Audi to Introduce Solar Roofs, Improve Fuel Efficiency and EV Range

Thin-film solar cells in panoramic glass roofs of Audi models: Audi and Alta Devices, a subsidiary of the Chinese solar-cell specialist, Hanergy, are working together on this development project. With this cooperation, the partners aim to generate solar energy to increase the range of electric vehicles.
Photo courtesy Audi AG.

Audi today announced a plan to increase the range of the company’s electric vehicles by generating onboard solar energy using thin-film solar cells. Audi and its partner, California-based Alta Devices, a subsidiary of the Chinese solar-cell specialist Hanergy, are taking an incremental approach and will first integrate Alta’s efficient, thin, and flexible mobile power technology into panoramic glass roofs. A prototype is expected by the end of this year.

Recognizing that drivers demand maximum range from their electric vehicles, and also responding to ever more stringent fuel economy requirements around the globe, Audi and other vehicle manufacturers are going to great lengths to maximize every opportunity to increase overall efficiency as well as replace liquid fuels with electricity. Consistent with this effort, Audi’s next step after integrating solar into glass panels will be to cover almost the entire roof with solar cells.

By generating onboard and clean renewable power for systems such as air-conditioning and seat heaters, the solar cells will reduce the demand on an all-electric vehicle’s main battery, thereby providing a longer range for driving. But solar cells also can improve fuel efficiency in mild-hybrid vehicles by making the gasoline or diesel engine’s output more fully available for moving the vehicle instead of producing electricity for in-cabin use. Eventually, Audi and Alta envision solar energy directly charging a fully-electric vehicle’s main battery. “That would be a milestone along the way to achieving sustainable, emission-free mobility,” said Bernd Martens, Audi’s Board of Management Member for Procurement.

The partnership with premier automaker Audi is a high-profile opportunity for Alta, holder of multiple world records for energy conversion efficiency. “This partnership with Audi is Alta Devices’ first cooperation with a high-end auto brand. By combining Alta’s continuing breakthroughs in solar technology and Audi’s drive toward a sustainable mobility of the future, we will shape the solar car of the future,” said Alta CEO Ding Jian.

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Hyundai’s Ioniq EV Delivers Ultra-Low Total Cost of Ownership With Novel Recharging Credit

Photo of Hyundai Ioniq Electric.
Hyundai Ioniq Electric; photos courtesy Hyundai America

Recognizing that electric vehicle customers expect a charging plan with their new cars, Hyundai is now offering the “Ioniq Unlimited+” subscription program for the company’s Ioniq Electric (currently available in California only). The subscription program is unique in the industry because it wraps into the lease payment a reimbursement for electricity, based on the number of miles driven, up to the first 50,000 miles. This “recharging credit” will be applied directly to the owners’ subsequent monthly payment. Unlike other automaker charging plans, which generally are limited to one charging service provider and do not include home charging, Hyundai’s plan is completely agnostic as to where the driver plugs in.

The monthly recharging credit, which is included in the $275/month lease price for the base model (having an MSRP of $30,335), essentially offers drivers a charging allowance for use at home, at work, or on the go. The formula Hyundai uses to determine the credit is: Monthly mileage * kWh/mile * Cost per kWh.

These factors are derived as follows:

  • Monthly mileage: Transmitted from the vehicle to Hyundai via Hyundai’s Blue Link service (i.e., the vehicle’s telematics service)
  • kWh/mile: 28 kWh per 124 miles = 0.2258 kWh/mile
  • Cost per kWh: The then in effect California Residential “Average Price of Electricity to Ultimate Customers by End-Use Sector, by State” as published by the U.S. Energy Information Administration in its Electric Power Monthly publication (or $0.186 if the EIA source is no longer available).

An important point to remember is that if the driver uses a charger that requires payment in excess of the reimbursement credit on a per-kWh basis the driver will not be made whole. On the other hand, if the driver plugs in at a free charger, the reimbursement credit will be 100 percent profit because it’s based on miles driven and not the cost of a particular charging session.

Although the Unlimited+ plan is available only for vehicles leased in California, the recharging credit will apply even if the vehicle is no longer in the state (though the reimbursement credit will remain pegged to the price of electricity in California, which should generally be beneficial to the driver because California has some of the highest retail electricity prices in the country).

Photo of plugging in a Hyundai Ioniq Electric.

To maximize the recharging credit, the vehicle would have to cover an average of about 45 miles per day over three years. That would result in a monthly credit of about $60 in addition to avoided gasoline costs of approximately $150 per month (assuming the Ioniq replaces a traditional vehicle getting 29 MPG with gasoline at a California average price of $3.055/gallon).

