Slide 1 

Item No: A-3

October 20, 2011

FEDERAL ENERGY REGULATORY COMMISSION

Winter 2011 Winter 2011-12

Energy Market Assessment Energy Market Assessment

The Winter Assessment provides forward prices for both electric 

and natural gas markets. These forward prices are not 

projections of what winter prices may be. No such analysis has 

been conducted by staff. 

Mr. Chairman, Commissioners. Today I am pleased to present the Office of 

Enforcement’s Winter 2011-2012 Energy Market Assessment. The Winter Energy 

Assessment is staff’s opportunity to share observations about natural gas, electricity 

and other energy markets as we enter the winter. 

Market conditions going into the winter are generally positive. Despite a 2.6% 

increase in natural gas demand this year, prices remain among the lowest in the past 

decade, due to continued production growth and new pipelines transporting gas from 

the producing areas to consumers. Gas-fired electric generation is benefiting from 

the lower gas prices, raising expectations for continued demand growth from this 

sector in the upcoming winter. As has been the case in past years, we can expect 

localized pipeline constraints in the Northeast during extreme cold weather periods, 

as growing gas power generation adds to peak gas demand for space heating. 

I will begin by discussing the natural gas markets, and talk about the electric 

markets later in the presentation. 
Slide 2 

2011 Henry Hub Spot 2011 Henry Hub Spot 

Prices Near a 10 Prices Near a 10-Year Low

Source:

Derived from Platts 

and NYMEX data$/MMBtu

NYMEX Forward Price

2010

0

2

4

6

8

10

12

14

16

18

20

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

2011

10-Year Range: 2001-2010

Despite record-cold temperatures at the end of the 2010-2011 winter heating season 

and strong demand for electric generation for air conditioning needs this past 

summer, U.S. natural gas prices in 2011 have remained near the bottom of the 10-

year range. The average forward Henry Hub price for the upcoming winter, 

November through March, is currently $3.87/MMBtu. These price levels are due to 

record setting production, robust storage levels, and pipeline projects that have 

allowed additional supplies to flow out of the production areas, helping moderate 

regional transportation constraints, and get natural gas to markets. 
Slide 3 

Source: Derived from ICE data. YTD prices as of 9/30/2011

Sumas

$4.18

$3.99

-4%

SoCal

$4.40

$4.24

-4%

PG&E

$4.65

$4.40

-5%

CIG

$4.03

$3.96

-2%

Henry

$4.57

$4.21

-8%

Chicago

$4.62

$4.34

-6% TCO

$4.72

$4.31

-9%

TZ6 NY

$5.29

$5.41

2%

FGT Z3

$4.63

$4.30

-7%

El Paso El Paso

$4.32

$4.09

-5%

Regional Spot NG Prices Regional Spot NG Prices 

Generally Lower in 2011 Generally Lower in 2011

2010 YTD 2010 YTD

2011 YTD 2011 YTD

% change

Year-to-date prices in 2011 are below 2010 levels in most regions. The exception is 

in the Northeast, where prices are up for the year due to price spikes in January. 

Additional pipeline capacity has helped moderate prices across the country. 

According to FERC’s Office of Energy Projects, 8.2 Bcfd of pipeline capacity went into 

service from January through August of this year. In the West, the new Ruby and 

Bison pipelines are providing additional supplies from the Rockies to Western and 

Midwestern markets. The increased supply from the Rockies helped reduce prices in 

Northern California and the upper Midwest. In the Southeast, the Florida Gas 

Transmission Phase VIII mainline expansion entered service on April 1, increasing 

capacity from 2.3 to 3.1 Bcfd. The additional supply of Gulf Coast natural gas helped 

moderate price spikes in Florida this past summer. Between June and August, 

Florida gas demand peaked at 4.5 Bcfd, a 22% increase from last year’s peak, and 

gas prices reached a high of $5.23/MMBtu. In contrast, during the summer of 2010 

constraints on the pipeline resulted in frequent price spikes over $7.00/MMBtu and a 

high price of $12.84/MMBtu. 

Access to new production and added natural gas transportation capacity has 

contributed to a trend towards the convergence of prices between regional markets. 

During 2011, there were fewer incidences of spikes in basis between regional natural 

gas hubs and the Henry Hub benchmark price. This trend is expected to continue 

throughout the winter, as additional pipeline infrastructure comes into service and 

provides access to new low cost gas supplies. 
Slide 4 

Northeast Forward NG Northeast Forward NG 

Prices Higher Than 2010 Prices Higher Than 2010

Source: Derived from 

Bloomberg data

0

2

4

6

8

10

12

14

Nov Dec Jan Feb Mar

$/MMBtu

TZ6 NY Forward Price TZ6 NY Forward Price

10/2008 10/2008 10/2009 10/2009 10/2010 10/2010 10/2011 10/2011 

Forward prices for winter natural gas in the Northeast are significantly higher than 

they were last year. On October 11 the winter contract forward price, November to 

March, at New York’s Transco Zone 6 was $6.52/MMBtu, 21% higher than last 

winter’s forward contract price on the same date in 2010. The increase reflects the 

low forward price expectations leading into last winter. Last year, added pipeline 

capacity in the Northeast raised expectations for lower winter prices. Despite the 

additional infrastructure, the region experienced occasional pipeline constraints and 

price spikes during the cold snaps in January and February. This year the markets 

seem to be accounting for the possibility of similar spikes, but overall, forward prices 

remain at moderate levels. 

