CAISO is moving forward with a proceeding that could result in changes to how it allocates transmission costs to participants in its wholesale markets, meant to better reflect increased adoption of distributed generation and other factors.
The grid operator is considering a proposal to replace its current method, which utilizes end-use metered load to bill a volumetric transmission access charge (TAC). That method does not reflect the role of DG in reducing transmission costs.
CAISO is analyzing whether to reduce TAC charges in transmission owner service areas for load that is offset by DG output, and how best to do so. It also is considering a demand-based charge instead of — or in addition to — its volumetric charge, or one based on time-of-use pricing.
The ISO on Tuesday held a stakeholder working group on the proposed TAC changes outlined in a June 30 issue paper. Neil Millar, CAISO executive director of infrastructure development, said during the meeting that because transmission charges are applied both to energy provided from central stations and DG, the cost of delivering energy is ignored, creating an inefficient market.
“It distorts cost allocation, distorts energy markets [and] costs money,” Millar said. Transmission costs are also rising, making dealing with the issue a “political necessity.”
Graph of Declining Load Factor of California Investor-Owned Utilities | Energy Policy Initiatives Center; California Energy Commission
CAISO also considered changing another settlement process that uses a volumetric rate for wheeling power to loads off the ISO-controlled grid, but it put it on hold after talking with stakeholders and deciding the initiative had “a number of complex and controversial issues.”
Moving the point where transmission usage is measured would solve a lot of the issues, according to Millar. To address the issue, the ISO is considering a Clean Coalition proposal that would rely on gauging hourly net load at each transmission-distribution interface substation, referred to as “transmission energy downflow.”
In an effort to place some boundaries on the proposal, CAISO plans to remove some other topics that are broad in scope regarding the TAC. Among those initiatives were an assessment of current regional and local transmission charges that are recovered through a postage-stamp rate and an analysis of the ISO’s role in collecting the TAC. Other topics to be postponed are alternative types of transmission service. CAISO said it would study other regions and some other proposals put forth by stakeholders.
CAISO plans to issue a straw proposal on the TAC changes by Oct. 31, followed by a Nov. 15 stakeholder call. A final proposal will be submitted to the ISO Board of Governors sometime in 2018.
The grid operator earlier developed a proposal to allocate transmission costs over an expanded balancing area if the ISO integrates new members such as PacifiCorp. (See CAISO Floats Latest Cost Allocation Plan for Expanded Balancing Area.) That proposal has been shelved until CAISO expands into other regions of the West.
Ameren Illinois may have hit a roadblock in its efforts to lower its energy efficiency targets prescribed under a new law.
Illinois Commerce Commission Administrative Law Judge Jan Von Qualen on Tuesday issued a preliminary order (17-0311) denying the utility’s request to lower its energy efficiency goals established under the state’s recently enacted Future Energy Jobs Act (FEJA). The ICC is expected to render a final decision on the request by mid-September.
Under the law, Ameren is required to meet 9.8% in cumulative annual energy savings by 2021, but the utility is planning for 8.24% in savings. The utility has allocated $114 million per year for the program, the maximum budget under the law, but claimed it still could not meet the savings goal. A maximum budget triggers the ICC’s authority to reduce annual incremental savings goals.
“Based on the record, the commission finds that [Ameren] should modify its plan in a manner that ensures cost efficiencies and serves the customers, including low-income customers, to the maximum extent practicable throughout its service territory,” Von Qualen said. “The commission will not modify the [annual savings] goal absent a showing that every attempt has been made to meet the goal and it cannot be met.”
The Illinois Clean Jobs Coalition, along with other environmental and consumer activists, last month held a press conference to criticize Ameren for setting low energy efficiency goals and to urge state regulators to reject the utility’s four-year efficiency and demand response plan. (See Ameren Illinois Criticized for Lowered Energy Efficiency Goals.)
Von Qualen said the state attorney general’s office — as well as the Citizens Utility Board, Environmental Defense Fund and the Natural Resources Defense Council — provided multiple suggestions in testimony regarding how Ameren could meet its annual savings goal “while staying within the budget cap.”
The judge suggested that Ameren reallocate its optional $6 million per year efficiency research and development spending to programs that actually lower costs per kilowatt-hour. She also said the utility could use a portion of the $4.7 million budgeted for air conditioners on more cost-effective programs. The judge directed Ameren to work with the Illinois Energy Efficiency Stakeholder Advisory Group, the Economically Disadvantaged Advisory Committee and the Illinois Home Weatherization Assistance Program to make better use of its required $8 million in spending on third-party energy efficiency implementation programs, instead of using national retailers and online stores.
