Item A-3 Presentation:

Slide 1

Item No.: A-3 | May 17, 2018

Summer 2018 Energy 

Market and Reliability 

Assessment

“Good morning Mr. Chairman and Commissioners.
Slide 2

Electric and Natural Gas 

Markets Appear Ready for a 

Potentially Warm Summer

• Summer temperatures are expected to be above 

average.

• Reserve margins are expected to be adequate in 

most regions.

• Natural gas demand from power generators may 

set record highs this summer.

• Natural gas production could also set record highs.

• Performance requirements will apply to a majority 

of capacity resources in ISO New England and PJM.

“The Office of Electric Reliability and the Office of Enforcement are pleased to present the 2018 

Summer Assessment. This is staff’s high level summary of the reliability challenges that are 

anticipated in the coming operating season and staff’s corresponding assessment of electric and 

natural gas markets as we head into the summer months. We will discuss current and future 

trends, as well as how recent developments may influence market outcomes. 

“Please note that some information in this presentation comes from NERC’s 2018 Summer 

Reliability Assessment which will be released at a later date and is still subject to change.

The National Oceanic and Atmospheric Administration (NOAA) forecasts a warmer than average 

summer for most of the country.

“The North American Electric Reliability Corporation (NERC) Regional Entities anticipate that 

power resources will be able to meet the reference margin levels in most regions this summer. 

The Electric Reliability Council of Texas (ERCOT), however, anticipates its reserve margin will be 

below its reference margin level.

“In Southern California, lower-than-average hydro generation may create challenges as natural 

gas-fired generation, the replacement for hydro production shortfalls in past years, may be 

limited due to reduced gas storage capacity and local pipeline outages in the region.

Nationwide, this may be a record summer for natural gas demand for electric generation. EIA 

forecasts that natural gas production will climb to near record highs.
“Performance requirements for all capacity resources in ISO New England will take effect on 

June 1, while over 80 percent of capacity resources in PJM will be subject to a performance 

requirement for the upcoming capacity year. 
Slide 3

NOAA Forecasts AboveNormal Temperatures for 

Summer 2018

Source: National Oceanic and Atmospheric Association

“NOAA forecasts an above-normal chance for higher than average temperatures for the West, 

South, and East for June, July, and August. The expectation for higher than average 

temperatures is greatest in New England and along a band running from West Texas through the 

Pacific Northwest.
Slide 4

Generation Capacity Sufficient 

to Meet Forecasted Demand in 

the U.S. 

0

200

400

600

800

1,000

2008 2010 2012 2014 2016 2018

GW Net Internal Demand Resources & Net Transfers Actual Demand

Source: NERC Historical and 2018 NERC Summer Reliability Assessment Data

“The NERC Regional Entities forecasted net demand for electricity to be approximately the same 

as it was last summer. The projected lack of growth in the net peak is mainly attributable to the 

higher implementation of demand response in certain areas, and an increase in behind-themeter distributed energy resources. 

“Over 25 GW of new generating capacity plans to enter commercial service through the end of 

the summer period. A majority of the capacity additions will come from natural gas-fired and 

renewable resources, such as solar and wind. 

“Approximately 14 GW of generating capacity has retired since May 2017, including 

approximately 10.8 GW of coal-fired capacity and 2.3 GW of natural gas-fired capacity. Notable 

coal retirements within the past six months include the 1,187 MW Big Brown, 1,980 MW 

Monticello, and 1,282 MW Sandow power plants in Texas. In addition, the 1,358 MW St. Johns 

River Power Park coal plant in Florida retired this year.
Slide 5

Reserve Margins Adequate in 

Most NERC Regions

0%

5%

10%

15%

20%

25%

30%

35%

ERCOT FRCC MISO NPCC PJM SERC SPP WECC

US

Reserve Margin (%)

Reserve Margin Anticipated Reference Margin Level

Source: 2018 NERC Summer Reliability Assessment Data

“The NERC Regional Entities’ data indicates that planning reserve margins for most assessment 

areas will be adequate this summer. The columns shown on this chart display the anticipated 

reserve margins for the markets and regions, while the black bars indicate the reference 

margins.

“ERCOT anticipates that its reserve margin will be 10.92 percent, which is below its reference 

margin level of 13.75 percent. According to the ERCOT summer assessment, significant 

resource changes since last summer have reduced reserve margins in ERCOT, including the 

retirement of 4,449 MW of coal capacity in January and February 2018; the retirement of 806 

MW of gas-fired capacity in late 2017; and delay in construction of new resources, totaling 

about 2,100 MW, that will not be available to serve load during the peak. 

“ERCOT expects to have sufficient operational tools to manage tight reserves and maintain 

system reliability. Those operational tools include deploying ERCOT- contracted load resources 

and emergency response services, using a previously mothballed unit expected to return to 

service in May 2018, requesting power across the existing DC ties, calling on generating 

resources that can switch between the Eastern Interconnection and ERCOT, and block-load 

transfers with SPP and MISO. There are also voluntary actions that consumers and market 

participants may take, such as conservation, operating distributed generation, and price 

responsive demand response.

