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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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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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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Electricity Use Falls, Prices Follow

On March 7, I wrote about the high quantity of natural gas in storage this winter. Because natural gas is the fuel most prevalently used to generate electricity in most parts of the country, an increase in stored natural gas is likely due, at least in large part, to a decrease in withdrawals for power generation. Now that electricity usage data from January (the latest month for which data is available) is in, we see evidence of why storage is increasing. The U.S. Energy Information Agency reports that retail electricity sales volumes fell in 42 states and the District of Columbia in January (marked in blue below).

U.S. Electric Industry Retail Sales January 2016 over January 2015, percent change

On a percentage basis, Delaware led the pack in the year-over-year decline with a decrease of more than 15%. Next were New Jersey (-8%), Tennessee (-7%), Indiana, and Maryland (both down 6%).

Nationally, among the four end-use sectors which include Residential, Commercial, Industrial, and Transportation, the Residential sector experienced the largest decline in sales volume (-4.9%) in January 2016 compared to January 2015. The most likely cause for this decline was a reduced need for home heating in 2016 due to average temperatures being warmer than the year earlier.

To compare electricity consumption across time, the industry uses a metric called “Heating Degree Days.” The Heating Degree Day metric accounts for cooler or warmer temperatures. This adjustment is necessary because temperature is a key driver of energy consumption, particularly in the Residential sector; the Heating Degree Day adjustment accounts for temperature variations and allows an “apples to apples” comparison.

Heating Degree Days are calculated by how much colder the mean temperature at a location is than 65°F on a given day. For example, if a location experiences a mean temperature of 55°F on a certain day, there were 10 HDD (Heating Degree Days) that day because 65 – 55 = 10. The following graphic shows fewer Heating Degree Days, which means warmer weather (and therefore less need for heat) in the 22 reddish states across the Northeast, Great Lakes, and lower Midcontinent regions this January compared to January 2015. The largest Heating Degree Day decreases were found in the Northeast, with New Hampshire, Maine, Vermont, and New York the top four states with Heating Degree Day declines between 15% and 17%.

Change in Heating Degree Days, January 2016

 

Heating Degree Days increased in 28 states across the Southeast and West and the District of Columbia, indicating colder weather in these regions compared to last year. California had the largest Heating Degree Day increase, up 33%, followed by Florida, up 31%, and Nevada, up 23%. Despite the increase in some states, the country overall experienced a net decrease as indicated by the lower electricity usage described above.

As economists would predict, lower quantity demanded was generally accompanied by lower prices. The following map shows that average revenue per kilowatt-hour decreased in 27 states and the District of Columbia, and increased in 23 states in January compared to last year.

Change in Average Retail Revenues, January 2016

Average revenues per kilowatt-hour across all sectors were 9.96 cents in January, down 2.2% from last year. Hawaii had the largest decrease for the thirteenth month in a row, down 20% from last year as lower world oil prices continue to benefit Hawaii’s largely petroleum-fueled bulk power system. The next largest year-over-year declines were found in New York, down 13%, and Nevada, down 11% from last year. The largest year-over-year increase occurred in West Virginia, up 16%, followed by Washington, up 11%, and Delaware, up 9%.

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Expect Continued Low Energy Prices With Record Natural Gas Storage

Working gas in underground storage compared with 5-year max and min 2016-02.

The U.S. Energy Information Agency (EIA) reported last week that the amount of natural gas in storage for the week ending February 26 exceeded the year-ago total by 46 percent, and the five year average by 36 percent.