Weather is a key factor in winter gas demand and prices. In its most recent winter 

forecast, the National Oceanic and Atmospheric Administration (NOAA) calls for 

average temperatures in the Northeast. 

Forward winter prices in the rest of the country are relatively flat, except at the 

Northwest Sumas Hub, which is 15% below 2010 levels. This is due to lower natural 

gas demand for power generation resulting from high hydropower output, and also 

the additional supply of Rockies gas via the new Ruby pipeline. 
Slide 5 

Electric Wholesale On Electric Wholesale On-Peak 

Forward Winter Prices Forward Winter Prices

Source: Derived from ICE data as of 09/30/11 for 2012 contracts and as of 09/30/10 for 2011 contracts.

* The Midwest ISO (Cinergy) Hub will become the MISO Indiana Hub at the start of 2012.

($Mwh) FOR JANUARY AND FEBRUARY

Location

New York City

Massachusetts Hub

PJM Western Hub

Midwest ISO (Cinergy)*

Northwest (Mid C)

Southern California (SP-15)

Henry Hub (Gas) $/MMBtu

2011 

$65.75

$56.02

$47.71

$36.93

$37.02

$38.41

$4.31

2012

$85.13

$73.25

$55.25

$43.25

$33.10

$37.65

$4.18

% Change

29%

31%

16%

17%

-11%

-2%

-3%

I will now turn to the outlook for electricity prices this winter. For the purpose of this 

slide, winter peak electricity demand is defined as January and February. 

Forward winter prices are generally mixed compared to last year. In the Northeast, 

forward winter prices are higher than they were at this time last year. The 

Massachusetts Hub has the largest increase, up 31%, and New York City is 29% 

above last year's price, reflecting the outlook for local natural gas prices. This is 

important because gas is typically the marginal, or price setting, fuel in this region. 

Unlike the Henry Hub in Louisiana, which is slightly down, Northeast gas prices are, 

as previously indicated, significantly higher than last year. 

Forward winter prices are also higher for MISO and PJM, with the Cinergy Hub up 

17% and the PJM Western Hub up 16%. These increases may reflect higher demand 

from industrial power customers, which at the end of the second quarter was 2.5% 

higher than in 2010. In addition, the weather forecast from both NOAA and 

AccuWeather call for colder than average weather for the Great Lakes, the Midwest, 

and northern plain states, which may also be influencing the forward electric prices. 

Despite the increase from last year, prices for this winter are at the same level as 

2010 winter prices, and are significantly below 2009 winter levels. 

In the West, prices are generally unchanged, except for the Mid-Columbia Hub, 

which is 11% lower than last year. This is consistent with winter forward natural gas 

prices in the Northwest, which are 9.3% lower than last year. Additionally, NOAA is 

forecasting above average precipitation in the Northwest this winter, which could 

have a positive effect on hydroelectric production. 
Slide 6 

U.S. Dry NG Production U.S. Dry NG Production 

Continues to Grow Continues to Grow 

30

40

50

60

70

2005 2006 2007 2008 2009 2010 2011

Bcfd

Dry Gas Production

NGL Production

Source: 

Derived from 

Bentek Energy 

data

Natural gas production continued to grow in 2011, setting records throughout the 

year and averaging 60.3 Bcfd through September, a 6% increase over 2010. Shale 

gas now accounts for more than 25% of U.S. production, up from 5% in 2007. 

There has also been an increase in production of associated gas from oil shale wells, 

as high oil prices led to the acceleration in drilling for shale oil. The Baker Hughes 

gas-directed rig count remained relatively flat this year, but oil-directed rigs 

increased from 777 at the beginning of the year to 1080 on October 14. 

Production growth brings its own challenges, such as insufficient infrastructure to 

move natural gas, natural gas liquids (NGLs) and shale oil to markets. Also, higher 

on-shore production in areas prone to cold weather increases the likelihood of well 

freeze-offs, which in past winters temporarily affected regional supplies. 

