Slide 1 

Item No: A-3

May 17, 2012 May 17, 2012

Summer 2012 Summer 2012

Energy Market and Energy Market and 

Reliability Assessment Reliability Assessment

Mr. Chairman, Commissioners, good morning. We are pleased to present the Summer 

2012 Energy Market and Reliability Assessment, which is a joint effort of the Office of 

Enforcement and the Office of Electric Reliability. 
Slide 2 

Key Takeaways Key Takeaways

 Low gas prices are expected to drive generally lower 

prices in the electricity markets.

 Without San Onofre, Southern California, and 

particularly the San Diego area, could see very low 

reserve margins.

 Texas is looking at another year with low reserves.

 Capacity reserves appear adequate in the rest of the 

country.

 The markets could see further substitution of naturalgas fired generation for coal generation.

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

Robust supplies of natural gas have led to the lowest sustained natural gas prices since 

2001. This market trend is expected to continue to place pressure toward generally 

lower electricity market prices; 

With the outage of two San Onofre nuclear units, supply-demand conditions in 

Southern California, and particularly in the San Diego area, warrant close attention to 

electric grid operations and electricity market prices if the two units should remain 

offline during high load periods this summer; 

The generation supply in Texas may be strained if the state experiences another hot 

summer like last year; 

However, overall in the rest of the country, capacity reserves appear adequate; and 

The shift from coal-fired to natural gas-fired generation will have limited market 

effects. 
Slide 3 

Reserve Margins Reserve Margins 

Adequate in Most Regions Adequate in Most Regions

Source: Preliminary data from NERC Summer Assessment

0

200

400

600

800

1000

2003 ’04 ’05 ’06 ’07 ’08 ’09 ’10 ’11 2012

GW

Forecast Capacity Forecast Peak Demand Actual Peak Demand

Thank you Alan. 

Preliminary data from NERC’s Summer Assessment indicates that reserve margins are 

projected to be adequate in most, but not all, regions of the country this summer. 

Some areas, such as ERCOT, are projecting a small amount of load growth, while other 

areas, such as New England are projecting that loads will remain flat or decline. 

Overall, NERC forecasts that the total US load, when weather adjusted, will decline by 

less than one percent when compared to last year. 

In Texas, ERCOT is forecasting a reserve margin of 13.3 percent, which is below its 

reserve margin target of 13.75 percent. For California, WECC is forecasting a reserve 

margin of 15.2 percent, slightly above the reserve margin target of 15.1 percent. 

Under normal weather and system conditions, New England’s electric power supplies 

are expected to be adequate this summer. However, reduced and uncertain supplies 

of Liquefied Natural Gas to fuel the Mystic Generating Station could result in an 

inadequate supply to the Greater Boston area during extremely high loading periods 

and multiple contingency conditions. ISO New England is reaching out and working 

with asset owners in North East Massachusetts and the Boston area to alert them to 

the situation and is working with local generation and transmission companies to 

develop special operating plans that can be used to manage a shortage situation. 
Slide 4 

Wind Generation Wind Generation

Source: Preliminary data from NERC Summer Assessment

5

15

25

35

45

2008 2009 2010 2011 2012

Wind Capacity (GW)

Capacity Projected On-peak

Total Nameplate Capacity

The NERC Summer Assessment reports that the projected summer installed nameplate 

wind capacity will increase by about 3.4 GW, or about 9 percent from 2011, for a total 

nameplate capacity across the nation of approximately 40 GW. 

The average on-peak wind capacity for the 2012 summer is forecast to be 11 percent 

of nameplate capacity. The on-peak capacity forecasts reflect the differing wind 

characteristics across the country, and range from lows of 2.2 percent of the 

nameplate capacity of 4.5 GW in the Southwest Power Pool to a high of 26 percent of 

the nameplate of 1.2 GW in Mid-Continent Area Power Pool. 
Slide 5 

Eastern Plant Outages Eastern Plant Outages 

and Retirements and Retirements

• No significant increase in retirements for 

this summer.

• Potential retirements in fall and beyond.

• Planning coordinators working to

coordinate outages, upgrades, etc.