Despite a sustained fall in commodity prices (see table below), which should spur demand, the combination of high injections and low withdrawals resulted in the unusually high 2.536 billion cubic feet (Bcf) in storage for the week ending February 26. (Overall production in 2015 was 5.4% greater than 2014, and consumption is down due to recent warm weather, with December at the lowest level in 31 years).Natural gas spot prices (Henry Hub)

Meanwhile, the Henry Hub spot price fell 11 percent for the week ending March 2, from $1.79/MMBtu on February 24 to $1.59 on March 2. On March 1 the price reached an intraweek low of $1.57, which is the lowest nominal Henry Hub price since December 1998. Other major market locations saw similar declines. At the Chicago Citygate, the spot price fell from $1.80/MMBtu last Wednesday to $1.72 yesterday, hitting an intraweek low of $1.68 on Monday. The Chicago Citygate price hasn’t been below $1.68 since March 1999. At the SoCal Citygate, prices fell from $1.87/MMBtu last week to $1.71 yesterday, hitting a low of $1.59 on Monday as well. This is the lowest SoCal Citygate price on record.

According to the EIA:

If withdrawals follow the five-year average for the remainder of heating season . . . [t]his would mark only the second time that working gas stocks finished the heating season above 2,000 Bcf [at 2,275 Bcf).

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Vast Majority of Planned Capacity in PJM is Natural Gas, Wind, and Solar

PJM's Regional Backbone Transmission System
PJM’s Regional Backbone Transmission System

Introduction

PJM Interconnection, which is the largest grid operator in America and serves more than 61 million people throughout 13 states and the District of Columbia, this week released its annual Regional Transmission Expansion Plan (RTEP). The RTEP is an important document because it charts the path for how PJM plans, over the next 15 years years, to dispatch more than 171,000 MW of generation capacity across 72,000 miles of transmission. To develop the RTEP, PJM annually conducts a thorough “stakeholder process” involving nearly 1,000 members, the Independent Market Monitor, and state public service commissions and other governmental and non-governmental organizations, all of whom gather with PJM’s planning department to consider how to implement a wide range of considerations such as:

  • Load growth;
  • Generating resource interconnection requests;
  • Federal and state public policy (including regulatory action such as the Clean Power Plan);
  • Fuel-of-choice shifts (i.e., from coal to natural gas);
  • Renewable resources;
  • Reliability criteria violations;
  • Operational performance issues;
  • Congestion constraints;
  • Local reliability requirements;
  • Distant load centers;
  • Light load and winter peak load; and
  • Aging infrastructure.

On the load side, PJM finds in the latest RTEP that flatter load growth means fewer network upgrades will be required. PJM attributes flat load growth to factors such as a slow recovery from the 2008 recession, increased efficiency in manufacturing and home appliances, and solar power.

On the generation side, PJM is experiencing a shift from coal to natural gas due primarily to inexpensive gas from the Marcellus Shale, but also as a result of coal plant deactivations driven by increasingly stringent environmental regulations. In addition to new gas resources, new wind and solar resources are being driven by favorable state and federal incentives, along with demand response and energy efficiency.

Today’s Resource Mix

PJM’s current installed capacity – nearly 172,000 MW of RPM-eligible “iron in the ground”– reflects a fuel mix comprised of 35 percent coal, 34 percent natural gas and 20 percent nuclear, as shown below. Hydro, wind, solar, oil and waste fuels comprise the remaining 11 percent.

PJM Existing Generation Fuel Mix - RPM-Eligible Capacity Rights (Dec. 31, 2015)
PJM Existing Generation Fuel Mix – RPM-Eligible Capacity Rights (Dec. 31, 2015)

Today’s fuel-mix looks a lot different from 2010, particularly with regard to coal. In 2010, coal’s 66,221 MW accounted for 40 percent of capacity; today, coal’s 60,291 MW account for only 35 percent of capacity. The 2010 generation profile, which follows, illustrates the recent changes:

PJM Existing Generation Fuel Mix - RPM-Eligible Capacity Rights (Dec. 31, 2010)
PJM Existing Generation Fuel Mix – RPM-Eligible Capacity Rights (Dec. 31, 2010)

As discussed below, the 2015 RTEP shows that, with new projects in the pipeline overwhelmingly gas-fired, the trend away from coal appears certain to continue:

PJM Gas and Coal Capacity

Resources Anticipated in Latest RTEP

The generation mix reflected in the latest RTEP shows several dramatic shifts in installed capacity from only five years ago, most notably:

