CPUC Launches Proceeding for Wildfire Fund Ratepayer Charge

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The California Public Utilities Commission on July 26 launched a proceeding to consider the adoption of a nonbypassable charge that would feed into the state’s new wildfire fund.

The rulemaking was initiated under AB 1054, legislation signed by Gov. Gavin Newsom on July 12. The bill created a fund to pay for wildfire-related claims filed against utilities, and requires the CPUC to consider whether to charge ratepayers a certain amount to support it. State utilities will also make contributions to the fund.

At the July 26 meeting, Commissioner Martha Guzman Aceves praised certain aspects of AB 1054 and the wildfire fund.

“In particular, that the utility cannot participate if it is in bankruptcy, that it cannot participate if it has not settled their pre-bankruptcy claims and that it has to be ratepayer neutral, so no bill increases coming out of bankruptcy,” she said.

As part of the new proceeding, the CPUC will look into whether such a nonbypassable charge is “just and reasonable,” as well as estimate the connected revenue requirements for utilities. If commissioners determine the charge to be reasonable, the agency will launch a separate proceeding or phase to determine how it will be collected from ratepayers.

The CPUC intends to issue a final decision in the proceeding in October.

SED: 67 Dig-Ins Possibly Caused by PG&E Locate-and-Mark Violations

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Persistent problems with Pacific Gas & Electric’s locate-and-mark practices might have contributed to 67 occasions where people hit underground lines while digging, according to new testimony from safety investigators.

The California Public Utilities Commission in December launched an investigation into alleged locate-and-mark violations committed by PG&E employees. State law requires gas pipeline operators to identify and mark their underground facilities within two working days of being notified of any planned excavation activities (see CEM No. 1519 [11]).

According to the CPUC’s Safety and Enforcement Division, PG&E employees were repeatedly tweaking records to conceal the fact that certain sites had not been visited on time, leading to an undercounting of “late tickets.” In testimony filed with the commission on July 24, the division said late tickets could have contributed to as many as 67 dig-ins, or instances where an excavator struck underground gas infrastructure. The division noted that while PG&E’s senior leadership “seemed” unaware of the issues, management within the locate-and-mark department knew that the records were being manipulated.

According to an analysis conducted by Bates White, an economic consulting firm recruited by PG&E, there were 325 instances where a dig-in occurred on a site that had not been marked on time. In 258 cases, PG&E found that the late tickets were not a contributor to the accident; however, in 67 cases, they could not rule that out.

SED also pushed back against PG&E’s claims that it had successfully reduced its rate of dig-ins over the last few years. The division noted that while the dig-in “rate” decreased, the number of instances of excavation damage did not—in fact, the number of instances of damage increased from 1,534 in 2012 to 1,874 in 2017.

Microgrid Project Could Help Address ‘Duck Curve,’ CEC Report Says

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The California Energy Commission is using a recently completed microgrid project at Las Positas College to show how battery energy storage can mitigate the “duck curve”—despite a couple of hitches.

Las Positas’ utility power demand curve, similar to a statewide curve, is called a “duck” because of its shape: a large midday drop due to solar generation followed by a steep ramp in late afternoon and evening as solar generation slows and people return from work to their homes.

The school’s demand curve is similar to the statewide curve, a July 16 report to the CEC said.

Las Positas currently has a 2.3-MW-capacity solar array that supplies 55 percent of its electricity. With a CEC grant, the campus added a 1-MWh battery storage system, including software that allows the school to forecast its microgrid’s capacity availability and deliver that capacity when signaled.

The project cost about $1.8 million and has a payback period of 10 to 12 years. It is projected to reduce the college’s energy cost by $120,000 a year.

Las Positas’ square footage has nearly doubled since 2004, resulting in a corresponding increase in energy use and cost, according to the school. As campus buildings were added, peak power demand increased to more than 2 MW, the CEC’s report said.

Most of the campus’ energy use happens in the evening, around 8 p.m., which is also when electricity in Pacific Gas & Electric’s service territory, where Las Positas is located, costs the most.

The project team identified opportunities to flatten the school’s demand curve, including increasing consumption of on-site renewable energy in the morning hours; evaluating the cost trade-off of reducing electricity export to the grid between noon and 6 p.m.; and implementing ways to predict and automatically reduce demand peaks.

The team tried to manage the times when the school’s large mechanical equipment turned on and off. The goal was to have thermal storage equipment operate from about 4 p.m. to 9:30 p.m. and then switch to chiller units in the morning. However, the plan failed: The on/off signal that was supposed to be sent between the thermal storage equipment and the chillers never made it through, the report said.

Prior to the battery storage project, Las Positas was sending about $30,000 worth of solar-generated electricity each year back to the power grid at no charge, due to previous net-metering tariff regulations that only allowed a solar generator to be paid for power from a 1-MW solar system. The battery now captures a portion of the excess solar power and stores it for use at other times.

California schools and colleges have installed about 1,000 MW of solar capacity in total, but often use the local utility grid as a battery, the report said, to mitigate the duck curve.

Los Positas’ microgrid was supposed to be a blueprint for other California schools; however, the project team did not publish an official blueprint, even though the requirement to do so was stated in the grant funding award.

Instead, the team said it presented the information at conferences and seminars attended by educational facilities managers and energy managers. The microgrid blueprint was going to be used by educational institutions statewide to evaluate, plan and install their own microgrids, and to help manage the output of their existing renewable-energy assets using energy storage systems.

The battery storage project grant was awarded in 2015 through the CEC’s Electric Program Investment Charge program.

EVs Spread in California, but Gas-Powered Car Growth Remains Steady

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Despite increasing greenhouse gas emissions from California’s transportation sector, one thing remains clear about the state’s emissions future: more cars are on their way in.

State officials expect to see more cars on California’s roads over the next decade, the California Energy Commission said at a staff workshop on July 22, including those fueled by gasoline, electricity, hydrogen or natural gas.

Thirty million cars are driven in the state today and about 35 million are expected to be on the roads in 2030. Twenty-seven million of those in use today are fueled by gasoline, a figure expected to increase to about 28 million by 2030. In comparison, about 400,000 electric vehicles operate today, inflating to about 4.5 million in 2030.

What will spur the EV uptake, officials say, are California rebates lasting until 2025; shortened charging times of 10 to 16 minutes by 2030; increased average driving range of up to 341 miles per charge; and decreased battery costs.

Battery costs could decrease by about 50 percent by 2030, from $190 per kWh to between $90 and $140 per kWh, H-D Systems President Gopal Duleep said at the workshop. Those cost-reduction forecasts for batteries might be aggressive, Duleep said, but he added that communicating aggressive price-reduction forecasts to the public is important in order to ensure “EV competitiveness in the future.”

Electricity demand due to the additional EVs is expected to increase from about 5,000 GWh in 2019 to about 20,000 GWh in 2030. Light-duty electric vehicles are estimated to account for nearly all of the growth, requiring about 4,000 GWh today and about 16,000 GWh in 2030. The remaining load increase will come in the medium- and heavy-duty vehicle categories, such as electrification of school buses (see CEM No. 1548 [11]) and airport shuttles (see CEM No. 1545 [11]).

In January 2018, then-Gov. Jerry Brown issued Executive Order B-48-18 to put at least 5 million zero-emission EVs on California roads by 2030 and to add 250,000 plug-in EV chargers, including 10,000 direct-current fast chargers, and 200 hydrogen refueling stations by 2025. In 2017, EVs made up 5 percent of new-car sales in California, up from 3.8 percent in 2016, according to the California Air Resources Board.

However, GHG emissions from the state’s transportation sector have increased over the years, rising 1 percent in 2014, 3 percent in 2015 and 2 percent in 2016.

Emissions impacts due to a greater number of EVs on the road will be determined by how the additional electricity supply is generated, such as by natural gas or renewables, the CEC said. The emissions changes will “depend highly on the future composition of projected electricity supplies,” according to the CEC’s 2018 Integrated Energy Policy Report.

When asked about emissions projections due to increased numbers of both electric and gasoline cars, the CEC told California Energy Markets it had not completed such a comparison.

“The hope is to develop a method to evaluate GHG impacts for electric vehicles, but the Energy Commission does not have a current timeline for having a method or analytical results,” the CEC said.

Earlier this year, CARB Chair Mary Nichols said the agency was considering a ban on all internal combustion engines, specifically by requiring all new-car sales to be EVs.

No proposal has been made yet; however, Nichols said that by 2045 “there can’t be any cars sold in California that aren’t zero-emissions vehicles of one sort or another. I don’t expect to be alive to see that, but that’s where we’re headed.”

CARB estimates that 70 percent of GHG emissions from California’s transportation sector—and 28 percent of all GHG emissions in the state—come from light-duty vehicles, which are cars and trucks that weigh 8,500 pounds or less.

Government agencies in the state are trying to lead EV uptake by example, CARB said. By 2030, the air board will try to purchase or lease only EVs for its fleet, unless no EV option exists to meet a required function.

However, some industry experts are advocating for more attention to local solutions. “There is not a single solution at the regional level,” Center for Sustainable Energy manager Jonathan Changus said at another CEC EV workshop on July 18. “It is equally important we listen to our communities, especially when we’re talking about the barriers faced by moderate- and low-income communities. San Francisco charging solutions are not going to be the same as Fresno’s.”

