RMR contracts for reliability concerns that have a very low probability of occurring.
The RMR, ERCOT’s first since 2011, was approved last June to run through June 2018. Greens Bayou 5 is the largest of seven units at NRG’s Harris County complex. Built in 1973, the 371-MW natural gas unit was mothballed in 2010 and 2011, but returned afterward. (See “Greens Bayou Still Needed Under RMR Protocol Changes,” ERCOT Board of Directors Briefs.)
Public Service Enterprise Group has received approval to operate as a third-party supplier of retail electric energy in New Jersey and eastern Pennsylvania, company officials said during its report on earnings for the fourth quarter and full year of 2016.
“The forecast for 2017 doesn’t assume meaningful contribution from retail sales, but Power’s team will begin its marketing efforts,” CFO Dan Cregg said.
“This is primarily a defensive move on our part,” said CEO Ralph Izzo. “We’ve opted to pursue this organically, building the capability in-house. We still are targeting between 5 and 10 TWh at its maturity. … We have a head of the operation onboard that we’ve hired and a couple support folks and are talking to people about some of the back-office fundamentals that we don’t want to build on our own.”
The business would be in addition to its requirement to provide power to default customers within its footprint that don’t shop around — about 11 of the company’s 50 annual terawatt-hours of production, Izzo said.
“What we’re looking to do here is to basically claw back some of the [customers who purchased elsewhere] that over years had gone away either by some combination of migration or changing of thresholds for the [basic-service] customer. We think that it will help us capture some lost margin and improve our management of basis differentials,” Izzo said.
PSEG reported income of $887 million ($1.75/share) for 2016 compared to $1.68 billion ($3.30/share) for 2015. For the fourth quarter, the company reported a loss of $98 million (-$0.19/share) compared to income of $309 million ($0.60/share). Expenses associated with the early retirement of coal-gas units at the Hudson and Mercer generating stations and reserves for a leveraged lease impairment accounted for the difference in year-end results, company officials said. The fourth-quarter loss reflects the impact of depreciation and other expenses associated with the plant retirements.
NJ Gov. Chris Christie and PSE&G President and COO Ralph LaRossa in Hackensack on October 28, 2016 discussing improvements made to PSE&G equipment since Superstorm Sandy. | PSEG
Operating earnings for the year were $1.48 billion ($2.90/share), virtually unchanged from the $2.91/share earned in 2015. Operating earnings were $279 million ($0.54/share) for the quarter compared to $255 million ($0.50/share) for the same period last year.
Company officials and analysts largely shrugged off the quarterly losses, noting annual operating results came solidly within its guidance of $2.80 to $2.95/share.
“The board’s recent decision to increase the common dividend by 4.9% to the indicative annual level of $1.72/share represents confidence in our firm’s investment strategy and an acknowledgment of our strong financial condition,” Izzo said.
FERC has accepted MISO’s plan to pare down pre- and post-service restrictions on its directors as part of a package of transmission owner agreement bylaw changes.
The short Feb. 23 order (ER17-686) approved all MISO’s requested bylaw changes effective Feb. 27. RTO staff said the bylaw change was needed to attract more board member recruits.
Most prominently, FERC’s delegated order cuts the pre-service restriction to one year and eliminates a post-service restriction. MISO’s directors had been subject to a two-year pre- and post-service prohibition on affiliations with RTO members, affiliates and market participants. (See Board OKs Pay Hike, Change to Independence Rules.)
The edits also added the gender-neutral “board chair” in lieu of “chairman” and specified that adjustments to board compensation must be made by an independent compensation consulting firm. The RTO last year used firm Willis Towers Watson to up board compensation by $4,000 annually.
Other bylaw edits the commission approved allow board elections to take place earlier in the year, remove the requirement that the annual MISO members meeting be held on the second Thursday of December — allowing for more flexible scheduling — and eliminate the specific Jan. 1 due date for the annual $1,000 MISO membership fee. MISO staff said membership fee billing and payment usually takes place sometime after Jan. 1.
Finally, the edits clarify that member voting — even voting to remove a board member — can take place outside of meetings.