“MISO’s reserve margin for summer 2018 is projected to be 19.1 percent, which is two 

percentage points higher than the reference margin level of 17.1 percent. Since last summer in 
MISO, some large units retired, but these were offset by additions. With a reserve margin of 

19.1 percent, MISO does not anticipate reliability issues for the normal forecast for the 

upcoming season. In addition, MISO’s Summer Assessment studies system reliability for both 

high-outage and high-load scenarios. For these conditions, MISO expects to rely heavily on 

demand response.

“Finally, the summer 2018 reserve margin for the portion of WECC that is mostly CAISO is 

projected to be 20 percent, which is 5 percent higher than the reference reserve margin of 15 

percent. Generally, CAISO expects an adequate supply for normal load and supply forecasts. 

However, CAISO’s 2018 Summer Loads and Resources Assessment expects tighter supply 

conditions if high-load and below-average hydroelectricity production conditions occur. CAISO 

indicates that it expects demand response and consumer conservation to mitigate tight supply 

conditions in that scenario.

“In the Mid-Atlantic and Northeast regions, as well as SPP and Florida, reserve margins appear 

to be more than adequate, ranging between 5 and 10 percent above reference levels.
Slide 6

Diverse Generating Capacity 

Available During On-Peak 

Load

Source: 2017 NERC LTRA Data, On-Peak Forecast of Available Capacity for Summer 2018

Texas

East

West

“This graphic shows a breakdown of this summer’s expected generating capacity to be available 

on peak by primary fuel type across the Eastern, Texas, and Western Interconnections. 

Looking more broadly at the nameplate capacity additions forecasted to occur during the 

summer period (May 1 through September 30), the Eastern Interconnection expects to add 

approximately 11,286 MW of natural gas-fired capacity, 4,835 MW of solar photovoltaic 

capacity, and 2,476 MW of wind capacity, based on ABB Velocity Suite. 

“ERCOT expects an additional 355 MW of gas capacity to be added by September 30, 2018, 

which is the end of ERCOT’s summer “peak load season.” Also, ERCOT expects an additional 

installed renewable capacity of 1,348 MW to be added by September 30, 2018 including 961 

MW coming from wind and 387 MW from solar.

“Finally, WECC anticipates installed capacity additions in the Western Interconnection of 319 

MW of natural gas, 570 MW of solar photovoltaic, 968 MW of wind capacity, and 568 MW of 

hydro capacity by the end of 2018. 
Slide 7

Narrow Coal-Natural Gas 

Spread to Fuel Diverse 

Generation

 -

 10

 20

 30

 40

0

1

2

3

4

5

6

2013 2014 2015 2016 2017 2018

Power Burn Henry Hub CAPP Coal

$/MMBtu Bcfd

Forecast

Sources: U.S. Energy Information Administration, CME Group, Bentek Energy

“This summer could see near-record-high gas demand from natural gas-fired power generators. 

EIA forecasts natural gas power burn to average 35.16 Bcfd through June, July, and August, just 

0.3 Bcfd less than the record high natural gas power burn set in the summer of 2016, and 3 Bcfd 

higher than last year. The addition of over 16,000 MW of new capacity to the natural-gas fired 

generator fleet since the record highs in 2016 and relatively low natural gas prices contribute to 

expectations for strong natural gas generation this summer. Futures prices for Central 

Appalachian (CAPP) coal are less than $2.50/MMBtu, while the Henry Hub natural gas futures 

summer strip reaches as high as $2.87/MMBtu. 
Slide 8

Natural Gas Futures Prices Are 

Lower Across All Regions

Henry Hub

$2.76 (-16%)

Transco 85

$2.72 (-15%)

NGPL TxOk

$2.58 (-17%)

TCO

$2.51 (-19%) Transco Z6 Non-NY

$2.47 (-20%)

Transco Z6 NY

$2.52 (-16%)

Algonquin

Citygates

$2.48 (-24%)

Chicago 

Citygates

$2.40 (-23%)

Waha

$1.54 (-48%)

NGPL Midcont

$2.13 (-28%)

CIG

$1.95 (-29%)

Socal 

Border

$2.21 (-28%)

PG&E 

Citygates

$2.71 (-21%)

ICE Summer 2018 

Futures

$/MMBtu 

<=1.50 >=2.80

Source: Intercontinental Exchange, Inc.

Basis futures show prices for July and August 2018 as taken on March 23, 2018.

Comparison is to July and August 2017 basis futures; however cut off date may vary depending on availability.

“Summer 2018 natural gas futures prices are generally lower compared to those for summer 

2017. At $2.76/MMBtu, Henry Hub summer futures prices are down $0.52/MMBtu, or 16 

percent, compared to a year ago. The difference between the summer futures prices around 

the country and the futures price at the Henry Hub, also known as basis, fell for most domestic 

natural gas production regions, except for Transco Zone 4 which is up $0.03/MMBtu from last 

year and Dominion South which is up $0.08/MMBtu from last year.
Slide 9

Natural Gas Storage Levels 

Expected to Remain Within 

Five Year Range

Source: U.S. Energy Information Administration

0

1,000

2,000

3,000

4,000

Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec

Storage Inventories (Bcf)

5 Year Range 2017 2018 Actual 2018 EIA Forecast

“Natural gas storage inventories began the injection season on April 1, at 1,354 Bcf, about 350 

Bcf less than the 5-year average. This is the largest deficit to the 5-year average at the start of 

an injection season since 2014.

