FERC on Friday voted 2-1 to reject a CAISO proposal intended to prevent small transmission owners from shouldering the costs for network upgrades needed to interconnect generation serving load outside of their service territories.
The proposal was designed specifically to address the circumstances of Nevada-based Valley Electric Association, the California grid operator’s only out-of-state member. The electric cooperative serves 45,000 customers and peak demand of 135 MW within a 6,800-square-mile territory straddling the California-Nevada border.
| Valley Electric Association
FERC’s decision means Valley Electric’s ratepayers potentially face the cost of interconnecting almost 4,000 MW of solar resources that would help support California’s renewable portfolio standard. The cooperative has 25 requests totaling 3,952 MW of new capacity in its interconnection queue.
CAISO conducted a seven-month stakeholder process to develop the proposal to certify Valley Electric as a small participating transmission owner (PTO) and distribute its interconnection costs across the broader ISO. (See Board Approves CAISO Small TO Generator Interconnection Plan.)
The rule changes would have folded low-voltage generator interconnection costs into high-voltage transmission revenue requirements, spreading costs among the ISO’s entire ratepayer base. San Diego Gas & Electric had cited a concern that CAISO’s solution did not meet FERC cost allocation rules and Southern California Edison opposed the proposal.
“In the past, CAISO has justified its cost allocation methodology by explaining, with supporting evidence, that low-voltage facilities generally support local service and that the high-voltage transmission facilities perform a backbone function that supports regional flows of bulk energy,” FERC said (ER17-1432).
The ISO was now asserting “without supporting evidence” that low-voltage upgrades on Valley Electric’s system — but not those on the systems of Pacific Gas and Electric, SCE and SDG&E — benefit customers throughout the region, the commission said.
“CAISO’s proposal is inconsistent with the commission’s cost causation principles because it shifts costs from a single PTO to all load in CAISO without providing evidence that CAISO transmission system users being allocated such costs benefit from the network upgrades to Valley Electric’s low-voltage transmission system,” FERC said.
“Of additional concern is CAISO’s proposal to allow stakeholders to decide whether to grant alternative certified small PTO rate treatment; stakeholders are interested parties that may be impacted by the determination that a PTO should become a certified small PTO.”
Commissioner Cheryl LaFleur dissented in the ruling.
“It is simply unfair to require the 0.27% of CAISO’s customer base in Nevada to bear the costs of these interconnections, which are not remotely commensurate with the benefits they receive,” she said. “Rather, I believe the customers in California, whose policies are driving the costs, should largely bear the burden of these costs. The CAISO proposal achieves that objective in a pragmatic way.”
In June, FERC staff sent CAISO a deficiency letter asking for a better definition of CAISO’s criterion for designating a certified small PTO and how transmission customers will benefit from low-voltage interconnection network upgrades in Valley Electric’s service territory.
CAISO did not immediately respond to a request for comment. In comments previously filed with FERC, the ISO said Valley Electric faced the risk of being allocated all of the costs for network upgrades necessitated by other utilities’ procurement efforts, and that similarly situated small TOs potentially could face the same situation.
The Public Utility Commission of Texas last week gave preliminary approval to Oncor’s and Sharyland Utilities’ proposed swap of $400 million in assets.
The order lists a set of 27 issues to be discussed before the PUC renders a decision, which is due by Feb. 1, 2018 (Docket 47469).
Oncor and Sharyland filed a settlement agreement early last month, asking the PUC to expedite the case by deciding it without referring it to the State Office of Administrative Hearings (SOAH). The companies said Sharyland’s current retail customers will receive “substantial rate relief” under the transaction, in which Sharyland will take over 258 miles of 345-kV transmission from Oncor in exchange for Sharyland’s distribution network and retail delivery customers.
“The hard work that’s gone into this is going to significantly change people’s lives,” said Commissioner Brandy Marty Marquez. “I’m happy this is all proceeding.”
Among those signing on to the settlement agreement are commission staff, the Office of Public Utility Counsel (OPUC), the Steering Committee of Cities Served by Oncor, the Alliance of Oncor Cities, numerous other Texas cities and various electric retailers. The Texas Industrial Energy Consumers (TIEC), the Targa Pipeline Mid-Continent WestTex and Golden Spread Electric Cooperative chose not to oppose the settlement.