She did approve other aspects of Ameren’s plan, including savings goals for its gas program and riders for the recovery of electric energy efficiency costs.
Ameren: No Change
Ameren defended its plan and said it has no plans to change its filing in light of the proposed order.
“We have put forth the right plan to help working families in our territory save energy and we look forward to making our case with the Illinois Commerce Commission,” Ameren Illinois spokesperson Marcelyn Love told RTO Insider.
Ameren Illinois linemen at work in 2017 | Ameren Illinois
Ivan Moreno, communications manager of the Natural Resources Defense Council, said Ameren has been heavily lobbying state legislators to lean on the ICC to approve the plan.
“This is unusual given that legislators have already debated and voted on this issue through the Future Energy Jobs Act,” Moreno said, adding that he expects Ameren to escalate efforts to get the ICC to approve the plan “despite the proposed order.”
The Illinois Clean Jobs Coalition welcomed the preliminary ruling: “As the Illinois Clean Jobs Coalition has said from the start, Ameren should be able to deliver energy efficiency programs that serve low-income communities and — at the same time — achieve the energy efficiency targets that the company agreed to under FEJA. We are hopeful that members of the Illinois Commerce Commission will agree with the judge in this case.”
The group said it looked forward to working with Ameren on a new plan “that meets the goals set forth in FEJA which can create jobs, savings and better health across Illinois and, in particular, deliver benefits to economically disadvantaged communities throughout the state.”
SACRAMENTO, Calif. — A key California State Assembly committee on Wednesday advanced a Senate bill requiring publicly owned utilities in the Los Angeles Basin to support deployment of distributed energy resources and energy storage.
The Committee on Appropriations approved SB 801, which now goes to the full Assembly for a vote.
The legislation was drawn up by State Sen. Henry Stern (D) in response to the 2015 leak that resulted in the closure of the Aliso Canyon natural gas storage facility. Many area residents are trying to get the facility closed permanently, but owner Southern California Gas recently resumed gas withdrawals after a court battle. (See Aliso Canyon Resumes Injections.)
Stern noted that investor-owned utilities Southern California Edison and San Diego Gas & Electric deployed energy storage quickly after the blowout, which threatened to compromise fuel deliveries to the region’s gas-fired generators.
“However, publicly owned utilities in the area have not yet adopted the same aggressive approach to clean energy storage and other safe reliability solutions in response to Aliso Canyon,” Stern said.
If passed, the measure would require the Los Angeles Department of Water and Power (LADWP), which serves 250,000 customers, to make data available that would help DER providers identify solutions to increase reliability in the region. It also requires LADWP to maximize use of demand response, renewables and energy efficiency in the area where reliability has been impacted by the Aliso Canyon outage.
The bill would allow LADWP to offset any ratepayer expenses with fines or fees levied over the leak against SoCalGas and its parent company Sempra Energy.
It would also require LADWP to study deployment of 100 MW of energy storage and oblige SCE to deploy 20MW of storage by June 1, 2018.
Stern has called the reopening of Aliso Canyon “premature and unnecessary.” California Energy Commission Chairman Robert Weisenmiller has said the facility should be closed permanently.
The committee also suspended until Friday a vote on SB 100, which mandates that the state’s utilities procure 100% of their electricity from zero-carbon resources by 2045. The Senate in May approved the legislation introduced by Senate President pro Tempore Kevin de León, a Los Angeles Democrat. (See California Senate Passes Bill Mandating 100% RPS.)
FERC on Tuesday approved a MISO pilot program allowing the RTO to share information on power plants’ gas use with pipeline operators (ER17-1556-001).
Starting in December, MISO will share day-ahead hourly burn estimates from gas-fired generators with a trio of gas operators: Northern Natural Gas, ANR Pipeline and DTE Energy. The RTO says the program will help ensure adequate fuel supplies for gas plants.
DTE’s Washington 10 Complex near Detroit | DTE Energy
FERC agreed that the program complies with the communications permitted in Order 787.
“We find that MISO’s proposal to extend the information sharing provisions to LDCs [local distribution companies] and intrastate natural gas pipeline operators will help ensure and optimize the reliable operation of the grid, particularly during the winter months where demand for natural gas is strongest,” the commission said.
