Arizona Solar Center

Arizona Corporation Commission- MODIFICATIONS TO THE ARIZONA CORPORATION COMMISSION'S ENERGY RULES

On May 26th 2021, the Arizona Corporation Commission reconsidered and passed a Clean Energy Rules package. The energy rules package includes 100% carbon-free energy in Arizona by 2070. And the carbon reductions are requirements and not goals.

Revised carbon emissions reductions levels by the following:
• 50% by December 31, 2032
• 65% by December 31, 2040
• 80% by December 31, 2050
• 95% by December 31, 2060
• 100% by December 31, 2070

Most importantly, the passed rules retained all the beneficial policies and requirements around storage and distributed storage. Specifically, the rules include a 35% energy efficiency requirement, which is the nation’s first distributed storage/solar requirement, preferential treatment for energy procurement from coal-impacted communities and tribes, as well as a complete rewrite of the IRP rules that will require the Commission to approve, rather than acknowledge a preferred portfolio of resources.

This is not yet final, as a result of substantive changes made to the original Recommended Opinion and Order, the amended energy rules package will be sent back through the formal rulemaking process. An updated schedule will be implemented that will allow for written comments and public comment on the record. Interested parties can submit formal written comments to the docket beginning July 9, 2021 through August 20, 2021. Public comment sessions will be held on August 16 and 19, 2021, at 10am.

The passage of the Energy Rules as they presently stand reflects a significant win for ratepayers, for the people of Arizona and for the Solar Energy Industry.

The Nature Conservancy has submitted their report "Arizona Thrives - A Path to a Healthy and Prosperous Future" to the ACC. Interesting.

APS has submitted their report, The Solar Center has slightly reformatted this report by rotating the pages for easier viewing. APS has provided two presentations to address the ACC questions. Worth a read.

Underachieving Solana Solar Plant Keeps Polluting Arizona's Air

Ray Stern | November 28, 2018 | 8:07am

At about 9:40 a.m. on August 28, a toxic vapor cloud rose from the shiny rows of parabolic mirrors at the Solana concentrated solar plant just west of Gila Bend, Arizona.

Workers notified the control room, where managers immediately shut down the $2 billion plant, which was built by the Spanish firm Abengoa with help from U.S. taxpayers. The facility works by using its 900,000 mirrors to focus sunlight on pipes in front of the mirrors that contain "heat transfer fluid," (HTF), a toxic sludge that becomes super-heated by the sun's energy before being pumped to two 140-megawatt steam turbines.

That morning, according to county records, one of the larger, 2-inch feeder pipes developed a crack above a weld point and burst, spraying and spilling 1,000 gallons of molten HTF into the environment. Most went "into concrete containment and a fraction of this overtopped to soil," Carrolette Winstead of Abengoa told county officials in a September 7 email. Winstead estimated about 7 tons of material had been released.

Most of the release was in fluid form, but an estimated 2.6 tons evaporated into the air. About a quarter of the emissions were of biphenyl, a chemical sometimes used as a food preservative that's dangerous to breathe. No one was injured, but Maricopa County's air quality division issued the plant an initial notice of violation over the incident, which records show was self-reported by plant administrators.

The August incident was only the latest such problem to strike the plant, which had its first full year of operations in 2014. Its ongoing air-pollution incidents clearly complicate the idea of "clean energy." But the biggest challenge, stock filings reveal, is the weak performance that threatens Solana's financial viability.

As Phoenix New Times has reported since late 2014, the plant habitually generates less than 75 percent of the electricity that it's supposedly capable of cranking out.

The plant does have its benefits, even as an underachiever.

When most people think of solar power, they're thinking of photovoltaic solar panels. Solana's special skill is to keep making electricity for about six hours after solar panels quit for the day. The heat-transfer fluid running through the pipes at Solana stays hot in this overtime period, keeping those steam turbines turning. At its so-far theoretical max production level, Solana could pump out the same amount of electricity used each year by 71,000 households, according to Abengoa.