If an Ioniq Electric driver is so fortunate as to get free charging at work and have solar panels at home, the savings of more than $200/month enjoyed from the recharging credit combined with avoided gasoline and maintenance means that the total cost of driving an Ioniq Electric is about half that a traditional vehicle.

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Debate Flares Over Electric Grid Fuel Supplies

Graph showing PJM Cleared ICAP by Delivery Year
Data source: PJM Interconnection

In a thinly-veiled swipe at renewable energy resources, Energy Secretary Rick Perry is reportedly ordering a study to determine whether the proliferation of renewables is threatening grid reliability by causing baseload (i.e., coal) resources to retire prematurely. The target of the report is not renewables, per se, but rather the compensation scheme for wholesale power in restructured markets around the country, and whether these markets are over or under-compensating various resources and therefore resulting in a sub-optimal fuel mix.

The subjects of generator compensation and fuel diversity are hotly contested in the energy world, as new (and renewable) resources such as wind, solar, and storage seek to compete with traditional resources such as gas, coal, and even nuclear. These new resources, which are favored by regulators in many states (including Perry’s home state of Texas), to date have generally complemented the existing resource mix and grid operators have been able to balance increasing quantities of intermittent resources; while industry insiders have debated the merits and value of various resource types, for the most part these arguments have taken place outside of the spotlight.

Now, though, with the new administration’s efforts to support coal power, along with nuclear operators loudly arguing their plants are being under-compensated and threatening shutdowns in New York, Illinois, and Ohio, and also as wind and solar generation reach ever higher levels of penetration and threaten to upend the historical pricing and production models in states such as California and Hawaii, the fight for the future of the grid is bursting into the headlines.

The Federal Energy Regulatory Commission next month will be holding a technical conference, during which Commission staff seeks to discuss long-term expectations regarding the relative roles of wholesale markets and state policies in the Eastern RTOs/ISOs in shaping the quantity and composition of resources needed to cost-effectively meet future reliability and operational needs.

Testimony for the technical conference will be forthcoming, but in the meantime the nation’s largest electrical grid, PJM Interconnection, has issued a report concluding that today’s resource profile “is both reliable and diverse,” and that not only does a more diverse grid not threaten reliability, “[t]he expected near-term resource portfolio is among the highest-performing portfolios and is well equipped to provide the generator reliability attributes.”

As the resource mix moves in the direction of less coal and nuclear generation, according to PJM, generator reliability attributes of frequency response, reactive capability, and fuel assurance decrease, but flexibility and ramping attributes increase. With regard to solar capacity, PJM concludes that this resource cannot feasibly exceed 20 percent of the mix due to unavailability at night. That said, assuming other nighttime resources, PJM “could maintain reliability with unprecedented levels of wind and solar.”

As for the grid’s reliance on individual fuels, PJM advises that heavy reliance on any one fuel type may negatively impact resilience. For example, gas plants can generally be relied upon to serve up to 86 percent of demand, but risks include interruptions in fuel deliverability in extreme conditions such as a polar vortex; for coal plants, operational risks include coal piles freezing or an inability to replenish coal supplies in extreme conditions.

The resource mix within PJM has become more evenly balanced in recent years. In 2005, coal and nuclear resources generated 91 percent of the electricity on the PJM system. Over time, policy initiatives, technology improvements, and economics spurred a shift from coal to natural gas and renewable generation. From 2010 to 2016 in PJM, coal-fired units made up 79 percent of the megawatts retired, and natural gas and renewables made up 87 percent of new megawatts placed in service. PJM’s installed capacity in 2016 consisted of 33 percent coal, 33 percent natural gas, 18 percent nuclear, and 6 percent renewables (including hydro).

Without identifying the optimal resource mix, PJM concludes that “there are resource blends between the most diverse and the least diverse portfolios which provide the most generator reliability attributes.”

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Utility Rate Structures Challenge Electric Vehicle Fast Charging

According to a report issued by EVgo and Rocky Mountain Institute, today’s electric utility rate structures generally present major, if not insurmountable, challenges to the commercial viability of Direct Current (DC) fast charging of electric vehicles. To solve the problem, utility tariffs must be amended to recognize the rapidly evolving grid and provide a framework that accommodates this unique and critical infrastructure (as generally illustrated by the following video).

