News Article | April 15, 2016
Wind power not the main driver of negative prices in Texas. Negative prices still rare, mostly caused by other energy sources Celeste Wanner and Walter Reid contributed to this analysis. Some recent press articles have again fallen into confusion over wind’s impact on electricity markets. Recent occurrences of negative prices during a few hours in some markets are actually a different phenomenon from the localized negative price events we discussed two years ago. However, two similarities to those prior events are that the new events are also largely caused by energy sources other than wind, and that both types of occurrences have a minimal impact on markets. As background, renewable resources do tend to reduce electricity prices by displacing more expensive sources of energy, benefiting consumers. The cost and emissions savings of using wind energy to displace fossil fuel generation are precisely why wind energy has become electric utilities’ number one choice for new generating capacity. As we explained previously, wind’s impact on electricity prices is an entirely market-based outcome that also occurs for other low-fuel cost sources of energy, such as nuclear, coal, and hydropower. Negative prices are rare, have minimal impact on average market prices Much of the focus of recent press articles has been on the main electricity market in Texas, known as the Electric Reliability Council of Texas, or ERCOT. A close examination of wholesale electricity price data shows that negative prices accounted for only 0.64% of ERCOT-wide average market prices in 2015. These events have an even smaller impact on demand-weighted average market prices because they tend to occur during hours of lower electricity demand, and because prices go negative by only a dollar or two in almost all cases. As a result, in 2015 negative prices reduced demand-weighted average ERCOT power prices from $26.38/megawatt hour (MWh) to $26.26/MWh, a decrease of only $0.12/MWh, or less than one half of one percent. In contrast, volatility in the price of natural gas has a profound impact on ERCOT market prices. In 2014, prices for the delivery of natural gas to power plants in Texas averaged $4.62/MCF (thousand cubic feet), yet that fell to an average of $2.88/MCF in 2015. Because natural gas power plants set the electricity market price in nearly all hours in ERCOT, average electricity prices fell from $36.41/MWh in 2014 to $26.26/MWh in 2015, a decline of 28%. This impact is nearly 100 times larger than the impact of all negative price events in 2015. As numerous sources previously explained, occurrences of negative prices have a minimal impact on generators compared to the effect of fuel price fluctuations. Other energy sources are a leading cause of negative prices Low natural gas prices also appear to have indirectly caused many of the negative price occurrences in ERCOT in 2015. Low natural gas prices caused many gas power plants to become cheaper to run than coal power plants in 2015, causing coal’s share of the total ERCOT generation mix to plummet from 36 percent in 2014 to 28 percent in 2015, while gas’s spiked from 41 percent to 48 percent. However, many coal power plants have inflexible contracts with coal mines for the purchase of coal and with railroads for the delivery of that coal. As a result, while Texas coal consumption fell by 15 million tons in 2015, Texas coal deliveries only fell by 10 million tons. The extra 5 million tons were added to coal piles at power plants across Texas, leading to a 37 percent increase in coal stockpiles at Texas power plants over the course of 2015. For reference, the 19.5 million tons of coal stockpiled at Texas power plants as of the start of 2016 would fill a coal train stretching from coast to coast across the United States. The 197 million tons stockpiled at coal power plants nationwide could fill a coal train stretching nearly around the world. Many coal power plants have limited space to stockpile coal. However, as mentioned above, coal purchase and delivery contracts often have minimum delivery requirements, which are used by the mine and railroad to guarantee revenue so they can finance capital upgrades necessary to deliver the coal. As a result of these contract provisions, the power plants must continue to take deliveries of coal even if they don’t need it, or else the power plant owner would face contract penalties or a lawsuit for breach of contract from the mine or railroad. As a result, it appears that many power plants have decided to continue operating at a loss simply so that they can continue to burn coal to avoid those large contract penalties. In some cases it appears that these coal power plants continue producing electricity as power prices fall well below the cost of operating the plant, even as power prices go negative. The inflexibility of the coal contract provisions thus acts as an out-of-market incentive to continue operating coal power plants despite power prices going negative and sending a signal that generation should be reduced. Different policies have led to a similar outcome in China, with coal generation inefficiently displacing wind generation in some hours. Indications of out-of-market coal generation can be seen in market data provided by ERCOT. As an example, the following chart from April 8, 2016, shows electricity demand in green and online generating capacity in red. This chart shows that many power plants are available to come online quickly (see the steep increase in the red line at around 6 AM) and increase their output in the morning and as demand increases over the course of the day. Despite the availability of those quick-starting resources, many power plants continued to operate unnecessarily through the night, even