Other alternative fuels for cars are forecast to see growth over the next decade as well. Hydrogen for vehicle fueling is expected to increase from about 2 million kg today to about 25 million kg in 2030, while the “flex fuel” E85, an ethanol-gasoline blend of 51 percent to 83 percent ethanol, is expected to grow from about 22 million gallons to 55 million gallons. Diesel fuel is expected to flatline over the next 10 years, staying near 3.7 million gallons annually.

Investor-owned utilities have said they plan to support growth in EVs and associated electricity demand. Southern California Edison released its Clean Power and Electrification Pathway in October 2017, proposing an electric grid that is supplied by 80 percent carbon-free energy and can accommodate at least 7 million EVs.

Aspen Environmental Group said the CEC should also expect significant electricity demand growth in the state’s shipping and trucking industries.

Shipping port cargo-handling equipment, such as cranes, is expected to require up to 200 GWh per year in 2030, up from about 1 GWh annually today. Trucks carrying refrigerated goods currently require about 100 GWh per year and are expected to need about 700 GWh in 2030.

PG&E, Other Parties Confront Possibility of Multiple Reorganization Proposals

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U.S. Bankruptcy Judge Dennis Montali on July 24 preserved Pacific Gas & Electric’s control over its reorganization process for two additional weeks, allowing the company, state regulators and representatives for Gov. Gavin Newsom time to figure out how they will handle competing restructuring plans filed by parties in the utility’s bankruptcy proceeding.

Montali delayed ruling on a June motion filed by a group of PG&E’s bondholders to terminate the company’s exclusivity period, during which it currently retains the sole right to file a reorganization plan that would bring the company out of bankruptcy. PG&E’s exclusivity period is set to expire on Sept. 26, but the bondholders pitched a $30-billion reorganization plan of their own that they argued warranted consideration by the court.

However, attorneys for the California Public Utilities Commission and Newsom asked the judge for a two-week adjournment in the case over concerns that competing reorganization plans could create chaos in PG&E’s restructuring and jeopardize the utility’s chances of exiting bankruptcy by June 2020. If PG&E were to miss the deadline outlined in AB 1054, it would not be able to access a new wildfire recovery fund set up as part of the legislation. The request was supported by attorneys for PG&E as well.

CPUC attorney Alan Kornberg said the agency is “keenly interested” in the bondholders’ plan, but reminded the judge that AB 1054 requires the CPUC to review PG&E’s reorganized governance structure—while keeping in mind state climate goals and ratepayer impacts—by next June. The two-week delay would allow all the parties to craft a protocol and identify a timeline for handling potential competing plans, according to Kornberg.

“We cannot permit competition to turn into chaos. I think that is really the challenge that we all face—how do we manage a competitive plan process in this court and at the PUC and not derail a successful resolution by June 2020?” he said.

The June 25 restructuring plan outlined by the ad hoc committee of senior unsecured noteholders is built around a $30-billion investment from the group to help PG&E resolve its wildfire liabilities. It would set aside $16 billion for past wildfire claimants, as well as $4 billion for a fund to handle future claims. In addition, the plan would preserve PG&E’s renewables contracts without increasing customer bills, according to the committee (see CEM No. 1545 [13]).

In a July 23 motion, an ad hoc group of subrogation claim holders—insurance companies that hold more than $20 billion in wildfire-related claims against PG&E—outlined a plan of their own. This proposal would allocate $15.8 billion for the wildfire claims, 90 percent of which would be equitized, and would also prevent customer bills from increasing.

Given the competing plans—as well as indications that other parties intend to file plans of their own—terminating PG&E’s exclusivity would not be the right answer, the CPUC’s Kornberg said. He intends to work with other parties in the bankruptcy to negotiate a protocol for submitting various plan proposals.

“The goal is to avoid multiple contested confirmation proceedings and all that go with them,” he said.

According to Matthew Hinker, an attorney for Newsom, a controlled protocol for handling competing plans would allow multiple parties—including municipalities and PG&E’s third-party purchasers—to bring forth potential plans of their own within the time frame set by AB 1054. Newsom envisions a process that is competitive, transparent and subject to checks and balances, Hinker said.

“The governor believes that the parties working together can develop that process over the next two weeks,” he added.

The request also received support from PG&E attorney Stephen Karotkin.

“We certainly share the governor’s view and the PUC’s view that terminating exclusivity to allow competing plans to go forward is not in the best interest of any parties here, and will lead to chaos,” Karotkin said, adding that PG&E will try to accommodate the CPUC’s and Newsom’s concerns during the two-week adjournment.

But Michael Stamer, an attorney for the bondholders, pushed back against the CPUC’s request, saying that PG&E needs to confirm a plan in approximately 11 months and has not made sufficient progress toward putting something viable on the table.

“What they are proposing is really an unprecedented, undocumented road to nowhere,” he argued.

However, after hearing all the arguments, Montali said he did not think the delay would harm the bondholders’ cause.

“I am inclined to grant their request because I don’t think there is a real downside to your client, and this is another way of saying, look, perhaps I need to hear the ad hoc subrogation group’s motion at the same time,” he said, referring to the second plan filed by the group of insurance companies.

He ordered the CPUC and Newsom’s representatives to report back on Aug. 9 on whether they had agreed upon a process for competing plans, and he postponed to Aug. 13 consideration of the bondholders’ motion.

CAISO Warns of Import Shortages, Mulls Market-Power Mitigation Approach

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The California Independent System Operator has its eye on a number of issues as the 2019 summer season unfolds, including new renewables peaks and ongoing requests from market participants for the ISO to deal with possible market power when the system is tight on supply.

CAISO began summer operations last month and much of the generation fleet is available for peak load conditions, winter maintenance outages having been completed. Renewables continue to grow, as CAISO set another solar peak recently: 11,473 MW on July 2 at 12:52 p.m., records show. The most recent wind generation peak, 5,309 MW, was set on May 8 at 3:21 a.m. CAISO also set a new record for peak renewable generation on May 15, when 80.3 percent of load was served by renewables.

“Once again, I think this continues to show that we can operate the system reliably with very high levels of renewables on it,” CAISO CEO Steven Berberich told the CAISO Board of Governors at a June 24 meeting in Folsom.

But concerns arose on June 11, when load peaked at 42,739 MW at 5:23 p.m., during the evening period. This is the time of day when CAISO must ramp up other resources and/or import power to make up the gap as utility solar—as well as thousands of megawatts of behind-the-meter solar that CAISO does not control—is waning.

On June 11, “conditions were very tight and the ISO issued a Flex Alert to ask for conservation as both the peak and subsequent net peak were difficult to meet with available resources and imports,” Berberich said. “This is of concern as last year’s peak was 46,424 MW and the 2017 peak was 50,116 MW.”

Berberich said that adding to the concerns are a growing difficulty in procuring imports and the continuing decline of the thermal, natural gas-fired fleet. He said the ISO is working closely with the California Public Utilities Commission to ensure the state’s resource-adequacy program addresses any pending capacity shortfalls.

Ensuring adequate imports was a topic at the meeting as the board learned more about an effort the ISO has undertaken to address market power, flowing from a white paper it issued earlier this year (see CEM No. 1545 [7]).

CAISO initially said the scope of the white-paper effort would be relatively narrow, but a number of market participants are urging a systemwide market-mitigation framework to address extremely high electricity prices when conditions are tight. Some have postulated that market power is being exercised at these times, bolstered by the Department of Market Monitoring’s finding that market power is possible in hours with several “pivotal suppliers,” an environment in which generators can withhold supply to drive up prices.

But if prices are mitigated when the system is constrained, it discourages power sellers from outside of California to sell into the market, potentially cutting off crucial imports, Berberich said.

“I also would warn us greatly to be very cautious about how we do this,” he said. “You could have some very untoward consequences where we don’t get the imports that we need to serve system load.”

If CAISO mitigates prices down to cost, Berberich said, “why would anybody sell power in California when [they] can sell it for $1,000 outside of California?”

So far in the stakeholder process, CAISO has developed a series of market-power mitigation proposals, outlined at the meeting by CAISO Senior Manager Bradley Cooper. Systemwide market-power mitigation would be “a new thing for the ISO” and “unique among ISOs in the U.S.,” according to Cooper.

“Stakeholders are pretty much in two camps in how we should address the situation,” Cooper said. The investor-owned utilities and the CPUC support a system-level market-power mitigation process. But suppliers have raised concerns about potential impacts to supply, saying mitigating prices during tight supply conditions could discourage needed imports.

Cooper in a presentation outlined several proposals as alternatives to systemwide mitigation. Load-serving entities could do forward energy contracting, which hedges load and reduces incentives for supply to bid high during system constraints. There could also be bilateral procurement of additional resources during net load peaks, and additional energy storage could add supply as solar output decreases. The ISO could also enhance its scarcity-pricing provisions, Cooper said.

“These measures aren’t mutually exclusive,” Cooper said. “Potentially you could do a combination of them, or all of them.” He said options will be discussed at an Aug. 19 Market Surveillance Committee meeting. The committee will provide a written opinion on the appropriate response, and a briefing to the board is set for November.