An administrative law judge set Tuesday as the deadline to request a hearing in the docket.
The settlement would also resolve Sharyland’s separate applications to deploy an advanced metering system (Docket 44361) and requests for rate relief and a certificate of convenience and necessity (Docket 45414), and Oncor’s application to change its rates (Docket 46957).
“This will ultimately solve a lot of problems for a lot of folks,” said Commissioner Ken Anderson.
Commissioners Undecided on LP&L’s Contested-Rate Case Request
The PUC postponed a decision on how to process Lubbock Power & Light’s request to move 430 MW of its load from SPP into ERCOT. The commission is considering whether to treat the request as a contested case or refer it to SOAH, where it would be heard before an ALJ.
The commissioners will announce their decision during their Sept. 28 meeting, after reviewing a draft preliminary order (Docket 45633).
“I’m fine going to SOAH,” Anderson said. “The other tradeoff, in terms of time, is SOAH may be able to handle getting the facts. It handles much of discovery anyway.”
“If we send it to SOAH, the judge won’t do much of anything until the preliminary order comes out,” Marquez said.
LP&L is hoping for a decision before March 2018, which will enable it to maintain its plan to integrate with ERCOT by June 2021. The municipality announced its intention in 2015 to disconnect its load from SPP and join ERCOT in June 2019. That that date has since slipped, but LP&L extended a power purchase agreement with Southwestern Public Service through May 2021.
The preliminary order will allow the PUC to decide policy questions over load migrations “by putting a framework around what needs to be decided,” Anderson said.
“A ‘Hotel California’ clause in the order might be appropriate,” he said, referring to the Eagles’ lyric, “You can check out any time you like, but you can never leave!”
“Going back and forth between ERCOT and other regions is, at best, disruptive, not to mention expensive,” Anderson said.
ERCOT, SPP Agree to Rayburn Country Migration Studies
Rayburn Country Electric Cooperative representatives told the commissioners they are comfortable with ERCOT’s and SPP’s proposed scope and timeline for their studies of the East Texas co-op’s proposed transfer of much of its SPP transmission facilities and load into ERCOT (Docket 47342).
The grid operators said they would conduct individual studies using a common scope and assumptions, including an analysis of system impacts, expected changes in production costs and avoided projects. ERCOT and SPP also plan to conduct a reliability review of the transfer using power flow and system contingency analysis.
ERCOT and SPP said they expect to complete their studies on the move by February.
“It’s time to get started,” Marquez said.
Rayburn Country is an SPP member, but only about 150 MW (less than 20% of its load) and 160 miles of its transmission sit in the Eastern Interconnection. ERCOT has said it will cost $38 million to connect the SPP load with the Texas grid.
SWEPCO Seeks to Reduce Wind Catcher Costs
The commissioners consented to a list of 36 issues to be contested before an ALJ related to Southwestern Electric Power Co.’s costs associated with parent American Electric Power’s massive Wind Catcher project. (See AEP to Spend $4.5B on Largest Wind Farm in US.)
| AEP
SWEPCO has filed a request with the PUC (Docket 47461) that its costs associated with the Oklahoma wind farm and EHV transmission line — $2 billion and $1.1 billion, respectively — be treated as an eligible fuel expense, and that the federal production tax credit be treated as a credit against it. The utility has estimated $1.1 billion is jurisdictional, and it wants to credit the PTC’s value against its fuel expenses, until the project can be included in base rates.
SWEPCO also wants to defer for ratemaking purposes a portion of the PTC into a regulatory liability that would be credited back to ratepayers 11 years after Wind Catcher’s planned 2020 in-service date. This would avoid a large increase in rates once the PTC expires, the company said.
The PUC referred SWEPCO’s request to SOAH early last month. OPUC, TIEC and Golden Spread have filed motions to intervene and contributed to the list of issues. That list includes accounting and cost allocation questions and whether SWEPCO needs the additional capacity.
AEP plans to build 350 miles of 765-kV lines to connect the 2,000-MW wind farm in the Oklahoma Panhandle to its SWEPCO and Public Service Company of Oklahoma subsidiaries. SWEPCO services northeastern Texas. The wind farm would be the largest in the nation.