The commission noted that Order 787 encouraged grid operators to make Tariff filings “to facilitate greater sharing of nonpublic, operational information with entities such as local distributions companies.”
“We note that the proposed revision will improve communication and coordination among MISO and operating personnel of the interstate natural gas pipeline companies in the MISO region to ensure that MISO and interstate natural gas pipeline control room operators have better information on which to base operating decisions,” FERC said.
The acceptance comes after FERC in June issued MISO a deficiency letter in response to an earlier version of the proposal. The letter noted that the pilot lacked a no-harm clause and that the RTO failed to justify its reason for sharing confidential information with LDCs, which FERC must approve on case-by-case basis. (See FERC: MISO Gas Data Sharing Plan Falls Short.)
In response, MISO amended its filing with language borrowed from PJM that expressly states that any shared information will not be used “to the detriment of any natural gas and/or electric market.” MISO also contended communication with LDCs is crucial because about 25% — or 12,511 MW — of the RTO’s gas-fired capacity is served by the companies.
FERC accepted both responses, saying that MISO’s use of nondisclosure agreements and restrictions placed on shared data “minimizes the opportunity that the information can be used in an unduly discriminatory or preferential manner by the recipient or to the detriment of the market.”
The commission rebuffed Indianapolis Power and Light’s protest against the pilot. The utility asked that MISO not be allowed to “grant itself the ability to provide proprietary data to anyone without the expressed consent of the generation owner.” FERC, however, noted that Order 787 did not require “three-way communications” for such programs.
Some MISO stakeholders earlier this year voiced opposition to the pilot, saying it could affect reliability if participating gas operators make burn rate decisions relying solely on partial day-ahead data. (See MISO Stakeholders Question Electric-Gas Info Sharing.)
A new study prepared for the American Coalition for Clean Coal Electricity (ACCCE) spotlighting the “resiliency” of coal-fired generators echoes the findings of a U.S. Department of Energy report released earlier this month.
Although the study by PA Consulting Group concludes that “no single electricity resource has all of the attributes necessary for a reliable and resilient grid” and that “a mix of resources is the best strategy,” it lauds coal generation for its “many critical attributes,” including stable fuel prices and an on-site fuel supply that can act as a hedge against potentially volatile natural gas prices, interruptible fuel deliveries and intermittent renewable and demand response resources.
Coal stockpile | Worldcoal.org
The study’s release may prove to be an early salvo in the possible “fuel wars” predicted by one former senior FERC official who said that new FERC commissioners could break with agency tradition by each acting as advocates for favored types of resources. (See Coal Seeks ‘Resiliency’ Premium; FERC ‘Fuel Wars’ Coming?)
The study ranked generation resources on 11 attributes, giving coal high marks in all but black start capability.
The report is effectively a response to a study done by The Brattle Group for the American Petroleum Institute (API), which concluded that gas-fired generation is “relatively advantaged” in all but one of the 12 attributes identified in that study. (See NG Lobby Goes on Offensive vs Coal, Nukes.)
The API/Brattle report ranked coal as only “neutral” on two categories for which ACCCE claimed a full score — frequency response and ramp rates (referred to as “ramp capability” by ACCCE).
API did not score three categories in which ACCCE said coal had an advantage over gas: on-site fuel supply, reduced exposure to a single point of disruption and price stability.
“This new report shows the coal fleet is essential to help maintain the reliability and resilience of the electricity grid,” said ACCCE CEO Paul Bailey. “For that reason, we are especially supportive of DOE’s recent recommendation that policymakers need to establish criteria to value attributes, such as on-site fuel, that help protect the grid against low probability events that have extreme consequences.”
Bailey said he looked forward to “working with policymakers to implement DOE’s recommendation as quickly as possible” that RTOs begin valuing on-site fuel storage as a measure of “resiliency.” (See Perry Grid Study Seeks to Aid Coal, Nuclear Generation.)
Natural Gas Criticisms
The report took particular aim at natural gas-fired generation, coal’s biggest competitor. According to the report, coal generators on average stockpiled 82 days of bituminous coal and 73 days of subbituminous coal on site over the last five years. It compared that to the position of “vulnerable” gas-fired plants, which last year on average had about 60 days of fuel in storage reserves and rely on interruptible deliveries via pipeline.
| ACCCE
It also pointed out that low-probability, high-impact events like earthquakes can cause supply shocks in the gas distribution network. More than 50% of gas storage capacity is located in five states — Michigan, Texas, Louisiana, Pennsylvania and California — PA Consulting warned, and 18 states in the continental U.S. have “no material storage capability,” including New England and North Carolina, South Carolina, Georgia and Florida.