CARMEL, Ind. — Mild temperatures and inexpensive natural gas resulted in a slight load decrease and lower energy prices in MISO in January.
Average load was 76.2 GW, a 0.7-GW decrease over December. LMPs averaged under $30/MWh systemwide, a 7.6% decrease from December, with real-time prices of $28.04/MWh and day-ahead prices of $28.69/MWh. The average January gas price was $3.28/MMBtu, a decrease of 8.6% from the prior month.
Operating conditions in the RTO during January were “generally favorable,” punctuated by a few short-lived severe weather conditions, Executive Director of Market Design Jeff Bladen said at a Feb. 21 Informational Forum. MISO reported zero minimum or maximum alerts or warnings.
The RTO also recorded 4,245 GWh of systemwide wind production in the month, a drop from December’s 5,687 GWh, but 3% higher than January 2016’s 4,110 GWh.
WILMINGTON, Del. — After months of rule changes, PJM stakeholders decided to largely take a break at last week’s Markets and Reliability Committee meeting. Aside from endorsing some administrative revisions and an uncontroversial exception to competitive bidding for substation equipment, members rejected or deferred votes on all other voting items, often citing FERC’s lack of a quorum for why there is no pressing need to decide.
Decision on Order 825 Implementation Postponed Until March
Stakeholders agreed to delay voting for a month on additional rule changes associated with Order 825, which requires that shortage pricing be triggered for any period of energy or operating reserve. The order required PJM to eliminate its practice of waiting until a shortage is forecast for a sustained period before shortage pricing. (See FERC Issues 1st RTO Price Formation Reforms.)
To continue to avoid “transient shortages,” PJM has proposed a two-part response to the order. The first part, which was filed last month, satisfies FERC’s requirements for initiating shortage pricing. The second part — which PJM plans to submit to FERC as a Federal Power Act Section 205 filing contingent upon approval at the Members Committee meeting in March — would adjust its operating reserve demand curves. (See “Order 825 Implementation Moves Forward,” PJM Market Implementation Committee Briefs.)
“Is this a decision the commission could make absent a quorum?” American Municipal Power’s Ed Tatum asked. PJM staff confirmed that there has been a challenge in the docket, so FERC wouldn’t be able to accept it via delegated approval.
Susan Bruce of the PJM Industrial Customer Coalition asked if a vote could be delayed another month to work out issues. It’s possible, PJM’s Adam Keech responded, but the delay might create exposure for PJM’s markets if FERC requires implementation of five-minute settlements, also mandated by Order 825, by May.
Keech also explained that an increase in the market clearing price will have as much as triple the impact on reserve clearing price credits. PJM’s analysis found that a 5% increase in the clearing price would add about $6.4 million, or 15%, to the credits, while a 10% increase in the price would add about $8.7 million, or 20%.
For the purposes of simplicity, the sensitivity study assumed that lost opportunity cost credits remained static. Generally, however, “as the clearing price credits go up, the opportunity cost credits go down,” Keech said.
Stakeholders Deny Replacement Capacity Initiative; Consider Other Incremental Auction Changes
A problem statement and issue charge to address replacement capacity failed to garner 50% approval after presenter Bob O’Connell of Panda Power Funds navigated around objections to secure a vote. He’ll get another chance on a separate problem statement involving incremental offers next month, when members also will consider the proposed charter language for the Incremental Auction Senior Task Force.
Several members had attempted to postpone voting on the problem statement for a month, but a vote to postpone fell short, receiving 3.33 in a sector-weighted vote that required 3.34 to pass. That allowed O’Connell to call for a vote.
Tom Rutigliano of consulting firm Achieving Equilibrium said a delay would help alleviate problems with the problem statement, such as what he called a mischaracterization of some FERC orders that put stakeholders “on a path to repeat the same conclusions that FERC has already rejected.” But O’Connell was intent on bringing the motion to a vote. Rutigliano then proposed some hastily devised amendments, some of which O’Connell accepted.
Citigroup Energy’s Barry Trayers also proposed amending the language to focus on streamlining the replacement-capacity process and reducing PJM staff discretion. O’Connell considered this a friendly amendment and included the revisions.