Cooper noted the Department of Market Monitoring’s competitiveness test had found that market power could have been exercised in about 2 percent of hours in 2018, when system conditions were tight.

“Maybe it’s only 2 percent, but to us that’s a lot,” Eric Eisenman of Pacific Gas & Electric said during public comments at the meeting. Prices hit the bid cap of $1,000 per MWh, which he said represents hundreds of millions of dollars in excess costs that could be coming from market power. He questioned whether it was really market fundamentals at work.

“CAISO energy prices can still be high, if there is really a true shortage . . . but high prices driven by economically withholding during uncompetitive peak periods need to be mitigated,” Eisenman said, saying he hoped that mitigation measures could be in place for next summer.

“The development of mitigation measures must be done carefully—we don’t want anything to go haywire during this process,” he said.

But Mark Smith of Calpine, representing the Western Power Trading Forum at the meeting, said nobody has asserted that market power is actually being exercised.

“All that has been asserted so far is that high prices are correlated with high demand, and in many ways, that makes a lot of sense,” he said. WPTF and Calpine support digging into the details, but the potential consequences of a suppressed price and inadequate imports, such as loss-of-load costs from not meeting load, could be much more costly, Smith said.

“We counsel and suggest a diligent continuation of this, but with eyes wide open,” he said.

CAISO Vice President Keith Casey said that summer 2020 is too soon to implement new market-power mitigation measures because of software changes that would need to be put in place.

“There is going to be a lot of work done between now and November to bring those recommendations forward,” Casey said.

Separately, CAISO on July 22 filed comments with the CPUC on its ruling that would initiate a new procurement track, in which the CPUC sought comment on reliability issues [R16-02-007]. CAISO said it generally agrees with an analysis by Energy Division staff showing a reliability shortfall of 2,000 MW as early as 2021 and increasing to 2,500 MW in 2022 if all “once-through cooling” generation units retire as planned.

“CAISO urges the commission to focus immediately on developing a comprehensive plan for addressing near-term reliability needs through 2022,” CAISO said. The plan should prioritize procurement of existing and new resources to be on line as soon as possible and, as a backstop, facilitate extending the once-through cooling regulations “for gas-fired resources that are needed to maintain near-term reliability.”

CAISO said there have been some new developments since the CPUC did its reliability analysis, including General Electric’s June 20 announcement that it will retire the 750-MW Inland Empire Energy Center at the end of the year (see CEM No. 1545 [14]).

Gas-Linked Interests Warn Against Poorly Planned Renewables Integration

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California faces a quandary as natural gas-fired power plants that are critical for maintaining reliability are not making adequate energy-market profits, setting up a situation where generation becomes uneconomic even when needed—a dynamic of which natural gas-related interests are well aware.

There is no stopping the movement to integrate large amounts of renewables onto the grid in California, but without careful management, reliability problems could emerge and knock the state off its path to clean energy, industry experts said during a July 17 panel discussion at Infocast’s California Energy Summit in Los Angeles.

Representatives of independent power producers, Southern California Gas Co. and NRG Energy laid out some of the pitfalls and concerns as the state moves toward its goal of 100 percent renewable and zero-carbon energy. The transition to renewables brings myriad new issues as the state’s goals are overlaid on an energy infrastructure that was meant to function in very different ways.

Renewables show lots of promise, but natural gas will be a part of the state’s energy mix for a long time to come, Jan Smutny-Jones, CEO of the California Energy Producers Association, said. He raised the issue of the glut of renewable power at certain times that requires curtailments or selling at negative energy prices—paying to offload energy.

Renewable resources such as solar and storage have a great deal of potential, “but at some point in time, anybody selling power that has zero energy value . . . you know, how is that business model actually going to work?” he said. Smutny-Jones, a long-time industry participant and observer in California, said the state is moving from an energy-market to a capacity-market-type structure, in which capacity such as natural gas-fired plants has value as a standby resource.

“We are going to need a significant amount of the gas facilities to sit around, to provide capacity,” Smutny-Jones said. “They produce very little energy, but they are there to provide the power when it’s needed.” Also, he said, between 2000 and 2015, the state added about 16 GW of natural gas line capacity, relatively new infrastructure built by public and investor-owned utilities, that is in place and ready to use.

“No matter what it is you are selling, it has to have value and at this point in time the value is capacity,” he said, noting that California recently switched to multiyear resource-adequacy procurement. A capacity market had been considered, but was shelved under concerns that the Federal Energy Regulatory Commission would gain too much control over California. Legislation that would have created a central government procurement agency also floundered this year (see CEM No. 1547 [6]).

“This is a big issue. My point is that if we screw up reliability, the support for everything else that people want to do, in terms of getting to a clean-energy future, gets eroded fairly quickly,” Smutny-Jones said. “People in California have a very low tolerance for an unreliable system.”

Tanya Peacock, public policy and planning manager for SoCal Gas, also discussed the ongoing need for natural gas for a few decades. The problem is that the gas system is not designed to act in a standby fashion in terms of physics, and curtailing renewables or paying customers to take excess power doesn’t make much sense, she said.

Peacock discussed a creative solution: converting excess renewable power through a molecular process into gaseous form, to be transported on the existing pipeline system as hydrogen. She also mentioned biomethane from treatment plants, dairies and landfills

The industry is “starting to think of creative ways we can utilize existing assets to meet California’s decarbonization goals and also provide resilient and affordable and reliable energy,” Peacock said.

NRG Energy’s Brian Theaker said that when he joined the company in 2011 “they had their finger in practically every pie in the energy space in California.” But as of now, with all the change, “We are kind of living in our parents’ basement, trying to figure out what’s going to happen next in California,” he said. NRG owns gas as well as solar assets including the 400-MW Ivanpah concentrated-solar facility.

Over the last decade there has been a heavy buildout of renewables that has changed system dynamics greatly. There has been 10 to 12 GW of utility solar brought onto the system and 8 GW of behind-the-meter solar. Much more solar is coming, but there are diminishing returns from adding renewables on a capacity basis, Theaker said.

“We are seeing a totally different resource profile in the RA program,” he said, adding that reliability issues are emerging in periods where they were not expected.

This requires looking at things more “expansively,” he said, adding: “I think those conversation are underway. I think we just have to let those flowers bloom where they will.”

CalOES Files Oroville Dam Reimbursement Appeal With FEMA

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The California Office of Emergency Services on July 22 filed an appeal with the Federal Emergency Management Agency of the state’s reimbursement costs for the Oroville Dam spillway collapse.

A total of $1.108 billion was spent through the end of 2018 on emergency response and repairs after the February 2017 spillway failures at the dam, according to the California Department of Water Resources, on behalf of which the appeal was filed.

FEMA notified DWR in March that it does not consider some spillway reconstruction work to be eligible for reimbursement based on information DWR submitted at the end of 2018.

To date, FEMA has approved reimbursement of $337.4 million.

“In its appeal and cost submittals, DWR included updated reimbursement requests totaling an estimated $1.11 billion to cover the costs of the Oroville spillways emergency response and emergency recovery efforts,” DWR stated in a press release. “This updated estimate is based on actual costs through Dec. 31, 2018 and anticipated costs for ongoing and future work to finalize the repairs.”

The estimated bill for emergency response is $194 million, according to the agency. Another $580 million is expected to be spent on main spillway recovery, with $291 million covering emergency spillway recovery. Other recovery projects—which include work such as permanent power-line installation, construction of on-site access roads, and repairs to the Feather River fish hatchery—are anticipated to cost $43 million, according to the agency.

The state asserts that the final costs remain unknown until all the work at the site is complete, and adds that the estimate remains “essentially unchanged” from that released in October 2018.

When the newly reconstructed main spillway of Oroville Dam was opened April 2, returning it to normal operation for the first time since 2017, DWR officials said they do not expect the state to pay the bill, but rather the federal government (see CEM No. 1533 [6]).

The state has shifted some expenses from one category to another. The removal of debris from the diversion pool, for example, was moved to the emergency-response expenses category. Also, the state said some DWR staff and interagency costs previously included in the “other recovery” category were moved.

“Reimbursement costs may change slightly based on final invoices at the completion of the project,” DWR said.

The agency said it will continue submitting updates to FEMA until the project is complete. It had previously stated that other modernization work that might be necessary to ensure the continued safety and functionality of the entire complex was being evaluated.

According to the FEMA website, its Public Assistance program reimburses applicants “not less than 75 percent of eligible costs” of a federally declared disaster. Typically, the state determines how the nonfederal share is split between other eligible applicants.

Those costs not reimbursed by FEMA will be paid by beneficiaries of the State Water Project, DWR said.

Tri-State Settles With DMEA Over Departure, Files FERC Tariff Application

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Delta-Montrose Electric Association will end its power-purchase agreement with Tri-State Generation and Transmission Association next spring, ending a saga that has embroiled both parties and other entities over the future of rural electricity in Colorado and elsewhere in Tri-State territory.