The study also said that because most U.S. coal is used for electricity, coal-fired generation “does not compete with higher-priority uses” and will not have to be forcibly curtailed. It also pointed out that “all but two lignite coal-fueled plants [in the U.S.] source their coal from mines within 30 miles of the plant.”
The popularity of gas-fired generators relies on the continuation of low-cost shale natural gas, the study contends.
“The current investment boom in natural gas-fired plants is driven in part by an expectation of continued low natural gas prices of approximately $3-4/MMBtu,” the study said. The 77 GW of gas-fired capacity built since 2009 might be a result of an “over-focus on short-term price signals,” the authors contend.
Over the last decade, monthly average natural gas prices have “repeatedly seesawed” from $3/MMBtu to more than $12/MMBtu, reaching $100/MMBtu in some markets during the so-called “polar vortex” of 2014, the study noted. It also pointed to dramatically fluctuating gas prices during 2015’s Aliso Canyon leak and an extreme cold front in Texas in 2011 that caused 193 generating plants to either fail outright or experience weak output.
“Retaining existing coal-fueled power plants can help insulate ratepayers against rising and possibly volatile natural gas prices,” the report said.
NYISO locational-based marginal prices (LBMPs) have averaged $36.35/MWh for the year through July, a 12% increase from a year earlier, COO Rick Gonzales told the Management Committee during its Aug. 30 meeting. Natural gas prices were up 13.1% over the same period.
LBMPs averaged $35.84/MWh during July, up 13% from June and down 10% from July 2016. Last month’s daily sendout averaged 498 GWh/day, compared with 532 GWh/day a year earlier.
July natural gas prices and distillate price averages gained from the previous month, with Transco Z6 NY gas up 4% to $2.44/MMBtu, jet kerosene Gulf Coast up 9% to $10.49/MMBtu and NY Harbor ultra-low sulfur No.2 diesel up 7% to $10.85/MMBtu. Distillate prices increased 11.1% from the same period a year ago.
| NYISO
Average uplift costs — not including NYISO cost of operations — were down to -43 cents/MWh for the month, compared with -37 cents/MWh in June. The local reliability share fell 4 cents to 11 cents/MWh. The statewide share of -54 cents/MWh came in 2 cents below June. July’s total uplift costs were also lower than in June.
The monthly peak load of 29,699 MW occurred July 19, far short of the all-time summer peak of 33,956 MW recorded on July 19, 2013.
NYISO Evaluates Energy Market Offer Cap
The ISO is continuing to evaluate its energy market offer cap to prevent differences in regional offer caps from interfering with economic and reliability-driven interchange scheduling, according to a report presented by NYISO Senior Vice President for Market Structures Rana Mukerji.
NYISO’s control room | NYISO
Under FERC Order 831 issued last November, NYISO is required to cap each resource’s incremental energy offer at the higher of $1,000/MWh or that resource’s verified cost-based incremental energy offer, and cap verified cost-based incremental energy offers at $2,000/MWh when calculating LBMPs. The grid operator last December filed a request for clarification/rehearing on the issue with FERC and submitted a compliance filing in May.
Mukerji also noted that the ISO is working to improve forward horizon coordination of real-time constraints (RTC) and real-time dispatch (RTD). NYISO aims to improve modeling consistency between RTC and RTD and evaluate improvements in look-ahead evaluations to facilitate more efficient scheduling and price convergence.
Pending issues include possible proposals to allow market participants to buy and sell reserves and regulation service between NYISO and adjacent control areas and to develop a market mechanism to assign external parties with the costs associated with congestion rent shortfalls resulting from external transmission outages.
The ISO is also examining the reciprocal elimination of fees on export transactions in order to increase interregional transmission scheduling efficiency. Rate pancaking between NYISO and ISO-NE has already been eliminated.
Interconnection Queue Improvements Approved
The committee approved steps intended to improve the efficiency of the interconnection queue process while maintaining needed reliability evaluations.
The proposed changes clarify and update existing practices and procedures, except for the transmission interconnection procedures, which are still pending FERC acceptance. Transitional rules would allow projects currently in the interconnection process to benefit from the proposed changes. (See “Committee Advances Interconnection Queue Improvements,” NYISO Business Issues Committee Briefs: Aug. 9, 2017.)