“Really this is a vote about whether we want to try to solve the problem on our own or if we want to have the commission solve it for us,” O’Connell said.
The proposal to revise the replacement-capacity rules comes after recent stakeholder debates about the impact of “paper capacity” — when a market participant offers into Base Residual Auctions and buys out of the obligation during subsequent Incremental Auctions to take advantage of price differences. (See “PJM Has No Objection to IMM’s ‘Paper Capacity’ Report,” PJM Market Implementation Committee Briefs.)
Regarding his second problem statement proposal, O’Connell said PJM’s opportunity-cost calculator needs to be recalibrated to account for penalty rates implemented along with the Capacity Performance market construct.
Independent Market Monitor Joe Bowring challenged a work activity to find ways to incorporate nonperformance charge rates into the calculators. O’Connell agreed to add “where appropriate” or “if necessary” as a revision.
The task force charter language was developed in response to a problem statement presented by Direct Energy that was approved in November. It focuses on the Incremental Auction structure and how excess capacity is sold back by PJM.
PJM’s Brian Chmielewski, who is facilitating the task force, said detailed replacement capacity issues will be addressed in a separate problem statement and issue charge.
Transmission Replacement Activity Hiatus Extended
Stakeholders agreed to extend the Transmission Replacement Process Senior Task Force’s hiatus for another 90 days, citing FERC’s continued silence on the issue.
In August, the commission issued an Order to Show Cause questioning whether PJM transmission owners are complying with their local transmission planning obligations, specifically with respect to supplemental projects, as required by Order 890. (See “Transmission Task Force Halts Most Action in Response to FERC Order,” PJM Markets and Reliability and Members Committees Briefs.)
The TOs responded in October, but FERC has not acted on the filing and has no deadline for doing so.
PJM’s Fran Barrett, who is facilitating the task force, said the commission’s loss of its quorum was unexpected and recommended extending the deferral.
Some stakeholders called for using the downtime to resolve the problems. “We can work a thorny issue for FERC so FERC doesn’t have to work it for us,” Tatum said, who added that he has “great concern” with extending the hiatus.
“The time we have been waiting for FERC to act has not been wasted time. We have been working hard,” Exelon’s Gloria Godson said.
O’Connell said the decision should be based on whether there is anything to talk about. “Just go ahead and tell Fran: ‘Fran, we have enough meat for a meeting. Go ahead, and schedule it. If we don’t have enough meat, don’t schedule it,’” he said.
Barrett agreed to return to next month’s meeting with an update.
Stakeholders Endorse Revisions
Stakeholders endorsed by acclamation several manual revisions and other operational changes:
Revisions to Manual 22 to update terms and definitions, developed as part of a periodic review of the manual. The term revisions largely replace “partial outage” so that the manual now refers to forced, maintenance and planned outages as “derated.” For example, “Equivalent Forced Partial Outage Hours” became “Equivalent Forced Derated Hours.”
Revisions to manuals 13 and 27 will add the Mid-Atlantic Interstate Transmission Co. as a transmission owner in PJM. MAIT is a new subsidiary of FirstEnergy that owns and operates the company’s transmission assets in the Met-Ed and Penelec utility territories. (See NJ Opposition Derails FirstEnergy’s Tx Reorganization — but not Projects.)
Revisions to the RTEP and the Operating Agreement to exempt certain transmission substation equipment from Order 1000 competitive bidding. (See “Endorsements Sail Through by acclamation,” PJM Planning Committee and TEAC Briefs.) John Farber of the Delaware Public Service Commission staff took the microphone to thank PJM for its attention to the topic. The measure was also later endorsed by the Members Committee.
Two stakeholders complained that the proposals didn’t align with FERC’s order on the issue. “I don’t agree that the package is counter to FERC’s order,” PJM Public Power Coalition’s Carl Johnson replied. “In fact, I think it’s the first step to something they might approve.”
Consent Agenda Endorsed
The committee also endorsed:
Tariff, Operating Agreement and Reliability Assurance Agreement revisions to update definitions.
Revisions to the PJM Tariff regarding operating parameters.