DMEA, a rural Colorado distribution cooperative, on July 22 issued a press release saying it would withdraw its membership in Tri-State—a wholesale cooperative comprised of 43 members in Colorado, New Mexico, Nebraska and Wyoming—effective May 1, 2020. The announcement follows a settlement agreement filed at the Colorado Public Utilities Commission July 19 [18F-0866E]. The highly confidential deal ends a yearslong battle between the two entities over DMEA’s effort to extract itself from Tri-State (see CEM Nos. 1518 [17], 1522 [14] and 1546 [15.2]).

At issue in the conflict between Tri-State and DMEA was the amount of Tri-State’s exit fee proposed to DMEA, which the distribution co-op called “unjust, unreasonable and discriminatory.” The amount of the exit fee has remained confidential throughout the negotiation process and remains so in the settlement, but DMEA in its release said the agreement “includes a fair and reasonable exit charge.”

“DMEA recognizes the importance of its continued partnership with Tri-State in various areas, and we know we will continue to rely upon Tri-State for safe and reliable transmission service,” DMEA CEO Jasen Bronec said in the release.

In a statement accompanying the confidential settlement agreement, the parties said the agreement addresses the financial terms of DMEA’s withdrawal, the disposition of certain transmission facilities, transmission service to DMEA prior to and after its withdrawal, and dismissal of district court and Colorado PUC proceedings related to DMEA’s withdrawal.

“The redacted information is neither relevant to nor replicable in any possible future member withdrawal proceedings,” Tri-State said. It said it will include the redacted information in 8-K filings with the U.S. Securities and Exchange Commission following DMEA’s withdrawal.

The Colorado Energy Office, also a party to the settlement, said it “resolves a range of issues that have been in dispute between DMEA and Tri-State.” The office also said it believes the agreement will further its policy interests and those of Colorado.

DMEA and Tri-State were scheduled to begin a five-day hearing before the Colorado PUC in August when Tri-State, at its July 9 board meeting, voted to pursue action that would bring the wholesale co-op under Federal Energy Regulatory Commission rate jurisdiction (see CEM No. 1547 [19]). DMEA sought to prevent this effort by seeking a restraining order against Tri-State in Adams County District Court on July 2, a week prior to the FERC vote.

DMEA was joined in opposing the move toward FERC regulation by fellow Colorado Tri-State members United Power, San Miguel Power Association and La Plata Electric Association, according to a July 11 email from DMEA Chief Operating Officer Virginia Harman. LPEA of Durango, Colorado, is considering pursuing its own split from Tri-State, and on July 2 asked the wholesale cooperative to offer an exit-charge estimate.

These members and a group of Colorado lawmakers had all asked Tri-State for more time to consider the ramifications of federal oversight of Tri-State’s rates. The legislators on July 3 sent a letter, signed by the leadership of both state houses and the chairs of the energy and transportation committees of the Colorado Senate and House, to Tri-State requesting a delay of the vote.

The lawmakers expressed concern in the letter that FERC oversight could upend aspects of legislation signed by Gov. Jared Polis May 30 that is intended to put Tri-State’s resource planning under PUC oversight. “Given the connection between rates and resource planning, we are concerned that Tri-State was not more transparent about the possibility of transitioning to FERC oversight during this negotiation,” the letter says.

Following Tri-State’s vote to pursue FERC regulation, Colorado PUC member Frances Koncilja excoriated Tri-State attorney Tom Dougherty in a July 12 emergency hearing at the commission that was convened in response to the Tri-State decision. “The concern is bait-and-switch and being misrepresented to,” Koncilja told Daugherty. “To make us go through all of this when you have a plan to do some forum-shopping is very upsetting,” she said, referring to commission efforts in the negotiation between Tri-State and DMEA.

Despite the criticism, Tri-State moved forward, on July 23 issuing a press release saying it had made tariff application filings with FERC to be fully rate-regulated by the federal commission. Tri-State anticipates the filings will be accepted within 60 days, after which they will be ruled upon. Tri-State said that under FERC regulation it will remain subject to state jurisdiction regarding resource planning and environmental requirements.

“Tri-State is committed, and we are also required, to work with all state regulatory agencies, including the Colorado Public Utilities Commission, on resource planning and the Colorado Air Quality Control Commission on carbon reduction planning,” Tri-State CEO Duane Highley said in the release.

Upon its exit from Tri-State, DMEA plans to partner with Guzman Energy, a regional wholesale power provider with headquarters in Denver and Coral Gables, Florida. Guzman spokeswoman Kathleen Staks confirmed in an email that the company will serve DMEA’s wholesale power needs once the exit is finalized. Details of the power-purchase agreement between Guzman and DMEA are still in the works, Staks said.

Guzman has PPAs with other cooperatives, communities and Native American tribes in Colorado and New Mexico. Kit Carson Electric Cooperative, a former Tri-State member that left in 2016 after negotiating a $37-million exit charge, is a central Guzman customer.

Environmental Group Seeks Clarity on San Juan Generating Station Abandonment Plan

  • Updated

A Colorado-based environmental organization wants clarity from New Mexico regulators about which law they plan to utilize in the abandonment proceeding for the San Juan Generating Station.

Western Resource Advocates on July 22 filed a motion at the New Mexico Public Regulation Commission seeking clarification as to whether the commission intends to disregard provisions of the state’s sweeping Energy Transition Act as it oversees Public Service Company of New Mexico’s July 1 application for abandonment and financing of the 847-MW coal-fired plant [19-00195-UT] (see CEM Nos. 1546 [15] and 1547 [17]).

WRA is one of several environmental and clean-energy organizations that had a hand in developing the ETA, signed into law by Gov. Michelle Lujan Grisham March 22 (see CEM No. 1531 [18]).

The ETA took effect June 14, but a July 10 order issued by the NMPRC suggests the commission intends to oversee PNM’s abandonment proceeding through a docket that predates its passage in the hope of avoiding provisions of the new law.

The commission stopped short of saying it would disregard the ETA, but discussion leading up to the order indicates “that the commission intends to not apply the Energy Transition Act to the abandonment and financing portions” of PNM’s application, WRA said in its motion. “There does not, in fact, appear to be another rationale behind reassigning the abandonment and financing portions of PNM’s application” to the earlier docket [19-00018-UT].

The motion requests that if the NMPRC confirms that it plans to oversee abandonment and financing of the plant through prior law, it reconsider that decision and allow briefs and oral arguments on the issue of applying the ETA to PNM’s entire abandonment filing.

WRA’s motion, supported by PNM and Interwest Energy Alliance, contends there would be “severe consequences of not utilizing the tools and directives found in the new law.” Without the ETA’s provisions for abandonment and financing, the motion states, “$40 million in economic relief, job training and severance to the Four Corners [region] will be lost, as will the ratepayer benefits that flow from the low-interest bonds that the ETA enables” (see CEM No. 1526 [20.1]). The ETA also mandates that replacement resources be sited in the Four Corners region, where the San Juan plant and its associated coal mine are located.

PNM supports WRA’s motion, the utility’s spokesman, Ray Sandoval, said in an email.

Arizona Adopts EV Plan as Other SW States Ponder Increased Usage

  • Updated

Arizona regulators have begun paving the way for wider adoption of electric vehicles in the state, suggesting that the state’s utilities create sweeping EV implementation plans.

The Arizona Corporation Commission at its July 10 open meeting adopted the EV implementation plan and followed that vote up with approval of Tucson Electric Power’s time-of-use EV rate design [RU-0000-A-18-0284, E-01933A-17-0250].

The Arizona plan encourages—but does not require—regulated utilities to propose to the ACC by Sept. 1 EV pilot programs that focus on infrastructure, including make-ready provisions for new construction, rate design, and load-management strategies for EV usage. Utilities would also submit along with their EV pilot programs a comprehensive transportation-electrification plan developed with stakeholder input. The commission said it will allow cost recovery in future rate cases for utility investment in the pilot programs.

Arizona’s plan encourages utilities to develop rate options and load-management strategies to maximize the use of variable generation resources, particularly excess solar and wind generation. The commission also advised utilities to incentivize EV charging during off-peak hours for residential customers, as TEP’s approved tariffs already do [77290]. The ACC encouraged regulated utilities to work with third parties to develop rates that will encourage deployment of DC fast-charging stations [77289].

The commission expects regulated utilities to include EV infrastructure plans, needs and costs in future integrated resource plans or in their transportation-electrification plans if the utilities do not file IRPs. Regulated utilities must also address in their pilot programs how they will account for and minimize financial impacts of EV pilot programs on low-income customers in Arizona until the EV market and services are better able to serve such customers directly.

Commissioner Justin Olson, the lone no vote on both the EV plan and TEP’s EV tariffs, expressed concern that the policies would lead to rate increases that effectively result in ratepayers subsidizing electricity for EV charging. Olson said he preferred third parties develop charging-station infrastructure and recover investments from the stations themselves rather than from ratepayers.

In order to increase the practicality and ease of EV use across geographic and socioeconomic strata, the ACC decision encourages utilities to deploy charging stations in rural and low-income areas, multi-dwelling units, interstate corridors or highways, and elsewhere there is inadequate coverage.