NYISO expects to file associated Tariff changes with FERC in late September following board approval.
New York Easily Handles Solar Eclipse
NYISO easily met operational reliability criteria throughout the solar eclipse Aug. 21, despite a 1,010-MW reduction of net load that exceeded predictions by nearly 300 MW, according to a report from NYISO Vice President of Operations Wes Yeomans.
The ISO did not experience the slight projected load increase early in the eclipse, possibly because of lower loss of behind-the-meter solar than originally anticipated, as well as public reaction to the event. He attributed the higher-than-expected net load increase later in the eclipse to high humidity.
New York experienced a partial solar eclipse from 2:30 to 2:45 p.m., with peak obscuration ranging from 80% in Chautauqua County, to 75% in New York City and Long Island and 67% in Clinton County.
California utilities and state agencies are cooperating on developing plans to manage the effects of global climate change on the electricity grid, an issue that looms especially large for the state.
Rising sea levels, reduced snowpack, more wildfires and extreme weather events such as drought and severe rain are predicted for California, which experts say will be more affected by global warming than other states because of its warm climate and extensive coastline.
Partnership between state officials, local government and utilities was the theme at a Tuesday workshop hosted by the California Energy Commission. Participants discussed the physical impacts of climate change on the grid, geophysical changes, temperature trends and the challenges facing vulnerable populations.
State law requires the CEC to assess and forecast the state’s energy production, supply and demand, and develop policies that conserve resources. The agency is studying climate change impacts on the energy grid as part of its 2017 Integrated Energy Policy Report process, which is updated every year and adopted every two years.
Pacific Gas and Electric is a critical infrastructure company with 16 million customers and a “critical responsibility,” said Melissa Lavinson, vice president of federal affairs and policy. The company is getting more requests from local governments for information on its efforts to prepare for climate change, she said.
PG&E favors a regional approach to the issue that would help with coordination, rather than going community by community. The utility has proposed a “climate resilience clearing house” to aggregate information and a regional governing body to coordinate local governments.
“We are far from the end of this process. We are at the beginning of this journey,” she said.
San Diego Gas & Electric is in the midst of a “Climate Vulnerability and Adaptation Options” study consisting of both electric grid and natural gas tracks, Sempra Energy Meteorologist Brian D’Agostino said. The electric analysis looks only at the effect of the rising water level and flooding on the coast where many of the company’s power plants are located, while the natural gas program also looks at climate hazards inland. The report also highlights downstream impacts on customers, electricity demand and the economy.
Historic and Project State-Wide Temperature | California Energy Commission
PG&E is working with the University of California, Berkeley and the California Department of Water Resources on a program to deploy wireless remote sensors to study moisture, temperatures and snowpack and more effectively manage hydro assets, said Gary Freeman, the company’s principal hydrologist. The company closely studies weather and increasing “atmospheric rivers,” which are columns of moisture that occur in the atmosphere and can dump large amounts of rain.
Atmospheric rivers hundreds of miles wide occur in California because of the Pacific Ocean and mountains that cool the air as it travels inland. The formations provide up to 50% of the annual precipitation on the West Coast, and their increasing activity is another example of how climate change affects grid planning and reliability in a region with extensive hydroelectric capacity.
Gov. Jerry Brown in April 2015 signed an executive order that set 2030 greenhouse gas reduction targets that were recently codified into law. (See California Lawmakers Extend Cap-and-Trade.) The state has also developed online tools providing climate change data, including climateconsole.org and cal-adapt.org.
American Transmission Co. has agreed to pay a federal fine and undergo a year of monitoring after failing to properly report more than 60 agreements and transactions to FERC over the past 16 years.
Under an agreement reached with FERC’s Office of Enforcement, Milwaukee-based ATC will pay a civil penalty of $205,000 to the U.S. Treasury and submit semi-annual compliance monitoring reports for one year detailing any further violations (IN17-5).
ATC headquarters in Milwaukee | Mortenson Construction
The office found that ATC repeatedly failed to seek approval to merge or acquire FERC-jurisdictional facilities and to file “timely” contracts and agreements relating to rates and charges for jurisdictional service.
“Enforcement determined that, although ATC’s violations did not result in quantifiable market harm, they created a lack of transparency in the market by failing to have all of ATC’s jurisdictional agreements on file with the commission, and by consummating purchases of commission-jurisdictional assets without commission authorization,” the commission said.