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

retire older fossil fuel generating units over the next few years, with some retirements 

in PJM beginning as early as this fall. According to NERC and the Regions, plant 

retirements are not projected to affect reliability for this summer, and appear to 

represent normal generation fleet turnover. Similarly, NERC and the Regions report 

that the planning coordinators continue to work with their generation and transmission 

owners to manage any maintenance outages related to plant retrofits or upgrades. 

Looking ahead to the fall, FirstEnergy has announced plans to retire generating units 

totaling approximately 3.4 GW in its service territory in northern Ohio and western 

Pennsylvania. PJM and the transmission owners are coordinating transmission 

upgrades, reliability must-run agreements, and projects and procedures to allow 

continued reliable operations in this area. 

The NERC Long-Term Reliability Assessment, which will be released in the fall, will 

provide additional information on projected resource adequacy in future years. 
Slide 6 

Low Reserve Margins Low Reserve Margins 

in Texas in Texas

60

62

64

66

68

70

72

Normal High Load

GW

Source: ERCOT

Generation

Demand

Generation

Demand

ERCOT is projecting a reserve margin of 13.2 percent, assuming that normal weather 

conditions occur in Texas this summer. This projected reserve margin will be 

approximately one half of a percentage point below its reserve margin. ERCOT also 

projects that forecasted load could exceed projected capacity during an extreme heat 

wave with higher-than-normal forced generation outages. ERCOT forecasts that over 

1.4 GW of demand response will be available to operators during periods of peak 

demand, and may obtain additional load reductions from public appeals for 

conservation and price-sensitive demand. 

According to NERC and ERCOT, the low reserve margins in Texas are due largely to 

load growth outpacing generation development. ERCOT has continued to experience 

load growth through the recession, and several years of hot summer weather have 

contributed to an increasing load forecast. While drought remains a concern in Texas, 

ERCOT projects that winter precipitation was sufficient to maintain reservoir levels 

and provide sufficient cooling water through the summer months. 
Slide 7 

San Onofre Nuclear Generating Nuclear Generating 

Station (SONGS) Outage Station (SONGS) Outage

Source: Derived from FERC staff analysis

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

and San Diego has been shut down for repairs. Without the 2.3 GW from this plant, 

NERC forecasts that projected reserve margins in California may be close to, but still 

be above, the regional target of 15.1 percent. The extended plant outage will also 

limit transfers into the San Diego area from the Los Angeles basin. Two mothballed 

units at Huntington Beach have been reactivated, and will provide additional capacity 

in the Los Angeles basin and support additional transfers into San Diego. Entities in 

the area are also working to increase demand response and conservation measures in 

southern Orange County and San Diego. Alan... 

Thank you, David. 

In addition to the reliability concerns David just described, if the San Onofre Nuclear 

Generating Station units continue on outage into the summer the market impacts 

could extend beyond the San Diego area. In particular, Southern California, which 

includes the transmission zones of both San Diego Gas & Electric and Southern 

California Edison, may see elevated prices compared to Northern California and 

neighboring regions, especially during periods of high demand. With the region reliant 

on imports, the removal of the two SONGS units means the region will need to rely on 

plants with higher costs. Greater price volatility typically occurs under such 

situations. 

The ultimate impact on customers should be at least partially buffered, with the local 

load-serving entities having physical capacity, purchase agreements, and Congestion 

Revenue Rights. Few customers pay bills based on the real-time price, but high realtime prices work their way into day-ahead prices and longer-term instruments if they 

are sustained. 

Staff will follow the market operations closely, including the supply and demand 

conditions and any market participant behavioral issues. 
Slide 8 

Henry Hub Next Henry Hub Next-Day Price Day Price

April 2001 to May 2012 2001 to May 2012

Source: Derived from ICE

0

4

8

12

16

20

2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012

$/MMBtu

The most prominent market driver for energy markets this summer will be the cost of 

natural gas, which has fallen to prices last seen a decade ago. In staff’s 2011 State of 

the Markets Report last month, staff showed how prices have declined throughout 

2011. This decline to below $3 per MMBtu has continued into 2012. 

Gas prices at the recent lower level can be expected to have a significant impact on 

electric markets. Gas prices in the $2-$2.50 price range place downward pressure on 

electricity prices generally, and moves some dispatch to natural gas from coal, which I 

will discuss later. 