Arizona Public Service, the state’s largest utility, launched its Take Charge EV pilot program in April with a focus on workplace charging, fleet vehicles, and multifamily communities. Jenna Rowell, an APS spokeswoman, said in an email that the program is not at odds with the ACC’s new EV implementation plan, so the utility has no plans to make any changes to its pilot as a result of the decision.

Arizona’s second-largest utility, Salt River Project, which is not regulated by the ACC, supports enabling 500,000 EVs in its service territory as part of its 2035 Sustainability Goals. SRP aims to manage 90 percent of EV charging through price plans, dispatchable load management and other programs.

Other Southwest states that adopted ambitious goals for decarbonization and emissions reductions this year predict increased use of electric vehicles in the near future. Making EVs a practical choice in the largely rural region calls for approaches to infrastructure development that will require cooperation between utilities, regulators and other stakeholders across the Southwest’s wide-open spaces.

Colorado passed economywide greenhouse gas-reduction goals this spring (see CEM No. 1538 [18]) as well as other laws likely to make EV ownership more appealing in the state. These include extending tax credits for EV purchases through 2026 and offering the Colorado Energy Office greater flexibility in administering grants to cover operating and installation costs of EV charging stations at the local level.

Another new Colorado law allows investor-owned utilities to pursue from the Colorado Public Utilities Commission cost recovery through rates for investing in charging ports, a feature consistent with the Arizona policy.

An environmental coalition that includes Environmental Defense Fund, the Natural Resources Defense Council, Western Resource Advocates, the Sierra Club and the Southwest Energy Efficiency Project on July 10 filed a brief before the Colorado Air Quality Control Commission, part of the state’s Department of Public Health and Environment, encouraging it to adopt a proposed zero-emission-vehicle program from the Colorado Air Pollution Control Division.

New Mexico’s EV expansion got a jump-start in April when Gov. Michelle Lujan Grisham signed a law ensuring third-party charging stations won’t be regulated as utilities in the 120,000-square-mile state. The new law also requires regulated utilities to propose programs and partnerships with independent companies to advance the EV market, including through the deployment of charging infrastructure.

In 2015, Public Service Company of New Mexico, the state’s largest utility, partnered with Nissan to bring five charging stations to its service area for customers to use free of charge. Customers began paying to charge their vehicles at the public stations in 2017.

PNM, which plans to go carbon-free by 2040, five years ahead of the state mandate for investor-owned utilities, is working to model the impact of added EV load on the grid, and says it will prioritize work to improve reliability in anticipation of increased load from EV charging.

Experts at Southwest Conference Predict Rise of Microgrids, Hydrogen

  • Updated

Climate goals, national security threats and grid reliability in a landscape defined by increasing load and an expanding population were hot topics at Law Seminars International’s annual Electric Power in the Southwest Conference in Santa Fe, New Mexico, on July 15 and 16.

Jeanette Pablo, general counsel and senior associate at the Energy Futures Initiative, a Washington, D.C.-based think tank that provides reports and analysis to advance cleaner, safer, more affordable and more secure energy options, explored strategies for meeting ambitious climate and decarbonization goals. Speaking at the conference, Pablo emphasized that while innovations will emerge, meeting these goals will essentially transform the current energy system and present plenty of challenges. She pointed to energy efficiency, which addresses transportation, electricity, industry and building construction, as a big factor in this transformation when combined with advancing technologies in coming decades.

Software that includes artificial intelligence to smooth out the demand curve in “smart communities” and prospects for hydrogen from electrolysis are among the technologies that show promise, according to Pablo. Over the past 50 years, people have been saying a hydrogen revolution is 10 years out, she said, “but there have been a number of developments that suggest we really are within the 10-year window for [hydrogen] feasibility.” The nation of Japan and the automaker Toyota are among those investing heavily in hydrogen, which they plan to showcase at the 2020 Summer Olympics in Tokyo, Pablo said.

Rao Konidena, a principal with Rakon Energy in Minnesota, spoke of the potential for increased participation in regional markets to improve reliability by balancing load and using excess renewable generation to capture hydrogen from electrolysis and build fuel cells. Such an approach would help mitigate the “duck curve” phenomenon that has been prevalent with the rise of renewables in California and is likely to manifest in other independent system operator and regional transmission organization markets as renewable generation resources increase.

Konidena also pointed to Toyota, which partnered with the Fuel Cell and Hydrogen Energy Association on the installation of a fuel-cell power plant at the Port of Long Beach in California that will generate electricity along with 100-percent renewable hydrogen fuel via biogas from dairy cattle waste. Toyota will purchase the hydrogen for its fuel-cell-powered cars and heavy-duty trucks deployed at the port, Konidena said, quoting Morry Markowitz, president of the FCHEA.

Karl Rudisill of Element One Technologies discussed in a presentation industrial-scale hydrogen projects that could transition coal communities toward the production of hydrogen fuel from coal, with resulting emissions captured in on-site greenhouses.

“The energy technology innovation is relatively slow due to the system’s long cycles of adoption, its role as a highly capitalized commodity business, complex supply chains, and established customer bases,” Pablo told the audience. But scenarios for a breakthrough technology portfolio post-2030 could include smart communities and hydrogen along with expanded offshore wind, advanced photovoltaics, battery storage and recycling, direct-air carbon capture, advanced nuclear and bioenergy. Blockchain technology, she said, offers promising applications for managing an increasingly complex energy sector.

Former Arizona Corporation Commission Chairman Doug Little, now a senior advisor in the Office of Electricity at the U.S. Department of Energy, reminded the audience that risks to reliability do not come only from increased load, inadequate transmission and the lack of dependability from variable resources. Reliability continues to face perennial low-tech threats such as earthquakes and wildfires. All of these, Little pointed out, can threaten national security as well.

As an example, Little pointed to Beale Air Force Base near Marysville, California, which he said gets most of its power through a 169-kV power line that hangs on wooden poles and runs through tinder-dry brush in the summer. The China Lake Naval Air Weapons Station in Ridgecrest, California was out of commission during the conference due to an earthquake the previous week centered in Ridgecrest, Little said.

An increasingly urgent need to accommodate the tremendous growth in renewable resources on a grid that was engineered to build generation and deliver it to load centers represents another risk. Current demand calls for a grid that can balance load across regional markets with variable generation resources, Little pointed out. The traditional system won’t work for renewables, he said: “We’ve got to upgrade the grid.”

Little said DOE has an “all of the above” strategy when it comes to reliability and security. A believer in public-private partnerships, Little said he would prefer that private entities invest in building out new technologies. He pointed to microgrids as a possible solution for military installations.

Little cautioned that big Western states planning to meet ambitious renewable-energy goals by getting their power from power-purchase agreements have too often not worked out those details. “What happens when we get to the point that there’s not enough power to go around?” he asked.

Wyoming Wind Potential May Be Dampened by Production Tax Hikes

  • Updated

Wyoming’s great wind potential has been recognized by academics, energy developers and politicians; however, whether that potential will be fully developed depends on many factors, including whether state officials will increase wind production taxes.

Those pass-through costs would likely be seen on electric bills in California, Oregon and Washington—destinations for Wyoming-generated wind. 

The state currently has 1,488 MW of installed wind capacity in which $3.2 billion in capital investments have been made, according to the American Wind Energy Association. Another 3,000 MW of projects are under development, with an additional 1,780 MW in “advanced development.” The National Renewable Energy Laboratory estimates the state has a technical wind-capacity potential of 472 GW and the potential to generate 1.6 million GWh from wind by 2020.

But state taxation of wind production is an ongoing issue that could impede further development. The state has a $1/MWh tax, which has remained the same since 2011. State Sen. Cale Case (R-Lander) thinks that should be as high as $5/MWh. 

Inadequate transmission capacity, not taxation, has prevented wind development, according to Case. Taxation is needed, he said, to compensate Wyoming residents for “losing something important to us,” which is “the best vistas in the Lower 48.” 

Case said in a phone interview that taxing wind is “not tit for tat” with coal-based revenue decreases. The owner of two Wyoming coal mines recently filed bankruptcy, pink-slipping 700 workers the same day, said Case. “That put a lot of people in a panic. We’re trying to backfill our revenues and we are looking at what we can do.” This includes considering a corporate tax and a mill levy. The state has neither a corporate nor a personal income tax. State sales tax is charged on wind farm supplies.

Any long-term benefits to Wyoming from wind power production are nominal, according to Case. He notes that 30 GW of Wyoming wind is scheduled to be used in Washington and Oregon to help those states meet their greenhouse gas reduction goals, which he says is more than other states’ contributions. “This seems an awful big sacrifice to make without getting something in return.”

Jonathan Naughton, director of the Wind Energy Research Center at the University of Wyoming, said previous production-tax increase attempts have not succeeded, save to cause uncertainty. “If you read between the lines,” Naughton said, proponents of higher production taxes “don’t want wind development.”

Naughton said taxing a renewable resource is difficult to justify. Some lawmakers understand that wind will not replace coal and any improvement in the plight of the state’s extractive industries is unlikely. Natural gas prices, as an example, would have to revert to $10/MMBtu for the natural gas industry to improve the Wyoming economy. New revenue sources are needed, but should not be at the expense of wind development, he said.