In some regions, the rush to extract oil from oil rich shale formations has also 

resulted in high levels of flaring, or burning of natural gas. In the Bakken shale 

formation in North Dakota, for example, the natural gas gathering system is 

struggling to keep pace with growing production, and an estimated 25% of the 

natural gas produced, as much as 100 MMcfd, has been flared this year. However, 

major gatherers and pipelines are expanding their systems, and adding storage and 

gas processing capability to get the gas to markets. 
Slide 7 

New Infrastructure for New Infrastructure for 

Rising Marcellus Production Rising Marcellus Production

Source: Derived from FERC & industry sources. Note: FERC-Approved or Pending Projects Over 300 MMcfd Going In-service in the Next Year

Capacity Capacity 

(Mmcfd) Company/Project Name

1

2

3

4

5

6

Central NY Oil & Gas Mark I Project Central NY Oil & Gas Mark I Project

Dominion Appalachian Gateway

Tennessee 300 Line Expansion

Empire Tioga Line Extension

National Fuels Gas Northern Access

Equitrans Equitrans Sunrise Project

550

484

350

350

320

314

Projected Inservice Date

Summer 2012

Fall 2012

Fall 2011

Fall 2011

Fall 2012

Summer 2012

Marcellus Shale production has increased from 2.7 to 4.7 Bcfd in the past year alone. 

In Northeast Pennsylvania, where production is up 1.3 Bcfd from 2010 levels, 

pipeline constraints have led to natural gas prices in the $2.00/MMBtu range, the 

lowest in the country. New expansion projects should help relieve constraints in the 

Marcellus producing region this winter, and stabilize prices in areas with high levels 

of constrained take-away capacity. 

At this time there are over 6 Bcfd of FERC-approved and proposed pipeline projects 

designed to provide additional takeaway capacity for Marcellus shale gas. In 

Northern Pennsylvania, the Tennessee Gas 300 Line Expansion project will add 350 

MMcfd of capacity starting this fall. The Empire Tioga Line Extension will connect 

Pennsylvania Marcellus production to the Empire Connector Pipeline in New York, for 

an additional 350 MMcfd of takeaway capacity, also starting this fall. In the 

southwestern Marcellus area, Dominion’s Appalachian Gateway will help move gas 

from Pennsylvania and West Virginia to eastern markets starting fall 2012. 
Slide 8 

LNG Imports Decline LNG Imports Decline

As U.S. Prices Drop As U.S. Prices Drop

-8

-6

-4

-2

0

2

4

6

2006 2007 2008 2009 2010 2011 2012

$/MMBtu

0

10

20

30

40

50

60

70

80

90

100

Bcf/Month

LNG Imports

Henry Hub - NBP

Forward Price Difference

Source: Derived 

from Waterborne 

Energy and 

Bloomberg data

Growing shale gas production has had a significant impact on liquefied natural gas 

imports. Year-to-date, the eight active U.S. LNG terminals have operated at only 

5% of capacity. Some Gulf Coast terminals have managed to extract value from 

their underutilized facilities by providing temporary storage of landed LNG before 

sending it to higher priced destinations around the world. These LNG re-exports 

amounted to 45 Bcf through the first nine months of 2011, about 19% of total U.S. 

LNG imports over the same period. 

Decreasing LNG imports are due to the low price of natural gas in the United States 

compared to world markets. In 2007, U.S. natural gas prices commanded a 

$4/MMBtu premium over the National Balancing Point in the United Kingdom, and 

LNG imports peaked at almost 100 Bcf/month. Since the fall of 2007, U.S. prices 

have generally been at a substantial discount to world LNG prices, and LNG imports 

have tumbled. Current winter forward natural gas prices at Henry Hub are $6 to 

$8/MMBtu lower than comparable European prices. LNG does continue to play a role 

in the Northeast, where imports through Everett in Boston and Canaport in New 

Brunswick, Canada, are underpinned by long-term contracts. 
Slide 9 

NG in Storage Nears Last NG in Storage Nears Last 

Year’s Record Level s Record Level 

Source: Derived from EIA data as of October 7, 2011

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

1,000

1,500

2,000

2,500

3,000

3,500

4,000

Volume (BCF) Volume (BCF)

5-year range 2010-2011 2011-2012

Natural gas storage levels are an important indicator of the industry’s ability to meet 

winter demand. As of October 7, 2011, U.S. working gas in storage was 2% above 

the 5-year average, and is expected to end the injection season near or above the 

record set last year. 

This year’s injection season began slowly, due to high temperatures and robust use 

of natural gas as an electric generation fuel. Record heat in the Gulf Coast and 

Midwest led to a 5% increase in summer power burn, resulting in lower injections in 

those regions. Also, Rockies natural gas, which in the past would have flowed to fill 

Western storage, flowed east to meet the high demand. 