as electricity demand fell more than 10,000 MW below the level of online capacity. With around 5,000 MW of nuclear generation and around 7,000 MW of wind generation running at essentially 100 percent of their available output that night, one can calculate that around 25,000 MW of fossil generating capacity remained online to meet an incremental need for 15,000 MW or less of generation. This indicates these fossil plants were operating at around 60 percent of their nameplate capacity on average, with many fossil power plants likely approaching the minimum level of generation they can provide while remaining online. Even though power prices fell below $7/MWh early that morning, these power plants remained online and continued generating. Some of this behavior was likely motivated in part by the inability of coal power plants to rapidly change their output, and the fact that it is often costly and takes days to turn coal power plants on and off. For example, in some cases power plants remain online based on the expectation that power prices will go high enough to earn a profit later that day or the next day. However, the fact that power prices averaged less than $15/MWh for all of April 8, and the fact that April 8 was a Friday leading into a weekend period of low demand and low power prices, provides strong evidence that at least some coal power plants are operating at a loss to avoid coal contract penalties. Some of the most definitive proof that the recent negative prices in ERCOT were not primarily caused by wind is that the market prices are not consistent with the prices typically offered by wind generators. In 2015, 50 of the 56 instances of negative prices were between -$1/MWh and $0/MWh, while the other 5 were between $-1 and $-2.21/MWh. In contrast, wind generators receiving the renewable Production Tax Credit (PTC) tend to offer their generation at prices in the $-20/MWh to -$35/MWh range. Texas has less than 1,000 MW of wind capacity that received a Section 1603 cash grant in lieu of the PTC, only around 1,000 to 2,000 MW of projects built prior to 2006 that are reaching the end of the 10-year PTC, and an unknown but likely small number of projects that received an Investment Tax Credit in lieu of the PTC. As a bit more background, recent events of ERCOT-wide negative prices are different from previous occurrences of negative prices in Texas. As mentioned in our previous report, earlier this decade wind plants in West Texas were harmed by a lack of transmission capacity that led to negative prices and wind curtailment in the West region. While recent events have seen mildly negative prices across all regions of ERCOT, earlier events typically included negative prices in the -$20 to -$35/MWh range and were confined to the West region. That occurred because transmission constraints prevented wind energy from reaching consumers in large demand centers in East Texas, causing power prices to drop in West Texas while they remained high in the rest of the ERCOT. Because almost no conventional generators are located in the West region, those earlier occurrences almost exclusively affected wind generators and had little to no impact on other generators. Fortunately, building transmission largely eliminated those localized instances of negative prices and greatly reduced wind curtailment in ERCOT, and other parts of the country are seeing similar success in eliminating localized negative prices by building transmission. In addition to coal, other types of generation also contribute to negative prices. In the U.S., nuclear plants almost never change their output in response to changes in demand or power prices, and hydroelectric plants sometimes continue operating despite negative power prices. For example, April is typically a period of low electricity demand and negative prices in many markets, yet April was one of only two months in 2015 when there were no ERCOT-wide negative prices; the likely cause is that one of the state’s large nuclear units was down for a refueling outage for the entire month. Natural gas power plants often sign contracts with gas pipelines that include “take or pay” provisions with inflexibility similar to that of coal contracts, with the gas power plant owner facing penalties if they do not use gas they have purchased. While coal contracts typically cover periods of several years versus several days for natural gas contracts, these inflexible fuel contracts can still cause negative prices if electricity demand falls unexpectedly but generators must still run to avoid contract penalties. Fortunately, it is likely that over the long-term, coal supply contracts will be re-negotiated and the market will catch up to the current reality of low electricity prices caused by low natural gas prices. This should eliminate the negative electricity prices that appear to be driven by the market upheaval caused by low natural gas prices. Transmission can also play a role in alleviating these negative prices, just as it was the solution to the earlier, more localized occurrences of negative prices. In the case of Texas, there are pending proposals to increase power transfer capacity across the asynchronous ties between ERCOT and neighboring regions. This would provide numerous benefits to generators and consumers in both ERCOT and the neighboring regions. For example, when power prices are low in ERCOT they are often high elsewhere, so consumers in those other regions can buy cheaper electricity from ERCOT generators to the benefit of both regions, and the opposite occurs during the hours when power prices are high in ERCOT and low elsewhere. Much like the interstate highway system enables trade that provides billions of dollars in benefits, a stronger electric grid also saves consumers billions.