In an internal review of its filing processes during 2014 and 2015, ATC discovered 63 instances in which it failed to either properly report or file information starting in 2001.
Those include several agreements that it failed to file pursuant to Federal Power Act obligations, relating to operations, transmission design on shared 345-kV projects, pole replacements, repairs on jointly owned substations, transmission line relocation and ownership, and cost-sharing for jurisdictional facilities. ATC in some cases also neglected to file notices to terminate existing agreements. The company has already paid $1.4 million to several affected parties in time-value refunds.
The company also identified 21 jurisdictional facilities it acquired without gaining FERC approval. The facilities range in value from $1,513 to $1.2 million. FERC retroactively approved each transaction after ATC sought permission between 2014 and 2015.
Section 203 of the FPA requires public utilities to file for FERC authorization to merge or acquire jurisdictional facilities, and Section 205 requires public utilities to file “all contracts which in any manner affect or relate to such [jurisdictional] rates, charges, classifications and services.”
FERC said that, since discovering the violations, ATC has taken steps to “strengthen its compliance policies and procedures and to prevent noncompliance in the future regarding jurisdictional agreements,” holding employee training seminars, updating training documents and developing an internal review process to make sure the company has proper authorization.
Great Plains Energy has pulled back from its attempted acquisition of Westar Energy, recasting the move as a “merger of equals” after the two companies last week asked Kansas regulators for permission to merge under a tax-free share exchange.
The Kansas Corporation Commission blocked an earlier version of the deal in April, criticizing the $60/share purchase price as too high. (See Westar Shares Fall as Kansas Regulators Block Great Plains Deal.) Shareholders are poised to gain less in the new, stock-for-stock proposal.
| Great Plains and Westar
Under the new proposal, Great Plains would no longer become Westar’s parent company. Instead, the two companies would combine under a $14 billion holding company operating in Kansas and Missouri. Westar shareholders would own about 52.5% of the company with Great Plains shareholders holding the rest, according to the amended merger application (18-KCPE-095-MER).
The new deal would entail no cash exchange or transaction debt, and retail customers would receive $50 million in upfront bill credits across all rate jurisdictions. The combined company would serve about 1 million customers in Kansas and almost 600,000 customers in Missouri.
The two companies are expected to retain their original names after the merger, and Westar will continue to maintain an operating headquarters in Topeka, Kan., staffed by 500 employees. The companies have pledged not to lay off any employees. Corporate headquarters for the merged company would be located in Great Plains’ Kansas City, Mo., location.
The plan requires approval from both the KCC and the Missouri Public Service Commission. The companies will also file applications before FERC and the Nuclear Regulatory Commission as early as this week and will seek respective shareholder approval during the fourth quarter. If approved, the deal is expected to close in the first half of 2018.
The CEOs of both companies say the revised agreement represents savings for customers and an opportunity for long-term growth for shareholders, while better positioning the companies to invest in infrastructure.
“We carefully listened to the KCC’s concerns with our original transaction and crafted a new merger agreement using the KCC’s earlier order for guidance to bring better value to customers and shareholders of both utilities compared with remaining standalone,” said Great Plains CEO Terry Bassham.
Westar CEO Mark Ruelle called the merger “a long and unpredictable path” during a second-quarter earnings call in early August: “We spent a lot of time in May and June confirming that there wasn’t just a stop sign in the order, but also road map to approval. … It wasn’t the course on which we first set out, but I’m pleased where it’s taken us and encouraged by the value it creates for our customers and our shareholders. The KCC order was clear that a big premium deal was going to be problematic.”
Fewer Future Rate Cases
In testimony to support the filing, Ruelle said that without a merger, Westar’s “flat sales and rising costs” will translate into higher prices. Bassham testified along similar lines, saying that “costs to serve … customers will continue to rise unchecked” and absent a merger, Great Plains “would need to seek higher prices and more frequent price increases as the remedy for any unmitigated higher costs.”
Both CEOs claim the merger will lessen the need for future rate cases.
“With the merger savings, we’ll no longer be as dependent on rate cases to produce earnings,” Ruelle said during the earnings call.
In early August, Great Plains posted a second-quarter loss of $22.1 million ($0.10/share), while Westar announced earnings of $72 million ($0.50/share), in line with last year’s second-quarter results.