The biggest financial challenge for DC fast chargers is the demand charge. Demand charges are determined by the maximum rate at which energy is used, typically during peak hours of a billing period. Generally speaking, once the peak demand is established, the customer must pay for that capacity for the entire year, 24/7/365. While usually not transparent to (nor avoidable by) residential customers, demand charges are a significant and sometimes manageable cost for commercial and industrial customers. In fact, customers who have the ability to curtail their load during peak events do curtail so that they can enjoy the benefit of a reduced demand charge over the course of the year.

DC fast chargers draw a large quantity of electricity (thereby triggering high demand charges), but generally do so only intermittently and for relatively short periods. Because usage on the vast majority of DC fast chargers is relatively light, these units usually do not consume enough electricity over the course of a year to average out the demand charges to a cost-effective level. And companies such as EVgo cannot feasibly avoid or mitigate demand charges by curtailing or spreading load because the units spike by design and customers must be able to charge at any time.

RMI’s study found that, under certain electricity tariffs, demand charges can make up as much as 90 percent of the monthly bill of operational public DC fast chargers, driving the cost of delivered electricity as high as $1.96 per kilowatt-hour (kWh) during summer months in some locations. These charges are nearly seven times as high as the current gasoline equivalent cost of $0.29/kWh, meaning it is difficult for DC Fast charging providers like EVgo to remain competitive with the costs of operating petroleum-fueled vehicles.

“As EV adoption increases, it’s important that drivers have access to affordable charging options outside their homes,” said Terry O’Day, Vice President, Product Strategy and Market Development, at EVgo. “Public fast charging is critical to EV deployment, and the more chargers installed will affect the amount of EVs deployed, which, in turn, will drive utilization and revenue.”

The report recommended the following approaches to promote a competitive business environment for public DC fast charging stations and to facilitate future infrastructure investment:

  • Low fixed charges, which primarily reflect routine costs for items such as maintenance and billing.
  • The opportunity to earn credit for providing grid services, perhaps along the lines of a solar net-metering design.
  • Rates that vary by location—for example, offering low rates for DC fast chargers installed in overbuilt and underutilized areas of the grid. This strategy can increase the efficiency of existing infrastructure and help build new EV charging infrastructure at a low cost.
  • Limited or no demand charges. If demand charges are necessary, it’s essential that they do not capture upstream costs of distribution circuits, transmission or generation.
  • Time-varying volumetric rates, such as those proposed for San Diego Gas & Electric’s Public Charging Grid Integration Rate (GIR). These volumetric charges would recover all, or nearly all, of the cost of providing energy and system capacity.

“As more and more Californians embrace the many benefits of EVs—reduced carbon and air emissions, lower per-mile usage costs compared with gasoline-powered vehicles and increasing operating ranges— now is the time for California to ensure that the support infrastructure for EVs keeps pace,” said Jeruld Weiland, a Managing Director at RMI. “We hope this research helps inform California’s electricity-sector stakeholders on constructive approaches to best position the state to meet its ambitious carbon-reduction goals.”

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More Customers to Benefit from Florida Power & Light’s Commitment to Solar

Florida Power & Light Company, the third-largest electric utility in America and the largest generator of solar energy in Florida, this week announced an accelerated timetable to build nearly 600 megawatts of solar capacity across eight locations. The energy these projects will produce, which will be enough to fully support approximately 120,000 homes, will diversify the source of electricity for all customers on the grid and efficiently provide a little more green energy to the entire customer base.

Utility-scale solar is a cost-effective way of delivering renewable energy to everyone, and for customers who rent their homes or whose roofs are not suitable for solar panels, the type of projects FPL is undertaking may represent the only way of obtaining renewable energy. “We have been working hard to drive down the costs of adding solar so we can deliver even more zero-emissions energy to all of our customers. As the first company to build solar power generation cost effectively in Florida, we are proud to continue leading the advancement of affordable clean energy infrastructure. We have proven that it’s possible to cut emissions and deliver reliable service while keeping electric bills low for our customers,” said Eric Silagy, FPL president and CEO. Construction is expected to commence this spring. During peak construction, an estimated 200 to 250 people will be working at each site.

The company expects the new installations will be cost-effective over their operational lifetimes, which is consistent with other reported metrics. For example, FPL reports that its carbon emissions today are lower than the U.S. Environmental Protection Agency’s Clean Power Plan’s goals for 2030, while the company’s typical residential customer’s 1,000-kWh bill is approximately 25 percent lower than the latest national average. Last year, according to the company, FPL’s residential bills were the lowest in Florida among reporting utilities for the seventh year in a row. In addition to the grid-scale projects announced this week, FPL has installed small-scale solar arrays for more than 100 Florida schools and other educational facilities.