News Article | March 29, 2016
ERCOT, the organization responsible for maintaining the Texas electricity grid, is predicting more than adequate capacity in the spring amidst an expected surge in renewable power for the state in 2016. In its Seasonal Assessment of Resource Adequacy, ERCOT is predicting a spring usage peak of 58,279 MW. This is well within system capacity even with the assumption that there will be 9,482 MW of lost system capacity due to maintenance and forced outages. This is based on historical outage data going back to 2010. The demand estimates were made using May 2006, a hotter than normal May, as a model. Due to the fact that Texas’ operational solar capacity recently passed a threshold of 200 MW, the methodology for determining how much solar power to include in capacity projections has changed. This resulted in a decreased amount of solar power included in the spring projections. However, 2016 is expected to be an exceptional year for solar energy in Texas. By some estimates, the state will see an additional 2 GW of installed solar capacity in 2016. This would result in a 10-fold increase in solar electricity. Texas has long been considered a sleeping giant when it comes to solar power. Although it has the geography and climate to be a substantial producer, it has had very little in the way of utility scale solar power. This is changing in a big way with projects underway for both the Austin and San Antonio municipal utilities among others. The Austin project, in particular, is notable for its low cost. The purchase agreement for that project calls for a rate of less than 5 cents per kilowatt hour. This is cheap even when compared to natural gas. Several years of cheap natural gas have led to low electricity rates in Texas and created a challenging environment for solar and natural gas to compete on price. Despite this, renewables have continued to gain ground in Texas, led by wind in particular. Wind, along with solar, make up around two-thirds of the state’s additional capacity for 2016. Of the 12,500 MW in new power expected to come online, wind will account for about 63%. 2016 will likely see wind overtake coal as the second largest source of electricity in the state. Although coal is rapidly becoming a smaller contributor to the state’s electricity output, coal plants are still critical for keeping the lights on in Texas. The report downplays any potential impact of compliance with the Mercury and Air Toxics Standards regulations for coal units. With the final compliance date being April 15, 2016, planners expect generators to be in compliance. The preliminary summer report predicts record peak electricity usage for the state with demand peaking at over 70,000 MW for the first time. Against this, it is predicted that the system will have over 79,000 MW of available generation. Original article
News Article | March 20, 2016
Additions this year to the ERCOT grid in Texas are expected to be dominated by ⅔ from wind and solar PV, according to energy research from SNL. If SNL research proves true, this will be a huge boost to the generation of renewable electricity within this historic oil-producing state. As Christian Roselund has written for pv magazine, “This is the beginning of a boom anticipated in Texas over the next 15 years.” In spite of its abundant sunshine and massive open spaces, Texas has long trailed in the US solar market, a trend now changing, ElectricityPolicy concludes: “Solar is poised to take off in Texas,” Peter Sopher, a policy analyst for the Environmental Defense Fund in Austin, told the Dallas News. He compared it with wind power a decade ago, when wind generated 1.4% of the ERCOT system’s electricity. For the first 11 months of 2015, wind’s share was over 11%. And in November, it was over 18%. For a warm, sunny state, Texas has been lagging in solar, as it lacks the incentives of some states and has an abundant supply of cheap energy, including natural gas. But prices for solar panels have fallen over 80% since 2009, making solar competitive with fossil fuels. Last year, solar installations on ERCOT grew almost 50%. This year, solar generation could jump six-fold, by ERCOT projections. If proposed rules to cut emissions and haze remain in place, ERCOT estimates solar will add 14 GW to the ERCOT grid by 2030—and that projection came before last month’s federal budget deal, which extended tax creditsfor renewable energy. Last summer, Austin Energy signed solar power agreements for less than 4 ¢/kWh, hailed at the time as “the cheapest solar ever.” January 14, 2016″ ERCOT is a separate grid from the other two US grids, covering most of Texas’ territory and 85% of the state’s demand. Demand on the ERCOT grid has traditionally been met mostly with gas- and coal-fired generation. Although, in recent years, wind has met more