Slide 1

Item No: A-4

May 16, 2013

Summer 2013

Energy Market and 

Reliability Assessment

Good morning Mr. Chairman and Commissioners. We are pleased to present the Summer 2013 Energy 

Market and Reliability Assessment, a joint effort of the Office of Enforcement and the Office of 

Electric Reliability. The Summer Assessment is the staff’s annual opportunity to share our assessment 

of the electric, natural gas, and other energy markets, as we head into the summer months. 

This presentation does not necessarily reflect the views of the Commission or any Commissioner. 

Market conditions going into the summer will reflect the rebound in natural gas prices and the 

anticipation of a warmer-than-normal summer for most of the country. The markets are expected to 

see greater coal burn in reaction to higher natural gas prices and utilize demand response programs to 

manage peak loads. As weather is an important, but unpredictable factor, there can be localized price 

spikes, particularly in the South Orange County and San Diego area, as constraints become acute. 
Slide 2

Key Takeaways

 Reserve margins remain adequate with one exception.

• Texas faces increased risk with extreme heat.

 South Orange County and San Diego face very tight capacity 

situations with San Onofre offline.

 Higher natural gas prices should predominantly favor dispatch 

of coal over natural gas. 

 Forward natural gas prices rebound above $4.00/MMBtu for 

this summer and drive increase in electric forwards. 

The key takeaways from today’s presentation are as follows:

In general, reserve margins remain adequate with the exception of Texas. The availability of the San 

Onofre Nuclear plant remains a key market and reliability factor in South Orange County and San Diego. 

Higher natural gas prices should favor dispatch of coal plants over natural gas plants in some regions, 

especially the Midwest, Rockies, and Mid-Continent.

Higher natural gas forward prices are translating into higher electricity forward prices. While forwards 

are not a forecast of prices, they may portend upward price trends on power prices for this summer.

Dave will discuss the summer assessment from a reliability perspective. 
Slide 3

Reserve Margins Adequate 

in Most Regions

Source: NERC 

0

200

400

600

800

1000

2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013

GW

Forecast Demand Actual Demand Forecast Capacity

Preliminary data from NERC’s Summer Assessment indicates that reserve margins will exceed planning 

targets in most regions of the country this summer. However, in Texas, ERCOT is forecasting a reserve 

margin of 12.9 percent, which is below its reserve margin target of 13.75 percent. For California, 

WECC is forecasting a reserve margin of approximately 19 percent, four percentage points above the 

reserve margin target of 15 percent. 

Overall, NERC forecasts that total U.S. load, when weather adjusted, will rise slightly less than one 

percent compared to last year. Some areas, such as ERCOT, are projecting load growth over the next 

year, while other areas are projecting that loads will remain flat or decline. 
Slide 4

Wind and Solar Capacity

Source: NERC and SEIA

0

10

20

30

40

50

60

2008 2009 2010 2011 2012 2013

Wind Capacity (GW)

Available On Peak

Total Capacity

The NERC Summer Assessment forecasts that the summer installed nameplate wind capacity will 

increase by about 9 GW, or about 19 percent from 2012. This will bring the total nameplate capacity 

across the nation to approximately 56 GW. The forecasted average on-peak wind capacity for this 

summer is 15 percent of nameplate capacity. 

WECC also projects that approximately 2 GW of new utility-scale solar capacity will come online this 

summer, primarily in Southern California and Arizona. WECC’s on-peak capacity forecast for this 

generation is 99 percent of the nameplate capacity. Industry reports indicate that by the end of 2013 

total installed solar capacity in the United States is expected to top 12 GW when utility-scale, 

residential, and commercial installations are included.
Slide 5

Eastern Plant Outages 

and Retirements

 Scattered retirements of older units since 

last summer.

 Additional potential retirements in next few 

years.

 Planning coordinators working to coordinate 

transmission upgrades, must-run 

agreements, etc.