This photo from Solana plant operators submitted to the county shows a hairline crack above a weld in a pipe that burst, causing 1,000 gallons of heat transfer fluid to spill on August 28.
Maricopa County
Without additional battery storage, of course, Solana couldn't meet the actual electricity demand of even a single average Arizona household (about 14 megawatt hours), because it provides power for only part of a 24-hour day. But according to Arizona Public Service, it helps offset some of its power load in the evening.

Owned by a conglomerate of investors called Atlantica Yield, Solana agreed to sell its power to APS for 30 years. The utility estimated in 2013 that, on average, each customer pays about $1 extra per month because of Solana.

For that buck, APS customers can feel a warm fuzzy that a fraction of their kilowatt hours are generated with clean, Solana solar power. Except it's not always so clean. Solana has an unseemly air pollution problem.

In 2016, the county slapped the plant with a $1.5 million fine — the largest it's ever imposed. Leaking HTF was the culprit then, too.

A division manager for the county's air-quality department told New Times in 2016 that HTF released at the plant emitted twice as many volatile organic compounds than a natural-gas plant of the same size. (VOCs lead to ozone pollution).

Officials believe that nearby residents, had they been outside during Solana's emissions, could have smelled the chemical. The manager predicted that HTF pollution problems would continue.

In 2017, the plant self-reported three HTF leaks. Officials didn't fine Solana because plant operators were following the rules when equipment failed.

That was also the case with the August 28 spill, and the county didn't levy a fine. The plant was offline for two days until the weld on the pipe could be repaired.

Solana workers are accustomed to containing HTF spills, records show.

The 12-month "rolling total" for VOCs emitted by the plant — including the 2.6 tons released in August — was 17.2 tons as of September 11, plant officials reported to the county. The total amount of released "hazardous air pollutants," most of which is biphenyl, was 4.8 tons.

Emiliano Garcia, vice president of Atlantica Yield's North America operations, gave a brief response to questions about the plant's struggle with air pollution when contacted this week.

"As any industrial facility, we are exposed to equipment failures that could cause emissions," Garcia said. "Arizona Solar One is committed to minimize those failures and we are self-reporting, remediating any emissions, and working inside our permit parameters. The records are public and we follow strictly the legislation."

Garcia also addressed Solana's performance, which has not met expectations.

For 2016, the plant generated 643,443 megawatt hours. For 2017, it produced 724,505 — not much higher than the plant produced in 2015.

Garcia pointed out that 2016 and 2017 are not "representative" years for the plant. As New Times previously reported, a monsoon-driven microburst knocked out Solana for weeks in summer 2016. Two transformer fires in July 2017 cut the plant's production by more than half.

All these problems have been "completely solved," Garcia maintained.

They'd better be, public records show, if the plant is to remain viable. Atlantica Yield's March 2018 filing with the U.S. Securities and Exchange Commission acknowledges that "Solana has not yet achieved its technical capacity on a continuous basis," and that its financial health is on the line.

Because of the plant's under-production, Abengoa has been forced to make extra payments on Solana's considerable debt. In late 2017 and early 2018, the Spanish company paid an extra $120 million to compensate for the plant's lower-than-expected electricity output, records show. Starting in December, Abengoa must pay an additional $13 million per year for the next 10 years. But Atlantica Yield disclosed to investors that it can't guarantee Abengoa will fulfill that obligation.

If it doesn't, "Solana may have a negative financial impact or may not reach its target production, which could have a material adverse effect on our results of operations and cash flows."

Furthermore, the plant's "underperformance" could cause it to stumble on obligations to Liberty Interactive Corporation, which made a $300 million investment in the plant — a situation that would "adversely affect the cash flows expected from that project."

On the plus side for the plant: The filing shows that plant will pay no federal taxes for the next 10 years.

Garcia agreed that the SEC filing describes that Solana "performed below expectations" in 2016 and 2017. But he emphasized the 2018 numbers, which show that Solana may be on its way to a record production year. The plant has produced 655,344 megawatt hours so far this year, according to the Federal Energy Regulatory Commission's Electric Quarterly Report site. The output for July to September this year has already broken its record for the same time in previous years, Garcia noted.

Even if it sets a new record in 2018, Solana will fall well short of its 900,000-plus goal for generated megawatt hours.

