Has Permian Productivity Peaked?

The U.S. shale industry might have just received a huge windfall with the nine-month extension of the OPEC cuts. Shale output was already expected to come roaring back this year, but the extension of the cuts provides even more room in the market for shale drillers to step into.The sky is the limit, it seems. However, there are growing signs that the U.S. shale industry could be reaching the end of the low-hanging fruit. Or, more specifically, drilling costs are starting to rise and the enormous leaps in production that can be obtained by simply adding more rigs also appears to be running into some trouble.

Source: Has Permian Productivity Peaked? | OilPrice.com

Posted in Energy

Microgrid Goes Online At Schneider Electric’s North American HQ

Project partners have announced completion of a new microgrid at the North American headquarters of energy management and automation company Schneider Electric.

iStock-91363404 Microgrid Goes Online At Schneider Electric's North American HQ

Located at the company’s Boston One Campus (BOC) in Andover, Mass., the microgrid was built by Schneider Electric and REC Solar, a subsidiary of Duke Energy Renewables and provider of commercial solar and energy solutions. Duke Energy Renewables, which owns a majority interest in REC Solar, owns the microgrid system and solar array and is selling the power to Schneider Electric through a long-term power purchase agreement.

“The integration of an advanced microgrid at the Schneider Electric campus reduces its energy costs, incorporates more sustainable energy and delivers demand-side efficiency, while also offering resiliency to the facility in the event of a loss of power from the grid,” says Chris Fallon, vice president of Duke Energy Renewables. “Additionally, in partnership with Schneider, we can research and develop new microgrid technologies, solutions and applications in a real-world environment.”

The microgrid is expected to generate more than 520,000 kWh of electricity per year. It includes a 354 kW AC solar array with 1,379 solar modules that power the system. The microgrid also incorporates a natural gas generator as an anchor resource, allowing the solar panels to operate during grid outages to maintain critical operations.

“With the growth in the availability of affordable renewable energy and other distributed energy resources, energy consumers are more empowered than ever to use microgrids to generate and manage their consumption through active involvement in the market,” says Schneider Electric’s Mark Feasel. “Schneider Electric used this model at BOC to build an advanced microgrid that reduces costs, incorporates more sustainable energy and takes control of its energy future. It will also be a living laboratory at our North American R&D hub, driving global innovation in energy storage and distributed energy resource management solutions.”

In addition to the BOC site, Duke Energy Renewables, Schneider Electric and REC Solar have a second microgrid project under way for the Montgomery County, Md., Public Safety Headquarters and Correctional Facility.

Duke Energy Renewables will own the two Montgomery County microgrids, which will consist of a 2 MW AC solar project and two combined heat and power (CHP) units. The CHP systems will save energy by using waste heat from on-site power generation to heat and cool the buildings. In addition, “island mode” capabilities of the microgrids will allow continued operation of Montgomery County’s critical facilities for extended periods during power outages.

REC Solar will build and operate the solar facility, and Schneider Electric will design and implement the microgrid project, which is expected to become fully operational in 2018.

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California is getting so much power from solar that wholesale electricity prices are turning negative

The extraordinary success of solar power in some pockets of the world that combine sunshine with high investment in the technology mean that governments and energy companies are having radically to rethink the way they manage—and charge for—electricity.

California is one such a place.

On March 11, it passed a milestone on the route to powering the whole state sustainably. For the first time, more than half the power needs of the entire state came from solar power for a few hours that day, according to the US Energy Information Administration (EIA).

The power came from utility-scale solar photovoltaic farms, solar thermal plants, and the panels installed on private homes. Based on the data it collects, the EIA estimated that in total that capacity produced 4 million kWh of electricity during peak times on March 11.

It’s a massive and rapid change: Just 15 years ago, the state produced almost no power from solar at all.

The spikes also have a big effect on wholesale energy prices, which dipped to zero or even to negative territory this spring during certain hours in California, the EIA said. That’s in sharp contrast to the same hours in the month of March between 2013 and 2015, when wholesale prices ranged from $14-45 MW/h.

Negative prices usually happen because there’s a glut of renewable energy, but non-renewable generators are also producing. (They don’t shut them off completely because of the high costs of restarting.)

California now accounts for a sizable chunk of the US market, having the highest energy demand of any state after Texas. It also has almost half of all the solar power in the US.

Free power?

Some of the surge is seasonal. Spring tends to have temperate weather, meaning the demand for power used for heating and cooling is lower. So while solar cells will produce more energy in the summer, there’ll also be a lot more power used.

The abundance of renewable power at certain times means grid managers have a new task on their hands—dealing with all the energy.

We don’t yet have batteries capable of storing huge amounts of electricity, and grids can only support so much. There are times, therefore, when really successful renewables have to be “curtailed,” or stopped from feeding the grid, to prevent surges. (Just as there are times when other “baseload” power sources need to step in, for example when the sun’s not out and at night.)

Germany, which has also invested heavily in both solar and wind power, sometimes has so much power it has to pay neighboring countries to use it—a quirk of the transition to high levels of renewables it calls the Energiewende, or energy transformation.

This doesn’t mean, however, that Californians are paying nothing for their power because wholesale prices don’t translate directly into retail prices, which are based on averages, not single days. But it will mean energy companies start to rethink how they deliver and charge for electricity as the mix of renewables increases.

Read this next: Has lithium-battery genius John Goodenough done it again? Colleagues are skeptical

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Posted in Energy

Drivers Behind Flattening CO2 Emissions

The International Energy Agency (IEA) recently reported that carbon dioxide emissions from energy use remained flat in 2016, the third year in a row. This is a noticeable departure from the 21st century trend which has seen global carbon dioxide emissions rise by some 40% in just 14 years. The Guardian reported this story and added the by-line “International Energy Agency report puts halt in emissions from energy down to growth in renewable power”. But the story within the energy system has more facets than this (Data sourced from the BP Statistical Review of World Energy).

IEA CO2 Emissions

Although global growth hasn’t been outstanding in recent years, it has nevertheless chugged along at around 2.5-3%. Energy use has also increased, albeit at a lower rate of some 1% per annum. This is at the lower end of the expected range of energy vs. GDP, but it is probably too early to say that this represents a longer term shift in this relationship. However, this could be the case if efficiency improvements can outpace economic development or at least come close.