than 10% of annual electric demand, pv magazine has reported. But this year, a number of significant solar projects are under construction, led by those under power contracts awarded by municipal utilities in Austin and San Antonio. Austin Energy has signed contracts for 600 MW of solar PV, which has yet to be completed, and OCI Solar Power had scheduled to complete 400 MW of solar PV for CPS Energy by the end of the year. At this time, solar still only represent an estimated 2% of ERCOT generation capacity by the end of the year. Image via Shutterstock Get CleanTechnica’s 1st (completely free) electric car report → “Electric Cars: What Early Adopters & First Followers Want.” Come attend CleanTechnica’s 1st “Cleantech Revolution Tour” event → in Berlin, Germany, April 9–10. Keep up to date with all the hottest cleantech news by subscribing to our (free) cleantech newsletter, or keep an eye on sector-specific news by getting our (also free) solar energy newsletter, electric vehicle newsletter, or wind energy newsletter.
News Article | April 14, 2016
Originally published on RMI Outlet. By Kevin Brehm and Thomas Koch Blank In a previous blog post, we explained how rural electric cooperatives could become a multi-GW market for community-scale solar by 2020. Co-ops want solar to save money, diversify energy supply, meet renewable portfolio standard (RPS) requirements, and meet member needs. Yet in order for the co-op solar market to achieve its potential, co-ops need to better understand the value of community-scale solar and need to access compelling community-scale offerings. Below we describe three rural electric cooperatives that are accessing compelling community-scale solar offerings. While each co-op has adopted a different approach, their collective experience shows that costs can be reduced through utility-supported development—when utilities proactively support aspects of the development process—and aggregation—when multiple community-scale projects are aggregated into a portfolio. In February, Dairyland Power, a Wisconsin-based generation and transmission provider, announced plans for 15 MW of solar, a huge project in a state off the radar for most solar developers. The 15 MW will take the form of 12 projects ranging between 0.5 MW and 2.5 MW each. Dairyland decided to pursue solar in order to diversify its energy portfolio, remain ahead of RPS and other mandates, and meet the needs of consumers of distribution co-op members who are asking for more solar. In response to its request for proposals (RFP), Dairyland received bids for large centralized solar farms as well as portfolios of community-scale projects. The winning bids, from groSolar of Vermont and SoCore Energy of Chicago, were for portfolios of community-scale projects sited on the distribution grid in the territories of Dairyland’s member co-ops. Craig Harmes, business development manager at Dairyland explains, “There was not a significant difference in prices between centralized projects and distributed projects, and distributed projects provide multiple benefits. Smaller projects can be better absorbed by the local distribution system, they can be located adjacent to substations—minimizing the need for infrastructure upgrades, and by dispersing projects throughout the system we diversify weather conditions. Most importantly consumers of member co-ops prefer distributed systems because they like to know that their renewable energy is local.” Laura Caspari of SoCore explains that though distributed portfolios sacrifice some economies of scale compared to central systems, they save on interconnection costs. “Connecting at the distribution level saves money and time. You don’t have to go through the lengthy MISO study process, and transformer and other tie-in hardware costs are also reduced.” The 15 MW of Dairyland projects are not shared solar; the power is directly sold to one off-taker (Dairyland). Several member co-ops, however, have expressed interest in developing shared solar to add on to the project. Caspari expects that distribution co-ops will add an additional six or eight shared solar projects around 100 kW to 250 kW each. Serving nearly 280,000 accounts in Texas Hill Country, Pedernales Electric Cooperative (PEC) is one of the largest distribution electric cooperatives in the country. In November, PEC released a request for information for a portfolio of community-scale systems. After a competitive procurement process, Pedernales is moving forward with plans to purchase up to 15 MW from several distributed solar sites across its service territory. PEC sees solar as a means to diversify its energy supply, meet member demand for solar, and secure long-term competitive pricing. Instead of developing one 15 MW project in a sparsely populated region of its service territory, Pedernales developed