Naughton points out that 50 percent of Wyoming’s power consumption is used for extracting oil, natural gas and coal. Wind has the potential, said Naughton, to attract energy-intensive businesses. 

A report by University of Wyoming researchers Benjamin Cook and Robert Godby, released March 7, found New Mexico is the lowest-cost state in which to develop wind, trailed by Montana, Colorado and Wyoming. 

The authors looked at the ramifications of a $5/MWh tax and found this would increase Wyoming’s wind-development costs by 10 percent, making it the fourth most expensive state behind California, Nevada and Washington. The state’s estimated tax burden would rise from $3.05/MWh to $6.62/MWh, the highest in the West. Dropping current sales and production taxes and “replacing them with a gross receipts tax could both lower the cost of wind development in the state by 1.5 percent and raise tax revenues from wind generation over the lifetime of a project by over 8 percent.” 

Wyoming was one of the first states in which wind energy was developed, said Naughton, with some turbines erected in the 1970s and 1980s. The development push occurred in the early 2000s. 

The sticking point was how to get the wind to areas needing renewable energy, like California.

California wind and solar is nicely complemented by Wyoming wind, Naughton said. Afternoon wind peaks in Wyoming coincide well with California demand. “Any barriers are going to mess us up moving into this new energy mix,” Naughton said.

But transmission capacity is one such barrier. Of seven or eight proposed regional transmission projects, only three or four are now being pursued, he notes. Among them are the Energy Gateway project—developed by PacifiCorp to move energy to customers farther West—and TransWest Express, designed to move wind energy from the Chokecherry and Sierra Madre Wind Energy Project in Carbon County, Wyoming, to California.

The Wyoming section of the Energy Gateway project is roughly 140 miles. Until its launch, it had been 20 years since PacifiCorp expanded its transmission system, David Eskelsen, a PacifiCorp/Rocky Mountain Power spokesman, said. 

“Expansion of the transmission capacity is essential to wind development,” Eskelsen said, “but it’s worth noting that the major segments of Gateway West across Wyoming to eastern Idaho have yet to be completed.”

Rocky Mountain Power has 635 MW of net wind capacity from its Wyoming projects and another 506 MW of net wind capacity purchased via long-term contracts from other companies’ projects. It expects to add 1,150 MW of new wind capacity in the near future, plus its repowering projects are expected to increase existing capacity by more than 25 percent.

The Chokecherry and Sierra Madre Wind Energy Project, being developed by Power Company of Wyoming, should generate 3,000 MW or more when it comes fully on line in 2026. The power is earmarked for California. 

The project schedule was extended to 2026 by the Carbon County Board of County Commissioners at its July 2 meeting, allowing alignment of federal, state and county permitting requirements, Kara Choquette, director of communications for Power Company of Wyoming and TransWest Express, said.

Three transmission possibilities exist from the northernmost site: Gateway South, Gateway West and TransWest Express. 

TransWest Express is a 730-mile, 500-kV-capacity HVDC/HVAC line from Wyoming connecting to the California Independent System Operator’s grid in Nevada. It will initially be powered at 1,500 MW when it comes on line in 2023, but will be upgraded to 3,000 MW in 2025 or 2026.

Choquette says support for the Chokecherry and Sierra Madre Wind Energy Project has been tremendous. “From outside the state, there’s the perspective that Wyoming doesn’t like wind. That’s not a fair characterization of the state,” she said.

But a wind tax is imminent, according to Case, who says a ballot initiative is likely. 

“A lot of people support [higher taxes] as a way to modulate development a little bit,” Case said. “We are selling out too cheap for something we don’t consume . . . I’m convinced it will happen. Maybe not at $5, but it will happen.”

Wyoming’s great wind potential has been recognized by academics, energy developers and politicians; however, whether that potential will be fully developed depends on many factors, including whether state officials will increase wind production taxes.Those pass-through costs would likely be seen on electric bills in California, Oregon and Washington—destinations for Wyoming-generated wind. The state currently has 1,488 MW of installed wind capacity in which $3.2 billion in capital investments have been made, according to the American Wind Energy Association. Another 3,000 MW of projects are under development, with an additional 1,780 MW in “advanced development.” The National Renewable Energy Laboratory estimates the state has a technical wind-capacity potential of 472 GW and the potential to generate 1.6 million GWh from wind by 2020.But state taxation of wind production is an ongoing issue that could impede further development. The state has a $1/MWh tax, which has remained the same since 2011. State Sen. Cale Case (R-Lander) thinks that should be as high as $5/MWh. Inadequate transmission capacity, not taxation, has prevented wind development, according to Case. Taxation is needed, he said, to compensate Wyoming residents for “losing something important to us,” which is “the best vistas in the Lower 48.” Case said in a phone interview that taxing wind is “not tit for tat” with coal-based revenue decreases. The owner of two Wyoming coal mines recently filed bankruptcy, pink-slipping 700 workers the same day, said Case. “That put a lot of people in a panic. We’re trying to backfill our revenues and we are looking at what we can do.” This includes considering a corporate tax and a mill levy. The state has neither a corporate nor a personal income tax. State sales tax is charged on wind farm supplies.Any long-term benefits to Wyoming from wind power production are nominal, according to Case. He notes that 30 GW of Wyoming wind is scheduled to be used in Washington and Oregon to help those states meet their greenhouse gas reduction goals, which he says is more than other states’ contributions. “This seems an awful big sacrifice to make without getting something in return.”Jonathan Naughton, director of the Wind Energy Research Center at the University of Wyoming, said previous production-tax increase attempts have not succeeded, save to cause uncertainty. “If you read between the lines,” Naughton said, proponents of higher production taxes “don’t want wind development.”Naughton said taxing a renewable resource is difficult to justify. Some lawmakers understand that wind will not replace coal and any improvement in the plight of the state’s extractive industries is unlikely. Natural gas prices, as an example, would have to revert to $10/MMBtu for the natural gas industry to improve the Wyoming economy. New revenue sources are needed, but should not be at the expense of wind development, he said.Naughton points out that 50 percent of Wyoming’s power consumption is used for extracting oil, natural gas and coal. Wind has the potential, said Naughton, to attract energy-intensive businesses. A report by University of Wyoming researchers Benjamin Cook and Robert Godby, released March 7, found New Mexico is the lowest-cost state in which to develop wind, trailed by Montana, Colorado and Wyoming. The authors looked at the ramifications of a $5/MWh tax and found this would increase Wyoming’s wind-development costs by 10 percent, making it the fourth most expensive state behind California, Nevada and Washington. The state’s estimated tax burden would rise from $3.05/MWh to $6.62/MWh, the highest in the West. Dropping current sales and production taxes and “replacing them with a gross receipts tax could both lower the cost of wind development in the state by 1.5 percent and raise tax revenues from wind generation over the lifetime of a project by over 8 percent.” Wyoming was one of the first states in which wind energy was developed, said Naughton, with some turbines erected in the 1970s and 1980s. The development push occurred in the early 2000s. The sticking point was how to get the wind to areas needing renewable energy, like California.California wind and solar is nicely complemented by Wyoming wind, Naughton said. Afternoon wind peaks in Wyoming coincide well with California demand. “Any barriers are going to mess us up moving into this new energy mix,” Naughton said.But transmission capacity is one such barrier. Of seven or eight proposed regional transmission projects, only three or four are now being pursued, he notes. Among them are the Energy Gateway project—developed by PacifiCorp to move energy to customers farther West—and TransWest Express, designed to move wind energy from the Chokecherry and Sierra Madre Wind Energy Project in Carbon County, Wyoming, to California.The Wyoming section of the Energy Gateway project is roughly 140 miles. Until its launch, it had been 20 years since PacifiCorp expanded its transmission system, David Eskelsen, a PacifiCorp/Rocky Mountain Power spokesman, said. “Expansion of the transmission capacity is essential to wind development,” Eskelsen said, “but it’s worth noting that the major segments of Gateway West across Wyoming to eastern Idaho have yet to be completed.”Rocky Mountain Power has 635 MW of net wind capacity from its Wyoming projects and another 506 MW of net wind capacity purchased via long-term contracts from other companies’ projects. It expects to add 1,150 MW of new wind capacity in the near future, plus its repowering projects are expected to increase existing capacity by more than 25 percent.The Chokecherry and Sierra Madre Wind Energy Project, being developed by Power Company of Wyoming, should generate 3,000 MW or more when it comes fully on line in 2026. The power is earmarked for California. The project schedule was extended to 2026 by the Carbon County Board of County Commissioners at its July 2 meeting, allowing alignment of federal, state and county permitting requirements, Kara Choquette, director of communications for Power Company of Wyoming and TransWest Express, said.Three transmission possibilities exist from the northernmost site: Gateway South, Gateway West and TransWest Express. TransWest Express is a 730-mile, 500-kV-capacity HVDC/HVAC line from Wyoming connecting to the California Independent System Operator’s grid in Nevada. It will initially be powered at 1,500 MW when it comes on line in 2023, but will be upgraded to 3,000 MW in 2025 or 2026.Choquette says support for the Chokecherry and Sierra Madre Wind Energy Project has been tremendous. “From outside the state, there’s the perspective that Wyoming doesn’t like wind. That’s not a fair characterization of the state,” she said.But a wind tax is imminent, according to Case, who says a ballot initiative is likely. “A lot of people support [higher taxes] as a way to modulate development a little bit,” Case said. “We are selling out too cheap for something we don’t consume . . . I’m convinced it will happen. Maybe not at $5, but it will happen.”