GDP Growth and Energy Growth

Renewable energy is growing rapidly, although this is mainly in the area of electricity generation. From 2014 to 2015 solar and wind generation increased globally by about 200 TWh, which was nearly equal to the overall growth in electricity generation for that year. As an aside, BP reported that the overall electricity growth rate in 2015 was down on 2014 (2.4%) and remained well below the 10-year trend (2.8%). This is slightly concerning as electrification of the energy system is a key requirement for long term emissions reduction. Electricity generation needs to be accelerating compared to overall energy demand growth.

Although the 2016 data isn’t available yet, BP reported that coal use declined globally in 2015 vs. 2014 by 1.8% and natural gas use increased. While most of this could be attributed to the USA and Canada, China also saw a notable coal decline along with growth in natural gas use. The global coal use reduction is equivalent to nearly 300 million tonnes CO2, or about 0.8% of global emissions. Any replacement with natural gas would result in about half the emissions. This is very noticeable in the USA where coal use fell in 2015 by 13%, natural gas use grew by 3% (but against a larger absolute use), oil demand increased by 3%, but emissions declined by 2.6%.

Coal use is declining for a number of reasons;

  • The surge in natural gas production in the USA in particular, triggering the closure of older coal fired power stations that cannot meet new environmental regulations.
  • Air quality concerns in China, leading to a shutdown of coal fired industry and power generation around the major cities.
  • Some mothballing or closure of overcapacity in metallurgical industries in China.
  • The impact of a modest carbon price in a number of jurisdictions and some government imposed moratoriums on new coal generation construction (e.g. Canada).

However, coal use continues to increase sharply in a number of developing countries such as Vietnam, the Philippines, Malaysia, India, Colombia and Indonesia. Current expectations are that this will continue.

Oil use continues to increase, with BP reporting a global rise from 2014 to 2015 of 2%.

The final story is therefore one of several parts and it would appear that this trend has continued into 2016 although further data will be required for verification;

  • Global growth is modest, but energy use increases are trending at the lower part of the expected rise for this level of economic growth.
  • Coal use is declining, with natural gas filling much of the gap but at lower emissions.
  • Renewables are growing quickly, covering most of the increase in electricity generation, but not quite all.
  • Oil demand continues to increase, with its growing emissions being offset by the reduction in coal use.

The end result is that flattening in global emissions that has been seen for three years now.

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As PACE Financing Grows Up, the Industry Grapples With Lending Standards and Consumer Protections

By many measures, the financing programs referred to as PACE — or property-assessed clean energy — are among the most successful energy-efficiency financing tools in U.S. history.

The programs, which fund building efficiency upgrades and rooftop solar panels through loans paid off in tandem with property taxes, are closing in on $4 billion in transactions across 140,000 American homes, and have created 35,000 jobs.

But if you’ve read any number of headlines on the model in recent months, or if you count yourself among the seemingly small group of homeowners who have had a negative experience with this type of financing, you may be more circumspect about PACE’s prospects.

Critics contend that residential PACE programs have used questionable lending practices akin to those that led to the subprime crisis — and lack both consumer protections and accountability in terms of energy savings achieved.

The major companies that issue the PACE financing and work with local governments to implement the programs are listening to the criticisms, even if they don’t always agree with them.

This year, the industry is heavily focused on improving regulations and implementing more rules around how PACE should operate to protect consumers and potentially achieve energy-reduction goals.

In the process, the industry is working closely with legislators. California Senator Nancy Skinner has developed a new bill to add more consumer protections for residential PACE programs in the state, GTM has learned.

By collaborating on regulations, the industry is seeking to bolster its reputation. The sector has seen explosive growth in the last few years, and, in some cases, has operated under little oversight in its early days.

“The industry has come a long way. There are a lot of incentives for investors and providers to push for standards,” said Brian Grow, managing director of the credit agency Morningstar, who co-authored a report on misconceptions of PACE.

PACE programs for residential homes are currently only available in California and two other states, but they are expected to emerge in other states in the coming years. PACE programs for commercial buildings are operating in dozens of states, and while smaller in volume, they have fomented relatively little controversy.

PACE “is entering the big leagues and bringing the benefits and requirements that come with that,” said Cisco DeVries, the CEO of PACE provider Renew Financial. He was the creator of the original PACE concept a decade ago while he serving as the chief of staff to the mayor of Berkeley, Calif.

DeVries estimates that Renew Financial will execute nearly $1 billion in transactions this year, with more than half of that coming from PACE financing.

If providers can ease fears and make the financing products valuable to more consumers and businesses, PACE could end up emerging as both a big market and an important environmental tool. Ultimately, the financing products could help lower the energy use of buildings across the U.S., decreasing carbon emissions and helping states meet environmental goals.

A new era?

The PACE industry is already able to boast of some solid data showing that the model is a relatively low risk way to help homeowners make energy upgrades.

Renovate America, the largest PACE provider, says it has a customer default rate of less than 1 percent. DeVries said, “There have been zero foreclosures due to PACE.” Morningstar’s report found that PACE financing does “not materially increase the risk to the underlying mortgage.”

Yet some problems have emerged across the hundreds of thousands of projects that have been completed.

There were reports of an elderly homeowner who couldn’t afford to pay back a PACE loan and feared losing her home. Industry watchers say that in the early days of PACE, there have been cases stemming from minimal oversight of contractors and weak protections for consumers.

But the industry points to a series of new rules in recent months that have started to set standards and best practices to try to maintain adequate consumer protections.

Last November, the Department of Energy issued a set of best practices for residential PACE programs that included a number of suggestions such as: enhancing the criteria for eligibility in programs by adding reviews of income and existing debt obligations; requiring more transparent disclosures of all PACE financing terms; increasing contractor management and enforcement; and enabling consumers access to dispute resolutions if something goes wrong.

Nonprofit industry group PACENation analyzed the DOE guidelines and in February released an updated set of policies for the industry partly modeled on the federal “Know-Before-You-Owe” disclosures for home mortgages. The PACENation guidelines ask issuers to discuss financing terms over recorded phone calls and request that programs set standards to better govern contractors.

Suggestions, guidelines and best practices can lack teeth if the industry isn’t forced to follow them, however. Charles Harak, a senior energy attorney with the National Consumer Law Center, said that while the new DOE guidelines are an improvement, the industry needs more enforceable protections in place.

One new law, which California Governor Jerry Brown signed last September and was enacted on the first of January 2017, is AB 2693. It gives the property owner the right to cancel a financing contract within three days and adds disclosures noting that some lenders may require a homeowner to pay off the total amount of the PACE loan before refinancing or selling a home. That latter piece has become a contested issue for some homeowners as they try to sell their homes years after signing a PACE deal.