Staff expects that surplus-gas conditions will continue through the summer. Overall, 

with these market conditions, natural gas prices can be expected to stay near their 

present levels. 
Slide 9 

Natural Gas Prices Natural Gas Prices

2011 and 2012 Forwards 2011 and 2012 Forwards

(per MMBtu)

2011 2012

Transco Zone 6 NY

Chicago

NWP Sumas

SoCal

Henry

$4.89

$4.29

$3.90

$4.28

$4.22

$2.48

$2.28

$2.05

$2.51

$2.25

Forward prices for July and August each year as of May 1. Source: New York Mercantile Exchange (Nymex)

% Change

-49%

-47%

-47%

-41%

-47%

This chart compares forward natural gas prices for last summer with forwards for this 

summer. Staff looks at forward prices for the peak summer months of July and August 

for perspective on how market participants currently view the dynamics affecting 

seasonal prices. Staff does not view forward prices as a predictor of actual prices, but 

analyzing the trends in the forward prices can help to understand market factors 

heading into summer. The sharp contrast between what summer forwards are today 

and what they were in 2011 shows that the forward markets expect that the current 

natural gas surplus in supply will continue to be the price driver over this period. 

With storage already filling as we enter summer and production levels continuing at a 

robust level, physical fundamentals indicate that natural gas prices will continue at 

lower levels compared to recent years. 

While regional differentials persist, there is much less variation than in years past. 

New pipeline infrastructure, such as the Ruby Pipeline, the new Florida Gas 

Transmission expansion and Rockies Express has linked new supply sources to demand 

markets and reduced bottlenecks significantly. The differences that do arise in basis 

are limited in magnitude. Also, basis differences derive from temporary conditions 

such as weather-driven demand in the Northeast, driving basis higher, or from supply 

surplus in the Northwest, driving basis lower. 
Slide 10 

Electricity Prices Electricity Prices

2011 and 2012 Forward 2011 and 2012 Forward 

Price Comparison ($/MWh)

PJM Western Hub

Mass Hub

Cinergy/Indiana

Mid C

SP-15

Palo Verde

$63.25

$60.95

$47.50

$31.62

$47.00

$42.50

2011 2012

$46.55

$38.50

$37.25

$25.00

$38.50

$34.75

Source: Derived from ICE

% Change

-26%

-37%

-22%

-21%

-18%

-18%

This chart compares electricity forward prices for this summer as of May 1st with 

electricity forwards from last year. The forward prices indicate that market 

participants expect lower prices than a year ago. The chart shows that prices for the 

forward summer strip this year are $7 to $22/MWh less than similar forwards a year 

ago. 

As noted, staff does not view forwards as a price forecast, but, rather, perspective on 

how the various market participants view market conditions. This is particularly true 

for electric prices. The weather impact on electric prices can introduce large swings 

that cannot be predicted months in advance. Typically, because the market does not 

know for certain how hot the summer will be, it takes a weather-normalized view of 

load levels and their effect on price when contracting forward. 
Slide 11 

Weather Conditions Weather Conditions

Source: NOAA Climate Prediction Service

NOAA predicts a warmer-than-normal summer across most of the country. The only 

exceptions are parts of the Pacific Coast and the northern tier of the nation, where 

normal temperatures are expected. The greatest chance of above-average 

temperatures is the area centered around Arizona and New Mexico. NOAA also sees an 

increased chance of below-normal precipitation in the Northwest through the summer 

months. 

Early forecasts for the hurricane season from Colorado State University call for lowerthan-normal activity for the Atlantic this summer. It predicts 10 named storms, of 

which 4 will become hurricanes, and 2 of those 4 will become major hurricanes, 

category 3 or greater. Six hurricanes are considered normal for a season. When 

assessing the impact of hurricanes, an important factor to keep in mind is the 

geographical change in U.S. production. In 2005, before the shale gas revolution, the 

double hit from hurricanes Katrina and Rita sent gas prices soaring through large 

portions of the U.S. market. By 2008, shale gas added more than 9 Bcf to daily 

production, and another double-hurricane hit that summer (hurricanes Gustav and Ike) 

caused barely a ripple in gas prices. New onshore production less vulnerable to 

hurricanes, pipeline infrastructure additions, additional Gulf Coast storage and LNG 

terminals have added diversity of supply options and flexibility to the system that 

minimize the effects of hurricanes on natural gas markets. 
Slide 12 

Northwest Hydro Northwest Hydro 

Conditions Conditions

0

100

200

300

400

500

J F M A M J J A S O N D

Outflow (kcfs)

2007-11 Range

2012 Outflow

2011 Outflow

River Flow at The Dalles Dam

Source: U.S. Army Corps of Engineers

Conditions for hydroelectric generation in the West are mixed. Snowpack in British 

Columbia and parts of the U.S. Northwest came in at average or above-average levels. 