a portfolio of distributed projects. According to Dr. Peter Muhoro, PEC’s director of energy research and strategy, “By sizing our projects just under 1 MW we were able to realize the true benefits of the system being on the distribution side. There is also value in members being able to view the assets. When they can view the solar assets, our members feel more connected to the co-op and our clean energy generation.” In addition, projects less than 1 MW avoid some costly and time-consuming ERCOT wholesale generation requirements. PEC was deliberate about procuring solar in a way that reduced total cost. One way it did this was by bundling individual projects into a portfolio, which reduced its power purchase agreement (PPA) price by approximately $10 to $15/MWh. Those cost reductions include economies of scale from bulk procurement, efficient labor use, and efficient equipment usage. Another way PEC reduced cost was by identifying and securing land for the developers, saving between $3 and $5/MWh on PPA prices. “In some cases, it’s easier for us to find land in our service territory,” Muhoro explains. “We know the local landowners, they trust us, and they are willing to make a fair deal.” Though PEC’s projects were developed as economic additions to PEC’s generation mix and not as shared solar, PEC is exploring options for members to subscribe to the systems. According to Muhoro, “The concept of community solar is not new to co-ops. For nearly eight decades, co-ops have served their member-owners in a similar fashion as community solar, where the member is an owner of the co-op. We believe that co-ops are best positioned to provide community solar solutions as they already have the culture of member ownership.” While PEC serves almost a quarter million Texans, Springer Electric Cooperative serves just over 3,000 meters in northern New Mexico. After an RMI-hosted workshop in Santa Fe, when Springer CEO David Spradlin wanted to expand the co-op’s solar portfolio, he teamed up with neighboring Kit Carson Electric Cooperative (KCEC) to procure community-scale solar. RMI’s Shine program is supporting the co-ops with scoping, procurement, vendor selection, and PPA execution. Earlier this month, RMI released an open RFP for 3 MW from three 1-MW systems on behalf of Springer and KCEC. These are not the first solar projects for KCEC or Springer. Springer has signed PPAs for power from two 1-MW systems in its service territory. KCEC has signed PPAs with multiple community-scale projects including a recent PPA with Picuris Pueblo, one of New Mexico’s 19 pueblo tribes. Though KCEC and Springer are already experienced solar buyers, both co-ops saw value in participating in a collaborative procurement process and receiving RMI support on RFP development and evaluation. Both co-ops are motivated to procure solar to save money and meet member needs. The three examples above show how co-ops can reduce the cost of community-scale solar through utility-supported development and aggregation. Buyer-owned levers include buyer-supported siting, buyer-supported interconnection, and buyer-supported permitting. Collectively these levers are called buyer-supported development or, when the buyer is a utility, utility-supported development. RMI analysis suggests that utility-supported development can reduce PPA prices by around $9/MWh. The co-ops described above supported development by securing sites (Pedernales), identifying leads on sites (KCEC/Springer), and facilitating interactions with local authority having jurisdictions (AHJs) (Dairyland member co-ops). When multiple community-scale projects are aggregated into a portfolio of projects, developers save on hardware procurement, equipment rental costs decrease, and developer labor can be more efficiently utilized. Dairyland, Pedernales, and Springer and Kit Carson each aggregated demand into portfolios of community-scale projects. RMI analysis suggests that volume aggregation can reduce PPA prices nearly $3/MWh. Muhoro of Pedernales believes that savings from volume aggregation may be much greater, perhaps as high as $15/MWh. The examples above are just three of many instances of co-ops pursuing community-scale solar. The market will continue to grow (we estimate to an installed base of 6 GW by 2020) as more co-ops access appealing community-scale solar offerings and as more co-ops learn from the experience of their peers— corresponding to a market opportunity of $8–10 billion over the next 5 years. Drive an electric car? Complete one of our short surveys for our next electric car report. Keep up to date with all the hottest cleantech news by subscribing to our (free) cleantech newsletter, or keep an eye on sector-specific news by getting our (also free) solar energy newsletter, electric vehicle newsletter, or wind energy newsletter.