A new bill, SB 242, has been drafted by California Senator Nancy Skinner. It adds even more consumer protections and some nods to energy accountability. SB 242, which will likely be heard by first committee in the coming weeks, adds requirements to help determine if a homeowner has the ability to pay off the PACE assessment, sets standards for the type of projects that can be funded by PACE, and requires contractors to be licensed with the California State Licensing Board.

In addition, the bill mandates that PACE issuers need to report energy savings and environmental benefits (at least annually) and makes sure that program administrators don’t take kickbacks from contractors.

Senator Skinner — whose hometown of Berkeley was the birthplace of PACE — told GTM in an interview that the new bill is meant to ensure appropriate consumer protections as PACE grows. “[California was] the start of the PACE program, and we want to continue to be the national leader,” said Skinner.

Meanwhile, PACE issuers have been developing new corporate programs that they say will manage contractors better, add transparency for consumers, and use technology to track and ensure the energy savings of projects.

Renovate America has developed a new contractor rating and management system that screens and rates contractors, barring those who underperform. The new contractor system “helps find who the good actors are and who aren’t providing good experiences,” said Renovate America CEO JP McNeill.

Renovate America, which is backed by venture capital and private equity investors, appears to have the most reputational cleanup to do. The company was hit with lawsuits last year from three homeowners accusing it of charging excessive and deceptive fees.

The suits were more recently consolidated into a single case, which is seeking class-action status. Renovate America and co-defendant Western Riverside Council of Governments (the local government that administered the accused PACE program) have filed a motion to dismiss the suit. Renovate America says it finds “no merit” in the allegations of the complaints and says it intends to “defend PACE, our company and the program vigorously.”

Renovate America’s other bugaboo was a Wall Street Journal article from earlier this month reporting that the company had paid off some of the PACE debts of struggling borrowers and subsequently hid those moves from investors who buy bonds backed by the company’s loans.

Renovate America confirmed to GTM that it assisted 83 homeowners out of 90,000 customers on payments, for a total dollar figure of less than $175,000 out of $2.2 billion.

The company also said it discontinued the practice in 2016 after it implemented new disclosures, confirmations of term calls, and other measures intended to close the “understanding gap.”

“I don’t think Renovate America is trying to hurt anyone,” says NCLC attorney Harak, adding the industry doesn’t have a long history with consumer protection programs.

“We want to see PACE become a broader, better, safer product in 2017,” said Renovate America’s McNeill. “None of this will occur overnight, but we’ve made great progress."

Energy accountability

Adding in new consumer protections for homeowners is pretty straightforward. There are a lot of examples to follow from other industries and government programs.

But finding the best practices to ensure that PACE-funded energy and water upgrades are actually delivering savings is trickier. Solar panel systems can do this pretty easily, but what about new insulation or windows?

Utilities might be able to provide some help. Last year Renew Financial created a pilot program in which a group of its customers made their real-time energy data available from smart meters.

Combining that data with other modeling and financing information, the company was able to develop a clearer picture of how much energy was being saved and during what times of day. The company is now working with PG&E and other utilities to grow the program and add more energy transparency.

Last year, Renovate America acquired energy software startup CakeSystems to help it better model home energy use and estimate the savings of its customers. McNeill said that the company is incorporating the technology into its products this year.

Tracking energy savings is “the hardest thing to do” for the PACE providers, as there are a variety of models to rely on and factors to consider, said PACENation Executive Director David Gabrielson.

Morningstar’s Brian Grow agreed: “We’ve had trouble finding data on energy savings. We talked to the issuers about it, and they said they are starting…to track it” internally.

It’s still early days when it comes to energy accountability for PACE.

In fact, the entire financing product is still fairly nascent.

“There might be 140,000 homes and $3.5 billion of financing through PACE, but there are 40 million people who live in California,” said PACENation’s Gabrielson.

That immaturity has likely contributed to some of the worries about the inherent risks of the product. “There’s some fear because this is new and different,” said Renew Financial’s DeVries.

DeVries, the godfather of the industry, takes doing the right thing for PACE very seriously.

“We need to learn from issues that come up, address people’s fears and concerns, and go above and beyond other financing projects. Those of us involved with PACE need to execute at a very high standard," said DeVries.

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Is Elon Musk’s Model 3 Production Plan Too Ambitious?

Elon Musk, Silicon Valley’s automotive visionary, loves to wow the world with grandiose visions that serve primarily to reinforce his position at the top of the list of tech titans. That said, at some point we suspect his shareholders will actually expect him to work towards his ‘visions’ rather than simply talk about them.

And while one can never be sure just how many chances investors in this frothy market will allow Musk before turning on him and his aggressively priced stock, it appears as though he isn’t doing himself any favors with his recent Model 3 production guidance. As Bloomberg pointed out this morning, Musk is guiding the market to production volumes of 10,000 Model 3’s per week by 2018, or roughly 5x his current volumes for the Model S and Model X, combined.

First, Musk said the company is placing orders with suppliers for “1,000 cars a week in July, 2,000 a week in August, and 4,000 a week in September.” Tesla then plans to increase production to 5,000 cars a week by the end of the year, and 10,000 a week by the end of 2018. For context, the company is currently able to make about 2,000 Model S and Model X cars a week.

(Click to enlarge)

And while it’s certainly reasonable to assume that a lower-priced Tesla will have more of a mass market appeal than previous, more expensive models, it just might be a stretch to assume the new car will out sell the BMW 3 Series and Mercedes C Class, combined, in its first year of production.

For Musk to hit all of his targets, Tesla would need to build about 430,000 Model 3s by the end of next year. That’s more than all of the all-electric cars sold planet-wide last year. The rollout will begin in California and move east, focusing on U.S. reservation holders. Even if half of the Model 3 inventory is shipped to other countries, U.S. sales under Musk’s targets would outpace the BMW 3 Series and the Mercedes C class—combined.

Another forecast Musk reiterated is that Tesla thinks it can build 500,000 total cars next year while Model S and Model X growth would continue, but at a slowing rate. The chart below, as far as we can figure, is the ramp that Tesla is forecasting.

(Click to enlarge)

To sell that many $35,000 sedans in the U.S. “would be absolutely unprecedented based on what we know about car markets today and how people spend their dollars,” said Salim Morsy, electric car analyst at Bloomberg New Energy Finance. “It could happen. I’m pretty sure it won’t.” Related: OPEC Compliance Nears 100% On Libyan, Nigerian Outages

Virtually every Wall Street analyst agrees. Even the most bullish among them don’t think Tesla can sell half a million electric cars next year, and Musk has a long history of never setting a deadline that he’s likely to keep.