“Growing gas production from fields in Appalachia, Texas, and elsewhere increased U.S. output 

to record highs. In March 2018, the U.S. produced 84.9 Bcf/d of marketed natural gas, a yearover-year gain of over 8 Bcf/d. Continued production at this volume should position the market 

to meet summer demand and adequately restock storage inventories. Specifically, EIA forecasts 

that inventories will grow to about 3,800 Bcf by November, which is within the 5-year range. 
Slide 10

Performance Requirements Will Apply to 

a Majority of Capacity Resources in PJM 

and ISO New England

• PJM and ISO New England are adopting 

performance requirements in their capacity 

markets.

• PJM and ISO New England assess penalties when 

providers fail to perform in specified hours; give 

rewards to over-performers in those hours.

• No Performance Assessment Hours have been 

declared in PJM since the program began.

• ISO New England Pay for Performance rules start 

June 1.

“Both PJM and ISO New England are implementing changes to their three-year forward capacity 

markets to enhance reliability through market incentives. These changes alter capacity markets 

in both regions to compensate and/or penalize capacity suppliers based on how well they 

perform when called upon by system operators during shortage conditions. Resources that fail 

to perform during these shortage conditions will have compensation subtracted from their 

capacity revenues, while those resources that over-perform in providing energy and reserves 

will receive additional compensation. In the two delivery years thus far in which some resources 

in PJM have been subject to Capacity Performance rules, there have been no shortage 

conditions that triggered an assessment of penalties or rewards.

“PJM is phasing in its Capacity Performance; the program now encompasses 80 percent of the 

total capacity requirement. After one more transition year, 100 percent of resources must meet 

the Capacity Performance rules in delivery year 2020-2021. ISO New England’s Pay for 

Performance program imposes similar performance obligations and will apply to all capacity 

resources beginning June 1, 2018. 
Slide 11

CAISO Depends on Natural Gas 

and non-Hydro Renewable 

Generation in Dry Years

0

2,000

4,000

6,000

8,000

10,000

12,000

1 5 9 1 5 9 1 5 9 1 5 9 1 5 9 1 5 9 1 5 9

2011 2012 2013 2014 2015 2016 2017

GWh

Hydro Renewables Natural Gas

Source: ABB Velocity Suite Note: Summer months in grey

“Hydroelectric generation to serve the California ISO depends on precipitation, especially snow 

pack, in the months leading up to the spring and summer. This year, snowpack in the Pacific 

Northwest topped normal levels, but fell well below normal in California. 

With warmer than normal temperatures forecasted for this spring, the snowpack may melt 

faster than usual, reducing the amount of hydro generation available during the coming 

summer months to help meet peak electric demand. 

“Historically, CAISO has increased use of natural gas fired-capacity and imports to offset lower 

hydro generation levels. However, natural gas supply limitations in southern California this year 

may affect CAISO’s use of its natural gas generation fleet and present some risk to CAISO’s 

markets and operations this summer. Distribution level pipeline outages in southern California 

could affect the amount of natural gas that can be supplied to power plants and can hamper the 

movement of natural gas into storage.

“Limited operations at Aliso Canyon natural gas storage facility, plus state rule changes reducing 

the rate at which natural gas may be injected and withdrawn from storage, may complicate 

pipeline operations. 
Slide 12

Use of Battery Storage 

Increases

Source: Derived from U.S. Energy Information Administration Form EIA-860M (January 2018)

*Note: Alaska (43 MW) and Hawaii (41.5 MW) nameplate capacity not shown.

“Electric battery storage is deployed across the U.S., with the largest number of installations in 

PJM and California. As of January 2018, 720 MW of battery storage capacity was in operation 

nationwide, an increase of 30 percent from the previous year. An additional 63 MW is expected 

by this summer. According to EIA, 88 percent of battery storage capacity provided frequency 

regulation, 28 percent served as ramping/spinning reserve, and 23 percent provided voltage or 

reactive support to the transmission system in 2016, with some serving more than one function 

during the year.
Slide 13

Conclusions

• Capacity and fuel availability appear adequate in 

most areas.

• ERCOT expects tight capacity conditions, but has 

mapped out procedures to maintain grid reliability.

• Lower-than-usual hydro production will affect the 

Western generation mix and may put upward 

pressure on energy prices in California.

• Adequate natural gas supplies in most regions will 

support anticipated gas generators’ needs.

“Staff’s analysis of the energy reliability and market conditions and trends going into this 

summer indicate that most regions appear prepared for the expected summer demand. Areas 

worthy of attention as we proceed through the summer season are hydro and natural gas 

availability in Southern California and total generating capacity in ERCOT.