SCE Thanks Gov. Newsom and Wildfire Legislation for Earnings Increase

  • Updated

Southern California Edison on July 25 reported a substantial increase in second-quarter earnings, up $122 million from the second quarter of 2018, and cited new wildfire legislation recently approved by Gov. Gavin Newsom as a primary reason for the growth.

SCE reported a net income of $392 million in the second quarter of 2019, up from a net income of $276 million in the second quarter of 2018. Representatives of the investor-owned utility on a July 25 earnings call said they appreciated the “significant leadership” the governor and Legislature had shown in approving AB 1054—a wildfire bill that creates an insurance fund to address third-party claims against IOUs for wildfires caused by their systems.

“We are encouraged by the regulatory and legislative policy changes to our risk profile,” SCE President Pedro Pizarro said. “This important legislation, with its crucial establishment of an insurance fund, works toward restoring California’s regulatory framework to provide the financial stability that utilities require to invest in system safety, reliability and resiliency.”

Some critics have called AB 1054 a utility bailout that was rushed through the legislative process (see CEM No. 1547 [14]). But Pizarro said AB 1054 is a comprehensive wildfire bill that holds “utilities accountable for mitigating wildfire risks and improves the regulatory compact by clarifying the determination of prudent wildfire operations.”

Earnings also increased due to the California Public Utilities Commission’s approval of SCE’s 2018 general rate case earlier this quarter, Pizarro said. The IOU estimates it will spend approximately $390 million on wildfire-related work in 2019 and $500 million to $700 million in 2020. About 27 percent of SCE’s territory is in high-fire-risk areas, Pizarro said, which is less than the IOU’s previous estimate of about 35 percent.

SCE will contribute $2.4 billion by Sept. 10 to the state’s wildfire insurance fund, Pizarro said, and approximately $95 million to the fund on Jan. 1 of each year for 10 years.

For year-to-date earnings, SCE reported a net income of $670 million through June 30, or $2.05 per share, compared with $494 million, or $1.52 per share, during the same period in 2018.

Automakers Cut Greenhouse Gas Emissions Deal With California Governor

  • Updated

Four automakers have reached a “framework agreement” with California officials on greenhouse gas emissions standards, Gov. Gavin Newsom announced July 25.

California’s deal with Ford, American Honda Motor Co., Volkswagen Group of America and BMW North America is an end run around the Trump administration’s proposed rollback that would freeze standards for six years and block California from setting its own rules to limit heat-trapping emissions from motor vehicles.

“We recognize the importance of compromise and we all agree that a framework maintaining a national solution is the preferred path forward,” the agreement says.

Automakers have raised concerns that the Trump administration’s proposal would result in years of litigation. The administration proposal would undo a 2012 agreement between California and the federal government that set harmonized standards for GHG emissions and fuel economy.

Automakers also are concerned about building for two markets—one for states following the administration’s proposed standards and the other for California and the 13 states that enforce California’s emissions limits, an option they have under Section 177 of the Clean Air Act. The 13 states include Colorado, Oregon and Washington.

The new agreement recognizes California’s authority to establish its own emissions rules and set requirements for marketing zero-emission vehicles, including electric cars, in the state.

“Participating companies are choosing to pursue a voluntary agreement in which California accepts these terms as compliance with its program, given its authority, rather than challenge California’s GHG and ZEV programs,” the agreement states.

Newsom urged other automakers and the administration to accept the agreement. “I now call on the rest of the auto industry to join us and for the Trump administration to adopt this pragmatic compromise instead of pursuing its aggressive rule change,” Newsom said in a statement.

Rep. Frank Pallone (D-N.J.), chairman of the House Energy and Commerce Committee, and Sen. Tom Carper (D-Del.), ranking Democrat on the Senate Environment and Public Works Committee, praised the agreement. Carper said the Trump administration’s proposal would “send the automotive sector into years of litigation and economic disarray.”

Rep. Debbie Dingell (D-Mich.), who last month chastised Trump administration officials at a House hearing for what she called their failure to negotiate in good faith with California, called the agreement a “positive development.” She added that the framework should be “a catalyst for all stakeholders to go back to the table.”

Mary Nichols, chair of the California Air Resources Board, said if the White House balks at accepting the new agreement, the state would “work with individual car makers to implement these principles.” She said if the administration proposal is finalized, the state would continue enforcing its rules and challenge the administration’s rule in court.

The Alliance of Automobile Manufacturers took a cautious stance on the agreement. In a statement, the group reiterated its support for “year-over-year increases in fuel-economy standards that align with the marketplace, while also advocating for one national program.”

However, the group also said that standards required under the 2012 program for model years 2022 to 2025 “are not attainable and need to be adjusted.”

“Individual companies may have different perspectives on how best to achieve greater certainty,” the statement said.

Under the deal, the four automakers’ “terms for a national program” include year-over-year increases in emissions limits at a nationwide annual average of 3.7 percent, for model years 2022 through 2026. Of the 3.7 percent, 1 percent of the annual improvement could be covered through credits earned by selling electric vehicles, including battery, hybrid, plug-in hybrid or fuel-cell drives.

The 3.7-percent annual improvement target over five years was a concession to automakers. Under the 2012 program, the automakers would have to achieve 4.7-percent annual improvements over four years.

Under the agreement, automakers also would receive incentives to adopt nondrive technologies for reducing GHG emissions, such as aerodynamic improvements.

The agreement would result in “at least 30 percent more greenhouse gas emissions reductions” compared with a market split between vehicles built to the Trump administration’s proposed standards and those following standards set by California and the 13 other states that enforce California’s rules, according to Newsom’s office.

Committee Advances Energy R&D Bills

Legislation authorizing funds for solar, wind and fossil-fuel energy research and development on July 24 passed out of the House Science, Space, and Technology Committee.

Rep. Eddie Bernice Johnson (D-Texas), chairwoman of the committee, said the bills would “directly address the growing issue of climate change by focusing the federal government’s energy research efforts toward cutting greenhouse gas emissions.”

Rep. Randy Weber (R-Texas), ranking Republican on the panel’s Energy Subcommittee, said the fossil-energy bill (HR 3607) would result in “narrowing” the goals of the Department of Energy’s fossil-fuel energy research program to “focus almost entirely on emissions-control technologies.” The committee rejected Weber’s amendment to reduce authorized spending and to direct DOE to research a “broad range” of fossil-energy production and use technologies.

HR 3607 includes language directing DOE to give priority to technologies, including carbon capture, use and sequestration, with the “potential” to meet emissions-reduction goals in the 2015 Paris climate accord.

The bill also would direct DOE to study extraction of rare earths from coal and coal byproducts; advanced combustion and fuel-cell technologies; direct-air capture of carbon dioxide; and methane leak reduction.

Authorized spending in fiscal years 2020 through 2024 would total $4.56 billion.

The committee also reported out HR 3597, authorizing $1.49 billion for solar energy research projects over the next five fiscal years. The bill would direct DOE to undertake research into reusing and recycling solar-photovoltaic devices.

For wind energy R&D, the committee reported out HR 3609, authorizing nearly $573 million in spending in fiscal years 2020 through 2024. The bill includes direction for DOE to study technologies to reduce wind energy impacts on eagles, bats and marine wildlife.

House Passes Energy-Water Study Bill

The House on July 23 passed by voice vote a bill that would direct DOE to integrate water issues into its research and development programs.

Under the bill, HR 34, DOE would have one year to draft a plan for meeting the bill’s goals, which include advancing energy technologies that minimize freshwater withdrawals and consumption and increase water efficiency.

The plan would have to touch on developing advanced energy generation cooling technologies; treatment and use of produced waters and wastewater from oil and gas extraction; and energy-efficient technologies for water distribution, treatment, supply and collection systems.

Congress Urged to Boost Water Project Funding

Congress should consider allowing Reclamation Fund revenues to be spent on water projects without going through the appropriations process, a Western water official said at a July 24 House subcommittee hearing.

Tony Willardson, executive director of the Western States Water Council, told a hearing of the House Natural Resources Committee’s Oversight and Investigations Subcommittee that Congress should consider changing the Reclamation Fund into a fund in which receipts could be used for authorized expenses in the year they’re deposited without congressional appropriation. Under a 1914 statute, Reclamation Fund revenues must be appropriated by Congress before they can be spent.

Rep. T.J. Cox (D-Calif.), the panel’s chairman, said use of Reclamation Fund revenues is currently left to the “unpredictable whims of Congress.”

Speaking in opposition, Rep. Louie Gohmert (R-Texas), the subcommittee’s ranking Republican, said switching to a revolving fund would lessen congressional oversight.

Revenues are building up in the fund. Between fiscal years 2012 and 2018, the ending balance increased from $10.84 billion to $16.63 billion, according to testimony from Grayford Payne, the Bureau of Reclamation’s deputy commissioner for policy, administration and budget.