Meanwhile, as we pointed out earlier this month (see “Tesla Admits It Still Hasn’t Completed A Model 3 Beta Prototype“), Car and Driver found an interesting “risk factor” in Tesla’s 10-K which basically cautioned that, despite aggressive production guidance slated to begin just 6 months from now, the company hasn’t even developed a Model 3 “beta prototype”….

Car and Driver’s Anton Wahlman – who appears to be one of the few who actually read Tesla’s 10-K filing – may have found the reason for the doubts…

From the filing:

We expect that the next performance milestone to be achieved will be the successful completion of the Model 3 Beta Prototype, which would be achieved upon the determination by our Board of Directors that an eligible prototype has been completed. Candidates for such prototype are among the vehicles that we are currently building as part of our ongoing testing of our Model 3 vehicle design and manufacturing processes.”

In other words, Wahlman points out, Tesla has not “completed” a Model 3 “beta prototype” as of, well, either of these two dates: December 31, 2016 (the period that the SEC filing covers), or March 1, 2017 (the date on which the document was filed). Pick your poison.

…but it’s totally fine because, as Bloomberg notes, Musk has plans to simply ‘revolutionize’ the automotive production process by simply skipping the beta testing phase.

Tesla is redefining how cars are developed, built, sold, and updated. Some of the tricks Musk plans to speed up the launch can only be done once. Others may transform the automotive industry much like Telsa’s over-the-air software updates. Here’s what we know:

Tesla is skipping “beta”—sort of. On Friday, Musk fired off a barrage of 50 messages on Twitter while on a flight to Cape Canaveral, Florida. Among them was a six second clip, the first glimpse of what he calls a “release candidate” Model 3. The term is more typically used in the software industry, referring to a final version that’s almost ready for public release.

Musk is condensing the typical timeline for a car release. A traditional auto manufacturer spends about six months testing a beta cars prior to a rollout. Musk seems to have skipped a step, and is building test vehicles using the same equipment line that will feed mass production. If that’s the case—and this truly is a “release candidate”—then it implies that production is on track. The car looks very much like the vehicles Musk showed a year ago, and that fidelity to the original prototype will have helped keep engineers on schedule.

Of course, if beta testing phases are so irrelevant, one has to wonder why the major OEMs spend 1-2 years, and millions of dollars, testing their vehicles before mass release…we’re sure it’s all just bureaucratic waste…

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Climate Change Policies Working: CO2 Emissions Flat For 2 Years In A Row

The International Energy Agency gave environmentalists cause for celebration earlier this month when it reported that carbon dioxide emissions in 2016 remained unchanged from the levels reached in 2014 and 2015. Analysts are hopeful that this could represent the end of the upward trend that CO2 emissions have seen since 1980.

Emissions stalled despite continuing growth in the global economy, thanks to greater use of renewable energy, productive efforts in the direction of better energy efficiency, and replacing coal with natural gas for power generation.

At 32.1 gigatons, CO2 emissions in 2016 stayed unchanged in Europe and increased in most of the emerging economies, bar China, which, along with the U.S., was the only country where the emissions actually fell. In the U.S., the decline brought emissions to their lowest level since 1992, with the IEA noting that between 1992 and 2016, the country’s economy grew by 80 percent.

So far so good – renewable energy accounted for the bulk of the increase in energy generation last year, economies transformed to accommodate better energy efficiency initiatives, and natural gas continued squeezing out coal.

However, IEA’s chief Fatih Birol advised wary optimism, saying this was just the beginning of a trend, and a lot more work would need to be done in the years ahead to start cutting CO2 emissions.

Indeed, in a more recent news release, the IEA said that the world needs “an energy transition of exceptional scope, depth and speed” in order to meet the Paris Agreement target of limiting temperature rises to below 2°C. This transition, the IEA said, involves capping any further rises in CO2 emissions before 2020 and cutting them by as much as 70 percent by 2050. Related: The Wealthiest Oil & Gas Billionaires In The U.S.

Among the targets that the world has to meet to enable this transformation, the IEA lists the following: 7 out of 10 new cars need to be electric (versus 1 in 100 currently); the entire building stock of the world will need to be retrofitted for greater energy efficiency; $3.5 trillion will need to be invested in the energy industry every year until 2050 – that’s twice the current level of investments.

These targets certainly seem challenging. The global economy will continue to grow, and it’s anyone’s guess whether this growth will be matched by the growth in renewable energy use and energy efficiency advancements. The fact that emissions in Europe stayed the same instead of dropping, given the continent’s commitment to green energy, already casts a shadow on the sunny mood brought about by IEA’s CO2 report.

And then there’s some more bad news. It’s not just CO2 emissions that need to be curbed in a bid to limit climate change – methane is about 30 times more potent as a heat-trapping gas, and there was a piece of not so good news recently regarding methane. Related: Saudi Aramco IPO Under Pressure, As 9/11 Lawsuits And Oil Prices Hit

A peer-reviewed study published in the Environmental Science and Technology found that methane emissions from natural gas-fueled power plants and oil refineries may be substantially higher than previously believed, thanks to leaks. In fact, the authors have estimated that hourly methane emissions from gas-fired plants could be between 21 and 120 times higher than currently reported by plant operators in the U.S. Together, the emissions of gas-fired plants and refineries could be 20 times higher than reported.

The results of this study are not conclusive, and research will continue, but they do raise the question of how reliable the emissions data is that numerous reports and forecasts are based on, driving legislation and initiatives aimed at curbing the harmful effects that certain chemicals have on the atmosphere. This is just one more question to add to a growing list: How will governments and carmakers incentivize people to buy electric cars (and how much will the recharging infrastructure cost)? Where will the additional $1.75 trillion for energy sector investment come from? How will the whole global building stock be retrofitted, and how much it will cost? We need to find some plausible answers to these questions, urgently, if the IEA is to be proven right.

By Irina Slav for Oilprice.com

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Where have drilling costs dropped the most? Midland Basin, of course

Core acreage breakeven costs in West Texas' Midland Basin, courtesy of Rystad Energy

The costs of producing oil in the major U.S. shale fields have dropped by almost half over the past two years, but none as much as West Texas’ Midland Basin, a part of the prodigious Permian.

Drillers in the Midland, the eastern section of the Permian Basin, used to produce oil for about $71 a barrel, according to a new report by the Norwegian energy research firm Rystad Energy. Last year, that cost dropped by half, to $36 a barrel.