IRVING, Texas — The Gulf Coast Power Association’s fourth annual SPP Regional Conference last week drew more than 130 registrations, but most from the Houston area and those involved in Hurricane Harvey restoration efforts were unable to attend, cutting the audience by almost 20%. GCPA Executive Director Tom Foreman said the organization refunded registration fees to those from Houston.
“My heart, prayers and concerns go out to all of our friends, family and colleagues in Houston and South Central Texas,” said Foreman, a Houston native. “They are still in the midst of a truly historic and devastating event. Please know that all of us at GCPA wish you well and hope you remain safe.”
Referring to the SPP region as the “Saudi Arabia” of wind, SPP Board Chair Jim Eckelberger focused his keynote presentation on the RTO’s ample wind and solar resources, and the challenges they present.
He pointed to slides that listed the 17.9 GW of wind capacity currently in service and the 43.8 GW of additional capacity in all stages of development. That includes 36.8 GW in the generation-interconnection queue and 7.1 GW with signed interconnection agreements. SPP’s queue also has 7.7 GW of solar projects.
But that’s not all. Eckelberger said the Great Plains states of Kansas, Nebraska, New Mexico and Oklahoma, along with the Texas Panhandle, may produce up to 90 GW of wind capacity — almost double SPP’s current peak demand of 52 GW.
On April 24, Kansas wind farms generated more energy (3,712 MW) than the state’s load (3,507 MW). Oklahoma came close that same day, producing 5,054 MW of wind energy while the state’s load was 5,682 MW.
“There’s a future that’s really unknown. That unknown future is a dilemma for what this green revolution is,” Eckelberger said. “All this is happening, not because of the Clean Power Plan, and not because of government-subsidized wind and solar. It’s about science moving forward, technology moving forward and the market itself. That’s what pricing does.”
The wind revolution has resulted in more than 20,000 industry-related jobs, more than $23 billion in capital investments and more than $40 million in annual lease payments to landowners within SPP’s footprint, Eckelberger said.
“This is why governors say, ‘Don’t export wind to my state. I want that development to myself and bring those jobs to my state,’” Eckelberger said. “What a national energy policy would do is have us move this immense wind energy from west to the east. It would really make sense to be in that mode, but we don’t have a national energy policy. It’s not going to happen, at least in the foreseeable future.”
Asked why he is so pessimistic about a national energy policy, Eckelberger told RTO Insider some of the blame lies with “parochial [state] governors” protecting their states’ interests.
“I sense from the states they feel the same way,” he said. “There’s not a lot of oomph for a national energy policy. Of course, not much is getting done in Washington anyway.”
Bruce Rew, SPP’s vice president of operations, said wind energy is fast replacing natural gas as the RTO’s No. 2 fuel resource, and surpasses coal at times as the No. 1 fuel source.
“Gas is pretty much a secondary resource,” Rew said. “It’s still important for short-term reliability commitments.”
Khai Le, senior vice president for energy software provider Power Costs Inc., noted that SPP’s Integrated Marketplace has pushed almost 5 GW of less efficient capacity out of the dispatch stack most days, which has resulted in lower production costs. Le said the market’s prices “are rational and consistent with gas costs.”
However, he also said no market has more negative day-ahead and real-time LMPs than SPP. The Integrated Marketplace cleared about 160 negative five-minute intervals in 2016.
“With greater wind output and low gas prices, 70 to 80% of coal units are offered as must-run resources, so 20 to 30% of coal is out of the money,” Le said. “SPP will need more quick-start peakers, but under current SPP protocols, peakers do not receive sufficient reliability unit commitment make-whole payments to cover their full production costs.”
Still, Le said, he has yet to come across a market participant who wants to leave the SPP market. “If you talk to most market participants, they give a fairly high score to SPP,” he said. “Somewhere between an A- to an A.”
Golden Spread Electric Cooperative’s Mike Wise, the company’s senior vice president of regulatory and market strategy, said the region will have to decide what to do with the potential wind energy to come, given SPP’s lack of load growth.
“SPP is the renewable breadbasket of energy for the U.S., but we’re an island,” Wise said. “We’re throwing more and more renewable energy into this island, with very little capability to push this out. Can a market consistently continue with negative pricing long-term? This problem, or opportunity, is going to get deeper and deeper as you go on.