A number of utilities in the Eastern Interconnection have announced intentions to retire older fossil 

fuel generating units over the next few years. In PJM, approximately 5 GW of capacity has retired 

since last summer for a net loss of roughly 2.5 GW. According to NERC and the Regions, reserve 

margins are generally projected to exceed planning targets for this summer. Planning coordinators 

continue to support reliable operations in areas experiencing higher than normal levels of plant 

retirements through the development of new capacity resources, operating procedures, transmission 

upgrades, and reliability must-run agreements.
Slide 6

Low Reserve Margins 

in Texas

Extreme 

Heat Wave

65 GW

75 GW

Source: ERCOT Peak Load Available Capacity

Typical Outages

Extreme Outages

ERCOT is projecting a reserve margin of 12.9 percent, assuming that normal weather conditions occur 

in Texas this summer. This forecast reserve margin is approximately one percentage point below the 

reserve margin target. With declining reserve margins, ERCOT faces an increasing risk that load could 

exceed available capacity during an extreme heat wave with higher than normal forced generation 

outages. ERCOT forecasts that over 1.7 GW of demand response resources and 1 GW of new generation 

will be available to operators this summer. Stakeholders and regulators in Texas continue to work on 

policies and initiatives to promote the development of new generation and increase participation in 

demand response programs.

While drought remains a concern in Texas, ERCOT projects that sufficient cooling water will be 

available for power generation this summer. 
Slide 7

Los Angeles

San Diego

500 kV

230 kV

Market and Reliability 

Concerns in LA Basin and 

San Diego Region

Source: Energy Velocity and CAISO

New Generation

Voltage Support

Transmission Upgrade

San Onofre

In Southern California, the San Onofre Nuclear Generating Station between Los Angeles and San Diego 

remains offline. While NERC projects that reserve margins in California, as a whole, will remain 

adequate, transmission constraints will continue to limit transfers into the Los Angeles basin and San 

Diego, particularly under multiple contingency conditions. Three new generators are projected to 

enter service in the area over the summer, and Southern California Edison is continuing to work on 

transmission reconfiguration and voltage support projects in Southern Orange County. Entities in the 

area are also working to increase demand response and conservation measures. 

Eric will now discuss market conditions heading into the summer. 
Slide 8

South Orange County 

and San Diego CA

• Higher natural gas prices

• Low hydro production

• Transmission constraints

• Hotter temperatures

• Cap and Trade

• San Onofre Unit 2 

operation

Price 

pressure

Price

pressure

The unavailability of the San Onofre Nuclear Generating Station will make capacity tight in the 

transmission-constrained South Orange County and San Diego area, resulting in limited imports and use 

of higher-cost local generation. Constrained transmission into the area also yields the potential for 

price spikes in the real-time market, as were experienced last summer. In addition, drought conditions 

in the West increase fire hazards, potentially affecting regional transmission and generation capability. 

Finally, California’s Greenhouse Gas Cap-and-Trade Program has placed upward pressure on prices in 

California, further compounding the cost of operating less-efficient generation dispatched within 

transmission constrained zones. 

Given the confluence of potentially negative events in South Orange County and San Diego, the market 

is likely to experience greater volatility with upward price pressures. Staff will monitor the market 

operations closely, including the tight supply and demand conditions and for any market participant 

behavioral issues. 
Slide 9

Rising Natural Gas Prices 

Should Favor Dispatch of 

Coal Plants

Source: Derived from Nymex

$0

$1

$2

$3

$4

$5

$6

$7

Jan-10

Apr-10

Jul-10

Oct-10

Jan-11

Apr-11

Jul-11

Oct-11

Jan-12

Apr-12

Jul-12

Oct-12

Jan-13

Apr-13

Jul-13

Adjusted Fuel Price 

($/MMBtu)

Gas Coal

Futures

Historical Prices

Adjusted for the relative efficiency of coal and natural gas-fired power plants, current U.S. natural gas 

prices are 78¢/MMBtu higher than Central Appalachian coal prices, the highest separation between 

natural gas and coal prices since July 2010. With the rebound in natural gas prices, staff expects less 

displacement of coal fired generation by natural gas this summer compared to last summer. 