More than half of that savings — 57 percent — comes from lower drilling prices, as operators have squeezed oil field service companies during the two-year-old oil-price crash, Rystad said. Efficiency improvements have cut another one-quarter of the costs.

And the last one-fifth come from a practice known as “high-grading,” when oil companies move drilling operations to their best land.

RELATED: Texas drilling, oil field hiring accelerates in first quarter

Essentially, as oil prices crashed in 2014, companies stopped drilling. When they restarted, they picked spots with the most oil, where they knew they’d get their best returns — what they call “core” acreage.

In 2014, according to Rystad, companies drilled in core acreage about 60 percent of the time.

Last year? 80 percent.

Moreover, as companies moved into core acreage, wellhead breakeven prices dropped.

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The Lowdown on Hydrogen, Part 1: Transportation

After more than two decades of hype about the imminent arrival of a transformative “hydrogen economy”, many veteran technology watchers — myself included — had concluded that hype was pretty much all it was. Hydrogen fuel cell vehicles, in particular, looked like a failed dream. Bright innovators like Canada’s Geoff Ballard had attacked the problem and burned through serious investment money trying to develop a product that could stand up to the rigors of the automotive market. All with little success. And beyond the cost and durability issues of fuel cells themselves, the hydrogen storage issue stubbornly resisted commercially practical solutions.

In recent years, hybrids and battery electric vehicles have appeared to hold the inside track for low carbon and zero carbon transportation. Tesla has reshaped perceptions of what is possible for battery electric vehicles. The cost of lithium-ion battery packs has been driven down, while capacity, performance, and reliability have increased dramatically. To be sure, government programs have continued to fund fuel cell R&D. If nothing else, fuel cells still hold broad appeal for military programs. But to those of us who felt we understood the issues, the barriers to broad use of hydrogen as an energy carrier looked pretty fundamental. We — or at least I — didn’t really expect to see them fall anytime soon.

In the face of that expectation, a spate of announcements and news articles over the past year relating to hydrogen have come as a shock. Most prominent have been recent announcements by Toyota, Honda, and Hyundai of new FC vehicles for production release in markets where hydrogen refueling stations are available. Toyota announced the Mirai, Honda announced the Clarity Fuel Cell, and Hyundai announced the Tucson Fuel Cell SUV. But those were just the commercial announcements backed by ad campaigns. When one starts digging, scores of significant news stories and announcements from around the world turn up. The whole idea of the hydrogen economy — which never quite went away — seems to be resurgent.

So what is it that happened while I wasn’t paying attention? A thorough review seems in order. Since battery vs. fuel cell EVs are at the eye of the storm, I’ll start there. Then, time permitting, I’ll go on to look at some of the broader issues of energy storage and hydrogen production.

The EV technology race

Despite disappointing progress in the early years of the Bush “Freedom Car” initiative, fuel cell R&D never dried up. It has been ongoing, and not all of it has been politically driven. There has always been genuine promise in FC technology. The problems have been cost and durability. As far as I can tell, there have been no singular technology breakthroughs behind the resurgence of interest in hydrogen. But persistence and general advances in materials and manufacturing have begun to pay off. A small example: automated machinery able to make reliable gas-tight welds between thin sheets of metal. That turns out to be crucial for fabrication of efficient bipolar plates in PEM fuel cells.

Analysis by DOE’s Fuel Cell Technologies Office puts present cost of automotive FC stacks at $53 per kW for manufacturing volumes of half a million units annually. That’s half of what was projected for the state of the art in 2006.

Ironically, one thing widely seen as needing to change before FCEVs could become practical has stubbornly not changed: technology for carrying hydrogen on-board the vehicle. Despite a plethora of promising lab developments, there seems to have been no practical breakthrough in hydrogen storage. The new FC vehicles all use high pressure gaseous hydrogen stored in polymer-lined, fiber-wound pressure tanks. Similar tanks were made by Quantum in the 1980s. The tanks remain heavy, bulky, and costly. However, with better manufacturing methods and stronger, cheaper carbon fibers, their cost now measures in the low thousands of dollars rather than the high tens of thousands.

FC Advantages: weight, capital cost, refueling time

From Toyota’s product sheet for the Mirai, the fuel cell system delivers 2.0 kW/kg with a power output of 114 kW max. That implies a FC system weight of 57 kg. The hydrogen tanks hold 5 kg H₂ at a weight percentage of 5.7%. That implies a tank weight of 83 kg. So, 145 kg total for tanks + FC system + 5 kg hydrogen, delivering an EPA estimated range of 312 miles. That compares to 540 kg for the battery pack in a Tesla Model S with a rated range of 265 miles.

It appears that despite the heavy and bulky pressure tanks, the Mirai delivers a greater driving range than the Model S, with roughly a 4:1 weight advantage for the energy delivery system. More important for most buyers, however, will be the system cost per kWh to the drive motors. That’s harder to nail down, because manufacturers don’t normally release cost data publically.

There’s a small cottage industry devoted to guessing and predicting the cost of Tesla’s battery packs. GTM Research projects that by 2020, Tesla’s average cost for packs will be $217 / kWh. Using that figure, the 85 kWh Model S battery pack would come to $18,500. That’s less than some estimates, but more than the $12,000 that Tesla itself is willing to guarantee to Model S owners as the replacement cost after 8 years. Everyone agrees that costs are on the way down as production from new battery “gigafactories” kicks in, so $18,500 is probably a reasonable figure to use for near term comparisons between battery and fuel cell vehicles.

On that basis, fuel cells appear to come out ahead of batteries on cost as well as weight. At $53 per kW, the Mirai’s 114 kW fuel cell system would cost just over $6000. The high pressure storage for 5 kg H₂ is probably around $3000. So the capital cost of the Mirai’s energy delivery system with longer range looks to be roughly half that of the battery pack for the Model S.

Of course, FC vehicles are also much faster to refuel. That’s widely considered their strongest market advantage. But it presumes a network of public hydrogen refueling stations that for the most part does not yet exist.

Normally a “chicken and egg” problem like that would be lethal for a new product introduction. It may prove to be so in this case as well. However, there are some special factors for hydrogen that could potentially enable it to break through. We’ll get to those. First, though, we should look at other issues on the flip side of fuel cells relative to batteries.