And it will still have its troublesome, ironic, air-pollution problem.

Dropped Pallet of PV Modules

On October 26, 2017 a pallet of 33 solar modules got "delivered". After spending an hour checking it was determined that amazingly this 1400 pounds of solar modules didn't break a single module after being dropped off the back of the truck.

A Case Study in the Movement towards a 100% Renewable Grid–a Bright Future

Based on recent results, the cost of renewables is now cheaper than coal generation. © American Public Power Association.

In this article, we explore current and future trends in utility-scale solar and wind and the potential for the movement to a 100% renewable electric grid. Using some recent renewable power purchase agreements (PPAs), we perform a case study on an electric co-op in Colorado – the Platte River Power Authority (www.prpa.org/). As we are considering utility-scale renewable project pricing, let’s look at PRPA’s 2017 resource cost as a comparison (see Figure 1).

As of October 2017, PRPA’s total generation costs were averaging about $31/megawatt-hour (MWH), with their coal generation (Rawhide and Craig units) averaging about $27-28/MWH.

Developments for Utility-scale Renewable Power Purchase Agreements (PPAs)

Austin Energy announced in December 2017 that it had accepted a record low US bid for a solar power purchase agreement (https://bit.ly/2DdQJ02). Estimates put this bid as low as $21/MWH fixed for 15 years.

Also, the results of Mexico’s most recent energy auction were released on November 22, 2017, with 16 different bids at an average price of $20/MWH (https://bit.ly/2ATzwYL).

Canadian Solar was awarded 370 megawatts (MW) and Enel Group a new record low wind PPA at $18/MWH (https://bit.ly/2ATzwYL). In December 2017, Xcel Energy released its RFP responses. Xcel received 96 bids for wind, with the median at $18/MWH totaling over 42 gigawatts. Wind plus storage bids had a median bid of $21/MWH.

Based on these results, the cost of renewables is now cheaper than coal generation; as shown above, PRPA’s average cost for coal generation is above $27/MWH. Since PRPA is a located close to the lowest cost coal reserves of the Powder River Basin (https://yhoo.it/2Qh7Rrp) of Wyoming, this is one of the lowest cost coal-fired power plant operators.

The average cost for large investor-owned utilities in 2016 was about $35/MWH for coal, according to the US Energy Information Administration (EIA). Another important aspect of the above renewable bids is that the RFP-to-bid process takes time – maybe over a year. This means we are seeing old renewable energy cost dynamics at play, and current costs may be even cheaper today.

Future Utility-scale Solar Developments

First Solar’s new utility-scale solar module – December 2017 First Solar, one of the largest utility-scale solar module manufacturers, recently started manufacturing a new utility-scale module – the series 6. This new larger format module will not only reduce the cost of the module but also reduce many other balance of system costs. Here is an article that recaps First Solar’s new technology from the firm’s presentation: https://bit.ly/2DEuG7a.

This new module is estimated to cost 40% less to manufacture and will also lower labor installation cost by up to 55%. First Solar is projecting a 40+% decrease in full system costs by 2020. First Solar has confirmed it currently has the lowest cost project structure, so future PPA pricing could be trending below $15/MWH.

The Chinese decision – June 2018 On June 1st, 2018, China’s National Development and Reform Commission (NDRC) set a limit on solar installations to 30 gigawatts (GW) for 2018 (https://bit.ly/2DFEgqq). The ripple effects on the Chinese solar supply chain have driven down costs and the average selling prices of silicon-based solar modules from China. Here is a quote from Cao Haiyun, the CEO of Jinko Solar on June 26, 2018 (https://bit.ly/2N9DPE6): “In terms of cost improvement, we are targeting I think a 20% improvement. And then roughly for the multi and mono products, the cost will improve to 24% to 25%.

Firstly, US$0.24 to US$0.25 is by the end of the year. It’s not Q4 average number. And second one for 2019, it’s too early to evaluate the cost roadmap.” So, with the new Si-based solar module pricing, we could have PPAs fall well below $19/MWH in the USA.