Willardson said in written testimony that Congress has used the unappropriated balances as an accounting maneuver to reduce overall federal borrowing.

“You could say that Congress has borrowed the ‘golden’ egg and left the goose sitting on a Treasury IOU,” his testimony said.

Reclamation Fund revenues could be used for deferred maintenance, dam safety repairs, fish recovery and water conservation projects, Willardson said. He noted that the estimated cost of “major rehabilitation and replacement needs” over the next five years totals $2.9 billion. An additional $1.6 billion is needed for new water and power projects for the Central Valley Project, the Yakima Integrated Plan and the Platte River, he said.

Payne estimated the cost of dam-safety needs for the next decade totals $1.3 billion.

Sources of Reclamation Fund revenues include power sales receipts and royalties from oil and gas leasing on federal lands.

House Dem Leaders Call for Net-Zero GHG by 2050

House leaders on July 23 rolled out a plan for the U.S. to lower greenhouse gas emissions to net zero by 2050.

The House Energy and Commerce Committee plans a series of hearings to begin drafting legislation. Hearings began July 24 with testimony on decarbonization heard by the panel’s Environment and Climate Change Subcommittee.

At the hearing, witnesses said meeting a net-zero goal would require a broad range of energy-efficiency, renewables, storage and carbon-capture technologies, along with zero-carbon fuels for transportation and heat-dependent industrial uses.

“Just like you’re in Vegas, don’t put all your chips on one or two slots,” Karl Hausker, senior fellow at the World Resources Institute’s climate program, said.

Armond Cohen, executive director of the Clean Air Task Force, said a power generation system dominated by wind and solar would be impractical because of the large amount of storage needed to accommodate seasonal variability.

In a California system with 100 percent wind and solar generation, the result of seasonal variability is that “roughly 27 percent of hours of the year cannot be served by wind and sun,” Cohen said in written testimony.

“In theory, we could use battery storage to harvest surpluses and use them in deficit periods. But this is where cost comes in. The sheer amount of storage that must be built to capture maximum surplus, and then [is] utilized infrequently, becomes cost-prohibitive, even at very low storage costs,” he added.

Cohen estimated the costs of building such a storage system at $2.9 trillion, assuming low storage costs of $80 per kWh. In addition, he said, “Only a small amount of the storage capacity would be used regularly to balance daily variations in solar and wind output. Most of the storage capacity would need to be built to store peak seasonal surplus and thus only cycle seasonally,” he added.

Upcoming committee hearings will focus on grid modernization and reducing industrial and transportation emissions.

“Much has changed in the decade since Congress last considered a comprehensive climate plan, including transformative advances in clean-energy technology and a far deeper understanding of climate science and the cost of continued inaction,” Rep. Frank Pallone (D-N.J.), committee chairman, said in announcing the net-zero-by-2050 plan.

At the subcommittee hearing, Rep. Greg Walden (R-Ore.), the full committee’s ranking Republican, spoke against what he called “top-down policies that have been shown to be costly and harmful to consumer and worker interests.”

Rep. John Shimkus (R-Ill.), the subcommittee’s ranking Republican, called for exporting U.S.-made carbon-capture technology to developing countries expanding their dependence on coal-fired generation.

Battery Experts Say Recycling Is Supply Key

Greater recycling of lithium-ion batteries from electric vehicles would increase the domestic supply of battery raw materials, spur domestic battery manufacturing, and reduce sourcing from countries with lax labor and environmental standards, industry witnesses told a July 17 Senate hearing.

The witnesses testified at a Senate Environment and Public Works Committee hearing on battery production and waste management.

Recycling is “low-hanging fruit” for boosting domestic supplies of battery raw materials, Sen. Ben Cardin (D-Md.) said.

James Greenberger, executive director of the trade group NAATBatt International, said in written testimony that 65 percent of cobalt needed for EV demand in the U.S. by 2040 could be supplied by recycling, according to a National Renewable Energy Laboratory study.

Greenberger urged U.S. policymakers to match China in boosting demand for domestic battery manufacturing by simplifying collection of used batteries and keeping recycling costs down. Currently, he said, the costs of recycling exceed the value of materials that could be recovered and sold.

Michael Sanders, senior advisor to the rechargeable-battery consulting firm Avicenne Energy, said it costs roughly $5,000 to recycle an EV battery. About $3,500 of the cost is recoverable by extracting and reselling the battery’s materials, he estimated.

Sanders also testified that establishing battery-collection facilities, as China did, would simplify recycling.

EVs have come under fire from Republican lawmakers because of the labor and environmental impacts of battery production and mining of raw materials. Sen. John Barrasso (R-Wyo.) said 60 percent of global cobalt supply is mined in Congo, and Chinese plants processing cobalt for battery manufacturing cause “significant environmental impacts.”

According to Greenberger, more than 80 percent of cobalt sulfate used in batteries is processed in China, which makes 75 percent of all lithium-ion batteries worldwide.

Sen. James Inhofe (R-Okla.) referenced child labor used in Congolese cobalt mines.

Sanders said child labor concerns involve 20 percent of Congo’s cobalt mining. For the rest, he added, producers and original equipment manufacturers have instituted “traceability” programs to avoid purchase from mines employing children.

Sanders said research is underway to reduce cobalt need for lithium-ion batteries. “The percentage of cobalt per battery is likely to go down substantially,” he said.

Ajay Chawan, associate director of Navigant Consulting, said Toyota has announced plans to roll out a solid-state lithium-ion battery by 2022. Compared to batteries with liquid electrolytes, solid-state batteries would need less cobalt and, in addition, would have greater energy density, Chawan said.

Lawmakers Urged to Create Grid Resilience Metrics

Metrics quantifying the value of grid resilience would speed deployment of energy storage resources by making a stronger case for their cost-effectiveness, the head of the Energy Storage Association told a House subcommittee hearing July 17.

Kelly Speakes-Backman, CEO of the trade group, said, “The major delay in having [storage] deployed on a major scale is really how it fits within the regulatory construct and how it fits within the energy grid, integration itself. It’s really more of a commercial question that’s happening more than a technology question. I think the technology is ready,” she told a hearing of the House Science, Space, and Technology Committee’s Energy Subcommittee.

The subcommittee held a hearing exploring legislation to boost grid and storage research, the Grid Modernization Research and Development Act, and two bills focused on storage—HR 2909, the Promoting Grid Storage Act, and HR 2986, the Better Energy Storage Technology Act.

HR 2986, co-sponsored by Rep. Jaime Herrera Beutler (R-Wash.), would direct DOE to set up a research and development program for grid-scale storage research and development, including cost targets and a mandate for at least five demonstration projects.

In her written testimony, Speakes-Backman said that “without a well-defined and broadly accepted valuation model, resilience will remain challenging to fit into the cost-benefit analysis and program designs” that grid operators, utilities and regulatory commissions use to weigh cost-effectiveness.

She urged the subcommittee to consider mandating DOE to work with “government and industry stakeholders” to develop resilience quantification methods.

Also at the hearing, the head of the Advanced Energy Management Alliance, a trade group for distributed resources, called for helping private-sector technology developers validate their innovations through research programs run by DOE and its national laboratories.

Katherine Hamilton, the group’s executive director, said it is important to “bring entrepreneurs to test and make sure that we have proof of concept, because no utility is going to purchase a piece of equipment that was designed in somebody’s basement. They need to know DOE and the national labs have given it the seal of approval and have shown credibility by testing it and making sure this all works.”

DOE Funds Tribal Energy Projects

The Department of Energy on July 23 announced $16 million in funding for 14 tribal energy projects, including six in the West.

The tribes will put up $23 million to fund the cost-shared projects, DOE said.

DOE grants include:

$2 million for the Colusa Indian Community Council in Colusa, California, to expand electrical distribution and battery storage systems. The council also was awarded nearly $1.15 million to build a 448-kW parking-canopy solar PV system.

$2 million for the Rincon Band of Luiseño Indians in Valley Center, California, to develop two microgrids integrating about 3,100 kW of solar PV capacity with 2,450 kW of standby battery storage and 2,920 kW of diesel-fueled capacity.

$2 million for Aha Macav Power Service to develop a 2.3-MW solar PV array for the Fort Mojave Indian Tribe, whose 42,000-acre reservation is located where California, Nevada and Arizona meet along the Colorado River.

$2 million for the Northern Cheyenne Tribe in Lame Deer, Montana, to install a 2.6-MW solar PV array and 400 kW of behind-the-meter solar for tribal facilities.

$313,406 for the Fort Peck Assiniboine and Sioux Tribes in Montana to install a 72- to 78-kW rooftop solar PV system and integrate efficiency measures into a 50,039-square-foot wellness center.

FERC Opens Houston Office for LNG

The Federal Energy Regulatory Commission is opening a regional office in Houston to handle permitting for liquefied natural gas export terminals.

FERC Chairman Neil Chatterjee said the commission is opening an LNG review and inspection division, with 20 employees in Washington, D.C., and an additional eight employees to be hired for the new office.

Chatterjee said the growth in number and complexity of proposed LNG projects necessitated establishing a commission office in Houston.

“Much of the work related to those LNG projects, and the expertise it requires, is based in and around Houston,” he said.