FC disadvantages: efficiency, carbon emissions, fuel cost

There are many ways to produce hydrogen. For electrification of transport, the green vision is that it would be by electrolysis of water. That vision is promoted for hydrogen fueling stations. The H₂ to be dispensed each day would be produced on-site the same day or the day before by electrolysis. That reduces on-site H₂ inventory, enhancing safety, and minimizes the capital cost of the station. It also avoids the need for new and costly infrastructure to distribute hydrogen. No need to either dig up the streets to lay hydrogen pipelines, or have liquid hydrogen tanker trucks mixing with city traffic.

In that scenario, the relatively low efficiencies of PEM fuel cells and electrolyzers put fuel cells at a distinct disadvantage relative to batteries. For each kilowatt-hour delivered to the drive motors of the vehicle, the electrolyzer / fuel cell system requires roughly twice the kilowatt-hours of energy input as the battery system.

The rough 2:1 difference in electrical load that FCEVs impose is bad enough, but it also carries over to the indirect carbon emissions of the two classes of vehicles. In terms of what they emit on the road, both BEVs and FCEVs are zero emission vehicles. Both, however, inherit indirect emissions via the power grid. If the grid were supplied entirely from carbon-free power sources, then both BEVs and FCEVs would be carbon-free as well. But that’s far from the case today. A 2:1 difference between FCEVs and BEVs electrical load means that an FCEV will have double the indirect carbon emissions per mile of a BEV.

The actual difference in fuel cost per mile will be quite a bit greater than the 2:1 difference in electrical load suggests. For BEVs, the fuel cost is just the cost of the electricity consumed in charging. There is no capital equipment of any significance between the vehicle and the power grid. For FCEVs, however, there’s the electrolyzer, hydrogen storage, dispensing system, and the commercial property hosting the station. There is also the daily operational overhead of running the station. Those elements raise the retail cost of hydrogen dispensed well beyond the cost of electricity to the electrolyzer.

Solid estimates of what can be expected in the near future are hard to come by. A jumble of subsidies confuse the picture, and estimates for future costs are sensitive to assumptions about rates of adoption, size of refueling stations, and the technology used for supplying H₂. DOE’s aspirational goals for 2020 are a wholesale production cost of $2.00 or less / gge (gallon of gas equivalent; ~1 kg of H₂). The goal for price at the pump, exclusive of taxes, is $4.00 or less (ref. here).

The bottom line is that fuel costs for an FCEV will be at least 5 to 10 times more than for a BEV for some years to come. I doubt that zero-carbon electrolytic hydrogen will ever be less than 4x as expensive. However for context, the fuel costs for a BEV are a fraction of those for a gasoline vehicle and are usually considered negligible. If the cost of hydrogen in an FCEV were 4 times higher than the per mile cost of electricity in a BEV, most drivers would find it acceptable. Fuel would still be a small part of the overall cost of owning and driving a vehicle. Witness to that is the fact that manufacturers of FC vehicles can afford to bundle free hydrogen into the purchase price or lease terms for the vehicles in their California test markets.

Situation in flux

The relative advantages and disadvantages cited above for FCEVs vs. BEVs are mostly soft. They’re subject to changes in technology, design approach, and use patterns. For example, developments in battery technology and manufacturing will almost certainly trim the upfront cost and weight disadvantages of BEVs. At the same time, changes in hydrogen production methods could reduce the per-mile cost disadvantages of FCEVs. There’s also an easy FCEV design change that would substantially reduce their cost of driving and mitigate the H₂ infrastructure challenge. (See below.)

Perhaps most significantly, the arrival and spread of autonomous vehicle capabilities will transform the automotive market in ways that significantly affect the tradeoffs between hydrogen and batteries. I’ll talk about that later.

Universal hybrids?

Controversy over batteries vs. fuel cell aside, there’s consensus on one aspect of future vehicle technology. Electrical motor-generators and solid state power controllers will increasingly be at the heart of drive systems. They make for cheaper, more reliable, and higher performance than mechanical transmissions and engine-coupled drive shafts. Ultimately, all future vehicles will be either pure BEVs or hybrids.

It’s not touted, but the new FC vehicles are, in fact, already hybrids. Toyota’s Mirai is built atop the Prius’ drive system. The two share many components, including traction battery and power controller. That enables regenerative braking and instant throttle response. It also buffers the FC system and reduces its cost. Commonality of components with Prius and a more benign FC environment are key parts of how Toyota limited its costs in fielding a new FC vehicle class.

All it would take to produce a plug-in hybrid version of the Mirai would be addition of a plug-in charging port. The same is likely true of Honda and Hyundai FC offerings as well. But batteries and fuel cells are competing for mindshare in the EV marketplace; it’s understandable that companies backing an FC play don’t want to expose the HEV roots of their flagship FC vehicles. It wouldn’t make marketing sense. A charging port does make technical sense, however. Local miles could be driven mostly in battery electric mode. The cost per mile would be low. Hydrogen consumption for a typical driving profile could be cut by half or more. In Europe, Symbio FCell has in fact taken that approach for a range-extended Nissan e-NV200 van for the taxi market.

A plug-in hybrid capability mitigates the hydrogen infrastructure issue for FC vehicles. They remain drivable even in areas without hydrogen refueling stations. The limited plug-in battery range might be a pain, and drivers would still want to have hydrogen refueling available near their home base. But they wouldn’t be tightly tethered to that base. The plug-in capability would provide flexibility, drawing from on-board hydrogen to extend range between plug-in chargings, or drawing on plug-in charging to extend range between hydrogen fill-ups.

The switch to electric drive changes the tradeoffs between batteries and fuel cells. It’s no longer a stark either-or choice. If electric drive and at least a modicum of battery capacity are givens, then the issues become how much battery capacity to have and what technology to employ for delivering extended range beyond what the hybrid drive battery supports. If the latter is enough to let local miles be driven mostly in battery electric mode, then the optimal solution for extended range is one that minimizes added vehicle cost. That holds even at the expense of higher fuel costs for times when the extended range capability is tapped.

Alternative fuels

It’s possible that neither large batteries nor hydrogen fuel cells are optimum choices for range. With large batteries, capacity above and beyond the needs of local driving may be a costly way to achieve an infrequently tapped range capability. And while future batteries will be lighter and cheaper, that also makes it attractive to offer more capacity for local driving. Increased capacity in the basic battery pack reduces the frequency of resort to the extended range capacity. The conceptual simplicity of having a single large battery may not be worth the cost. Separate subsystems could deliver greater range at lower vehicle cost, while enabling fast fueling as a bonus.

The separate subsystem for extended range might or might not be hydrogen. The added vehicle cost of the hydrogen approach looks like it would be about $9,000; that’s not small, but it’s not all that far above the cost of an IC engine and the various subsystems around it. The question is, what would it be buying?