Since August, however, injections have been strong as demand moderated with the 

end of the summer cooling season. Currently, the East region is 1% below the 5-

year average, the West is 3% higher and the producing region is up 7%. At the 

current injection rates, natural gas in storage should be sufficient to meet winter 

demand. 
Slide 10 

Power Generation Drives Power Generation Drives

NG Demand Higher NG Demand Higher

Source: Derived from Bentek Energy data Peak season defined as January-March

0

1

2

3

4

5

NE SE MW TX West

Bcfd

2006 2007 2008 2009 2010 2011 

U.S. natural gas demand for power generation is up 3.6% through October 14, 

driven by high summer electricity demand. In addition, natural gas continues to 

displace some coal used for electric generation, particularly in the east, due to rising 

coal prices and lower natural gas prices. In 2011, the central Appalachian coal price 

is 21% higher than in 2010, and Powder River coal is up 7%. 

In some regions, gas-fired power generation for the peak winter months, January 

though March, has been increasing for the past few years, due to new gas-fired units 

and greater utilization of existing ones. This is of special interest in the Northeast, 

where generation demand on peak days can coincide with heating load demand. 

These coinciding peak events can strain the pipeline delivery system and lead to fuel 

supply restrictions on natural gas-fired units, as regional gas pipelines prioritize 

deliveries to customers holding firm transportation rights. In recent winters these 

coinciding peaks have led to occasional price spikes but no major reliability issues. 

In other sectors, year to date residential and commercial demand rose 3.5%, mostly 

due to the cold temperatures in the first quarter. This growth is offset by the small 

uptick in industrial gas demand, up only 0.2% due to the slow pace of the economic 

recovery. U.S. natural gas demand for all sectors is up 2.6% from last year. 
Slide 11 

Electric Industrial Electric Industrial 

Demand Higher than 2010 Demand Higher than 2010 

Source: Derived from EIA Monthly Electric Sales data. Monthly figures adjusted for number of days in the month

70

75

80

85

90

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

MW

2008 2009 2010 2011

Two prime factors that influence the level of electric consumption from year to year 

are the economy and weather. The level of economic activity is reflected primarily in 

industrial electric consumption, which is largely immune to weather effects. By 

contrast, electric demand in the residential sector is more sensitive to weather. 

The industrial sector makes up 25-30% of total electric consumption. At the trough 

of the recession in 2009, annual demand by industrial users was the lowest in ten 

years. Industrial demand has grown steadily since then. As the chart shows, 

industrial electric use, when compared to the same month a year earlier, has grown 

each month of 2010 and so far in 2011. These levels, however, are still below the 

industrial consumption prior to the recession. 
Slide 12 

Southwest Outage and Southwest Outage and 

Curtailments Follow-up

 February 2011, the Southwest region 

experienced 5–days of unusually cold weather

 3.7 million electric customers affected

 Natural gas service to over 50,000 customers in 

New Mexico, Texas and Arizona interrupted

 FERC and NERC initiated an inquiry, and issued 

recommendations in August

 State led initiatives are already underway to 

address the problems encountered

As reported to the Commission in August, during the first week of February 2011, 

the Southwest region experienced unusually cold weather that resulted in the 

widespread loss of electric and gas service. Over 3.7 million electricity customers 

were affected, as utilities were forced to initiate rolling blackouts totaling over 6,000 

MW. At the same time, local distribution companies interrupted gas service to more 

than 50,000 customers in New Mexico, Texas and Arizona. 

A joint inquiry by the Federal Energy Regulatory Commission and the North American 

Energy Reliability Corporation looked into the causes of the outages and made 

recommendations. The recommendations, released in August 2011, included 

measures that electric and natural gas companies can take to reduce the chances of 

similar events in the future, such as steps to weatherize equipment, and adopt 

procedures to prevent similar problems in the future. Additional inquiries and 

recommendations were launched by the industry and by state regulators. 

At this time, there are several state level initiatives underway to address the issues. 

On the electric side, the Salt River Project in Arizona has made infrastructure and 

procedural improvements to better handle cold weather events. Staff of the New 

Mexico Public Utilities Commission is preparing a report on the outages to include 

recommendations for weatherization and other infrastructure improvements. Under 

new state legislation, the Texas Public Utility Commission has directed its electric 

utilities to update their emergency plans and recommend improvements. 

On the gas side, the New Mexico legislature and PUC are awaiting a formal report 

and recommendations from the state task force established to investigate the event. 

However, the New Mexico Gas Company has begun installing additional gas valves to 

better control their system and procured additional storage capacity at the Chevron 

Keystone Storage field. The Arizona Corporation Commission (ACC) reviewed the 

circumstances surrounding the gas outages. The ACC has said it would like to see 

underground natural gas storage developed in the state. 
This concludes the 2011-2012 winter assessment. We will answer any questions you 

may have. 
Slide 13 

Item No: A-3

October 20, 2011

FEDERAL ENERGY REGULATORY COMMISSION

Winter 2011 Winter 2011-12

Energy Market Assessment Energy Market Assessment