AUSTIN, Texas — With Hurricane Harvey rapidly gaining strength in the Gulf of Mexico and threatening the Lone Star State, ERCOT’s Technical Advisory Committee on Thursday focused on three tabled revision requests and appeals before quickly scattering to their homes and work.
“Be safe,” urged TAC Co-Chair Bob Helton, of Dynegy, as he adjourned the meeting.
Committee members did approve one of the three tabled issues, passing a nodal protocol revision request (NPRR768) after staff filed comments most could agree to. The NPRR was the subject of vigorous debate during the July TAC meeting but was passed this time with only Shell Energy and Sharyland Utilities abstaining. (See “EEA Price Adder Change Tabled,” ERCOT Technical Advisory Committee Briefs: July 27, 2017.)
The revision request adds real-time DC tie imports and exports through registered block load transfers to the list of ERCOT-initiated actions that trigger a price adder to ensure that prices reflect scarcity conditions.
Staff revised the language to cap the total adjustment for DC tie imports at 1,250 MW, the current capacity of all DC ties.
That was enough to placate the Texas Industrial Energy Consumers group, which has opposed the measure throughout the stakeholder process.
“We have a philosophical disagreement about whether this is appropriate,” said Katie Coleman, legal counsel for TIEC. “Rather than continue fighting about that, we got comfortable about moving this forward with a megawatt limit on it.”
Shell’s Greg Thurnher called the revised language a “nice compromise” and a “step in the right direction” to support scarcity pricing signals, but said he wasn’t sure “every adder is a good adder.”
“This one has a lot of fine print,” Thurnher said. “We’ve had some growth in traditional [DC ] ties that could be excluded for the circumstances it’s trying to prevent. We’ve arrived at the solution, but I’m not sure it’s a good one.”
NPRR768 does not address the Southern Cross Project, a proposed HVDC transmission project that would transport more than 2 GW of electricity from Texas to Southeastern markets. Several stakeholders agreed that is a discussion for a later date.
“When we wrote this, we tried to recognize what exists today,” said Kenan Ögelman, ERCOT’s vice president of commercial operations. “We don’t believe it’s biased toward anything. Our process allows the accommodation of whatever the future is going to be. This was our effort to put something forward to get to a compromise and recognize some of the concerns.”
Shell filed comments to ERCOT’s revisions, suggesting modifying the NPRR to restrict price correction to imports ordered on DC ties classified as transmission facilities. Cratylus Advisors’ Mark Bruce, speaking for Southern Cross, disagreed with the change.
“It seems pretty clear to us that once the Southern Cross project is interconnected to the ERCOT network, it will be a transmission element by definition, which means the definition of a transmission facility has to be amended to include it,” Bruce said. “Shell’s comments don’t really change anything. It actually opens it up and includes Southern Cross when it goes live.
“The ERCOT approach, on its face, is sort of less discriminatory. It doesn’t really start distinguishing between transmission facilities based on regulatory classification or ownership structure of the facility, which in our view isn’t a permissible way to go about this. In our view, this is either a good policy, [and] you put the megawatts in the calculation, or it’s not good policy, and you don’t.”
“Our intent was to impose a limit,” Thurnher responded. “The protocols get tricky when they define things. I think of Southern Cross as a load sometimes and a generator sometimes, neither of which are transmission assets. If Southern Cross gets built, then this needs to be revisited.”
Said Coleman, “We are intentionally leaving that for future discussion.”
CRR Deration Remanded Back to Subcommittee
The TAC unanimously remanded back to the Protocol Revision Subcommittee NPRR821, which failed to pass the committee in July after substantial discussion, to reconcile “three very different” modifications proposed by stakeholders.
The revision request would eliminate the reduction of congestion revenue rights (CRR) payments, or deration, by reversing the day-ahead market’s deration-settlement mechanism. The mechanism, which was introduced to deter market manipulation, has resulted in large financial losses to generators.
The deration price for a CRR path is determined at the constraint level and applied to the CRR payout. Payments can be derated if transmission elements are oversold, the target payment is a positive value, or the CRR source or sink is a resource node.
The Lower Colorado River Authority filed two proposed adjustments to NPRR821 following a $1.9 million loss in 2016 that it called “unusual and unique.” LCRA said it worked with ERCOT and others in attempting to find a balance between low impact and low implementation cost.
The company’s preferred solution was linking the CRR’s holder and the point-to-point (PTP) obligation of the qualified scheduling entity on the same path. It suggested linking the PTP price to the corresponding CRR value if a PTP obligation bid is awarded to a QSE with a CRR. If the CRR is derated, the PTP bid’s settlement price is matched to the CRR’s derated value.