With a fully decarbonized electricity grid and electrolytic hydrogen, the HFC approach would be buying carbon-free transportation. Yet if addition of easy and ubiquitous plug-in capability with larger hybrid drive batteries has already enabled most local miles to be driven in battery electric mode, then carbon emissions have already been slashed. If average fuel consumption for new plug-in vehicles is already 150 mpg or better, then the incentive to use hydrogen will be weak.

Barring a major breakthrough in hydrogen storage technology and further reductions in fuel cell cost, the default competitor to both batteries and fuel cells for extended range driving will likely be gasoline or compressed natural gas. Perhaps, if the price of fossil carbon emissions gets high enough, a carbon-neutral synthetic fuel might prove cheaper and more competitive. The energy cost of producing synthetic fuels from CO₂ and H₂ isn’t much greater than that of H₂.

Heavy Transport

The discussion so far has been about passenger cars. For a broader view of the hydrogen economy, we need to consider heavy transport as well: trucks, buses, trains, ships, and airplanes. Not to mention farm and heavy construction machinery. For the sake of brevity, I won’t cover any of the latter here. But trucks and buses play big roles and warrant comment.

For trucks and buses, the factors favoring hybrid electric drive systems are at least as strong as they are for passenger vehicles. The ability to deliver smoothly controlled torque for acceleration and uphill driving across the full speed range, with attendant capacity for regenerative braking, are attractive. Electric drive can deliver performance and safety advantages, along with fuel economy, clean air, and quiet operation. Low production volume for the heavy duty batteries, power control units, and motor-generators have hampered widespread adoption so far, but things are changing.

For energy supply to the electric drive system, there are different tradeoffs and different options that may be favored, depending on the application sector. All-battery approaches are attractive for metropolitan buses and utility trucks. Metro buses spend hours parked each day, either in their barns at low service times or at route ends while drivers change or take rest breaks before starting their next scheduled runs. It should be relatively easy to provide fast recharging at those points. The on-board batteries should never have to deliver more than about 25 miles in regular service.

For long-haul trucking and inter-city buses, all-battery approaches are currently impractical — and likely to remain so. Hydrogen has potential opportunities there. The recent unveiling of the prototype for the Nikola One electric semi (pictured below) has, in fact, caused quite a stir.

Credit: Nikola Motors

The truck is a hydrogen FC model, and its specs are quite impressive. 1000 horsepower (twice that of a diesel semi), 2000 ft. lbs torque, range of 1,200 miles, … If Nikola Motors can deliver on its promises, it will have a winner. Production deliveries aren’t scheduled to start until 2020, but truckers have already been plunking down $1500 deposits for reservations.

The high cost of electrolytic hydrogen will still make the per-mile fuel cost for a Nikola One relatively high — assuming that Nikola Motors is even able to deliver on ambitious plans to build solar farms for supplying its trucks with zero-carbon hydrogen fuel. The financial case for the vehicles would probably be stronger if they ran on compressed natural gas rather than H₂. They would still be hybrids — the Nikola One is planned to carry a 315 kWh battery that will give it the power to maintain 65 mph up a 6% highway grade and soak up the energy of descent from a mountain pass without touching the brakes — but it would lose its cachet as a hydrogen fuel cell vehicle.

It could retain some of that cachet if the Nicola One used high temperature SOFC fuel cells that run directly on methane. That’s an approach recently demo’d by an alliance between Ascend Energy and Atrex Energy. High temperature SOFCs are at least as efficient as PEMFCs, and if their high temperature waste heat is used to power a Brayton cycle turbine, they are a lot more efficient. The combination would certainly make for a low-carbon vehicle. To be zero-carbon, however, the methane burned would need to be from a carbon-neutral source.

Further topics

I haven’t yet covered the likely impact from autonomous vehicle developments, nor have I talked about different technologies for hydrogen production, or the use of hydrogen for energy storage and backing of intermittent renewables. Those are important topics, but I’ll leave discussion of them for part 2, next week.

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Too Much of a Good Thing? An Illustrated Guide to Solar Curtailment on California’s Grid

The end of California’s drought is exposing the full effect of the state’s move to renewable energy. 

A wet winter has loaded up the hydroelectric system, while solar generation rose by 33 percent in the past year. These increases, combined with the usual spring winds, are pushing gas off the grid, cutting imports, and reducing carbon emissions at an unprecedented level.

As California’s independent system operator said: “The growth in these preferred resources is nothing short of phenomenal.”

But that "phenomenal" growth is also setting new records for negative prices and curtailment of renewables, primarily utility-scale solar plants. CAISO predicts 6,000 megawatts to 8,000 megawatts of curtailment this year. 

“It’s an interesting growing pain of our increasingly green grid,” said Shannon Eddy of the Large-Scale Solar Association. “We’re curtailing the cleanest and newest resource on the grid, and leaving alone the 2,000+ megawatts of mostly fossil imports and in-state gas.”

And the growing pains will likely continue. The latest U.S. Solar Market Insight report from GTM and SEIA counts solar projects in the works that will double California’s capacity from 17 gigawatts in 2016 to 34.5 gigawatts by 2022. With springtime power demand peaking at well under 30 gigawatts, we may see a very solar future.

Or a train wreck.

One fine day

Spring shoulder months are especially concerning. With demand low due to cool temperatures, supply is already high from copious wind, water and sun. As summer temperatures rise, air conditioning demand will soak up the solar power.

March 26, a balmy spring Sunday in the Golden State, was an especially vivid example of the growth of renewables and their impact on the market. CAISO got 33 percent of its power from RPS-eligible renewables, plus 15 percent from big hydro, plus another 10 percent from nuclear — making it fully two-thirds carbon-free. As shown in the first interactive figure below, thermal (namely gas) and imports were shoved out of the way by a huge burst of solar power, but came back to cover the evening ramp and peak.

(The figure also estimates output from customer-owned solar, though no one actually tracks it. See the article “California Has More Solar Than You Think” for more information.)


Unfortunately, March 26 also saw lots of curtailment of utility-scale solar plants — about 6,500 megawatt-hours or 8.5 percent of their output for the day. Two-thirds of the cuts were to mitigate local congestion, with the rest to reduce system-level impacts.  

This can also result in negative prices. While good for consumers, too much negative pricing can spell trouble for generators of all kinds. Negative pricing has been steadily increasing in recent years, and shifting to midday hours. January and February saw more than twice as many incidents of negative pricing as the year before, and the peak is expected to come in April. April 2016 saw negative prices in 15 percent of all 5-minute intervals tracked in the state. 