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Cheap Natural Gas Provides Temporary Dip In Residential Electricity Prices

Countering a slow but sustained climb, data released this week by the U.S. Energy Information Administration shows that residential electricity prices for the first half of 2016 fell 0.7%, to a national average of 12.4 cents per kWh. Over the past five years, nominal residential prices have increased an average of 1.9% annually, about the same rate as overall inflation.

Graph showing U.S. residential electricity prices

The key factor driving prices down this year is the low price of natural gas, the fuel that many power plants burn to produce electricity. Over the first six months of 2016, the weighted average cost of natural gas delivered to electricity generators was $2.58 per million Btu, 28% lower than in the first half of 2015 and down substantially from 2014.

Chart showing price of natural gas for electric power generation

Some regions are experiencing larger drops than others, though this is at least partly a reflection of prices being particularly high in those areas prior to this year’s decline:

Graph showing average residential electricity prices by census division (1H-2015 to 1H-2016)In New England, for example, where energy prices increased substantially from 2013 to 2014, prices in June of 2016 were 6% lower than in January of 2016. Prices in New England today are lower due to a sustained low price of natural gas nationally, combined with increased gas deliverability to a region that previously was constrained. Key pipeline projects that came online to serve that part of the country in late 2015 or early 2016 include:

  • The Rockies Express Pipline (REX) reversal project had added westbound capacity to flow natural gas to the Midwest in 2014. In late 2015, Texas Eastern Transmission Company’s (Tetco) OPEN project added 550 million cubic feet per day (MMcf/d) of pipeline takeaway capacity out of Ohio.
  • Columbia Gas Pipeline’s East Side Expansion, a 310 MMcf/d project that flows natural gas produced in Pennsylvania to Mid-Atlantic markets.
  • Tennessee Gas Pipeline’s Broad Run Flexibility Project, a 590 MMcf/d project originating in West Virginia that moves natural gas to the Gulf Coast states.
  • Tetco’s Uniontown-to-Gas City project flows up to 425 MMcf/d of natural gas produced in the Marcellus region to Indiana.
  • Williams Transcontinental Pipeline’s Leidy Southeast project provides additional capacity to take Marcellus natural gas to Transco’s mainline, which extends from Texas to New York. From there, the natural gas serves Mid-Atlantic market areas as well as the Gulf Coast.

Map of Gas Pipelines in New England

Notwithstanding the increase in pipeline capacity, the Energy Information Administration projects the national average delivered cost of natural gas in the last six months of 2016 will be 27% higher than the average cost in the first six months of the year. Residential electricity prices, in turn, are expected to increase by about 3% in 2017.

Graph showing projected retail price of electricity in residential sector 2015 to 2017.

The 2017 projection is supported by the following graph, which shows current options and futures prices placing the lower and upper bounds for the 95% confidence interval for December 2016 contracts at $2.25/MMBtu and $4.51/MMBtu, respectively. According to the Energy Information Administration, the 2017 forecast Henry Hub average is $2.87/MMBtu (compared to $2.58/MMBtu for the first half of 2016).
Graph showing Henry Hub prices, 2015 to 2017.

Another factor causing retail prices (as opposed to wholesale prices) to rise is the increased costs utilities are passing on to customers to maintain, update, and secure their grids. Can anything be done to avoid or mitigate these price increases? One approach would be to reduce demand for electricity through energy efficiency, demand response, and behind-the-meter generation such as solar power. All else being equal, these practices should cause the price to fall due to a lower quantity of electricity demanded. Paradoxically, however, reduced demand for grid power could actually increase the price for those remaining on the grid because of a smaller pool of kWh over which the utility can spread fixed costs. Regulators in regulated and vertically-integrated states are taking a variety of approaches to this dilemma, as demonstrated by proceedings in states including (but not limited to) Nevada, New York, California, Massachusetts, Maryland, and Minnesota.

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Nevada Solar Dispute Nears Resolution After Court Remands Controversial Ruling

Picture of residential rooftop solar panels.A Nevada state court this week set aside part of the Public Utilities Commission’s controversial decision to change rates on existing solar customers because the Commission’s process lacked adequate notice to the public, but due to ongoing discussions between the parties the hotly contested issue may soon be at least partially settled anyway. Regardless of what happens at the Commission, the subject is certain to be revisited when the legislature next convenes.