The current trends show First Solar still in the lowest cost position, but the Chinese Si-based manufactures are also reducing costs rapidly. The upcoming competition in the utility solar space will lead to much lower bids in response to Request for Proposals (RFPs) executed in 2018 and 2019. Looking at these new cost dynamics, bids in 2018 and 2019 will fall well below $20/MWH, making the move to a 100% renewable electric grid more feasible.

PRPA Case Study: How Much Renewable Energy Generation Can We Really Achieve?

To compare these recent low PPAs with 2017 generation costs for a utility, I performed a case study on an electric co-op in Colorado – the Platte River Power Authority (PRPA). PRPA is an electric co-op that serves four cities in Colorado: Fort Collins, Longmont, Loveland, and Estes Park. Over the past year, the communities that PRPA serves have called for more renewables and less coal-fired generation (https://bit.ly/2D0c3cS). This trend is not just municipalities, but large corporations (with large electrical loads) as well (https://bit.ly/2xYxKoz). PRPA had about 75% coal generation (Craig and Rawhide) in 2017, at a cost of $27-28/MWH. PRPA also buys federal hydropower (LAP in the graph) at about $32/MWH.

Simulating Renewables with PRPA Load Data

Using the current data points for PPA pricing, I have run grid simulations for PRPA by using the most recent 12 months of hourly load data (8760 model) for this electric co-op. I loaded the 2017 8760 hours of PRPA loads into Homer Energy software.

Homer Energy is an economic grid and micro-grid software modeling platform. Homer analyzes all the possible sources for electric generation and matches each hourly load for the year, with solar, wind, storage, grid sales and purchases. In doing thousands of simulations, Homer arrives at the mix of generation, electric purchases and sales that will minimize the levelized cost of energy (LCOE). The LCOE is a very similar metric to a long-term power purchase agreement (PPA) – a fixed cost for 15-20 years. My simulations included wind, solar, natural gas generation, storage, grid purchases and sales, and they assumed no coal generation. I ran over 100,000 simulations, and many of them had the levelized cost of energy (LCOE) under $25/MWH. The way to look at these results is as “what if” scenario analytics.

Grid Simulation Result

My assumption for solar was for an on-site solar array at PRPA’s existing coal and natural gas plants and for wind projects in Wyoming. I used PPA costs of about $24/MWH for both wind and solar to include some estimates for integration costs.

This modeled system picked 600 MW of solar and 450 MW of wind, resulting in 80% (48.2% wind, 31.4% solar) renewable energy penetration, with grid sales and purchases of about 20% each. The LCOE for this simulation is about $25/MWH, lower than all the current generation costs for PRPA, and lower than PRPA’s total average current cost of generation of $30.85/MWH.

The LCOE of PRPA’s current generation mix would be much higher due to inflation. A future proposed generation mix for PRPA is show above in Figure 2. We can see from this modeling that we can have a future state of 80% renewables, with a lower LCOE than the current cost of coal generation. Also, PRPA would be generating more renewable energy than the energy it provides to its municipalities, selling the excess to others in Colorado – helping them with their renewable targets.

Another important dynamic is the capacity factors for wind and solar. For our Colorado example, wind and solar combined can achieve a 60% capacity factor or better; wind can be over 45%, and utility-scale solar 25%. Wind and solar work well together, as it is windier in the winter and shoulder seasons, and windier at night, whereas solar produces more in the summer and in the daytime.

Summary

The dramatic declines in the cost of renewables are starting to change electric markets and utilities. While there are still technical challenges in a fully 100% renewable grid, how about the 80% renewable grid by 2025-2030?

By combining the extremely low cost of solar and wind, further cost reductions in energy storage, our modeling has shown this high percentage of renewables to be economically achievable. These simulations included wind, solar, natural gas, storage, grid purchases/ sales, and no coal generation. The new energy economy looks bright indeed.

About the Author

Bill Ellard is an energy economist and consultant, servicing businesses, utilities, and municipalities, and focusing on distributed energy implementation, solar energy, demand side management, microgrid development, facility energy management, and renewable energy integration. He can be reached at This email address is being protected from spambots. You need JavaScript enabled to view it..

From: https://www.ases.org/a-case-study-in-the-movement-towards-a-100-renewable-grid-a-bright-future/