The second option would cap the PTP’s value at the derated CRR’s value on the same path.
“It’s clear a lot of folks still have a learning curve with how this process works and the way the money flows,” said LCRA’s Randa Stephenson. “If it’s TAC’s will to send this back, please be ready to vote on this. This is going to be an issue that comes back to us.”
ERCOT staff agreed and volunteered to put together a presentation detailing all the proposed modifications.
“I just want to make sure everything’s clear,” Ögelman said, noting that LCRA’s proposal considers PTPs, not CRRs. “People need to look at all of these things to understand all of the mechanisms.”
DC Energy’s suggestion to add a “circuit-breaker” lowering the capacity offered in the CRR monthly auctions when the balancing account reaches zero at the end of any month drew positive feedback from several stakeholders.
“It’s a little bit more protection for our customers,” said Austin Energy’s Barksdale English.
Under DC Energy’s proposal, the CRR balancing account would be allowed to rebuild its value before reverting to the 90% capacity offering status quo.
Morgan Stanley offered the third proposal, which it said would “level the playing field” for all CRR participants by making short pays equivalent, regardless of the source or sink of the owned CRRs. Eliminating the current process — which covers hub and load zone CRRs and provides hedge value for those instruments involving resource nodes (well over half of these shortfalls) — would eliminate the expense created for load, the company said.
“There was a request to try and narrow the NPRR, and this narrows the application as far as you can get it,” said Morgan Stanley’s Clayton Greer, whose first preference was either the original NPRR or DC Energy’s proposal. “It actually eliminates all short-pay recoveries and hedge payments entirely. The retail segment argued that derate support was being done on the backs of load. If that’s the case, then all derate coverage would be on the backs of load.”
The Protocol Revision Subcommittee (PRS) plans to return with new language for NPRR821 in September.
Small Municipalities’ Appeal Tabled Again
The committee once again tabled the Small Public Power Group of Texas’ (SPPG) appeal of a rejected revision to the Nodal Operating Guide (NOGRR149) regarding the definition of transmission owners. In granting a six-month extension until February, the TAC agreed to take up the “substance of the appeal” at that time.
The revision would exempt distribution service providers without transmission or generation facilities from having to procure designated transmission operator services from a third-party provider if their annual peak load is less than 25 MW. The proposal was developed in 2015 to settle the noncompliant status of six municipally owned utilities with loads from 9 to 21 MW.
The SPPG has been filing monthly updates since the appeal was last tabled in January. In its most recent, the group said, “significant progress has been made” in reaching permanent market solutions for its members’ designated TO service, but they have not yet been achieved.
“All of these have been proceeding as hard and as fast as they can,” said Tom Anson, legal counsel for SPPG. “These things take more time than you think. We want another six months to keep working hard at it.”
The appeal has now been tabled eight times since it was first brought to the TAC in March 2016, shortly after it failed to pass the Reliability and Operations Subcommittee.
PRS Adds Resource Definition Task Force
The PRS brought forward two unopposed NPRRs and announced the formation of the Resource Definition Task Force. The task force, chaired by Vistra Energy’s David Ricketts and ERCOT’s Jay Teixeira, will work to synch up the ISO and Public Utility Commission of Texas’ definitions.
The TAC tabled NPRR829, one of two unopposed revision requests, to allow ERCOT time to refresh its initial impact statement. Staff said it believes the second impact statement, which should be complete for the next PRS meeting, will come in above the current $120,000 to $160,000 estimate to implement.
NPRR829 requires the use of telemetered data from non-modeled generation in the day-ahead market to more accurately calculate QSE collateral requirements. The change will increase day-ahead liquidity through the increased participation of non-modeled generation, and potentially allows ERCOT to gain near real-time transparency into the generation.
The committee unanimously approved NPRR836, which incorporates the following “other binding documents” into the protocols as a new Section 23 (Forms): Congestion Revenue Right Account Holder Application Form, Load Serving Entities Application Form, Managed Capacity Declaration Form, Market Participant Agency Agreement Form, Notice of Change of Information, QSE Agency Agreement Form, QSE Application Form, Qualified Scheduling Entity Acknowledgement, Resource Entity Registration Form, Transmission/Distribution Service Provider Registration Form and WAN Agreement.
Changes to these Section 23 forms will be made using the NPRR process.