The immediate result of the court’s ruling is that the part of the Commission’s order which would have reduced bill credits to customers who already have solar panels is set aside and remanded to the Commission, while the remainder of the ruling upholding the Commission’s order relating to new solar customers is affirmed.

But the court’s remand is likely to be superseded because the Commission, at a hearing coincidentally scheduled for tomorrow, will consider a settlement between utilities and customers to grandfather the 32,000 existing residential rooftop customers on the old rate for 20 years. If, as expected, the Commission ratifies the grandfathering agreement, the remanded case will become moot.

Since 1997, Nevadans have participated in a program called net energy metering, under which customers earn a kilowatt-hour bill credit for each kilowatt-hour of clean power they produce that exceeds their own consumption. The high value of the credit was a key factor in many Nevadans’ decision to install solar because the credit offset a meaningful portion of cost. The Commission’s recent decision radically changed the way credits are calculated and valued, and replaced the framework with a new system that values the excess much lower than before.

Recognizing that a critical element in the financial model for solar installations went away overnight, the Commission’s ruling caused nearly every solar installer to immediately abandon the state. The new formula also caused an uproar in the renewable energy community because it significantly reduces income that solar customers had been expecting to receive, causing what had been good investments to go under water (financially). The move to not grandfather customers also set a precedent that alarmed renewable energy advocates concerned that commissions in other states might follow Nevada’s lead.

While states do periodically shift gears on rates on a going-forward basis, it was well-known in Nevada that customers relied on the net metering tariff in making relatively significant long-term investments. While the Commission is legally entitled to change the tariff in a way that reduces payments to customers for excess solar production, for policy reasons such changes are often made only to new customers, not existing customers.

With regard to the process the Commission followed in this case, the court found that the Commission did not sufficiently notify the public of its intention, and therefore the public was deprived of its right to participate in the proceeding. It is well established in American law that public entities such as the Commission must provide notice of the matters before it. As to the question of how specific notice must be, the Nevada Supreme Court in a previous case explained that “[i]nherent in any notice and hearing requirement are the propositions that the notice will accurately reflect the subject matter to be addressed,” and that “notice must be specific enough to alert all interested persons of the substance of the hearing.” When notice is deficient, the court found, the result is a “denial of fairness and due process.” The requirement, which falls under the legal description “subject matter jurisdiction,” cannot be waived, does not require the affected parties to have been absent from the proceeding, and may be raised by any party or the court at any time.

The notice in this case not only did not include a sufficient description of the issue that was ultimately addressed, the notice specifically excluded the highly controversial matter by saying that the proposal “does not . . . [a]ffect the rights of [existing solar] customers in any way.” Based on the fact that courts as high as the Supreme Court of the United States have, for decades, held notice to be an “inexorable safeguard,” the Nevada court rejected a multitude of arguments that the deficient notice should not result in the court throwing out the Commission’s ruling.

However, the court also explained that its ruling in this case is limited to the procedural requirement of notice for existing customers, not to substantive policy issues related to existing solar customers or to anything relating to new solar customers. In fact, the court specifically rebuffed all objections raised by solar supporters relating to the validity of the Commission’s order on new solar customers, finding that the Commission’s order is not contrary to law, is not arbitrary or capricious, and does not violate the Contract Clause of the U.S. Constitution.

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100 MW Mustang Solar Project Begins Commercial Operation

Photo of Mustang Solar Project.
Mustang Solar Project

Thanks to a large new solar installation constructed by Recurrent Energy, a wholly owned subsidiary of Canadian Solar Inc., approximately 45,000 more homes in California will now have access to 100% renewable energy. The Mustang solar project, spread across 1,000 acres in Kings County, California, has reached commercial operation and is expected to produce 100 MWac/134 MWp of electricity.

“The commercial operation of the Mustang solar project continues a historic year that will see Recurrent Energy complete more than one gigawatt of U.S. solar photovoltaic (PV) projects,” said Dr. Shawn Qu, Chairman and Chief Executive Officer of Canadian Solar.

The renewable energy generated by Mustang’s single-axis trackers will be sold under long-term power purchase agreements to Sonoma Clean Power and MCE. The project is expected to produce enough electricity to power approximately 45,000 homes.

Sonoma Clean Power and MCE are both not-for-profit agencies, offering their customers the option of using environmentally friendly power, generated by renewable sources, like solar, wind and geothermal, at competitive rates.

The power purchase agreement allowed Recurrent Energy to secure a tax equity investment commitment from U.S. Bancorp Community Development Corporation. Adam Altenhofen, the bank’s vice president, commented on the reasons for the investment by saying “High-quality solar projects like Mustang are an important strategic investment for U.S. Bank, which provide jobs to local communities, while delivering clean, reliable energy to the state of California.”