Too much of a good thing

Curtailment and negative prices come from a surfeit of generation. Lots of generation relative to supply means low prices, as generators compete to be called on by the ISO market optimization software. Too much generation, or “oversupply” as CAISO calls it, can create reliability problems, and must be curtailed.  

Neither is strictly a problem — they are just signals to market participants to change behavior — but if California’s clean energy and climate goals are to be met, they can create long-term complications.

As GTM’s Jeff St. John recently explained, CAISO follows a set procedure to deal with oversupply. First, market prices drop, pushing some generators out of the market. Prices can even go negative, giving generators a very strong incentive to curtail. CAISO can also accept bids from generators to reduce their output, called a “decremental” bid. And as a last resort, CAISO can order specific generators to turn down, though this is very rare. 

What is curtailment?

Who gets curtailed, in what order, and why? And what does curtailment mean for market participants?

CAISO considers three types of curtailment: Economic dispatch, a self-scheduled cut, and exceptional dispatch. These can all happen at the local level, to reduce congestion, or at the system-wide level, to reduce oversupply. 

As shown in the second interactive figure below, virtually all curtailments in the past three years have been in the first category, where generators respond to CAISO’s call for less generation and get paid to do so. These "decremental" bids can be worth as much as generation, though they can have other revenue implications for renewable generators. 

In economic terms, the decremental bid needs to be more than the opportunity cost of the producer to make it worth their while to turn down. Generators do get paid not to generate, but it is more economically efficient than the alternatives.


Self-scheduled cuts are for generators who have contracts directly with utilities and other power retailers. These generators place a quantity bid with CAISO, but not a price bid, meaning they take whatever the clearing price is for that hour. This tells the market how much volume is being served, but not the price of those generators. 

If the first step, economic curtailment, is not adequate to resolve the problem, the market software will pick some self-scheduled generators to curtail based on location and other operational impacts — but not on price. Still, self-scheduled curtailments are quite rare.

As a last option, CAISO can order a specific generator to reduce output, called “exceptional dispatch.” This is even more rare than self-scheduled cuts, and in fact has been declining even as solar, wind and hydropower output grow. “There is no clear cut reason why, since they are so situational and unique,” said Anne Gonzales of CAISO. She notes that economic and self-scheduled cuts are rising, showing that the market is able to handle the oversupply.  

Why pick on solar?

So why are only wind and solar curtailed? Why not other sources?

This comes down to definitions.

“We try not to use the word ‘curtailment,’” said Phil Pettingill, CAISO’s director of regional integration. “It’s not an operational term.” 

“When we talk about it, we are saying that a renewable resource is operating at a level lower than it could. The state RPS assumes that a solar plant will be able to operate all the time, but now we’re saying we are reducing them to meet reliability needs," said Pettingill.

Put another way in a CAISO report: “Only wind and solar resources can be reported in this manner because these resources have a forecast.” Thus, deviations from the forecast output are considered a curtailment.

“There’s really no perfect way to measure curtailment,” said Mark Bolinger of Berkeley Lab. In Texas, they use “individual wind turbine anemometers in real time to estimate what would have been generated absent curtailment.” 

Other generators whose bids are not low enough to be accepted will also “curtail,” in that they don’t generate power to the market. But that is not what CAISO means by “curtailment.” 

And a certain amount of curtailment may be beneficial from a cost-benefit perspective, as it avoids an overinvestment in grid infrastructure. For example, investing in expensive transmission upgrades in order to prevent a few hours of curtailment a year may not be a prudent use of resources. 

Andrew Mills at Berkeley Lab thinks there is a ‘‘valley of reasonable curtailment.’’ If you try to absorb all renewable generation, infrastructure costs become very steep. If there is too much curtailment, it becomes too costly to build renewable resources. In the middle of the valley is a cost-effective sweet spot.

One man’s cost is another man’s benefit 

But who bears the costs and earns the benefits depends on the details of contracts, which are proprietary. Utilities can have contracts with generators that allow some hours of economic curtailment without compensation, with additional curtailment paid by the utility at the PPA price. These curtailment rights allow the utilities to optimize their portfolio and reduce customer costs.

Solar generators are responsible for almost all economic curtailments to date, rather than wind. This was certainly true on March 26, as shown in the third interactive figure.


According to Pettingill, an increasing number of contracts require that even self-scheduled renewable generators bid both quantity and price into the CAISO market, so they can respond to economic curtailment, rather than be selected by the market software. This makes the process of curtailment more economically efficient.

But other factors go into the curtailment decision. Solar generators earn investment tax credits and resource adequacy payments, which are not based on generation, but they also earn credits for the state RPS obligations, which are.  

As a result, they can afford to make smaller decremental bids that are more likely to get accepted. In 2016, according to the CAISO Market Monitor, solar bids accounted for most of the bids in the $0 to -$25 range.

Wind generators are not curtailing, according to Bud Earley at Covington & Burling LLP, because they “generally receive — in addition to market revenues — production tax credits, renewable energy credits, and contractual energy payments, which amount to about $130/MWh for the average wind resource.”

“Those payments would be forgone if the resource is not dispatched,” he pointed out. If the decremental bid price is too small, wind generators “have no incentive not to generate once they have been accepted in the day-ahead market.”

Another contractual problem is that dispatchable generators may be running more than they should, based on ‘‘use limitations’’ in their contracts that restrict the amount of curtailments, stops, starts and ramps that they are required to perform. So while generators may be technically able to respond, their contract allows them to ignore calls for flexibility.

In a recent memo, Eric Hildebrandt, director of market monitoring at CAISO, recommended that gas generators be dispatched based on “actual unit constraints” as a way to increase flexibility and decrease curtailment of renewables.  He believes it is “inefficient for the ISO to treat contractual limitations as physical limitations in the ISO market optimization.”

For all kinds of generators, CAISO recommends “modify[ing] provisions in power-purchase agreements…that deal with curtailment limits to reconcile with renewable portfolio standards priorities.”

The Market Monitor agrees that changes are needed. “As the volume of renewable energy increases — including within EIM areas — it will be important for the ISO to continue to encourage flexibility and minimize commitment of inflexible resources, including gas-fired units operating at minimum load.”

Like a Zen master, CAISO concludes that “the market often remedies the oversupply situation and automatically works to restore the balance between supply and demand. In almost all cases, oversupply is a manageable condition, but it is not a sustainable condition over time.”

The CAISO video below illustrates how the system operator is managing oversupply.

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