  • Generators’ flight from coal (down 9 percent from 2010 to 2015)
  • Big increase in natural gas (up 19 percent from 2010 to 2015)
  • Big increases in wind (from 617 MW to 919 MW) and solar (2 MW to 128 MW)

But a truly momentous shift is reflected in the queue for new resources, with natural gas accounting for a whopping 87 percent of all queued capacity rights (72 percent when based on nameplate, with wind accounting for the bulk of the difference due to the large difference between wind’s nameplate and projected actual output):

PJM Queued Generation by Fuel Type - Requested Capacity Rights (Dec. 31, 2015)
PJM Queued Generation by Fuel Type – Requested Capacity Rights (Dec. 31, 2015)

Big Shift in Fuel Choice

The 2015 queue stands in sharp contrast to the entire decade of applications from 1999 through 2010 not only in the lack of variety of fuels, but also in sheer magnitude. The queue in 2015 has nearly 60,000 MW of gas-fired capacity, while the 10-year cumulative applications from 1999 through 2010 for all fuel types contained a total of just over 100,000 MW, with just under 40,000 MW accounted for by gas.

Interconnection Requests by Fuel Type (1999 - 2010)
Interconnection Requests by Fuel Type (1999 – 2010)

Conclusion

With the extension in late 2015 of the Investment Tax Credit for wind and solar we should expect to see a sharp up-tick in those resources in the 2016 RTEP, but these will likely be in addition to, and not necessarily instead of, natural gas.

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U.S. LNG Exports to Benefit Europe’s Energy Security

European gas imports - WSJ

With Cheniere Energy, Inc.  beginning LNG exports from the U.S., The Wall Street Journal reports (subscription required) that plentiful and cheap natural gas will help Europe replace coal with gas (thereby reducing GHG emissions), and increase energy security by lessening dependence on Russia, which currently supplies the bulk of natural gas to Europe at a premium. Commenting on the benefits of having options for natural gas suppliers, Vytautas Grubliauskas, mayor of Klaipeda, the Lithuanian town where an offshore LNG terminal is docked, said “U.S. LNG is more than just about gas. It’s about freedom.”

First Liquefied Natural Gas Export Headed to Brazil

Sabine Pass LNG
Sabine Pass LNG Terminal, photo courtesy of Cheniere.

Cheniere Energy expects the first-ever liquefied natural gas (LNG) export from the lower 48 U.S. states will depart the company’s Sabine Pass terminal in Louisiana today. The ship is headed to Petrobas, in Brazil. Cheniere has six LNG vessels under contract, and will use them to continue exporting gas in the coming weeks and months following approval from the Federal Energy Regulatory Commission (FERC). Noting the significance of today’s event, Neal Shear, Cheniere Partners’ Chairman of the Board and Interim Chief Executive Officer said via a news release:

This historic event opens a new chapter for the country in energy trade and is a significant milestone for Cheniere as we prepare . . . for commercial operations.

Speaking about the international implications of the U.S. exporting natural gas, the State Department’s Bureau of Energy Resources tweeted:

By diversifying global LNG supplies and increasing LNG volumes globally U.S. LNG exports improve global energy security.

It was only about 10 years ago that natural gas was so scarce and costly in America that facilities such as Sabine Pass were intended to import natural gas. Henry Hub prices exceeded $13/MMBtu in late 2005 and nearly reached that level again in mid-2008 before beginning the sustained decline to the current price of around $2/MMBtu. Today’s shipment is a clear sign that the economics have, indeed, changed completely.

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Energy Secretary Moniz on Current Trends in Energy

U.S. Energy Secretary Ernest Moniz

Energy Secretary Ernest Moniz on CNBC now, discussing America’s energy infrastructure. On the subject of cheap natural gas’s impact on energy prices, the Secretary said that nuclear and coal (particularly small plants and plants in the Midwest) are strongly affected, but that cost reductions in wind and solar, in conjunction with state Renewable Portfolio Standards, are keeping the renewables market strong.