 
Slide 10

Natural Gas Forward Prices 

2011 - 2013

Source: Derived from Nymex Clearport data

$0

$1

$2

$3

$4

$5

$6

Transco Zone

6 NY

Chicago Sumas Socal Henry

Foward Price ($/MMBtu)

2011 2012 2013

Natural gas forward prices for July and August 2013 show a dramatic increase compared to 2012, when 

forwards were below $2.50/MMBtu. However, they are similar to 2011 forward prices. Key hubs 

around the country show similar trends. Summer forwards at Chicago are $4.51, $4.47 at SoCal, and 

$4.73 in New York. The only forward price below $4.20 is at Sumas on the Canadian/Washington 

border, which relies primarily on hydroelectricity to meet summer power needs. Since natural gas is 

frequently the marginal fuel type in electricity markets, it influences electric forward prices. Devin is 

going to discuss the effects of rising natural gas prices on electric forwards.
Slide 11

Electric Forward Prices

2011-2013

Electricity Prices

2011-2013 Forward Prices ($/MWh)

Source: Derived from ICE

$0

$10

$20

$30

$40

$50

$60

$70 2011 2012 2013

Forward Price ($/MWh)

Electric prices for the forward summer strip this year are 25 percent to 58 percent higher than similar 

forwards a year ago. The 2012 electricity forwards reflected low marginal fuel costs tied to the 

exceptionally low gas prices of last summer. This summer’s forward prices are comparable to those of 

2011 in the PJM Western, Cinergy/Indiana, and Mass hubs, but higher in Mid-C, SP-15, and Palo Verde. 

The increase in the latter three hubs is largely attributable to a decrease in hydroelectric generation 

availability from 2011 to 2013. 
Slide 12

Summer Outlook

Source: NOAA Climate Prediction Service Source: NOAA

NOAA predicts another warmer-than-normal summer for most of the country. Like last year’s 

prediction, the exceptions are the Pacific Coast and the Pacific Northwest where normal temperatures 

are expected. The Four Corners and Great Basin areas of the West look to have the greatest chances

of above-average temperatures. NOAA also expects an increased chance of below-normal-precipitation 

within an area extending from the Texas Panhandle and New Mexico, and through the central Rockies 

to most of Oregon and northern California through the summer months. It appears that those areas of 

the central and western U.S. currently experiencing drought will not experience much improvement in 

those conditions.

Early forecasts for the hurricane season from Colorado State University call for higher-than-normal 

activity for the Atlantic this summer, with 18 named storms, of which nine will become hurricanes, 

four of which will become major. Seven hurricanes are considered normal for a season. Generally 

speaking, hurricanes do not have as large an impact on U.S. energy markets as they did several years 

ago due to the shift in U.S. natural gas production away from the Gulf of Mexico and to onshore shale 

production. 
Slide 13

Increased Reliance on NG 

and Alternative Resources

The shift back and forth in the dependence on natural gas-fired generation compared to coal is having 

an impact on power markets. High levels of natural gas power burn means that natural gas supply 

dependability becomes more important. This continues to be a focus of the Commission’s gas-electric 

coordination initiative.

As in recent summers, and particularly since this summer is predicted to be warmer-than-normal, 

demand response may be an important ingredient in managing peak loads. Regions such as PJM, New 

York, and ISO New England relied upon demand response to manage high-load periods during the 

summers of 2011 and 2012. With growth in demand response resources, their use may have a growing 

market impact during the summer period. 
Slide 14

Item No: A-4

May 16, 2013

Summer 2013

Energy Market and 

Reliability Assessment

This concludes our prepared remarks. We will answer any questions you may have.