“[Our] congested areas have a large amount of renewable energy in those pockets and significantly high amounts of negative pricing. We need units able to operate and provide services necessary to support a reliable grid. Coal plants are paying to put coal-fired energy in the market. With that in mind, we need flexible units and the ability for market signals to encourage and bring on those units with short, quick-start capability.”
Improvements to SPP-MISO Interregional Process
SPP members offered recommendations to improve the interregional transmission planning process with MISO, which has yet to result in a project between the two organizations. MISO last month told stakeholders it was no longer considering the first transmission project to result from a coordinated study with SPP. (See SPP Glum as MISO Axes Last Interregional Project.)
American Electric Power’s Jim Jacoby said the RTOs should align their study processes and timelines, noting that MISO only allocates costs for 345 kV or higher, while SPP allocates down to the 115-kV level. He also pointed to a 2,500-MW export capability with MISO, “which isn’t much when SPP has a 50-GW system and MISO a 150-GW system.”
“AEP thinks that’s a problem. It thinks lower-level kV projects can be valuable,” Jacoby said. “[Aligning the study requirements] might help incent some of these projects get built.”
“We classify projects as purely reliability or purely economic or public policy, but it’s very unusual to see a project selected for reliability that doesn’t have economic benefits as well,” said ITC Holdings’ Alan Myers. “We need to be less limiting in our thinking.
“Bottom line, our traditional planning has focused on reliability and incremental fixes to the detriment of the overall system,” he said, emphasizing that ITC is not advocating less focus on reliability. “We’re in the midst of a green revolution and a rapidly evolving shift in load. All of this calls for, and demands, a new approach to the planning system, and bigger picture things across the seams.”
Jesse Moser, MISO’s director of transmission planning, promised his audience changes are coming. He said the two RTOs are working to resolve the differences in cost allocation and expect a FERC filing next year with an effective date for the 2019 planning cycle.
“We did get a push from FERC as a result of a complaint on the MISO-PJM seam,” said Moser, referring to the commission’s 2016 order on a complaint by Northern Indiana Public Service Co. (See FERC Signals Bulk of NIPSCO Order Work Complete.)
“If we don’t make those changes, we’ll probably get a complaint on the other side. We’re trying to get in front of that and be the masters of our own destiny.”
“If there’s an interregional solution to a regional problem, that’s what we think is very important,” said Missouri Public Service Commissioner Steve Stoll, who chairs SPP’s Regional State Committee. “So far, we haven’t come up with any [interregional solutions], but that doesn’t mean there won’t be any in the future.”
Political Uncertainty Cast Cloud over Market
Wise set the stage for a discussion of Lubbock Power & Light’s intended migration of 430 MW of load from SPP to ERCOT by asking what compels a load to switch grid operators.
“They’ve been served reliably [by SPP] for many, many years,” he said. “It’s not really a reliability issue. It’s purely economics. What are those compelling reasons loads would seek to move?”
Wise answered the question himself, saying that unlike SPP, ERCOT does not have capacity or firm transmission requirements. Transmission costs also are allocated differently in the SPP system. The Texas grid regionally allocates costs of service equally under “less intrusive” requirements than SPP in its base plan funding and highway/byway processes, he said.
“Those are the facts, and they’re undisputed,” Wise said, paraphrasing a line from the movie “A Few Good Men.” “Now we’ll have to spend time with what those facts mean. [The Public Utility Commission of Texas] will be dealing with those facts extensively over the next few months.” (See “Commissioners Undecided on LP&L’s Contested-Rate Case Request,” Public Utility Commission of Texas Briefs: Aug. 31, 2017.)
Asked by Wise why ERCOT didn’t simply build a DC tie as a cheaper option to connect Lubbock’s load, Jeff Billo, the ISO’s senior manager of transmission planning, said the alternative was never studied. ERCOT and SPP have determined in separate joint studies that LP&L’s proposed transition would cost the two nearly $370 million. (See Load Migrations Put SPP’s Focus on Retention.)
“Their request seemed to be, ‘We want to be in the ERCOT market and ERCOT regulatory construct,’” Billo said.
The studies considered the differences between the two grids’ market and regulatory structures.
“At the end of the day, the study results would not be apples to oranges, but apples to apples,” Billo said. “More like Jonathan apples to Gala apples.”
Texas regulators last week praised the response of the state’s utilities, ERCOT and first responders during discussion of a preliminary report on restoration efforts in the wake of Hurricane Harvey.