Recurrent Energy employed approximately 450 during the peak of construction, and supported the local economy by spending more than $3 million on local construction materials and services such as food and housing. In terms of long-term economic benefits, the project will generate $3.6 million in tax revenue for the county and $8.1 million in tax revenue for the state.

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Wholesale Energy Prices Down Dramatically in PJM

Map of PJM Showing Locational Marginal Pricing

Real-time and day-ahead wholesale energy prices in PJM Interconnection, the regional grid operator serving 60+ million customers in 13 states and the District of Columbia, fell by more than a third in the first half of 2016 compared to the first half of 2015 according to a recent report from Monitoring Analytics, the grid operator’s independent market monitor.

The decline is attributed to lower fuel prices and lower demand for electricity. Specifically, the load-weighted average real-time locational marginal price* (LMP) was 36.0 percent lower in the first six months of 2016 than in the first six months of 2015. In terms of dollars per MW-hour (the cost of generating one megawatt of power for one hour), this means a decline from $42.30 to $27.09. Day-ahead prices declined by a similar amount, 36.8 percent, from $43.26 per MW-hour to $27.33 per MW-hour.

The first factor driving price, which is fuel, reflects a decline in the coal and gas commodity markets. The other factor driving LMPs down was reduced demand. Average load in the first half of 2016 was 5.3% lower than in the first half of 2015 (90,586 MW vs. 85,800 MW), and average offered real-time generation increased by 458 MW, from 156,679 MW to 157,137 MW.

While notable, this price drop will generally not be seen quickly by most residential retail customers for the following reasons:

  1. The price of energy is only part of the total bill that residential customers pay. The balance of the bill includes distribution charges (the utility’s cost of maintaining the local grid) and various taxes and fees.
  2. In addition to energy being only a portion of the bill, energy itself is comprised of multiple factors, LMP being only one. According to the market monitor’s recent report, LMP today is about two-thirds of the energy cost (the other third being capacity, transmission, and a few incidental energy-related services).
  3. Residential retail electricity prices, as well as most retail electricity prices in general, are usually set relatively far in advance and adjust slowly and periodically.

That said, the real-time prices addressed by Monitoring Analytics are a key signal for short, medium, and long-term contracts. Therefore, if low LMPs are sustained, as appears to be the case today, then these prices will eventually make their way into the prices all customers pay.

*LMP is defined as “the hourly integrated market clearing marginal price for energy at the location the energy is delivered or received.” The market for electricity on the PJM grid contains many delivery points (see map above), and the price at any given point is determined largely by the cost of the most expensive generator delivering electricity to that point at that particular time.

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Gas-Fired Power Generation Extends Dominance Over Coal

Photo of Siemens gas turbine.
Natural gas-fired combined cycle turbine (Siemens press picture)

For the first time ever, the rolling 12-month total of natural gas-fired power generation in the United States ending in January 2016 was higher than the rolling total for coal-fired generation. According to reports from the U.S. Energy Information Agency, this was not a one-month anomaly: the running 12-month totals for natural gas continued to be higher in February, March, and April 2016.

Rolling 12-month and monthly output of natural gas and coal-fired generatorsUntil as recently as March 2015, gas-fired generators had *never* produced more power in a single month than coal-fired generators. This graph shows coal’s historical dominance:Net generation by coal and natural gas, 2001 - 2015The gap between coal and gas has been slowly narrowing, and in April 2015 electricity generated from natural gas-fired sources for the first time exceeded generation from coal-fired sources.Net generation by fuel type, March 2015 - March 2016The turn toward from coal to gas is small but decisive: Although coal-fired generation narrowly regained the lead in May and June of 2015, since that time gas-fired generation surpassed coal-fired generation in eight out of nine months (relinquishing it only in January, 2016, when coal produced 113,750 MWh to 109,979 MWh for natural gas).

Natural gas’s surge in the power sector is driven by two factors: (1) a flight from coal due to costly new emissions requirements that challenge coal’s economics, and (2) a falling commodity price that helps even in the absence of environmental factors. The following graph shows the long-term decline in the price of natural gas:Average cost of fossil fuels for electricity generation (per Btu) for natural gas, monthlyThe dominance of natural gas is expected to continue, as demonstrated by a report from PJM Interconnection showing that natural gas accounts for a whopping 87 percent of all queued capacity rights.

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