California, on the other hand, is well below average. The Pacific Northwest reached 

98 percent of average snowpack as of April 1, the historical peak snow accumulation 

date, while California was 60 percent. 

This means that conditions likely will support significant hydroelectric production in 

the Northwest. Inside California, available hydroelectric generation is expected to be 

somewhat below average. While snowpack levels are low, reservoir levels are closer 

to normal owing to good hydrologic conditions last year. The expected abundance of 

hydro production in the Northwest will benefit the California and Southwest markets. 

As is typical of normal hydro conditions, transmission lines from the Northwest into 

California can be expected to be well loaded during the spring and going into the 

summer. 

Even though hydro conditions are not expected to be as flush as a year ago, BPA sees a 

high likelihood that there will be some over-generation as a result of river and hydroelectric facility protocols designed to protect fish. Over-generation may, in turn, lead 

to curtailments of non-hydro resources, which has already occurred this spring. The 

financial markets may see negative prices during some over-generation conditions. 

Other regions such as ISO New England, New York ISO, and MISO use hydroelectric 

generation as part of their generation mix, both from internal generation within each 

region and from Canadian imports. None of these areas is as dependent on, or 

influenced by, hydro conditions as the Northwest and California. Based on hydro 

conditions in the eastern regions, we do not see any notable market issues to report. 

In the past there have been concerns about drought conditions in some areas and the 

availability of cooling water. Some regions, such as the Southeast and the Southwest 

are expected to be under drought conditions this summer, but these conditions are not 

expected to be severe enough to cause concern about the reliability of generators that 

depend on water supplies for cooling. 
Slide 13 

Coal-Fired to Natural Gas Fired to Natural GasFired Generation Shift Fired Generation Shift 

May July Sept Nov Jan Mar May

$2.00

$2.50

$3.00

$3.50

$4.00

$4.50

$5.00

$5.50

Price per MMBtu (Adjusted)

Coal

Natural Gas

2011 2012

Source: Staff analysis derived from Bloomberg data

As noted, the low cost of natural gas is expected to continue to exert downward 

pressure on electricity prices this summer. We expect the ongoing substitution of 

natural gas-fired generation for coal-fired generation to continue as a result of these 

low gas prices. When the cost of natural gas dropped below $4 per MMBtu, combined 

cycle units started competing on price with coal-fired steam units using Central 

Appalachian coal. The graph above shows a crossover in favor of natural gas in the fall 

of 2011. The comparison is on an MMBtu basis adjusted for typical heat rate of natural 

gas and coal-fired units. In regions such as MISO, PJM, and the Southeast for example, 

where there is significant coal-fired capacity as well as natural gas-fired capacity, use 

of the installed natural gas-fired generation has grown as use of coal resources has 

dropped. 

The ability of the natural gas-fired plants to obtain sufficient fuel does not appear to 

be a significant factor or a market concern during the upcoming summer. In 

particular, capacity in long-haul pipelines is generally sufficient to avoid disruptions in 

the use of natural gas for electric generation for this summer. 

 

The switch-over from coal to natural gas can be expected to lower coal plant 

revenues. In addition, some coal plant owners may reduce their offers in order to 

keep running because they need to manage their coal piles. This is because many 

coal-fired plant owners entered into contracts determining price and delivery 

schedules when conditions were different. 
Slide 14 

Item No: A-3

May 17, 2012 May 17, 2012

Summer 2012 Summer 2012

Energy Market and Energy Market and 

Reliability Assessment Reliability Assessment

This concludes our prepared presentation. I would like to express gratitude to the 

many staff members in the Office of Electric Reliability and the Office of Enforcement 

who contributed to this report. 

We are happy to answer any questions you may have.