Speaking during an Aug. 31 open meeting of the Public Utility Commission of Texas, Commissioner Ken Anderson noted the “remarkable” restoration effort in flood-stricken Houston, especially when compared to Hurricane Ike’s aftermath in 2008.
Brandy Marty Marquez, the PUC’s other commissioner, described a road trip she took a day earlier to the deep-sea fishing community of Port Aransas. Port A, as South Texans refer to the beach town, was devastated by Harvey’s 130-mph winds.
“I saw linemen with all different uniforms [on the way]. It was very inspiring,” Marquez said. “We have a long way to go, but you can’t mess with Texas. We’ll be fine. This is a big test for us, but everyone’s risen to the occasion.”
ERCOT’s Brian Lloyd
PUC Executive Director Brian Lloyd became visibly emotional as he talked about the 10,000 utility workers from around the country who have descended to help Texas with the restoration.
Taking a few seconds to regain his composure, Lloyd told the commissioners, “It’s great to see that work.”
NRG’s Bill Barnes
“As an industry, we should be very proud of what has happened in the response,” said NRG Energy Director of Regulatory Affairs Bill Barnes. “We have a lot of friends to thank across this industry.”
American Electric Power, CenterPoint Energy, Entergy Texas and Texas-New Mexico Power reported just more than 200,000 combined customer outages Aug. 31, down from about 278,000 the day before. That number had dropped to almost 78,000 by Sunday afternoon.
“Other than the areas with extensive damage and flooding, a good chunk of this will be back online this weekend,” Lloyd said.
‘This is Personal’
ERCOT filed a status report with the commission Aug. 30 indicating that two of the six 345-kV lines that Harvey knocked out of service have yet to be restored. Another 55 high-voltage transmission lines in the storm-affected areas were still out of service as of Friday morning, the ISO said.
Most of those outages are in the Coastal Bend area between Corpus Christi and Houston, which took the full brunt of high winds when Harvey made landfall as a Category 4 storm. AEP Texas said Thursday that more than 4,600 workers have spent 14- to 16-hour days restoring power.
The bulk of those without power — about 40,000 — are in the Rockport-Victoria-Aransas Pass area. AEP Texas estimates it will take until Sept. 8 to complete its restoration work in the region.
Barnes offered a note of caution to the PUC: Just because it’s stopped raining doesn’t mean Harvey’s damage is over.
“What we’re dealing with is something that is very devastating and will have a lasting impact,” he said. “This is going to take a significant amount of time to recover from. A lot of people have had their lives changed forever as a result of this. That includes our employees, our families, our friends.
“The Corpus Christi-Victoria area is our backyard; Houston is our home. So this is personal.”
Barnes told the commissioners that NRG and its retail electric providers would halt disconnect notices through Sept. 30 for its customers in affected areas, and provide “direct financial relief” in the form of payment extensions, late fee and deposit alternatives or waivers, and increased funding of bill payment assistance programs.
The companies will also provide more than $2 million in disaster relief resources, including donating money to relief agencies and deploying a mobile generation station and disaster relief command center for affected communities, according to a filing with the PUC.
TXU Energy said it would also be waiving late fees through Sept. 30, along with extending payment due dates with no down payment required, and reducing down payments and deferring balances over five equal installments.
Anderson commended the retailers for their actions, saying, “It’s a good example for the rest of the retail industry.”
Generation, Demand Down
ERCOT also reported Friday that 7,500 MW of generation remains unavailable or operating at reduced capacity. The loss does not represent a reliability concern, and the ISO expects to have sufficient generation for the “foreseeable future.”
System demand has been down significantly since shortly before the storm made landfall Aug. 25, ranging between 41 and 48 GW, approximately 15 to 20 GW lower than normal. Demand has started to increase as service is restored and temperatures begin to rise, with projected peaks over the weekend of 56 GW. (ERCOT had predicted a peak of 73 GW this summer.)
The South Texas Project nuclear plant in Bay City, 90 miles southwest of Houston, remained online during the storm. Like other plants in the area, operators at the 2,760-MW double-unit facility were “literally locked in [the] plant for days,” Marquez said.
Barnes agreed. “Road access was flooded,” he said, referring to the situation at other NRG plants. The company is one of STP’s co-owners.
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.
